IR 05000445/2013007

IR 05000445-13-007; 05000446-13-007; 05/20/2013 - 06/20/2013; Comanche Peak Nuclear Power Plant, Units 1 and 2: Baseline Inspection, NRC Inspection Procedure 71111.21, Component Design Basis Inspection.

ML13214A346
Person / Time
Site:	Comanche Peak
Issue date:	08/02/2013
From:	Thomas Farnholtz Division of Reactor Safety IV
To:	Flores R Luminant Generation Co
References
IR-13-007
Download: ML13214A346 (67)

Text

UNITE D S TATE S NUC LEAR RE GULATOR Y C OMMI S SI ON ust 2, 2013

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT, UNIT 1 AND UNIT 2 - NRC COMPONENT DESIGN BASES INSPECTION, NRC INSPECTION REPORT 05000445; 05000446/2013007

Dear Mr. Flores:

On June 20, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Comanche Peak Nuclear Power Plant, Units 1 and 2. The enclosed report documents our inspection results, which were discussed on June 20, 2013, with Mr. Flores, Senior Vice President and Chief Nuclear Officer, 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 inspectors reviewed selected procedures and records, observed activities, and interviewed cognizant plant personnel.

Eleven NRC identified findings were identified during this inspection. Ten of the findings were determined to have very low safety significance (Green). One of the findings was determined to be a Severity Level IV violation. All of the findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Comanche Peak Nuclear Power Plant, Units 1 and 2. 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, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at Comanche Peak Nuclear Power Plant, Units 1 and 2.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Thomas R. Farnholtz, Branch Chief Engineering Branch One Division of Reactor Safety Dockets: 05000445; 05000446 Licenses: NPF-87; NPF-89 Enclosure: Inspection Report 05000445; 05000446/2013007 w/ Attachment: Supplemental Information cc w/ encl:

Electronic Distribution for Comanche Peak Nuclear Power Plant

SUMMARY OF FINDINGS

IR 05000445; 05000446/2013007; 05/20/2013 - 06/20/2013; Comanche Peak Nuclear Power

Plant, Units 1 and 2: baseline inspection, NRC Inspection Procedure 71111.21, Component Design Basis Inspection.

The report covers an announced inspection by a team of five regional inspectors and two contractors. Eleven NRC identified findings were identified during this inspection. Ten of the findings were determined to have very low safety significance (Green). One of the findings was determined to be a Severity Level IV violation. 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.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, that states, in part, applicable regulatory requirements and design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, prior to June 5, 2013, the licensee did not establish that the minimum switchyard voltages established in station procedures were adequate to prevent undesired actuation of the undervoltage protection scheme. This condition resulted from an inadequate analysis of undervoltage relay setpoints in design calculations, and the failure to provide acceptance criteria for undervoltage relay reset setpoints in relay calibration procedures. The finding was entered into the licensees corrective action program as Condition Report CR-2013-006176.

The inspectors determined that the failure to properly analyze minimum switchyard voltage requirements, and control relay setpoints necessary to maintain the availability of offsite power was a performance deficiency. The performance deficiency is more-than-minor because it was associated with Reactor Safety, Mitigating Systems Cornerstone,

Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, at the minimum switchyard voltages established in station procedures, actuation of the undervoltage protection scheme could have occurred and removed the reliable offsite power sources during an accident. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. The finding had a cross-cutting aspect in the Area of Problem Identification and Resolution, associated with the Operating Experience Component, since the issues noted in this finding were discussed in Regulatory Issue Summary (RIS) 2011-12, Adequacy of Station Electric Distribution System Voltages, and RIS 2011-12 was reviewed by the licensee as part of the self assessment conducted in February 2013. P.2(b) (1R21.2.1)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, that states, in part, applicable regulatory requirements and design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, prior to June 20, 2013, the 125 VDC calculation did not take into account the maximum inrush currents and actual accident loading, and the 120 VAC calculation did not properly account for low voltage when the buses are supplied from their alternate source. The finding was entered into the licensees corrective action program as Condition Report CR-2013-006273 and CR-2013-006396.

The inspectors determined that the failure to perform accurate voltage calculations for the 125 VDC system and 120 VAC bus was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety,

Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the 125 VDC calculation did not take into account the maximum inrush currents and actual accident loading, and the 120 VAC calculation did not properly account for low voltage when the buses are supplied from their alternate source. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green)safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. (1R21.2.2)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR 50.65(a)(1),

Requirements for monitoring the effectiveness of maintenance at nuclear power plants, that states, in part, that the licensee shall monitor the performance or condition of structures, systems, or components, against licensee established goals, in a manner sufficient to provide reasonable assurance that these structures, systems, and components are capable of fulfilling their intended functions. Specifically, on July 26, 2012, the licensee failed to establish goals and monitor the performance of the alternate power diesel generator system to ensure the system is capable of providing the necessary electric power onto the emergency buses. The finding was entered into the licensees corrective action program as Condition Report CR-2013-006521.

The inspectors determined that the failure to follow procedure to establish performance goals while performing Maintenance Rule (a)(1) monitoring to ensure the APDG system is capable and tested to meet the design basis requirements, was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Equipment Performance attribute and adversely affected the cornerstone objective to ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the procedure directs the licensee to establish performance goals on activities that address conditions which were determined to be classified as (a)(1). In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating System Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality.

This finding had a cross-cutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that emergency equipment is adequate and available to assure nuclear safety. H.2(d) (1R21.2.3)

• SLIV. The inspectors identified a Severity level IV, non-cited violation of 10 CFR 50.71(e)(4), requires the UFSAR be updated, at intervals not exceeding 24 months, and states in part, the revisions must reflect all changes made in the facility or procedures described in the UFSAR. Specifically, prior to June 20, 2013, the inspectors identified the alternate power diesel generator system was not described in sufficient detail in the FSAR as required. This finding was entered into the licensees corrective action program as Condition Report CR-2013-006256.

The inspectors determined that the failure to update the Final Safety Analysis Report to include the description of the APDG system in section 8.3.1 AC Power Systems was a performance deficiency. The issue is a performance deficiency because it was a failure to meet requirement, 10 CFR 50.71(e)(4), and it was within the licensees ability to correct the problem. Using Inspection Manual Chapter 0612, Appendix B, the performance deficiency was assessed through both the Reactor Oversight Process and traditional enforcement because the finding had the potential for impacting the NRCs ability to perform its regulatory function. The finding resulted in a minor performance deficiency. For traditional enforcement, the inspectors used the Enforcement Policy, in accordance with Section 6.1.d.3, and determined the violation to be a Severity Level IV, non-cited violation, because the licensee failed to update the UFSAR as required by 10 CFR 50.71(e)(4), but the lack of up-to-date information had not resulted in any unacceptable change to the facility or procedures. This violation did not have a cross-cutting aspect. (1R21.2.3)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, that states, in part, measures 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 May 20, 2013, the licensee failed to assess the adverse effects of 6.9kV and 480V system harmonics on the degraded voltage relays. The finding was entered into the licensees corrective action program as Condition Report CR-2013-006230.

The inspectors determined that the failure to analyze the effect of electrical system harmonics on the degraded voltage relays was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to analyze the effect of electrical system harmonics on the degraded voltage relays could cause the relays to fail to actuate at the setpoint specified in Technical Specifications. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was a deficiency affecting the design or qualification that did not result in the safety-related equipment losing operability or functionality. This finding did not have a crosscutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. (1R21.2.5)

Green.

The inspectors identified a Green, non-cited violation, with three examples, of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, that states, in part, Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings and shall be accomplished in accordance with these instructions, procedures, or drawings. Specifically, for example 1 on February 28, 2013, for example 2 on June 5, 2013 and for example 3 on June 8, 2013, the licensee failed to follow procedure STI-442.01, Operability Determination and Functionality Assessment Program, Revision 1, Attachment 8.B page 3 of 5 which states, in part,

Identify the topics that are applicable to the quick technical evaluation and include information for applicable topics within the evaluation such as: for example 1, The effect or potential effect of the degraded or nonconforming condition on the affected SSCs ability to perform its specified safety function, or for example 2, Compensatory Measures are recommended, or for example 3, Whether there is reasonable expectation of operability, including the basis for the determination. The finding was entered into the licensee's corrective action program as Condition Report CR-2013-006599.

