IR 05000461/1999003
| ML20205T581 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 04/21/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20205T575 | List: |
| References | |
| 50-461-99-03, 50-461-99-3, NUDOCS 9904270296 | |
| Download: ML20205T581 (81) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli Docket No:
50-461 License No:
NPF-62 Report No:
50-461/99003(DRS)
Licensee:
lilinois Power Company Facility:
Clinton Power Station Location:
Route 54 West Clinton,IL 61727 Dates:
February 8 through March 18, its99 Inspectors:
E. Duncan, Team Leader Z. Falevits, Assistant Team Leader F. Burrows, Reactor Engineer, NRR D. Butler, Reactor Engineer D. Chyu, Reactor Engineer D. Jones, Reactor Engineer K. Stoodter, Clinton Resident inspector D. Prevatte, Contractor R. Cooney, Contractor P. Madden, Senior Fire Protection Engineer, NRR P. Qualls, Fire Protection Engineer, NRR Approved by:
Ronald N. Gardner, Chief, Engineering Specialist Branch Division of Reactor Safety 9904270296 990421 PDR ADOCK 05000461 G
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EXECUTIVE SUMMARY Clinton Nuclear Power Station
NRC Inspection Report 50-461/99003(DRS)
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The purpose of this inspection was to assess the engineering organization's effectiveness and I
readins3s for restart through an in-depth review of calculations, analyses and other engineering documents and products used to support syslam performance during normal and accident conditions.
Enoineerina The team reviewed and closed NRC Manual Chapter 0350," Staff Guidelines for Restart
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Approval," Case-Specific Checklist item IV.3, " Resolve issues Associated With Circuit Breaker Failures." Based on observations of ongoing maintenance activities, review of maintenance procedures, and the review of ceriacuve actions proposed and completed, the team concluded that licensee efforts to address NRC concems regarding circuit breakers had been effective. Tne team observed measurable improvement in engineering and maintenance activites relative to circuit breakers. The team concluded that the licensee adequately addressed each of the commitments in Confirmatory Action Letter Rlli-97-009. (Section E1.1)
The team reviewed NRC Manual Chapter 0350," Staff Guidelines for Restart Approval,"
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Case-Specific Checklist item IV.4, " Degraded Voltage and Electrical Distribution Concems." The team concluded that planned electrical distribution system changes and other initiatives to address degraded voltage concems were well-implemented.
Case-Specific Checklist item IV.4 will remain open pending an NRC revktw of post-modification testing which had not yet been completed. (Section E1.2)
The team reviewed and closed NRC Manual Chapter 0350, * Staff Guidelines for Restart
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Approval," Case-Specific Checklist item VI.1, " Provide Reasonable Assurance That Safety-Related Structures, Systems, and Components Will Perform Their intended Safety Functions as Described in the Desiga and Licensing Basis." The team concluded that based on the review of System Design and Function Validation project findings, as well as an independent review of the reactor core isolation cooling system, the licensee had established reasonable assurance that safety-related structures, systems, and components would perform their intended safety functions as described in the design and licensing basis. However, the team also identified a number of examples where engineering personnel failed to ensure that problems were adequately resolved through the implementation of effective corrective actions. (Section E1.3)
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The team reviewed and closed NRC Manual Chapter 0350, " Staff Guidelines for Restart
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Approval," Case-Specific Checklist item VI.2, " Validate the Adequacy and Control of i
Calculations." The team concluded that the licensee had satisfactorily addressed calculation control issues and had completed sufficient calculation reviews to provide reasonable assurance that structures, systems and components would be able to perform their specified safety function. (Section E1.4)
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The team reviewed NRC Manual Chapter C350," Staff Guidelines for Restart Approval,"
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Case-Specific Checklist itern VI.3, "VaWate the Adequacy and Control of the Setpoint Program." The team concluded that the licensee had implemented satisfactory controls to ensure setpoint calculations would be property controlled and were performing appropriate setpoint reviews to ensure safety-related setpoints were conservatively set in the field. However, the setpoint operability determination for the next operating cycle was not available for review by the team. Case-Specific Checklist item VI.3 will remain
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open pending NRC review of the safety-related setpoint operability determination.
(Section E1.5)
The team reviewed and closed NRC Manual Chapter 0350, "St# Guidelir.as for Restart
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Approval," Case-Specific Checklist item IV.5, " Resolve Fire Protection Safe Shutdown Concems." The team concluded that the remote shutdown procedure adequately incorporated the assumptions in the revised safe shutdown analysis and that the procedure could be adequately implemented. The licensee also committed to complete necessary operator training prior to plant restart. In addition, the team concluded that all modifications to prevent fire induced valve damage to critical safe shutdown valves, as required by fire protection regulations, were completed. Finally, the team concluded that the program to address the fire-resistive technical concoms associated with Thermo-Lag was adequate. The licensee committed to complete all remaining Thermo-Lag activities prior to plant restart. (Section F2.1)
The team concluded that with regard to the resolution of significant hardware
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deficiencies, the performance of engineering personnel was good. However, the team identified a number of examples where engineering personnel failed to ensure that less significant problems were adequately resolved through the implementation of effective corrective actions. (Section E4.1)
The team reviewed a number of modifications and determined that the modifications
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were adequately designed and installed. However, two defeiencies related to post-modification testing were identified. (Section E1.6)
Licensee efforts to walkdown all safety-related fuses, and replace all incorrectly installed
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fuses prior to plant restart, will provide reasonable assurance that installed fuses conform to design document requirements. (Section E2.1)
Engineering performance indicators were not stand-alone and were not easy to
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understand. At the end of the inspection, corrective actions were being developed to address this issue. (Section E2.2)
The team concluded that the quality of 10 CFR 50.59 screenings and safety evaluations
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had improved, in addition, the program for ensuring that trained and qualified personnel prepared and reviewed 10 CFR 50.59 screenings and safety evaluations was adequate.
(Section E3.1)
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Report Details Background On September 5,1996, a reictor recirculation pump seal failed at Clinton Power Station (CPS).
Based on event followup by illinois Power and the NRC, the need for extensive corrective actions to address performance deficiencies was identified. In a December 9,1996 letter to the NRC, Illinois Power described corrective action commitments that would be completed prior to plant restart.
In February 1997, NRC inspoetors identified deficiencies in Illinois Power's maintenance program for safety-related circuit breakers. Following this finding, Illinois Power completed inspections and tests in an effort to establish reasonable assurance that safety-related breakers would function when called upon. The completion of sufficient inspections and tests for the establishment of such reasonable assurance was reported in a public meeting on July 3,1997.
I Subsequently, a number of safety-related and nonsafety-related breakers, which were subjected to the referenced inspections and tests, failed when called upon. Consequently, the NRC
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issued Confirmatory Action Letter Rlll-97-009 to establish a formal understanding of Illinois j
Power's planned corrective actions to address the breaker failures.
As a result of the continued identification of recurring weaknesses in Illinois Power's corrective.
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action program at CPS, the NRC issued a Demand-for-information (DFI) letter dated Septemtmi 26,1997, regarding corrective action performance at CPS. In response to the DFI, CPS management committed by letter dated December 23,1997, to a number of additional actions, including the performance of System Design and Functional Validations (SDFVs) for selected systems and the establishment of the CPS Plan-For-Excellence, which contained strategies addressing problems in a number of areas.
To ensure that the planned corrective actions identifed in various documents such as the Plan-For-Excellence, NRC inspection reports, and enforcement correspondence, had been satisfactorily accomplished to support plant restart, an NRC 0350 Restart Action Plan was developed. This plan included a Case-Specific Checklat which identified a number of activities that the NRC planned to verify had been adequately completed prior to restart approval. During this inspection, the team reviewed a number of these items. The team also reviewed the adequacy of selected plant design changes and their impact on system functionality and the design and licensing basis; evaluated implementation of the 10 CFR 50.59 safety evaluation process; reviewed engineering staff involvement in root cause analyses, operability
~ determinations, and corrective actions to address problems; reviewed actions to address fuse i
control problems; and reviewed licensee actions to address previously identified inspection items for closure.
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lit. Engineering E1 Conduct of Engineering E1.1 Review of NRC Case-Soecific Checklist item IV.3 a.
lnspection Scope (37550)
The team reviewed NRC Case-Specific Checklist item IV.3, " Resolve issues Associated With Circuit Breaker Failures." To address this checklist item, the team assessed corrective actions associated with 4160-volt breakers and molded case circuit breakers, assessed the implementation of corrective actions developed from the root cause analysis for breaker failures, and reviewed actions taken to address the issues documented in Confirmatory Action Letter (CAL) Rlli-97-009.
In particular, the team examined licensee activities to ensure that safety-related and balance of-plant drcuit breakers were capable of performing their intended function. The team reviewed selected engineering and maintenance procedures, condition reports, and maintenance work requests. The team also observed ongoing breaker maintenance and testing activities, and conducted interviews and meetings with engineering and maintenance personnel. Finally, the team reviewed the implementation of commitments made in response to CAL Rill-97-009.
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Observations and Findings b.1 Background in February 1997, NRC inspectors identified deficiencies in the maintenance program for safety-related circuit breakers. Following this finding, CPS performed inspections and tests in an effort to establish reasonable assurance that safety-related breakers would function when called upon. The completion of sufficient inspections and tests for the establishment of such reasonable assurance was reported in a public meeting on July 3, 1997. On July 22,1997, a Westinghouse 4160-volt DHP-type safety-related breaker,
- which had been subjected to the inspections and testing discussed above, failed to open when called upon in service. On the same day, a similar Westinghouse 4160-volt -
DHP-type nonsafety-related breaker failed to close when called upon. During a public meeting on July 31,1997, Illinois Power informed the NRC that the problem which led to the breaker failures had been identified and corrected, all necessary corrective actions had been taken for other safety-related breakers, and that safety-related breakers would function when called upon.
On August 5,1997, another Westinghouse 4160-volt DHP-type safety-related breaker failed to open when called upon. This breaker had been subjected to the inspections,
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tests, and corrective actions discussed above. As a result, on August 6,1997, the NRC issued CAL Rill-97-009 which identified the actions committed to by CPS to ensure that the failure mechanism of the safety-related breaker which failed on August 5 would be established, effective corrective action would be taken to prevent recurrence, and a basis would be established for reasonable assurance that all safety-related breakers would function when called upon. In addition, an NRC Augmented Inspection Team (AIT)
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responded to the event. At the end of the inspection, the AIT concluded inat the breaker failures were predominantly caused by inadequate and inappropriate maintenance
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b.2 ' Assessment of Corrective Actions for 4160-Volt Breakers The licensee convened a special investigation team to evaluate the root cause and extent of condition of the Westinghouse 4160-volt DHP-type breaker which failed to open on August 5,1997. Various breaker and laboratory tests determined that the principal failure mechanism was high friction forces in the main and arcing contacts due to a lack of lubrication. Based on analytical and chemical analysis, the licensee determined that the resulting poor condition of springs and other breaker components significantly contributed to this failure. Other contributing factors included inadequate maintenance requirements, incomplete and vague technical manual guidance, inadequate support of maintenance by engineering, and a lack of breaker failure trending. Clinton Power Station used Westinghouse 4160-volt DHP-type breakers in 24 safety-related applications and 57 critical balance-of-plant applications.
To establish a basis for reasonable assurance that all safety-related circuit breakers would function when called upon as required by CAL Rill-97-009, the following corrective actions were planned:
Revise circuit breaker preventive maintenance and lubrication procedures.
a Refurbish, replace, or perform improved preventive maintenance on all
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safety-related circuit breakers.
Refurbish or replace all Westinghouse 4160-volt Division i DHP-type circuit
breakers prior to restart.
Refurbish or replace all Westinghouse 4160-volt Division 11 DHP-type circuit
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breakers by September 1999.
Provide training to maintenance and engineering personnel.
- Conduct an assessment and improve the industry information feedback process.
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Create a material condition management team.
- lnitiate a system engineer improvement plan which included re-defining duties
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and responsibilities of system engineers, equipment failure training, and lubrication training.
Establish a circuit breaker failure trending program.
- Revise the periodicity for routine circuit breaker preventive maintenance.
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Establish a circuit breaker refurt>ishment schedule.
- Assess the extent of condition and generic implications of the circuit breaker
failures.
During this inspection, the team reviewed the implementation of the corrective actions described above.
The team verified that breaker replacement and refurbishment commitments were on schedule. The team also verified that all Westinghouse 4160-volt DHP-type circuit breakers had preventive maintenance conducted in accordance with Procedure 8410.21,
" Westinghouse DHP 6900-Voit. 4160-Volt Power Circuit Breaker," which was revised to incorporate vendor recommendations, Clinton Special Investigation Team recommendations, and past experience. The team also reviewed Procedure MS-01.00,
" Equipment Lubrication Procedure," and verified that this procedure was revised to include circuit breaker lubrication. The eeam observed circuit breaker replacement and refurbishment efforts and concluded that the maintenance and testing of circuit breakers had significantly improved, in particular, the team observed improved work practices during maintenance activities on the circud breakers which included increased management involvement, good teamwork, and strict adherence to procedure requirements.
To assess improvements in system engineering, the team reviewed Nuclear Station Engineering Department (NSED) Procedure A.18," Conduct of Sys'em Engineering,"
which was revised to re-define the duties and responsibilities of the system engineer, and verified that equipment failure training and circuit breaker lubrication treining had been conducted or scheduled. No deficiencies were identified.
The industry feedback program was also revised to improve the availability, t ssessment, and response to industry experience notifications. At the end of the inspection, actions to strengthen this program were in progress. 4 ne team reviewed this revised prg:ess and determined that the actions were adequate to support plant restart.
in October 1997, the Material Condition Management Team was created to provide oversight for the completion of corrective actions associated with circuit breaker failures.
The team verified through direct observation that this team was providing adequate oversight for activities associated with circuit breakers.
The preventive maintenance and refurbishment schedules had been revised for the Asea-Brown-Boveri (ABB), Westinghouse, and General Electric circuit breakers. The preventive maintenance periodicity for Westinghouse and ABB circuit breakers was reduced from 6 years to 3 years, and the General Electric circuit breaker preventive maintenance periodicity was reduced from 6 years to 2 years. The specifications for refurbishment were established as every 5 years for the General Electric 4160-volt Magne-Blast circuit breakers and Westinghouse DHP-type circuit breakers, and every 10 years for the 480-volt ABB K-Line circuit breakers. These recommendations were based on vendor and Clinton Specal Investigation Team recommendations. The team reviewed these revisions. No concems were identified.
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To provide reasonable assurance that equipment was properly maintained, the licensee conducted a review of preventive maintenance tasks for selected safety-related maintenance rule risk-significant system components in October 1997. More than 2200 components in 47 groups were reviewed. Vendor recommendations, industry information, site failure history, and information from other nuclear utilities were used to determine if the preventive maintenance tasks were adequate. The evaluation concluded that although numerous deficiencies due to a lack of complete incorporation of users group and industry group recommendations were identifed, there was I
reasonable assurance that the preventive maintenance tasks were adequate to support safe operation. The team reviewed thic evaluation. No concems in addition to those
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already discussed were identifed.
The team also reviewed corrective actions to address other breaker concems.
General Electric 4160-Volt Magne-Blast AM-Type Circuit Breakers
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Clinton Power Station used five General Electric 4160-volt Magne-Blast AM-type circuit breakers in the Division lll high pressure core spray switchgear. As discussed in NRC Inspection Report 50-461/98019, the NRC identified concems with these circuit breakers due to inadequate lubrication and preventive maintenance activities, and a lack of incorporation of vendor recommendations. During this inspection, the team determined that all five safety-related circuit breakers had been refurbished, tested, and re-installed in the switchgear.
Asea-Brown-Boveri 480-Volt K-Line Breakers
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From 1995 to February 1997,38 ABB 480-volt K-Line circuit breakers were shipped to ABB for refurbishment. As discussed in NRC Inspection Report 50-461/98026, the NRC identified that ABB reports documented that the as-found condition of grease on the circuit breakers refurbished in 1995 was moderately tacky or hard. However, the licensee had not accelerated the program to correct the hardened grease concems. In addition, the NRC determined that testing of the refurbished circuit breakers after they arrived onsite was not always accomplished prior to field installation. In addition, although the vendor recommended that the 480-volt circuit breakers be refurbisM at a
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maximum 10-year interval, this recommendation had not been fully implemented. As a
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result, the NRC issued a violation for a failure to identify rand correct hardened grease problems with 480-volt ABB circuit breakers. During this inspection, the team determined that the licensee refurbished, tested, and re installed all 33 safety-related
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ABB 480-volt K-Line circuit breakers.
Westinghouse 6.9 Kilovolt (kV) DVP-Type Brerskers
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The team reviewed the corrective actions to improve the materiel condition of the four Westinghouse 6.9 kV DVP-type circuit breakers used to operate the reactor recirculation pumps. In 1997, only limited preventive maintenance on these circuit breakers was accomplished. In response to NRC concems regarding the effectiveness of preventive
maintenance activities completed in 1997, in November 1988 four new maintenance work requests were issued to perform extended preventive maintenance activities prior to plant restart using an upgraded preventive maintanance procedure. The team
E observed the performance of breaker lubricction activities, measurements, adjustments of circuit breaker component tolerances, and testing on a sample of these circuit breakers. Maintenance personnel exhibited good understanding and knowledge of circuit breaker design and maintenance requirements. No deficiencies were identified.
As part of their long-term actions, the licer.see planned to replace these circuit breakers.
b.3 Assessment of Corrective Actions Associated With Molded Case Circuit Breakers The team reviewed the test program for molded case circuit breakers. There were approximately 1500 safety-rf,cted molded case circuit breakers in the test program,900 of which had been recently added and had not been tested since installation. As discussed in NRC Inspection Report 50-461/98011, the NRC identified that the licensee failed to apply corrective actions from 4160-volt circuit breaker testing problems to molded case circuit breakers. Molded case circuit breaker testing program deficiencies included improper test cable size, inadequate low current instantaneous trip testing, excessive test current pulse length, excessive instantaneous test current, improper instantaneous trip times, preconditioning of circuit breakers, inadequate documentation of valid test attempts, and inadequate evaluation of circuit breaker coordination issues.
In addition, the NRC determined that licensee personnel had not effectively utilized industry information and experience even though they were involved in the development of industry guidance for testing 480-volt molded case circuit breakers.
To address these issues, the licensee halted all molded case circuit breaker testing, revised Procedure 8410.04, " Molded Case Circuit Breaker Functional Testing and Maintenance," to incorporate recent industry guidance regarding molded case circuit breaker testing, and procured upgraded testing equipment. / s discussed in NRC Inspechon Report 50-461/98014, to demonstrate the functic ality of the molded case circuit breakers, the licensee planned to test a representative sample of about 130 previously untested molded case circuit breakers and increaes the sample size based on the testing results. Following the identification of motor starter contactor problems, the sample size was increased to 200 untested molded case circuit breakers and any other molded case circuit breakers due for testing. On February 23,1999, the licermee had completed testing of 167 previously untested molded case circuit breakers. One breaker was identified that would have failed to coordinate with the upstream breaker. An additional 100 previously-tested molded case circuit breakers were also tested with the new procedure and test equipment. Five additional breakers were identified which would have failed to coordinate with the upstream breaker. However, no molded case circuit breaker failed to open.
The initial results of the testing revealed several deficiencies. About 20 percent of the motor starter contactors failed to meet the coil pull-in voltage acceptance criterion of less than or equal to 84 volts altemating current (Vac). The licensee initiated corrective actions and completed an operability determination for the dogmded condition. The results of the operability determination indicated that the acceptance criterion was based on the manufacturer's nameplate rating and not on a specific design basis requirement.
Therefore, a sufficient margin existed to consider the nx) tor starter contactors operable; however, a detailed analysis had to be accomplished for each motor starter contactor.
On February 23,1999, the licensee had completed calculations on all safety-related molded case circuit breaker enclosure motor starter contactor circuits and had scheduled
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additional testing on all suspect enclosures. The licensee had completed testing of 254 starter contactors, of which 66 failed the 84 Vac acceptance criterion; however, the licensee determined that only 3 would have failed during undervoltage conditions. After further review of the National Electrical Manufacturers Association Class 1E value from the qualification summary report, the licensee determined that a revised value of 102 Vac was appropriate if there was a preventive maintenance and trending program established. The licensee initiated actions to compare the analyzed voltage present during undervoltage conditions to the 102 Vac value to determine the preventive maintenance population. A regular preventive maintenance program was scheduled to be developed for this most limiting group to ensure that motor starter contactors would function during the most limiting undentoltage conditions.
As discussed in NRC Inspection Report 50-461/98017, in addition to the contactor degradation, the initial enclosure inspections revealed that 23 of 79 installed fuses were the incorrect fuse type. As a result, prior to plant restart, the licensee planned to inspect all safety-related fuses to ensure that the correct fuse was installed. On February 23, 1999,1088 Division i fuses had been inspected, of which 235 were the incorrect type and 29 were the incorrect rating. At the end of the inspection, the licensee's evaluations indicated that none of the incorrect fuses would have caused circuit damage. All incorrect fuses were being replaced and a condition report written upon discovery.
Additional discussion of this item is contained in Section E2.1.
- After evaluating the significance of all the discrepancies identified during the testing program, the licensee committed to replace all 40 ampere and Dreater safety-related molded case circuit breakers with new fully tested replacement molded case circuit breakers. This was due to an excessive rate of test failures in the larger size breakers.
Additionally, the licensee committed to completing testing on all the suspect motor starter relays and to complete all scheduled molds.d case circuit breaker preventive maintenance prior to plant restart.
The team concluded that the revised molded case circuit breaker testing program conformed to the latest NRC and industry guidance, and had been appropriately expanded to include testing the molded case circuit breaker auxiliary contacts and relays.
b.4 Review of Confirmatorv Action Letter Rlll-97-009 On August 6,1997, the NRC issued CAL Rlll-97 009 which identified the actions committed to by CPS to ensure that the failure mechanism of the safety-related circuit breaker which failed on August 5 would be established, effective corrective action would be taken to prevent recurrence, and a basis would be established for reasonable assurance that all safety-related circuit breakers would function when called upon.
Based on the reviews conducted prior to and during this inspection as documented above, the team concluded that each of the commitments in CAL Rill-97-009 had been adequately addressed.
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Condusions Based on observation of ongoing maintenance activities, review of maintenance procedures, and the review of corrective actions proposed and completed, the team conduded that licensee efforts to address NRC concems regarding circuit breakers had been effective. The team observed measurable improvement in engineering and maintenance activities relative to circuit breakers. The team conduded that each of the commitments in Confirmatory Action Letter Rill-g7-009 had been adequately addressed.
Case-Specific Checklist item IV.3, " Resolve issues Associated With Circuit Breaker Failures,"is closed.
E1.2 Review of NRC Case-Soecific Chad!!st item IV.4 a.
Insoection Scooe (37550)
The team reviewed NRC Case-Specific Checklist item IV.4, " Degraded Voltage and Electrical Distribution Concems." To address this checklist item, the team reviewed selected degraded voltage modifications and calculations, and performed an integrated assessment of electrical distribution modifmations.
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Observations and Findinas b.1 Background in 1994, lilinois Power identified that the setpoints for the degraded voltage relays at CPS were not sufficient to ensure proper operation of all equipment. Subsequently, the 4160-volt degraded voltage relay setpoints were revised and approved by NRC amendment 110 dated December 4,1996. Subsequently, due to the reduced margins for ensuring adequate voltage loads from the offsite electric power system, CPS conducted detailed studies of the electrical distribution system at projected peak system load conditions. These studies identifed that future offsite power conditions would not provide adequate voltage to the 4160-volt safety-related busses.
An extensive plan was developed to ensure that adequate voltage would continue to be supplied to plant loads from the offsite power system. This plan included modifications which added regulating transformers, the replacement of the emergency reserve auxiliary transformer with a load tap changing transformer, and the addition of static VAR
[ Volt-Ampere-Reactive) compensators (SVCs). These modifications were approved by license amendments dated October 1 and October 9,1998.
Subsequently, the licensee determined that some of the non-regulating transformers originally planned to be replaced with regulating transformers were still needed to support proper operation of the regulating transformers. This led to the development of a modified approach to regulating transformer installation. Under the modifed approach, the number of regulating transformers was reduced. In addition, the reserve auxiliary transformer secondary voltage was increased through a change in the reserve auxiliary transformer load tap setting and by crediting the regulating effect of the reserve auxiliary transformer SVC. This also required that degraded voltage relay setpoints be revised.
