IR 05000298/2012007

IR 05000298-12-007, on 03/05/2012 - 06/08/2012, Cooper Nuclaer Station - NRC Component Design Bases Inspection

ML12202B187
Person / Time
Site:	Cooper
Issue date:	07/20/2012
From:	Thomas Farnholtz Region 4 Engineering Branch 1
To:	O'Grady B Nebraska Public Power District (NPPD)
References
IR-12-007
Download: ML12202B187 (48)

Text

UNITED STATES uly 20, 2012

SUBJECT:

COOPER NUCLEAR STATiON - NRC COMPONENT DESIGN BASES INSPECTION, NRC INSPECTION REPORT 05000298/2012007

Dear Mr. O'Grady:

On April 4, 2012, the US Nuclear Regulatory Commission (NRC) completed a Component Design Bases Inspection at your Cooper Nuclear Station. The enclosed report documents our inspection findings. The preliminary findings were discussed on April 4, 2012, with Mr. D.

Buman, Director of Engineering, and other members of your staff. After additional in-office inspection, a final telephonic exit meeting was conducted on June 8, 2012, with Mr. D. Buman, Director of Engineering, Mr. A. Zaremaba, Director of Nuclear Safety Assurance, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The team reviewed selected procedures and records, observed activities, and interviewed cognizant plant personnel.

Based on the results of this inspection, the NRC has identified six findings that were evaluated under the risk significance determination process. Violations were associated with all of the findings. All of the findings were found to have very low safety significance (Green) and the violations associated with these findings are being treated as noncited violations, consistent with the NRC Enforcement Policy.

If you contest any of the noncited violations, or the significance of the violations you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the US Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Reguiatory Commission, Region IV, 1600 East Lamar Blvd., Arlington, Texas 76011; the Director, Office of Enforcement, US Nuclear Regulatory Commission, Washington, DC 20555-0001, and the NRC Resident Inspector at the Cooper Nuclear Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. In addition, if you disagree with the characterization of the crosscutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report,

"

-L.

with the basis for your disagreement, to the Regional Administrator, Region and at Nuclear Station.

In accordance with Code of Federal Regulations, Title 10, Part 2.390 of the NRC's Rules of Practice, a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS)

component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at (the Public Electronic Reading Room).

Sincerely ( (

Thomas R. Farnholtz, Chief Engineering Branch 1 Division of Reactor Safety Docket: 50-298 License: DRP-46 Enclosure:

NRC Inspection Report 05000298/2012007 wiAttachment:

Supplemental Information cc w/Enciosure:

Electronic Distribution for Cooper Nuclear Station

REGION License: DRP-46 Report: 05000298/2012007 Licensee: Nebraska Public Power District Facility: Cooper Nuclear Station Location: 72676 648A Ave Brownville, NE 68321 Dates: March 5 through June 8, 2012 Team Leader: R. Kopriva, Senior Reactor Inspector, Engineering Branch 1, Region IV Inspectors: R. Latta, Senior Reactor Inspector, Engineering Branch 1, Region IV M. Williams, Reactor Inspector, Engineering Branch 1, Region IV B. Correll, Reactor Inspector, Engineering Branch 2, Region IV S. Garchow, Senior Operations Engineer, Operations Branch, Region IV Accompanying V. Ferrarini, Structural Contractor, Beckman and Associates Personnel: G. Morris, Electrical Contractor, Beckman and Associates Approved By: Thomas R. Farnholtz, Chief Engineering Branch 1

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SUMMARY 05000298/201 03/05/2012 - 06/08/2012; Cooper Nuclear Station, baseline inspection, NRC Inspection Procedure 71111.21, "Component Design Inspection."

The report covers an announced inspection by a team of five regional inspectors and two contractors. Six findings were identified. All of the findings were of very low safety significance.

The final significance of most findings is indicated by their color (Green, White, Yellow, Red)

using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

A. NRC-Identified Findings Cornerstone: Mitigating Systems Green. The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," which states, in part, "measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions." Specifically, prior to March 8, 2012, the licensee failed to incorporate the seismic/barge impact loadings using a +Y (vertical up) component in combination with the lateral loads, which would result in the highest concrete anchor bolt interaction, into Calculation NEDC 12-20 for the service water instrument rack. Also, the calculation incorrectly utilized a factor of safety of four for the anchor bolts, where as the Updated Safety Analysis Report, Appendix C 2, Section 2.10, specified a factor of safety of five. This finding was entered into the licensee's corrective action program as Condition Report CR-CNS-2012-01665.

The team determined that the failure to incorporate the seismic/barge impact loadings using a +Y (vertical up) component in combination with the lateral loads into calculation NEDC 12-20, and using an incorrect safety factor for the instrument rack anchor bolts was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee revised the associated calculations to include the correct required standards, and the calculation was acceptable. This finding was determined to have a crosscutting aspect in the area of human performance, associated with the work practices component because the iicensee did not ensure that supervisory or management oversight of the work activities, including contractors, were such that nuclear safety was supported

H.4(c) (Section 1R21.2.5).

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identified a violation 10 CFR Criterion XI, "Test Control," which states, in part, "A program shall be established to assure that all testing required to demonstrate structures, "'<CIT!

will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate acceptance limits contained in applicable documents."

Specifically, prior to April 4, 2012, for the Startup Station Service Transformer (SSST),

the licensee did not use the actual measured bus bar resistance values which exceeded the calculated values. This resulted in non-conservative values used in Calculation NEDC 00-003, which did not bound actual plant parameters. Also, for the Emergency Station Service Transformer (ESST), the current procedure has a resistance acceptance tolerance specified as 1 Ohm, and in Condition Report CR-CNS-2011-11750, the licensee found the actual measured value was in the milliohms, which should have been used as the acceptance criteria in the procedure. This finding was entered into the licensee's corrective action program as Condition Reports CR-CNS-2012-02358 and CR-CNS-2012-02359.

The team determined that the failure to provide adequate acceptance criteria for the bus duct resistance for the Emergency Station Service Transformer and the Startup Station Service Transformer was a performance deficiency. This finding was more than minor because it was associated with the test control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green)

because it was a test deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee performed an engineering justification for the bus resistance acceptance criteria based on the difference between the as measured resistance values and those values used in the voltage iegulation study, and found the values acceptable. This finding was determined to have a cross-cutting aspect in the area of human performance associated with the decision making component because the licensee did not use conservative assumptions in decision making and adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action

[H.1 (b)] (Section 1R21.2.13).

Green. The team identified a Green noncited violation of 10 CFR Part 50, Appendix 8, Criterion XVI, "Corrective Action," which states, in part, "measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition." Specifically, in 2005, the licensee performed a review of the "c" swing battery charger disconnect switch fuses and their ratings, documented in Condition Report CR-CNS-2005-09378. However, the actions associated with this Condition Report did not evaiuate the Updated Safety Analysis Report emergency event function which states that each battery charger shall have adequate capacity to restore its battery to full charge from a totally discharged condition

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current entered into the licensee's corrective action program as Condition Report 2012-01 1 The team determined that the failure to adequately assess all design requirements during the review of Condition Report CR-CNS-2005-09378 was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the team determined that the finding represented a loss of system safety function requiring a Phase 2 evaluation. The Region IV Senior Reactor Analyst concluded that a Phase 3 evaluation was needed to address the issue because it departed from the guidance provided for Phase 1 or Phase 2. Using NRC Inspection Manual Chapter 0609, and Standardized Plant Analysis Risk (SPAR) model, the Senior Reactor Analyst identified that the frequency of events where the defective swing charger would affect core damage sequences were very low, that a station blackout restored by offsite power within one hour would not be expected to result in a failure of the swing charger, and it would be likely that the other battery charger would successfully charge the associated direct current bus and battery and result in a successful recovery. Therefore, the issue was determined to have very low significance (Green). This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance (Section 1R21.2.14).

Green. The team identified a Green noncited violation of 10 CFR Part 50, Appendix S, Criterion III, "Design Control," which states, in part, "measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program." Specifically, prior to Apri! 4, 2012, the licensee faiied to perform an adequate review of the design basis requirements to establish a preventive maintenance program for molded case circuit breakers located in the safety-related station battery chargers and important to safety battery inverters. This finding was entered into the licensee's corrective action program as Condition Reports CR-CNS-2012-1647 and CR-CNS-2012-1664.

The team determined that the failure to adequately review the design basis requirements, and not establishing a preventive maintenance program for molded case circuit breakers located in the safety-related station battery chargers and important to safety battery inverters, was a performance deficiency. This finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green)

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because it was a deficiency to in or functionality. Specifically, there have not been any failures of these molded case circuit breakers attributed to lack This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance (Section 1R21.2.15).

Green. The team identified a Green noncited violation of Technical Specification 5.4.1.a, which states, in part, "Written procedures shall be established, implemented, and maintained, covering the procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A.6.w, Acts of Nature (e.g., tornado, flood, dam failure, earthquakes)." Specifically, prior to April 4, 2012, the licensee failed to maintain Procedure 7.0.11, Flood Control Barriers, Revision 24, to ensure the materials required to construct flood protection barriers were correctly listed and inventoried, to effectively protect personnel and equipment doors around the perimeter of the facility. This finding was entered into the licensee's corrective action program as Condition Report CR-CNS-2012-01920.

The team determined that the failure to maintain Cooper Nuclear Station Operations Procedure 7.0.11, "Flood Control Barriers," Revision 24, with an adequate inventory of required materials listed in the procedure, was a performance deficiency. This finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the team determined that the finding was potentially risk significant due to a seismic, flooding, or severe weather initiating event and a Phase 3 analysis was required. A Region IV Senior Reactor Analyst performed a Phase 3 significance determination using NRC Inspection Manual Chapter 0609, Appendix M, "Significance Determination Process Using Qualitative Criteria." In accordance with Appendix M, the Senior Reactor Analyst determined that although it is not certain that the licensee could erect all of the flood barriers within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, it is likely that they could finish barriers to the emergency diesel generators and emergency core cooling systems in time to piOvide vital power and injection capabilities within the time required. Also, it is likely that extraordinary efforts could be taken to complete the barriers if the licensee was falling behind their time line, with knowledge of the timing of the arrival of flood waters. The failure of the Missouri River dams would most likely begin with incipient failure symptoms, providing extra time for the licensee to stage and prepare for the erection of barriers. Therefore, the issue was determined to have very low safety significance (Green). This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity P.1(d) (Section 1R21.2.16).

Green. The team identified a Green noncited violation, with two examples, of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," which states, in part, "Activities affecting quality shall be prescribed by documented instructions,

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or a appropriate to accomplished in accordance with these instructions, procedures, or drawings.

or shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished." Specifically, prior to April 4, 2012, the licensee did not follow the requirements of Cooper Nuclear Station Operations Manual Administrative Procedure 0.5.0PS, "Operations Review of Condition Reports/Operability Determination," Section 6 "Prompt Determination," Step 6.1.1.6. This step requires the use of Attachment 3, Item 3, which addresses design basis assumptions, descriptions, calculations, or values used in the Cooper Nuclear Station Updated Safety Analysis Report shall be used to ensure all aspects of the condition are addressed. For two, separate, Prompt Operability Determinations, one for the standby liquid control test tank, and the second one for the standby liquid control tank, the licensee had not considered the effect of vertical seismic loading in their calculation as identified in the Updated Safety Analysis Report (Table -3-7 page C-3-73). These findings were entered into the licensee's corrective action program as Condition Reports CR-CNS-2012-001214, CR-CNS-2012-001232, CR-CNS-2012-001651, CR-CNS-2012-001918 and CR-CNS-2012-01962.

