IR 05000395/1998009
| ML20198N870 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 12/21/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20198N841 | List: |
| References | |
| 50-395-98-09, 50-395-98-9, NUDOCS 9901060241 | |
| Download: ML20198N870 (29) | |
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l U. S. NUCLEAR REGULATORY COMMISSION )
I REGION 11 !
Docket No.: 50-395 License No.: NPF-12 Report No.: 50-395/98-09 l
Licensee: South Carolina Electric & Gas (SCE&G) l i
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Facility: V. C. Summer Nuclear Station Location: P. O. Box 88 Jenkinsville, SC 29065 Dates: October 11 - November 21,1998 I
inspectors: K. O'Donohue, Acting Senior Resident inspector M. King, Resident inspector (In-Training)
E. Girard, Reactor Inspector, Rll (Section M1.5)
W. Rogers, Senior Reactor Analyst, Ril (Section E8.2)
K. Coyne, Project Engineer (In-Training) (Section M8.4)
Accompanying Personnel: T. Scarbrough, Senior Mechanical Engineer, NRR (Section M1.5)
Approved by: R. C. Haag, Chief, Reactor Projects Branch 5 Division of Reactor Projects Enclosure 2 k OMh5 PDR
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EXECUMVE SUMMARY V. C. Summer Nuclear Station NRC Inspection Report No. 50-395/98-09 This ?,iegrated inspection included aspects of licensee operations, maintenance, engineering, ;
and plant support. The report covers a six-week period of resident inspection; in addition, it '
includes the results of an announced inspection by a regionalinspector and headquarters senior mechanical engineer, and in-office reviews by a regional senior reactor analyst and a I regional project engineer. I Ooerations
A violation was identified for failure to document entry into Technical Specification Action statements. Operations personnel failed to recognize preventative maintenance
activities placed the ECCS Accumulators and ECCS Subsystems outside the conditions established by surveillance requirements. This condition resulted in the failure to meet the Technical Specification Limiting Conditions for Operation and, as a result, operations personnel failed to document entry into TS Action statements in the Station Log Book (Section O1.2).
Detailed inspection of the Reactor Building Spray and Residual Heat Removal Systems determined that the systems were in adequate condition to perform as designed. Valve alignments were proper and component labeling was adequate (Section O2.1).
A review of the licensee's cold weather protection program revealed no significant discrepancies. The system engineers interviewed were knowledgeable and the heat l trace system performance was being properly monitored within the licensee's
, Maintenance Rule program (Section O2.2). l Maintenance
- In general, performance of maintenance and surveillance testing was professional and thorough. All work was performed with the work package present and actively referenced. Technicians were experienced and knowledgeable of their assigned tasks (Section M1.1).
- The inspectors observed technically sound troubleshooting activities to determine the cause for tripping of the motor operated valve FCV-602A breaker during surveillance testing. The root cause was identified and procedure revisions were implemented to prevent recurrence (Section M1.2).
- Observed year 2000 (Y2K) testing of control room recorders was performed satisfactorily. No safety significant concerns were identified with the testing results. The maintenance and vendor technicians performing the tests were knowledgeable of the Y2K tests and demonstrated good work practices (Section M1.3).
- In general, planning for governor replacement on B Emergency Diesel Generator was adequate. Licensee personnel perfor.ning the maintenance were knowledgeable and well informed and supervision was actively involved in the work. Due to the inability to
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] . adjust and satisfactorily complete setup runs for the replacement governor units, the licensee reinstalled the original governor units (Section M1.4).
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The licensee had established and was implementing a program to provide continued 1, assurance that motor-operated valves (MOVs) within the scope of Generic Letter (GL)
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96-05," Periodic Verification of Design-Basis Capability of Safety-Related Motor-
- Operated Valves," were capable of performing their design-basis safety functions (Section M1.5).
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- The B main steam power operated reliei valve was determined to be able to perform its design function. Licensee miscommunication resulted in an unnecessary retest of the B .
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main steam power operated relief valve (Section E1.1).
- Plant Suooort
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The removal of the large radwaste high integrity container was well coordinated, d
resulting in limited personnel exposure. The pre-job planning and the designation of
- pre-determined goals for specific activities also contributed to limiting personnel ;
radiation exposure (Section R4.1).
Surveillance activities for the Early Warning Siren Control System demonstrated 4 satisfactory performance of the equipment. Emergency planning personnel were responsive to correcting an identified procedure deficiency associated with notification of siren system inoperability (Section P2.1).
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The licensee identified and corrected several pre-fire plan discrepancies concerning the
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location and type of fire extinguishers staged in the plant. An independent review of the
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pre-fire plan maps and auxiliary building fire extinguishers and fire hose stations in the -
field identified no additional discrepancies (Section F2.1).
Discrepancies identified during performance of a Turbine Building Fire Barrier Inspection were properly dispositioned. Control room personnel were immediately informed of deficiencies and corrective action was initiated. The licensee indicated the inspection procedure STP-728.003 would be revised to eliminate unnecessary inspection points from the procedure (Section F3.1).
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- Summary of Plant Status Unit 1 began this inspection period at approximately 100 percent power and remained there throughout the inspection period.
l. Operations 01 Conduct of Operations 01.1 General Comments (71707)
The inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below.
01.2 Accumulator Discharae isolation Valves a. Inspection Scooe (71707) -
The inspectors reviewed the licensee's control of Technical Specification (TS) related activities, b. Observations and Findinas During the week of October 19,1998, a preventive maintenance activity on XMC1DB2Y 161M, the B Reactor Coolant System Accumulator discharge isolation valve breaker, was scheduled. Operations shift personnel denied authorization to initiate the work.
The breaker is normally deenergized and locked open per TS Sunreillance Requirement 4.5.1.1.c. Unlocking and energizing the valves would place the system outside of this surveilled condition. Operations personnel stated that they did not authorize the activity because of a concern that the valve may go closed once ths breaker is energized. TS 3.5.1 requires the accumulator isolation valves to be open in Modes 1 and 2, and in Mode 3 when pressurizer pressure is above 1000 psig. Because the accumulator discharge valves do not meet the single failure criteria, the power supply breaker is locked open por TS Surveillance Requirement to ensure the valves remain open when required.
The inspectors determined that the same preventative maintenance activity for Accumulator A and C discharge isolation valve breakers was performed on July 15, 1998. Placing a system outside the conditions established by surveillance requirements results in a failure to meet the TS Limiting Conditions for Operation (LCO) and therefore
, requires entry into the applicable TS Action statement. TS Action Statement 3.5.1.a is
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the applicable action statement when a reactor coolant system accumulator is inoperable. The inspectors reviewed Station Log Book entries for July 15,1998 and determined that entry into the applicable TS action statement was not logged. Plant personnelinformed the inspectors that during performance of this preventative maintenance activity, the valve breakers are typically energized for less than fifteen minutes. Because entry into the applicable TS Action statements was not documented, L
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I 2 I the actual duration that the valve breakers were closed during these instances could not be determined.
Station Administrative Procedure SAP-204," Operating Logs and Records," Revision 7, identifies log books and records to be prepared by the Operations Department. This procedure required Station Log Book entries for entering any LCO Action Entry not i covered by a removal and restoration form. Operations personnel stated that they did l not recognize entry into the applicable TS Action statements was required during the performance of the preventative maintenance.
During discussions with the inspectors, operations personnel stated that they did not recognize that placing system outside the surveilled condition resulted in a failure to meet the associated TS LCO. The licensee's general philosophy for TS surveillance requirements did not support the view that placing a system outside the conditions established by performance of TS surveillance requirements resulted in a failure to meet !
the applicable LCO. During the discussion with the inspectors, the licensee identified a l second example when a TS Action statement was not entered when required. On January 26,1998, the Shift Supervisor authorized maintenance activities on the
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. Charging /High Head Safety injection Cross-connect valve 8133B-0-CS without !
recognizing that the work rendered the system inoperable due to being outside of TS surveillance requirement 4.5.2.a. Consequently, the TS action statement was not l
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entered and no Station Log Book entry was completed.
