IR 05000413/2012007

IR 05000413-12-007 and 05000414/2012-007; 08/13/2012 - 09/14/2012; Catawba Nuclear Station, Units 1 and 2; Component Design Bases Inspection

ML12293A205
Person / Time
Site:	Catawba
Issue date:	10/18/2012
From:	Nease R NRC/RGN-II/DRS/EB1
To:	Henderson K Duke Energy Corp
References
IR-12-007
Download: ML12293A205 (34)

Text

UNITED STATES ber 18, 2012

SUBJECT:

CATAWBA NUCLEAR STATION - NRC COMPONENT DESIGN BASES INSPECTION - INSPECTION REPORT 05000413/2012007 AND 05000414/2012007

Dear Mr. Henderson:

On, September 14, 2012, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Catawba Nuclear Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on September 14, 2012, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The team reviewed selected procedures and records, observed activities, and interviewed personnel.

Two NRC identified findings of very low safety significance (Green), which were determined to involve violations of NRC requirements, were identified during this inspection. The NRC is treating these violations as non-cited violations consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest the violations or the significance of these non-cited violations, you should provide a written response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at Catawba. In addition, if you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at Catawba. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Rebecca L. Nease, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-413, 50-414 License Nos.: NPF-35, NPF-52

Enclosure:

Inspection Report 05000413/2012007 and 05000414/2012007, w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 050000413, 05000414 License Nos.: NPF-35, NPF-52 Report Nos.: 05000413/2012007, 05000414/2012007 Licensee: Duke Energy Carolinas, LLC Facility: Catawba Nuclear Station, Units 1 and 2 Location: York, SC 29745 Dates: August 13 - September 14, 2012 Inspectors: E. Stamm, Senior Reactor Inspector (Lead)

D. Jones, Senior Reactor Inspector A. Alen, Reactor Inspector J. Montgomery, Reactor Inspector T. Su, Reactor Inspector (Trainee)

C. Baron, Accompanying Personnel S. Kobylarz, Accompanying Personnel Approved by: Rebecca Nease, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000413/2012-007 and 05000414/2012-007; 08/13/2012 - 09/14/2012; Catawba Nuclear

Station, Units 1 and 2; Component Design Bases Inspection.

This inspection was conducted by a team of five Nuclear Regulatory Commission (NRC)inspectors from Region II, and two NRC contract personnel. Two Green non-cited violations (NCVs) were identified. The significance of inspection findings are indicated by their color (i.e.,

greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross-Cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated June 12, 2012. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, (ROP) Revision 4.

Cornerstone: Mitigating Systems

• Green: The team identified a non-cited violation of Catawba Nuclear Station Units 1 and 2 License Condition 2.C.5, Fire Protection Program, for the licensees failure to establish a leakage acceptance criteria past check valves that supported minimum, post-fire safe shutdown (SSD) design flow requirements of the standby shutdown system. The licensee entered the issue into the corrective action program as PIP C-12-7717 and conservatively limited the allowed Total Accumulative RCS [reactor coolant system] Leakage to gain additional standby makeup pump (SMP) flow margin.

The licensees use of inadequate test acceptance criteria for back-leakage through check valves was a performance deficiency. The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute in that, if back-leakage through check valves 1(2)NV-46, 1(2)NV-57, 1(2)NV-68, and 1(2)NV-79 was to degrade to the allowed limits in the test procedure, the SMP would not be capable of meeting the 26 gpm reactor coolant system makeup requirement to support the standby shutdown system post-fire SSD function. The inspectors evaluated this issue in accordance with Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, and determined the finding to be of very low safety significance (Green). The finding was assigned the category of post-fire SSD and a low degradation rating that reflected the severity of the identified deficiency. There was no cross-cutting aspect associated with this finding because the condition existed since initial issuance of the test procedure and was not reflective of current licensee performance. (Section 1R21.2.7)

• Green: The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, for the licensees failure to establish a procedure to ensure that the requirements in EQMM 1393.01-A01-00, Environmental Qualification Maintenance Manual, were not exceeded to maintain the environmental qualification of motor-operated valves (MOVs). The licensee entered the issue into the corrective action program as PIP C-12-7121, declared MOVs 1KCC37A, 1WL807B, and 2KCC37A as operable but degraded/nonconforming, and instituted guidance to periodically review the cycles of all MOVs to ensure the maximum limit is not exceeded.