The team determined that the failure to follow the requirements of Cooper Nuclear station Operations Manual Administrative Procedure 0.5.0PS, "Operations Review of Condition Reports/Operability Determination," Step 6.1.1.6, was a performance deficiency. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green) because it 'Nas a design deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee revised the associated calculations to include the correct required standards, with acceptable results. This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to properly classify, prioritize, and evaluate for operability and reportability, conditions adverse to quality [P.1 (c)] (Section 1R21.3.5).

B. Licensee-Identified Violations No findings were identified.

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1 REACTOR Inspection of component design bases verifies the initial design and subsequent modifications and provides monitoring of the capability of the selected components and operator actions to perform their design bases functions. As plants age, their design bases may be difficult to determine and important design features may be altered or disabled during modifications. The plant risk assessment model assumes the capability of safety systems and components to perform their intended safety function successfully.

This inspectable area verifies aspects of the Initiating Events, Mitigating Systems and Barrier Integrity cornerstones for which there are no indicators to measure performance.

1R21 Component Design Bases Inspection (71111.21)

To assess the ability of the Cooper Nuclear Station, equipment and operators to perform their required safety functions, the team inspected risk significant components and the licensee's responses to industry operating experience. The team selected risk significant components for review using information contained in the Cooper Nuclear Station, Probabilistic Risk Assessment and the U. S. Nuclear Regulatory Commission's (NRC) standardized plant analysis risk model. In general, the selection process focused on components that had a risk achievement worth factor greater than 1.3 or a risk reduction worth factor greater than 1.005. The items selected included components in both safety-related and nonsafety-related systems including pumps, circuit breakers, heat exchangers, transformers, and valves. The team selected the risk significant operating experience to be inspected based on its collective past experience .

. 1 Inspection Scope To verify that the selected components would function as required, the team reviewed design basis assumptions, calculations, and procedures. In some instances, the team performed ca!cu!ations to independently verify the licensee's conclusions. The team also verified that the condition of the components was consistent with the design bases and that the tested capabilities met the required criteria.

The team reviewed maintenance work records, corrective action documents, and industry operating experience records to verify that licensee personnel considered degraded conditions and their impact on the components. For the review of operator actions, the team observed operators during simulator scenarios, as well as during simulated actions in the plant.

The team performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design issues, margin reductions because of modifications, and margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as failed performance test results; significant corrective actions; repeated maintenance;

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10 50.65(a)1 status; operable, but degraded resident inspector input of problem equipment; system health reports; industry operating experience; and licensee problem equipment lists. Consideration was also given to the uniqueness complexity of the design, operating experience, and the available defense in-depth margins.

The inspection procedure requires a review of 15 to 25 samples that include risk-significant and low design margin components, containment-related components, and operating experience issues. The sample selection for this inspection was 17 components, one of which is containment-related, six operating experience items, and four Event Scenario-Based activities. The selected inspection and associated operating experience items supported risk significant functions including the following:

a. Electrical power to mitigation systems: The team selected several components in the electrical power distribution systems to verify operability to supply alternating current (AC) and direct current (DC) power to risk significant safety-related and important to safety loads in support of safety system operation in response to initiating events such as loss of offsite power, station blackout, and a loss-of-coolant accident with and without offsite power available. As such the team selected:

125 Vdc Battery and Battery Charger 1B 125 and 250 Vdc Swing Battery Chargers 1C 125 Vdc Bus 1B Offsite power as a Loss of Offsite Power Initiator 4160 Vac Bus 1G Portable Emergency Diesel Generator Division II Critical 460Vac Motor Control Center Y b. Mitigating systems needed to attain safe shutdown. The team reviewed components required to perform the safe shutdown of the plant. As such the team selected:

High Pressure Core injection Steam Emission Valve (HPCi-MOV-0"14)

High Pressure Core Injection Suction Valve From Torus (HPCI-MOV-058)

High Pressure Core Injection Pump Governor Valve

• Containment Hardened Vent B Train Residual Heat Removal Minimum Flow Recirculation Valve (RHR-MOV-16B)

High Pressure Core Injection Steam Admission Valve (M014)

Service Water Pump 1 B RHR SW Booster Pump Motor 1B

.2 Results of Detailed Reviews for Components

.2.1 High Pressure Core Injection (HPCI) Steam Emission Valve (HPCI-MOV-014)

Insoection Scooe-8- Enclosure

The team reviewed the updated final safety analysis report, technical specification requirements and limiting conditions for operation, system description, the current system health report, selected drawings, relevant maintenance and test procedures, condition reports associated with the high pressure core injection steam admission valve, HCPI-MOV-014. Also reviewed were design bases documents, calculations, and conducted component inspection to assess the adequacy of the motor and actuator for the valve. Specifically, the team reviewed control circuit schematics, voltage drop calculations, motor sizing data, and overall condition of the motor actuator. The team also performed system walkdowns and conducted interviews with system engineering personnel to ensure the capability of this component to perform its intended design basis function. Specifically, the team reviewed:

System piping and instrumentation drawings for the high pressure core injection system.

Valve vendor manual and correspondence file information for the motor.

System design basis documents and system modifications.

Preventive maintenance procedures and schedule for valve and motor.

Valve thrust requirements for design/licensing basis conditions.

Motor operated valve torque test procedure and torque test trend data.

Completion of preventive maintenance work orders for motor starter breaker testing.

Calculations for determining minimum motor terminal voltage under design/licensing basis conditions.

Calculations for determining minimum contactor terminal voltage under design/licensing basis conditions.

Calculations for the motor starter breaker and motor thermal overload heater selection.

Environmental design requirements under design/licensing basis conditions.

Calculations for limiting component analysis (vveak link analysis) including seismic loads for valve HPCI-MOV-014.

Pipe stress calculation containing valve HPCI-MOV-014.

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b. Findings No findings were identified .

.2.2 High Pressure Core Injection Suction Valve from Torus (HPCI-MOV-058)

a. Inspection Scope The team reviewed the updated final safety analysis report, technical specification requirements and limiting conditions for operation, system description, the current system health report, selected drawings, relevant maintenance and test procedures; and condition reports associated with the high pressure core injection suction valve from the torus, HCPI-MOV-058. The team also performed system walkdowns and conducted interviews with system engineering personnel to ensure the capability of this component-9- Enclosure

to perform intended design basis function. Further, the team reviewed design bases documents, calculations, and conducted component inspection to assess the adequacy of the motor and actuator for the valve. Included in these reviews were the control schematics, voltage drop calculations, motor sizing data, and overall condition of the motor actuator. Specifically, the team reviewed:

System piping and instrumentation drawings for the high pressure core injection suction valve from the torus.

Valve vendor manual and correspondence file information for the motor.

System design basis documents and system modifications.

Preventive maintenance procedures and schedule for valve and motor.

Valve thrust requirements for designllicensing basis conditions.

Motor operated valve torque test procedure and torque test trend data.

Completion of preventive maintenance work orders for motor starter breaker testing.

• Calculations for determining minimum motor terminal voltage under design/licensing basis conditions.

Calculations for determining minimum contactor terminal voltage under design/licensing basis conditions.

Calculations for the motor starter breaker and motor thermal overload heater selection.

Environmental design requirements under design/licensing basis conditions.

Calculations for limiting component analysis (weak link analysis) including seismic loads for valve HPCI-MOV-058.

Pipe stress calculation containing valve HPCI-MOV-058.

Pipe stress isometric drawing.

Piping loads on Torus.

No findings were identified .

.2.3 High Pressure Core Injection Pump Governor Valve a. Inspection Scope The team reviewed the updated final safety analysis report, system description, the current system health report, selected drawings, relevant maintenance and test procedures, and condition reports associated with the high pressure core injection pump governor valve. The team also performed walkdowns and conducted interviews with system engineering personnel to ensure the capability of this component to perform its intended design basis function. Specifically, the team reviewed:

Valve assembly drawings and component vendor manual including correspondence file information.

Preventive and corrective work orders completed.

Operational history including related industry operational experience and condition reports.

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Mechanical over speed trip device and system description information.

over speed operational ov,... ",r,o reports.

b. Findings No findings were identified .

.2.4 Primary Containment Purge, Makeup, and Vent System a. Inspection Scope The team reviewed the updated final safety analysis report, system description, selected drawings, relevant emergency operating procedures, and condition reports associated with the primary containment purge, makeup, and vent system. Additionally, the team performed system walkdowns and conducted interviews with system engineering and operations personnel to ensure the capability of this system to perform its intended design basis function. The team also observed operator actions in response to a station blackout event in the simulator. Specifically, the team reviewed:

Design and installation of the torus hard pipe vent system including seismic supports and equipment maintenance history.

Operator actions associated with the primary containment purge, makeup, and vent system during station blackout conditions including equipment accessibility.

• Operator knowledge and understanding of alternate core cooling mitigation strategies including primary containment venting and hydrogen control.

Containment isolation signal override functions associated with the torus purge and vent valve supply line.

Pipe stress anaiysis and connection to torus analysis.

b. Findings No findings were identified .

.2.5 Service Water Pump 1B a. Inspection Scope The team reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures, and condition reports associated with Service Water Pump 1B. The team also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its desired design basis function. Specifically the team reviewed:

• Seismic/Barge impact calculations for instrument racks.

• SeismiciBarge impact analysis for pump and pump anchorage.

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Preventive maintenance procedures for the motor.

Vendor manual, nameplate data, and specifications for the pump.

• System basis documents.

Calculations for determining motor voltage under design/licensing basis conditions.

Calculations for determining minimum contactor terminal voltage under design/licensing basis conditions.

Calculations for the motor starter breaker and motor thermal overload heater selection.

• Environmental design requirements under design/licensing basis conditions.

b. Findings Introduction. The team identified a Green noncited violation of 10 CFR Part 50, Appendix 8, Criterion III, "Design Control," involving the seismic calculation for the service water pump instrument rack. Specifically, on March 6, 2012, the licensee failed to correctly incorporate the required safety factor and torqueing requirements in the bolting of the service water pump instrumentation rack.

Description. As a result of the walkdown activities associated with the inspection, the licensee identified that one of the support legs of the service water instrument rack (Class 1 seismic structure), located in the Service Water Pump room, was corroded to the extent that it would no longer support the rack under all required loading conditions.

The system was declared inoperable and a temporary design was implemented per TCC 4881013. Calculation NEDC 12-020 Rev. 0 was issued to justify the temporary modification. The team reviewed the temporary modification support calculation and identified some discrepancies.

consider the most limiting loading combination for the structure and its components. The most limiting component in the modified structure are the concrete anchor bolts r"nnnQr-tinn

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significantly higher safety margin). The calculation did not consider the seismic/barge impact loadings using a +Y (vertical up) component in combination with the lateral loads which would result in the highest concrete anchor bolt interaction. These anchor bolts are a pair of 3/8" Hilti HOI Drop-In anchors and are subject to a factor of safety of 5 as identified in the Updated Safety Analysis Report, Appendix C-2, Section 2.10. However, calculation NEDC 12-020 Rev. 0 incorrectly utilized a factor of safety of 4 for these bolts.