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During this inspection, the team reviewed the modifications planned and completed to address the voltage concems discussed above.
b.2 Degraded Voltage Modification and Calculation Review The team reviewed nine modifications and three engineering change notices to address degraded voltage issues. In particular, modifications corx:eming degraded voltage relays (modifications AP-027, AP-028 and AP-029), the reserve auxiliary transformer SVC (modification AP-037) and the emergency reserve auxiliary transformer SVC (modification AP-038) were reviewed. The team determined that the modifications were installed according to the associated design change packages, the associated safety evaluations provided sufficient detail to determine that an unreviewed safety question did not exist, and the specified testing was appropriate. The team verified a sample of the
modification packages and exempt change notices that were scheduled for completion and determined that the packages and notices reviewed were prepared in accordance with Procedure 1003.01," CPS Hardware Change Program."
i The team observed initial reserve auxiliary transformer and SVC post-modification testing. The pre-job briefing was conducted with the operations staff and test personnel
- in the main control room. The briefing re-enforced personnel safety and described in
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detail test personnel responsibilities. An initial energization test was observed by the NRC resident staff; however, the SVC tripped and testing was halted due to several i
protective relay trips. Subsequently, the licensee determined that the protective relays were out of calibration. A second energization test was observed by NRC team members. The testing proceeded smoothly initially during SVC bus energization and thyristor controlled reactor energization. However, during the test, the thyristor controlled i
reactor surge protectors failed. Subsequently, the licensee determined that during certain thyristor switching cycles, the peak voltage fed back to the thyristors could reach 8 kV. The equipment supplier indicated that this voltage level could be expected during this type of testing and would not damage the thyristors. However, it was determined that the initial SVC design had incorporated surge protectors that were only designed for about 6.9 kV. The surge protectors were replaced with ones rated for 10 kV, The licensee personnel indicated that the 8 kV transient voltage only occurred at the SVC thyristors and would not affect the 4 kV electrical distribution system.
Team members observed testing of the reserve auxiliary transformer and SVC utilizing Procedure 2825.18, Revision 2, on March 15,1999. This test connected the reserve auxiliary transformer and SVC to the 4 kV distribution system. Tests prescribed included
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Section 8.1 - Plant Air Compressor Start and Stop
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Section 8.2 - Plant Service Water Pump Starts
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Section 8.3 - 4 kV Buses 1 A1,1B1,1B Transfer and SVC Transient
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Section 8.4 - EDG [ Emergency Diesel Generator) 1 A Run Paralleled to the
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Reserve AuxiliaryTransformer Section 8.5 - 4 kV Buses 1 A and 181 Bus Transfer
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The test proceeded satisfactorily through Sections 8.1 and 8.2. The team observed the test pre-job briefing for Section 8.3. This section simultaneously loaded seven large
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motors onto the reserve auxiliary transformer and SVC to simulate loss-of-coolant-accident block start loading conditions. When the test was initiated, the reserve auxiliary transformer tripped within 1 second Subsequently, the licensee determined that the *A" phase reserve auxiliary transformer differential relay had tripped. The relay was replaced and the suspect relay was quarantined for further review. In addition, the "B" and "C" phase relays were verified to be cet correctly. Prior to performing an additional test, the reserve auxiliary transformer differential relays were fully instrumented according to recommendations of industry personnel. Static VAR compensator current transformer phasing was then verified during the start of a single motor. This test identified that the SVC current transformer input to the "A" phase differential relay was not configured (phased) correctly. Subsequently, the current transformer jumpers were re-arranged. A single motor start was re performed and the phasing traces indicated that the current transformer was correctly configured, in addition, the ernergency reserve auxiliary transformer SVC current tiansformer was verified to be correctly configured. Sections 8.3 and 8.4 were successfully completed during the week of Merch 22,1999. At the end of the inspection, Section 8.5 testing of the reserve auxiliary transformer and emergency reserve auxiliary transformer SVC remained to be completed.
The team reviewed 120-volt /208-volt calculation 19-AJ-74, " Class'1E Distribution Panel Loading Calculation," Volume C, Revision 0, which determined the minimum acceptable component operating voltages at the 480-volt motor control centers. This calculation overlapped 480-volt /4160-volt calculation 19-AQ-02, " Calculation for LOCA [ Loss-of-Coolant-Accident] Block Start," Volume AB, Revision 3, that determined the minimum acceptable component operating voltages at the 4 kV emergency (Class 1E) buses.
Calculation 19-AQ-02 determined the degraded voltage analytical limit that was used in developing degraded voltage setpoint calculation 19-AN-19, " Calculations for Functional Requirements for 1" and 2"' Level Undervoltage Relays at 4kV 1 A1,1B1, and 1C1,"
Revision 2. At the end of the inspection, the Office of Nuclear Reactor Regulation was reviewing calculations 19-AQ-02 and 19-AN-19 in support of a proposed change to the Technical Specification degraded voltage setpoint. These celculations provided the voltage overlap to ensure sufficient operating voltage would be available to 120-volt components. Calculation 19-AJ-74 clearly stated the calculation purpose, contained reasonable design inputs and assumptions, and applied the appropriate analytical methods in determining the calculation conclusion.
b.3 Assessment of Electrical Distribution Changes The team reviewed seven additional calculations associated with the electrical distribution system. These calculations clearly stated the calculation purpose, contained reasonable design inputs and assumptions, and applied the appropriate analytical methods in determining each calculation conclusion.
Calculation 19-AK-06, " Calculation of Auxiliary Power System Analysis," Volume AX, Revision 0, was issued following the inspection. The team reviewed this calculation to ensure distribution system component ratings would not be exceeded with the addition of the SVCs and the larger emergency reserve auxiliary transformer. This calculation evaluated the reserve auxiliary transformer, the new emergency reserve auxiliary transformer, and the new SVC effects on the medium-voltage and low-voltage
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distribution systems. The distdbution systems were analyzed with the main generator, the 345 kV system through the reserve auxiliary transformer, or the 138 kV system through the emergency reserve auxiliary transformer, as contributing power sources.
Five loading conditions were examined for each power source. This included startup conditions, winter normal conditions, summer normal conditions, loss-of-coolant-accident shutdown conditions, and normal shutdown conditions. Acceptance criteria were established for the minimum and maximum bus voltages, available short circuit currents, and bus loading. In addition, the calculation evaluated the impact of the reserve auxiliary transformer and emergency reserve auxiliary transformer load tap changes. The team reviewed the calculation results and determined that safety-related and nonsafety-related distribution system components, such as circuit breaker ratings, were not exceeded.
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Conclusions The team reviewed the planned electrical distribution system changes and concluded that initiatives to address degraded voltage concems were well-implemented. At the end of the inspection, some required post-modification testing had not yet been completed.
Case-Specific Checklist item IV.4 will remain open pending a review of the results of this testing.
E1.3. Review of NRC Or r S_ nae 4c Checklist item VI.1 a.
Inspection Scope (37550. 93809)
The team reviewed NRC Case-Specific Checklist item VI.1, " Provide Reasonable Assurance That Safety-Related Structures, Systems, and Components Will Perform Their intended Safety Functions as Descnbod in the Design and Licensing Basis." To address this checklist item, the team assessed the scope, findings, assessments, and expenslun activities associated with the System Design and Funchonal Validation (SDFV) program. In addition, the team independently assessed the SDFV review of the residual heat removal (RHR) and auxiliary power (AP) systems, and performed an
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independent inspection of the reactor core isolation c6oling (RCIC) system and compared the results to the SDFV.
b.
Observations and Findings b.1 Background in response to repeated failures of safety-related circuit breakers and the identification of recurring weaknesses with the CPS corrective action program, the NRC issued a Demand-for-Information letter on September 26,1997, which required that CPS provide the basis for their confidence in the operability of safety-related structures, systems, and components (SSCs).
To address this issue, CPS implemented several verification programs to provide assurance that SSCs will function when called upon. The SDFV was initiated to evaluate issues raised in several prior assessments at CPS that identified weaknesses in design basis integrity, surveillance testing, operations, maintenance, and material condition.
The fundamental objectives of the SDFV wore to evaluate the extent to which
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deficiencies were present in the SSCs important to safe and reliable operation of the plant, and to assess their significance with respect to operability and functionality.
b.2 Assessment of SDFV Reviews b.2.1 Review of SDFV Scooe. Findinos. and Assessments Five systems were selected for the SDFV review: Shutdown Service Water, Control I
Room Ventilation, RHR, AP, and Containment Monitoring. Additionally, selected structural modifications and leak detection system modifications were evaluated. The SDFV review process included the development of a system scope and boundary document, as well as a functional matrix for each system to be reviewed. For each selected system, a review of accident analyses, design and licensing basis information, drawings, and calculations, was conducted to ensure that all functions and all modes of operation were evaluated. Surveillance test acceptance criteria were validated to ensure that system functionality was demonstrated through the performance of appropriate surveillance tests.
Following the SDFV reviews, the licensee concluded that although the original design of the reviewed systems was fundamentally sound, identified issues with design control practices were substantive. In particular, two cases were identified in which the operability of reviewed systems was challenged due to inadequate modifications. In the first case, a design change installed on July 17,1997, to address hot short concems inadvertently introduced an interlock problem which would have prevented motor-operated valve 1E12-F024B (RHR discharge to the suppression pool) from remotely opening to establish suppression pool cooling or shutdown cooling for the "B" train of RHR. The licensee concluded that the event was due to inattention-to-detail by the preparer and reviewers of the subject design change. However, the event had minimal safety significance because the other train of RHR was not affected, local operation of 1E12-F024B was possible to establish shutdown cooling, the containment spray function was unaffected and was a backup to suppression pool cooling as evaluated in analysis P21-99(01-07)-6, " Containment Response Without Smpression Pool Cooling," and the condition was present only when the plant was shutdown. In the second case, the containment and drywell hydrogen and oxygen concentration monitoring subsystem was determined to be inoperable. This was due, in part, to incornplete and failed testing associated with a modification. in this case, operation of the post-accident sample
system provided a redundant ability to monitor containment and drywell hydrogen and
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oxygen levels. Therefore, this event was also determined to have minimal safety
significance.
The SDFV also identified instances of important missing surveillance test results and inadequate acceptance criteria in some surveillance procedures, with the consequence that some surveillance requirements may not have been fulfilled. The licensee concluded that although additional SDFV-type reviews were not warranted prior to plant restart, additional selected reviews to identify the nature and scope of design control issues and surveillance testing issues were required prior to restart.
The team reviewed the findings and assessments summarized above. The team verified j
the findings of the SDFV project through a review of a list of the 182 condition reports
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generated as a result of the SDFV reviews, in addition, the summary list of the restart-required and nonrestart-required items was also reviewed.
To assess the sigruficance of the RHR modification issue identified above, the team
. reviewed analysis P2199(01-07)6 and verified that the assumptions were cor:servative and the results were valid to conclude that containment pressure limits, suppression pool temperature limits, and suppression pool water level limits would not be exceeded in the event of the failure of train "B" of suppression pool cooling and the most limiting single active failure (loss of Division I including train "A" of suppression pool cooling) in a design basis accident.
The team concluded that the SDFV project scope was adequate and that the expanded reviews conducted to ensure that the nature of the problems identifed during the SDFV were within design margin and had limited consequences were appropriate. Details regarding these expanded reviews are discussed below.
b.2.2 Review of SDFV Expansion Activates As a result of the SDFV project, several additional engineering reviews were conducted.
The scope of the post-SDFV project included the System Surveillance Test Review (SSTR), the Engineering Product Review (EPR), the Detailed Design Review (DDR), and the Detailed Calculation Review (DCR).
i System Surveillance Test Review During the SDFV project, examples of missing surveillances and inadequate test acceptance criteria were identified. The SSTR project reviewed the Technical Specification surveillance requirements related to plant operation to assure that testing was in place to demonstrate the operability of required equipment. All Technical Specification systems were included in the SSTR. The SSTR review of 1441 quantitative surveillance requirements resulted in the generation of 50 condition reports. Examples were identified of missing surveillance tests, inadequate acceptance criteria, missing design basis information, and problems with calculation control and adequacy. However, the licensee concluded that the identified deficiencies were limited in consequence.
The team reviewed the SSTR report and associated findings. The team verifed the findings of the SSTR through a review of the summary listing of the 50 condition reports generated as a result of the effort. Based upon the team's verification of the SSTR results, the team concluded that the SSTR project provided reasonable assurance that adequate testing was in place to demonstrate the operability of Technical Specification equipment.
Engineering Product Review An Engineering Product Review project was initiated to address an SDFV conclusion that the collective significance of design control practices was substantive and thnt additional reviews were required to confirm that the consequences of any fu-identif;ed issues remained limited and did not exceed the available margins in (no design ofimportant SSCs. The scope of the review consisted of a selection of engineering
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products such as modifications, analyses, and calculations periaining to changes potentially affecting the functionality of Technical Specification systems. The EPR identifed a number of deficiencies which were similar to those identified during the SDFV reviews. In all instances, the consequences of the deficiencies were determined to be
within the margin of the affected SSC design.
The team reviewed the EPR report and associated findings. The team verified that the deficiencies identified were similar to those identified in the SDFV project. The team j
concluded that the EPR was adequate to identify deficiencies in engineering products and that the consequences of the problems identifed were within the margin of the design.
Detailed Design Review Reviews of the design change control processes completed during the SDFV and EPR projects resulted in a recommendation that a detailed design review (DDR) of selected engineering products be performed. As a result, detailed reviews of 111 engineering products were conducted. These products included completed modification packages
and plant changes, and selected Individual calculations. The results of the review did not identify any significant deviation of the plant configuration with the design or licensing basis. Sixty-four of the 111 products reviewed had no identified deficiencies. Thirty-six of the products contained minor errors in the documentation that had no significant impact on the plant. Nine issues were identifed where the engineering documentation was in error or incomplete. However, similar to the EPR results, in all instances the consequences of the deficiencies were determined to be within the margin of the design.
The team reviewed the DDR report and associated findings. The team verifed the findings through a review of condition reports generated as a result of the DDR and the summary tables of the engineering products reviewed. The team found the DDR to be thorough as evidenced by the design review checidist which used attributes of independent design verification identified by American National Standards institute N45.2.11, " Quality Assurance Requirements for Design of Nuclear Power Plants," and the findings of the DDR project. The team concluded that the DDR was effective.
Detailed Calculation Review Based on the results of the DDR and other reviews, Illinois Power elected to perform additional reviews of CPS calculations. The purpose of this Detailed Calculation Review (DCR) was to determine if deficiencies in calculations or any failures to maintain calculations consistent with the plant configuration had resulted in the inability of SSCs to perform their safety functions. Overall, the detailed calculation reviews did not identify any safety significant deficiencies. However, the quality of a significant fraction of the calculations reviewed was identified as poor, and two reviewed calculations contained errors that, when corrected, required the revision of other documents such as surveillance procedures. Since no safety significant items were identifed, the licensee concluded that there were no significant calculation issues.
The team reviewed the DCR report and associated findings. The team verified the results of the DCR by reviewing the results summary and comments, as well as the
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11 condition reports generated as a result of the DCR project. The team determined that the sample size of 112 calculations and the resultant findings were adequate to identify discrepancies and calculation weaknesses. The team concluded that the DCR project was effective.
b.2.3 Assessment of AP and RHR SDFV Reviews As discussed in NRC inspection Report 50-461/98019, the NRC verified that the shutdown service water SDFV was thorough and comprehensive. During this inspection, the team reviewed the SDFV for the RHR and AP systems. Specifically, the team reviewed the methodology to identify, document, and resolve RHR and AP system J
design, testing, and material condition deficiencies. The team also reviewed selected restart-related and nonrestart-related condition reports associated with these systems.
Assessment of AP SDFV Review The AP system was reviewed to determine if the system could demonstrate performance consistent with the design basis to distribute electrical power to plant equioment. Prior to the SDFV, a number of significant problems such as degraded voltage concems and circuit breaker failures had been identified.
The SDFV identified concoms in the areas of design, testing, and material condition of equipment. These included inadequate or missing safety evaluations, lack of testing documentation to demonstrate the ability to meet statements in the Updated Safety Analysis Report (USAR) and Technical Specifmation bases, and inadequate surveillance procedure testing parameters. Specife issues related to circuit breakers, voltage drops, load sequencing, and offsite power sources were documented in 64 condition reports of which 23 were NRC-reportable and 22 were classified as requiring resolution prior to plant restart.
The team also attended several Senior Engineering Review Group (SERG) meetings.
i The SERG reviews were conducted to evaluate the consequence of defciences associated with the design change control process and the extent-of-condition of conooms identified during the SDFV, The SERG members included experienced
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industry consultant personnel and CPS staff. The SERG reviewed various engineering
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products including condition reports, plant modifmations, safety evaluations, and root cause evaluations. The SERG provided overview, guidance, and mentoring to the engineering staff. The team noted that SERG members also provided mentoring to CPS engineers during reviews and discussions of findings in their systems. The meetings were effective in assessing SDFV findings and in proposing resolutions to prevent recurrence.
i The team determined that the SDFV effort for the AP system was comprehensive and effective in identifying issues and developing a corrective action plan to address the identified concems.
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Assessment of RHR SDFV Review The RHR system was reviewed to determine if the system could operate in the various modes defined in the licensing and design basis. The SDFV identifed concems in the areas of design, testing, and material condition of equipment. Cases were identifed in which inadequate modifications and calculations, as well as programmatic issues such as motor-operated valve program implementation, challenged the operability of the RHR system. The team reviewed the various condition reports generated as a result of the RHR SDFV review as well as the identified corrective actions to verify that the planned or completed corrective actions were adequate. In addition, based on interviews with design and system engineers, the team determined that the engineers were
knowledgeable of the hardware changes and the effects of the design changes on the j
RHR system._ Overall, the team concluded that the SDFV effort for the RHR system was
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comprehensive and effective in identifying issues and developing a corrective action plan to address the identified concems.
b.3 Review of Reactor Core Isolation Coohng (RCIC) System The team assessed engineering effectiveness through an in-depth review of calculations, analyses, and other engineering documents used to support RCIC system performance during normal and accident conditions using the guidance contained in NRC inspection Procedure 93809, " Safety System Engineering Inspection."
b.3.1 Review of RCIC Surveillance Testina Procedures The team reviewed various RCIC surveillance testing procedures to verify that the acceptance criteria specified were adequately supported by design calculations or other engineering documents. Overall, the team concluded that surveillance procedures associated with the RCIC system were adequate to ensure that the system was operable. However, the following deficiencies were identifed.
RCIC Test Procedure Acceptance Cnteria Errors Technical Specification Surveillance Requirements 3.5.3.3 and 3.5.3.4 specified flow testing to verify the capability of the RCIC system to provide rated flow to the reactor vessel. Both surveillance requirements required that the RCIC pump develop a flow rate greater than or equal to 600 gallons per minute (gpm) against a system head { emphasis added] corresponding to reactor pressure. Procedure 9054.01, "RCIC System Operability Chock," and Procedure 9054.05, "RCIC Pump Flow Operability (Low Steam l
Pressure)," were conducted to meet these requirements.
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The team reviewed Procedure 9054.01 which was last conducted on September 16, 1994; and Procedure 9054.05, which was last conducted on April 27,1995, in both procedures, the steps which establishM pump discharge test pressure required opening valve 1E51-F022, the RCIC pump test valve to the RCIC storage tank, until a discharge pressure " equal to or Just slightly greater than reactor pressure" was established.
The team reviewed these procedure steps and determined that in order to produce
" system head" as described in the surveillance requirements, the discharge pressure
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would have to include, in addition to reactor pressure, the system resistance when in the
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design basis system lineup, and the worst case design basis elevation head. However,
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in the surveillance procedures reviewed, only the reactor pressure was accounted for. In addition, the acceptance criteria did not account for instrument uncertainties or for the difference between pump suction head conditions existing during test conditions and design basis conditions. The team also observed that the only pump test data obtained during these tests indicated that the pump had a developed head of only 1,007 pounds per square inch differential (psid) for a reactor pressure of 1,014 pounds per square inch gauge (psig). Under these conditions, the pump would not have delivered any water to the reactor vessel. Therefore, the test did not demonstrate that the pump was operable.
Subsequently, the team determined that condition report 1-97-02-287, dated February 27,1997, was generated to document that the acceptance criteria of many of the Technical Specification surveillance test procedures did not account for instrument uncertainties. Corrective actions included the review of each of the Technical Specification surveillance requirements to determine the specific deficiences. Condition report 1-97-03-182, dated March 26,1997, was generated to specifically address RCIC Technical Specification Surveillance Requirements 3.5.3.3 and 3.5.3.4. An informal calculation that accounted for instrument inaccuracies, system resistance, and elevation head determ!ned that 150 psig was required to be added to the reactor pressure to provide the corrected pump discharge pressure acceptance criteria. This value was subsequently incorporated into Procedure 9054.01, Revision 35, dated August 23,1997, and Procedure 9054.05, Revision 29, dated August 11,1997.
As a result of the team's inquiries, the licensee discovered that condition report 1-97-03-182 had been closed out by deferring the performance of a formal calculation to document the results of the evaluation to condition report 1-97-02-287. However, condition report 1-97-02-287 was not revised to include this corrective action, and the formal calculation was not performed. As a result of this discovery, condition report 1-99-02-326, dated February 19,1999, was generated to document this oversight, and condition report 1-97-03-182 was re-opened to correct this deficiency.
The team also identified that even though the iriformal ca.lculation accounted for many of the factors that had not been previously considered, it did not account for the additional pump discharge pressure that would be available during testing as a result of the RCIC
storage tank level. This additional discharge pressure would not be available under I
design basis conditions. The licensee planned to resolve this issue prior to plant restart.
Criterion XVI, " Corrective Action," of Appendix B to 10 CFR 50 requires that measures shall be established to assure that conditions adverse to quality, such as deficiencies, shall be promptly identified and corrected. The failure to revise Technical Specification acceptance criteria associated with RCIC surveillance procedures to incorporate system head losses and other factors was an example where the requirements of 10 CFR 50, Appendix B, Criterion XVI, were not met and was a violation. However, this Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/99003-01),
consistent with Appendix C of this NRC Enforcement Policy. This violation is in the licensee's corrective action program as condition report 1-99-02-326.
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Preconditioning Weaknesses During the review of guidance regarding preconditioning contained in Procedure 1401.09, " Control of System and Equipment Status," Revision 1, the following weaknesses were identified:
Procedure Guidance Weaknesses
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The team identified that Procedure 1401.09 failed to adequately characterize acceptable and unacceptable preconditioning. For example, licensee personnel did not consider pre-lubrication of emergency diesel generators prior to testing to be preconditioning.
However, NRC Inspection Manual Part 9900 Technical Guidance, " Maintenance -
Preconditioning of SSCs Before Determining Operability," dated Saptember 28,1998, identified pre-lubrication of emergency diesel generators prior to testing as an example of acceptable preconditioning. At the end of the inspection, the licensee planned to revise Procedure 1401.09 to be consistent with NRC guidance.
System Venting Weaknesses
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The team identified that in a number of routine surveillance procedures that demonstrate emergency core cooling system and RCIC system operability, the systems were vented prior to testing. Inspection Manual Part 9900 Technical Guidance recognized this as an acceptable preconditioning practice provided that the venting evolution was propedy l
controlled. The team reviewed procedures which directed pump venting evolutions and identified that the procedural controls consisted of the following statement: " Venting does not enhance pump capacity, but does prevent transients on the system. Should abnormal amounts of air be observed during venting, it should be addressed."
The team determined that the statements in Procedure 1401.09 regarding pump venting did not constitute " proper controls" as discussed in NRC Inspection Manual Part 9900.
At the end of the inspection, nine comment control forms had been submitted to ensure that adequate controls were in place for procedures which prescribed system venting prior to surveillance testing.
b.3.2 Review of RCIC System Operating Procedures The team reviewed several RCIC system operating procedures to determine whether the normal and emergency operation of the system were consistent with the design basis and licensing documents. Overall, the team determined that the system operating procedures were adequate to control the operation of the RCIC system. However, the following deficiencies were identifed:
Annunciator Response Procedure Deficiency The team identified that in the event of a failure of RCIC suction valve 1E51-F010 to isolate during a swapover from the RCIC storage tank, USAR Section 6.2.4.3.2 credited the isolation of the RClC tank through operator action to close a suppression pool isolation valve. However, the team identified that the annunciator response procedure for a low RCIC storage tank level did not direct this action if the 1E51-F010 valve failed
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t to close. At the end of the inspection, the licensee planned to revise the annunciator response procedure to direct the required operator action. However, cince limited
interviews of licensed operators indicated that the required actions would be taken even though not specWied in the annunciator response procedure, the safety significance of this issue was considered minimal.