The inspectors determined that the failure to perform adequate operability assessments was a performance deficiency. The performance deficiency is more-than-minor because:

Example 1: It was associated with the Reactor Safety, Barrier Integrity Cornerstone,

Configuration Control attribute and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, shutting off of the containment spray pumps during a large break LOCA inside containment would allow containment pressure to increase. Using Inspection Manual Chapter 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power,

Exhibit 3, the inspectors determined the finding was of very low (Green) safety significance because it did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components or actual reduction in function of hydrogen igniters in the reactor containment.

Example 2: It was associated with the Reactor Safety, Mitigating Systems Cornerstone,

Equipment Performance attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the compensatory measures established in the first operability assessment did not ensure that offsite power would be maintained at minimum grid voltage.

Example 3: It was associated with the Reactor Safety, Mitigating Systems Cornerstone,

Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the operability assessment initially credited the use of the battery chargers after the emergency diesel generators restored power to the bus, without evaluating design basis for the battery chargers.

For examples 2 and 3, the inspectors used Inspection Manual Chapter 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power,

Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because these examples were a deficiency affecting the design or qualification that did not result in losing operability or functionality.

This finding had a cross-cutting aspect in the area of human performance associated with the decision making component because the licensee failed in all three examples to conduct an effectiveness review of a safety-significant decision to verify the validity of the underlying assumptions to identify possible unintended consequences during the original operability assessments. H.1(b) (1R21.2.5)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, 10 CFR Part 50, Appendix B, Criterion XI, "Test Control," that states, in part, A test 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 the requirements and acceptance limits contained in applicable design documents. Specifically, since 2001, the licensee failed to provide appropriate acceptance criteria and testing procedure instructions during modified performance tests involving Class 1E batteries for the 1-minute critical period testing data which incorporated the requirements of IEEE Standard 450-1995 to ensure the battery would meet the required design voltage for the duty cycle. The finding was entered into the licensees corrective action program as Condition Report CR-2013-005673.

The inspectors determined that the failure to provide appropriate acceptance criteria and testing procedure instructions involving Class 1E batteries for the 1-minute critical period testing data during modified performance tests was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Procedure Quality attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, Procedure MSE-S0-5715 does not direct the technicians to record and evaluate the voltage at the end of the 1-minute critical period to ensure it does not drop below the designed minimum voltage, which would indicate the battery would not be capable of meeting the required design function. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green)safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because Calculation EE-CA-0000-5121 was implemented in 2001 and did not reflect current licensee performance. (1R21.2.8)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XI, "Test Control," that states, in part, A test 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 the requirements and acceptance limits contained in applicable design documents.

Specifically, since 1994, the licensee failed to recognize that if the safety-related chilled water pumps were degraded to 90 percent of their reference value, as permitted by IST Procedures OPT-209A/B, the system may not be able to achieve the required design flowrates as stated in Calculation 1-EB-311-8. This finding was entered into the licensees corrective action program as Condition Report CR-2013-006252.

The inspectors determined that the failure to ensure appropriate acceptance criteria were incorporated into test procedures for the safety chill water pumps was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to recognize that if the safety-related chilled water pumps were degraded to 90 percent of their reference value, as permitted by IST Procedures OPT-209A/B, the system may not be able to achieve the required design flowrates as stated in Calculation 1-EB-311-8. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because Calculation 1-EB-311-8 was updated in 1994 to incorporate the uninterruptible power system fan coil units and did not reflect current licensee performance. (1R21.2.16)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, that states, in part, measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Specifically, prior to June 17, 2013, the licensee failed to establish an activity to identify fouling of the Unit 1 emergency diesel generator building exhaust ventilation screens. The finding was entered into the licensee's corrective action program as Condition Report CR-2013-006540.

The inspectors determined that the failure to identify fouling on the Unit 1 emergency diesel generator building exhaust ventilation screens was a performance deficiency.

The performance deficiency is more-than-minor because it had the potential to lead to a more significant safety concern. Specifically, the Unit 1 emergency diesel generator rooms could have insufficient exhaust flow to meet design basis temperature requirements if left uncorrected. Using Inspection Manual Chapter 0609, Appendix A,

The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the emergency diesel generators losing operability or functionality. This finding did not have a crosscutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. (1R21.2.17)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, states, in part, measures shall be establish to assure that the design basis for systems, structures, and components are correctly translated into specifications, drawings, procedures and instructions. Specifically, since 2006 and 2007, the licensee failed to appropriately incorporate the RWST vortexing design calculations 6 percent indicated level into the emergency operating procedures for switching containment spray pump suction from the RWST to the containment sump to prevent damage to the pumps. The finding was entered into the licensees corrective action program as Condition Report CR-2013-005739.

The inspectors determined that the failure to appropriately incorporate the RWST vortexing design calculations 6 percent indicated level into the emergency operating procedures for switching containment spray pump suction from the RWST to the containment sump to prevent damage to the pumps was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Procedure Quality attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, Emergency Operating Procedure EOS-1.3A/B allowed the operators the ability to delay transfer of containment spray pump suction source which could have caused damage to the pumps due to vortexing. Using Inspection Manual Chapter 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power,

Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because the change to the procedure due to the addition of the sump strainers occurred in 2006 and 2007, and did not reflect current licensee performance. (1R21.4)

Green.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, states, in part, measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Specifically, since May 2010, the licensee failed to correct a condition adverse to quality in a timely manner that involved updating design basis calculations for safety-related equipment to include the allowed technical specification frequency range of +/- 2 percent for the emergency diesel generators. The finding was entered into the licensee's corrective action program as Condition Report CR-2013-006604.

The inspectors determined that the failure to correct a condition adverse to quality in a timely manner that involved updating design basis calculations for safety-related equipment to include the allowed technical specification frequency range of +/- 2 percent for the emergency diesel generators was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety,

Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the calculations to support safety-related equipment did not include allowed technical specification frequency range for the emergency diesel generators to ensure the equipment would be capable of performing their safety-related functions. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was a deficiency affecting the design or qualification that did not result in the safety-related equipment losing operability or functionality. This finding had 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 updating design basis calculations to include technical specification allowed emergency diesel generator frequency range in a timely manner, commensurate with their safety significance. P.1(d) (4OA2)

Licensee-Identified Violations

No findings were identified.

REPORT DETAILS

REACTOR SAFETY

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

To assess the ability of the Comanche Peak Nuclear Power Plant, Units 1 and 2, equipment and operators to perform their required safety functions, the team inspected risk significant components and the licensees responses to industry operating experience. The team selected risk significant components for review using information contained in the Comanche Peak Nuclear Power Plant, Units 1 and 2, probabilistic risk assessment and the U. S. Nuclear Regulatory Commissions (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, or a Birnbaum value greater than 1E-6. 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 calculations 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; 10 CFR 50.65(a)1 status; operable, but degraded conditions; NRC resident inspector input of problem equipment; system health reports; industry operating experience; and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in-depth margins.

The inspection procedure requires a review of 15 to 25 total samples that include risk-significant and low design margin components, containment-related components, and operating experience issues. The sample selection for this inspection was 22 components, 3 of which are containment-related, and 3 operating experience items.

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 and safety-related 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 offsite power available. As such the team selected:

• 345 kV Startup Transformer XST2 (CPX-EPTRST-02)

• 125 VDC Switchboard 1ED2 (CP1-EPSWED-02)

• Unit 1 Alternate Power Generators

• Unit 1 Diesel Generator 1-01 Emergency Feeder Breaker (1EG1)

• Unit 1 6.9kV Switchgear 1EA2 (CP1-EPSWEA-02)

• Unit 2 Emergency Diesel Generator Sequencers

• Unit 2 Containment Electrical Penetrations

• Unit 1 Class 1E Battery BT1ED2 (CP1-EPSWED-02)b. Mitigating systems needed to attain safe shutdown: The team reviewed components and supporting equipment required to perform the safe shutdown of the plant. As such the team selected:

• Unit 1 Containment Equipment Hatch and Personnel and Emergency Airlocks

• Unit 1 Containment Purge Valves (1-HV-5536, 5537, 5538, 5539)

• Unit 1 Component Cooling Water Surge Tank 1-01 (CP1-CCATST-01)

• Unit 1 Component Cooling Water Recirculation Flow Valve (1-FV-4536)

• Unit 1 Auxiliary Feedwater System Check Valve (1AF-0032)

• Unit 1 Emergency Diesel Generator Exhaust Relief Valve

• Unit 2 Safety-related Chilled Water Recirculation Pump (2-06)

• Unit 2 Emergency Diesel Generator Building Fans

• Unit 2 Safety Injection System Recirculation Sump Isolation Valves (2-8811A/B)

• Unit 2 Residual Heat Removal Pump Mechanical Seal and Breaker Coordination

• Unit 1 Component Cooling Surge Tank Air Operated Fill Valves (1-LV-4500/4501)

.2.1 345 kV Startup Transformer (XST2)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the 345 kV startup transformer, XST2. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• Preventive maintenance schedules and procedures for the transformer

• Load calculations of record and supporting documentation

• Calculations of record for protection settings and alarms

• Completion of last preventive maintenance work orders

• Operating Procedures

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to properly analyze minimum voltage requirements required to maintain the availability of offsite power and the failure to control relay setpoints necessary to maintain the availability of offsite power.