The licensees failure to establish a procedure to ensure the MOV cycle requirements of EQMM 1393.01-A01-00, were not exceeded was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of procedure quality and adversely affected the cornerstone objective in that, the lack of procedural guidance to track the cycles of MOVs resulted in 1KCC37A, 1WL807B, and 2KCC37A exceeding their environmental qualification cycle limit of 2,000 cycles and decreased the reliability and capability of the MOVs. The team assessed the finding in accordance with Inspection Manual Chapter 0609,

Significance Determination Process, Attachment 4, Initial Characterization of Findings, and determined the finding was of very low safety significance (Green) because the performance deficiency did not result in a loss of MOV operability. The finding was associated with the cross-cutting aspect of implementation and institutionalization of operating experience in the Operating Experience component of the Problem Identification and Resolution area. P.2(b) (Section 1R21.2.12)

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R21 Component Design Bases Inspection

.1 Inspection Sample Selection Process

The team selected risk significant components and related operator actions for review using information contained in the licensees probabilistic risk assessment. In general, this included components and operator actions that had a risk achievement worth factor greater than 1.3 or Birnbaum value greater than 1 X10-6. The sample included fifteen components, two of which were associated with containment large early release frequency, and six operating experience items.

The team performed a margin assessment and a detailed review of the selected risk-significant components and related operator actions to verify that the design bases had been correctly implemented and maintained. Where possible, this margin was determined by the review of the design basis and Updated Final Safety Analysis Report (UFSAR) response times associated with operator actions. This margin assessment also considered original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for a detailed review. These reliability issues included items related to failed performance test results, significant corrective action, repeated maintenance, maintenance rule status, Regulatory Issue Summary 05-020 (formerly Generic Letter 91-18) conditions, Nuclear Regulatory Commission (NRC) resident inspector input regarding problem equipment, system health reports, industry operating experience, and licensee problem equipment lists.

Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense-in-depth margins. An overall summary of the reviews performed and the specific inspection findings identified is included in the following sections.

.2.1 Auxiliary Feedwater (CA) Check Valves (CA-8, -10, -12, -23, -28, -33)

a. Inspection Scope

The team reviewed CA system check valves located in the pump suction piping and in the pump minimum flow piping. The review included applicable portions of the plants UFSAR and piping and instrumentation diagrams (P&IDs) to identify the design bases requirements of the CA check valves. The team examined system health reports and records of surveillance testing and maintenance activities to verify that potential degradation issues were being monitored, prevented, and/or corrected. The team performed a walkdown of the CA check valves and associated equipment to review the installed configuration of the valves, verify the material condition of the equipment, and to verify that the equipment and associated piping was not exposed to any other hazards. Discussions with system and component engineers were conducted regarding pump and check valve design and performance requirements.

b. Findings

No findings were identified.

.2.2 Residual Heat Removal (ND) Pumps and Motors (1A and 1B)

a. Inspection Scope

The team reviewed the UFSAR, current system health report, selected drawings, operating procedures, and past Problem Investigation Program reports (PIPs) for the Unit 1 ND pumps. The team interviewed the ND system engineer to discuss the overall health and condition of the pumps and associated equipment. The team interviewed mechanical and electrical design engineers responsible for verifying the pumps capacity to operate under both minimum and maximum flow conditions. The team reviewed calculations, test procedures, and test results addressing required ND pump performance requirements during design bases accidents, calculations addressing required pump net positive suction head, and calculations addressing pump minimum and runout flow conditions. The team reviewed the design with regard to industry issues, including potential pressurization of system piping during some accident conditions and reduced thrust bearing life under low flow conditions. The team also performed walkdowns of the pumps and associated equipment to verify the material condition of the equipment and to verify that the equipment was adequately protected.

The team verified, by review of schematic drawings, that operation of the Unit 1 ND pump motors was consistent with the design basis and operational requirements. The team verified that the brake horsepower required by the pump was the maximum horsepower that was required during a loss of coolant accident and was within the motor rating. The team reviewed the protection coordination calculation for the motor and verified that the circuit breaker ratings, protective device trip settings and alarm functions were consistent with the licensing basis and operational requirements. The team reviewed recent calibration tests of the breaker overcurrent relays to confirm that the calibration results satisfied design requirements and that corrective actions were implemented, if required. The team reviewed maintenance and corrective action histories to determine whether there had been any adverse operating trends. The team verified that the ambient conditions were consistent with vendor recommendation for the motors. In addition, the team performed a walkdown of the observable installed equipment to determine whether the installed configuration was consistent with design documents including drawings and calculations, and to assess the presence of hazards.

b. Findings

No findings were identified.