Criterion V, " Instructions, Procedures, and Drawings," of Appendix B to 10 CFR 50 requires that activities affecting quality shall be prescribed by documented instructions, procedures, and drawings of a type appropriate to the circumstances. The failure to specify actions to close a suppression pool isolation valve in the event of a failure of the.
RCIC storage tank isolation valve to close on low level was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violation.
However, this failure constitutes a violation of minor significance and is not subject to formal enforcement action Potentially Ccie diciciv and Confusino Procedure SLt.T,ents The team identified that ir. the event that the RCIC storage tank suction valve failed to close during the automatic transfer from the RCIC storage tank to the suppression pool on low storage tank level, an unmonitored release path could be created if water from the suppression pool was diverted to the RCIC tank to maintain vessel level.
Subsequently, the team ident5ed that steps 8.9.4 and 8.9.5 of Procedure 3006.01, " Unit Shutdown," Revision 26, stated that when performing a reactor cooldown without the main condenser, the RCIC svstem could be used to control reactor pressure and level in accordance with Procedure 3310.01, " Reactor Core Isolation Cooling," Revision 18. In addition, Procedure 3006 01 indicated that water could be diverted to the RCIC tank (from the suppression pool) when the emergency operating procedures were in use.
The team also identified that Soction 8.1.9.1 of Procedure 3310.01 contained a caution which stated, "Do Not Direct RCIC Flow to the RCIC Storage Tank if RCIC Pump Suction is From the Suppression Pool." Operations personnel informed the team that the caution was placed in Procedure 3310.01 to prevent the creatum of an unmonitored release path between the suppression pool and the RCIC storage tank.
The team was concemed that operators might be confused when operating in situations where both procedures applied since Procedure 3006.01 did not address the fact that
. water should not be diverted to the suppression pool when operating with the suppression pool as the RCIC system suchon source. The team discussed this potentially confusing and contradictory information with operations personnel. At the end of the inspection, the licensee planned to revise Procedure 3006.01 and Procedure 3310.01 to eliminate any potential confusion. The lack of clear guidance in procedures used during abnormal operating conditions was considered a weakness.
b.3.3 Control and Use of Desion and Licensino Inout Information The team reviewed design, licensing, and other documents such as calculations and analyses, to determine whether the design requirements of the RCIC system could be
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met during normal operation and accident conditions. Overall, the team concluded that the system would function when required, However, the following issues were identified:
Unfiltered Containment Bvoass Leakaos Not AcmJnted For Table 6.2-1, " Containment Design Parameters," of the USAR stated that the maximum allowable unfiltered secondary containment bypass leakage rate was 8 percent of the total maximum allowable containment leakage rate. Table 6.2 47, " Isolation Valve Summary for Lines Penetrating Containment," of the USAR identified the containment
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isolation valves and penetrations that were in bypass leakage pathways.
Section 6.2.4.3.2.3, " Evaluation Against Criterion 57," of the USAR provided a discussion of these pathways. Procedure 1305.01F003," Bypass Leakage Summary Sheet," Revision 0, dated October 11,1996, required that the totalleakage through the primary containment isolation valves must not exceed 62.8 standard cubic feet per hour (scfh), which represented this 8 percent value. This procedure implemented the requirements of Technical Specification 3.6.1.3.8, and Attachment 4-4 of the Operational Requirements Manual, Revision 23, dated January 29,1999.
The team identified that RCIC steam line containment isolation valves 1E51-F063 and 1E51-F064 were in a bypass leakage pathway that had not been identified in the USAR and had not been accounted for in Procedure 1305.01F003. Leakage from these containment isolation valves would migrate down the RCIC steam line to the steam line drain pot, through drain pot isolation valves 1E51-F025 and 1E51-F026, and finally through the nonsafety-related, nonseismically-qualified drain line that penetrated secondary containment and was routed to the main condenser. Therefore, in the event of a loss-of-coolant-accident, an open bypass leakage pathway that had not been accounted for would exist.
The team discussed this issue with licensee personnel. At the end of the inspection, the licensee planned to add the contribution from the RCIC steam line containment isolation valves to the total bypass leakage prior to plant restart. A review of the most recent measured leakage rate indicated that this additional contribution was small, and that Technical Specification limits would not be exceeded.
Criterion lil, " Design Control" of Appendix B to 10 CFR 50 requires that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specificatens, drawings, procedures, and instruchons.
The failure to include all potential bypass leakage flowpaths into the total bypass leakage was an example where this requirement was not met and was a violation.
However, this Severity Level IV violation is being treated es a Non-Cited Violation (NCV 50461/99003-02), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as condition report 1-99-02-193.
Potentially inadeouate Flow in RCIC System Minimum Flow Pathway General Electric system design specification 22A3124BK, Revision 0, "DSDS Reactor Core isolation Cooling System," required that the RCIC minimum flow orifice, 1E51-D005, be sized to provide 85 gpm i 10 percent. During RCIC system startup
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testing in 1987, it was discovered that the flow did not conform with the specification and the orifice would allow only 69.7 gpm vice the required 76.5 gpm. General Electric evaluated this condition, and generated Field Deviation Disposition Request LH1-5805,
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dated June 26,1987, which revised the flow speafication to add the following statement:
"The orifice may be sized for 60 to 76 gpm flow through the bypass line, provided that the operation of the RCIC pump under these conditions shall be limited to less than
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20 seconds in order to prevent potential degradation of the pump intemal parts." No change was made to the orifice, and this minimum flow time restriction was subsequently j
incorporated into the RCIC plant procedures.
The team questioned whether the system configuration was adequate to meet the design requirements for the full range of operating conditions. In particular, for low decay heat conditions, the corresponding RCIC injechon flow could be so low as to require that either the RCIC turbine be operated at very low speed, or that part of the pump flow be bypassed through the minimum flow line. Since this latter option was not available due to the 20-second time limit, the requirements of the operating procedures may not be accomplished in a low flow condition.
At the end of the inspechon, the licensee had not resolved this concem. The licensee planned to resolve this issue by May 1999. This is an inspechon followup item (IFl 50-461/99003-03) pending NRC review of the licensee's corrective actions.
System Lee %t= Condition Report Closed Without Corrective Action information Notice 91-56, " Potential Radioactive Leakage to Tanks Vented to Atmosphere," dated September 19,1991, informed licensees of potential problems resulting from the leakage of isolation valves in emergency core cooling system piping to storage tanks vented to atmosphere. Such leakage represented the potential for unquantified radioactive releases in a design basis accident. This leakage was required to be controlled by NUREG-0737, Action item lli.D.1.1, " Integrity of Systems Outside Containment Likely to Contain Radioactive Material."
Engineering work request 92-00855, dated November 10,1992, was generated to evaluate information Notice 91-56. The engineering work request response identifMxl that the potential for such leakage existed at the isolation valves between the RCIC and high pressure core spray (HPCS) systems and the RCIC storage tank. It also documented an initial calculation which used design basis assumptions and a 1.0 gpm leak mie into an empty RCIC tank. This leak resulted in calculated exposures well in j
excess of 10 CFR Part 100 limits and the control room exposure limits of 10 CFR 50, Appendix A, Criterion 19. However, the RCIC system leakage acceptance criterion in Procedure 9861.05D004, "RCIC Closed Loop Outside Containment Test," Revision 28, dated February 10,1997, was 4.0 gpm, and the HPCS system leakage acceptance criteria in Procedure 9861.05D003,"HPCS Water Leakage Rate Data Sheet,"
Revision 23, dated October 8,1996, was 6.0 gpm. A subsequent calculation, RTER 95-014-ED, " Calculation of Offsite and Main Control Room Dose Due to a Leak
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From the RCIC Tank Vent in the Event of a Design Basis Loss-of-Coolant-Accident,"
Revision 0, dated May 26,1995, using more realistic assumptions and inputs, and an assumed 2.0 gpm total leakage rate into the RCIC storage tank (1.0 gpm each for the
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RCIC and HPCS systems), indicated that the effects of such leakage would be insignificant.
The corrective actions identified to address Information Notice 91-56 and engineering work request 92-00855 were to issue new test procedures and revise Procedure 9861.05D003 and Procedure 9861.05D004 for the interfacing valves. This engineering
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work request was closed out on October 2,1995, without these actions having been j
taken instead, the engineering work request stated that the actions would be tracked by submitted comment control forms to the Plant Staff Procedures Group. During this inspecten, the team identified that these actions had not been completed. The team discussed this finding with licensee personnel. Subsequently, the licensee determined that although this action was not completed as required, a review of historical leakage rate data indicated that the maximum allowable 1.0 gpm leakage rates for the RCIC and HPCS systems had not been exceeded.
Criterion XVI, " Corrective Action," of Appendix B to 10 CFR 50 requires that measures shall be established to assure that conditions adverse to quality, such as deficiencies, shall be promptly identified and corrected. The failure to revise procedures to reflect the accurate maximum leakage of isolation valves in emergency core cooling system piping to storage tanks vented to atmosphere was an example where the requirements of 10 CFR 50, Appendix B, Critenon XVI, were not met and was a violation.
However, this Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/99003-04), consistent with Appendix C of the NRC Enforcement Policy.
This violation is in the licensee's corrective action program as condition report 1-99-02-177.
Updated Safety Analysis Recori Error During the review of the allowable containment bypass leakage rate, the team determined that the maximum allowable containment bypass leakage rate identifkx1 in USAR Secten 6.2.4.3.2.3, " Evaluation Against Criterion 57," was incorrect. Although the bypass leakage formula accounted for the containment volume by weight (i.e., the number of standard cubic feet), the calculation did not convert the containment free volume in cubic feet into standard cubic feet. As a result, the allowable bypass leakage rate identified in the USAR,908 ft*/ day, was incorrect. Corrected for accident pressure, this value should have been 1,507 standard A8/ day, or 62.8 scfh, the value used for the acceptance criteria in Procedure 1305.01F003, " Bypass Leakage Summary Sheet,"
Revision 0, dated October 11,1996. The licensee planned to address this error during their USAR review project which was in progess at the end of the inspection. Since this error was not translated into other design or licensing basis documentation, the error was determined to be of only minor significance.
Maximum Allowable Suporess'en Pool Temperatur, Cooling water for the RCIC pump and RClO turbine lubricating oil was provided by a 2-inch line from the pump discharge piping that was routed to the lube oil cooler through a pressure control valve, a flow orifice, and then retumed to the pump suction piping.
Under certain conditons, the safety-related suppression pool would be used as the RCIC pump sucten source. The suppression pool could also be used as the safety-related
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heat sink for the reactor and for the RCIC turt>ine itself. The temperature limit for the suppression pool to assure that it could provide the required cooling for the RCIC lube oil cooler was 140 degrees fahrenheit (*F). This limit was specified in General Electric Purchase Specification 21 A9443, " Reactor Core isolation Cooling Pump," Revision 4, dated June 4,1976, and was also reflected in USAR Section 5.4.6.2.2.2, _"[RCIC System)
Design Parameters."
However, the team identified that plant emergency operating procedure did rot reflect this limit. Specifically, the following caution statement was identified: " Operation of the RCIC turbine with suction temperature above 185'F (maximum allowable cooling water temperature for RCIC lube oil) may result in equipment damage." Condition report 1-99-02-388, dated February 24,1999, was generated to resolve this discrepancy. The team determined that since the emergency operating procedure in question addressed conditions outside the design basis of the plant, the issue had minor significance.
b.3.4 RCIC System Modifications and Calculations The team reviewed documentation regarding modifications and calculations performed on the RCIC system and concluded that overall the modifications and calculations were adequately conducted However, the following deficiencies were identified:
Non-Conservative Poe Roughness Calculation Assumption Calculation 01Rl13, "NPSH [ Net Positive Sucten Head) Calculation - RCIC Suction from Suppression Pool (Licensing Basis)," Revision 0, dated July 8,1998, was performed to demonstrate that the RCIC pump available net positive suction head would be more than that required for the worst case design basis conditions. The calculated available net positive suction head was 37.6 feet versus the required 21.0 feet. Therefore, the available net positive suction head was adequate.
However, the team identified that the calculation used an absolute roughness coefficient, c, for clean commercial steel pipe. This was non-conservative since this relatively smooth piping condition would only exist for a short period of time when the pipe was initially installed.
The team discussed this issue with engineering personnel. At the end of the inspection the licensee planned to re-perform the calculation assuming a more realistic piping roughness. The team calculated that if the absolute roughness for cast iron piping were used, which would more closely represent a corroded steel surface, this would reduce the available not positive suction head by about 2 feet. Because there would be adequate available net positive suction head with the correction, the team concluded that the error was of only minor safety significance.
Criterion lil, " Design Control," of Appendix B to 10 CFR 50 requires that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The failure to assume a conservative roughness coefficient in calculation 01Rl13 was an example where the requirements of 10 CFR 50, Appendix B, Criterion lil, were not met
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and was a violation. However, this failure constitutes a violation of minor significance and is not subject to formal enforcement action.
Non-Conservative RCIC Turbine Heat Loss Calculation Assumotion Due to physical interferences in several locations, thermal insulation specification requirements for RCIC turbine insulation thickness could not be met. Calculation IP-M-0432, "RCIC Turbine Heat Loss with 3" and 2" Insulation," Revision 0, dated October 23,1996, was generated to demonstrate that with reduced thicknesses, the additional heat losses would be acceptable with regard to the environmental qualification of equipment in the room.
The team reviewed this calculation and identified that the assumed turbine outer surface temperature of 250*F was non-conservative. This temperature was based on the expected room conditions for a RCIC steam line break. However, this temperature was inappropriate since for this event the RCIC system could not operate. Engineering personnel agreed with the finding and informally substituted 145'F, the room temperature for shutdown conditions from the design criteria, into the calculation. The increased heat load was insignificant with respect to the maximum total room heat load.
Therefore, the team concluded that the error was of only minor safety significance.
Condition report 1-99-02-376, dated February 23,1999, was generated to enter this issue into the corrective action program.
Criterion 111, " Design Control," of Appendix B to 10 CFR 50 requires that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures and instructions. The failure to assume an appropriate RCIC turbine outer surface temperature in calculation IP-M-0423, "RCIC Turbine Heat Loss with 3" and 2" Insulation," was an example where the requirements of 10 CFR 50, Appendix B, Criterion lil, were not met and was e, violation. However, this failure constitutes a violation of minor sigriificance and is not subject to formal enforcement action.
I b.3.5 Comoarison of RCIC Review Findinos to SDFV Results The SDFV project and expansion activities identified numerous issues regarding the functional capability of systems relative to the design and licensing basis. In particular, problems with the control and accuracy of calculations, inadequate acceptance criteria for surveillance tests, USAR errors, and missing design basis documentation were identified. However, the SDFV concluded that the consequences of the deficiencies were minimal and were accommodated within the margin of the design.
As discussed above, the team also identified problems related to calculation errors, missing design basis documentation, surveillance testing deficiencies, and USAR errors.
However, consistent with the conclusions in the SDFV, the impact of these deficiencies were within the design margin of the system and had limited individual consequences.
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b.4 Assessment of Correcthre Actions Associated With SDFV Findinas The team reviewed the implementation of corrective actions identified in condition reports which were generated as a result of the SDFV reviews. In most cases, the team determined that corrective actions to address SDFV findings were adequate to prevent recurrence and were adequately implemented. However, the following deficiencies were identified.
Coridition Report 1-98-05-168 Condition report 1-98-05-168 was generated to document that the use of the
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containment spray reset timer pushbutton could establish containment conditions
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following a small break loss-of-coolant-accident which were not bounded by the current accident analysis. The licensee conducted an apparent cause evaluation and determined that operators were provided training on the reset timer pushbutton.
However, the apparent cause evaluation preparer was unable to identify any reason for operations personnel to use the pushbutton during an emergency condition. As a result, the apparent cause evaluation preparer proposed to revise the respective operations j
training material to state that there were no specific known circumstances when the use
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of the containment spray timer reset pushbutton would be necessary or desirable.
Following a review of this condition report, the team determined that operations personnel had utilized the reset timer pushbutton during an emergency preparedness exercise. This disenvery contradicted the apparent cause evaluation which concluded that there were no known circumstances when the reset timer pushbutton would be used. - The team discussed this contradictory information with the apparent cause evaluation preparer, operations personnel, and the containment spray system engineer.
Operations personnel informed the team that the reset timer pushbutton was used in Emergency Operating Procedure 6, " Primary Containment Control," Revision 24, and was discussed in Procedure 3312.01, " Residual Heat Removal System," Revision 30,
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Based upon this new information, the licensee planned to revise the apparent mee evaluation and the corrective action plan to state that the reset timer pushbutton should only be utilized as directed by procedure. The team concluded that the apparent cause evaluation was ret adequate and the implementation of the corrective action process was wesk. The team also determined that since the pushbutton was only used in conditions outside the design basis of the plant, this error had minimal safety significance.
Condition Report 1-96-05-067 Condition report 1-98-05 067 was generated to document that RHR system valve interlocks were not tested periodically or following maintenance or modification activities.
l An apparent cause evaluation deterinined that the potential interlock problem did not I
constitute a condition adverse to quality since interlock bypassing was controlled by
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Procedure 8801.06, ' Wire Removal / Jumper Installation," Revision 16. An extensive review was not completed due to the large number of valve interiocks in the plant.
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The team was concemed that the apparent cause evaluation did not completely evaluate the extent of this condition. During discussions with engineering personnel, the team explained that the use of a jumper and lifted lead form to ensure interlock integrity during maintenance or modification activities may not be adequate since this type of control did not meet the requirements of 10 CFR 50, Appendix B, Criterion XI, " Test Control." In response, engineering personnel stated that many of the interlocks were tested daily using the self-test system and that interlock testing was completed following modification activities. However, none of this information appeared in the apparent cause evaluation report. Due to the lack of information, the team requested that engineering personnel provide documentation to demonstrate that valve interlocks previously subjected to maintenance or modification activities would perform their intended function.
In response, the licensee used the results of a review of Generic Letter 96-01, " Testing of Safety-Related Logic Circuits," to demonstrate that many of the interiocks were periodically tested under the surveillance testing program. As discussed in Section E8.13, the team concluded that the licensee's Generic Letter 96-01 program guidelines were appropri?te and were adequately implemented.
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To address interiocks outsida the scope of the Generic Letter 96-01 program,
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maintenance personnel reviewed three recently completed work packages. The licensee determined that post-maintenance and post-modification testing was completed as long as a test procedure existed. However, when no test procedure was in place or when restoring a simple lifted lead condition, a jumper and lifted lead form was utwed to control the activity, rather than completing functional testing or continuity checks.
Licensee personnel recognized that the use of the jumper and lifted lead form could result in errors since the form did not ensure that previously distu,oed interlocks continued to function following maintenance. As a result, condition report 1-99-03-063 was generated to document weaknesses in the post-maintenance testing process.
However, licensee personnel believed that the results obtained from reviewing the three recently completed work packages and the results of the Detailed Design Review and Engineering Product Review demonstrated that interlock testing following ridn% nance or modification activities was not a concem. The team questioned this conclusion for the following reasons:
Two of the three work packages selected for review would not have provided
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information regarding a potentialinteriock testing problem. One of the selected packages received significant attention by the Senior Engineering Rev'ew Group to ensure that a previously identified interlock issue was corrected prior to retuming the component to service. The somnd work package was completed on a valve which did not have interlocks.
The licensee had not reviewed any maintenance or modification activities
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completed recently to ensure that appropriate testing was completed prior to retuming the equipment to service.
To address these concems, licensee personnel reviewed two additional post-maintenance work packages. Subsequently, condition report 1-99-03-198, dated March 13,1999, was generated and identified that component cooling water
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motor-operated valve 1CC0758, " Fuel Pool Cooling Heat Exchanger 1B CCW
[ Component Cooling Water) inlet Valve," limit switch rotor contact 14/14C was in an incorrect electrical arrangement. This contact interlocked motor-operated valve 1SXO62B, "FC [ Fuel Pool Cooling) Heat Exchanger 1B SX [ Shutdown Service Water)
Outlet Valve," open to prevent crosstleing lake water with the component cooling water system. This type of permissive was considered a manual interlock, was not covered by the Generic Letter 96-01 program or Technical Specifications, and was the type of interlock that concemed the team. Procedure 1014.05," Preparation of Post-Maintenance Testing," stated, "... funcl.ionally test any interlocks affected by the work activity. This could be physicalinteriocks or electricalinterlocks." However, Procedure 1014.05, Appendix A, regarding recommended post-maintenance testing stated, in part, that interlock functional testing was only required if""* ' intemals were replaced and/or rebuilt. The recommended testing did not require it i functional testing for control
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circuit maintenance to ensure that a contact feeding, A :er component control circuit would function properly following maintenance. Licer W wrsonnel acknowledged that the testing matrix did not cover all maintenance activiks, which left the testing determination up to the maintenance planner. Licensee personnel indicated that they would review the recommended testing matrix to identify additional activities in which functional testing was required. In addition, the licensee expanded their review to identify other safety-related and nonsafety-related interlocks that had the potential to initiate an operational transient, and initiated efforts to review all interlock-related modification packages prior to plant restart to ensure that proper testing was completed prior to retuming components to service. The team considered the issue regarding the adequacy of interlock testing to be an inspection followup item (IFI) pending a review of the results of the licensee's additional planned actions (IFl 50461/99003-05).
Condition Reoort 1-98-04-194 This level 4 condition report was initiated when RHR shutdown cooling valve 1E12-F006A failed to stroke open during surveillance testing. An apparent cause evaluation report stated that the root cause was unknown. An extent of condition review was not completed since this type of review was not required for level 4 condition reports.
On May 2,1998, maintenance personnel completed maintenance work request D82808 and determined that 1E12-F006A failed to stroke open due to a defective torque switch.
A new torque switch was installed and post-maintenance testing was completed satisfactorily.
On May 21,1998, the apparent cause evaluation preparer closed condition mport 1-98-04-194 to maintenance work request D82808. Although the work directed by maintenance work request D82808 was completed on May 2, maintenance personnel did not revise the apparent cause evaluation report prior to closure. As a result, an extent of condition review was not completed to determine if defective torque switches j
were an adverse trend.
The team questioned why the apparent cause evaluation report was not revised prior to closing the condition report. On March 2,1999, maintenance personnel informed the team that the apparent cause evaluation report was not revised prior to closure due to human error. Specifically, the individual that closed the condition report searched the
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maintenance work request database and determined that maintenance work request D82808 was open. However, the individual failed to verify whether the work completed under the maintenance work request had been completed and if an apparent cause had been identified. The team considered the failure to revise the condition report with the appropriate apparent cause to be a corrective action program implementation weakness.
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At the end of the inspection, the licensee planned to revise the apparent cause evaluation and perform an extent of condition review, c.
Conclusions
. Based on the review of the SDFV project findings, as well as an independent review of
- the RCIC system, the team concluded that the results of the SDFV project were valid and that the licensee had established reasonable assurance that safety-related structures, systems, and components would perform their intended safety functions as described in the design and licensing basis. Case-Specific Checklist item VI.1," Provide Reasonable Assurance That Safety-Related Structures, Systems, and Components Will Perform Their intended Safety Funchons as Described in the Design and Licensing Basis," is closed.
The team also identified a number of examples where engineering personnel failed to ensure that problems were adequately resolved through the implementation of effective corrective actions.
E1.4 Review of NRC Case-Soecific Checklist item VI.2 a.
Insoection Scooe (37550)
The team reviewed NRC Case-Specific Checklist item VI.2, " Validate the Adequacy and Control of Calculations." To address this checklist item, the team assessed corrective actions implemented from the SDFV, including revisions to the calculation crntrol process, and evaluated core reflood calcula'Jons.
b.
Observations and Findinos b.1 Background On October 20,1997, Illinois Power issued the Integrated Safety Assessment (ISA)
report which comprehensively reviewed CPS performance. On January 2,1998, the NRC issued a Special Evaluation Team (SET) report which documented the NRC's review of the rescits of the ISA effort. The ISA and SET reports identified a number of
issues related to calculations. In particular, the report concluded that calculation revisions were generally difficult to link to other associated calculations and procedures affected by the changes, which resulted in calculations which were not always updated.