Description.

The safety-related 6.9kV buses can be supplied from either of two separate switchyards, the 138kV switchyard or the 345kV switchyard. The preferred source to Unit 1 is the 345kV switchyard and startup transformer, XST2; the preferred source to Unit 2 is the 138kV switchyard and startup transformer, XST1. Both of the two 6.9kV safety buses and both of the two 480V switchgear buses connected to each of the 6.9kV safety buses are equipped with undervoltage relays that will separate the 6.9kV buses from the offsite power source if the relay voltage and time delay setpoints are exceeded. These relays include the 6.9kV degraded voltage relays, the 480V low grid undervoltage relays, and the 480V degraded voltage relays. Voltage profile calculations EE-VP-U1-1E and EE-VP-U2-1E, show that during accident load sequencing, bus voltage dips below the voltage setpoints of the relays due to the starting of large motors, thereby initiating the time delay relays. If bus voltage does not recover above the reset setpoint of the relays, the time delay relays will time out, activating the load shedding scheme which will separate the 6.9kV safety buses and their associated 480V buses from the offsite power supplies. 10 CFR 50 Appendix A, Criterion 17 requires that provisions be included to minimize the probability of losing offsite power coincident with an accident when power from the generating unit is lost. FSAR 8.2.2 states, in part, that In order to satisfy offsite power requirements, the Transmission Operator should

maintain 345kV grid system voltage at CPNPP switchyard between the voltage range of 340kV to 361kV and 138kV grid system voltage at CPNPP switchyard between the voltage range of 135kV to 144kV. These limits are implemented by station administrative procedure STA-629, Switchyard Control and Transmission Grid Interface. The inspectors noted the following deficiencies with the licensees control of the availability of offsite power:

• Inadequate calculations There was no analysis which demonstrated that the switchyard voltage limits incorporated into Procedure STA-629 were adequate to prevent actuation of the undervoltage protection schemes during accident conditions. Calculation EE-1E-871 analyzed undervoltage relay setpoints, but it did not include an analysis of undervoltage relay reset requirements. Moreover, an informal discussion of reset requirements, in Section 8.1.7a of the calculation, concluded that the 480V low grid undervoltage relays would not reset if system voltage declined to the minimum levels controlled by procedure STA-629, (340kV and 135kV). The failure to reset these relays would result in tripping of the offsite power supplies after their nominal time delay of 54 seconds. Rough calculations by the inspectors confirmed that, based on actual field as-left settings for these relays, and the uncertainties for the relays determined in Calculation EE-1E-00871, the minimum switchyard voltage limits provided in STA-629 were insufficient to prevent disconnecting the 6.9kV safety buses for either Unit experiencing an accident.

• Inadequate procedures to control relay reset setpoints The 6.9kV Degraded Voltage Relays are Model ITE27-H, and feature a reset setpoint which are a fixed (non-adjustable) percentage of the adjustable dropout setpoint. Vendor Instruction Bulletin IB 18.4.7-2 listed the differential voltage as approximately 3 percent. The 480V low grid voltage relays and the 480V degraded voltage relays are Model ITE-27N, and feature a reset setpoint which is an adjustable percentage of the separately adjustable dropout setpoint. The inspectors noted that calibration procedures for these relays did not specify acceptance criteria for the undervoltage relay reset setpoints. As described in the preceding paragraphs, the undervoltage reset value is a key parameter necessary to evaluate and control the availability of the offsite power supply. Specifically, if the reset setpoint is too high, the 6.9kV safety buses could become separated from the offsite power supply at the start of an accident, even if the switchyard voltage remains within its expected values. Therefore, the reset setpoints should be procedurally controlled at a value below the minimum bus recovery voltage under worst case accident loading conditions. A review of actual as-left reset setpoints for the low grid undervoltage relays revealed that the 6.9kV switchgear buses of either unit experiencing an accident could become separated from offsite power, even while the offsite power was within the limits prescribed by STA-629.

In response to the inspectors concerns, the licensee initiated CR-2013-006176, declared the offsite power sources operable but degraded, and entered a compensatory action via EVCR-2013-006176-1. This compensatory action set new minimum switchyard voltage levels of 345kV for the 345kV switchyard, and 137kV for the 138kV switchyard, which

were determined by the licensee to be adequate to prevent spurious separation from the offsite power supplies, considering actual as-left setpoints and instrument uncertainties.

Analysis.

The licensees failure to properly analyze minimum switchyard voltage requirements, and control relay setpoints necessary to maintain the availability of offsite power was a performance deficiency. The performance deficiency is more-than-minor because it was associated with Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, at the minimum switchyard voltages established in station procedures, actuation of the undervoltage protection scheme could have occurred and removed the reliable offsite power sources during an accident. In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating System Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality.

The inspectors determined that this finding had a cross-cutting aspect in the Area of Problem Identification and Resolution, associated with the Operating Experience Component, since the issues noted in this finding were discussed in Regulatory Issue Summary (RIS) 2011-12, Adequacy of Station Electric Distribution System Voltages.

RIS 2011-12 was reviewed by the licensee as part of the self assessment conducted in February 2013. P.2(b)

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, applicable regulatory requirements and design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, prior to June 5, 2013, the licensee did not assure that applicable regulatory requirements and design basis relating to the availability of offsite power were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee did not establish that the minimum switchyard voltages established in station procedures were adequate to prevent undesired actuation of the undervoltage protection scheme. This condition resulted from an inadequate analysis of undervoltage relay setpoints in design calculations, and the failure to provide acceptance criteria for undervoltage relay reset setpoints in relay calibration procedures. The violation did not present an immediate safety concern because the licensee implemented compensatory measures that require the control room operators to verify voltage will not go below the new minimum grid voltage values of 345kV and 137kV, which align with the as-left relay setpoints. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensees corrective action program as Condition Report CR-2013-006176. (NCV 05000445;05000446/2013007-01; Inadequate Calculations and Procedures for Offsite Power Availability)

.2.2 125 VDC Switchboard (1ED2)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, selected drawings, maintenance and test procedures and condition reports associated with the 125 VDC switchboard, 1ED2. The inspectors conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• System design basis document

• Electrical one-line diagrams

• Technical Specifications

• Voltage Drop Calculations

• Breaker/Fuse Coordination Studies

• Maintenance Inspection Procedures

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to perform accurate voltage calculations for the 125 VDC system and 120 VAC bus.

Description.

Example 1: During review of design basis document, DBD-EE-044, DC Power Systems, Revision 25, the minimum voltage for the battery output was assumed to be 105 VDC. This voltage was calculated to be the minimum battery output voltage at the end of the four hour discharge following a loss of all alternating current to the facility.

This minimum battery output voltage was subsequently used in the 125 VDC voltage drop calculations for the direct current system. The inspectors reviewed the voltage drop calculations associated with the 125 VDC system and determined that the calculations used the normal (running) currents instead of the maximum (inrush)currents for the associated components. The inspectors also identified that the voltage drop calculations failed to calculate the worst case combination of 125 VDC loads that would be cycled on during a design basis event. The result of the failure to use the maximum currents and combination of components was a calculated higher voltage drop from the battery to the components being supplied by the battery during design basis events.

Using the worst case combination of system loads during the first minute of a design basis event, and the associated inrush currents of these loads to calculate the voltage drop, the resulting minimum calculated battery voltage required for the direct current system would be 112.5 volts instead of the previously assumed 105 volts. The licensee entered this into their corrective action program as Condition Report CR-2013-006273.