During further review of the licensee's administrative procedures the inspectors determined that SAP-205, " Status Control and Removal and Restoration," Rev. 8, states that if a system is required to be operable and is found to be inoperable or made i inoperable except when being tested under a surveillance testing procedure then a I removal and restoration (R&R) checksheet should be implemented. Additional guidance l
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is supplied by Operations Management Standard (OS) 002, " Work Control Standard,"
Rev. 2, which states that if a surveillance is in progress over shift turnover then an R&R should be written. Interviews with operations personnel indicated to the inspectors that there were different interpretations of what the OS guidance meant. The licensee stated that they would review and address any confusion related to completing an R&R form and required log entries. j Technical Specification (TS) 6.8.1.a requires that written procedures be implemented covering the activities recommended in Appendix "A" of Regulatory Guide (RG) 1.33, Revision (Rev.) 2, February,1978. RG 1.33, Appendix "A", paragraph 1.h identifies log entrias, record retention, and review procedures as typical safety-related activities that should be covered by written procedures. SAP-204 states that a Station Log Book entry shall be made for "any LCO action entry not covered by an R&R." The inspectors identified the failure to document entry into TS LCO action statements in the Station Log Book during preventative maintenance to be a violation of NRC requirements. The licensee wrote Condition Evaluation Report (CER) 98-1007 to address these failures to document entry into TS action statements. The corrective actions include training i operations personnel on entry into TS action statements, specifically TS 3.5.1 and 3.5.2 l and the required documentation. Additionally, the preventative maintenance activities j related to the accumulator discharge valve breaker and the Charging /High Head Safety !
Injection Cross-connect valve will be scheduled for refueling outages to preclude
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3 entering action statements for these activities on-line. The projected completion date for the CER corrective actions is February 5,1999. The inspectors determined that the corrective actions adequately address the failure to enter the appropriate TS action statements and to log the entry in the Station Log Book. This is identified as Vic!ation (VIO) 50-395/98009-01, " Failure to Follow Procedure for Documenting LCO Entries, Two Examples."
c. Conclusions A violation was identified for failure to document entry into Technical Specification Action statements. Operations personnel failed to recognize preventative maintenance activities placed the ECCS Accumulators and ECCS Subsystems outside the conditions established by surveillance requirements. This condition resulted in the failure to meet the Technical Specification Limiting Conditions for Operation and, as a result, operations personnel failed to document entry into TS Action ctatements in the Station Log Book.
O2 Operational Status of Facilities and Equipment O2.1 Enaineered Safety Feature System Walkdown a. Inspection Scope (71707)
The inspectors conducted detail inspections of the Reactor Building Spray (RBS) and Residual Heat Removal (RHR) systems.
b. Observations and Findinas The inspectors conducted detail system walkdowns of the accessible portions of the RBS and RHR systems. The inspection included verification of adequate labeling, system alignment per station system procedures, system component condition, and accuracy of the as-built drawings. No procedure discrepancies or improper valve alignments were identified. Component labeling was adequate, Although the general condition of the system components was adequate, some minor concerns, including indications of slight leakage, were identified by tho inspectors and forwarded to the system engineers for resolution. The inspectors reviewed the portions of the Final Safety Analysis Report applicable to RBS and RHR and did not identify any discrepancies. The inspectors determined that the RBS and RHR systems were capable of performing their design functions.
c. Conclusions Detailed inspection of the Reactor Building Spray and Residual Heat Removal Systems determined that the systems were in adequate condition to perform as designed. Valve alignments were proper and component labeling was adequate.
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O2.2 Cold Weather Precarations I l
a. Insoection Scoce (71707) l The inspectors conducted an independent review of the licensee's preparation for prolonged subfreezing temperature conditions.
b. Observations and Findinas The inspectors reviewed the requirements contained in Operations Administrative Procedure (OAP)-109.1," Guidelines for Severe Weather," Revision 1 A. Section 6.1 of OAP-109.1 contains the requirements for prolonged exposure to subfreezing ambient l conditions. The inspectors verified that the requirements of Section 6.1 were completed l and documented by the control room operators. Beginning on October 6, Shift Supervisors were verifying during shift turnover that freeze protection controls were in place.
Operations personnel routinely verify that the installed Electric Heat Tracing (ET) is l operating properly. The inspectors conducted a walkdown of the ET system with the ;
system engineer and verified that the heat trace circuits were in proper operating condition and that no alarms were present. The inspectors reviewed the ET system engineer's files including maintenance rule implementation, monthly system engineer walkdown inspection results and technical work records related to continuing review of ET system performance. The inspectors discussed the overall system performance with the current and former ET system engineers and concluded the system is being properly monitored within the licensee's Maintenance Rule program. The inspectors also reviewec yplicable sections of the Final Safety Analysis Report (FSAR) and concluded, based on this review and the walkdown inspection, that the freeze protection heat tracing system was properly installed to protect safety-related systems.
The installation and maintenance of heat tracing are the responsibility of the electrical maintenance group. The inspectors reviewed a recent heat tracing Maintenance Work Request, MWR 9816036, which repaired heat tracing circuits related to the Condensate Storage Tank Outlet and Outlet Bypass Line. Walkdown of the affected piping revealed the insulation metal Jacket and banding material were not reinstalled after the heat tracing repair was completed on November 11. The inspectors discussed this with maintenance personnel who indicated the material was on order and would not be replaced until after the close of the inspection period (November 21). The recently repaired heat tracing and related insulation were protected from the weather by clear plastic sheeting. After discussion with the system engineer, the inspectors concluded that this arrangement would not prevent the system from performing its design function.
As part of the licensee's cold weather protection program, Electrical Maintenance j Procedure (EMP)-120.002, " Freeze Protection Heat Tracing Inspection," Revision 3,
- was completed on November 9 under Preventative Maintenance Task Sheet PMTS l
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9811216. Minor problems were identified and corrected by the licensee. The inspectors reviewed paperwork associated with EMP-120.002 and independently walked down the level sensing lines associated with the Condensate Storage Tank and the Refueling
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l Water Storage Tank. The insulation and heat tracing equipment for these lines were in l good condition. The inspectors noted concerns with field labeling for the Condensate l Storage Tank (CST) heat trace modules. These heat trace modules, which were not i specifically labeled as CST modules, are located in the Reactor Makeup Water Storage Tank Heat Tracing Control Panel. Failure of CST heat trace modules would be ,
indicated in the control room by actuation of the Reactor Makeup Water Storage Tank l low temperature annunciators. The associated Annunciator Response Procedure (ARP) ,
"ARP-002-XPN-6031," Revision 1, did not indicate the Reactor Makeup Water Storage l Tank Heat Tracing Control Panel supports the safety-related, risk-significant CST heat '
tracing circuits. The inspectors were concerned that the lack of specific labeling could delay timely restoration of CST heat tracing following a failure. Operations Management was responsive to these concerns and indicated field labeling would be improved and procedure enhancements would be implemented to include additional ARP j
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supplemental compensatory actions for responding to heat tracing alarms.
c. Conclusions A review of the licensee's cold weather protection program revealed no significant I discrepancies. The system engineers interviewed were knowledgeable and the heat trace system performance was being properly monitored within the licensee's Maintenance Rule program.
11. Maintenance M1 Conduct of Maintenance M1.1 Observation of Work Activities (62707 and 61726)
The inspectors observed ali or portions of the maintenance and surveillance testing activities listed below.