In addition, the ISA identified concems regarding adherence to Technical Specification requirements with regard to developed differential pressure across emergency core cooling system (ECCS) pumps required to meet injection flow requirements.
The SDFV also identified calculation and calculation control weaknesses. To determine the scope and impact of these weaknesses, a Detailed Design Review (DDR) was
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performed. This effort evaluated 111 recently completed multi-discipline engineering products which included 40 calculations. The review scope included calculation assumptions, design inputs, references, and methodology. Although numerous calculational errors such as incorrect assumptions, improper design inputs, and incorrect calculation methodologies were identified, none of these errors resulted in the loss of structure, system, or component function. Additional detailed calculation reviews were performed as part of the Detailed Calculation Review (DCR) process with similar results.
During this inspection, the team reviewed the actions to address the calculation concerns identified in the ISA and SET reports as well as the SDFV and SDFV expansion projects, b.2 Assessment of Corrective Actions and Calculation Process Revisions To address the calculation weaknesses identified in various assessment initir tives, improvements to the calculation control process were implemented in two revisions to calculation control procedure E.1, " Calculations." Revision 9 was approved on October 6,1998, which added requirements to ensure calculations were ngorously controlled through increased supervisory involvement. The revision also added calculation revision process improvements, and established standard format requirements for recording information in calculations, in addition, the licensee planned to issue Revision 10 to calculation control procedure E.1 prior to restart. The primary purpose of Revision 10 was to authorize the use of a new calculation index. The team reviewed the completed and planned revisions to calculation control procedure E.1 and concluded that the actions described above would strengthen the calculation control process.
The licensee completed calculation control process training for engineering personnel on March 5,1999. This training included calculation control procedure E.1 and the new calculation index database. The team reviewed the training materials and determined that the information oresented adequately addressed the calculation control process.
Lotus Notes Calculation index The team identified that the creation and implementation of the Lotus Notes Calculation index as the controlled calculation data base would significantly improve the control and identification of calculation data. The database contained about 10,000 of the most frequently used calculations. Calculations not in the database were to be controlled by administrative processes already in place. The initial calculation review validated all I
50 informational fields for about 6,000 calculations and validated about 30 fields for the remaining 4,000 calculations. The fields validated for the 4,000 calculations were appropriate to ensure that the calculation of record would be used by the engineering staff. The licensee indicated that long-term data base reviews would include a complete validation of the 4,000 calculations. During this inspection, the team verified that several calculations correctly referenced other dependent calculations and surveillance procedures.
The licensee planned to ensure database information was controlled by a database manager and other administrative personnel. At the end of the inspection, the licensee
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was in the process of reviewing the calculation list to determine which calculations were critical calculations containing operational, licensing basis, and design basis information.
b.3 Evaluation of Core Reflood Analysis Calculations The ISA report identified concems regarding the Technical Specification requirements with regard to developed differential pressure across ECCS pumps to meet injection flow requirements. To address this concem, detailed reviews of all ECCS pump performance Technical Specification surveillance tests were completed.
The team discussed these reviews with licensee personnel and concluded that the licensee had established an appropriate methodology to conduct the reviews. In particular, the team recognized the incorporation of emergency diesel generator frequency variations into system performance as conservative and thorough.
The team also reviewed the HPCS system surveillance testing procedures and supporting calculations to provide a sample assessment of the quality of the licensee's review of ECCS system performance. Although no deficiencies were identified, the team was concemed that the testing point specified by the Technical Specifications was at a location on the pump curve which was not representative of the actual injection pressure
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I and flow. The team discussed this concem with engineering personnel. During that discussion, engineering personnel indicated that this same concem had been identified and that if the pump degraded 10 percent as allowed by American Standards for Mechanical Engineers Code,Section XI," Inservice inspection Program," HPCS system performance would not meet design basis requirements. To address this issue, the licensee revised the surveillance test procedure to increase the acceptance criteria by the amount necessary to assure that HPCS system performance would be adequate over the full operating range of the system. The team concluded that the licensee had adequately resolved this issue.
c.
Conclusions The team concluded that the licensee had satisfactorily addressed calculation control issues and had conducted a sufficient calculation review to provide reasonable assurance that structures, systems and components would be able to perform their specified safety function. Case-Specific Checklist item VI.2, " Validate the Adequacy and
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Control of Calculations," is closed, i
E1.5 Review of NRC Case-Soecific Checklist item VI.3 a.
Insoection Scope (37550)
The team reviewed NRC Case-Specific Checklist item VI.3, " Validate the Adequacy and Control of the Setpoint Program." To address this checklist item, the team assessed corrective actions implemented from the SDFV and SSTR reviews, including the revisions to the setpoint control process, and evaluated selected setpoint calculations.
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b.
Observations and Findinas b.1 Background The NRC Special Evaluation Team report identified that procedures for the control of setpoints did not clearly define a standard setpoint methodology. In addition, the program failed to correctly and consistently address setpoints and instrument inaccuracies.
In addition, the SDFV project identified missing surveillance tests and inadequate surveillance test acceptance criteria. As a result, the SSTR project was initiated to determine if surveillance test acceptance criteria fulfilled Technical Specification requirements. This was satisfied, in part, by identifying the critical instrumentation used to ensure design basis limits were not exceeded, and verifying that adequate setpoints associated with the instruments had been established. In particular, associated setpoint calculations were reviewed to verify that assumptions and design inputs were correct, the calculation methodology was reasonable, and that the calculation conclusions were properly translated into surveillance test acceptance criteria. At the end of this review, the licensee concluded that significant problems existed with the control of setpoints.
b.2 Assessmenbf Revisions to the Setooint Control Process To address issues associated with the setpoint control program, Procedure 1003.09,
" CPS instrument Setpoint Program Interfaces," Revision 0, dated January 18,1999, was created and Cl-01.00, " Instrument Setpoint Calculation Methodology," was significantly revised.
The purpose of Procedure 1003.09 was to formally establish an upper tier procedure to describe the setpoint program including the delineation of the elements of the program, the roles and responsibilities of various plant organizations which implement the program, and the identification of the various documents used in the program. The purpose of Cl-01.00 was to provide the methodology for the determination of instrument uncertainties and setpoints. It was extensively revised to provide improved guidance for the calculation of setpoints and for the identification of all input data applicable to the calculation.
The team reviewed Procedure 1003.09, and determined that this procedure required that setpoint changes be processed as a modification in accordance with Procedure 1003.01,
" CPS Hardware Change Program." This process included a multi-disciplinary engineering staff impact assessment of the proposed change. Procedure writers were providad with a list of " key attributes" that discussed information such as measuring and test equipment accuracy and transmitter process corrections that were design input information used to establish instrument setpoints.
Although the control and instrument procedure writers used Procedure 8801.05,
" Corrections to Instrument Calibrations," to conduct process correction calculations, the procedure writers did not always inmive engineering in the review of such calculations.
The team reviewed several calculations and did not identify any that were incorrectly performed At the end of the inspection, the licensee planned to add the " key attributes"
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to Procedure 1005.01, " Procedures and Documents," and require that calculation control procedure E.1, " Calculations," and Procedure 1003.01 be referenced when revising " key attribute"information. In addition, the procedure writers were to be trained on recognizing design input procedure information.
b.3 gyaluation of Control and Instrumentation Setooints To assess the effectiveness of the revised setpoint program, the team reviewed a sample of recently completed setpoint calculations which utilized the revised setpoint methodology. The team determined that the methodology followed current industry setpoint uncertainty calculation practices. Fourteen setpoint calculations were reviewed.
The calculations established their respective setpoint in an adequate manner and each setpoint was correctly scaled, including head and tail corrections, in their respective instrument calibration procedure. No deficiencies were identified.
Licensee personnel identified 852 instruments that were considered to be either Regulatory Guide 1.105 type instruments (General Electric reactor protection system and engineered safety feature actuation instrumentation), Regulatory Guide 1.97 type instruments, or other Technical Specification related instruments. These instruments were to be reviewed prior to plant restart. About 25 percent of the setpoint packages were in the owner review process with the remainder in the review package development process. This review was assessing whether sufficient margin existed in the setpoint calculations to ensure that field setpoints would be set correctly. A few field setpoints were identified to be non-conservative with respect to design documents; however, no analytical limits were identified as exceeded since sufficient design margin existed in the calculations. Setpoint setting errors were corrected in the plant and in surveillance procedures. In the short term, until the setpoint calculation upgrade program is complete, the licensee planned to perform an operability determination for all associated instrument setpoints to demonstrate their operability over the next operating cycle.
c.
Conclusions The team concluded that the licensee had implemented satisfactory controls to ensure setpoint calculations would be prope 1y controlled and were performing appropnate setpoint reviews to ensure safety-related setpoints were conservatively set in the field.
However, the setpoint operability determination for the next operating cycle was not available for review by the team. Case-Specific Checklist item VI.3 will remain open pending NRC review of the safety-related setpoint operability determination.
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E1.6 Design Modifications a.
Irme Scope (37700. 37550)
The team revewed documentation associated with other recently completed modifications unrelated to the RCIC system and conducted system walkdowns to verify proper installation. Documents specifically reviewed included the following, where i
applicable:
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i 10 CFR 50.59 safety evaluation
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Supporting calculations
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Operating and emergency operating procedure changes
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Operator training
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Revisions to as-built drawings
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Revisions to the USAR
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b.
Observations and Findinos i
Overall, the modifications reviewed by the team were adequately designed and installed.
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However, the team identified the following post-modification testing deficiencies:
Post-Modification Testina Not Conducted As Reauired The team reviewed exempt change notices 29979 and 29980 which removed the auto-restart relays from safety-related chillers OVC13A and OVC13B to prevent the chillers from automatically starting during the recovery from a loss-of-offsite-power. The team identified that maintenance work request D75078 associated with exempt change notice 29979 which was completed in January 1997, failed to specify required post-modification testing. Subsequently, the licensee determined that the modification had been adequately tested during the performance of Procedure 9080.21 " Emergency Diesel Generator 1 A-ECCS Integrated," in October 1998.
Criterion XI, " Test Control," of Appendix B to 10 CFR 50 requires that a test program be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. The failure to prescribe adequate safety-related chiller post-modification testing was an example whers the requirements of 10 CFR 50, Appendix B, Criterion XI, were not met and was a violation.
However, this Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-481/99003-06), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as condition report 1-99-02-189.
Post-Modifk.t;on Testina Revised Without Anorooriate Review
During a review of modification AP-33, Supplement 4," Division i Regulating Transformer-Control Building Motor Control Center 'A' Transformer," the team
identified that a step to conduct a post-modification megger test of transformer 0AP24ERT was removed from the modification package without documenting and evaluating this change on a " Detailed impact Assessment Form" as required by
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Procedure 1003.01, " CPS Hardware Change Program." However, since a megger test was performed prior to installation and other prescribed post-installation testing would have identified this problem, the issue was considered to have only minor safety significance. Condition report 1-99-02-406 was generated to enter this issue into the corrective action program.
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Criterion V,'* Instructions, Procedures, and Drawings," of Appendix B to 10 CFR 50 requires that activities affecting quality shall be prescribed by procedures appropriate to the circumstances and shall be accomplished in accordance with those procedures. The failure to complete a detailed impact assessment to revise modification AP-33 was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violation. However, this failure constitutes a violation of minor significance and is not subject to formal enforcement action.
c.
Conclusions Overall, the team concluded that the modifications reviewed were adequately designed, installed, and tested. However, two deficiencies related to post-modification testing were
identified.
E2 Engineering Support of Facilities and Equipment E2.1 Fuse Controlissues a.
Inspection Scope (37550)
The team assessed the licensee's efforts to address previously identified fuse installation deficiencies.
b.
Observations and Findinas b.1 BackarouM in 1991, the NRC issued Information Notice 91-51, " inadequate Fuse Control Program,"
which identified a number of areas of concern with fuse control programs in the nuclear industry.- During an Electrical Distribution Safety Functional Inspection in 1993, and as documented in NRC Inspection Report 50-461/93003, the NRC identified that CPS did not have a formal fuse control program. The NRC also identified that the only controlling document for fuse replacement was Plant Manager Standing Order (PMSO) 052 which was limited to "like-for-like" replacements and did not cover fuse dedication, fuse inspection criteria, selection of fuse types, fuse characteristics, or fuse quality
' requirements.
In 1995, Quality Assurance Surveillance Report Q-17137, " Fuse Replacement Program,"
identified that significant weaknesses existed in Climon ause control program implementation, documentation, effectiveness, and controls. Numerous condition reports were issued for installed fuses that were of a rating or type which differed from design documents, in March 1998, condition report 1-98-03-163 was issued to document that PMSO-052 failed to ensure that correct fuses were installed in the plant during replacement and included a corrective action plan to ensure that an upgraded and controlled fuse replacement program was in place.
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As discussed in NRC inspection Report 50-461/98017 and Section E1.1 of this report, licensee personnel identified that 23 of 79 fuses inspected in accordance with Procedure 8410.04. " Molded Case Circuit Breaker / Bucket Component Functional Testing and Maintenance," were the incorrect fuse type.
b.2 Licensee Corrective Actions To address the fuse control problems discussed above, a field walkdown of safety-related fuses was conducted to ensure that the installed fuses conformed with design documentation. During initial walkdowns, licensee personnel identified that approximately 30 percent of the fuses inspected were incorrect. As of March 9,1999, 1304 safety-related fuses had been inspected of which 32 were of an incorrect rating and 265 were of an incorrect type. About 23 percent of the fuse inspected were identified to in some way deviate from the fuses characteristics specified in the design drawings. As a result of their initial findings, the licensee planned to walkdown and verify all safety-
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related fuses against design drawings prior to plant restart.
l in the past, fuse data in the Master Equipment List (MEL) was not verified to be in
agreement with design or vendor documents. The MEL was used to identify the fuse stock codes for replacing blown fuses. To address this issue, the licensee planned to enter all fuse data into the MEL and update applicable drawings to include fuse equipment identification numbers. In addition, the licensee planned to develop a new procedure for fuse replacement and trending of blown fuses. Operability Determination 1-98-11-157-0D was issued on November 12,1998, to assess the operability of fuses located in the field that may not have the same ratings as those identified on design i
drawings, i
b.3 Team Review During this inspection, the team observed field verification walkdowns of reactor protection system fuses. Walkdown packages and a fuse data sheet which included fuse type, model, and size were used to conduct the walkdowns. Condition reports were initiated to document discrepancies and replam fuses that were not in agreement with design and vendor documents. Engineering evaluations to address the impact of incorrect fuse installations were initiated, but were not expected to be completed until after plant restart. However, the licensee committed to replace all discrepant fuses identified during the walkdowns with correct fuses as specified in design documents.
Overall, the team concluded that the licensee's planned corrective actions were adequate. In particular, the walkdown efforts were well-organized and well-implemented. However, the following deficiencies were identified:
Inaoorooriate Fuse Control Proerem Ooerability Determination Operability Determination 1-98-11-157-OD was completed on January 8,1999, to determine, based on a sample of fuses, the operability of all fuses in the plant. The operability determination concluded that all systems that contain or may contain oversized, undersized, or incorrect type fuses were operable. The team reviewed the operability determination and identified that the following data was used to support a
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oetermination that all installed fuses were acceptable:
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The operability determination concluded that since a walkdown of 20 fuses
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revealed that these fuses were installed as designed, fuses in all safety-related panels would also be installed as designed.
A review of the condition report data base revealed that condition reports had
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been generated to document more than 100 cases of discrepancies between the
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installed fuse and design documents. Of the 100 discrepancies,3 had been reviewed. Licensee personnel concluded that the installed fuse would not have prevented the fuse from performing its design function.
The team discussed this operability determination with licensee personnel and identified the following concems:
The sample size of.uses reviewed was very small compared to the total
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population.
Many of the statements in the operability determination were not based on
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detailed analysis, but rather a cursory review of documents such as schematics.
The operability determination assumed that circuits would always be operable
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with oversized fuses.
For control circuits fed from circuit breakers in a distribution panel, the operability
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determination assumed that a lack of coordination would never disable any other equipment.
The operability determination assumed that surveillance testing would always
reveal the presence of undersized fuses in safety-related circuits.
The team determined that the assumptions in Operability Determination 1-98-11-157-OD were not censervative and that the sample size of the fuses walked down and evaluated was not large enough to make an evaluation with reasonable confidence. In addition, the team concluded that the use of an operability evaluation based on the findings of a -
sample of fuses to evaluate the condition of all fuses was not appropriate. However,
'since the licensee planned to complete walkdowns of all safety-related fuses prior to plant restart, this issue had minimal safety significance.
Emergency Diesel Generator (EDG) Fuse Evaluation During fuse walkdown verifications, the licensee identified that fuses on the primary side of the 4180-volt /240-volt potential transformer T1, used for safety-related EDG underfrequency/overvoltage protection circuitry, had an inadequate short circuit interrupting rating. This transformer supplied the voltage regulator and generator control loads for the safety-related EDGs.
An engineenng evaluation determined that the interrupting rating of these fuses was only i
347 amperes althmagh the maximum available short circuit current at the primary side of
transformer T1 was 49,056 amperes. As a result, the very low interrupting rating of the fuses would not be sufficient to safely clear a fault condition between the fuses and the i
primary side of the transformer. The evaluation stated that the maximum fault
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interruption current of fuses would be exceeded during a fault and result in damage to wiring, the transformer, and the bus bar. The evaluation also stated that a fault on the primary side of transformer T1 would render the EDG inoperable regardless of the types of fuses installed and that the single failure criteria would be met. However, the use of incorrectly sized fuses would cause much more damage to equipment. The engineering evaluation concluded that these fuses were not adequate for the application and recommended that they be replaced on all three safety-related EDG circuits since the same deficiency applied to all three EDGs.
Following NRC questioning, engineering personnel performed a review and stated that the differential protection relay scheme will detect and disconnect the EDG and the bus from the fault. However, it was not clear as to the damage that could result by the time the circuit breakers opened to disconnect the fault with the inadequately sized fuses installed. Licensee personnel informed the team that they planned to modify the fuse holders and replace the fuses with the appropriate type on all three EDG circuits by August 1999. Although single failure criteria were met, the team considered having inappropriately sized fuses in all three EDG circuits not a good practice.
c.
Conclusions in the past, the licensee failed to take appropriate correcove actions to address the inadequate fuse control program and field fuse deficiencies. However, recent efforts to walkdown all safety-related fuses in the plant, replace all incorrectly installed fuses prior to plant restart, and upgrade the fuso control program will provide reasonable assurance that the installed fuses conform to design document requirements and future fuse controls will ensure appropriate fuses are installed. The team identified that the use of an operability evaluation process to evaluate the fuse control program was poor. Also, although the licensee met the single failure criteria with regard to inappropriate fuses installed in the EDG circuits, the team considered having inappropriate fuses in all three EDG circuits not a good practice.
E2.2 Enaineerina Performance Indicator Review
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a.
Inspection Scooe (37550)
The team reviewed the engineering performance indicators to determine whether the indicators were valid.
b.
Observations and Findinos The team reviewed the engineering performance indicators for December 1998 and January 1999, and held discussions with cognizant licensee personnel. The team determined that the definition of each indicator category was not well-defined within ti.e performance indicator report. In addition, the team was unable to understand and interpret the indicators without extensive explanation from licensee personnel. The team discussed these observations with licensee personnel who indicated that a similar finding i
had already been identified and corrective actions were being developed to address this issue.
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ConclutQD1 i
The team concluded that the performance indicators were not stand-alone and were not easy to understand. At the end of the inspection, corrective actions were being developed to address this issue.
E3 Engincoring Procedures and Documentation
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E3.1 10 CFR 50.59 Prooram Review a.
Inspection Scooe (37001)
The team reviewed the implementation of the 10 CFR 50.59 program including procedures for screening changes, tests, and experiments and preparing safety evaluations; the processes for maintaining records, revising the USAR, and reporting to the NRC; and the training and qualifications of 10 CFR 50.59 screening and safety evaluation preparers. In addition, the team reviewed a sample of 10 CFR 50.59 safety evaluations associated with procedure changes, modifications, temporac alterations, and operability determinations.
b.
Observations and Findinas b.1 10 CFR 50.59 Procedure Review The team reviewed Procedure 1005.06, " Conduct of Safety Reviews," Revision 12, and verified that the guidance in this procedure was in conformance with 10 CFR 50.59 and NUREG-1606, " Proposed Regulatory Guidance Related to implementation of 10 CFR 50.59." In particular, the procedure included guidance on assessing and documenting the applicability of safety evaluation screenings and reviews, assessing and documenting whether a change to Technical Specifications or en unreviewed safety question was involved, and maintaining records of 10 CFR 50.59 safety evaluations.
The team concluded that adequate procedural guidance had been established for implementing the requirements of 10 CFR 50.59.
b.2 10 CFR 50.59 Reocttina Review The team verified that all completed safety evaluations were reported to the NRC in accordance with 10 CFR 50.59(b)(2). No deficiencies were identified. However, the team determined that safety evaluation 97-238, dated February 26,1998, which approved a change to USAR Table 3.11-5, " Environmental Zone. Summary Table," was inadvertently omitted from the USAR change log. Subsequently, the licensee determined that the USAR change package was not forwarded from the USAR change originator to licensing as required by step 8.1.1.4 of Procedure 1038.03, " Revising the USAR and the Operational Requirement Manual," Revision 3, dated January 23,1998.
Condition report 1-99-02-125 was generated to identify this issue for entry into the corrective action program.
Criterion V, " Instructions, Procedures, and Drawings," of Appendix B te 10 CFR 50 requires that activities affecting quality shall be prescribed by proceduies appropriate to
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the circumstances and shall be accomplished in accordance with those procedures. The failure to forward a USAR change package to licensing as required by Procedure 1038.03 was an example where this requirem nnt was not met and was a violation.
However, this failure constitutes a violation of minor significance and is not sutlect to formal enforcement action, b.3 10 CFR 50.59 Proaram Trainina Review The team reviewed the materials used in the training cwrse for personnel that prepared 10 CFR 50.59 screenings and safety evaluations and veriC9d that the infomation presented in the course was consistent with NRC guidance. !n addition, the classroom session included detailed design and licensing basis document discussions, as well as numerous examples and exercises. The team also reviewed the qualification of safety evaluation preparers, reviewers, and approvers and verified that each had attended required training and was qualified to perform their assigned role.
b.4 10 CFR 50.59 Safety Evaluation Review The team reviewed a sample of 10 CFR 50.59 screenings and safety evaluations and concluded that, overall, the screenings and safety evaluations were appropriately prepared and were adequate. In particular, the team determined that the preparers reviewed appropnate documents during the preparation of 50.59 screenings and safety evaluations; the 50.69 screenings and safety evaluations adequately addressed the effects of the proposed changes on plant operations, interactions with other systems and components, any new failure modes, and the effects on accidents and transients; and the 50.59 safety evaluations adequately addressed unreviewed safety question criteria.
Review of Safety Evaluation 98-066 The team reviewed safety evaluation 98-066, Revision 0, "USAR Change to Substitute ADS [ Automatic Depressurization System] for RCIC in the Accident Analysis for a Feedwater Line Break Outside Containment." This evaluation was performed to substitute ADS, in conjunction with low pressure ECCS, for the RCIC system during a postulated feedwater line break within the auxiliary building steam tunnel, that renders RCIC not available due to room flooding as identified in condition report 1-97-02-191.
The following issues were identified:
Feedline Break Classification
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On page one of the safety evaluation, the feedwater line break outside containment event was identified as a special cese of a loss-of-coolant-accident. However, the team identified that contrary to this statement,10 CFR 50, Appendix A," Definitions and Explanations," defined a loss-of-coolant-accident as "those postulated accidents that result from the loss of reactor coolant at a rate in excess of the reactor coolant makeup system from breaks in the teactor coolant pressure boundary (emphasis added), up to and including a break equivalent in size to the double-ended rupture of the largest pipe of the reactor coolant system." in addition, paragraph 1 on page 9 of the safety evaluation stated that the ECCS was designed to provide protection against postulated loss-of-coolant-accidents caused by primary system piping and therefore, substitution of
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ADS for RCIC for mitigation of a postulated feedwater line break outside containment did not increase the probability of equipment malfunctions. As a result, the team questioned whether this statement was correct, since a feedwater line break outside containment was not a loss-of-coolant-accident as defined in 10 CFR 50, Appendix A.