.2.3 Pressurizer Power Operated Relief Valves (PORVs) (NC-32B, -34A, -36B)

a. Inspection Scope

The team reviewed applicable portions of the design and licensing documents, including flow diagrams, applicable plant calculations, and drawings to identify the design bases and functional requirements of the pressurizer PORVs. The team also interviewed design and system engineers to evaluate the components design requirements and obtain historical test performance results. In addition, the team reviewed the PIP database to assess identification and resolution of failures or nonconforming issues.

The team reviewed the valve control diagrams to verify they conformed to the system functional description and operational requirements contained in the UFSAR and design basis documents (DBDs). The team also reviewed availability and capability of air and nitrogen supply, and electrical power sources to verify that the valves would be able to perform their intended design function when called upon under design basis requirements. The team examined system health reports, records of recent surveillance testing and maintenance activities to confirm the readiness of the components to perform their required functions during system demands. Additionally, the team reviewed station operating and off-normal procedures to verify that design basis requirements had been adequately translated into procedures and instructions. The team did not perform a walkdown and assessment of the material condition of the PORVs because they were located in an inaccessible area.

b. Findings

No findings were identified.

.2.4 Standby Shutdown Facility (SSF) Ventilation Fans (#1 and #3)

a. Inspection Scope

The team reviewed applicable portions of the plants UFSAR, DBDs, and P&IDs to establish an overall understanding of the design bases of the SSF ventilation fans.

Inspectors walked down the SSF to visually inspect the material condition of the fans.

Inspectors reviewed electrical drawings and calculations to verify fans could be energized from appropriate standby power sources for accident scenarios where use of the SSF is required. Inspectors reviewed electrical and control diagrams to assess whether the fans would be able to start under accident conditions and whether they were subject to common-cause failures. Inspectors also reviewed NRC Information Notice 2012-12, HVAC Design Control Issues Challenge Safety System Function, for applicability to this facility.

b. Findings

No findings were identified.

.2.5 Unit 1 Emergency Diesel Generator (EDG) Starting Air System

a. Inspection Scope

The team reviewed the plants technical specifications (TS), UFSAR, DBDs, and P&IDs to establish an overall understanding of the design bases of the EDG starting air system.

Design calculations (i.e. air receiver sizing) and site procedures were reviewed to verify that the design bases and design assumptions had been appropriately translated into these documents. The team reviewed modifications over the life of the system to verify that the subject modifications did not degrade the systems performance capability and were appropriately incorporated into relevant drawings and procedures. System walkdowns were conducted to verify that the installed configurations would support its design bases functions under accident conditions and had been maintained to be consistent with design assumptions and to visually inspect the observable material condition of the system. Operating and alarm response procedures were reviewed to verify that component operation and alignments were consistent with design and licensing bases assumptions. Test procedures and recent test results were reviewed against design basis documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. An interview with the system engineer was conducted to discuss the history of the system operation, maintenance, and corrective actions. Vendor documentation, current system health reports, preventive and corrective maintenance history list, and relevant PIPs were reviewed in order to verify that potential degradation was monitored or prevented and that component replacement was consistent with inservice/equipment qualification life.

b. Findings

No findings were identified.

.2.6 EDG Governor and Controls

a. Inspection Scope

The team reviewed the plants UFSAR, TS, DBDs, and relevant electrical drawings to establish an overall understanding of the design bases of the EDG governor and its control functions. The team reviewed system maintenance records of the components and relevant PIPs to verify that the maintenance activities did not degrade the components performance and there were no adverse performance trends. Component walkdowns were conducted to verify that the installed configurations would support their design bases function under accident/event conditions and had been maintained to be consistent with design assumptions. Control panel indicators were observed and operating procedures reviewed to verify that component operation and alignments were consistent with design and licensing basis assumptions. Test procedures and results were reviewed against DBDs to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and/or analyses served to validate component operation under accident/event conditions. Vendor documentation, system health reports, preventive and corrective maintenance history, and relevant PIPs were reviewed in order to verify that potential degradation was monitored or prevented and that component replacement was consistent with inservice/equipment qualification life.

b. Findings

No findings were identified.

.2.7 Standby Makeup Pump (1NVPUSB) and Filter

a. Inspection Scope

The team reviewed the plants TS, UFSAR, DBDs, and P&IDs to establish an overall understanding of the design bases of the standby makeup pump (SMP) and filter.