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. STP 501.002 Battery Quarterly Surveillance Test Number 1 Critical Surveillance l Test, Revision 9 I STP 503.003 Functional Test of Sc;vice Water to Emergency Feedwater Cross Connect Circuit, Revision 7 l
. STP 125.004 Diesel Generator Load Rejection Test, Revision 7 STP 125.002 Diesel Generator Operability Test, Revision 18 ;
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. STP 125.013 Diesel Generator Semiannual Operability Test, Revision 6
. ICP 370.006 Reactor Building Spray Pump B Discharge Pressure IPT07377, Revision 2
. STP 215.001 A Reactor Building Personnel Airlock Test
. WR 9813466 Main Vent Airflow measurements
. WR 9817210 Pressure Verification to XUM02801B-PRI-MS l . WR 9812954 B Diesel Generator Motor Lubrication
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. WR 9813088 Diesel Generator Engine Quarterly Maintenance
. WR 9806826 EG-B Unit Replacement For Diesel Generator B
. WR 9806414 EG-A Unit Replacement For Diesel Generator B I
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The inspectors generally found the work performed during these activities to be professional and thorough. All work was performed with the work package present and actively referenced. Technicians were experienced and knowledgeable of their assigned tasks. The inspectors observed that supervisors and system engineers often monitored job progress. The inspectors forwarded minor concerns to licensee management for resolution.
c. Conclusions in general, performance of maintenance and surveillance testing was professional and thorough. All work was performed with the work package present and actively referenced. Technicians were experienced and knowledgeable of their assigned tasks.
M1.2 Troubleshootina Work Activities Associated with the Breaker for FCV-602A a. Inspection Scope (62707)
The inspectors observed portions of maintenance and troubleshooting activities on the A Residual Heat Removal (RHR) pump miniflow valve FCV-602A breaker XMC1DA2Y18AD.
b. Observations and Findinas On October 14,1998, the inspectors observed troubleshooting activities on breaker XMC1DA2Y18AD for the motor operated A train RHR miniflow valve FCV-602A. The breaker tripped open during performance of Surveillance Test Procedure (STP)-
205.004, " Residual Heat Removal Pump and Valve Operability Test," Revision 3, during the previous night shift. The operations department declared the A Train of RHR system out of service at 3:00 a.m. on October 14. Preliminary checks including visual, meggaring and micro-ohm checks of the breaker did not identify any physical problems.
FCV-602A was manually stroked and did not exhibit indication of binding. The inspectors observed the breaker removal for bench testing and troubleshooting under Work Order 9815071/ EMP 280.004, Molded Case Circuit Breaker Testing," Revision 14. The observed testing was conducted in accordance with the procedure and the breaker was verified to be operating properly.
With the breaker in proper operating condition, troubleshooting then focused on the performance conditions associated with STP-205.004 as a possible cause.
Investigation by the troubleshooting team determined that the sequence of steps in STP-205.004 could result in valve FCV-602A receiving a close signal while the valve is still going open. When FCV-602A reaches the full open position, the presence of the close signal results in a sudden reversal of the motor direction causing the breaker to trip open. As a result, FCV-602A would remain in the full open position.
Condition Evaluation Report (CER) 98-0907 was written to document the evaluation of this failure mode for the effects on the RHR system in normal and accident configurations. The inspectors observed the presentation of the CER results to the Plant Safety Review Committee (PSRC) on October 16. The disposition concluded that
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the existing mini-flow setpoints may result in tripping of the circuit breaker for the mini-flow valve. A similar condition was the subject of Westinghouse Nuclear Safety Advisory Letter NSAL-98-002," Potential Common-Mode Failure of Residual Heat Removal Pumps During Intermediate Break Loss of Coolant," issued on July 9,1998.
Based on a review of NSAL-98-002 and the CER dispostion, the licensee concluded that the condition does not result in a loss of safety function. The bounding analysis assumptions were met for both normal and accident RHR system alignments because system design functions can be achieved with the miniflow valve failed open . RHR train A was declared operable on October 16. Corrective actions for this condition included procedure changes to STP-205.004 to preclude test induced dual signals to the A or B train RHR pump mini-flow valves FCV-602A/B. The inspectors reviewed the CER disposition and the procedure revisions and concluded that the revisions were sufficient to prevent recurrence of the condition experienced.
c. Conclusions The inspectors observed technically sound troubleshooting activities to determine the cause for tripping of the motor operated valve FCV-602A breaker during surveillance testing. The root cause was identified and procedure revisions were implemented to prevent recurrence. Train A of the RHR system was restored to operable status within the Technical Specification (TS 3.5.2) Limiting Conditions for Operation Action Statement allowed outage time.
M1.3 Observation of Year 2000 Testina on Control Room Recorders a. Inspection Scoce (61726)
The inspectors observed and reviewed year 2000 (Y2K) testing of control room recorders.
b. Observations and Findinas On October 27,1998, inspectors observed the performance of year 2000 testing conducted under work request 9813373 " Perform Y2K Testing on Chessell Model 344 Recorders on the Main Control Board (MCB)." The observed testing included LR 459 Pressurizer Level and PR 444 Pressurizer Pressure recorders. Nine of ten tests performed were satisfactory. The unsatisfactory test identified that this type of recorder does not rollover to the year 2000 when normal power is turned off and the century change occurs while on backup power. Once normal power was restored, the recorder would revert to the date January 1,1996. This same condition was identified to occur for all recorders of this type in the control room. Reverting to January 1,1996 has no safety significance in that the recorders continue to display accurate parameter indications. The only affect is an incorrect date stamp. The incorrect date stamp can be corrected by reprogramming the recorder after the century change. The inspectors noted that the recorders do not have control functions. The maintenance and vendor technicians performing the tests were knc@dgaable concerning the Y2K tests and demonstrated good work practices. The inspectors noted that the recorders PR 444 and LR 459 were not listed on the original work scope, but a vendor technician identified that these recorders should be within the work scope during performance of other
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control room recorder testing. The licensee corrected this omission and added these l recorders to the control room recorder work scope. The inspectors determined this to l be a minor deficiency in pre-job scoping. Inspectors review of data for other control l' room recorders identified no additional concerns.
c. Conclusions Observed year 2000 (Y2K) testing of control room recorders was performed l
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satisfactorily. No safety significant concerns were identified with the testing results. The !
maintenance and vendor technicians performing the tests were knowledgeable of the Y2K tests and demonstrated good work practices.
L M1.4 Emeroency Diesel Generator B Governor Reolacement a. Inspection Scooe (61726 and 62707) :
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The inspectors observed portions of the B Emergency Diesel Generator (DG B) ;
electrical control unit EG-A and hydraulic actuator unit EG-B governor replacement. i Maintenance and operability testing and associated documentation were reviewed.
b. Observations and Findinas On November 18,1998, the licensee entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement of Technical Specification 3.8.1, A.C. Sources, for the replacement of EG-A and EG-B on DG B.
Other maintenance work was performed as well, including relay calibrations and minor mechanical repairs. The licensee encountered difficulty in the setup of the replacement EG-A and EG-B and ultimately reinstalled the original EG-A and EG-B. The inability to i l complete setup of the replacement units will be analyzed within the licensee's root .
- . cause evaluation program.
The inspectors noted that maintenance personnel responsible for the replacement and setup of EG-A and EG-B received vendor training on November 17. A review of the training material indicated that the information was adequately detailed and appropriate for the maintenance activities. The inspectors determined that the training was pro-active and timely. !
l in general, the observed activities were performed without complication. Licensee personnel were knowledgeable and well informed. Supervision was actively involved in the work, providing additional guidance when required.
j During EG A and EG-B setup runs, the diesel generator output breaker failed to close ;
twice and the DG tripped once from mechanical overspeed. The licensee determined that the failure of the output breaker to close resulted from starting the diesel remotely in ;
the control room followed by a transfer to local control of the DG. During the transfer, l the manual start seal-in circuit deenergized and was not re-instated by depressing the l ." Test Start " push-button on the DG local control panel. The licensee is in process of l enhancing the applicable procedures to provide more detailed guidance. The condition !