Design and Licensing Basis Concems
The team also identified potentially contradictory information in the USAR regarding the design and licensing basis of the RCIC system. In particular, USAR Section 15.6.6,
"Feedwater Line Break - Outside Containment," stated the following: "The RCIC and/or HPCS initiate on low-low water level and restore the reactor water level to the normal elevation. The fuel is covered throughout the trraient and there are no pressure or temperature transients sufficient to cause fuel damage." The use of ADS is not
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discussed in addition, USAR Table 15.6.6-1, which identified the sequence of events for a feedwater line break outside containment, indicated that in less than 30 seconds the reactor low-low water level is reached and in less than 60 seconds, HPCS and RCIC flow enters the vessel.
On the other hand, USAR Figures 15.A.6-43, -44, and -45 were developed as part of the licensee's Nuclear Safety Operational Analysis to demonstrate that essential protection sequences required to aucuirnr.odate plant normal operations, anticipated and abnormal transients, and design basis accidents were available and adequate. These fqures indicated that HPCS or ADS, in conjunction with the low pressure ECCS systems, would be used to address postulated pipe breaks outside containment, including the feedwater line break.' in addition, USAR Section 6.3.3.7.8.4, which discussed ECCS performance, stated that for feedwater and steamline breaks, the worst single failure was the failure of the HPCS system. There was no mention of the RCIC system in this section, although ADS and low pressure ECCS systems were assumed to be available.
The team concluded that the USAR was not clear regarding which systems were assumed to actuate as part of the licensing and design basis to mitigate the j
consequences of a feedwater line break outside containment. In particular, statements in USAR Sechon 15.6.6, "Feedwater Line Break - Outside Containment," appeared to contradict discussions in USAR Appendix 15A, " Plant Nuclear Safety Operational Analysis," and USAR Sechon 6.3, * Emergency Core Cooling System."
This issue was forwarded to the Office of Nuclear Reactor Regulation for technical review as task interface action item 99-004, " Review of Clinton Safety Evaluation 98-066," dated March 15,1999. This is an Unresolved item (URI 50-461/9900347) pending the results of that review.
b.5 10 CFR 50.59 Safety Evaluation Self-Assessment The team reviewed various licensee safety evaluation self-assessment reports. The reports indicated that from July 1998 to January 1999 the licensee made small
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improvements in the areas of condition report generation relating to safety evaluations and safety evaluation rejecten rate by the Facility Review Group. The team also reviewed the Detailed Design Review dated September 1998. This review indicated that
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safety evaluations and screenings received the best grades from all the engineering products reviewed.
The team independently determined that the quality of safety evaluations and safety evaluation screenings had improved. In particular, in the 1996 and 1997 safety evaluations and screening forms, questioned were answered "yes" or "no" without justification for each specife question. Instead, the justification for all questions were combined without distinguishing which question was being addressed. However, in the 1998 safety evaluations and screenings reviewed, preparers provided justification for each question answered.
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Conclusions Overall, the team concluded that the 10 CFR 50.59 screenings and safety evaluations had improved and were of good quality. In addition, the team concluded that the licensee had an adequate program for ensuring that trained and qualified personnel prepared and reviewed 50.59 screenings and safety evaluations.
E4 Engineering Knowledge and Performance E4.1 Enoineerina Personnel Performance Observations a.
Inspection Scope (37550)
The team assessed the overall effectiveness of the engineering staff in implementing the CPS corrective action program. This was accomplished through a review of corrective actions implemented to address plant technical and hardware issues identified in condition reports, engineering work requests, and other documents discussed in this report.
b.
Observations and Findinas The team determined that with regard to the licensee's resolution of significant plant hardware deficiencies affecting the operability of electrical circuit breakers and the electrical distribution system's ability to perform during degraded voltage conditions, the performance of engineering personnel was good. In particular, the licensee's recognition of the potential for future grid voltage degradation and the resultant identification and implementation of plant modifications to proactively address such degradation by revising undervoltage setpoints and installing load tap changing transformers, demonstrated that the engineering staff was capable of recognizing and comprehensively resolving complex technical issues.
The team also noted a number of examples of comprehensive engineering analyses generated in response to engineering issues, with clear and correct results that were correctly implemented in plant procedures and practices. In addition, a number of CPS engineers demonstrated keen technical understanding in their areas of responsibility and understanding of plant design, procedures, organizational interfaces, and responsibilities. For example, the methodology and analyses used to address ECCS
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pump flow concems indicated that the engineering staff was capable of understanding and addressing this technically complex problem.
However, the team also identified a number of examples where engineering personnel failed to ensure that problems were adequately resolved through the implementation of adequate and effective corrective actions. The following specific examples were identifed:
As discussed in Section E1.3, the team identifed that condition report
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1-97-03-182 regarding RCIC Technical Specification 3.5.3.4 surveillance testing assumptions was closed, although the prescribed corrective actions to verify the surveillance testing assumptions were not completed.
As discussed in Section E1.3, the team identifed that engineering work request
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92-00855 issued to evaluate information Notice 91-56 regarding potential leakage paths through tanks was closed although actions to revise procedures to address an identified problem were not completed.
As discussed in Section E1.3, the team identifed an example in which the
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corrective actions to address potential interlock testing problems discussed in condition report 1-9805-067 lacked an appropriate depth of review. As a result, following questions from the team, the licensee identified an additional example in which required interlock testing was not conducted following maintenance.
c.
Conclusions The team concluded that with regard to the resolution of significant hardware deficiencies, the performance of engineering personnel was good. However, the team also identified a number of examples where engineering personnel failed to ensure that probierrg were adequately resolved through the implementation of effective corrective actions. t;
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Miscellaneous Engineering issues E8 E8.1 (Closed) Violation 50461/9700301: Licensee Event Report (LER) 50-461/97018-00:
Failure of Westinghouse DHP Circuit Breakers to Open.
The team verified the curi ctive actions described in the licensee's response letters, dated August 29,1997, and September 29,1997, to be reasonable and complete. To address this issue, the licensee proiivily performed corrective maintenance on all inservice safety-related and critical nonsafety-related Westinghouse 4160-volt DHP-type circuit breakers to reduce the friction in the operating mechanism. In addition, the licensee committed to either replace or refurt>ish all Division 1 DHP breakers prior to plant restart and to replace or refurbish all Division 11 DHP breakers by September 30,1999.
Also, preventive maintenance procedures were upgraded to provide appropriate instructions to perform preventive maintenance activities. Additional discussion regarding the implementation of corrective actions to address this violation is contained in Section E1.1 of this report.
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E8.2 (Closed) Violation 50-461/97003-02: Unapproved Cleaning Compounds and Lubricants on Safety-Related Breakers.
i The team verified the corrective actions tiescribed in the licensee's response letters,
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dated August 29,1997, and September 29,1997, to be reasonable and complete.
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Specifically, the licensee provided " Fundamentals of Lubrication" training to maintenance and engineering staff. In addition, Procedure MS-01.00," Equipment Lubrication Procedure," was significantly revised to specify approved lubricants for electrical breakers, and Procedure 1019.08, " Control of Lubrication," was issued on December 18, j
1998, to provide instructions for the storage, control, and use of lubricants.
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E8.3 (Closed) Insoection Followuo item (IFI) 50-461/97011-16: Seismic Qualification of Circuit Breaker Cabinets.
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I The seismic qualification of safety-related circuit breaker cabinets was based upon having the circuit breakers installed in each cabinet bay, although the circuit breakers were removed from the cabinets during maintenance. The team was concemed that although the affected circuit breaker cabinets were determined to be inoperable when the breakers were removed, probabilistic risk assessment considerations were factored into the operability assessment. This was inconsistent with regulatory guidance and the definition of operability contained in the licensee's Technical Specifications.
Duritig this inspection, the team was informed by engineering personnel that the use of probabilistic risk assessment was not a valid method for determining operability, and that this approach would not be utilized in the future.
E8.4 (Closed)IFl 50-461/97999-16: Generic Letter 89-13 Preventive Maintenance items Not Reviewed.
As discussed in the NRC's Special Evaluation Team report which independently assessed Clinton Power Station performance problems, and a memorandum from K.
Perkins, Office of Nuclear Reactor Regulation, to G. Grant, NRC Region Ill, dated December 5,1997, the results of ultrasonic tests to measure pipe wall thinning had not been evaluated by engineering for tests PMMSXM013 through PMMSXM032.
i During this inspechon, to determine the process in which piping wall thickness measurements were evaluated, the team reviewed the preventive maintenance task card and digital data record for maintenance work request PMMSXM013. The team i
determined that the preventive maintenance task evaluated the measured piping wall
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thickness against a specified minimum value. A condition report reviewed by engineering personnel was required for any test result below the minimum specified value. A search of condition reports issued since January 1997 did not identify any
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reportable condition associated with these measurements. The team concluded that the
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piping wall thickness measurement evaluation process was adequate to ensure appropriate engineering involvement.
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E8.5 (Closed) IFl 50-461/97999-17: Design Problems With Auxiliary and Offsite Power Systems.
The team reviewed this issue during a review of NRC Case-Specific Checklist item IV.4,
" Resolve Degraded Voltage and Electrical Distribution Concems." The team concluded that the licensee's planned electrical distribution system changes and efforts to address degraded voltage concems were good. Additional details of this review are contained in Section E1.2 of this report.
E8.6 (Closed) NCV 50-461/98004-01: Failure to Rely on Local Emergency Diesel Generator I
(EDG) Indication.
I As discussed in NRC Inspection Report 50-461/98004, operations personnel failed to reduce EDG loading during a surveillance test when local indication of an overload condition was identified.
To address this issue, engineering personnel determined the operating parameters that should be monitored locally during EDG operation and incorporated those parameters into EDG operating procedures. In addition, operations personnel were provided i
additional training on local EDG operations and the revised procedures. The team verified these corrective actions to be reasonable and complete. No similar problems were identified.
E8.7 (Closed) NCV 50-461/9800442. Inadequate Residual Heat Removal Fill and Vent Procedure.
As discussed in NRC Inspection Report 50-461/98004, Procedure 3312.01, " Residual Heat Removal," was inadequate since during residual heat removal system fill and vent operations, suppression pool water would be pumped into the residual heat removal system.
To address this issue, the licensee revised Procedure 3312.01, Procedure 4006.01,
" Loss of Shutdown Cooling," arvJ generated Procedure 3312.03, "RHR-Shutdown
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Cooling & Fuel Pool Coolino rnd Assist." The team venfied these corrective actions to be reasonable and complete. No similar problems were identifuxi.
E8.8 (Closed) NCV 50-461/98004-03 : Inadequate Crew Briefing.
As discussed in NRC inspection Report 50-461/98004, operations management failed to ensure that an operating crew was adequately briefed on a loss of shutdown cooling event as required by Procedure 1401.01, " Conduct of Operations."
To address this issue, the licensee took immediate action to brief the operating crews on the response to a loss of shutdown cooling. The operations department also issued a night order to emphasize the requirements and expectations for shift tumovers and other vert >al communications. Finally, the operations department revised their shift tumover process to improve communications between operations personnel. The team verified the corrective actions to be reasonable and complete. No similar problems were identified.
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E8.9 (Closed) NCV 50-461/98004-04: Failure to Evaluate Risk Prior to Maintenance.
As discussed in NRC Inspection Report 50-461/98004, maintenance activities on the nuclear systems protection system regulating transformer were not identified as a higher risk evolution requiring contingency plans and mitigating procedures.
To address this issue, Procedure 1151.09, * Methodology for Outage Safety Reviews and Maintenance of Acceptable Shutdown Risk," was revised to incorporate expectations for risk reviews and work package preparation prior to equipment being removed from service, and trained all Work Week Managers, Operations Coordinators and the Unit Coordinator on the revised procedure. The team verified the corrective actions to be reasonable and complete. No similar problems were identified.
E8.10 {Qlosed) LER 50-461/97007-00: Lack of Procedural Guidelines for Maintaining Seismic Qualification of Breakers.
The licensee identified that during a seismic event, the potential existed for unrestrained circuit breakers in the racked-down position to cause relay chatter in adjacent circuit breaker cubicles which could compromise safety-related equipment. The engineering response to this issue identified that seismic qualification and operability of the Division ill switchgear could not be demonstrated for the General Electric 4160-volt Magne Blast circuit breakers in the racked-down position.
The licensee performed a root cause investigation and determined that CPS procedures did not identify the specific requirements for circuit breaker configuration to maintain seismic qualification of the circuit breakers and switchgear. Due to the low probability of a seismic event occurring simultaneously with a circuit breaker in an unqualified position, the safety significance of the event was determined to be low.
As part of the licensee's immediate corrective actions, a walkdown was conducted to verify that all potentially affected Division ill 4160-volt circuit breakers were in the racked-in position. In addition, an operations night order was issued to require the removal of racked-down General Electnc 4160-volt circuit breakers from the Division 111
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switchgear cubicle to maintain the seismic qualification of the switchgear. As part of their long-term actions, the licensee planned to review and revise the applicable seismic analyses as necessary to address the seismic qualification of the Division lli switchgear i
with the General Electric 4160-volt circuit breakers in various positions.
During this inspection, the team reviewed this event and identified that the licensee used probabilistic risk assessment data to demonstrate that the condition was not safety significant as long as appropriate time restraints were applied. The team noted that data less conservative than that depicted in the USAR was used as a basis for these
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probabilistic determinations. In particular, Figure 2.5-427 of the USAR contained a seismic hazard curve for Clinton Power Station which indicated that the operating basis earthquake had a 0.11g ground acceleration with 0.1g at the foundation level. However, the licensee used Electnc Power Research Institute (EPRI) Report RP-101-53,
"Probabilistic Seismic Hazard Evaluation for Clinton Power Station," as a basis for the probabilistic risk assessment calculations, which contained less conservative parameters. When questioned by the team, engineering personnel stated that the EPRI
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information was more recent than that contained in the USAR. Engineering personnel also noted that implementing the USAR numbers would not significantly impact the results. At the end of the inspection, the licensee planned to re-perform the calculations using the more conservative USAR data.
Criterion lil, " Design Control," of Appendix B to 10 CFR 50 requires that measures shall be established to assure that the applicable regulatory requirements and the design basis are correctly translated into procedures. The failure to translate requirements for maintaining the seismic qualification of circuit breakers into procedures was an example where the requirements of 10 CFR 50, Appendix B, Criterion ill were not met and was a violation. However, this Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/99003-08), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/97007-00.
E8.11 (Closed) LER 50-461/97008-00: LER 50-461/97010-00/01: Emergency Diesel Generator Undervoltage Relays inoperable and incorrect Voltage in Procedure for Verification of Offsite Power Sources.
In April 1992, engineers raised a concem that the setpoints for the second level undervoltage relay in the auxiliary power system may not be correctly set to provide adequate voltage for proper operation of all required equipment. The second level undervoltage relay was designed to transfer safety-related electrical loads to the
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associated emergency diesel generator in the event of a sustained degraded voltage condition or a loss of normal offsite power. Subsequently, the licensee identified that since initial plant startup, if a loss-of-ooolant-accident had occurred while grid voltage was low, sufficient voltage may not have been available for proper safety system operation. A review of previous bus voltage data determined that offsite voltage had gone below minimum grid voltage for several periods in the past. However, because the periods identified were relatively short and from the licensee's limited review did not
. appear to occur frequently, the team concluded that this event was not safety sign'iicant.
The team reviewed the licensee's correchve actions to address this issue during a review l
of NRC Case-Specific Checklist item IV.4, " Resolve Degraded Voltage and Electrical
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Distribution Concems." The team concluded that the licensee's planned electqcal distribution system changes and efforts to address degraded voltage concems were good. The results of that review is discussed in Section E1.2 of this report.
Technical Specification 3.8.1, "AC [Altemating Current) Sources - Operating," and Technical Specification 3.8.2, "AC Sources - Shutdown," requires that in the event that AC sources are not available, immediately restore the offsite circuit to operable status.
The failure to immediately restore inoperable offsite circuits to an operable status during degraded voltage conditions was an example where the requirements of TS 3.8.1 and TS 3.8.2 were not met and was a violation. However, this Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/99003-09), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/97008-00 and LER 50-461/97010-00/01.
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E8.12 (Closed) LER 50-461/97028-09: Improperly Qualified 480-Volt Bisaker Components.
On November 26,1997, during a review of industry bulletins and 10 CFR Part 21 notifications to ensure that Asea-Brown-Boveri (ABB) vendor information had been properly addressed, engineers identified that the power shield trip unit used on 33 inservice ABB 480-volt K-line safety-related circuit breakers were not qualified to sustain the radiation levels previously described in the supplied qualification reports and expected to be subjected to during a design basis accident.
To address this event, the licensee planned to either replace or repair the affected power t
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shield trip units for the affected breakers prior to plant restart. In addition, the licensee j'
committed to obtain and review a list of 10 CFR Part 21 notifications for circuit breakers l
and relays from ABB to determine if Illinois Power was notified of all applicable 10 CFR Part 21 notifications.
Subsequently, the licensee performed an environmental qualification impact assessment which concluded that based on the original ABB qualification report and radiation tests performed on similar components, the solid state trip devices at CPS were qualified at their installed locations. On February 6,1998, the licensee also completed an evaluation of 10 CFR Part 21 ioports of circuit breakers and relays from ABB. The team reviewed this information and had no additional concems j
E8.13 (Closed) LER 50-461/97031-00. Inadequate Testing of Safety-Related Logic Circuits.
A team of licensee engineers reviewing the adequacy of logic circuit testing in response
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to Generic Letter 96-01," Testing of Safety-Related Logic Circuits," identified that overiap testing did not adequately cover portions of the logic circuitry as required by Technical Specification 3.3.6.4.7 for the suppression pool makeup system instrumentation and Technical Specification 3.3.6.1.6 for the primary containment and drywall isolation l
l instrumentation. In addition, overlap testing did not adequately cover a portion of the
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logic circuitry for the thermal overload bypass circuit for the suppression pool dump valves to verify that surveillance requirements associated with Technical Specification 3.6.2.4.4 were met.
During this inspection, the team reviewed logic o!agrams, electrical schematics, test procedures, Technical Specifications, and other documents relateri to logic circuits. This review varified parallel logic, interiock, and permissive testing required by Technical Specifications for RCIC automatic suction shift testing conducted through the performance of Procedure 9054.04, "RCIC Automatic Suction Shift Test," Revision 24, and reactor water cleanup logic system functional testing conducted through the performance of Procedure 9015.05, " Reactor Water Cleanup Logic Sy Am Functional Test," Revision 27. The team reviewed the testing of a given logic circuit by comparing individual circuit contacts to specific steps in corresponding surveillance procedures.
The team concluded that the logic circuit functions were tested in an adequate manner.
No deficiencies were identified.
The team also reviewed the licensee's action in response to Generic Letter 96-01 and determined that the Generic Letter 96-01 review packages identified the initiating and actuating devices followed by a description of each actuation contact. Procedure test
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sechons and drawings were identified for each logic contact. About 148 condition reports were issued to document testing discrepancies. The majority of the discrepancies involved procedure problems, such as incorrect battery connections and incorrect data points, and missed testing requirements. The licensee relied on the automatic self-test system to verify the majority of the logic circuit paths. However, the self-test system did not test through the final actuation load driver, but placed reliance on I
other tests to provide sufficient test overlap. The licensee did not identify any safety-related logic circuits that would not perform their safety function and was revising test procedures to ensure equipment actuation logic paths overlapped the self-test system.
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These actions were scheduled to be completed prior to plant restart. The team concluded that the licensee's Generic Letter 96-01 program guidelines were appropriate for reviewing the issues identified in the generic letter.
Criterion XI, " Test Control," of Appendix B to 10 CFR 50 requires that a test program be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. The failure to prescribe adequate testing for suppression pool makeup system instrumentation, primary containment and drywall isolation instrumentatiori, ;nd a portion of the logic circuitry for the thermal overload bypass circuit for the suppression pool dump valves, was an example where the requirements of 10 CFR 50, Appendix B, Criterion XI, were not met and was a violation. However, this Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/99003-10), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/97031-00.
E8.14 (Closed) LER 50-461/98003-00/01: Loss of Division ll Nuclear Systems Protection System (NSPS) inverter Results in isolation of Shutdown Cooling.
This event was discussed in NRC Inspection Report 50-461/98004. No new issues were revealed by the LER. As part of the licensee's immediate corrective actions, shutdown cooling was promptly restored. In addition, the licensee upgraded the associated NSPS power supplies. The team reviewed the licensee's corrective actions and had no additional concems.
E8.15 (Closed) LER 50-461/98015-00. Engineered Safety Feature Actuation Caused by Shoited Diode in the Nuclear Systems Protection System.
On April 15,1998, maintenance personnel were in the process of replacing the Division 16 NSPS bay "C" 24-volt direct current (DC) power supply when the redundrant bay "B" 24-volt DC power supply tripped on overvoltage. This resulted in the loss of the Division ll NSPS bus and the actuation of a number of engineered safety features. The licensee conducted a root cause investigation and determined that the event was due to a shorted blocking diode in the wiring between the NSPS bus and the bay *C" 24-volt DC power supply.
As part of the licensee's immediate corrective actions, the defective blocking diodes were replaced, the NSPS bus was retumed to service, and all affected emergency
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reserve auxiliary transformer equipment and components were restored. The blocking diodes in the Division I, Ill, and IV NSPS power supplies were checked with no abnormalities identified. In addition, the lessons leamed from this event were incorporated into maintenance work requests for replacing NSPS power supplies. The team reviewed the licensee's corrective actions and had no additional concems.
E8.16 (Closed) LER 50-461/98017-00: Misinterpretation of Technical Specification Regarding Measurement of Battery Specific Gravities.
During a review of Procedure 9382.02, "125 VDC [ Volt Direct Current] ICV [ individual Cell Voltage) and Battery Charger Checks," licensee personnel identified that the specific gravity measurement of safety-related battery cells was not property temperature-corrected. The specific gravity of each cell was corrected based on the average electrolyte temperature of every sixth battery cell, instead of the individual cell electrolyte
. temperature as required by footnote (b) of Technical Specification Table 3.8.6-1, " Battery Cell Parameter Requirements."
The licensee conducted a root cause investigation and determined that the event was due to a misinterpretation of the requirements of Technical Specification Surveillance Requirement 3.8.6.2. However, a review of historical cell temperatures indicated that temperature variations between cells had not adversely impacted corrected speafic gravity calculations.
To address this event, the licensee revised Procedure 9382.02 to ensure that the requirements of Technical Specification 3.8.6.2 were met. The team reviewed the licensee's corrective actions and had no additional concems.
Technical Specification 3.8.0.2, " Battery Cell Parameters," required that battery cell specific gravity be corrected based on the individual cell electrolyte temperature. The failure to property correct battery cell specific gravity was an example where the requirements of Technical Specification 3.8.6.2 were not met and was a violation.
However, this Severity Level IV violation is being treated a3 a Non-Cited Violation (NCV 50-461/99003-11), consistent with Appendix C of the NRC Enforcement Policy.
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This violatiort is in the licensee's corrective action program as LER 50-461/98017-00.
E8.17 (Closed) LER 50-461/98025-00: Repeated Failures of Switchgear Heat Removal Condenser Gasket.
On July 27,1997, a transmission grid disturbance resulted in the actuation of the Division lll shutdown service water (SX) system. When the SX system pump started, a i
condenser gasket failed on the Division lli essential switchgear heat removal (VX)
system condensing unit,1VXO6CC. The VX system provided cooling to the Division lli safety-related switchgear and battery rooms in the event of a loss of the nonsafety-related cooling coil cabinet.
A root cause investigation detarmined that the gasket most likely failed due to a pressure i
transient. In addition, the investigation noted two previous instances of condenser gasket failures during pressure transients and one instance of a pressure transient which caused a relief valve to lift. The licensee concluded that the event was due to a lack of l
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ngorous design consideration of the effects of pressure transients on system components. Simpitfied evaluations of the SX system had been performed to address water hammer; however, these evaluations focused on the overall integrity of the system
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and did not address specific components, such as the system condensing unit. The Division I and ll SX systems were also identified to be potentially susceptible to similar transients. However, subsequent evaluations of these systems concluded that significant pressure transients were not a concem.