Design calculations (i.e., net positive suction head, pump sizing, and alarm setpoint) and site procedures were reviewed to verify that the design bases and design assumptions had been appropriately translated into these documents. The team reviewed system modifications over the life of the component to verify that the subject modifications did not degrade the components performance capability and were appropriately incorporated into relevant drawings and procedures. A component walkdown was conducted to verify that the installed configuration would support its design basis function under accident conditions and to visually inspect the observable material condition of the SMP. Test procedures and recent test results were reviewed against design basis documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. An interview with the system engineer was conducted to discuss the history of the component operation, maintenance, and corrective actions. Vendor documentation, current system health reports, preventive and corrective maintenance history, and relevant PIPs were reviewed in order to verify that potential degradation was monitored or prevented and that component replacement was consistent with inservice/equipment qualification life.

• Operator Action - The team reviewed the licensees abnormal operating procedure to verify that adequate guidance existed to provide a back-up cooling water supply to the charging (NV) pumps during a postulated loss of component cooling water event.

The team performed a walkdown of local manual actions, associated with aligning the drinking water system as a cooling water supply to the NV pumps, to verify the feasibility of the directed actions.

b. Findings

Introduction:

An NRC-identified Green non-cited violation (NCV) of Catawba Nuclear Station Units 1 and 2 License Condition 2.C.5, Fire Protection Program, was identified for the licensees failure to establish a leakage acceptance criteria past check valves 1(2)NV-46, 1(2)NV-57, 1(2)NV-68, and 1(2)NV-79 that supported minimum, post-fire safe shutdown (SSD) design flow requirements of the standby shutdown system (SSS).

Description:

The SSS is designed to mitigate the consequences of certain postulated fire, security, and station blackout events to either unit and consists of normal plant safety-related equipment and SSS-dedicated equipment. The system removes decay heat through the steam generators and provides reactor coolant system (RCS) makeup to achieve and maintain hot standby (Mode 3) conditions. To mitigate a postulated fire in a zone that would disable the normal RCS makeup and reactor coolant pump (RCP)seal injection capability, the SSS was equipped with two SMPs, one per unit. The pumps were required to provide a minimum design flow of 26 gallons per minute (gpm),at RCS pressure. This requirement was based on the 20 gpm Total Accumulative RCS Leakage (RCS leakage + normal RCP seal leakage) limit specified in the Selected Licensee Commitment (SLC) 16.7-9, Standby Shutdown System, Condition B. The SLC limit of 20 gpm provided an additional 6 gpm required to accommodate a projected 1.5 gpm RCP seal leak-off increase, per RCP, as the event progressed, thereby assuring that RCS inventory was maintained.

The team reviewed procedures PT/1(2)/A/4200/005 C, SMP Check Valve Test, Rev.

6(5), which were used by the licensee, in part, to demonstrate the closure of the RCP normal seal supply check valves 1(2)NV-46, 1(2)NV-57, 1(2)NV-68, and 1(2)NV-79.

These valves were located in the normal seal injection flow path (one for each RCP)upstream of the SMP tie-in and were required to close to prevent flow diversion from the SMP such that all flow was directed to the RCS via the normal RCP seal injection lines.

The test acceptance criteria for check valve back-leakage was specified to be less than 1 gpm (per check valve) at a test pressure of 1,000 psig. Because the actual system operating pressure for the check valves was approximately 2,300 psig, the higher differential pressure (at accident conditions) could reasonably result in back-leakage of more than 1 gpm for valves with a degreated seating surface. Additionally, per calculation CNC-1223.04-00-0072, RCP No.1 Seal Leak-off Annunciator Alarm Setpoint for Unit 1 and Unit 2, Rev. 3, the minimum design flow requirement of 26 gpm assumes each of the check valves leak a maximum of 0.2 gpm (0.8 gpm total). This assumption was not consistent with the acceptance criteria in PT/1(2)/A/4200/005 C.

Based on the above, the team concluded that the procedure for the RCP seal supply check valves was inadequate in that the acceptance criteria was non-conservative to ensure at least 26 gpm from the SMP would be available to meet the SSS flow requirements at the SLC limit of 20 gpm. The licensee entered the issue into the corrective action program as PIP C-12-7717. The licensee performed a functionality assessment and determined the SMPs would still be capable of performing their function based on the latest back-leakage test results, which indicated minimal leakage through the valves, and based on current and historical accumulative RCS leakage data. The licensee conservatively limited the SLC allowed Total Accumulative RCS Leakage to 15 gpm to gain additional SMP flow margin.