Example 2: The 118 VAC uninterruptible power system supplies critical instrumentation and control circuits from battery powered inverters. There are four Class 1E inverters per train, two for the reactor protection system and the other two for the balance of plant systems. Each inverter is connected independently to one Class 1E distribution panel.

Two sources of backup 120V AC power are also provided to the inverter panels (one source per train). Four of the eight distribution panels are connected to each source.

Each distribution panel can receive power from the 120 VAC backup source under operator control. The backup source for each train consists of a 480/120V transformer connected to a Class 1E 480V Motor Control Center (MCC). The transformers do not have automatic voltage regulation capability, so when connected to the transformer source, the 120 VAC distribution panel voltage will fluctuate with fluctuations on the upstream 480V MCC source.

Branch Technical Position PSB-1, to which the licensee is committed, requires that the setpoints for the degraded voltage relays be determined from an analysis of the voltage requirements of the Class 1E loads at all onsite system distribution levels. The inspectors reviewed voltage calculation EE-1E-1EB4-1, which determined voltage at MCC 1EB4-1, for bypass transformer T1EC4. The inspectors noted that the calculation used an available voltage at the MCC considerably higher (444.96V) than the voltage afforded by the degraded voltage relays (433V) under accident loading conditions.

In response to the inspectors inquiries, the licensee initiated Condition Report CR-2013-006396 and provided preliminary calculations showing that voltage required at the MCCs supplying the bypass transformers was considerably higher than previously analyzed and higher than voltage afforded by the degraded voltage relays.

For instance, the preliminary calculations showed that for Transformer T1EC3, a voltage of 466.32V was required at MCC 1EB3-1 to ensure operability of downstream 120V vital loads during steady state conditions, and 505.32V was required to ensure adequate voltage to loads requiring uninterruptible power during voltage dips associated with the starting of large loads at the start of an accident. Based on these results, CR-2013-06396 concluded that when aligned to the 120 VAC transformer bypass source, the affected 120V vital bus should be considered inoperable, and LCO 3.8.9 action B1 which requires restoration of the vital bus to operable status in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> would be applicable, instead of LCO 3.8.7 which would permit operation of a vital bus on 120 VAC bypass power for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee issued LOCAR TX-130098 to implement this action. A review of operator logs for the past three years showed that there were no instances of a 120V vital bus having been aligned to its alternate transformer source in excess of two hours.

Analysis.

The licensees failure to perform accurate voltage calculations for the 125 VDC system and 120 VAC bus was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the 125 VDC calculation did not take into account the maximum inrush currents and actual accident loading, and the 120 VAC calculation did not properly account for low voltage when the buses are supplied from their alternate source. In accordance with Inspection

Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, determined that finding affected the Mitigating Systems Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance.

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, applicable regulatory requirements and design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, prior to June 20, 2013, the licensee did not assure that applicable regulatory requirements and design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, the 125 VDC calculation did not take into account the maximum inrush currents and actual accident loading, and the 120 VAC calculation did not properly account for low voltage when the buses are supplied from their alternate source. The violation did not present an immediate safety concern because the licensee ensured proper voltage was maintained during the last surveillance test for the 125 VDC system and issued a Standing Order to ensure that if the power is being supplied by the alternate source for the 120 VAC system, they will enter the shorter limiting condition for operation time as if the primary and alternate sources are both not available. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensees corrective action program as Condition Report CR-2013-006273 and CR-2013-006396. (NCV 05000445;05000446/2013007-02; Inadequate Voltage Calculations for the 125 VDC and 120 VAC Buses)

.2.3 Unit 1 Alternate Power Generators

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 alternate power generators. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Design basis documents to determine the required functional capabilities of the system

• Vendor contract test data

• Maintenance activities performed on components to ensure the required power is capable of being delivered to the safety-related buses

• Maintenance Rule scope documents to ensure the system is being properly maintained

b. Findings

===.1

Introduction.

The inspectors identified a Green, non-cited violation of===

10 CFR 50.65(a)(1), for the licensees failure to establish performance goals while performing Maintenance Rule (a)(1) monitoring to ensure the alternate power diesel generator (APDG) system is capable and tested to meet the design basis requirements

Description.

The APDG system is a Non-Class 1E diesel generator package used to supply power to either 6.9kV safeguards bus when required due to loss of offsite power coincident with failure of both class 1E emergency diesel generators. The system consists of three diesel generators connected in parallel to a three-phase transformer, a selectable transfer/disconnect switch, and a Class 1E circuit breaker located in each 6.9kV safeguards bus.

The licensee installed and began crediting the availability of this system in 2012 to reduce the online risk of core damage to the facility. On July 26, 2012, the maintenance rule functions for the system were approved by the Maintenance Rule Review Panel to be added to the scope of Maintenance Rule for monitoring of the APDGs under the Electric Power 6.9kV Switchgear System (EPA). Since performance was not previously monitored, the EPA system for both units were placed into Maintenance Rule monitoring status (a)(1). The licensee established performance criteria for this system, but failed to establish goals, as required by the maintenance rule and licensee procedure STA-744, Maintenance Effectiveness Monitoring Program, Revision 6, step 6.4.1.

The inspectors reviewed the system functions required by the maintenance rule, and compared this function with the design, testing, and maintenance activities for the system. The inspectors identified the following issues associated with the systems ability to perform the required and credited function:

• Acceptance testing conducted at the vendor location did not adequately show that the diesel generator units could provide the necessary power profile as described in the design basis documents. Specifically, the vendor test started a 600kW load at a 1.0 power factor, when the design basis document specified a 1000HP load, which would be approximately a power factor of 0.2.

• The licensee could not produce documentation for performing acceptance testing or maintenance testing of the cables connecting the diesel generator units to the transformer, or between the transformer and transfer/disconnect switches, nor maintenance documents for the transfer/disconnect switches.

• The licensee has not connected the diesel generator units onto either bus, for either unit, to show the system is capable of performing the credited function.

The inspectors reviewed the past six months maintenance activity risk assessments to determine if a change in risk management actions would be warranted if the APDG system had been unavailable due to the lack of testing and maintenance. The inspectors found no instances where a change in risk management actions was warranted. The licensee entered this issue of concern into their corrective action program as Condition Report CR-2013-006521.

Analysis.

The licensees failure to follow procedure to establish performance goals while performing Maintenance Rule (a)(1) monitoring to ensure the APDG system is capable and tested to meet the design basis requirements, was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Equipment Performance attribute and adversely affected the cornerstone objective to ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the procedure directs the licensee to establish performance goals on activities that address conditions which were determined to be classified as (a)(1). In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating System Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality.

This finding had a cross-cutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that emergency equipment is adequate and available to assure nuclear safety. H.2(d)

Enforcement.

10 CFR 50.65(a)(1), Requirements for monitoring the effectiveness of maintenance at nuclear power plants, states, in part, that the licensee shall monitor the performance or condition of structures, systems, or components, against licensee established goals, in a manner sufficient to provide reasonable assurance that these structures, systems, and components are capable of fulfilling their intended functions.

Contrary to the above, on July 26, 2012, the licensee failed to monitor the performance or condition of structures, systems, or components, against licensee established goals, in a manner sufficient to provide reasonable assurance that these structures, systems, and components are capable of fulfilling their intended functions. Specifically, the licensee failed to establish goals and monitor the performance of the alternate power diesel generator system to ensure the system is capable of providing the necessary electric power onto the emergency buses. This violation did not present an immediate safety concern because the licensee has not used the APDGs and plans to monitor them to ensure they are capable of fulfilling their intended functions. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensees corrective action program as Condition Report CR-2013-006521.

(NCV 05000445;05000446/2013007-03; Failure To Establish 10 CFR 50.65(a)(1)

Performance Goals for the APDGs)

===.2

Introduction.

The inspectors identified a Severity level IV, non-cited violation for the===

licensees failure to update the Updated Final Safety Analysis report (UFSAR) in accordance with 10 CFR 50.71(e)(4) to include a description of the alternate power diesel generator system interconnections with the safety-related switchgear in Section 8.3.1.1.

Description.