I An assessment of the safety consequences of this event was performed and concluded that the loss of flow due to the gasket failure and the effect of leakage spray onto other equipment did not have an impact on overall system performance. To address this event, a blowout resistant gasket was installed in the VX system condensing unit. In addition, the licensee planned a modification to add vacuum breakers to the Division til SX system to mitigate the pressure transient. During this in" pecten, the team reviewed
' the licensee's corrective actons, including maintenance work request D78940 which installed the blowout resistant gasket, and the planned vacuum breaker modification. No deficiencies were identified.
Criterion lil, " Design Control," of Appendix B to 10 CFR 50 requires that measures shall i
be established to assure that applicable regulatory requirements and the design basis I
are correctly translated into specifications, drawings, procedures, and instructions. The
. failure to incorporate the effects of pressure transients into the design of the Division lll SX system was an example where this requirement was not met and was a violation.
However, this failure constitutes a violation of minor significance and is not subject to formal enforcement action.
j E8.18 (Closed) LER 50-461/98030-00: Insufficient Suppression Pool Makeup Volume to Meet Design Basis Suppression Pool Level Requirements Following a Loss-of-Coolant-Accident.
On August 28,1998, during a review of calculation 01SM1, " Calc.ulation of Minimum Water Levels Required in the 828' [ foot) 34nch Containment Pools for Various Combinations of Gate installations on the Pool," engineenng personnel discovered that.
the value used for the makeup volume to fill the drywell to the top of the suppression pool weir wall was not consistent with the value in General Electric specification 22A2576,
" Customer /AE Supplied Data-Phase 1." in particular, the value in specification 22A2576 indicated that there was insufficient makeup volume to support the design basis makeup requirement of the suppression pool following a loss of-coolant-accident.
Subsequently, the heensee determined that sufficient makeup volurne existed in the upper pool to fill the drywell to the top of the suppression pool weir wall. The team reviewed these calculatons as well as other supporting documentation. No deficiencies were identified.
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i E8.19 (Closed) LER 50-461/98034-00: Inadequate Design Change Renders Suppression Pool Cooling Mode of Residual Heat Removal Inoperable.
On December 22,1997, operations personnel discovered that motor-operated valve 1E12-F024B (RHR discharge to the suppression pool) would not operate when the control room handswitch was manipulated to open the valve.
The licensee conducted a root cause investigation and determined that a design change installed on July 17,1997, to address hot short concems inadvertently introduced an interlock problem which p6evented the valve from opening. The licensee concluded that the event was due to inattention-to-detail by the preparer and reviewers of the subject design change. However, since the other train of RHR was not affected, and local operation of 1E12-F024B was possible to establish shutdown cooling in train "B", the event had minimal safety significance.
To address this event, the licensee installed modification RH-048 to address the hot short concem without affecting the ability to place RHR train "A" in shutdown cooling.
During this inspection, the team reviewed modification RH-048 and verified that the modification was installed and tested. No deficiencies were identified.
IV, Plant SuDDort F2 Status of Fire Protection Facilities and Equipment F2.1 Review of NRC Case-Soecific Checklist item IV.5 a.
Insoection Scooe (92904)
The team reviewed Case-Specific Checklist item IV.5, " Resolve Fire Protection Safe Shutdown Concems." To address this checklist item, the team assessed the licensee's safe shutdown capabilities, assessed the resolution of hot short concems, and assessed
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the resolution of Thermo-Lag concems.
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Qhservations and Findinos b.1 Backaround The NRC Spe.ala! Evaluation Team (SET) report included a review of the fire protection program to verify that the station had properly implemented and maintained the fire protection program in accordance with the operating license. A number of issues related to safe shutdown capability, resolution of " hot short" problems, and corrective actions to address Thermo-Lag concems were identified.
In addition, on December 13,1998, the NRC issued inspection Report 50-461/98026 which documented the actions taken by CPS to resolve fire protection issues identified in the SET report and NRC Case-Specific Checklist item IV.S. The report concluded that although significant progress had been made to address the issues identified above, additional work remained to be completed before the item was rear,1y for closure by the NRC.
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During this inspection, the team reviewed the licensee's actions to address the fire protection program concerns discussed above and as delineated in NRC Case-Specific Checklist Item IV.S.
b.2 Assessment of Safe Shutdown Caoability
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b.2.1 Safe Shutdown Procedure Review As discussed in NRC Inspection Report 50-461/98026, the NRC concluded that the revised Appendix R re-validation project adequately demonstrated that tne safe shutdown analysis met the plant licensing basis. However, at the end of the inspection, a number of safe shutdown actions, such as the completion of safe shutdown procedure reviews, remained to be completed.
During this inspection, the team reviewed Procedure 4003.01, * Remote Shutdown,"
Revision 13, which incorporated actions identified during the review of the safe shutdown analysis. These actions included steps to prevent the spurious actuation of safety relief valves (SRVs). The team also reviewed calculation IP-F-0121, Revision 0, "RETRAN Analysis of Loss-of-Offsite-Power Event Due to Control Room Fire," dated April 14, 1998. The licensee identified that a spurious actuation of an SRV would be the worst case single spurious actuation during a postulated control room fire requiring control room evacuation to the remote shutdown panel. The time to reach top of active fuel without any reactor makeup water was about 13 minutes. The team walked down the remote shutdown procedure and verified that the remote shutdown panel could be
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staffed and procedural actions completed to restore makeup water within this time.
During the walkdown of the remote shutdown procedure, the team veiified that licensee personnel, independent of the fire brigade, would be available to perform the actions specified in the procedure. The team also verified that the licensee had dedicated, properly staged tools available to implement the procedure.
The team reviewed the licensee's ema.gency lighting designated for safe shutdown. For the additional actions of ensuring that the Division 11 SRVs were precluded from spuriously opening, the licensee credited the use of DC battery-powered lighting installed in the plant and AC lighting powered from the protected EDG. These lighting systems were confirmed by the licensee to be unaffected by a fire in the main control room. In addition, the licensee planned to provide eight 8-hour portable battery lights to assist licensee personnel in performing safe shutdown activities, if necessary. During the walkdown, the team verified that the installed lighting was adequate for access and egress, and to perform the required actions.
The team reviewed the training department lesson plans for the post-fire safe shutdown procedure and concluded that the plans were adequate. The team also reviewed training records and training schedules and verified that all training on the revised procedure was scheduled to be completed prior to plant restart.
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b.2.2 Qualification of Fire-Rated Safe Shutdown CaMas As discussed in NRC inspection Report 50-461/98026, the inspectors reviewed Whittaker cable fire testing documentation and identified that the fire exposure tests did not test the cable supports. In addition, there was no hose stream test, and the fire heatup rate was much slower than that discussed in the test standards. In response, the licensee began acquisition of additional test information. At the end of the inspecten, the inspectors concluded that pending review of additional information, the cable test documentation was not adequate to demonstrate that the installed fire-rated cables were equivalent to protecting the cables with a rated fire barrier.
During this inspection, the team identified that the licensee had determined that the
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cables were not required to be protected with a rated fire barrier to meet their fire protecton license condition or NRC regulations. The team verified that the cables were no longer listed in the licensee's analysis as required for post-fire safe shutdown.
b.2.3 Automatic Sorinkler Protection For Risk Sensitive Fire Areas As discussed in NRC Inspection Report 50-461/98026, the inspectors raised concems associated with the design and overall effectiveness of the sprinkler systems installed in the cable spreading rooms (fire zones CB-2 and CB-4) and the auxiliary electric equipment room (fire zone CB-3a). The team identified that a significant number of sprinkler head spray pattems would be obstructed by plant equipment. The Individual Plant Examination for Extemal Events assumed that automatic suppression would control and/or suppress a fire in these fire areas and reduce the Core Damage Frequency for the subject fire zones by 266 percent. The team questioned the validity of this factor and the adequacy of these suppression systems to control and localize the fire to the area of origin within the affected fire zone. At the end of the inspecton, the effectiveness of these systems to control a floor-based exposure fire or a fire in overhead
. cable trays was indeterminate.
During this inspection, the team reviewed an engineering evaluation dated February 12, 1999, in response to condition report 1-97-06-215-1, which identified this issue, as well as Section 9.5.2.1 of Clinton Safety Evaluation Report, Supplement 6, dated July 1986, as it related to the area sprinkler protection provided for fire zones CB-3a, CB-2 and CB-4. In the subject Safety Evaluation Report, the NRC concluded the following:
"In the event of a fire in one of these areas [CB-3a, CB-2, and CB-4), the staff expects the sprinklers to operate and control the fire until fire brigade action is initiated. In the staff's opinion, the sprirklers will provide adequate protection for the fire barriers until the fire is extinguished, it is the staff's judgement that with the detection and suppression provided, each of the subject fire areas is sufficiently bounded to withstand the hazards associated with the area and, as necessary, to protect the area from a fire outside the area. On these bases, the staff concludes that the 8-inch thick concrete block walls, with the fire protection provided, are adequate fire barriers for the fire areas listed in Safe i
Shutdown Analysis, Amendment 1, and are acceptable."
The team reviewed the licensing submittals used to make the above determination.
Specifically, the team reviewed the following documentation:
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Letter L30-86(03-04)-L, " Fire Protection Evaluation Report and Safe Shutdown
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Analysis." dated March 4,1986.
Letter L30-86(03-07)-L, * Resolution of the Fire Protection Site Audit Concems,"
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dated March 7,1986.
Let'er L30-86(05-29)-L, * Safe Shutdown Analysis," dated May 29,1986.
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Letter L30-86(06)-L, " Subject NFPA [ National Fire Protection Association) Code
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Conformance Deviations," dated June 19,1986.
Based on the review of these submittals, the team determ'ned that the licensee presented the code compliance review of the subject sprinkler systems to the NRC in the June 19,1986 letter, in this letter, the licensee identified that the sprinkler heads at the ceiling of these rooms were obstructed by plant equipment (i.e., cable trays and heating, ventilation, and air conditioning ducting).
The team conducted a walkdown of the sprinkler system in each of the subject fire zones and determined that these systems were obstructed and did not meet NFPA 13 requirements. Therefore, the design of these systems was limited with respect to the ability to control a floot-based or cable tray fire. However, based on the observations made during the walkdown, the team determined that the ceiling level sprinklers were necessary in order to provide reasonable assurance that a severe fire in any of tnwe rooms would not breech the fire barrier walls since the fire-resistive rating of these walls may not be sufficient to resist the energy generated by a severe fire within these areas.
By assuming that a severe fire occurs in any of these rooms, it was reasonable to conclude that the sprinklers would actuate to cool the hot gas layer in the upper zone (ceiling region) of the room. This would reduce the convective heat transfer of the fire plume and ceiling jet thereby reducing the severity of the fire exposure to the fire barrier j
walls and prevent the fire from spreading to adjacent plant areas. Following this logic, the team concluded that the sprinkler systems met the intent of the conclusions made by the staff in the Safety I valuation Report.
The team concluded that the remote shutdown procedure adequately implemented the revised safe shutdown analysis, that it could be adequately implemented, and the necessary operator training would be completed prior to plant restart, b.3 Resolution of Hot Short Concems b.3.1 Review of NRC Information Notice 92-18 i
As discussed in NRC Inspection Report 50-461/98026, the NRC verified that corrective actions were in progress to complete valve modifications to prevent motor-operated valves from spuriously actuating during a fire. This actuation could occur as the fire could cause a valve to operate with torque and limit switches bypassed as described in NRC Information Notice 92-18, " Potential for Loss of Remote Shutdown Capability
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During a Commt Room Fire." At the end of the inspection, the licensee had not completed all required motor-operated valve modifications.
During this inspection, the team verified that all required modifications were completed.
In particular, the team reviewed modifications associated with motor-operated valves RH-048, completed December 16,1998; RI-049, completed January 7,1999; RT-039,
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completed December 22,1998; FW-040, completed February 10,1999; IA-021, completed January 7,1999; and MS-044, completed January 21,1999.
The team concluded that the licensse had completed all required modifications to prevent fire induced valve damage to critical se's shutdown valves as required by fire protection requirements and as described in NRC Information Notice 92-18.
b.3.2 Review of Sourious Oceretion of Safety Relief Valves The team reviewed licensee actions to address an industry initiative conceming the potential actuation of all 16 SRVs due to a fire.
The potential existed for a single fire to cause two spurious reactor pressure vessel high pressure signals due to hot shorts which would result in fire induce 1 spurious operation I
of all 16 SRVs. The team identified a number of plant areas where the potential for spurious operation of SRVs existed including the control room (both divisions), fire zones C-2, A-2k, A-2n, and CB-4 (Division I) and C-2, A-3f, CB-2 (Division ll).
i For each division of reactor pressure vessel indication, two cables were routed from the containment to the control room. Each cab le transmitted the output of one pressure transmitter. Each division had two detectors hence two cables. If the two wires in a cable should short, the logic circuit would interpret the output as a valid hi-hi pressure signal. For the logic circuitry to actuate to rapdly depressurize the reactor, two hi-hi pressure signals in the same division must be generated. Both cables for a division were routed in the same cable tray and the cable tray route was enclosed with solid metai bottoms. Therefore, a single fire affecting the cable tray could cause the conductors within each cable to short and result in the actuation of all 16 SRVs.
At Clinton Power Station, for all plant areas outside the main control room, the fire-induced transient caused by the opening of all 16 SRVs could be mitigated by the non-fire affected ECCS train. In the main control room, the two cables for each train entered their respective divisional logic panels through the under-floor raceway.
This raceway and the respective logic panel was provided with smoke detectors. These detectors only alarmed in the back panel area. Each panel was also provided with a manual halon suppression system.
When a fire alarm is received in the panel for the affected train, the licentee planned to prevent spurious SRV actuation by locking out each SRV to prevent actuation. In addition, the control room operators were trained to react to an alarming smoke detector in a panel containing the pressure detection circuitry and take immediate positive control of the potentially affected SRV. If control room evacuation was required, operators were trained to de energize the SRVs in the Division I and Division li switchgear rooms.
The team identified that the licensee had developed a modification to the smoke deter e j
alarm circuitry to install a strobe light on top of the affected panel to aid operators in rapid determination as to which panel was affected and aid in the operator's decision to take the necessary steps to mitigate the condition. The team verified that this modification was planned and would be completed prior to plant restart. For fires outside of the i
control room, the licensee revised Procedure 1983.04, " Fire Fighting," Revision 8, to take
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action to prevent potential SRV actuation from occurring in a fire area containing one of the cable trains.
The team concluded that licensee actions were adequate to prevent a postulated fire from inducing a major plant transient by opening all 16 SRVs.
b.4 Besolution of Thermo-Laa Concems in response to NRC Bulletin 92-01, " Failure of Thermo-Lag 330 Fire Barrier System," the licensee declared all installed Thermo-Lag electrical raceway fire barrier systems inoperable in nine fire zones and established compensatory measures such as fire watches. As part of their corrective actions, the licensee planned to install modifications to address the Thermo-Lag concems. The following options were selected to resolve the Thermo-Lag fire barrier technical issues:
l Fire Zone C2 (containment)
Replace Thermo-Lag with fully qualified firebreak / radiant heat shield material.
Fire Zones CB-4, CB-Sa, CB-1g Reroute circuits / cables out of the fire zone / area of concem.
Fire Zones CB-6, A-1a Replace Thermo-Lag with a conventional fire barrier material.
Fire Zone D-8 Credit offsite power for non-altemate shutdown area.
Fire Zone CB-1e Upgrade the 1-hour Thermo-Lag raceway fire barrier system to fully meet the required 1-hour fire-resistive rating.
Fire Zone CB-1f Upgrade the Thermo-Lag raceway fire barrier system to fully meet the required 1-hour fire-resistive rating, add an area sprinkler system, and use fire rated cable.
As discussed in NRC Inspection Report 50-461/98026, the inspectors completed their review of the replacement fire break / radiant energy heat shield material inside i
containment; the re-routing of required post-fire safe shutdown circuits and cables out of fire zones CB-4, CB-5a, and CB-1g as part of the post-fire safe shutdown capability
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review; and the replacement of Thermo-Lag with a conventional fire barrier material in fire zones CB-6 and A-1a. However, other concems, such as the upgrading of cable vault fire barrier assemblies, remained opened pending the review of additional corrective actions. In particular, from a limited review of the Thermo-Lag upgrades in fire zone CB-1f, the inspectors could not deterrr.ine if the cable vault fire protection assemblies could be upgraded to a 1-hour fire barrier and be bounded by industry fire barrier test reports.
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. During this inspection, the team reviewed the remaining Thermo-Lag modifications associated with fire zones CB-1e and CB-1f.
Thermo-Lao Fire Barrier Uoarades - Fire Zone CB-1e in fire zone CB-1e, the team confirmed that the licensee had completed all required modifications to upgrade the Thermo-Lag electrical raceway fire barrier system to meet the 1-hour fire-resistive rating as specified by Generic Letter 86-10, Supplement 1, * Fire Endurance Test Acceptance Criteria for Fire Barrier Systems Used to Separate Redundant Safe Shutdown Trains Within the Same Fire Area," dated March 25,1994.
The modification to upgrade the existing 1-hour Thermo-Lag cable tray fire barrier system consisted of a 3-inch extemal stress skin and Thermo-Lag trowel grade overlay applied over all vertical and horizontaljoints. In general, this design upgrade was demonstrated by Nuclear Energy Institute testing to be an effective method to improve the fire-resistive rating of a baseline %-inch thick Thermo-Lag panel cable tray fire barrier from 21 minutes of fire resistance to 60 minutes of fire resistance,
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in addition, the licensee extended the sprinkler coverage in this fire zone and resolved some sprinkler obstruction concems. At the end of this inspection, the installation of the sprinkler modifications was in progress and was scheduled to be completed prior to plant restart. Based on the areas reviewed, the team did not identify any deviations or other concems associated with the implementation of the Thermo-Lag fire barrier system upgrade program in fire zone CB-1e.
Thermo-Laa Fire Barrier Uoarades - Fire Zone CB-1f As discussed in NRC Inspection Report 50-461/98026, modification FP-100 installed a
'new sprinkler system and upgraded the existing Thermo-Lag fire barrier systems in fire zone CB-1f. However, at the end of the inspection, this modification had not been compbted. in addition, the following technical concems were identified:
The actual construction attributes used to assemble the existing fire barrier
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system were unknown.
The evaluation referenced Nuclear Energy institute and Tennessee Valley
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Authority test results which were not applicable to these fire barrier systems.
As a result, the Thermo-Lag upgrade program remained open pending NRC review of additional licensee corrective actions to resolve the identified issues and complete the required modification.
During this inspection the team determined that the licensee verified the original design parameters by performing the following:
Re-evaluation of original design reviews, including quality assurance records and
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walkdown examinations.
Destructive examination of an existing Thermo-Lag fire barrier system applied to
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a tee-tray section located in fire zone CB-1e.
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Intemal boroscope examination and extemal mapping of the two large
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Thermo-Lag fire barrier cable tray riser enclosures located in fire zone CB-1f.
As a result of this original design re-verification, the licensee determined that: 1) the stress skin was not removed during the original installation of the barrier system; 2) the panel "v-ribs" were property oriented; 3) butt joint interfaces were pre-buttered with Thermo-Lag trowel grade material; 4) metal cable tray covers on the riser were installed per the design specification; 5) trays were pre-banded; and 6) butt joint locations were identified.
To address the Thermo-Lag fire barrier cable tray riser enclosure issues identifed by the inspectors, the licensee confirmed that there were 4-way Thermo-Lag panel butt joints and that they occurred only over metal cable tray covers. This arrangement provided a continuous backside structural support for the Thermo-Lag fire barrier panels. In order to meet the 1-hour fire-resistive requireant, these cable tray riser fire barrier enclosures were upgraded under modification FP-100. The team determined that these upgrades, as supported by the results of calculation IP-M-0340, " Fire Endurance Evaluation of Thermo-Lag Fire Barriers in Fire Zone CB-1f," Revision 1, Volume B, provided reasonable assurance that the cable tray riser fire barriers in fire zone CB-1f would meet the 1-hour fire-resistive requirement. The team conducted a re-verification walkdown of fire zone CB-if and re-assessed the subject Thermo-Lag raceway cable tray riser fire barrier enclosures installed along column line 129/AC and 129/S. The team determined that the upgrades identified above had been completed.
The team also conducted a walkdown of the wet pipe sprinkler system being installed on elevation 762'-0" of the Control Building and conducted a basic review of the sprinkler layout drawings (Grinnell Fire Protection Systems Drawings FP1 and FP2, original issue June 16,1998, Revision 3, Level 762 of Control Building); Engineering Change Notice 30682, dated October 23,1998; the licensee's technical review of sprinkler design, dated October 11,1998; and the associated hydraulic calculations for the system (Calculations IP-M-0487, " Control Building 762'-0" Elevation Wet Pipe Sprinkler System Hydraulic Calculation," Revision 0, dated October 9,1998, and IP-M-0747, " Control Building Elevation 762'-0" Fire Suppression Supply Calculation," Revision 0, dated October 6, 1998). Based on the results of this review, the team concluded that the new sprinkler system was being installed in accordance with NFPA 13. " Installation of Sprinkler Systems," and that the licensee addressed overhead sprinkler spray pattem obstructiona caused by plant equipment. Based on the review of the sprinkler design, walkdown of the system, and the near completion of the installation, the team concluded that the design will provide the, level of fire safety required by the applicable fire protection requirements.
The team concluded that the upgraded Thermo-Lag fire barrier systems installed in fire zones CB-1e and CB-if provided the 1-hour fire-resistive capabilities required by the fire protection requirements and that the licensee's program to address the fire-resistive technical concems associated with Thermo-Lag will be adequately addressed prior to plant restart.
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Conclusions The team concluded that the remote shutdown procedure adequately incorporated the
. assumptions in the revised safe shutdown analysis and that the procedure could be adequately implemented. The licensee also committed to complete necessary operator training prior to plant restart. In addition, the team concluded that all modifications to prevent fire induced valve damage to critical safe shutdown valves, as required by fire protection regulations, were completed. Finally, the team concluded that the program to adoress the fire-resistive technical concems associated with Thermo-Lag was adequate.
The licensee committed to complete all remaining Thermo-Lag activities prior to p; ant -
restart.
V. Manaaement Meetings X1 Exit Meeting Summasy The team presented the inspection results to members of licensee management at the conclusion of the inspection on March 18,1999. The licensee acknowledged the findings presented. The team asked the licensee whether any materials examined during the inspection should be considered proprietary. Although some proprietary information was identified, none of the information reviewed resulted in issues which were discussed with the licensee at the exit meeting or are discussed in this report.