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of the DG circuits caused by the transfer would not prevent closure of the feeder breaker during an emergency start of the DG.
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l The system engineer ostermined that the overspeed trip occurred due to adjustments to l
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EG-B during setting of the electrical droop. Because engine speed is not recorded and the overspeed trip setpoint is not currently tested, the maximum DG speed at the time of 1 the trip could not be determined. Because of the vendor's initial setting and testing of l the overspeed trip device, the licensee is confident that the mechanical overspeed set j point was between 110 percent and 112 percent. After the overspeed trip, maintenance personnel examined the DG exterior components for possible damage from the overspeed. No damage was identified. Further, operations monitored DG parameters l during the maintenance runs following the overspeed trip and verified the parameters l remained within the expected ranges. The licensee stated that an overspeed test will be I developed to monitor overspeed trip setpoints.
Due to the inability to adjust and satisfactorily complete DG B setup runs for the replacement governor units, the licensee reinstalled the original governor units.
I Following re-installation and set-up of the original EG-A and EG-B and completion of i operability surveillances, DG B was declared operable within the TS Action statement l allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. ;
! The licensee initiated a root cause investigation to determine the cause for the inability
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to set-up the replacement governor units EG-A and EG-B. The inspectors verified that root cause team members were appropriately selected and knowledgeable.
c. Conclusions 4 in general, planning for governor replacement on B Emergency Diesel Generator was !
! adequate. Licensee personnel performing the maintenance were knowledgeable and l well informed and supervision was actively involved in the work. Due to the inability to adjust and satisfactorily complete setup runs for the replacement governor units, the licensee reinstalled the original governor units.
l M1.5 Imolementation of Generic Letter (GL) 96-05. " Periodic Verification of Desian-Basis Caoability of Safetv-Related Motor-Ocerated Valves" a. Inspection Scoce (Temocrarv instruction 2515/140)
l l This inspection assessed the licensee's implementation of GL 96-05 which requested l licensees to establish programs to periodically verify that safety-related motor-operated valves (MOVs) are capable of performing their safety functions within the current
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licensing bases.
Prior to this inspection, the licensee responded to the recommendations of GL 96-05 in I letters to the NRC dated November 7,1996; March 13,1997; and April 2,1998; and described its long-term MOV periodic verification program. On October 8,1998, the licensee provided additional information concerning its GL 96-05 program in response to a request from the NRC staff. The licensee's letters described plans to participate in a i
program developed by a Joint Owners Group (JOG) on MOV Periodic Verification. This l JOG Program was reviewed by the NRC staff and determined to be acceptable with certain conditions and limitations documented in a safety evaluation issued October 30, 1997. The JOG program consists of three phases: (1) an interim MOV static diagnostic l
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test program with a test frequency based on the risk significance and capability margin l of each MOV; (2) a program of repetitive MOV dynamic tests at participating nuclear
) power plants with a total of more than 100 MOVs to be tested over a 5-year period; and i i
(3) a long-term periodic test program based on the results of the MOV dynamic tests.
The inspection assessed the licansee's program to determine whether it was consistent with the licensee's commitments and with the recommendations of GL 96-05. The inspection was conducted through reviews of documentation and interviews with licensee personnel. In assessing the adequacy of the licensee's GL 96-05 program, the inspectors selected a sample of MOVs based on dynamic test data availability, valve type, and risk significance for evaluation of implementation of the program. The MOV sample was as follows:
XVB-3116A Service Water Pump "A" Discharge Valve l (Henry Pratt 24-inch butterfly valve - high risk category)
XVG-2802A Main Steam to EFW Pump Turbine Isolation Valve (Anchor-Darling 4-inch flexible wedge gate valve -
medium risk category)
XVG-3107A SW Pond RBCU Return isolation Valve (Anchor Darling 16-inch flexible-wedge gate valve -
high risk category)
- XVG-31098 RBCU Discharge Isolation Valve (Anchor-Darling 10-inch flexible-wedge gate valve -
high risk category)
XVG-80000 Pressurizer Power-Operated Relief Valve (PORV) Block Valve (Westinghouse 3-inch flexible wedge gate valve -
medium risk category)
- XVT-8109C Charging /SI Pump C Miniflow Isolation Valve (Velan 2-inch under-seat-flow globe valve -
medium risk category)
The inspectors reviewed test packages and calculations for the above MOVs. Other documents reviewed included:
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Engineering Services Technical Report TR01520-001, " Generic Letter 89-10/96-05 Motor-Operated Valve Setup, Test, and Performance Validation Summary Report," Revision 3, October 13,1998.
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Calculation DC01520-065," Design, Review and Capability of Rising Stem MOVs i in the CC, EF, MS, RC, SP and SW Systems," Revision 9, October 12,1998, l
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Calculation DC01520-089,"GL 8910 MOV Scope, Grouping and Engineering Justification," Revision 8. September 30,1998.
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Calculation DC01520-090," Design Review and Capability of Henry Pratt Generic Letter 89-10 Motor Operated Butterfly Valves," Revision 3, October 2,1998.
. Nuclear Operations Station Administrative Procedure SAP-1250," Motor
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Operated Valve Program," Revision 2 October 16,1998.
Revision 0, October 13,1998.
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Letters dated November 7,1996; March 13,1997; and April 2 and October 8, 1998, from Gary J. Taylor to NRC providing information on the Summer GL 96-05 program.
b. Observations and Findinos
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1. Commitments to GL 96-05 (Tl 2515/140. Paraaraoh 03.01)
The licensee's response letters to GL 96-05 indicated it would participate in the JOG Program on MOV Periodic Verification. However, the licensee did not fully commit to
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implement the JOG program. Instead, the licensee indicated that it would exchange information with the JOG and that it would incorporate data received from the JOG, as appropriate. In discussions with the inspectors, the licensee indicated this was due to 1 uncertainty tegarding the JOG long-term testing criteria to be determined following completion of the JOG initial 5-year dynamic test program. During the inspection the licensee determined that it would provide a more definitive commitment to implement the JOG program. This was accomplished in a letter dated November 2,1998, which stated that the licensee would meet or exceed the JOG Program described in Topical Report MPR-1807, Revision 2. The letter further stated that the licensee would provide justification and notify the NRC of any (future) significant deviations from the JOG Program. The inspectors evaluated the licensee's GL 96-05 program as an implementation of the JOG Program.
2. GL 89-10 Lona-Term Actions (Tl 2515/140. Paraaraoh 03.02)
In NRC inspection Report (lR) 50-395/97-01 (dated April 17,1997), the NRC closed its review of the program implemented by the licensee in response to GL 89-10, " Safety- ,
Related Motor-Operated Valve Testing and Surveillance," based on the licensee's l actions to verify the design-basis capability of its safety-related MOVs. In IR 50-395/97- j 01, the inspectors noted several long-term planned actions by the licensee to address weaknesses in the MOV program involving assumptions for valve factor, load sensitive behavior, and stem friction coefficient in its MOV calculations. Information on the licensee's action to address MOV valve factors was documented in NRC Inspection Report 50-395/98-06. In its letter dated October 8,1998, the licensee stated that stem friction coefficient and load sensitive behavior continue to be monitored as part of the GL 96-05 program. During this inspection, the inspectors verified that the licensee was addressing the planned actions discussed in IR 50-395/97-01.
In GL 89-10, the NRC staff recommended that MOV performance be trended on a long-
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term basis. In Engineering Services Procedure ES-513, the licensee specified that a
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summary report be prepared for trending MOV performance every 2 years. In Engineering Services Technical Report TR01520-001, the licensee provided the most recent MOV performance trending report including GL 96-05 test results. Based on the sample of MOVs, the inspectors verified that the licensee ~was adequately analyzing and trending MOV performance.