The inspectors reviewed the UFSAR to verify the alternate power diesel Generator (APDG) system interaction with the safety-related switchgear was appropriately described in UFSAR Section 8.3.1 as required by Regulatory Guide 1.70-1995, Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants LWR Edition. The inspectors identified that Section 8.3.1.1, Description, failed to discuss the APDG system interactions with safety-related equipment. The inspectors also identified that Section 8.3.1.2, Analysis, discussed the use of the APDGs in Modes 5 and 6, but failed to mention their use in Modes 1 through

The licensee made Amendment No. 105 to the UFSAR, but failed to update the appropriate description and include all modes for which the APDG system may be used.

Specifically, the Regulatory Guide states that in the Description section of 8.3.1.1, those portions that are not related to safety need only be described in sufficient detail to permit an understanding of their interactions with the safety-related portions. In section 8.3.1.1 of the UFSAR, the licensee failed to include a description of the interactions between the APDG system and the safety-related switchgear. In UFSAR section 8.3.1.2, Analysis, the licensee included documentation of the APDG system as it pertains to the associated cables from non-Class 1E alternate power transfer switch to the Class 1E 6.9kV switchgear. The inspectors noted that this documentation only details the use of the APDG system in Modes 5 and 6, and fails to mention the use in Modes 1 through 4. The licensee entered this issue into their corrective action program as Condition Report CR-2013-006256.

Analysis.

The licensees failure to update the Final Safety Analysis Report to include the description of the APDG system in section 8.3.1 AC Power Systems was a performance deficiency. The issue is a performance deficiency because it was a failure to meet requirement, 10 CFR 50.71(e)(4), and it was within the licensees ability to correct the problem. Using Inspection Manual Chapter 0612, Appendix B, the performance deficiency was assessed through both the Reactor Oversight Process and traditional enforcement because the finding had the potential for impacting the NRCs ability to perform its regulatory function. Screening the performance deficiency through the Reactor Oversight Process, the finding resulted in a minor performance deficiency.

For traditional enforcement, the inspectors used the Enforcement Policy, in accordance with Section 6.1.d.3, and determined the violation to be a Severity Level IV, non-cited violation, because the licensee failed to update the UFSAR as required by 10 CFR 50.71(e)(4), but the lack of up-to-date information had not resulted in any unacceptable change to the facility or procedures. This violation did not have a cross-cutting aspect.

Enforcement.

10 CFR 50.71(e)(4), requires the UFSAR be updated, at intervals not exceeding 24 months, and states in part, the revisions must reflect all changes made in the facility or procedures described in the UFSAR. Contrary to the above, prior to June 20, 2013, the licensee did not ensure that the UFSAR revision reflected all changes made in the facility or procedures described in the UFSAR. Specifically, the inspectors identified the alternate power diesel generator system was not described in sufficient detail in the FSAR as required. This violation is being treated as a Severity Level IV, non-cited violation, consistent with Section 6.1.d.3 of the Enforcement Policy and was entered into the licensees corrective action program as CR-2013-006256.

(SLIV 05000445;05000446/2013007-04; Failure to Update the FSAR for the APDGs in Accordance with Regulatory Guide 1.70-1995)

.2.4 Unit 1 Diesel Generator 1-01 Emergency Feeder Breaker (1EG1)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 diesel generator 1-01 emergency diesel generator output breaker, 1EG1. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• Schematics and control wiring diagrams of record for the breaker

• Vendor manual and specifications for the breaker

• Load calculations of record and supporting documentation

• Calculations of record for protection settings and alarms

• Completion of last preventive maintenance work orders

• Breaker control power circuit and ancillary supporting component and equipment

b. Findings

No findings were identified.

.2.5 Unit 1 6.9kV Switchgear (1EA2)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 6.9kV switchgear, 1EA2. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• Calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination

• Protective device settings and circuit breaker ratings to confirm adequate selective protection and coordination of connected equipment during worst-case short circuit conditions

• Circuit breaker preventive maintenance, inspection, and testing procedures to confirm inclusion of relative industry operating experience and vendor recommendations

• Results of completed preventive maintenance on 6.9kV switchgear

• Degraded voltage and loss of voltage relay protection scheme and circuit breaker control logics that initiate automatic bus transfers

• NRC Information Notice 95-05, Undervoltage Protection Relay Settings Out of Tolerance Due To Test Equipment Harmonics

b. Findings

===.1

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,===

Appendix B, Criterion III, Design Control, for the licensees failure to analyze the effect of electrical system harmonics on the degraded voltage relays.

Description.

Each 6.9kV safety bus and each of its two associated 480V Switchgear buses is equipped with various undervoltage relays that will separate the 6.9kV buses from the offsite power source if the relay voltage and time delay setpoints are exceeded.

These relays include the 6.9kV degraded voltage relays (Model ITE-27H), the 480V Low Grid Undervoltage Relays (Model ITE-27N), and the 480V Degraded Voltage Relays (Model ITE-27N).

Instruction Bulletin IB 7.4.1.7-7 for the ITE-27N relays states that, the relay employs a peak voltage detector and that harmonic distortion on the AC waveform can have a noticeable effect on the relay operating point and the measuring instruments used to calibrate the relay. The bulletin also notes that the relay is available with an internal harmonic filter for applications where waveform distortion is a factor. Similarly, Instruction Bulletin IB 18.4.7-2 for the ITE-27H relays identified the sensitivity of the relays to harmonics in the test source. In 1994, Comanche Peak identified setpoint errors for the ITE-27H relays caused by harmonic content in test source, as reported in NRC Information Notice 95-05.

The inspectors noted that Calculation EE-CA-0008-0871, Protective relay settings for Safeguard Buses OV/UV Relays and Associated Time Delay Relays, identified the undervoltage relays as models not equipped with harmonic filters, but the calculation did not address the basis for excluding harmonic distortion, which could occur on the onsite power system, as a factor affecting relay accuracy. The inspectors were concerned that

persistent harmonics on the 6.9kV or 480V systems could cause the relays to fail to actuate at the setpoint specified in Technical Specifications. Persistent harmonics can be produced by factors external to the nuclear site or by internal phenomena. The inspectors noted that typical industry specifications for allowable power system harmonics (e.g., IEEE Std 141-1993, Table 9-6) considerably exceed the 0.3 percent Total Harmonic Distortion specified for test sources in IB 7.4.1.7-7. A typical internal source of persistent harmonics at nuclear power plants is defects in rotating equipment that are not detectable without special instrumentation. The inspectors were also concerned that transient harmonics could cause the relays to spuriously reset, in the presence of an actual degraded voltage event thereby delaying the protective function beyond the time delays stipulated in the design bases. Transient harmonics can be produced by circuit breaker switching operations such as occur at the start of an accident.

In response to the inspectors inquiries, the licensee provided Condition Report CR-2013-001479, which had been issued during a self assessment in February 2013 and identified that Calculation EE-CA-0008-0871 did not provide bases for not using ITE-27N relays without harmonic filters. However, the condition report did not identify a similar concern for the ITE-27H relays, and characterized the issue as an administrative document issue only, not a condition adverse to quality. The inspectors advised the licensee that a similar condition had been recently been evaluated by NRR for another nuclear station with a similar design and had been confirmed to be a condition adverse to quality. Based on this advice, the licensee issued Condition Report CR-2013-006230, and identified the issue as a condition adverse to quality and performed an operability evaluation.

The inspectors noted that for this issue to present an operability concern an actual degraded voltage condition would need to exist. The inspectors further noted that per Station Administrative Procedure STA-629, the licensee has established agreements with the transmission system operator, Oncor Electric Delivery Company, to utilize a real time contingency analyzer to predict when transmission system voltage is expected to decline below acceptable levels. The inspectors further noted that per Electric Reliability Council of Texas (ERCOT) protocols for the summer months, switchyard voltage levels at Comanche Peak will be maintained well above the levels necessary to prevent a degraded voltage condition. Based on these considerations, the inspectors concluded that there was reasonable assurance of operability pending resolution.

Analysis.

The licensees failure to analyze the effect of electrical system harmonics on the degraded voltage relays was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to analyze the effect of electrical system harmonics on the degraded voltage relays could cause the relays to fail to actuate at the setpoint specified in Technical Specifications. In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the

Mitigating System Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was a deficiency affecting the design or qualification that did not result in the safety-related equipment losing operability or functionality. This finding did not have a crosscutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance.

Enforcement.