Analysis:

The licensees use of inadequate test acceptance criteria for back-leakage through check valves associated with the post-fire SSD flow requirements of the SMP was a performance deficiency. The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external factors, such as fire, and adversely affected the cornerstone objective of ensuring the capability of systems to respond to events to prevent undesirable consequences. Specifically, if back-leakage through check valves 1(2)NV-46, 1(2)NV-57, 1(2)NV-68, and 1(2)NV-79 was to degrade to the allowed limits of <1 gpm in the test procedure, the SMP would not be capable of meeting the 26 gpm RCS makeup requirement to support the SSS post-fire SSD function. The team evaluated this issue in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process, and determined the finding to be of very low safety significance (Green). The finding was assigned the category of post-fire SSD and a low degradation rating based upon the current minimal leakage past the check valves; and the current and historical accumulative RCS leakage having been sufficiently low such that margin was available for the SMP to perform its function. There was no cross-cutting aspect associated with this finding because the condition existed since initial issuance of the test procedure and was not reflective of current licensee performance.

Enforcement:

Catawba Nuclear Station Operating License Condition 2.C.5 for Units 1 and 2 required that Duke Energy Carolinas, LLC implement and maintain in effect all provisions of the approved fire protection program as described in the UFSAR, as amended, for the facility and as approved in the Safety Evaluation Report (NUREG-0954), dated February 1983, and Supplement Numbers 1 through 5. Safety Evaluation Report Supplement No. 4, Section 9.5.1, Fire Protection Program, stated, in part, that the SMP will provide at least 26 gpm of borated water to the RCS. Contrary to the above, from initial plant operation until September 14, 2012, the licensee failed to ensure that a minimum of 26 gpm from the SMP would be provided to the RCS. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety significance and was entered into the licensees corrective action program as PIP C-12-07717, to address recurrence: NCV 05000413, 414/2012007-01, Failure to Develop Adequate Test to Ensure Minimum SMP Flow Requirements.

.2.8 Unit 1 Nuclear Service Water System Strainers

a. Inspection Scope

The team reviewed the plants TS, UFSAR, DBDs, and P&IDs to establish an overall understanding of the design bases of the Unit 1 nuclear service water strainers. Design calculations (i.e. system thermal hydraulics) and site procedures were reviewed to verify that the design bases and design assumptions had been appropriately translated into these documents. The team reviewed modifications over the life of the component to verify that the subject modifications did not degrade the systems performance capability and were appropriately incorporated into relevant drawings and procedures. A component walkdown was conducted to verify that the installed configuration would support its design bases function under accident conditions and to visually inspect the observable material condition of the strainer and supporting equipment. Operating and alarm response procedures were reviewed to verify that strainer operation and alignment was consistent with design and licensing bases assumptions. Interviews with the component and system engineers were conducted to discuss the history of the component operation, maintenance, and corrective actions. Vendor documentation, current system health reports, preventive and corrective maintenance history list, and PIPs were reviewed in order to verify that potential degradation was monitored or prevented and that component replacement was consistent with in service/equipment qualification life.

b. Findings

No findings were identified.

.2.9 Emergency Core Cooling System Supply Motor Operated Valve (MOV) (1FW-27A)

a. Inspection Scope

The team reviewed the UFSAR, selected drawings, and operating procedures for MOV 1FW-27A. Design calculations (i.e., differential pressure and required torque/thrust) and site procedures were reviewed to verify that the design bases and design assumptions had been appropriately translated into these documents. The team also performed walkdowns of the valves and associated equipment to verify the material condition of the equipment and to verify that the equipment was adequately protected. Operating procedures were reviewed to verify that component operation and alignments were consistent with design and licensing bases assumptions. Test procedures and recent test results were reviewed against design basis documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. Current system health reports, preventive and corrective maintenance history, and relevant PIPs were reviewed in order to verify that potential degradation was monitored or prevented.

The team reviewed schematics of record for the 1FW-27A valve motor starter. The team reviewed the valve motor vendor nameplate data and the specifications for the motor to verify conformance with the calculation for motor terminal voltage. The team reviewed the calculation for determining the minimum motor terminal voltage under design/licensing basis conditions to assess the capability of the motor to provide the required thrust to operate the valve. The team also reviewed the calculation for determining the minimum motor starter contactor terminal voltage under design/licensing basis conditions to verify adequate voltage at the contactor coil for valve motor starting and running conditions.

b. Findings

No findings were identified.