3. GL 96-05 Proaram (Tl 2515/140. Paraaraoh 03.03)
The licensee described its overall MOV program in Nuclear Operations Station Administrative Procedure SAP-1250. In their review of the program and other implementing documents, the inspectors found that the licensee's GL 96-05 program was being developed and implemented in accordance with the licensee's quality assurance program. The inspection findings for specific aspects of the licensee's GL 96-05 program were as follows:
Scope of MOVs included in the Proaram The MOVs included in the licensee's GL 96-05 Program and the criteria for their selection were provided in Calculation DC01520-089 and Engineering Se rvices Technical Report TR01520-001. The inspectors found the selection crit 9ria consistent with the recommendations of GL 96-05. The program included 83 gate valves,21 butterfly valves, and 16 globe valves. Based on a sample review of the MOVs, the inspectors found that the scope of MOVs included in the licensee's MOV program was consistent witn the recommendations of GL 96-05.
MOV Desian Basis Engineering Services Procedure ES-513 specified that MOV design data would be included in the MOV design calculations. The inspectors found that the licensee was maintaining Calculations DC01520-065 and -090 up to date with respect to new data on MOV capability. The inspectors also noted that the licensee had included information from its review of MOVs for potential pressure locking in Engineering Services Technical Report TR01520-001 (for example, MOV XVG-8000C). Based on review of the sampled MOVs, the inspectors found that the licensee was maintaining an up to date design basis for GL 96-05 MOVs.
Dearadation Rate for Potential increase in Thrust or Toraue Operatina Reauirements The licensee's participation in the JOG dynamic test program was indicated in Engineering Services Technical Report TR01520-001. Dynamic tests of two MOVs were being performed as part of the licensee's participation in the JOG program and four additional MOYs were being dynamically tested for plant-specific information to help identify potential age-related degradation.
Calculation DC01520-089 discussed the grouping of GL 96-05 MOVs for sharing test data, including information on potential degradation of valvo performance. In Engineering Services Technical Report TR01520-001, the licensee provided a matrix identifying the groups of GL 96-05 MOVs that were to be used for age-related degradation evaluation. The groups were established using JOG Program guidance
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and were based on similarities in valve design, materials, and application of the valve (including fluid conditions). The licensee performed a review and determined that the GL ,
96-05 MOVs and their applications were within the scope of the JOG program or would I be covered by actual test data. Based on a review of sample MOVs, the inspectors found that the licensee was adequately addressing the scope of the JOG program. The .
inspectors found that the licensee's detailed evaluation and grouping of MOVs to help l identify valve age-related degradation was a positive aspect of the licensee's program. I In TR01520-001, the licensee specified a goal of m&+aining 10% margin in the l capability of the safety-related MOVs above uncertamties associated with MOV l calculations and measurements (such as test equipment inaccuracy, torque switch repeatability, load sensitive behavior, spring pack relaxation, and stem lubrication degradation). Any MOV determined to have less than 10% margin was required to be evaluated for acceptability. The inspectors found that the licensee had established an acceptable degradation assumption for its current interim static diagnostic tect program.
Dearadation Rate for Potential Decrease in MOV Motor Actuator Outout The licensee described the actions which would be performed to monitor degradation of parameters affecting MOV motor actuator output in Engineering Services Procedure ES-513 and Calculation DC01520-089. Consistent with its requirements, a computerized trending program had been established to monitor changes in MOV parameters that could indicate degradation in MOV motor actuator output. The inspectors found that the parameters trended in this program were appropriate and included stem friction coefficients when opening and closing the valve under static and dynamic conditions; stem loads, motor running current and power during opening and closing the valve; and load sensitive behavior.
Regulatory Tracking System (RTS) entry IEN960048-11 recorded that the design-basis capability of the rising stem GL 96-05 MOVs with Limitorque actuators had been revised to address Limitorque Technical Update 98-01 and its Supplement 1 by implementing a motor actuator output methodology deve'oped by Commonwealth Edison Company (Comed). In a sample review, the inspectors found that Calculation DC01520-065 (for rising stem MOVs in several systems) had been revised to incorporate the Comed methodology. Also, the inspectors found that RTS IEN960048-11 established a plan for the licensee to revise the calculations for GL 96-05 butterfly valves to incorporate the new limitorque guidance and that the affected MOVs had already been evaluated and determined to have acceptable capability. The inspectors confirmed that Calculation DC01520-090 for butterf!y valves had been revised to use a " pullout" efficiency consistent with the new Limitorque guioance. RTS IEN960048-11 indicated that the licensee also planned to incorporate the use of a 0.9 application factor as recommended by Limitorque in the butterfly valve calculations by December 31,1998.
The inspectors found that the licensee had justified its determination of MOV motor actuator output and had established adequate plans for monitoring potential degradation of actuator output, including consideration of the new guidance on motor actuator output from Limitorque. However, the inspectors noted that the licensee's written description of requirements for evaluating and trending potential degradation of MOV motor actuator l
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output was very limited. The licensee agreed with the inspectors and indicated that action would be taken to strengthen the description.
Periodic Test Method The licensee established an interim program of periodic static diagnostic testing to aid in monitoring the capability margin of its GL 96-05 MOVs during performance of the JOG dynamic test program. The inspectors found that the frequency of static diagnostic testing for each specific GL 96-05 MOV was based on its margin and risk ranking, as described in the licensee's Engineering Sentices Technical Report TR01520-001. In addition, the inspectors found that the licensee also performed motor power testing of each GL 96-05 MOV approximately every 18 months to help trend MOV performance.
The inspectors compared the risk ranking methodology applied by the licensee in determining static test frequency to that contained in Westinghouse Owners Group (WOG) Engineering Report V-EC-1658, which had been accepted by the NRC staff with certain conditions and limitations (safety evaluation issued April 14,1998). In addition, the inspectors compared the licensee's static test frequency criteria with interim criteria recommended by the JOG. The inspectors found that the licensee's risk ranking and static test frequency criteria were similar to, and in some cases, more conservative than those recommended by the WOG and JOG. Based on review of the test methods and frequencies specified by the licensee, the inspectors found that the licensee had established periodic test methods for identifying the degradation of valve operating requirements and actuator output that were currently adequate, pending completion of the JOG dynamic test program and establishment of the JOG long-term testing criteria.
l MOV Performance Evaluatiorj The licensee's Engineering Seivices Procedure ES-513 provided guidance for the evaluation of MOV static and dynamic diagnostic test results. In addition, ES-513 described the qualitative and quantitative trending of MOV performance through the ;
review of the MOV diagnostic test results (including static and dynamic testing, and l MOV motor power surveillance testing), MOV fai!ure and deficiency information (such as nonconformance notices and maintenance work requests), and industry MOV information (such as JOG letters and vendor notices). i The results of static and dynamic diagnostic tests of GL 96-05 MOVs performed by the licensee were documented in Engineering Services Technical Report TR01520-001. It included results from repetitive dynamic tests of two MOVs which the licensee performed as part of its participation in the JOG program and reported that the test information was provided to the MG for further evaluation of potential degradation in valve performance. TR01520-N worted that the licensee was also performing repetitive dynamic tests of four othe WVs and static tests of substantially allits GL 96-05 MOVs to aid in determining potential age-related degradation.
The licensee's trending program for MOV test results included motor power / current, open/close stem friction coefficient, valve operating torque, running load / packing load, seating thrust and unseating thrust, and valve capability / margin. In TR01520-001, the licensee summarized the MOV performance trends over the past 2 years based on review of in-plant and industry MOV activities, and a detailed review of Summer static
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15 and dynamic MOV test data. No significant adverse trends were identified. Based on their review, the inspectors found that the extensive trending of MOV performanca by qualitative and quantitative methods initiated by the licensee was a positive aspect of the licensee's program.