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PARTIAL LIST OF PERSONS CONTACTED J. Barron, Director - Plant Engineering R. Bhat, Supervisor - Fire Protection Engineering W. Carsky, Director - Design Engineering L. Demick, Chairman - Senior Engineering Review Group R. Ebright, Project Manager - System Design and Functional Verification A. Haumann, Supervisor - Design Engineering B. Haynes, Project Manager - Setpoint Program G. Hunger, Manager - Clinton Power Station J. McElwain - Chief Nuclear Officer M. Norris, Supervisor - Engineering Assurance E. Schweitzer, Supervisor - NSSS Systems J. Sipek, Director - Licensing D. Warful, Manager - NSED INSPECTION PROCEDURES USED IP 37001:
10 CFR 50.59 Safety Evaluation Program IP 37550:
Engineering IP 37702:
Design Changes and Modifications Program IP 93809:
Safety Svstem Engineering Inspection IP 92700:
Onsite LER Review IP 92903:
Followup - Engineering IP 92904:
Followup - Plant Support ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-461/99003-01 NCV Failure to Revise TS Surveillance Acceptance Criteria 50-461/99003-02 NCV Bypass Leakage Flowpaths Not included in TS Surveillance 50-461/99003-03 IFl RCIC System Minimum Flow 50-461/99003-04 NCV Failure to Revise Procedures to Reflect Maximum Valve Leakage 50-461/99003-05 IFl Interlock Testing Following Maintenance or Modifications 50-461/99003-06 NCV Failure to Prescribe Post-Modification Testing for VC Chillers 50-461/99003-07 URI 10 CFR 50.59 Evaluation Regarding Feedwater Line Break 50-461/99003-08 NCV Failure to Seismically Qualify Circuit Breakers 50-461/99003-09 NCV Operation at Less Than Minimum Required Grid Voltage 50-461/99003-10 NCV Failure to Prescribe Adequate Circuit Logic Testing 50-461/99003-11 NCV Failure to Correct Battery Cell Specific Gravities for Temperature i
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Closed 50-461/99003-01 NCV Failure to Revise TS Surveillance Acceptance Criteria 50-461/99003-02 NCV Bypass Leakage Flowpaths Not included in TS Surveillance 50-461/99003-04 NCV Failure to Revise Procedures to Reflect Maximum Valve Leakage 50-461/99003-06 NCV Failure to Prescribe Post-Modification Testing for VC Chillers 50-461/99003-08 NCV Failure to Seismically Qualify Circuit Breakers 50-461/99003-09 NCV Operation at Less Than Minimum Required Grid Voltage 50-461/99003-10 NCV Failure to Prescribe Adequate Circuit Logic Testing 50-461/99003-11 NCV Failure to Correct Battery Cell Specific Gravities for Temperature 50-461/97003-01 VIO Failure of Westinghouse DHP Circuit Breckers to Open 50-461/97003-02 VIO Unapproved Cleaning Compounds and Lubricants on Breakers 50-461/97011-16 IFl Seismic Qualification of Circuit Breaker Cabinets 50-461/97999-16 IFl GL 89-13 Preventive Maintenance items Not Reviewed 50-461/97999-17 IFl Design Problems With Auxiliary and Offsite Power Systems 50-461/98004-01 IFl Failure to Rely on Local Emergency Diesel Generator Indication 50-461/98004-02 NCV Inadequate Residual Heat Removal Fill and Vent Procedure 50-461/98004-03 NCV inadequate Crew Briefing 50-461/98004-04 NCV Failure to Evaluate Risk Prior to Maintenance 50-461/97007-00 LER Lack of Guidelines for Seismic Qualification of Breakers 50-461/97008-00 LER Emergency Diesel Generator Undervoltage Relays inoperable 50-461/97010-00/01 LER Incorrect Voltage in Procedure Verification 50-461/97018-00 LER Failure of Westinghouse DHP Circuit Breakers to Open 50-461/97028-00 LER improperly Qualified 480-Volt Breaker Components 50-461/97031-00 LER Inadequate Testing of Safety-Related Logic Circuits 50-461/98003-00/01 LER Loss of Division 11 NSPS Inverter 50-461/98015-00 LER ESF Actuation Caused by Shorted Diode in the NSPS System 50-461/98017-00 LER Misinterpretation of TSs Regarding Battery Specific Gravities 50-461/98025-00 LER Failures of Switchgear Heat Removal Condenser Gasket 50-461/98030-00 LER Insufficient Suppression Pool Makeup Volume to Meet Design
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50-461/98034-00 LER Suppressicn Pool Cooling Mode of RHR inoperable
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LIST OF ACRONYMS USED ABB Asea-Brown-Boveri AC Altemating Current ADS Automatic Depressurization System AIT Augmented Inspection Team AP Auxiliary Power CAL Confirmatory Action Letter CCW Component Cooling Water CFR Code of Federal Regulations CPS Clinton Power Station DC Direct Current DCR Detailed Caiculation Review DDR Detailed Design Review DFl Plan-for-Excellence DRP Division of Reactor Projects DRS Division of Reactor Safety ECCS Emergency Core Cooling System ECN Exempt Change Notice EDG Emergency Diesel Generator EPR Engineering Product Review EPRI Electric Power Research Institute
'F Degrees Fahrenheit i
I FC Fuel Pool Cooling GE General Electric gpm gallons per minute
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'HPCS High Pressure Core Spray ICV Individual Cell Voltage IFl Inspection Followup Item IP Inspection Procedure ISA Integrated Safety Assessment kV Kilovolt LER Licensee Event Report LOCA Loss-of-Coolant-Acciderc MEL Master Equipment List NCV Non-Cited Violation NFPA National Fire Protection Association NRR Nuclear Reactor Regulation NSED Nuclear Station Engineering Department NSPB Nuclear Systems Protection System NPSH Net Positive Suction Head
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PDR Public Document Room PMSO Plant Manager Standing Order i
RCIC Reactor Core isolation Cooling RHR Residual Heat Removal i
Rlli NRC Region lli scfh standard cubic feet per hour SDFV System Design Functional Validation SERG-Senior Engineering Review Group
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SET Special Evaluation Team SRV Safety Relief Valve SSC Structure, System, and Corr +0 rent SSTR System Surveillance Test Review SVC Static VAR Compensator SX Shutdown Service Water URI Unresolved item USAR Updated Safety Analysis Report Vac Volts Altemating Current VAR Volt-Ampere-Reactive VDC Volts Direct Current
.VIO Violation VX Switchgear Heat Removal i
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LIST OF DOCUMENTS REVIEWED The following is a list of licensee documents reviewed during the inspection. Inclusion on this list does not imply that NRC inspectors reviewed the documents in their entirety, but rather that portions or selected portions of the documents were evaluated as part of the overallinspection effort. NRC acceptance of the documents or any portion thereof is not implied.
Modificatons AP-027 SO Replace Division i Undervoltage Relays AP-028 S0 Replace Division ll Undervoltage Relays AP-029 S0 Replace Division 111 Undervoltage Relays AP-032 Allow Use of Operator Actions in Conjunction With Fixed Tap Transformers AP-033 S4 Division i Regulating Transformer - Control Building Motor Control Center "A" Transformer AP-037 S0 Reserve Auxiliary Transformer Static VAR Compensator AP-038 S0 Emergency Reserve Auxiliary Transformer Static VAR Compensator AP-040 S9 Emergency Reserve Auxiliary Transformer Load Tap Change - Connect Phase and Lightning Arrestor FW-040 Feedwater Motor-Operated Valve Modification to Address Hot Short Concem IA-021 Instrument Air Motor-Operated Valve Modification to Address Hot Short Concem M-082 Modify Valves 1E12-F042A/B/C And 1E21F005 To Prevent Pressure Locking M-0083 SO Emergency Core Cooling System Suction Strainer MS-044 Main Steam Motor-Operated Valve Modification to Address Hot Short Concem RH-048 Correct Deficiencies Caused by Field Alteradon RHF011 RI-049 SO Reposition Valve Limit and Torque Switches RRF024 SO Reactor Recirculation Single Loop Analysis and Design Basis RT-039 -
Reactor Water Cleanup Motor-Operated Valve Modification to Address Hot Short Concem SY-012 SO Switchyard Upgrade
- SX-047 SO Design Change to Replace Limitorque SMC-04 With SMB-000 ECN 9067 Revise Setpoint Log Sheet E51-02 to Change the Trip Setpoint and the Allowable Value ECN 27785 Altemate Magne-Blast Configuration ECN 28133 Isolate Residual Heat Removal Heat Exchangers from RCIC Supply ECN 28489 Change Stroke Time for 1E51F045 and 1E51F095 ECN 28988 Change Allowable Value for the RCIC Storage Tank Level Transmitters ECN 29249 injection Quills into Shutdown Service Water, Service Water, and Circulating Water Piping ECN 29457 Change of Setpoint for Differential Pressure Switch 1E51N581 and the Revision of Appropriate Design Documents ECN 29598 Drill 1/8-inch Pressure-Locking Relief Hole in Valve 1E51-F013 inboard Disk ECN 29890 RCIC Turbine insulation Reduction From 3 Inches to 2 inches ECN 29928 Trim Limit Switch Mounting Plate of RCIC Valve 1E51F025 ECN 29979 Remove Two Auto-Restart Relays From Chiller OVC13CA ECN 29980. Remove Two Auto-Restart Relays From Chiller OVC13CB ECN 30102 Reserve Auxiliary Transformer Tap Setting From 2 to 3 ECN 30119 Revise Tolerances For 1E51K601 and 1C61K001 ECN 30169 Emergency Reserve Auxiliary Transformer Tap Change From 3 to 2
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ECN 30170 Alternate Levering-in Device ECN 30171 Work With ECN 27783 on DHP-Type Breakers
' ECN 30225 Automatic Depressurization System Pressure Switch Setpoint Change ECN 30294 Add Fuse to isolate Annunciator Power Supply ECN 30441 Altemate Configuration for General Electric Magne-Blast Breakers ECN 30442 Voltage Reading for 138 kV Line -
ECN 30445 Revise Setpoint in High Voltage Shutdown Card 1DC08E
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ECN 30609 Altemate Low Voltage Alarm Card ECN 30660 Transformer Tap Change on 1DC06E
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ECN 30666 : Time Delay Change for Low Voltage Alarm Card ECN 30669 Transformer Tap Change on 1DC07E ECN 30682 Pipe Sprinkler System
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ECN 30699 Transformer Tap Change on 1DC07E l
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ECN 30713 Revise Line Size to Shutdown Service Water Pump Motor Division I ECN 30903 Residual Heat Removal / Shutdown Service Water Bypass Orifice ECN 30905 Division i Shutdown Service Water Flow Balance 10 CFR 50.59 Evaluations98-145 Replace Motor Operator on 1SX014B 98-144 RCIC and High Pressure Core Spray Tomado Missile issues 98-134-Condition Report 1-bJ-07-105-0 Residual Heat Removal Bypass Valve 98-123 Flooding Protection Requirements08-114 RCIC isolation Change (Licensee Event Report 98-013)98-092 Revise Main Control Room Pressure Description 98-074 Revise Orifice 1SX12MA Size 98-066 USAR Change to Substitute ADS for RCIC in the Accident Analysis for t.
Feedwater Break Outside Containment 98-017 Changes to 10 CFR 50.59 Procedure 98-006 Reserve Auxiliary Transformer Primary Tap Changes Requirements98-004 Update Updated Safety Analysis Report Regarding Leak Detection System 97-238 Revise Calculation DC-ME-09-CP 97-198 Temperature Correction for Batteries97-178 Relocate RCIC Stem Packing Leakoff 97-169 Emergency Reserve Auxiliary Transformer / Reserve Auxiliary Transformer Updated Safety Analysis Report Discussion 97-146 Uncoated Cart >on Steelin Containment 97-141 RCIC Component Downgrade from Class 1E to non-Class 1E 97-133 Division 11 Auxiliary Power Modification 97-102 Reserve Auxiliary Transformer Tap Change to Position 3 97-090 Change 1SX020B to Normally Open 97 087 Component Cooling Relief Valve Setpoint 97-044 Drill Hole in RCIC Valve 1E51-F095 97-042 RCIC Steam Admission Valve 1E51F013 97-037 USAR inconsistencies Regarding Postulated Pipe Breaks97-029 Operability Determination for Condition Report 1-96-10-360 97-008 Revise Overspeed Trip Setpoints for Diesel Generators96-101 Leak Detection Modification 96-047 Attemate Shutdown Cooling
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.96-044 Minimum Fuel Pool Temperature 90-0038 Low Shutdown Service Water Flow in Division I Heat Exchangers
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' Ooerability Determinations 1-99-02-027-00 Inadequate Short Circuit interruption Capacity of Fuses 1-98-11-157 0D Plant Configuration Discrepancy Not Reviewed and an inadequate Engineering Evaluation for Condition Report 1-98-03-163 1-98-09-292-0D Inability of Valves 1SX014A and 1SX014B to Meet the Sizing Guidance Provided in Limitorque Technical Update 98-01 1-98-08-219-0D High Percentage of Contactors Falling Minimum Voltage Pull-in Test 1-98-07-130-0D Flow Out of Shutdown Service Water Under a Loss of the Dam, Resulting in an Unaccounted Flow Not Going to the Ultimate Heat Sink 1-98-06-215-0D -
Use of Unqualified Zinc Coating in Containment 1 98-04-190-0D Breakers for Control Room Ventilation "B" Supply and Retum Fans Did Not Close Within Acceptable Values 1-98-04-066-0D Inadequate Calibration of Emergency Core Cooling System Motor Current Indication Loops 1-97-10-414-0D Use of improper Cable Resistance Values in Electrical Calculations 1-97-10-123-0D Division 11 Battery Charger Voltage Oscillations 1-97-09-359-0D High Bus Voltage During Paralleling of Emergency Diesel Generator 1-97-09-201-0D '
Division i Shutdown Service Water Flow Balance Low Flows to Safety-Related Components Fed By Shutdown Service Water 1-97-02-179-00 Breaker Coordination Problems Calculations Cl-CPS-144, Rev. 3 Setpoint Calculation for RCIC Tank Low Level Transmitter 1E51-NO35A Cl-CPS-145, Rev. 3 Setpoint Calculation for RCIC Tank Low Level Transmitter 1E51-NO35E.
Cl-CPS-146, Rev. 4 Setpoint Calculation for Instrument 1E51-N636A Cl-CPS-147, Rev. 5 Setpoint Calculation for instrument 1E51-N636E Cl-CPS-204, Rev. O Time Delay Relay K6 Setpoint Error Band for Emergency Diesel Generator Relay Setting Cl-CPS-688, Rev.1 Calculation for 0FC-VG004 Cl-CPS-689, Rev.1 Calculation for 0FC-VG104 j
IP-C-0036, Rev. O, Vol A Residual Heat Removal "B" High Pressure Setpoint Calculation j
IP-C-0037, Rev. O, Vol A Residual Heat Removal "A" High Pressure Setpoint Calculation IP-CL-006, Rev. O Seismic Qualification of Motor-Operated Valves 1E51-F013A and 1E51-F013D With SMB-0 Operator
IP-F-0121, Rev. 0 RETRAN Analysis: Loss of Offsite Power Due to Control Room Fire IP-M-0056, Rev. O RCIC High Steam Flow Setpoints IP-M-0258, Rev. 2 Generic Letter 89-10 Thrust Window for 1E51-F010 IP-M-0300, Rev. O Realistic Analysis for RCIC Direct Current Valve Availability During High Pressure Core Spray Out-of-Service and Station Blackout Conditions
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IP-M-0340, Rev.1, Vol B Fire Endurance Evaluation of Thermo-Lag Fire Barriers in Fire Zone CB-if IP-M-0384, Rev.1 Evaluation of Vortex in the RCIC Storage Tank i
IP-M-0423, Rev. O RCIC Turbine Heat Loss With 3" and 2" insulation i
IP-M-0487, Rev. O Control Building 762'-0" Elevation Wet Pipe Sprinkler System l
Hydraulic Calculation IP-M-0747, Rev. O Control Building Elevation 762'-0" Fire Suppression Supply I
Calculation I
IP-O-0331, Rev. 2 Seismic Qualification of Motor-Operated Valves 1E51-F010 and 1E51-F031 (SQ-CLO68)
q IP-S-0132, Rev.1 Acceptance Criteria for Allowable Sediment Depth in the CW l
Screenhouse
IP-Y-0001, Rev. O Calculate Amount of Boron and Boric Acid Required to Mix in the l
I RCIC Storage Tank to Support Emergency Operating Procedures 01HP14, Rev. O Minimum High Pressure Core Spray Pump Differential Pressure Requirement for the Surveillance Test to Assure that the High a
Pressure Core Spray Flow Rate is Equal or Greater Than 5010 Gallons Per Minute 01 HP09, Rev. 5 High Pressure Core Spray Rated Core Spray Flow Head and Pressure Requirements Based Upon PTP-HP-01 Data 01HP11, Rev. 2 Pump Differential Pressure and Flow Measurement Criteria for HPCS Pump 1E22-C001 Surveillance Test and Inservice Test 01LP08,Rev.O Low Pressure Core Spray Rated Core Spray Flow Head and
Pressure Requirements Based Upon PTP-LP-01 Data 01RH19, Rev. 3 Low Pressure Coolant injection Rated Reactor Pressure Vessel injection Flow Head and Pressure Requirement Based Upon PTP-RH-01 Data 01Rl01, Rev. 6 (C/D)
RCIC System Piping 01R112, Rev. O RCIC System Flow Element 1E51-N0001 Flow Coeffic!ent Determination and Evaluation of Flow Element Accuracy 01Rl13, Rev. O Net Positive Suction Head Calculation - RCIC Suction From Suppression Pool 01SM1, Rev. O Calculation of Minimum Water Level Required in the 828",3-inch Containment Pools for Various Combinations of Gate installations on the Pool 19-Al-14, Rev. 2 Fast Transfer of Emergency Reserve Auxiliary Transformer Buses j
1 A1 & 1B1 Between Reserve Auxiliary Transformer and Emergency Reserve Auxiliary Transformer 19-AJ-74, Rev. O, Vol. C Class 1E Distribution Panel Loading Calculation 19-AK-6, Rev. O. Vol. AF Calculation for Auxiliary Power System Analysis 19-AK-13, Rev. O, Vol. A Class 1E Auxiliary Power Load Follow, Short Circuit and Transient Analysis Feed From the Emergency Reserve Auxiliary Transformer 19-AN-19 Rev. 2 Calculations for Functional Requirements for 1" and 2"' Level Undervoltage Relays at 4kV 1 A1,1B1, and 1C1 19-AN-32, Rev. O Vol. B Emergency Reserve Auxiliary Transformer Load Tap Change Control Settings 19-AN-34, Rev. 0, Vol. A EPA Cards and Reactor Protection System inver'er 1C71S004A and 1C71S004B
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l 19-AQ-02, Rev. 3, Vol. AB Calculation for LOCA Block Start 19-D-28 Rev.12, Vol. D Review of Direct Current System 1 A 19-D-48, Rev. 0 Estimating Direct Current Motor-Operated Valve Motor Speed
Reduction Due to Elevated Temperature 4536-EAD-2, Rev.1 Ampacity of Cables From Emergency Reserve Auxiliary Transformer to Engineered Safety Feature Buses 060332,Rev.O RCIC Acceptance Criteria for Startup Test Procedures STP-17 and STP-33 RTER 95-014-ED, Rev. O Calculation of Offsite and Main Control Room Dose Due to a Leak From the RCIC Tank Vent in the Event of a Design Basis Loss of Coolant Accident Condition Reports CR 1-95-08-012 Failure of Various 480-Volt K-Line Breakers to Close CR 1-96-08-095 RCIC System Exceeded Availability Goals Due to Valve Seat Leakage CR 1-96-09-172 Failure to Perform Timely Corrections and/or Desired Changes to Resolve Control Room Ventilation Chiller Auto-Start issue CR 1-97-02-191 RCIC Operability During a Feedwater Line Break Outside Containment CR 1-97-02-287 Instrument Uncertainties in TS Surveillance Tests CR 1-97-03-037 Failure Trend item 97-11-27 on Molded Case Circuit Breakers CR 1-97-03-182 RCIC Pump Technical Specification Surveillance CR 1-97-05-014 Lack of Documentation of Consequences From Degraded Coatings in Containment Due to a Design Basis Accident CR 1-97-05-211 RCIC System Operating Procedures CR 1-97-06-330 Failed Components Not identified on Condition Reports Nor Evaluated as Maintenance Rule Failures CR 1-97-07-047 Apparent Violation on Use of Lubricants or Cleaning Compounds CR 1-97-08-223 -
Potential Generic Failure Mode of Westinghouse DHP-Type Breakers CR 1-97-09-214 Independent Safety Assessment 1997-0536: Inadequate Final Closure of
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Safety System Functional Assessments CR 1-97-10-052 '
Switch Roset for Reactor Pressure Vessel Pressure Permissive to Open RHR injection Valves is Above Technical Specification Limit CR 1-97-11-072 No Specific Testing Done to Ensure Delivery of 750 gpm at a RHR Pump Head of 229 psig CR 1-97-11-333 Independent Safety Assessment Observation RTG-01, RFI 0938:
Tracking the Resolution of SSFl/SSFA and EDSFl issues CR 1-97-12-015 Failure Trend item 97-11-03 on Pressure Gauge Failures CR 1-97-12-023 Repetitive Fuse Failures CR 1-97-12-029 Power Supply Calibration / Failure CR 1-97-12-033 Failure Trend item 97-11-18 on Solenoid Valve Failures CR 1-97-12-049 RPS Reactor Level CR 1-97-12-050 Electronic Cards CR 1-97-12-052 Remote and Shutdown Suppression Pool Level
- CR 1-97-12-109 Area Temperatures Below Minimum Temperatures Outlined in Environmental Design Criteria CR 1-98-01-320 Failure to Meet Updated Safety Analysis Report Requirements in the Calibration of Temperature Control Switches CR 1-08-02-265 Potential Violation for Failure to Follow Conduct of Operations Procedure
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CR 1-98-02-266 Potential Violation from NRC Special Inspection on Loss of Shutdown Cooling and Emergency Diesel Generator Overload Events CR 1-98-02-386 Ability of RHR Heat Exchanger Bypass Valve to Close on Containment Spray initiation CR 1-98-03-163 Fuse Replacement Program Does Ensure Correct Replacement of Blown Fuses CR 1-98-03-197 12-Volt Power Supply at 1H13-P662-B-A195 Failed CR 1-98-03-458 Repetitive Failures of Transformer Cards CR 1-98-03-459 Rod Control and Information System Should be Classified as a(1) Under the Maintenance Rule CR 1-98-03-467 Calculation 3010-0382-002 inconsistent with Emergency Procedure Guidelines T Licensing Basis CR 1-98-03-530 Problems s:, Safety Evaluation CR 1-98-03-549 Errors in Valve Data Sheets for 1E12-F008,1512-F009, and 1E12-F023 CR 1-98-04-034 Inadequate 125 Volt Battery Individual Cell Specific Gravity Correction CR 1-98-04-194 Motor-Operated Valve 1E12-F006A Failed to Open Fully CR 1-98-04-196 1E12-F006 RHR A Pump Shutdown Cooling Suction Valve Failed to Stroke Full Open CR 1-98-05-067 No Determination of Actual Flow Through the Residual Heat Removal Pump Minimum Flow Lines CR 1-98-05-067 Residual Heat Removal Valve Interlocks not Periodically Tested CR 1-98-05-121 Cable 1SX17D Green-Black Conductor not Spared Per Design CR 1-98-05-167 Manual Initiation Logic for Containment Spray not in Accordance with Design Specifcation CR 1-98-05-168 Use of Containment Spray Delay Timer not Bounded by Current Analysis or Proceduralized CR 1-98-05-190 Missing Labels on Shutdown Service Water System instrument Valves for Pressure Transmitters CR 1-98-05-191 Incorrect Master Equipment List Data CR 1-98-05-192 Shutdown Service Water Valves Locked in Field and Not identified as Such on the Piping and Instrument Diagram CR 1-98-05-193 M06 & M07 Drawing Discrepancies CR 1-98-05-201 Field Labels Do Not Match the Procedure or Drawing Designation CR 1-98-06-063 While Performing Work Under Maintenance Work Request D81958 Fuses Were Found of Incorrect Size CR 1-98-06-226 RCIC Gland Seal Compressor Shunt Trip CR 1-98-07-150 Fuse Rating Discrepancy CR 1-98-07-368 Inadequate Remote Shutdown Control Circuit Design CR-1-98-08-038 incorrect Fuse Installed in Panel 1H13P851 l
CR 1-98-08-062 Evaluation of NRC Information Notice 98-24 CR 1-98-08-157 incorrect Fuses Installed CR 1-98-08-206 Missed Design impact may Affect RHR-B Suppression Pool Cooling i
CR 1-98-08-238 Incorrect Fuse Found in Cubicle CR 1-98-08-281 Incorrect Size Fuse installed in Control Transformer in Motor Control Center CR 1-98-09-020 Incorrect Size Fuse on Control Transformer CR 198-09-245 Installation of Undersized Control Power Transformer in 0AP56E-2A CR 1-98-09-393 RCIC Steam Supply Line isolation j
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CR 1-98-10-077 Altemate Packing Arrangement is not supported by Plant Procedures and Updated Safety Analysis Report Requirements CR 1-98-10-211 Undersized Control Circuit Fuse in 0AP56E-2A CR 1-98-10-432 '
Design input Discrepancy for the Emergency Core Cooling System Suction Strainer CR 1-98-11-181 Fuse Type Discrepancies Found During Walkdown of Motor Control Center 181(1AP76E)
CR 1-98-12-017 Failure for Reactor Vessel Water Level Indication CR 1-98-12-030 Inadequate Evaluation of RCIC System Motor-Operated Valve Capability Under Loss of Altemating Current Power CR 1-99-01-205 incorrect Fuse Type, Breaker Not Tripping on Thermal Test CR 1-99-01-215 Incorrect Fuse Type, Breaker Did Not Pass High Limit Instantaneous Trip
CR 1-99-01-216 Post-Accident Sample System Cooler Plugged with Silt CR 1-99-01-239 incorrect Size Fuse Found in Control Circuit CR 1-99-01-258 Valve in Post-Accident Sample System Panel has a Cross Port Leak CR 1-99-01-263 Breaker Tripped on Low Tolerance Limit Test CR 1-99-01-318 Shutdown Service Water Flow Rate Below Design Conditions CR 1-99-01-320 Self-insulated Butt Splices Located in Harsh Zones CR 1-99-02-010 Analysis Results for 1SX01PA Upper Motor Bearing Oil Sample Identified a High Amount of Particulate CR 1-99-02-027 Interrupting Capacity of T1 Fuses insufficient interrupt Short Circuit Current for Emergency Diesel Generator Bus CR 1-99-02-091 incorrect Size Fuse Found in Motor Control Center Bucket Control Circuit CR 1-99-02-177 Failure to Resolve Actions Regarding NRC Information Notice 91-056 CR 1-99-02-182 Weak Justification of Assumption in Calculation 01Rl13 CR 1-99-02-125 USAR Change Omitted From USAR Change Log CR 1-99-02-193 RCIC Steam Supply Penetration 43 Not Listed As Class 2 CR 1-99-02-293 Incorrect Type Fuse Found in Control Circuit CR 1-99-02-307 Safety Evaluation 98-066 Was Not Revised After General Electric Notification That an Assumption was Wrong CR 199-02-319 Fuse Discrepancias identified During Division IV Walkdown CR 1-99-02-326 Condition Report Closed Without implementing Corrective Action CR 1-99-02-376 Non-Conservative Assumption in Calculation IP-M-0423 CR 1-99-02-406 Post Modification Megger Test of Transformer 0AP24ERT CR 1-99-03-063 Post Maintenance Test Process CR 1-99-03-198 Incorrect Electrical Arrangement of Component Cooling Water Motor-
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Operated Valve 1CC075B Licensee Event Reoorts i
50-461/97007-00 Lack of Guidelines for Seismic Qualification of Breakers 50-461/97008-00 Emergency Diesel Generator Undervoltage Relays inoperable 50-461/97010-00/01 incorrect Voltage in Procedure Verification 50-461/97018-00 Failure of Westinghouse DHP Circuit Breakers to Open 50-461/97028-00 Improperly Qualified 480-Volt Breaker Components 50-461/97031-00 Inadequate Testing of Safety-Related Logic Circuits 50-461/98003-00/01 Loss of Division ll NSPS Inverter 50-461/98006-00 Incorrect Calculation in Emergency Diesel Generator Control Circuitry
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50-461/98015-00 Engineered Safety Feature Actuation Caused by Shorted Diode in the Nuclear Systems Protection System 50-461/98017-00 Misinterpretation of Technical Specifications Regarding Battery Specific Gravities 50-461/98025-00 Failures of Switchgear Heat Removal Condenser Gasket 50-461/98030-00 insufficient Suppression Pool Makeup Volume to Meet Design
50-461/98034-00 Suppression Pool Cooling Mode of RHR inoperable
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Response to industry information Y-210150 Response to Rapid information Communication Service information Letter 037, Binding of Molded Head Tappet Assembly Used for Overspeed Trip on HPCI and RCIC Turbine Manufactured by Terry Corporation Y-211195 Response to Serv!os information Letter 319, Rev.1, Operating Experience with Right Angle Dnve Gear Assemblies on HPCS and RCIC Turbines Y-213304 Response to Service Information Letter 336, Rev.1, Surveillance Testing Recommendations for HPCI and RCIC Systems Y-211079 Response to Service information Letter 351. Rev.1, Procedures for Calibration of HPCI and RCIC Turbine Control System Y-213285 Response to Service information Letter 351, Rev. 2, Updated Turbine Control System Calibration Procedures for Terry HPCI and RCIC Turbines Y-209924 Response to Service Information Letter 475, Rev. 2, RCIC and HPCI High Steam Flow Analytical Limit Y-211719 Response to Service information Letter 485, RCIC Turbine Ramp initiation Logic Y-211808 Response to Service information Letter 507, RCIC Pump Seismic Pins Y-213360 Response to Service Information Letter 525, Improved RCIC Turbine Mechanical Overspeed Tappet Design Y-214940 Response to Service information Letter 531, High Pressure Coolant injection and RCIC Magnstrol Level Switches'
Y-105470 Response to Servios information Letter 580, HPCI and RCIC Turbine Drains Y-207384 Response to information Notice 86-14, Supplement 1, Overspeed Trips of AFW, HPCI and RCIC Turbines.