.2.10 125VDC Diesel Essential Auxiliary Power System Battery (1DGBA)

a. Inspection Scope

The team reviewed the UFSAR and DBDs to identify the loading requirements for the safety-related diesel essential auxiliary power system batteries. The team reviewed the inputs to the battery and charger sizing analysis and the battery voltage study to verify adequate sizing of the battery for both design basis accident and station blackout conditions and the sizing of the battery charger. The battery voltage study was reviewed to verify adequate voltage was available to critical components. Battery TS surveillance test and inspection results were reviewed to verify battery capacity. The team reviewed maintenance and corrective action histories to verify that identified equipment problems were corrected and to determine whether there had been any adverse operating trends.

In addition, the team performed a walkdown of the battery, battery racks, battery charger and battery enclosure to determine whether the installed configuration was consistent with design documents including drawings, and calculations, and to assess the presence of hazards.

b. Findings

No findings were identified.

.2.11 EDG Supply Breaker (1ETA-18)

a. Inspection Scope

The team verified by review of schematic drawings, that operation of the breaker was consistent with the design basis and operational requirements. The team reviewed the protection coordination calculation for the EDG supply breaker and verified that the circuit breaker ratings, protective device trip settings, and alarm functions were consistent with the licensing basis and operational requirements. The team reviewed maintenance schedules and procedures, and completed work orders to determine whether the breaker was being properly maintained. The team reviewed protective relaying schemes and calculations to determine whether the breaker was adequately protected and coordinated with the switchgear. The team reviewed maintenance and corrective action histories to determine whether there had been any adverse operating trends. The team reviewed recent calibration tests of the breaker overcurrent relays to confirm that the calibration results satisfied design requirements and that corrective actions were implemented, if required. In addition, the team performed a walkdown of the observable installed equipment to determine whether the installed configuration was consistent with design documents including drawings, and calculations, and to assess the presence of hazards.

b. Findings

No findings were identified.

.2.12 Residual Heat Removal Suction MOV (1ND-36B)

a. Inspection Scope

The team reviewed the plants TS, UFSAR, DBDs, and P&IDs to establish an overall understanding of the design bases of MOV 1ND-36B, which is the RCS C hot leg supply valve (for shutdown cooling) to the B ND pump. Design calculations (i.e.,

differential pressure and required torque/thrust) and site procedures were reviewed to verify that the design bases and design assumptions had been appropriately translated into these documents. Test procedures and recent test results were reviewed against design bases documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and/or analyses served to validate component operation under accident conditions.

Vendor documentation, current system health reports, preventive and corrective maintenance history lists, and PIPs were reviewed in order to verify that potential degradation was monitored or prevented. The team evaluated the environmental qualification requirements of the MOV including maximum allowable cycles. Selected industry operating experience was reviewed to verify that applicable insights had been applied.

The team reviewed schematics of record for the 1ND-36B valve motor starter. The team reviewed the valve motor vendor nameplate data and the specifications for the motor to verify conformance with the calculation for motor terminal voltage. The team reviewed the calculation for determining the minimum motor terminal voltage under design/licensing basis conditions to assess the capability of the motor to provide the required thrust to operate the valve. The team also reviewed the calculation for determining the minimum motor starter contactor terminal voltage under design/licensing basis conditions to verify adequate voltage at the contactor coil for valve motor starting and running conditions.

b. Findings

Introduction:

An NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to establish a procedure to ensure that the requirements in EQMM 1393.01-A01-00, Environmental Qualification Maintenance Manual, were not exceeded to maintain the environmental qualification (EQ) of motor-operated valves (MOVs).

Description:

The licensees EQMM 1393.01-A01-00, Environment Qualification Maintenance Manual, Rev. 8, section 2.1.1 established maximum limits of cycles for EQ-related MOVs. The inspection team determined that MOVs 1KCC37A (Component Cooling System Train 1A Recirculation Line Isolation Valve), 1WL807B (Reactor Coolant Drain Tank Pump Discharge Containment Isolation Valve), and 2KCC37A (Component Cooling System Train 2A Recirculation Line Isolation Valve) had exceeded their EQ cycle limit of 2,000 cycles as documented in Catawba PIP C-12-07121. Discussions with the MOV Engineer indicated that Catawba did not have written procedures for trending and monitoring the number of cycles of EQ-related MOVs.