The inspectors found that the licensee's procedures and documentation were i acceptable for evaluating MOV diagnostic test data and for providing feedback of l plant-specific and JOG information. i MOV Test Interval ,
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The inspectors found that the licensee was participating in the JOG dynamic test I program and had initiated an interim periodic static diagnostic test program to aid in monitoring MOV capability margin. The licensee was also monitoring potential I degradation in MOV motor actuator output through the periodic static testing and through in-plant dynamic testing. The test intervals for the licensee's tests were stated in Engineering Services Technical Report TR01520-001. MOVs in groups 4,8,9,10, 18,22,25,26,27 and 31 were assigned an interim static diagnostic test interval of 10 years or six refueling outages. The inspectors noted that the licensee's testing matrix did not specify that the data would be obtained over the first 5-year interval to provide confidence in MOV performance over the full 10-year interval (as discussed in the NRC ,
etaff evaluation dated October 30,1997, on the JOG program). The licensee stated that I normal MOV maintenance activities were expected to result in sufficient testing to provide data for the first five year interval but that further action would be taken to l assure this MOV test scheduling. The inspectors found that the licensee had justified a I periodic test interval that ensures the continued MOV design-basis capability until the l next scheduled test.
c. Conclusions Based on a review of sample MOVs, licensee letters, csiculations, test packages, procedures and engineering reports; the inspectors determined that the licensee had established and was implementing a program to provide continued assurance that MOVs within the scope of GL 96-05 were capable of performing their design-basis safety functions. The information obtained during the inspection will applied in the preparation of an NRC safety evaluation on the response of the licensee to GL 96-05.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Licensee Event Report (LER) 50-395/98001-01: plant shutdown due to failed mechanical governor on the A emergency diesel generator. This issue was identified as inspector Follow-up Item (IFI) 97013-01, " Licensee's Effort to identify the Root Cause and Corrective Action for the A Diesel Generator Problems." The issue was also discussed in NRC Integrated Inspection Report Nos. 50-395/97-14,50-395/98-01 and 50-395/98-02. IFi 97013-01 was closed in NRC Integrated inspection Report Nos. 50-395/98-02. The inspectors reviewed the final corrective actions and A Emergency Diesel Generator performance since replacement of the governor control units and
verified completion of the corrective actions. The inspectors did not identify any additional concerns.
M8.2 (Closed) LER 50-395/98002-00: 10 LFR Part 21 report on failed Electrical Governor (EG-A) on the A Emergency Diesel Generator. An EG-A controller, which had been refurbished and tested by a vendo". failed the licensee bench testing. The licensee's l investigation determined that the fidare resulted from inadequate post-refurbishment bench testing by the vendor. Original post-refurbishment testing did not identify intermittent failures. Corrective cctions included repair of the EG-A, establishing requirements for extended burn-in periods, and bench testing to detect intermittent failures. The inspectors reviewed the corrective actions and did not identify any concerns.
M8.3 (Closed) LER 50-395/97006-00: Technical Specification breaker alignment surveillance not performed due to personnel error. This issue was discussed in detailin NRC Integrated inspection Report 50-395/97-13 and identified as NCV 97013-03, Failure to Follow TS action requirements of TS 3.8.1.1.b.1, A.C. Sources. Once identified, the missed surveillance was completed satisfactorily. Further corrective actions included procedure enhancements to identify the personnel responsible for tracking and ensuring the timely completion of compensatory actions including technical specification action items. Although, a timer was also provided to the control room supervisor as an audible l aid for tracking the required surveillance due times, the inspectors noted instances when the timer was not used by operations personnel. Following discussions between the inspectors and operations management, the licensee stated that management expectations for use of the timer would be reviewed. The inspectors reviewed the completed corrective actions and did not identify any additional concerns.
M8.4 (Closed) URI 50-395/97013-02: Failure to make administrative changes to the snubber testing program. During the Fall 1997 refueling outage (RFO-10), the licensee replaced reactor building mechanical snubbers that were subject to surveillance testing. Snubber replacement, rather than removal, M;, and reinstallation of the existing snubbers, required only one trip to each snuW ;ocation and therefore reduced the time maintenance personnel were exposed to reactor building radiation levels. On October 16,1997, the results of a Quality Assurance (QA) review of snubber testing were documented in CER 97-1070. The CER identified administrative deficiencies with the testing documentation, including performance of pre-service testing without an approved Surveillance Test Task Sheet (STTS) and inappropriate use of the " retest" section on the STTS form.
Prior to placing replacement snubbers in service, the licensee tested each new snubber in accordance with STP-803.003, " Mechanical Snubber Operational Test," Revision 5.
Station Administrative Procedure (SAP)-134," Control of Station Surveillance Activities,"
Revision 9, Step 6.4.6 states that the " test performer shall ensure that all test data sheets reflect the applicable STTS number." The licensee's administrative process for snubber surveillance testing generated an approved STTS, including an STTS number, for snubber testing at each installation location within the plant. Since the licensee tested the replacement snubbers prior to determining their final installation location, the licensee performed pre-service testing of each replacement snubber without an approved STTS. Consequently, an STTS number was not recorded on Attachment 111 to
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i 17 j STP-803.003, " Pre-service Operational Test Data," when pre-service test data was obtained. When the licensee determined the final installation location for a replacement snubber, the STTS number associated with that location was recorded on the STP- ,
803.003, Attachment 111 data sheet.
l The CER also identified that the STTS form was not used in accordance with SAP-134, in that the performance of pre-service testing for the replacement snubbers was documented in the " Retest" section of the STTS form. SAP-134, Section 4.8, defines
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Retest as "the follow-up test of a surveillance activity whose results did not meet the I minimum acceptance criteria, or a test that was terminated prior to completion." CER 97-1070 reported that none of the twenty-eight completed snubber STTSs reviewed had a documented test deficiency. Use of the " retest" section of the STTS to document the results of pre-service testing on replacement snubbers was inconsistent with the
requirements of SAP-134. Similar deficiencies also occurred for testing performed per STP-803.002, " Mechanical Snubber, Visual Examination." In order to resolve the inconsistency between the actual plant practices and the snubber testing procedures, the CER included a recommendation to revise the snubber testing procedures to reflect the actual testing methodology. The licensee deferred revising the snubber testing procedures until after the refueling outage. The reactor building snubber testing was ;
completed with the existing procedures. l The inspectors concluded that reactor building snubber test results were not i documented in accordance with the requirements of the station surveillance testing !
procedures in use during the RFO-10 outage. Because the applicable adminhtrative and surveillance testing procedures did not recognize the snubber testing and replacement methodology used by the licensee during RFO-10, these procedures could not work as written. Station Administrative Procedure SAP-123," Procedure Use and Adherence," Revision 2, Paragraph 6.2.5 states, in part; " procedure changes are required to be completed prior to continuing with a procedure that does not work."
Contrary to SAP-123, the licensee failed to revise the surveillance test procedures prior to completing the remainder of the reactor building snubber testing activities.
On October 8,1998, the NRC Office of Investigations (01) completed an investigation regarding failure to follow procedures during snubber testing. The synopsis to 01 investigation Report No. 2-97-031 is contained in Enclosure 3. 01 concluded that there was a failure to follow procedures regarding snubber testing but there was not sufficient evidence that management intentionally or deliberately failed to follow procedures.
The failure to revise snubber testing procedures as required by SAP-123 constitutes a violation of Technical Specification (TS) 6.8.1. TS 6.8.1 states, in part, that written procedures shall be established, implemented, and maintained covering surveillance and test activities of safety-related equipment. The inspectors determined that the actual snubber testing was performed satisfactorily and there were no concerns regarding the operability of the snubbers installed in the plant. The inspectors verified that, following the RFO-10 outage, the licensee revised SAP-134 and STP-803.003 to address the procedural problems identified in CER 97-1070. This failure constitutes a violation of minor significance and is not subject to formal enforcement action.