10 CFR 50, Appendix B, Criterion III, Design Control, states, in part, measures 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, prior to May 20, 2013, the licensees design control measures had failed to check the adequacy of the design of the degraded voltage relays. Specifically, the licensee failed to assess the adverse effects of 6.9kV and 480V system harmonics on the degraded voltage relays. The violation did not present an immediate safety concern because the licensee has established agreements with the transmission system operator, Oncor Electric Delivery Company, to utilize a real time contingency analyzer to predict when transmission system voltage is expected to decline below acceptable levels. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensees corrective action program as Condition Report CR-2013-006230. (NCV 05000445;05000446/2013007-05; Failure to Analyze Effect of System Harmonics on Degraded Voltage Relays)

===.2

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50,===

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to perform adequate operability assessments with three examples. Specifically:

Example 1: The licensee did not addressed the safety function of the containment spray pumps continually running to maintain containment pressure within its design limits.

Example 2: The licensee did not ensure that compensatory measures would maintain operability of offsite power at minimum grid voltage.

Example 3: The licensee did not ensure that the basis would support crediting the use of the battery chargers after the emergency diesel generators restored power to the bus to supply emergency loads during the accident sequence.

Description.

Example 1: The inspectors reviewed Condition Report CR-2013-02031 that described a condition where the containment spray pumps will be manually shut off during a large break loss of coolant accident (LOCA) inside containment if the refueling water storage tank (RWST) reaches 0 percent indicated level or operators see indications of pump cavitation. An operability assessment was performed that stated the pumps would be restarted, if they were shut off due to 0 percent indicated level in the RWST, once the

suction of the pumps was transferred from the RWST to the containment sump. The operability failed to incorporate discussion of not restarting the pumps if they were shut off due to cavitation and potential damage to the pumps. The safety function of the containment spray pumps is to continually spray containment to maintain containment pressure within its design pressure. The operability did not address having no containment spray pumps running and the impact on containment pressure.

Additionally the inspectors observed an operation crew in the site simulator performing action during a simulated large break LOCA inside containment. The inspectors noted that operator assigned to perform the switchover actions from the RWST to the containment sump elected to use the highest of the RWST level indicators. The inspectors brought their concerns to site staff and they performed a reassessment of the operability and determined that they had no analysis to support their actions to secure containment spray pumps on 0 percent indicated level or indication of pump cavitation.

Also, they agreed that operator actions during switchover were not the conservative approach to be taken.

The licensee entered this issue of concern into their corrective action program as Condition Report CR-2013-05768. The immediate corrective action included an Operations Shift Order, explaining the concern and directing operators to perform the switchover actions based on lower of the RWST indicators until procedures could be evaluated and changed as needed.

Example 2: On June 5, 2013 the licensee initiated Condition Report CR-2013-006176 in response to the inspectors concerns regarding calculations and procedures for the availability of offsite power. The operability assessment concluded that the procedurally controlled minimum voltage limits of 135kV for the 138kV switchyard and 340kV for the 345kV switchyard, were not adequate to ensure reset of the low grid undervoltage relays during transient conditions of a safety injection. The operability assessment concluded that this condition resulted in the offsite power sources being operable but degraded, and that to maintain operability, it was necessary to implemented measures to maintain switchyard voltages above 136kV for the 138kV switchyard and 342kV for the 345kV switchyard. However, based on calculations performed by the inspectors using actual as-left relay settings, these new limits once again appeared to be too low to ensure reset of the low grid undervoltage relays during transient conditions of a safety injection.

In response to the inspectors inquiries, the licensee stated that no tolerances had been applied to the as-left settings because as-found as-left trend data showed very little relay drift over several calibrations. The inspectors noted that several tolerances were not measured during calibrations, and therefore would not show in as-found as-left data, including potential transformer accuracy, maintenance and test equipment accuracy, and variations in temperature and power supply voltage. Calculation EE-CA-0008-871 determined the cumulative effect of these tolerances to be 0.83 percent. When this tolerance was applied to relay settings, the licensee determined that the minimum switchyard voltages required to reset of the low grid undervoltage relays were 137kV for the 138kV switchyard and 345kV for the 345kV switchyard. The licensee revised the operability assessment of Condition Report CR-2013-006176 accordingly.

Example 3: The inspectors reviewed Condition Report CR-2013-006273 that described a condition where the minimum allowed battery voltage of 105VDC acceptance criteria applied during modified performance testing of safety-related batteries does not maintain sufficient voltage to prove that downstream equipment will function as expected during a loss of AC power event. Specifically, the current voltage drop methodology does not account for the increased voltage drop created during periods of higher current demand during the starting of equipment used to mitigate the event. An operability assessment was performed that credited use of the battery chargers during the first minute of accident mitigation to provide direct current electrical power to the 125 VDC buses to justify operability of the system, after the emergency diesel generators restored power to the bus. The operability assessment failed to verify the design basis of the battery chargers to ensure use of the chargers could be credited during the accident mitigation sequences. The design basis of the battery chargers is to supply steady state loads and recharge the battery during steady state conditions.

The licensee reevaluated the battery voltage requirements and voltage drop calculation using transient loading currents and determined that the battery remains operable during the event mitigation sequencing of loads, and that the battery chargers are not needed to support operability during this time sequence. The licensee updated the operability assessment in Condition Report CR-2013-006273.

Analysis.

The licensees the failure to perform adequate operability assessments was a performance deficiency. The performance deficiency is more-than-minor for the following reasons:

Example 1: It was associated with the Reactor Safety, Barrier Integrity Cornerstone, Configuration Control attribute and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, shutting off of the containment spray pumps during a large break LOCA inside containment would allow containment pressure to increase. In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Barrier Integrity Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3, the inspectors determined the finding was of very low (Green) safety significance because it did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components or actual reduction in function of hydrogen igniters in the reactor containment.

Example 2: It was associated with the Reactor Safety, Mitigating Systems Cornerstone, Equipment Performance attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the compensatory measures established in the first operability assessment did not ensure that offsite power would be maintained at minimum grid voltage.

Example 3: It was associated with the Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the operability assessment initially credited the use of the battery chargers after the emergency diesel generators restored power to the bus, without evaluating design basis for the battery chargers.

For examples 2 and 3 the inspectors used the Inspection Manual Chapter (IMC) 0609, 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating Systems Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because these examples were a deficiency affecting the design or qualification that did not result in losing operability or functionality.

This finding had a cross-cutting aspect in the area of human performance associated with the decision making component because the licensee failed in all three examples to conduct an effectiveness review of a safety-significant decision to verify the validity of the underlying assumptions to identify possible unintended consequences during the original operability assessments. H.1(b)

Enforcement.

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, for example 1 on February 28, 2013, for example 2 on June 5, 2013, and for example 3 on June 8, 2013, the licensee failed to ensure activities affecting quality are prescribed by documented instructions, procedures, or drawings and accomplished in accordance with these instructions, procedures, or drawings. Specifically, the licensee failed to follow procedure STI-442.01, Operability Determination and Functionality Assessment Program, Revision 1, Attachment 8.B page 3 of 5 which states, in part, Identify the topics that are applicable to the quick technical evaluation and include information for applicable topics within the evaluation such as: for example 1, The effect or potential effect of the degraded or nonconforming condition on the affected SSCs ability to perform its specified safety function or for example 2, Compensatory Measures are recommended or for example 3, Whether there is reasonable expectation of operability, including the basis for the determination.

The violation did not present an immediate safety concern because:

• Example 1: The licensee issued an Operation Shift Order, that explained the concern and directed operators to perform the switchover actions based on the lower of the RWST indicators until procedures could be evaluated and changed as needed.

• Example 2: The licensee issued an Operation Shift Order, that explained the concern and requires the control room operators to verify voltage will not go below

the new minimum grid voltage values of 345kV and 137kV, which align with the as-left relay setpoints.

• Example 3: The licensee performed additional voltage drop analysis to verify the safety-related battery could provide sufficient voltage during the first minute of transient load sequencing.

This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensee's corrective action program as CR-2013-006599.

(NCV 05000445;05000446/2013007-06; Failure to Perform Adequate Operability Assessments)

.2.6 Unit 2 Emergency Diesel Generator Sequencers

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 2 emergency diesel generator sequencers.

The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Logic diagrams of record for the sequencers

• Preventive maintenance procedures for the sequencers

• Completion of last preventive maintenance work orders

• Sequencer surveillance tests

• Sequencer control power circuit

• Sequencer voltage calculations

b. Findings

No findings were identified.