As a result of PIP C-12-07121, an immediate determination of operability and prompt determination of operability were performed. The licensee determined the MOVs were operable but degraded/nonconforming and provided justification for continued operation for the referenced MOVs based on a Kinectrics Inc. Test Report, K-012964-RA-0001-R01, which qualified similar Rotork MOVs to 4,000 cycles, and that mechanical wear was not excessive and the cumulative wear would not prevent MOVs from performing their design basis functions.

In 2009, operating experience (OE) item OEDB-09-051790 was assigned to the Nuclear General Office to evaluate an event where EQ-related MOVs exceeded their EQ cycle limits. The OE evaluation was not effective in that it did not identify the need for written procedures at Catawba to ensure that EQ MOV cycle limits were not exceeded. In addition, the Nuclear General Office failed to involve appropriate station personnel and/or general office personnel to ensure appropriate corrective actions.

Analysis:

The licensees failure to establish a procedure to ensure that the MOV cycle requirements of EQMM 1393.01-A01-00, were not exceeded was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of procedure quality and adversely affected the cornerstone objective of ensuring availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the lack of procedural guidance to track the cycles of MOVs resulted in 1KCC37A, 1WL807B, and 2KCC37A exceeding their EQ cycle limit of 2,000 cycles and decreased the reliability and capability of the MOVs. The team assessed the finding in accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and determined the finding was of very low safety significance (Green) because the performance deficiency did not result in a loss of MOV operability. The finding was associated with the cross-cutting aspect of implementation and institutionalization of OE in the OE component of the Problem Identification and Resolution area. Specifically, the 2009 OE evaluation was not effective in that it did not identify the need for written procedures to ensure that EQ MOV cycle limits were not exceeded. P.2(b)

Enforcement:

Appendix B of 10 CFR 50, Criterion V, Instructions, Procedures, and Drawings, required, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, from implementation of EQMM 1393.01-A01-00, Rev. 8, in 2003, until September 14, 2012, an activity affecting quality was not prescribed by documented instructions or procedures, in that the licensee failed to establish a procedure to ensure the maximum MOV cycle requirements in EQMM 1393.01-A01-00, Environmental Qualification Maintenance Manual, were not exceeded. The licensee declared MOVs 1KCC37A, 1WL807B, and 2KCC37A as operable but degraded/nonconforming, and instituted guidance to periodically review the cycles of all MOVs to ensure the maximum limit is not exceeded. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety significance and was entered into the licensees corrective action program as PIP C-12-07121, to address recurrence: NCV 05000413, 414/2012007-02, Inadequate Implementation of Procedure to Ensure EQ MOV Cycle Limit Is Not Exceeded.

.2.13 SSF Pressurizer Heaters Sub-bank (Group D Heaters 28, 55, 56)

a. Inspection Scope

The team reviewed applicable portions of the design and licensing documents, including plant calculations and drawings to identify the design bases and functional requirements of the pressurizer heaters that are powered and controlled from the SSF. The team reviewed plant calculations to determine that the capacity of the heaters was sufficient to support safe shutdown from the SSF. The team examined system health reports, records of recent surveillance testing and maintenance activities to confirm the readiness of the components to perform their required functions during system demands. Additionally, the team reviewed station operating and off-normal procedures to verify that design basis requirements had been adequately translated into procedures and instructions. The team also reviewed plant calculations to verify that the timeframe to energize the heaters specified in plant procedures was adequate to maintain pressure control of the RCS. The team reviewed component electrical drawings to determine that heaters would be able to be controlled from the SSF, and no interlocks would inadvertently defeat control from the SSF. The team did not perform a walkdown and assessment of the material conditions of the pressurizer heaters because they are inaccessible during plant operation.

b. Findings

No findings were identified.

.2.14 Steam Generator (SG) PORVs (SV-1, -7, -13, -19)

a. Inspection Scope

The team selected the SG PORVs for review due to their contribution to large early release frequency. The team reviewed the UFSAR, current system health report, selected drawings, operating procedures, and relevant PIPs for the SG PORVs. The team interviewed the air-operated valve component engineer to discuss the overall health and condition of the valves and associated equipment. The team interviewed mechanical and electrical design engineers to verify the valves capability to perform their required functions with a loss of normal electrical power, loss of instrument air, and the most limiting single failure. The team reviewed calculations, test procedures, and test results addressing valve performance requirements during design bases accidents.