The calculation was updated in Rev 1 to include the most limiting load case and utilized a factor of safety of 5 for the concrete anchor bolts.

The team reviewed Rev 1 of the calculation which in addition to the inclusion of the proper load combination and the factor of safety of 5 also included the as-built support review. The installed configuration modified the torque values for four (4) Y2 inch bolts from 62 ft/lbs to 22 ftllbs without justification. The site issued NEDC 12-020 Rev. 2 which satisfactorily addressed the team's concerns and concluded that the structure and anchor bolts were adequate to resist the updated load combinations using the correct factor of safety of 5 and reduced torque.

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Analysis. The team determined that the failure to incorporate the seismic/barge impact loadings using a up) component in combination with the lateral loads into calculation NEDC 12-20, and using an incorrect safety factor the instrument rack anchor bolts was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee revised the associated calculations to include the correct required standards, and the calculation was acceptable. This finding was determined to have a crosscutting aspect in the area of human performance, associated with the work practices component because the licensee did not ensure that supervisory or management oversight of the work activities, including contractors, were such that nuclear safety was supported

H.4(c).

Enforcement. The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," which states, in part, "measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions."

Contrary to the above, the licensee failed to ensure that measures were established to assure that applicable design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, prior to March 8, 2012, the licensee failed to incorporate the seismic/barge impact loadings using a +Y (vertical up)

component in combination with the lateral loads, which would result in the highest concrete anchor bolt interaction, into Calculation NEDC 12-20 for the service water instrument rack. Also, the calculation incorrectly utilized a factor of safety of four for the anchor bolts, where as the Updated Safety Analysis Report, Appendix C 2, Section 2.10, C!nQt"'ifiQ~ II"A

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action program as Condition Report CR-CNS-2012-01665. Because this finding is of very low safety significance and has been entered into the licensee's corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 5000298/2012007-01, "Failure to Adequately Analyze Seismic Requirements for Service Water Instrument Rack."

.2.6 Residual Heat Removal Service Water Booster Pump Check Valve (CV-20)

a. Inspection Scope The team reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures, and condition reports associated with residual heat removal service water booster pump check valve (CV-20). The team also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its desired design basis function. Specifically the team reviewed:

- 13 - Enclosure

Vendor installation instructions.

• maintenance records for the last three Surveillance procedures and surveillance results.

Leak rate testing for last three years.

Listing of condition reports for the past three years Piping and instrumentation diagram for the residual heat removal service water booster pump check valve (CV-20).

b. Findings No findings were identified .

.2.7 "B" Train 125 Vdc Battery a. Inspection Scope The team reviewed the updated safety analysis report, design bases documents, calculations, corrective and preventative maintenance, and testing of the safety-related, Division 2 250 V battery 1B, performed a walk down of the battery and associated components, and interviewed the system engineer. The team also reviewed alternating and direct current one-line diagrams, protective circuits, coordination curves, vendor manuals, maintenance procedures, pilot cell selection criteria and selection history, and conducted a conference call with the battery vendor on March 28, 2012. The team performed walk downs of the 125 V and 250 V battery chargers. Specifically, the team reviewed:

Technical specification requirements.

Electrical schematics.

Battery installation drawings.

Previous three modified performance discharge test results.

Battery rack and mounting calculation.

b. Findings No findings were identified .

.2.8 4160 Vac Bus 1G a. Inspection Scone The team reviewed the updated safety analysis report, main and 4160 Vac switchgear one-line diagrams, selected 4160 Vac, safety related switchgear circuit breaker elementary diagrams, load sequencing timing relays, undervoltage relay setpoints assorted calculations, manufacturer's information and related American National Standards Institute (ANSI) standards to ensure there was adequate voltage at the 4160

- 14 - Enclosure

volt and adequate interrupting in case a on the bus.

team conducted walk downs of the switchgear room, the simulator and the main control room. Specifically, the team reviewed:

Vendor installation instructions.

Past maintenance records for the last three years.

Surveillance procedures and surveillance results.

Listing of condition reports for the past three years.

System design basis documents and system modifications.

Environmental design requirements under design/licensing basis conditions.

b. Findings No findings were identified .

.2.9 Portable Emergency Diesel Generator a. Inspection Scope The team performed a walk down of the portable diesel generator, reviewed drawings, the vendor manual and procedures for its use. The team reviewed the diesel generator capacity (175 kW) to ensure it was adequately sized for the intended use with the two Train C (swing) battery chargers. The team confirmed the procedure provided the connection to 480 V buses and that there were pre-staged cables. Specifically, the team reviewed:

Vendor installation instructions.

• Past maintenance records for the last three years.

siintoiik,n('o

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_ , .. roco, litco Listing of condition reports for the past three years.

System design basis documents and system modifications.

Dro\lonfi\lo I

rn~in+o.n~nr"Q ,nrl"'\r"QnllrQ~

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Completion of preventive maintenance work orders for motor starter breaker testing.

Calculations for determining minimum motor terminal voltage under design/licensing basis conditions.

Calculations for determining minimum contactor terminal voltage under design/licensing basis conditions.

Calculations for the motor starter breaker.

Environmental design requirements under design/licensing basis conditions.

b. Findings No findings were identified .

.2.10 "8" Train Residual Heat Removal Minimum Flow Recirculation Vave (RHR-MOV-168)

15 - Enclosure

a.

team reviewed updated safety report, design bases calculations, and conducted component inspection to assess adequacy motor and actuator for the valve. Specifically, the team reviewed:

Control circuit schematics.

Voltage drop calculations.

Motor sizing data.

Flow and time delay setpoints.

Operating relay schematics.

Overall condition of the motor actuator.

Calculations for limiting component analysis (weak link analysis) including seismic loads for valve RHR-MOV-168.

b. Findings No findings were identified .

.2.11 Division II Critical 460 Vac Motor Control Center "Y" a. Inspection Scope The team reviewed the updated safety analysis report, design bases documents, calculations, corrective and preventative maintenance, and testing of the essential 460 Vac motor control center Y. Finally, the team performed a visual non-intrusive inspection to assess the installation configuration, material condition, and potential vulnerability to hazards. Specifically, the team reviewed:

System health reports, component maintenance history and licensee's corrective action program reports to verify the monitoring and correction of potential-J __ ~_-J_+:_~

UI::\::JI ClUCllIUl1.

Calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination to assess the adequacy and appropriateness of design assumptions and to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values to support transmission of power to downstream safety-related 460 Vac.

The protective device settings and circuit breaker ratings; to ensure adequate selective protection coordination of connected equipment during worst-case, short-circuit conditions to ensure continuity of power to downstream safety-related buses.

Circuit breaker preventive maintenance inspection and testing procedures; to determine adequacy relative to industry and vendor recommendations.

b. Findings f\Jo findings \"Jere identified.

- 16 - Enclosure

a.

The team reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures, protection relay setting sheets, coordination calculation and condition reports associated with residual heat removal service water booster pump motor. The team also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its desired design basis function. Specifically the team reviewed:

Vendor installation instructions.

Past maintenance records for the last three years.

Surveillance procedures and surveillance results.

Listing of condition reports for the past three years.

System design basis documents and system modifications.

Preventive maintenance procedures and schedule for the motor.

Completion of preventive maintenance work orders for motor starter breaker testing.

Calculations for determining minimum motor terminal voltage under design/licensing basis conditions.

Calculations for determining minimum contactor terminal voltage under design/licensing basis conditions.

Calculations for the motor starter breaker.

Environmental design requirements under design/licensing basis conditions.

b. Findings No findings were identified.

2.13 Offsite Power a. Inspection Scope The team reviewed the offsite power interface with the Cooper Nuclear Station as a Loss of Offsite Power initiator. The team reviewed the Operational Interface Agreement (OIA)

required by the North American Electric Reliability Corporation (NERC) Reliability Standard NUC-01-02 , "Nuclear Plant Interface," and confirmed the OIA was in place with Nebraska Public Power District transmission department. The team walked down the upgrades to the 345 kV, 161 kV and 69 kV switchyards, the proposed upgrades to the Large Power Transformers (Main Power Transformers) with an installed spare and new fire walls between phases, future replacements planned for the Normal Station Service Transformer, the Start-up Station Service Transformer (SSST) and the Emergency Station Service Transformer (ESST). The team reviewed selected power transformer nameplates, namepiate drawings and transformer test data for comparison with data used in the plant voltage regulation and short circuit calculations. The team also reviewed the condition monitoring of the non-segregated phase bus duct.

- 17 - Enclosure

b.

Introduction. team a violation 10 CFR 50, Appendix Criterion XI, "Test Control," failure provide adequate resistance values and acceptance criteria in documentation of the non-segregated phase bus ducts connecting the power transformers to the 4160 volt safety-related switchgear.

Description. During the walkdown of the non-segregated phase bus, which provides power path for the offsite power to the in-plant electric distribution system, the team questioned the licensee about the preventative maintenance criteria identified in the licensee's surveillance test document, Procedure 7.3.41, "Examination and Meggering of Non-Segregated Phase Bus," Revision 7. The team found that the acceptance criteria for the resistance measurement from the switchgear through the transformer was non-conservative. The value identified in the procedure was three orders of magnitude higher that the resistance used in the voltage regulation studies.

The Startup Station Service Transformer (SSST) bus bar resistances were measured in 2009 (W04458028), using Procedure 7.3.41. Four (4) bus bar circuits were measured, corresponding to the transformer feeds from the Startup Station Service Transformer to four (4) circuit breakers. The resistance values obtained included the transformer windings. When the transformer winding resistance was subtracted from the measured values, the actual resistance measured increased 998 micro-ohms for each bus bar phase. Calculation NEDC 00-003, "Cooper Nuclear Station Auxiliary Power System Load Flow and Voltage Analysis," used inputs to the bus bar resistance values calculated in NEDC 90-368, "Startup Station Service Transformer 4160 V Bus Impedance," for the Startup Station Service Transformer bus bar. The model inputs the bus undervoltage relay trip values, and then calculates the grid voltage necessary to assure that the grid remains tied to the 4160 volt safety related bus during accident/event conditions. The team identified that the actual measured bus bar resistance values exceeded the calculated values, which resulted in the values used in the NEDC 00-003 being non-conservative, not bounding the actual plant parameters, for bus bar resistance. The licensee revised the model used in NEDB 00-003, using the additional bus bar resistance (998 rnicro-ohms per bus bar phase) and the results indicate that the existing 168 kV value in Procedure 6.EE.610, "Offsite AC Power Alignment," remained acceptable.

Also, for the Emergency Station Service Transformer, the team identified that the NEDC 00-003, "Cooper Nuclear Station Auxiliary Power System Load Flow and Voltage Analysis." should appropriately match/bound the maintenance procedure criteria. The team identified that in Procedure 7.3.41, the resistance value for the Emergency Station Service Transformer (ESST) bus bar was inappropriate. The current procedure has a resistance acceptance tolerance specified as one (1) Ohm. The licensee had identified in Condition Report CR-CNS-2011-11750 that this resistance was not appropriate, and that actual measured values in milliohms should be used as the acceptance criteria.