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111. Engineerina El Conduct of Engineering E1.1 Review of Enaineerina Response to a Stroke Time Test Failure a. inspection Scope (37551)
The inspectors reviewed the licensee's response to a surveillance test deficiency for IPV-2010, Main Steam (MS) Header B Power Operated Relief Valve (PORV).
b. Observations and Findinas On October 28, STP-121.002, " Main Steam Valve Operability Test," Revision 11 A, was performed for IPV-2010, MS Header B PORV. The B MS PORV stroke time was 8.2 seconds, which exceeded the maximum limiting stroke time of 7.0 seconds. Operations personnel identified this as a test failure and generated CER S8-0976 to address the issue. The engineering evaluation, performed under Technical Work Record (TWR) MC 15002-9825, concluded that no valve degradation was indicated by the slightly longer stroke time. IPV-2010 performance was determined to be acceptable in that it was e capable of meeting its design basis maximum stroke time of 20 seconds. The valve was acceptable as-is. Following this stroke time test, the licensee revised the reference stroke time value per the requirements of ASME/ ANSI OMb-1989, Part 10, Section 4.2.1.8," Stroke Time Acceptance Criteria." V Due to miscommunication between engineering, operations and test group personnel, the valve was unnecessarily retested after the reference value was revised. The valve retest stroke time was 3.3 seconds which was less than the Inservice Testing Program minimum allowed stroke time of 4.1 seconds. A second TWR was issued to address this deficiency. This TWR determined the shorter stroke time was due to the retest occurring after the valve was isolated from the main steam system for nine hours. The valve is normally tested within one hour of isolation while at normal temperature. TWR MC 15002-9826 concluded the stroke times are well below the maximum allowed time of 20 seconds and the valve stroked smoothly, with no signs of binding. All the stroke times are acceptable for the valve to perform its design function and no fudher retest of the valve was needed. The inspectors questioned the lack of procedural guidance related to test conditions, such as testing within one hour of isolation. The licensee indicated procedure changes would be processed to address these concerns.
The MS PORVs (IPV 2000,2010,2020-MS) have a history of failing the stroke time test conducted in accordance with STP-121.002. Several CERs have been previously generated to address this condition. Under CER 97-0480, "MS PORVs Stroke Time Deviations," the licensee identified that due to the valve's air booster design, the ASME guidelines for minimum and maximum limiting stroke time testing was not a realistic indicator of valve degeneration. Nonconiormance Notice 98-0695 disposition included the processing of a plant specific relief request to address this concern. The licensee stated the targeted relief request submittal date is January 1999. The inspectors determined that, based on the review of ASME guidelines, system design basis, MS
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the B MS PORV is able to perform its design function. l
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c. Conclusions -
l The B main steam power operated relief valve was determined to be able to perform its j design function. Licensee miscommunication resulted in an unnecessary retest of the B
- main steam power operated relief valve. l
- Eti Miscellaneous Engineering issues (92903)
[ E8.1 (Ooen) Unresolved item (URI) 50-395/98006-01: Licensee controls of steam !
i. propagation barriers. The inspectors continued to review the licensee's controls for t- opening steam propagation barriers to support maintenance activities. Task Interface j Agreement (TIA)98-004, " Lack of Allowed Outage Time Guidance for Inoperable l Hazard Protection Equipment - Davis-Besse Nuclear Power Station, Unit No.1 (TAC a No. MA1667)" which provides the staff's position on controlling these types of barriers is
, included as an enclosure to this inspection report.
, E8.2 (Closed) Inspection Followuo item 50-395/97002-02: Followup on performance criteria
[ established for risk-significant structures, systems, and components (SSCs) following periodic balancing. During the NRC Maintenance Rule baseline inspection, the
inspection team expressed concern that meeting the SSC performance criteria was not b always indicative of an appropriate preventative maintenance / monitoring program. The i major concern was the potential cumulative effect on core damage frequency. During
- the licensee's periodic assessment conducted subsequent to the NRC inspection, the
. licensee evaluated the performance criteria for modifications. As part of this evaluation, I the licensee performed a sensitivity analysis which included decreasing the loss of l offsite power initiating event frequency and updating basic events with operating data i from the previous 18 months, which ended in November 1997. This resulted in a
! baseline core damage frequency of 6.65E-5 per reactor year, a decrease of 4.5 percent. .
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Also, the licensee decreased the unavailability performance criteria for the reactor trip i breakers from one maintenance preventable functional failure per year to zero. The
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licensee performed another sensitivity analysis for the highly unlikely situation of all SSCs performing at the new reliability and performance criteria. The resulting core damage frequency change was an approximate 44 percent increase.
The inspector performed an in-office review of the documentation supporting both sensitivity analyses and had no concerns with the methodology, truncation or the results. Through periodic balancing, the licensee demonstrated that the SSC performance criteria were adequate. 1
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IV. Plant Support l
- R1 . Radiological Protection and Chemistry (RP&C) Controls l l
~ RI.1 ' General Comments (71750) l l
The inspectors obsewed radiological controls during the conduct of tours and observation of maintenance activities and found them to be generally acceptable.. Minor concerns were forwarded to health physics personnel for resolution.
R4- . Staff Knowledge and Performance in RP&C -
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R4.1 Removal of the Hioh Inteority Container a. Insoection Scooe (71750) '
The inspectors observed the removal of a RADLOK-195 High Integrity Container (HIC),-
a large radwaste container, from the auxiliary building location to the transport truck for shipment to Barnwell, South Carolina.
b. Observations and F indinos l
The HIC was filled with spent resin and was to be transported to Bamwell, SC, for final l
- oisposal. Radwaste personnel coordinated the removal of the HIC to the transport truck. Radwaste,- Health Physics (HP) and maintenance personnel participated in the '
activity. The radiation fields around the HIC were measured to be to approximately 4.5 rem at a distance of one foot. In the interest of maintaining personnel radiation exposure as low as is reasonable achievable (ALARA), the licensee emphasized coordination of activities for the removal of the lead aprons and scaffolding installed around the HIC. The inspectors verified that all required postings, flashing lights and boundaries for the high radiation area were in place and accurate. HP personnel designated specific activities with pre-determined goals to limit individual exposure. The inspectors determined through observation and interviews that all of the participants understood the radiological conditions and the importance of the stay times. The inspectors also noted that a diagram of a current radiological surveillance was readily available.- The diagram included recommended low dose staging areas.
Radwaste personnel were familiar with the requirements for transporting the HIC. Prior to movement of the HIC, the licensee identified a need to ensure a different sling arrangement for the lift of the HIC was qualified. The vendor determined that the new sling arrangement was technically adequate. The South Carolina Department of Health and Environmental Control (DHEC) identified the vendor's supporting calculation as sufficient. The inspectors noted that a thorough pre-job brief was held prior to the start
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c. Conclusions The removal of the large radwaste high integrity container was well coordinated, resulting in limited personnel exposure. The pre-job planning and the designation of pre-determined goals for specific activities also contributed to limiting personnel radiation exposure.