.2.7 Unit 2 Containment Electrical Penetrations

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 2 containment electrical penetrations. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Ampacity sizing calculations for electrical containment penetrations

• Containment penetration protective device sizing and setting calculations

• Test procedures for containment penetration protective devices

• Completion of last preventive maintenance work orders for selected penetration protective devices

b. Findings

No findings were identified.

.2.8 Unit 1 Class 1E Battery (BT1ED2)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 class 1E battery, BT1ED2 and battery rack assembly. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• Calculations that established the basis for battery loading and sizing

• Voltage drop calculations, short circuit calculations, and coordination studies

• Results of the recent surveillance tests and maintenance activities to determine inclusion of vendor recommendations and industry standards

• Visible material condition and configuration of the component

• Pilot Cell selection criteria, selection history, and cell performance

• Service and modified performance test procedures and previous three performance data

• Battery inter-cell connection resistance to ensure battery internal voltage drop supports operability

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to provide appropriate

acceptance criteria and testing procedure instructions during modified performance tests involving Class 1E batteries for the 1-minute critical period testing data.

Description.

Comanche Peak Nuclear Power Plant Updated Safety Analysis Report, Section 8.3.2, DC Power Systems, states, in part that all maintenance and testing procedures and criteria for replacement are in accordance with IEEE Standard 450-1995. IEEE Standard 450-1995 requires, in part, trending battery voltage during the critical periods of the load duty cycle will provide the user with a means of predicting when the battery will no longer meet design requirements. The Standard also describes a modified performance test as a test of the battery capacity and the batterys ability to provide a high-rate, short-duration load (usually the highest rate of the duty cycle.) This will often confirm the batterys ability to meet the critical period of the load duty cycle.

The inspectors reviewed industry standard IEEE Standard 450-1995, surveillance test procedure MSE-S0-5715 Modified Performance Test, Calculation EE-CA-0000-5121 Class 1E Battery Loading Duty Cycle for Modified Performance Test per IEEE 450-1995, and design basis document DBD-EE-044 DC Power Systems. As specified in the IEEE Standard 450-1995, the modified performance test can be performed to satisfy the service test (duty cycle test) and the performance test (capacity test). The test is a simulated duty cycle consisting of two rates: a 1-minute rate enveloping the largest current load of the duty cycle, followed by the test rate employed for the performance test. Calculation EE-CA-0000-5121 established the modified performance test profile load currents used in the testing procedure, and the current revision of the calculation was implemented in 2001. The inspectors determined that the modified performance test procedure did not include acceptance criteria or procedure instructions for the voltage check at the 1-minute critical period during the test to ensure the battery would supply sufficient voltage at the end of the 1-minute critical period during the high-rate discharge.

In response to the inspectors request, the licensee reviewed the raw data from the most recent modified performance test and was able to provide reasonable assurance that the battery satisfactorily met the design voltage requirement at the 1-minute critical period during the test. The licensee initiated CR-2013-005673 in response to the concern.

Analysis.

The licensees failure to provide appropriate acceptance criteria and testing procedure instructions involving Class 1E batteries for the 1-minute critical period testing data during modified performance tests was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Procedure Quality attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, Procedure MSE-S0-5715 does not direct the technicians to record and evaluate the voltage at the end of the 1-minute critical period to ensure it does not drop below the designed minimum voltage, which would indicate the battery would not be capable of meeting the required design function. In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors

determined that the finding affected the Mitigating Systems Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because Calculation EE-CA-0000-5121 was implemented in 2001 and did not reflect current licensee performance.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XI, "Test Control," states, in part, A test 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 the requirements and acceptance limits contained in applicable design documents.

Contrary to the above, since 2001, the licensee failed to establish a test program that assured that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service was identified and performed in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents. Specifically, the licensee failed to provide appropriate acceptance criteria and testing procedure instructions during modified performance tests involving Class 1E batteries for the 1-minute critical period testing data which incorporated the requirements of IEEE Standard 450-1995 to ensure the battery would meet the required design voltage for the duty cycle. The violation did not present an immediate safety concern because the licensee reviewed the raw data from the most recent modified performance test and was able to provide reasonable assurance that the battery satisfactorily met the design voltage requirement at the 1-minute critical period during the test. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensees corrective action program as Condition Report CR-2013-005673. (NCV 05000445;05000446/2013007-07; Failure to Provide Appropriate Acceptance Criteria and Testing Procedure Instructions)

.2.9 Unit 1 Component Cooling Surge Tank Air Operated Fill Valves (1-LV-4500/4501)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, selected drawings, maintenance and test procedures, and condition reports associated with the Unit 1 component cooling surge tank air operated valves. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Schematics and flow diagrams of record for the air operated fill valves

• Preventive maintenance procedures for the air operated valves

• Valve actuator design calculations

• Vendor specifications for the air operated fill valves

• Original test data from air operated fill valve testing

• Completion of all preventive maintenance work orders

b. Findings

No findings were identified.

.2.10 Containment Equipment Hatch and Personnel and Emergency Airlocks

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the containment equipment hatch and personnel and emergency airlocks. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Airlock and equipment hatch procurement specification and vendor manual.

• Airlock and equipment hatch assembly drawings and bills of materials.

• Design basis accident dose rate calculations for these component locations.

• Environmental qualification for limiting temperature and radiation conditions associated with the air lock and equipment hatch door seals.

b. Findings

No findings were identified.

.2.11 Unit 1 Containment Purge Valves (1-HV-5536, 5537, 5538, 5539)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 containment purge valves, 1-HV-5536, 5537, 5538, 5539. The inspectors also performed a walkdown of the outboard containment ventilation purge isolation valves, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Valve procurement specification and vendor manual

• Valve assembly drawing and bills of material

• Design basis accident dose rate calculations for these valve locations

• Environmental qualification for limiting temperature and radiation conditions associated with the o-ring seat seals for these valves

b. Findings

No findings were identified.

.2.12 Unit 1 Component Cooling Water Surge Tank 1-01 (CP1-CCATST-01)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 component cooling water surge tank 1-01, CP1-CCATST-01. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• System Design Basis Document and operator lesson plan/study guide

• System piping and instrumentation diagrams

• Tank procurement specification

• Tank assembly drawing and bill of materials

• Level set point calculations for compliance with pump net positive suction head requirements and system expansion/contraction conditions

• Vent sizing calculations for vacuum relief and maximum tank pressure

• Seismic design documentation to verify tank design is consistent with limiting seismic conditions

b. Findings

No findings were identified.

.2.13 Unit 1 Component Cooling Water Pump Recirculation Flow Valve (1-FV-4536)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and

condition reports associated with the Unit 1 component cooling water pump recirculation flow valve, 1-FV-4536. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• System Design Basis Document and operator lesson plan/study guide

• Valve procurement specification and vendor manual

• Valve assembly drawing and bill of materials

• Preventative & corrective maintenance procedures and completed work orders

• IST acceptance criteria, trend data, and completed work orders

• Differential pressure and required torque calculations

• Seismic design documentation to verify valve operator design is consistent with limiting seismic conditions

b. Findings

No findings were identified.

.2.14 Unit 1 Auxiliary Feedwater System Check Valve (1-AF-0032)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 auxiliary feedwater system check valve, 1-AF-0032. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• System Design Basis Document and operator lesson plan/study guide

• Valve procurement specification

• Valve assembly drawing and bill of materials

• Preventative & corrective maintenance procedures & completed work orders

• IST acceptance criteria, trend data, procedures and completed work orders

b. Findings

No findings were identified.

.2.15 Unit 1 Emergency Diesel Generator Exhaust Relief Valves

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 1 emergency diesel generator exhaust relief valves. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Schematics and flow diagrams of record for the air intake and exhaust system

• Preventive maintenance procedures for the relief valves

• Structural evaluation of the relief valve enclosures

• Vendor specifications for the diesel generator exhaust back pressure

• Original test data from relief valve testing

• Completion of last preventive maintenance work orders

• Condition reports regarding material condition of heat shield around relief valves

b. Findings

No findings were identified.