After the team questioned the licensee about the bus bar resistance acceptance criteria, the iicensee noted that the corrective actions identified in the condition report had not been incorporated yet, but if the corrective actions had been followed, there would have been a discrepancy between revised Procedure 7.3.41 and NEDC 00-003, "Cooper

- 18 - Enclosure

Nuclear Flow Analysis."

has issued Condition Reports CR-CNS-2012-02358 and CR-CNS-2012-0259 to address these The performed calculation 1 3, "Operability SSST Bus Impedance Discrepancy" to demonstrate the measured values for duct resistance remained acceptable.

Analysis. The team determined that the failure to provide adequate acceptance criteria for the bus duct resistance for the Emergency Station Service Transformer and the Startup Station Service Transformer was a performance deficiency. This finding was more than minor because it was associated with the test control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green)

because it was a test deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee performed an engineering justification for the bus resistance acceptance criteria based on the difference between the as measured resistance values and those values used in the voltage regulation study, and found the values acceptable. This finding was determined to have a cross-cutting aspect in the area of human performance associated with the decision making component because the licensee did not use conservative assumptions in decision making and adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action

[H.i (b)].

Enforcement. The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion XI, "Test Control," which states, in part, "A program shall 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 acceptance limits contained in applicab!e documents." Contrary to the above, the licensee failed to incorporate known acceptance iimits into written test procedures. Specificaiiy, prior to Aprii 4, 2012, for the Startup Station Service Transformer (SSST), the licensee did not use the actual measured bus bar resistance values which exceeded the calculated values. This resulted in non-conservative values used in Calculation NEDC 00-003, which did not bound actual plant parameters. Also, for the Emergency Station Service Transformer (ESST), the current procedure has a resistance acceptance tolerance specified as 1 Ohm, and in Condition Report CR-CNS-2011-11750, the licensee found the actual measured value was in miiliohms, which should have been used as the acceptance criteria in the procedure. This finding was entered into the licensee's corrective action program as Condition Reports CR-CNS-2012-02358 and CR-CNS-2012-02359.

Because this finding is of very low safety significance and has been entered into the licensee's corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 5000298/2012007-02,

"Faiiure to Provide Adequate Resistance Vaiues for the Preventative Maintenance of the Non-Segregated Phase Bus Duct."

- 19 - Enclosure

.2.14 a.

The team reviewed the updated safety analysis report, alternating current (AC) and direct current (DC) one-line diagrams, protective circuits, coordination curves, vendor manuals and maintenance procedures. The team performed walk downs of the 125 V and 250 V battery chargers.

b. Findings Introduction. The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for failure to address the design bases of the battery chargers following identification of an undersized fused disconnect, connecting the "C" (swing) battery chargers to the DC buses.

Description. The licensee enhanced the 125 and 250 Vdc Class 1E systems with the addition of a "C" battery charger (installed by Design Change 87-073) for each system.

The addition of the "C" chargers permits the licensee the flexibility to operate with the "C" charger replacing either the Division I or the Division II battery chargers during plant operation, scheduled maintenance, or outages. Upon review of the direct current (DC)

one line diagram, the team noticed that the Division I and Division II 200 Amp battery chargers were connected to the direct current bus through a 300 Amp fused disconnect switch whereas the 200 Amp "C" swing charger was connected through a 200 Amp fused disconnect switch. In Condition Report CR-CNS-2005-09378 the licensee had previously questioned the size of the 200 Amp fuse in this application but their evaluation failed to analyze the Updated Safety Analysis Report, Section VIII-6.2.2 requirement which states that each battery charger shall have adequate capacity to rt=>C!tnrt=> ..

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normal station steady state direct current load. Under this condition, the battery charger will go into its current limit mode drawing 215 Amps. The manufacturer fuse curve for tho

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fr.r 4:1 , ..... I V I the 125 Vdc battery charger ends at 300 seconds (5.0 minutes or 0.083 hours9.606481e-4 days <br />0.0231 hours <br />1.372354e-4 weeks <br />3.15815e-5 months <br />). Based on the manufacture fuse curve, when extrapolated out past the published information, the 250 Vdc fuses may not remain intact during the recharge period. Based on the licensee's information for recent battery recharge evolutions following a discharge test, the battery charger output current remained high, in excess of 200 amperes for more than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Industry standards, such as the National Electrical Code, caution about using fuses above 80% of their rating. The team concluded that the capability to recharge the batteries following an event may be challenged.

The licensee declared the "C" swing battery chargers inoperable until further evaluation of the 200 Amp fuses could be performed. The licensee had sent the fuses to a vendor for testing. The licensee also confirmed that during the last three years, both the 125 Vdc and the 250 Vdc "C" swing chargers had been placed in service while one of the Division I or II battery chargers for were out of service. The 125 Vdc and the 250 Vdc "e" swing chargers had been in service for over 300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> each. The licensee is

- 20- Enclosure

currently reviewing to correct with disconnect switches.

Analysis. The team determined that failure to adequately assess all design requirements during the review of Condition Report CR-CNS-2005-09378 was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the team determined that the finding represented a loss of system safety function requiring a Phase 2 evaluation. The Region IV Senior Reactor Analyst concluded that a Phase 3 evaluation was needed to address the issue because it departed from the guidance provided for Phase 1 or Phase 2. Using NRC Inspection Manual Chapter 0609, and Standardized Plant Analysis Risk (SPAR) model, the Senior Reactor Analyst identified that the frequency of events where the defective swing charger would affect core damage sequences were very low, that a station blackout restored by offsite power within one hour would not be expected to result in a failure of the swing charger, and it would be likely that the other battery charger would successfully charge the associated direct current bus and battery and result in a successful recovery. Therefore, the issue was determined to have very low significance (Green). This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance Enforcement. The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," which states, in part, "measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are nrr\t'V'\nti\/ irionfifiori <:Inri I"t'wrol"tori t J l V l l l f J l . l J 1'-'1'""'1110.111"-' ...... c;;Afl"",, V\.I'II"",\""I""",,,,,,,,

In tho "<:ICO f"If ci('1nifil"<:>nt "f"Inriitif"lnc <:>ri\lorcQ tf"l 1111.11 ...... VU"",,V V I "-"I::::l'. III 1 V\"ooII 1 III. V..., 1 1_110.",",,11_ fooA._V_, ..... _

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the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition." Contrary to the above, the licensee identified a

.....!_\/i~+i,**\t*'" +r"I"'\!t'V'I .f.h_ '"'t"il"'llin..."i roi~~i,...1"'\ ,*u"\rf riiri nn+ "'lIC"'C"llro fh~f fho /""nnrlif;l"\n \A/~C nn;' ~~\Jo",cQ, UC:;VICHIV!I IIVIII LIIC V!I~IIIGtI \ ..H:;;:)I~II CUIU UIY IIVI. a " ..;:H...f I " 1I1QI. LII"'" V V f I V n , I V I I yvc;;...t...;;l' IIVI. ,""VY\,.,.r,,,Jv to quality. Specifically, in 2005, the licensee performed a review of the "C" swing battery charger disconnect switch fuses and their ratings, documented in Condition Report CR-CNS-2005-09378. However, the actions associated with this Condition Report did not evaluate the Updated Safety Analysis Report emergency event function which states that each battery charger shall have adequate capacity to restore its battery to full charge from a totally discharged condition while carrying the normal station steady state direct current load. This finding was entered into the licensee's corrective action program as Condition Report CR-CNS-2012-01611. Because this finding is of very low safety significance and has been entered into the licensee's corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 5000298/2012007-03, "Failure to Address the Design Bases of the Battery Chargers Following Identification of an Undersized Fused Disconnect Switch Connecting the Swing Battery Chargers to the Direct Current (DC) Buses."

.2.15 Molded Case Circuit Breakers

- 21 - Enclosure

a.

The one motor control centers, documents, industry standards, industry operating experience and preventive maintenance procedures to assess the condition monitoring performed on molded case circuit breakers.

b. Findings Introduction. The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for failure to appropriately evaluate preventive maintenance activities for molded case circuit breakers internal to safety-related and important to safety components, following the review of operating experience.

Description. The team performed an in-depth review of safety-related battery chargers and the important-to-safety battery inverter 1-A, and their internal molded case circuit breakers. While reviewing maintenance and surveillance procedures for this electrical equipment, the team noted that the licensee did not have an established preventive maintenance program, providing assurance that the equipment would operate and function as designed throughout the life expectance of the equipment.

The NRC Information Notice IN 93-64 identified certain standard molded case circuit breaker tests (such as individual pole resistance, 300-percent thermal overload, and instantaneous magnetic trip tests), performed periodically, were found to be effective along with the additional techniques of infrared temperature measurement and vibration testing. The information notice also stated that "An example of the industry standards that address periodic testing and preventive maintenance is IEEE Std 308-1974, IEEE Standard Criteria for Class 1 E Power Systems for Nuclear Power Generating Stations (endorsed by Regulatory Guide 1.32, Revision 2, February 1977}." Section 6.3, as weI!

as Section 7.4.1 of the current (1991) edition of the standard, recommended that periodic tests be performed at scheduled intervals to detect the deterioration of the eauioment and to demonstrate ooerabilitv of the comoonents that are not exercised

~ ~I - ,- ~ - - -" - - -" I J I during normal operation. The information notice also identified numerous other industry documents identifying concerns and requirements for testing of electrical equipment, specifically, molded case circuit breakers.

The Updated Safety Analysis Report, Chapter VIII, "Electrical Power," addresses inspection and testing of equipment in three locations:

Updated Safety Analysis Report Section VIII-3, "Emergency Power System,"

Subsection 3.7, "Inspection and Testing," Part 2, states: "Periodic tests/inspections of equipment is performed as defined in maintenance programs to determine equipment operability and functional performance."

Updated Safety Analysis Report, Section VIII-4, "Auxiliary Power Distribution System," Subsection 7, "inspection and Testing," Part 2, states: "Periodic tests of the equipment and the system are conducted to: a.) Detect the deterioration of equipment in the system toward an unacceptable condition, and b.) Demonstrate

- 22 - Enclosure

the capability properly energized."

Safety Analysis Report, Section "120-240 Vital Power,"

Subsection 8, "Inspection and Testing," states: "Periodic tests of the equipment and system are conducted to detect the deterioration of equipment in the system toward an unacceptable condition."

The team identified that the licensee had reviewed generic communication NRC Information Notice IN 93-64, "Periodic Testing and Preventative Maintenance of Molded Case Circuit Breakers." The licensee's evaluation of the information notice was documented in Inter-District memo, McClure to Moeller, dated January 20,1994. This evaluation referred to an earlier evaluation of molded case circuit breakers in licensee memorandum CNSS915709, dated August 19, 1991, and Nebraska Public Power District inter-district memo Horn to Meacham, dated August 7, 1991, which documents a review of molded case circuit breakers at Cooper Nuclear Station, and ruled out required testing of the safety-related battery chargers and the important-to-safety battery inverter i-A internal molded case circuit breakers. The evaluation specifically eliminated any requirements to perform preventive maintenance for the internal molded case circuit breakers on the basis that there were other electrical protective devices in the circuit (an upstream coordinated fuse) that would operate if the molded case circuit breakers failed to operate on a fault. The licensee considered the molded case circuit breakers as maintenance disconnects. The licensee's analysis, identified in the Nebraska Public Power District memorandum to M. Unruh from R. Krause, dated August 15, 1991, indicated that the NRC Information Notice 93-64 was to demonstrate that the molded case circuit breakers would trip on the time current curve. The licensee did not analyze all potential molded case circuit breaker failures, such as potential premature operation of the molded case circuit breakers. Premature operation of a thermal magnetic molded case circuit breaker is possible if there was a poor contact at a molded case circuit breaker terminal connection.