The team reviewed the design with regard to the diversity of the electrical power supplies, as well as the capacity and testing of the backup nitrogen supply. The team also performed walkdowns of the valves and associated equipment to verify the material condition of the equipment and to verify that the equipment was adequately protected.

• Operator Action - The team reviewed off-normal and emergency operating procedures to verify that adequate guidance existed for operators to respond to a design basis steam generator tube rupture (SGTR) event. The team observed a simulator scenario to verify the capability of the operators to mitigate a SGTR event as described in the UFSAR. The team performed a walkdown of local manual actions associated with a SGTR event to verify the feasibility of the directed actions.

b. Findings

No findings were identified.

.2.15 SG Main Steam Isolation Valves (MSIVs) (SM-1, -3, -5, -7)

a. Inspection Scope

The team selected the SG MSIVs for review due to their contribution to large early release frequency. The team reviewed the UFSAR, current system health report, selected drawings, operating procedures, and relevant PIPs for the MSIVs. The team interviewed the air-operated valve component engineer to discuss the overall health and condition of the valves and associated equipment. The team interviewed mechanical and electrical design engineers to verify the valves capability to perform their required functions with a loss of normal electrical power, loss of instrument air, and the most limiting single failure. The team reviewed test procedures and test results addressing valve performance requirements during design bases accidents. The team reviewed the design, including recent design changes, with regard to the diversity of the electrical power supplies. The team also performed walkdowns of the valves and associated equipment to verify the material condition of the equipment and to verify that the equipment was adequately protected.

b. Findings

No findings were identified.

.3 Operating Experience

a. Inspection Scope

The team reviewed six operating experience issues for applicability at Catawba Nuclear Station. The team performed an independent review for these issues and where applicable, assessed the licensees evaluation and disposition of each item. The issues that received a detailed review by the team included:

• NRC Generic Letter 1989-13, Service Water System Problems Affecting Safety-Related Equipment

• NRC Regulatory Issue Summary 2000-05, Resolution of Generic Safety Issue 165, Spring Actuated Safety and Relief Valve Reliability

• NRC Information Notice 2012-06, Ineffective Use of Vendor Technical Recommendations

• NRC Information Notice 2006-03, Motor Starter Failures Due To Mechanical-Interlock Binding

• NCV 05000331/2011009-01, Failure to Ensure Sufficient Thrust Margins for the 480 VAC Safety-Related MOVs

• NCV 05000369, 370/2012007-02, Inadequate Tornado Missile Protection for EDG Exhaust Ventilation System

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On September 14, 2012, the team presented the inspection results to Mr. Kelvin Henderson and other members of the licensees staff. Proprietary information that was reviewed during the inspection was returned to the licensee or destroyed in accordance with prescribed controls.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

S. Batson, Plant Manager

D. Belk, Component Engineer

B. Cauthen, RN System Engineer

R. Dickson, CDBI Technical Lead

A. Driver, Licensing Engineer

B. Ferguson, Systems Engineering Manager

E. Hacck, Design Engineer

T. Hamilton, Engineering Manager

R. Hart, Regulatory Compliance Manager

K. Henderson, Catawba Site Vice President

R. Herring, Standby Shutdown System Engineer

T. Jones, Field Operator

L. Keller, PCE Manager

D. Kulla, Civil Design Engineer

T. Pasour, Regulatory Compliance

D. Peal, Operations SRO

S. Putnam, Organizational Effectiveness Manager

M. Sawicki, Systems Engineer

P. Simpson, EDG System Engineer

T. Simril, Plant Manager (Acting)

W. Suslick, Design Engineering Manager

NRC personnel

J. Bartley, Chief, Reactor Projects Branch 1, Division of Reactor Projects, RII

R. Nease, Chief, Engineering Branch Chief 1, Division of Reactor Safety, RII

A. Hutto, Senior Resident Inspector, Division of Reactor Projects, Catawba Resident Office

R. Cureton, Resident Inspector, Division of Reactor Projects, Catawba Resident Office

LIST OF ITEMS

Opened and Closed

05000413, 414/2012007-01 NCV Failure to Develop Adequate Test to Ensure Minimum SMP Flow Requirements (Section 1R21.2.7)

05000413, 414/2012007-02 NCV Inadequate Implementation of Procedure to Ensure EQ MOV Cycle Limit Is Not Exceeded (Section 1R21.2.12)