Y-103672 Response to information Notice 88-67, Turbine Overspeed Trip Failure Y-212459 Response to information Notice 90-40, Results of NRC Sponsored Testing of Motor-Operated Valves Y-212730 Response to information Notice 90-45, Overspeed of the Turbine-Driven Auxiliary Feedwater Pumps and Overpressurization of the Associated Piping Systems.
Y-213283 Response to information Notice 90-76, Failure of Turbine Overspeed Trip Mechanism Because of inadequate Spring Tension Y-215899 Response to information Notice 93-51, Repetitive Overspeed Tripping of Turbine-Drtven Auxiliary Feedwater Pump Y-105470 Response to information Notice 93-67, Bursting of HPCI Line Rupture Disks injures Plant Personnel Y-216370 Response to information Notice 94-27, Facility Operating Concems Resulting From Local Area Flooding Y-217059 Response to information Notice 94-66, Overspeed of Turbine-Driven Pumps Caused by Govemor Valve Stem Binding Y-217477.
Response to information Notice 94-83, Reactor Trip Followed by unexpected Events
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Y-217050 Response to information Notice 94-84, Air Entrainment in Terry Turbine Lubricating Oil System
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Y-105471 Response to information Notice 95-13, Potential for Data Collection Equipment to
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Affect System Performance Procedures Procedure 1003.01, Rev. 22 CPS Hardware Change Program Procedure 1003.02 Field Configuration Change Program Procedure 1003.09, Rev. O CPS Instrument Setpoint Program interface Procedure 1005.01, Rev. 39 Clinton Power Station Procedures and Documents Procedure 1005.06, Rev.12 Conduct of Safety Reviews
- Procedure 1005.06F005 Preparation of Safety Evaluations Certification Card Procedure 1014.03 Temporary Modifications Procedure 1014.06 Guidelines for the Classification of Condition Reports Procedure 1014.11 Switchyard Circuit Breaker Operabilit) program
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Procedure 1016.01 Condition Reports Procedure 1019.00 Control of Chemicals Procedure 1019.07, Rev. 4 Leakage Reduction and Monitoring Program Procedure 1019.08 Control of Lubrication
' Procedure 1038.02, Rev. O Changes to the Technical Specification Bases Procedure 1038.03, Rev. 3 Revising the Updated Safety Analysis Report and the Operational Requirement Manual Procedure 1151.02, Rev. 2 Methodology for Outage Safety Reviews and Maintenance of Acceptable Shutdown Risk Procedure 1305.01F003 Bypass Leakage Summary Sheet Procedure 1401 Conduct of Operations Procedure 1401.09, Rev.1 Control of System and Equipment Status Procedure 1401.10 General Equipment Operating Requirements Procedure 1893.04M801 657'499' Screen House Prefire Plan Procedure 1983.04, Rev. 8 Fire Fighting Procedure 3006.01, Rev. 26 Unit Shutdown Procedure 3310.01, Rev.18 Reactor Core isolation Cooling System Procedure 3310.01V001 Reactor Core isolation Cooling Valve Lineup Procedure 3312.01, Rev. 30 Residual Heat Removal System
- Procedure 3312.03 Residual Heat Removal Shutdown Cooling & Fuel Pool Cooling Procedure 3506.01C001
. Emergency Diesel Generator Operating Logs.
Procedure 3506.01, Rev. 25 Emergency Diesel Generator and Support Systems Procedure 3506.01V001 Diesel Generator and Support Systems Valve Lineup Procedure 4003.01, Rev.12 Remote Shutdown Procedure 4003.01, Rev.13 Remote Shutdown Procedure 4006.01, Rev.13 Loss of Shutdown Cooling Procedure 4303.02, Rev. 5 Abnormal Lake Level Procedure 4304.01, Rev. 3 Flooding
Procedure 5063.02, Rev. 2 Annunciator Response Procedure, RCIC Storage Tank Level Low Procedure 7001.04, Rev. 3 Conduct of Radiological Technical Evaluations Procedure 8120.02 Maintenance of Anchor Dariing Pressure Seal Gate Valves Promdure 8410.03 Motor Overiosd Relay Testing
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Procedure 8410.04 Molded Case Circuit Breaker Functional Testing and Maintenance Procedure 8410.21 Westinghouse DHP 6.9kV/14.16kV Power Circuit Breaker Procedure 8801.05, Rev.15 Corrections to Instrument Calibrations Procedure 8801.06, Rev.16 Wire Removal / Jumper installation Procedure 8902.01, Rev. 3 Oil Sampling Procedure 9000.01D001 Control Room Surveillance Log - Mode 1,2,3 Procedure 9000.01D011 Control Room Surveillance Log-Modes 1,2, and 3 Procedure 9030.01, Rev. 30 Analog Trip Module Channel Functional and Calibration Check Instructions Procedure 9054.01, Rev. 35 RCIC System Operability Check Procedure 9054.05, Rev. 27 RCIC Pump Flow Operability (Low Steam Pressure)
Procedure 9054.05, Rev. 29 RCIC Pump Flow Operability (Low Steam Pressure)
- Procedure 9080.21. Rev. 23 Emergency Diesel Generator 1 A - ECCS Integrated Procedure 9382.02, Rev. 27 125 VDC [ Volts Direct Current] Battery ICV [ Individual Cell Voltage] and Battery Charger Checks Cl-01.00, Rev.1 Instrument Setpoint Calculation Methodology PSTG-EOPs, Rev. 3 Section I-5, Cautions NSED W.01, Rev. 2 Engineering Work Request EOP-6, Rev. 24 Primary Containment Control NSED A.18 Conduct of System Engineering NSED E.1, Rev. 9 Calculations NSED W.01, Rev. 2 Engineering Work Requests MS-01.00 Equipment Lubrication Procedure MS-08.00, Rev. 0 Lubrication Level of Rotating Equipment MS-08.00, Rev.1 Lubrication Level of Rotating Equipment NFPA 13 Installation of Sprinkler Systems Completed Surveillance Tests Procedure 1014.05 Preparation of Fost Maintenance Testing Procedure 2825.18, Rev. 2 Rererve Auxiliary Transformer and Static VAR Compensator Test Procedure 3808.01, Rev. 3 RCIC Turt>ine Overspeed Trip Test, completed 9/26/93 and 12/4/94 Procedure 3808.01, Rev. 4 RCIC Turbine Overspeed Trip Test, completed 3/12/95 Procedure 3808.01, Rev. 5 RCIC Turbine Overspeed Trip Test, completed 8/18/96 Procedure 9015.05, Rev. 27 Reactor Water Cleanup Logic System Functional Test Procedure 9027.01C002 RSP Operability - RCIC Checklist, completed 4/21/95 and 5/27/97 Procedure 9030.01C006 RCIC Reactor Vessel Level 2 B21-N692A (B,E,F) Charael Checklist, completed 2/13/97 and 7/28/97 Procedure 9030.010006 RCIC Reactor Vessel Level 2 B21-N692A (B,E,F) Channel Data Sheet, completed 2/13/97 Procedure 9030.01D006 RCIC Reactor Vessel Level 2 B21-N692A (B,E,F) Channel Data Sheet, completed 7/28/97 Procedure 9030.01C007 RCIC Reactor Water Level 8 B21-N693A (B) Channel Functional Checklist, completed 8/2/97
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Procedure 9030.01C007 RCIC Reactor Water Level 8 B21-N693A (B) Channel Functional Checklist, completed 11/17/97 Procedure 9030.01D007 RCIC Reactor Water Level 8 B21-N693A (B) Channel Functional Data Sheet, completed 8/2/97 and 11/17/97 Procedure 9030.01C034 RCIC Steam Line Flow E31-N683A (B), E31-N684A (B) Channel Functional Checklist, completed 5/14/97 and 8/26/97 Procedure 9030.01D034 RCIC Steam Line Flow E31-N683A (B), E31-N684A (B) Channel Functional Data Sheet, completed 5/14/97 and 8/26/97 Procedure 9030.01C035 RCIC Main Steam Supply Pressure E31-N685A (B) Channel Functional Checklist, completed 3/28/97 and 8/24/97 Procedure 9030.01D035 RCIC Main Steam Supply Pressure E31-N685A (B) Channel Functional Data Sheet, completed 3/28/97 and 8/24/97 Procedure 9030.01C040 RCIC Storage Tank Level E51-N635A (E) Channel Functional Checklist, completed 7/29/97 and 10/21/97 Procedure 9030.01D040 RCIC Storage Tank Level E51-N635A (E) Channel Functional Data Sheet, completed 7/29/97 and 10/21/97 Procedure 9030.01C041 RCIC Turbine Exhaust Diaphragm Pressure E51-N655A (B,E,F)
Channel Functional Checklist, completed 7/28/97 and 10/20/97 Procedure 9030.01D041 RCIC Turbine Exhaust Diaphragm Pressure E51-N655A (B,E,F)
Channel Functional Data Sheet, completed 7/28/97 and 1.0/20/97 Procedure 9030.01C042 RCIC Suppression Pool Level E51-N636A(E) Channel Functional Checklist, completed 7/18/97 and 11/7/97 Procedure 9030.01D042 RCIC Suppression Pool Level E51-N636A(E) Channel Functional Data Sheet, completed 7/18/97 and 11/7/97 Procedure 9054.01, Rev. 30 RCIC System Operability Check, completed 9/16/94 and 8/14/95 Procedure 9054.01, Rev. 31 RCIC System Operability Check, completed 11/1/95,2/2/96, and 4/18/96 Procedure 9054.01, Rev. 32 RCIC System Operability Check, completed 7/11/96 Procedure 9054.01, Rev. 34 RCIC System Operability Check, completed 8/3/97
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Procedure 9054.02, Rev. 31 RCIC Valve Operability Checks, completed 4/20/95
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Procedure 9054.02, Rev. 32 RCIC Valve Operability Checks, completed 7/11/96,5/4/97, 5/26/97, and 6/14/97 Procedure 9054.02, Rev. 33 RCIC Valve Operability Checks, completed 8/3/97 Procedure 9054.03, Rev. 27 RCIC Simulated Auto Actuation Test, completed 4/21/95
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Procedure 9054.03, Rev. 28 RCIC Simulated Auto Actuation Test, completed 8/3/97 l
Procedure 9054.04, Rev. 22 RCIC Auto Suction Shift Test, completed 11/9/95
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Procedure 9054.04, Rev. 23 RCIC Auto Suction Shift Test, completed 8/29/97
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Procedure 9054.06, Rev. 23 RCIC Filled Discharge Piping, Flow Path, and Flow Controller Checks, completed 8/8/96 and 9/5/96 I
Procedure 9861.05, Rev. 23 D003 - HPCS Water Leakage Rate Data Sheet Procedure 9861.05, Rev. 28 D004 - RCIC Closed Loop Outside Containment Test Quality Assurance Surveillances
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Quality Assurance Surveillance Report Q-17137, Fuse Replacement Program Quality Assurance Assessment 98-116380, Fuse Replacement Program Quality Assurance Report Q39-98-21, Breaker Source Quality Assurance Assessment NE-98-60, Fuse Replacement Program Assessment Update
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D Enoineerina Work Reauests (EWRs)
EWR 92-00855 Revision Of Interface Valve Procedures EWR 97-06-021 Discrepancy Between Updated Safety Analysis Report and Procedure 3310.01 Regarding Diversion of Flow Back to the Storage Tank Dunng injection into Vessel EWR 98-03-052 Validate RCIC System EWR 94-00014 Electrical Distribution System Functional Inspection Updated Safety Analysis Report (USAR)
USAR Section 1.2.1 Principle Design Criteria USAR Section 1.2.2.4.7 Reactor Core isolation Cooling System
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USAR Sectioi.1.2.2.4.8 Emergency Core Cooling Systems USAR Section 3.6 Protection Against the Dynamic Effects Associated With the Postulated Rupture of Piping s
USAR Section 5.0 Reactor Coolant System and Connected Systems USAR Section 5.4.6 Reactor Core Isolation Cooling System i
USAR Section 6.2.4 Containment Isolation System USAR Section 6.2.4.3.2.3 Evaluation Against Criterion 57 USAR Section 6.3 Emergency Core Cooling System USAR Section 6.5.1.1.1 Standby Gas Treatment System USAR Section 7.4.1.1 RCIC Instrumentation and Control USAR Section 6.3 Onsite Power System
'JSAR Section 15.0.3 Event Evaluation USAR Section 15.2.7 Loss of Feedwater Flow USAR Section 15.6.5.5.2.2 Fission Product Transport to the Environment USAR Section 15.6.6 Feedwater Line Break - Outside Containment USAR Appendix 15A Plant Nuclear Safety Operational Analysis USAR Figure 2.5-427 Seismic Hazard Curve USAR Figure 15.A.6-44 Protection Sequences - Anticipated Transkents USAR Figure 15.A.6-45 Protection Sequences - Abnormal Transients USAR Figure 6.3-3 Head Versus High Pressure Core Spray Flow Ur i in Loss of Coolant Accident Analysis - Clint: 1 USAR Figure 15.A.6-43 Protection Sequences - Normal Op3 ration USAR Figure 15.A.6-44 Protection Syuences - Anticipated Transients USAR Figure 15.A.6-45 Protection Sequences - Abnormal Transients USAR Tabic 3.11-5 -
Environmental Zone Summary Table USAR Table 6.2-1 Containment Design Parameters Drawinas M10-9079, Sheet 2, Rev. B Reactor Core Isolation Cooling System P&lD, 5/18/88
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M05-1002, Rev. S Main Steam System P&lD,8/20/98 M05-1079, Sheet 1, Rev. AC Reactor Core isolation Cooling, 9/3/98 M05-1079, Sheet 2, Rev. AF Reactor Core isolation Cooling,9/3/98 M05-1047, Rev. L Auxiliary Building Drain System P&lD,2/9/98 VPF3622-018 RCIC Trip System Assembly VPF3622-017(1)
RCIC Overspeed Trip Assembly
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E02-1Rl99, Sheet 10, Rev. F Reactor Core isolation Cooling NSPS System E02-1AP12 Relay and Metering Diagram EDG 1 A, Part 1 E02-1DG99 Schematic Diagram Diesel Generator System Emergency Diesel Generator Excitation E02-1AP44 Key Diagram 4160-Volt Bus 1 A1 E03-1AP07EC Intemai-Extemal Wiring Diagram Emergency Diesel Generator 1 A Transformer 1DG01JA E031P680C Intemal-Extemal Wiring Diagram Principal Plant Control Console Part 2 FECN 23820, Nooter Corporation, Job P-8109, Sheets 1&7,12/17/76 Grinnell Fire Protection Systems Drawings FP1& FP2, Level 762' of Control Building,6/16/98, Rev.3 General Electric (GE) Specifications GE Specification 21 A9443, Rev. 4 Reactor Core isolation Cooling Pump GE Specification 22A2576 Customer /AE Supplied Data; Phase 1 GE Specification 22A3'iS3, Rev. 4 Reactor Protection System GE Specification 22A3131 AL, Rev.13 High Pressure Core Spray GE Specification 22A3124BK DSDS Reactor Core Isolation Cooling System GE Specification 22A2746, Rev.1 Condensate Makeup Water GE Specification 145C3039 Fuse, Cartidge GE Specification NEDC-32202P Safety Relief Valve Setpoint Tolerance and Out-of-Service Ar alysis for Clinton Power Station Technical Specifications (TSs)
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TS 3.3.2.4.4, Suppression Pool Dump Valve instrumentation
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TS 3.3.6.4.7 '
Suppression Pool Makeup system Instrumentation TS 3.4.4 Safety Relief Valves TS 3.5 -
Emergency Core Cooling Systems and RCIC System TS 3.8.1 -
AC Sources - Operating TS 3.8.2-AC Sources - Shutdown TS 3.8.6.2 Battery Cell Parameters
. TS 5.5.13 Primary Containment Leakage Rate Testing Program TS Table 3.3.6.1-1 P.imary Containrrent and Drywell isolation instrumentation Miscellaneous Documents Action Request D76691During Performance of Preventive Maintenance Found Hardened Grease in the Motor Pinion Cavity Action Request D18955, Indicator Pegged High and Face Plate is Melted Auxiliary Power System Design Functional Validation
' CPS Comprehensive Plan of Corrective Actions to improve Breaker Reliability Field Deviation Disposition Request LH1-5805, Acceptability of Minimum Flow Through Bypast, Line on RCIC System CPS Continuous Performance improvement Program, CNP 3.02,1/99 CPS Letter L30-86(03-04)-L, Fire Protection Evaluation Report & Safe Shutdown Analysis, 3/4/86
79 L.
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CPS Letter L30-86(03-07)-L, Resolution of the Fire Protection Site Audit Concems,3/7/86 CPS Letter L30-86(05-29)-L, Safe Shutdown Analysis,5/29/86 CPS Letter L30-86(06)-L, NFPA Code Conformance Deviations,6/19/86 CPS Plan-For-Excellence CPS Response to NRC Plan-for-Excellence,12/23/97 Detailed Design Review of Selected Modification, Plant Changes and Calculations,12/98 Emergency Diesel Generator Vendor Manual K2861-0002-A, Rev. 78, 12/17/98 Engineering Department Monthly Performance Indicators,12/98 and 1/99 EPRI Report RP-101-53, Probabilistic Seismic Hazard Evaluation For Clinton Power Station Equipment Environmental Design Conditions Design Criteria, Rev.11, 3/21/96 ESA 105, Sargent & Lundy Standard for Calculation of Conductor Temperature of Power Cables 50.59 Review Checklists dated 2/10/99,2/11/99, and 2/18/99 50.59 Performance Reports dated 7/998,9/4/98,11/16/98, and 1/16/99 lilinois Power Company Letter U-0331, Response to NUREG-0737, item II.K.3.44 and corresponding Safety Evaluation Report,11/17/81, Illinois Power Company integrated Safety Assessment Report,10/20/97 January 1999 Material Condition Management Program Trend Report List of Preventive Maintenance Tasks and Preventive Maintenance Evaluation Requests for the RCIC System Master Equipment List Material Condition Management Team Meeting Minutes,3/14/96
- Memorandum B45-93 (08-09), Torque and Voltage Relationships for Direct Current Motor-Operated Valve Motors MWR D82808, Perform Corrective Maintenance on Valve 1E12-F006A MWR PMMSXM013 Perform Piping Wall Thickness Measurements National Electrical Manufactures Association Qualification Summary Report NEDO-32686, Rev. O, Utility Resolution Guidance for ECCS Suction Strainer Blockage,11/96 NSED Standard GS-04.00, SDFV, Rev. 3,5/12/98 Nuclear Steam Supply Shutoff System DL851E381 AC Plant Manager Standing Order 052 PMMRIM001, Changa RCIC Pump Lube Oil PMMRIM008, inspect the Condition and Setting of RCIC Overspeed Trip Throttle Valve Linkage J PMMRIP001, Change Oil in Turbine Oil System Post System Design Func*ional Validation Report Radiological Technical Evaluation 96-021-ED, 9/4/96 RCIC System Health Report,1"- 4* Quarter,1998
~ RCIC Pump Curves, Pump Test T-16210287-1,8/4/78 Residual Heat Removal Heat Exchanger - Division 1 Data and Performance Evaluation 1E12-B001 A, Rev.1,7/22/98 Safe Shutdown Analysis for Fire Protection, Amendment 1, 2/86 Clinton Power Station Fire Protection Appendix R Safe Shutdown Compliance Summary Report, Rev. 2,10/29/98 SDFV Walkdown Packages WD 98-01 and WD 98-02,7/28/98
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SDFV Final Report,6/4/98 System Design Functional Validation Report System Design and Functional Validation Report on the AP System System Design and Functional Validation Report on the RHR System Closure Package for Case Specific Checklist items IV.3, IV.4, IV.5, VI.1, VI.2, and VI.3
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Senior Engineering Group Meeting Minutes 1998-1999
- o, Training Guide Number LP10114, Nuclear Safety Evaluations, 9/1/98 USAR Change Package 96-044 Attemate Shutdown Cooling Method,9/11/97 USAR Change Package 97-238 Environmental Qualification Umits in ECCS Pump Room,12/97 I
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