The NRC also issued Information Notice IN 2008-02, "Findings Identified During Component Design Bases Inspections," which identifies circuit breakers as a component in which there had been numerous operational concerns. The information notice references thirty nine NRC inspection reports pertaining to the components specifically identified in the information notice. Information Notice IN 20008-02 presented another opportunity for the licensee to review specific components for proper operation, testing and maintenance. The licensee entered this issue in their corrective action program as Condition Report CR-CNS 2012-1647 issued for the molded case circuit breakers located in the battery chargers, and Condition Report CR-CNS 2012-1664 issued for the molded case circuit breakers located in the battery inverter 1A including and extent of condition review.

Analysis. The team determined that the failure to adequately review the design basis requirements, and not establishing a preventive maintenance program for molded case circuit breakers iocated in the safety-related station battery chargers and important to safety battery inverters, was a performance deficiency. This finding was more than minor because it was associated with the procedure quality attribute of the Mitigating

- 23- Enclosure

Cornerstone and adversely affected cornerstone objective availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green)

because it was a design deficiency confirmed not to result in loss of operability or functionality. Specifically, there have not been any failures of these molded case circuit breakers attributed to lack of preventative maintenance. This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance.

Enforcement. The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," which states, in part, "measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program." Contrary to the above, the licensee failed to provide for verifying or checking the adequacy of design by the performance of a suitable testing program. Specifically, prior to April 4, 2012, the licensee failed to perform an adequate review of the design basis requirements to establish a preventive maintenance program for molded case circuit breakers located in the safety-related station battery chargers and important to safety battery inverters. This finding was entered into the licensee's corrective action program as Condition Reports CR-CNS-2012-1647 and CR-CNS-2012-1664. Because this finding is of very low safety significance and has been entered into the licensee's corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 5000298/2012007-04, "Failure to Establish a Preventative Maintenance Drnrtr'=lrY'\

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.2.16 Flood Related Structures a. Inspection Scope The team reviewed the flood control barriers procedure, flood procedure, the dam break analysis, barrier strength calculations, and condition reports associated with flooding protection. The team also performed a walkdown of all primary and secondary barrier locations, and observed the materials and equipment, and their storage locations, for all barrier construction. Additionally, the team spoke with flood protection program members and system engineering personnel to gain understanding of the procedures and implementation strategy. Specifically the team reviewed:

Station procedures for Flood, and Flood Control Barriers.

Dam break flooding barrier analysis, dated April 2, 2012, and Rev 1 dated April 3, 2012.

Photos of previously constructed barriers from 2009, 2010, and 2011.

Calculations for strength capacity for materials and installation methods.

Condition reports related to flooding for the past three years.

- 24- Enclosure

b. Findings The team identified a noncited violation of Technical Specification 5.4.1.a, for failure to establish adequate procedures involving flooding protection.

Specifically, as of April 2, 2012, the licensee failed to establish an adequate procedure to supply adequate materials and manpower to complete the installation of plywood barriers and sandbags in order to protect personnel and equipment doorways from flooding during a 72-hour response time for an upstream dam break.

Description. The team reviewed the licensees' dam break flooding barrier analysis, dated April 2, 2012, and Revision 1 dated April 3, 2012, and found that if one of the upstream dams on the river were to break, the site would have approximately 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in which to respond to the break, and complete the installation of plywood barriers and sandbags in order to protect personnel and equipment doorways from flooding.

The team noted that in Cooper Nuclear Station Operations Procedure 7.0.11, "Flood Control Barriers," Revision 24, paragraph 3.1.3.3, the licensee's analysis for adequate reinforcement of the plywood barriers required 2 inch x 4 inch horizontal members on the top and bottom or the barrier, with an additional 2 inch x 4 inch horizontal support placed midway between vertical supports throughout the span. During the review of the procedure, the team identified that the required materials identified in paragraph 3.1.3.3 of Procedure 7.0.11 were not included in Attachment 5, "Bill of Material," and Attachment 6, "Location and Material Requirements." Additionally, Attachment 5 required only 2200 sand bags to complete the erected barriers. Review of the licensees'

photos of previously constructed barriers from 2009, 2010, and 2011, revealed that a significantly larger number of sandbags were used in construction of the flood barriers.

When the team questioned the licensee about the significant differences in required materials identified in Procedure 7.0.11 (the plywood barriers and the sandbags), the licensee produced a white paper outlining a flood barrier construction strategy that in,..10 Ir1Qr1 1? 7nn c;,<lnr1 h<lnc;, <lnr1 rQn, ,irinn 111_1 _ _ _ _ 1&...)' -- _ ...... 1 _ --::;:,-, _ ** - '-....,-, *** ':::J 1=\<1 1"""--,.....- tn

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h::lrril'>r installation. Upon review of the white paper document, the team pointed out to the licensee, that in order to complete the tasks outlined in the white paper, onsite teams would have to work consecutive shifts (56 hours6.481481e-4 days <br />0.0156 hours <br />9.259259e-5 weeks <br />2.1308e-5 months <br />) without breaks. The licensee then modified the white paper to include 139 individuals dedicated to flood protection barrier construction and installation in order to meet the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> completion time. On April 26, 2012, with inspection team members present, the licensee provided a demonstration of erecting two typical flood barriers. During the 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> demonstration, four teams, of two people each, filled approximately 450 sandbags. This rate of filling sand bags equated to less than half the rate identified in the licensees' revised white paper, which was used to support Procedure 7.0.11.

Analysis. The team determined that the failure to maintain Cooper Nuclear Station Operations Procedure 7.0.11, "Flood Control Barriers," Revision 24, with an adequate inventory of required materials listed in the procedure was a performance deficiency.

This finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone Enclosure

objective to ensure the availability, reliability, to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment "Phase 1 - Initial Screening and Characterization of Findings," the team determined that the finding was potentially risk significant due to a seismic, flooding, or severe weather initiating event and a Phase 3 analysis was required. A Region IV Senior Reactor Analyst performed a Phase 3 significance determination using NRC Inspection Manual Chapter 0609, Appendix M,

"Significance Determination Process Using Qualitative Criteria." In accordance with Appendix M, the Senior Reactor Analyst determined that although it is not certain that the licensee could erect all of the flood barriers within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, it is likely that they could finish barriers to the emergency diesel generators and emergency core cooling systems in time to provide vital power and injection capabilities within the time required. Also, it is likely that extraordinary efforts could be taken to complete the barriers if the licensee was falling behind their time line, with knowledge of the timing of the arrival of flood waters. The failure of the Missouri River dams would most likely begin with incipient failure symptoms, providing extra time for the licensee to stage and prepare for the erection of barriers. Therefore, the issue was determined to have very low safety significance (Green). This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity [P.i (d)].

Enforcement. The team identified a Green noncited violation of Technical Specification 5.4.1.a, which states, in part, "Written procedures shall be established, implemented, and maintained, covering the procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A.6.w, Acts of Nature (e.g., tornado, flood, dam failure, earthquakes)." Contrary to the above, the licensee failed to maintain a procedure recommended in Regulatory Guide 1,33, Revision 2, Appendix A.6.w. Specifically, prior to April 4, 2012, the licensee failed to maintain Procedure 7.0.11, Flood Control Barriers, Revision 24, to ensure the materials required to construct flood protection barriers were correctly listed and inventoried, to effectively protect personnel and equipment doors around the perimeter of the faciiity. This finding was entered into the licensee's corrective action program as Condition Report CR-CNS-2012-01 920. Because this finding is of very low safety significance and has been entered into the licensee's corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 5000298/2012007-05, "Failure to Have an Adequate Procedure for Erecting Flood Barriers."

.2.17 Containment Structures a. Inspection Scope The team reviewed the period inspection reports done under the Structures Monitoring program for concrete, masonry, seismic gaps, structural and tanks. The team aiso reviewed the leakrate testing on the primary and secondary containments, and tOiUS inspection packages from the previous two cycles. The team also spoke with the

- 26- Enclosure

owners gain documentation and program implementation.

b.

No findings were identified .

.3 Results of Reviews for Operating Experience

.3.1 Inspection of Information Notice 2010-25 - "Inadequate Electrical Connections" a. Inspection Scope The team reviewed the licensee's response to the information notice, and reviewed a condition report search for inadequate electrical connections for the past five years.

Specifically, the search was associated with individual keywords "electrical," "loose," and

"connection," and also "loose and connection."

b. Findings No findings were identified .

.3.2 Inspection of Information Notice 2010-26 - "Submerged Electrical Cables" a. Inspection Scope The team reviewed the underground cable raceway drawings, observed the P3 manhole, and reviewed the results of cable insulation resistance measurements for the Service '/Vater pump motors and the Emergency Diesel Generator 2 cables.

b. Findings No findings were identified .

.3.3 Significant Operating Experience Report (SOER) 10-1 "Power Transformers" a. Inspection Scope The team reviewed the licensee's response to the industry recommendations for maintenance, testing and replacement of large power transformers. The licensee had addressed all nine recommendations through their corrective action program using nine different Condition Reports.

b. Findings No findings were identified.

- 27- Enclosure

for Nuclear Plant Interface" a. Inspection Scope The team reviewed the Cooper Nuclear Station response to the North American Electric Reliability Corporation Reliability Standard NUC-01-02, Nuclear Plant Interface Coordination. The standard was developed by an industry working group in response to NRC concerns on grid reliability and offsite power. The standard was reviewed by the NRC before being accepted by the Federal Energy Regulatory Authority (FERC) to require a formal agreement on communication between the transmission entity and the nuclear generator. The Nuclear Plant Interface Requirements (NPIR) contained in the agreement are to ensure a greater degree availability of the offsite power supply to supply adequate voltage to the nuclear plant, particularly following a trip of the nuclear unit as required by General Design Criterion 17, Electrical Power.

b. Findings No findings were identified.

NRC Information Notice 2012-01: "Seismic Considerations - Principally Issues Involving Tanks" a. Inspection Scope The team reviewed the licensee's evaluation of NRC Information Notice 2012-01,

"Seismic Considerations - Principally Issues Involving Tanks," to verify that the review adequately addressed the industry operating experience. The team verified that the li ___ ..... __ ' .... r_l.If_H' .....! __ I u'**..*, ...... I"'\+_rJ i_ f"",_,..Ji+i",_ D __ ",r+ ("0 ("t\.IC ")(11"1 .., t")"l,) I"'\rlOl"'fll....,,+ohl II\JCIIo;:)t;;C ;;:) I eVI'C;;vv! UU'VUIII'VIlt.t;;U III VVIIUII..IVI I I '\.ctJV1 t. V I " - V I "'fV-.C..V I L.,- I 'v"",, ouc\,.p...IGU.vIY addressed the issues in the information notice. The information notice provides examples and references to events in which licensees failed to recognize various seismic considerations and system alignment issues that could impact safety. The ~~RC staff had identified recent concerns about Standby Liquid Control test tanks that were not seismically qualified when they contained water. The Standby Liquid Control test tank is not safety-related, but are required to be seismically qualified because they could potentially impact nearby safety-related equipment during a seismic event.

b. Findings Introduction. The team identified a Green noncited violation, with two examples, of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for failure to follow the requirements of Cooper Nuclear station Operations Manual Administrative Procedure 0.5.0PS, "Operations Review of Condition Reports/Operability Determination," step 6.1.1.6, in that they had not reviewed all design and technical data available to be considered and incorporated into the operability evaluations for the Standby Liquid Control tank and test tank.