P2 Status of EP Facilities, Equipment, and Resources P2.1 Early Warning Siren Control System Surveillance Review a. Inspection Scope (71750)
Inspectors reviewed performance of Early Warning Siren Control System (EWSS)
surveillance and the associated procedures, b. Observations and Findinas The inspectors reviewed the results of surveillance testing and associated procedures for the Early Warning Siren Ccntrol System. On November 9,1998, PMTS 9814097
"EWSS Silent Test" was completed with no discrepancies identified; all 106 sirens responded properly. On November 11, PMTS 9813883 "EWSS Monthly Siren Growl Test" was performed satisfactorily with 103 of 106 sirens, or 97 percent, responding properly. Two of the three defective sirens were repaired and successfully tested by November 12. Repairs included replacing a blown fuse and a faulty relay. The third i siren, F12, had a sound output failure which required a circuit board power supply l replacement. At the close of the inspection period, the licensee was waiting on parts to l allow completion of the repair, inspectors reviewed Emergency Plan Procedure (EPP)-026," Operation of the Siren i Control System," Revision 1, and EPP-021 " Activation of the Early Warning Siren System (EWSS)," Revision 17A, with emergency planning personnel. The procedures contained appropriate instructions to notify the duty Emergency Planning (EP)
representative and repair groups when the percentage of operable sirens was below 85 percent. If the system percentage drops below 75 percent, the shift supervisor declares the system inoperable and implements EPP-001 " Activation and implementation of the Emergency Plan," Revision 24. Emergency Action Level (EAL) classification for EWSS inoperability was formerly an Unusual Event, however, it is now reportable under 10 CFR 50.72(b)(1)(v) for any event that results in a major loss of emergency assessment capability, offsite response capability or communications capability. EPP-001 was reviewed and found to have been updated to reflect this change, however, procedures EPP-026 and EPP-021 had not been updated. Emergency planning personnel were responsive to this issue by processing revisions to EPP-021 and EPP-026 to reflect the reporting requirements contained in Nuclear Licensing Procedure, NL-122 " Regulatory Notification and Reporting."
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c. Conclusions l
Surveillance activities for the Early Warning Siren Control System demonstrated ,
satisfactory performance of the equipment. Emergency planning personnel were i responsive to correcting an identified procedure deficiency associated with notification of siren system inoperability.
F2 . ' Status of Fire Protection Facilities and Equipment i F2.1 Pre-Fire Plan Auxiliary Buildina Eouioment Review I l
a. Insoection Scope (71750)
The inspectors performed an independent review of the licensee's pre-fire plans and :
verified the auxiliary building fire protection equipment met the plans.
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b. Observations and Findinas On October 30,1998, the inspectors reviewed the licensee pre-fire plans and performed l walkdowns of the auxiliary building fire protection equipment. The inspectors reviewed i licensee response to CER 98-0947, in which the licensee identified that the type and j location of several fire extinguishers staged in the plant did not match the requirements I of the pre-fire plan. The discrepancies identified by the CER had minimalimpact on the ability of trained fire team members to respond to fires. The licensee responded to the discrepancies by performing a thorough walkdown of fire extinguishers identified on the j zone maps and correcting the discrepancies identified. The inspectors performed an independent review of the pre-fire plan maps and auxiliary building fire extinguishers and fire hose stations in the field. No discrepancies were identified.
c. Conclusions The licensee identified and corrected several pre-fire plan discrepancies concerning the location and type of fire extinguishers staged in the plant. An independent review of the pre-fire plan maps and auxiliary building fire extinguishers and fire hose stations in the field identified no additional discrepancies.
F3 Fire Protection Procedures and Documentation F3.1 Turbine Buildina Fire Barrier Insoection a. Insoection Scope (71750)
Inspectors observed performance of fire barrier inspections conducted in accordance with STP-728.033," Turbine Building Fire Barrier Inspection," Revision 4. Some of these fire barriers provide separation between safety-related areas in the control building and the turbine building.
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b. Observations and Findinas On October 29,1998, inspectors observed the performance of fire barrier inspections conducted in accordance with STP-728.033 " Turbine Building Fire Barrier inspection,"
Revision 4. The technicians performing the inspection noted a minor fire barrier labeling error which they documented for correction. The technicians also identified defects in traces 280 and 281, north wall of the turbine building rubber type seal around piping.
The technicians immediately informed the control room personnel of the condition. The control room supervisor and shift engineer posted a roving fire watch for the area while investigation of the condition continued. CER 98-0979 was generated and licensee personnel determined the inspection points were located in a section of the wall which is not a fire protection barrier. Work request 9816348 was generated to repair the defects and the licensee indicated that STP-728.033 would be revised to eliminate these inspection points for traces 280 and 281 from the procedure. No additional items of concern were identified during the performance of this inspection.
c. Conclusions Discrepancies identified during performance of a Turbine Building Fire Barrier inspection were properly dispositioned. Control room personnel were immediately informed of deficiencies and corrective action was initiated. The licensee indicated the inspection procedure STP-728.003 would be revised to eliminate unnecessary inspection points from the procedure.
V. Manaaement Meetinas X1 Exit Meeting Summary An exit meeting following the inspection of implementation of GL 96-05 was conducted on October 21,1998, where the inspectors presented the results of the inspection to members of licensee management.
The inspectors presented the inspection results to members of licensee management at the conclusion of the six week inspection on November 30,1998. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED 1.icensee
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F. Bacon, Manager, Chemistry Services L. Blue, Manager, Health Physics M. Browne, Manager - Plant Support Engineering S. Byrne, General Manager, Nuclear Plant Operations R. Clary, Manager, Quality Systems !
M. Fowikes, Manager, Operations ;
T. Franchuk, Supervisor - Quality Assurance l S. Furstenberg, Manager, Maintenance Services l R. Justice, MOV Engineer D. Lavigne, General Manager, Nuclear Support Services G. Moffatt, Manager, Design Engineering L. Hipp, Manager, Nuclear Protection Services J. Pease, Licensing / Operating Experience Specialist A. Rice, Manager, Nuclear Licensing and Operating Experience G. Taylor, Vice President, Nuclear Operations R. Waselus, Manager, Systems and Component Engineerint
- R. White, Nuclear Coortlinator, South Carolina Public Service Authority )
- B. Williams, General Manager, Engineering Services G. Williams, Associate Manager, Operations
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INSPECTION PROCEDURES USED l IP 37551: Onsite Engineering IP 61726: Surveillance Observations
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IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92902: Follow-up - Maintenance
, IP 92903: Follow-up - Engineering Tl2515/140: Inspection Requirements for Generic Letter 96-05, Periodic Verification of
, Design-Basis Capability of Safety Related Motor-Operated Valves ITEMS OPENED, CLOSED, AND DISCUSSED Opened i 50-395/98009-01 VIO failure to follow procedure for documenting LCO entries, two examples (Section 01.2)
Closed 50-395/98001-01 LER plant shutdown due to failed mechanical governor on the A emergency diesel generator (Section M8.1) I 50-395/98002-00 LER 10 CFR Part 21 report on failed electrical governor (EG-A)
on the A emergency diesel generator (Section M8.2)
50-395/97006-00 LER technical specification breaker alignment surveillance not performed due to personnel error (Section M8.3)
50-395/97013-02 URI failure to make administrative changes to the snubber testing program (Section M8.4)
50-395/97002-02 IFl followup on performance criteria established for risk-significant structures, systems, and components (SSCs)
following periodic balancing (Section E8.2)
Discussed 50-395/98006-01 URI licensee controls of steam propagation barriers (Section E8.1)
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SYNOPSIS
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The Office of Investigations (01), U.S. Nuclear Regulatory Commission (NRC), I Region II, initiated this investigation on December 2.1997, to determine if l the South Carolina Electric and Gas Company's Virgil C. Summer Nuclear Station i failed to follow procedures regarding snubber testing.
-The evidence developed during this investigation substantiated that the i
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licensee failed to follow procedures regarding snubber testing. There was not i sufficient eyidence that management intentionally or deliberately failed to follow procedures. !
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NOT TOR PUOLIC 0:SCLOSUR: L'IT"0LT APPROVAL CI IIELD CITICE CIRECTOR, OIIIC: CI INVESTIGATIONS, REG DN II rW d Case No. 2 97 031 1 [h llll $
ENCLOSURE 3