- 28- Enclosure

2, the resident inspectors brought to the attention of the licensee, the issuance of NRC Information Notice 2012-01, "Seismic Considerations-Principally Issues Involving Tanks," which provided examples and references to events in which licensees failed to recognize various seismic considerations and system alignment issues that could impact safety. The NRC staff had identified recent concerns about Standby Liquid Control test tanks that were not seismically qualified when they contained water. The operating experience identified may apply to other tanks found on site at nuclear plants. The Standby Liquid Control test tanks described in the information notice were not safety-related but were required to be seismically qualified because they could potentially impact nearby safety-related equipment during a seismic event.

Incorrect seismic structural analyses or inadequately reviewed procedure changes have led to licensees using tanks, such as the Standby Liquid Control test tanks, in a manner that left them vulnerable to seismic hazards. The operating experience indicated that it is important to verify that the Standby Liquid Control system test tanks and similar tanks have adequate seismic analysis and are procedurally controlled to ensure that seismic vulnerabilities are appropriately managed and that technical specifications are followed.

Example 1: The licensee issued Condition Report CR-CNS-2012-01232 for the Standby Liquid Control Test Tank in response to the NRC information notice. The licensee also reviewed the potential seismic concerns for the main Standby Liquid Control tank, which is identified in Condition Report CR-CNS-2012-01918. During the initial investigation of the seismic calculations for the different tanks, the licensee identified that they did not have a specific calculation pertaining to the seismic concerns of the Standby Liquid Control test tank. The licensee initiated Design Calculation NEDC 12-015 to evaluate both sliding and overturning at the base of each test tank support leg, in the event of seismic activity. The licensee performed an operability evaluation using the requirements identified in Cooper Nuclear station Operations Manual Administrative Procedure 0.5.0PS, "Operations Review of Condition Reports/Operability Determination" The licensee performed the operabiHty evaluation of the test tank assuming the test tank was full of liquid, and concluded that the tank would remain operable. The team reviewed the licensee's evaluation and identified that the licensee had not considered vertical movement in their calculation, as identified in the Updated Safety Analysis Report (Table -3-7 page C-3-73). Step 6.1 :L6, of Procedure 0.5 OPS requires that the licensee review all design and technical data available to be considered and incorporated into the operability evaluations. The licensee re-performed the calculation, incorporating all available design and technical data, and concluded that the test tank was operable.

Example 2: The licensee issued Condition Report CR-CNS-2012-01918 because they had identified that the original Burns and Roe Calculation, for the main Standby Liquid Control tank, BOOK 35, page 51, used a seismic coefficient of 0.46g, and the source of the coefficient could not be identified. The Cooper Nuclear Station Updated Safety Analysis Report (Table -3-7 page C-3-73) states a value of 0.33g for the operating basis earthquake and a value of 0.66g for the safe shutdown earthquake should be used for the seismic coefficients. The licensee revised the calculation to incorporate the new vaiues and found the tank to stiii be operabie. The team reviewed the licensee's seismic calculation and operability evaluation and found that the licensee had not considered vertical movement in their calculation, as identified in the Updated Safety Analysis

- 29- Enclosure

Report (Table -3-7 page Step 6.1.1.6, of Procedure OPS licensee review all design and technical data available to be considered and incorporated the operability evaluations. team identified that when vertical movement was incorporated into the seismic calculation, the number of bolts holding the tank in place was insufficient. The number of bolts required per the revised calculation was thirteen, where as there were only twelve bolts holding the tank in place. The licensee noted that the controlled drawing for the tank specified 7/8 inch anchor bolts, and the calculation had specified 3/4 inch bolts. The licensee confirmed that 7/8 inch anchor bolts were actually installed, and when the 7/8 inch anchor bolts were used in the calculation, twelve anchor bolts were more than adequate to hold the tank in place.

Analysis. The team determined that the failure to follow the requirements of Cooper Nuclear station Operations Manual Administrative Procedure O.S.OPS, "Operations Review of Condition Reports/Operability Determination," Step 6.1.1.6, was a performance deficiency. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," the issue was determined to have very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee revised the associated calculations to include the correct required standards, with acceptable results. This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to properly classify, prioritize, and evaluate for operability and reportability, conditions adverse to quality [P.1 (c)].

Enforcement. The team identified a Green noncited violation, with two examples, of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," which states, in part, "Activities affecting quality shall be prescribed by documented in",trllf'tinn",

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shall be accomplished in accordance with these instructions, procedures, or drawings.

Instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished." Contrary to the above, the licensee failed to accomplish specified steps in accordance with an approved procedure. Specifically, prior to April 4, 2012, the licensee did not follow the requirements of Cooper Nuclear Station Operations Manual Administrative Procedure O.S.OPS, "Operations Review of Condition Reports/Operability Determination," Section 6 "Prompt Determination," Step 6.1.1.6. This step requires the use of Attachment 3, Item 3, which addresses design basis assumptions, descriptions, calculations, or values used in the Cooper Nuclear Station Updated Safety Analysis Report, shall be used to ensure all aspects of the condition are addressed. For two, separate, Prompt Operability Determinations, one for the standby liquid control test tank, and the second one for the main standby liquid control tank, the licensee had not considered the effect of vertical seismic loading in their calculation as identified in the Updated Safety Analysis Report (Table -3-7 page C-3-73). These findings were entered

- 30 Enclosure

action as Condition Reports 2-001214, CR-CNS-2012-001232, CR-CNS-2012-001651, CR-CNS-2012-001918 and 2-01962. Because this finding is of very low safety significance and has entered into the licensee's corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 5000298/2012007-06, "Failure to Incorporate All Design and Technical Data Available into the Operability Determinations for the Standby Liquid Control Tank and Test Tank."

3.6 Inspection of Information Notice 2006-26, "Failure of Magnesium Rotors in MOV Actuators" a. Inspection Scope The team reviewed Information Notice 2006-26, which documented recent failures of motor-operated valve (MOV) actuators as a result of galvanic corrosion, general corrosion, and/or thermally induced stress. These failures highlight vulnerabilities of motor actuators with magnesium rotors, particularly when the motor is located in a high humidity and/or high temperature environment. These motor-operated valve failures illustrate the necessity of adequate inspection and/or preventive maintenance on actuators manufactured with magnesium rotors. The team reviewed current inspection work orders instructions and inspection documentation for inspections performed.

b. Findings No findings were identified .

.4 Results of Reviews for Operator Actions:

information contained in the licensee's probabilistic risk assessment. This included, but was not limited to, components and operator actions that had a risk achievement worth f~,...+1"'\1'" I"'tl"'o~+or IQvLVI ~I vC;H,vl fh""lt'""l lll(;(11 hA/1"\

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"""'t--Il.:"1 CUV! o.vl.lVII\:) 1.1 faL \,AV not have written guidance and are not frequently trained on were also considered.

a. Inspection Scope For the review of operator actions, the team observed operators during simulator scenarios associated with the selected components as well as observing simulated actions in the plant.

The selected operator actions were:

Loss of Electrical Power. Open doors for 125V/250V Switchgear A and control panels that don't have open backs. Requirement - Within 30 minutes from time power has been lost.

- 31 - Enclosure

and start Reactor !solation Requirement - Within approximately 10 minutes of High Pressure Core Injection operation.

Restore Service Water cooling to Diesel Generator(s) by starting Service Water pumps in control room or switchgear room. Requirement - Within 5 min.

De-energize Security System Inverter feed from NSPP and place Sever Accident Mitigating Guidelines Diesel Generator in service. Requirement - Within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after start of station blackout.

b. Findings No findings were identified.

40A6 Meetings, Including Exit On April 4, 2012, the team leader presented the preliminary inspection results with Mr. D. Suman, Director of Engineering, and other members of your staff. After additional in-office inspection, a final telephonic exit meeting was conducted on June 8, 2012, with Mr. D. Suman, Director of Engineering, Mr. A. Zaremaba, Director of Nuclear Safety Assurance, and other members of your staff. The licensee acknowledged the findings during each meeting. While some proprietary information was reviewed during this inspection, no proprietary information was included in this report.

40A7 Licensee Identified Violations No findings were identified.

Attachments: Supplemental Information

- 32- Enclosure

POINTS OF CONTACT Licensee personnel A. Alexander, Nuclear Support J. Anderson, Director of Projects J. Austin, Manager, System Engineering Barker, Manager, Engineering Support K. Billesbach, Manager, Materials, Purchasing and Contracts S. Brown, Manager, Planning, Scheduling & Outage D. Buman, Director, Engineering B. Chapin, Assistant Manager, Maintenance L. Dewhirst, Manager, Corrective Actions and Assessment R. Estrada, Manager, Design Engineering M. Ferguson, Manager, Human Resources J. Flaherty, Senior Staff Engineer, Licensing D. Goodman, Asst Manager, Operations B. Hasselbring, Supervisor, Operations Control Room J. Horn, Supervisor, Mechanical Design Engineering K. Kreifels, Assessment Leader, Quality Assurance E. McCutchen, Senior Engineer, Licensing B. Morris, Superintendent, Maintenance Support J. O'Connor, Manager, Maintenance R. Penfield, Manager, Operations R. Schultz, Audit Engineer, Quality Assurance K. Sutton, Manager, Nuclear Engineering K. Tanner, Shift Supervisor, Radiation Protection R. Thacker, Supervisor, Engineering Support M. Van Winkle, Supervisor, Electrical Design D. Van Der Kamp, Manager, Licensing f""\ \1\1 ..... ____ J\ -.."': __ I\Jt _ _ _ _ _ .... T ... _:_: __

u . VVt::1 I 1t::1 , r\\AIII~ IVlalla~t::I, I I allllll~

B. Wolken, Civil Design Engineering A. Zaremba, Director, Nuclear Safety Assurance NRC Personnel C. Henderson, Resident Inspector J. Josey, Senior Resident Inspector

- "I - Attachment

05000298/2012007 -01 NCV Failure to Adequately Analyze Seismic Requirements for Service Water instrument Rack (1 R21.2.5).

05000298/2012007 ~02 NCV Failure to Provide Adequate Resistance Values for the Preventative Maintenance of the Non-Segregated Phase Bus Duct (1R21.2.13).

05000298/2012007 -03 NCV Failure to Address the Design Bases of the Battery Chargers Following Identification of an Undersized Fused Disconnect Switch Connecting the Swing Battery Chargers to the Direct Current (DC) Buses (1 R21.2.14).

05000298/2012007 -04 NCV Failure to Establish a Preventative Maintenance Program for Molded Case Circuit Breakers (1 R21.2.15).

05000298/2012007 -05 NCV Failure to Have an Adequate Procedure for Erecting Flood Barriers (1 R21.2.16).

05000298/2012007 -06 NCV Failure to Incorporate all Design and Technical Data Available into the Operability Determinations for the Standby Liquid Control Tank and Test Tank (1 R21.3.5).

LIST OF DOCUMENTS REViEWED Calculations NUMBER TITLE REVISION/DATE 0640012-X-226 HPCI Suction Piping from Penetration X226 o 10-073 Evaluation of eNS Externai Fiood Barriers o 92-050K HPCI-LSO 74 AlB, HPCI 75 AlB Setpoints June 26, 1998 Burns & Roe Calculation Intake Structure, Substructure April 6, 1970 Civil Structural Book No.

Burns & Roe Calculation NPPD - Intake Structure - Barge Impact April 15, 1970 Civil Structural Book No. Study and Fendering System

Burns & Roe Calculation Reactor Building Miscellaneous Items - February 13, 1970 Civil Structural Book No. Standby Liquid Control Tank and Pump Pg. 51 35 & 52 Calculation Shock Load Analysis of 28 EXL - 1 Stage 681 H0441 Byron Jackson VCT 1\ "'", __ h.,...,.... __ +

"

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Calculations

- Shock Load Analysis NEDC 00-003 Aux Power System Load Flow and 7 Voltage Analysis NEDC 00-003 Auxiliary Power System Load Flow and 7 Voltage Analysis, NEDC 12-015 Standby Liquid Control Test Tank Seismic o Evaluation NEDC 12-017 Standby Liquid Control Storage Tank Seismic o Evaluation NEDC 86-105B CNS Critical AC Bus Coordination Study 8 NEDC 86-105B Critical AC Bus Coordination Study, 8 NEDC 86-105B 480 V Coordination 8 NEDC 86-105E AC Short Circuit Study 2 NEDC 86-105F Non-Critical AC Bus Coordination 6 NEDC 87-131 B 250 VDC Division II Load and Voltage Study 11 NEDC 87-131B 250 VDC Division II Load and Voltage Study 11 NEDC 87-131 B 250 VDC Div II Load and Voltage Study 11 NEDC 87-131D 125 VDC Division II Load and Voltage Study 12 NEDC 87-131D 125 VDC Division II Load and Voltage Study 12 NEDC 87-140 Anchor Bolt Load Calc. For 5000 PSI 4 Concrete NEDC 87-221 125 Volt Battery Racks and Battery Charger 1 Mounting Calculations DC Electrical/Control Building NEDC 88-086B Second Level Under Voltage Relay Setpoint 10 NEDC 88-086B Second Level Undervoltage Relay Setpoint 10 NEDC 89-1313 Class IV Service Water Piping Analysis 6 Problem SW-17 NEDC 89-149 Class liN Main Steam Piping Analysis 6 Problem MS-02 NEDC 89-1886 CNS Station Blackout Condensate Inventory 2 NEDC 90-367 NSST Bus Duct Impedance November 30, i 990-3- Attachment

Calculations NUMBER REVISION/DATE 90-368 Duct Impedance 3, 1990 NEDC 90-369 ESST Bus Duct Impedance December 3, 1990 NEDC 91-088C Review of Advent Calc. 96007TR-03 Rev. 2 8 Limiting Component Analysis M014 NEDC 91-088D Review of Advent calculation LCA Calculation 2 96007TR-14 Rev. 0 for HPCI-MOV-M017 and February 23, 1997 HPCI-MOV-M058 NEDC 91-093 5 KV Penetration Short Circuit and Heat Loss NEDC 91-094 125/250 VDC Battery Charger Analysis 5 NEDC 91-190 Short Circuit Withstand Capability, Rev 2, December 1989 Attach K NEDC 91-20 UV DV Relay Settings 0 NEDC 91-208 Review of B&R Timing Relay Setpoint July 9, 1991 Calculation NEDC 91-90 AC Equipment and Cable Short Circuit 2 Withstand Ratings NEDC 91-90 (K) AMH-A.76-250 Switchgear Fault Study December, 1989 NEDC 91-94 125/250 V Battery Charger Analysis 5 NEDC 92-054 Analysis of 24" Torus PurgeNent Duct for 0 Hard Pipe Vent Loading NEDC 92-074 Analysis of New 10" PC Line To Be Used As 0 Part of Hard Pipe Vent Flow Path NEDC 93-104 Emergency Transformer Permissive Relay 5 Setpoint NEDC 95-003 Determination of Allowable Operating 27 Parameters for CNS MOV Program NEDC 95-211 Maximum Valve Accelerations for 89-10 0 Program valves NEDC 98-001 Vortex Limit for the ECSTs A and B, 2 NEDC 99-043 Evaluation of 125V DC and 250V DC Racks 7 for CEO 1999-0121 and CEO 1999-012 NEDC-12-020 Service Water Instrument Rack Temporary 0 Post Braces Seismic/Barge Impact Evaluation-4- Attachment

CR-CNS-2006-05366 2-00059 CR-CNS-2012-01665 CR-CNS-2006-09304 CR-CNS-2012-00276 CR-CNS-2012-01694 CR-CNS-2006-10123 CR-CNS-2012-01104 CR-CNS-2012-01902 CR-CNS-2007 -04 765 CR-CNS-2012-01179 CR-CNS-2012-01918 CR-CNS-2007 -04977 CR-CNS-2012-01214 CR-CNS-2012-01920 CR-CNS-2008-06389 CR-CNS-2012-01232 CR-CNS-2012-01930 CR-JAF-2009-02647 CR-CNS-2012-01306 CR-CNS-2012-01933 CR-CNS-2009-09052 CR-CNS-2012-01308 CR-CNS-2012-01939 CR-CNS-2009-10139 CR-CNS-2012-01310 CR-CNS-2012-01962 CR-CNS-2009-10691 CR-CNS-2012-01326 CR-CNS-2012-01963 CR-CNS-2010-00897 CR-CNS-2012-01563 CR-CNS-2012-01971 CR-CNS-2010-03042 CR-CNS-2012-01566 CR-CNS-2012-01972 CR-CNS-2010-08749 CR-CNS-2012-01587 CR-CNS-2012-01974 CR-CNS-2010-08882 CR-CNS-2012-01588 CR-CNS-2012-01982 CR-CNS-2011-00756 CR-CNS-2012-01594 CR-CNS-2012-01994 CR-CNS-2011-07572 CR-CNS-2012-01611 CR-CNS-2012-02001 CR-CNS-2011-07573 CR-CNS-2012-01647 CR-CNS-2012-02002 CR-CNS-2011-08360 CR-CNS-2012-01649 CR-CNS-2012-02006 rO_rl\.iC:_ 'J1i11_IiQAIit:; ("'o_r1\.1 c:_ 'J1i1 ,)J11 t:;;:;;1i rOJ'I\.IC:_ ')1i1 ,)Ji,)"~"~;:;;

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CR-CNS-2011-09095 CR-CNS-2012-01651 CR-CNS-2012-02358 rDJ't...IC:_'?1i11_1IiOIiA

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'-'1'- .....", .. \oJ '-OJ I..c;., v&...vvv CR-CNS- 2012-02376 Condition Reports Generated During this Inspection CR-CNS-2012-01566 CR-CNS-2012-01649 CR-CNS-2012-01971 CR-CNS-2012-01587 CR-CNS-2012-01930 CR-CNS-2012-01972 CR-CNS-2012-01588 CR-CNS-2012-01963 CR-CNS-2012-01982 CR-CNS-2012-01594 Design Basis Documents NUMBER REViSiONiDATE DCD-01 Emergency Diesel Generator March 30, 2011-5- Attachment

Pressure 30,2011 Appendix B DCD-04 April 1, 1 DCD-05 EEDC February 2, 2009 DCD-13, Residual Heat Removal System (RHR) April 1 ,2011 B

DCD-35 Station Blackout February 2, 2009 Drawings NUMBER TITLE REVISIONIDATE E50i Sh 44B RHR-MOV-M016B Minimum Flow Bypass, RHR Pump N01 Band D 791 E261 Sh 7 Residual Heat Removal System - Relay Logic Circuit B 20 791 E261 Sh 8 Residual Heat Removal System 23 Sh 32A HPCi-MOV-M014 Steam Supply to HPCI Turbine N01 E50i Sh 33A HPCI-MOV-M058 HPCI Pump Suction From N01 Suppression Pool M08515 "L" Two Step EP3 Racks N03 M-9315 Battery Arrangement 2 Step EP 3 (2) Sets of (58) LCR- 1 25 Cells 3006 Sh 5 Auxiliary One Line Diagram Starter Racks LZ and TZ, N75 MCC's K, L, LX, RA, RX, S, T, TX, X 3007 Sh 6 Auxiliary One Line Diagram Motor Control Centers N83 r.

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D DD ;;> V I""\., !"'\u, Ut I 85B-70008 Sh Motor Control Center Y N06 128 E 150 Sh 22 Relay Settings for Nutherm DC Starter Overload Relays N02 3001 Main One Line Diagram, N19 3002 One Lines (Bus 1F, !G, 480 V Bus 1A, 1B, 1E, MCC Z) N47 3003 MCC One Lines (A,B,F,G) N47 3004 MCC One Lines (C,D,H,J,DG1, DG2) N22 3005 MCC One Lines (M,N,P,U,V,W) N60 3006 Starter and MCC One Lines - MCC-TX N75 3007 MCC One Lines (E,Q,R,B,Y) N83-6- Attachment

REVISION/DATE 3008 N20 3009 SH1 12.5 kV Ring Bus One Line N44 3010 SH1 Vital Power One Line N75 3010 SH2 Critical Distribution Panel CDPiA N08 3010SH15 RPS Power Panel Load and Fuse N12 3058 DC One Line N56 3059 SH1 DC Panels N39 3059 SH13 125 V Load and Fuse Lists N02 NC66688 345 kV Switchyard One Line Switching Diagram 15 NC66688 345 kV Switchyard One Line Switching Diagram 16 Burns & Roe Primary Containment Cooling & Nitrogen Integrating N78 2022 System Corp. Suction Hydraulic Trip May 23,1983 800315C Terry Corp. Assembly of Hydraulic Trip February 16, 1982 8002680 Terry Corp. Oil Relay Assembly- Remote Servo March 27,1968 0-6252 Terry' Corp. Governor Control System January 20, 1969 C-934-X Terry Corp. Lever Diagram September 13, 1968 Q1nA,)Y L.J I v-r &-1 '\.

Engineering Reports NUMBER REVISION/DATE EE 06-014 Design Basis Stroke Time Requirements for Various o Power Operated Valves 250Vdc Load and Voltage Study 11 Final Report for Reactor Torus IWE Inspection and January 2005 Corrosion Repair Final Report for Reactor Torus IWE Inspection and April 2008 Corrosion Repair

"7

- I -

NPPD # 4170660 NPPD # 4639052 # 4744583 # 4803046

1. 4192567 NPPD # 4664076 NPPD#4746115 # 4803099 NPPD # 4229616 NPPD # 4664077 NPPD # 4748522 NPPD # 4803367 NPPD # 4289552 NPPD # 4664310 NPPD # 4748527 NPPD # 4803463 NPPD # 4336934 NPPD # 4694669 NPPD # 4749938 NPPD # 4811307 NPPD # 4385313 NPPD # 4702575 NPPD # 4750079 NPPD # 4811310 NPPD # 4441737 NPPD # 4704711 NPPD # 4750080 NPPD # 4812188 NPPD # 4497165 NPPD # 4721931 NPPD # 4753138 NPPD # 4813493 NPPD # 4523336 NPPD # 4723658 NPPD # 4754502 NPPD # 4846462 NPPD # 4561338 NPPD # 4726461 NPPD # 4754509 NPPD # 4848232 NPPD # 4581527 NPPD # 4734975 NPPD # 4754892 NPPD # 4849589 NPPD # 4623906 NPPD # 4734976 NPPD # 4754899 NPPD # 4874132 NPPD # 4625263 NPPD # 4738272 NPPD # 4755012 NPPD # 4878634 NPPD # 4662871 NPPD # 4743377 Procedures NUMBER TITLE REVI SION/DATE 2.2.13 345 and 161 kV Power System 32 2.2.18 Aux Power Distribution System 145 2.2.20 Standby AC Power System (DG) 82 2.2.99 Supplemental DG 1 3.47.25 Non-EQ inaccessible Power Cables Program DRAFT 5.3 EOP Station Blackout March 2, 2012 5.9SAMG Severe Accident Management guidance 6 6.2EE.602 Div 2 125V/250V Station battery 92 Day Check 4 6.EE.601 125V/250V Station and Diesel fire Pump Battery 7 Day 20 Check 6.EE.607 125V Station Battery Performance Discharge Test 16 6.EE.609 125V/250V Station Battery Intercell Connection Testing 16 6.EE.609, Att. 125V/250V Station Battery Intercell Connection Testing 15 1* nn _. 4R

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'2 6.EE.611 125V/250V Battery Cell and Rack Examination -..J-8- Attachment

Procedures REVISION/DATE Operations Logs, Attachment 11 110 7.3.1.6 125/250 VDC Station Battery Charger Protective Relays 17 Testing and Calibration and Testing 13 Motor Control Center Examination and Maintenance 17 7.3.14 Thermal Examination of Plant Components 7 7.3.2.4 Molded Case Circuit Breaker Maintenance and Testing, o MCC LlC2B and MCC T/C3C 7.3.41 Examination and Meggering of Non-Seg Bus 7 Alarm Proc. Alarm (Response) Procedure 28 2.3 C4 Alarm Proc. Annunciator Response Procedure 28 2.3 C-4 Alarm Proc. CNS Operations Manual Panel 9-3, Annunciator 9-3-2 September 15, 2011 2.3_9-3-2 CNS 0.16 Control of Doors 47 CNS 0.27.1 Periodic Structural Inspections of Structures 4 CNS 2.1.11.1 Turbine Building Data 126 CNS 2.2.3.1 Traveling Screen, Screen Wash, and Sparger System 83 CNS 3.40 Primary Containment Leakage Rate Testing Program 9 C~JS 5.1 Emergency Procedure F!ood 11 CNS 6.PC.504 Primary Containment Integrated Leak Rate Test 3

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CNS 6.PC.504 Primary Containment Leak Test December 6, 1998 CNS 6.PC.504 Primary Containment Leak Test November 28, 1998 CNS 6.PC.506 Primary Containment Local Leak Rate Test February 8, 2012 CNS 6. PC.506 Primary Containment Local Leak Rate Test January 19, 2012 CNS 6.PC.522 Standby Nitrogen Injection and PC Purge and Vent January 4, 2012 System Local Leak Rate Tests CNS 6.PC.530 Primary Containment Integrated Leak Rate Test 2 CNS 6.PC.530 Primary Containment Leak Test October 24, 1998 CNS 6.PC.531 Primary Containment Integrated Leak Rate Test 4 CNS 6.PC.532 Primary Containment Integrated Leak Rate Test 3 C2 9- Attachment

CNS 6.SC.501 Secondary Containment Leak Test 21 CNS 6.SC.501 Secondary Containment Leak Test 24 CNS 6.SC.501 Secondary Containment Leak Test October 21, 2009 CNS 6.SC.501 Secondary Containment Leak Test April 23, 2008 CNS 6.SC.501 Secondary Containment Leak Test April 2, 2011 CNS 7.0.11 Flood Control Barriers 24 CNS 7.0.11 Flood Control Barriers 25 EN-DC-329 Engineering Programs Control and Oversight 4 CO EOPiA RPV Control 16 EOP3A Primary Containment Control 15 EOP 5.3 AL T Strategy 15 EOP 5.3 Station Blackout 29 EOP 5.3SBO Station Blackout 21 EOP 5.4FiRE- Fire Induced Shutdown From Outside Control Room 38 SID EOP 5.4POST- Post-Fire Operational Information 37 FIRE EOP 5.7 Attachment 1, RPV Flooding (Failure-to-Scram) (7B) 15 EOP 5.8 Attachment 1, Reactor Power (Failure-to-Scram) (6A) 14 EOP 5.8 Attachment 1, Emergency RPV Depression (Faiiure-to- 16 Scram) (6B)

EOP 5.8 Attachment 1, RPV Level (Failure-to-Scram) (7 A) 15 EOP 5.8 Attachment 1, RPV Flooding (2B) 15 EOP 5.8 Attachment 1, Primary Containment Control (3A) 14 EOP 5.8 Attachment 1, Secondary Containment Control/ 15 Radioactive Release Control (5A)

EOP 5.8 RPV Control (iA) 16 EOP 5.8 Emergency RPV Depressurization/Steam Cooling (2A) 15 EOP 5.8.18 Primary Containment Venting for PCPL, PSP, or Primary November 26,2008 Containment Flooding EOP 5.8.18 Primary Containment Venting For PCPL, PSP, or 31

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NUMBER Primary 7 EOP 5.8.18 Primary Containment for Primary Containment Pressure November 26, 2008 Limit, Pressure Suppression Pool, or Primary Containment Flooding EOP 5.8.22 PC Venting and Hydrogen Control September 22, 2011 EOP 5.8.22 Attachment 1, RPV Flooding (Failure-to-Flood) 15 EOP 5.8.22 PC Venting and Hydrogen Control (Greater Than September 22, 2011 Combustible Limits)

EOP 5.8.4 Alternate Injection Subsystems (Table 4) 16 EOP 5.8.4 Alternate Injection Subsystems (Table 4) 16 EP5.3 Alternate Core Cooling Mitigating Strategies February 28,2012 Alternate Strategy SOP 2.2.69 Residual Heat Removal System 90 SOP 2.2.92 Standby Nitrogen injection System April 25, 2011 System Standby Nitrogen Inspection System April 25, 2011 Operations Procedure 2.2.9.2 Systems High Pressure Coolant Injection System April 23, 2011 Operations Procedure 2.2.33 TPP 201 Licensed Personnel Qualification Program 58 Surveillances NUMBER TITLE REVISIONIDATE 6.1 EE.303 Emergency BU Undervoltage (27) relays Testing DC Alt April 9, 2011 Batt (Div 1)

6.1 EE.604 125V Battery Charger Performance Test (DIV 2) February 8, 2011 6.2 EE.303 Emergency Undervoltage (27) relays Testing DC Alt Batt May 7,2009 (Div 2)

CNS 6.PC.504 Primary Containment Leak Test November 21, 1998 CNS 6.PC.504 Primary Containment Leak Test December 6, 1998 CNS 6.PC.504 Primary Containment Leak Test November 28, 1998

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A A I I - Attachment

6, Containment Local Leak Rate Test 8,2012 CNS 6.PC.506 Primary Containment Local Leak Rate Test January 19, 2012 CNS 6. Standby Nitrogen Injection and Purge Vent January 4, 2012 System Local Leak Rate Tests CNS 6.PC.530 Primary Containment Leak Test October 24, 1998 CNS 6.SC.501 Secondary Containment Leak Test October 21, 2009 CNS 6.SC.50i Secondary Containment Leak Test April 23, 2008 CNS 6.SC.50i Secondary Containment Leak Test April 2, 2011 System Health Notebooks NUMBER REVISION/DATE DG_001 Diesel Generator System January 2012 EE-AC_001 AC Power Systems January 2012 EE-DC 001 DC Power Systems January 2012 EE-SY_001 Switchyard January 2012 Miscellaneous NUMBER TITLE REVISIONIDATE 098 (122) Training Qualification Description Appendix J 1 Engineer/Coordinator Amendment Additional Extension of Appendix J, Type A, Ingrated 19 224 Leakage Rate Test 8.1.36 License Renewa! Application, Structures Monitoring March 1972 Structures Monitoring inspection Checklists for Containment NRC Commitment 720309-01, FSAR Amendment 9 C&D Subject: Cracks Next to Positive Posts on CNS 125 V November 16, 2005 Technologies DC 1 B Battery Letter C&D Subject: Technical Specification Limits for Operability, May 1, 1997 Technologies Intercell Connection Resistance 125 Volt and 250 Volt Letter LCR-25 Batteries C&D Pilot Cell Recommendations March 20, 2012 Technologies Letter C&D Pilot Cell Recommendations March 21, 2012 Technologies

'12 - Attachment

NUMBER REVISION/DATE CED6025080 Replacement of RHR SWBP Motors CNSS915709 MCCB Testing August 19, 1991 CR-2005-9378 Battery Charger Fuses CR-2011- Bus Duct Resistance Testing 11750 DC-91-041 Torus Hard Vent Pipe Vent December 10,1992 MOV Program, Health Report Summary 4th Ouarter 2011 EPRI TR- Stationary Battery Guide: Design, Application, and 2 100248, pg 11- Maintenance 3 only Excel Data for Opening/Closing Thrust graphs for date range 5/31/1993 HPC!-M014 through 5/4/2008 Excel Data for Opening/Closing Thrust graphs for date range 1213/1991 HPCI-M058 through 10/8/2009 Excel Data for Stroke Times (Open and Close) for date range RHR-M016B 1/13/2009 through 1/17/2012 Excel Data for Opening/Closing Thrust graphs for date range RHR-M016B 10/23/1991 through 10/18/2007 GL 2006-02 Offsite Power Reliability GL 2007-01 Inaccessible Power Cables IN 2010-26 Submerged Cables lOA Interface Operating 1i1~greement 4 Lesson Plan Operations Containment, Rev 28 28 COR 002-03-

NEMAAB4 MCCB Maintenance NUC-001-02 Nuclear Plant Interface OE-30458 HPCI Governor Valve Failure to Stroke January 29, 2010 SOER 10-01 Power Transformers TOD Number Maintenance OSC Pool Personnel 2 0655; SAP Number 98 VM0001188 C&D Batteries and Chargers 10 A"l

- Iv- Attachment

NUMBER REVISION/DATE VMOO021 Supplemental 2 VM-0986 Limitorque Composite Manual 27 VM-1040 Westinghouse Electric Corp. ITEM Motor Control 19 Centers QA Audits NUMBER TITLE REVISION/DATE 12-01 QA Engineering Audit 10-01 QA Engineering Audit June 3,2010 10-04 QA Audit Operations and Technical Support October 11, 2010

- 14- Attachment