.2.16 Unit 2 Safety-Related Chilled Water Recirculation Pump (2-06)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 2 safety-related chilled water recirculation pump, 2-06. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• System Design Basis Document and operator lesson plan/study guide

• Pump procurement specification and vendor manual

• Pump assembly drawing and bill of materials

• Preventative and corrective maintenance procedures and completed work orders

• IST acceptance criteria, trend data, procedures and completed work orders

• Certified total developed head and net positive suction head curves

• Hydraulic calculations for compliance with total developed head and net positive suction head requirements

• Seismic design documentation to verify pump design is consistent with limiting seismic conditions

• High/moderate energy line break analysis for pump location

• Flooding analysis for pump location

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to ensure adequate acceptance limits were incorporated into test procedures for the safety chill water pumps.

Description.

As stated in Information Notice 97-90, licensees need to ensure that original plant design-basis calculations, or revisions to these calculations, are properly integrated into surveillance test procedure acceptance criteria. Inspectors reviewed the hydraulic network analysis for the safety-related chilled water system (Calc No. 1-EB-311-8) and determined that the licensee failed to properly address this requirement in the Inservice Test (IST) surveillance procedures for the chilled water pumps.

The original design calculation used the pump vendors generic catalog performance curve in the hydraulic model with no performance degradation assumed. The calculated friction losses in piping and fitting were determined by the Darcy formula using friction factors for smooth new steel pipe. For margin, these friction losses were then increased by 10 percent to determine the point at which the system curve and pump curve would intersect.

In 1994, the safety-related chilled water system was modified to add the uninterruptible power system (UPS) fan coil units. To accommodate the additional load of 55 gallons per minute (gpm) in the hydraulic analysis, the licensee: a) removed the 10 percent conservatism in the calculation for system friction losses; and b) reduced the required flowrate to other system users by eliminating unnecessary conservatisms in the heat transfer analyses for the other area coolers. The inspectors thus determined that the current hydraulic model for the chilled water system has little margin in it to compensate for the following:

• Uncertainty in parametric values (pipe roughness and L/D values for valves and fittings) used in the Darcy equation

• Potential for future increases in friction losses due to corrosion and/or scale buildup

• Potential for future need to plug tubes in the chiller or area cooler as a result of wall thinning or leaks

• Potential reduction of approximately 4 percent in pump performance during a loss of offsite power or loss of coolant accident as a result of allowance in the technical specifications for a 2 percent variance in emergency diesel generator frequency

• Pump degradation of 10 percent as allowed by the ASME Code and the licensees current IST procedures The IST surveillance procedures for the Train A and Train B safety-related chilled water pumps state that the quarterly test reference value for total developed head (TDH) is 93 pounds per square inch at a minimum flowrate of 290 gpm, which closely matches initial installed pump start-up test data. The inspectors noted that for the pump curve used in the analysis of record, the TDH at 290 gpm is approximately 95.2 psi. Based on this observation, the inspectors determined that after the UPS area coolers were installed in 1994, the analysis did not demonstrate that the safety-related chilled water system could achieve the required design flowrate if allowed to degrade to the IST required action value. In response to this, the licensee re-ran the computerized hydraulic model for the chilled water system using a progressively degraded pump curve until the flowrate was reduced to the design limit. These preliminary calculations indicated that Train As flowrate would fall below the required flowrate of 297 gpm should the pump degrade to 95 percent of the reference value. The licensee confirmed that the current pump performance curve is above the 95 percent curve, which ensures design basis flow rates are maintained.

Analysis.

The licensees failure to ensure appropriate acceptance criteria were incorporated into test procedures for the safety chill water pumps was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to recognize that if the safety-related chilled water pumps were degraded to 90 percent of their reference value, as permitted by IST Procedures OPT-209A/B, the system may not be able to achieve the required design flowrates as stated in Calculation 1-EB-311-8. In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating Systems Cornerstone.

Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because Calculation 1-EB-311-8 was updated in 1994 to incorporate the UPS fan coil units and did not reflect current licensee performance.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XI, "Test Control," states, in part, A test 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 the requirements and acceptance limits contained in applicable design documents.

Contrary to the above, since 1994, the licensee failed to establish a test program that assured that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service was identified and performed in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents. Specifically, the licensee failed to recognize that if the safety-related chilled water pumps were degraded to 90 percent of their reference value, as permitted by IST Procedures OPT-209A/B, the system may not be able to achieve the required design flowrates as stated in Calculation 1-EB-311-8.

The violation did not present an immediate safety concern because the licensee confirmed that the current pump performance curve is greater than the minimum required, to ensure that design basis flow rates are maintained. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensees corrective action program as Condition Report CR-2013-006252.

(NCV 05000445;05000446/2013007-08; Failure to Provide Appropriate Acceptance Criteria for the Safety Chill Water Pumps)

.2.17 Unit 2 Emergency Diesel Generator Building Fans

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, diesel generator building ventilation system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 2 emergency diesel generator building fans. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Design basis documents for the diesel generator area ventilation system

• Calculations of the diesel generator area space heat gains, space heat losses, and maximum and minimum area temperatures

• Calculation of flow resistance across diesel generator building air intake barriers

• Diesel generator exhaust fan vibration trend data

• Maintenance records, surveillance records, and work orders

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensee's failure to identify a condition adverse to quality involving the emergency diesel generator building ventilation system.

Description.

The inspectors performed a review of the Unit 1 and 2 emergency diesel generator (EDG) exhaust relief valves. During their review, the inspectors conducted a walk-down of the Unit 1 EDG roof area where the exhaust relief valves for the Unit 1 EDGs are located. While in the area, the inspectors noticed that exhaust flow coming from the EDG building ventilation system of the Unit 1 EDG buildings varied significantly over the exhaust screens. Upon further examination, the inspectors noticed that half of the screens were heavily fouled with debris. The inspectors asked the licensee if the screens were ever cleaned and if sufficient exhaust flow remained to ensure EDG building temperatures would remain below equipment qualification requirements for the as found condition at design basis limiting conditions.

The licensee conducted a review of site documents and determined that, since plant startup, the screens had never been cleaned nor were any preventive maintenance procedures in place to clean or inspect the screens. They then conducted flow measurements of the running fans and determined they had adequate flow for EDG building cooling for the existing plant conditions. Additionally, the licensee inspected the Unit 2 EDG building exhaust screens and discovered only slight fouling of the screens.

They attributed the difference in exhaust screen fouling between Units 1 and 2 to prevailing wind patterns in the area. The licensee entered this issue of concern into their corrective action program as Condition Report CR-2013-006540.

Analysis.

The licensee's failure to identify fouling on the Unit 1 emergency diesel generator building exhaust ventilation screens was a performance deficiency. The performance deficiency is more-than-minor because it had the potential to lead to a more significant safety concern. Specifically, the Unit 1 emergency diesel generator rooms could have insufficient exhaust flow to meet design basis temperature requirements if left uncorrected. In accordance with Inspection Manual Chapter (IMC)0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating System Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the emergency diesel generators losing operability or functionality. This finding did not have a crosscutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, before June 17, 2013, measures were not established to assure that conditions adverse to quality were promptly identified and corrected. Specifically, the licensee failed to establish an activity to identify fouling of the Unit 1 emergency diesel generator building exhaust ventilation screens. The violation does not present an immediate safety concern because the licensee measured adequate exhaust flow to maintain temperatures in the emergency diesel generator building below design basis limiting conditions. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensee's corrective action program as Condition Report CR-2013-006540.

(NCV 05000445;05000446/2013007-09; Failure to Identify Fouling on the Emergency Diesel Generator Building Exhaust Ventilation Screens)

.2.18 Unit 2 Safety Injection System Recirculation Sump Isolation Valves (2-8811A/B)

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 2 safety injection system recirculation sump isolation valves, 2-8811A/B. The inspectors also performed walkdowns, and conducted interviews with system engineering personnel to ensure the capability of these components to perform their required design basis function. Specifically the inspectors reviewed:

• Design bases documents for the safety injection system

• Calculations regarding design data for safety-related motor-operated valves within the scope of NRC Generic Letter 89-10

• Final design authorization and work orders for changing the actuator gear set

• Design change notice for replacement of the motor on isolation valve 8811B

• Trend data for the recirculation sump isolation valves

• Responses to NRC Generic Letters 89-10, 95-07, and 96-05

• Drawing for the 14 gate valve bonnet relief assembly

b. Findings

No findings were identified.

.2.19 Unit 2 Residual Heat Removal Pump Mechanical Seal and Breaker Coordination

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, residual heat removal system description, the current system health report, selected drawings, maintenance and test procedures and condition reports associated with the Unit 2 residual heat removal pump mechanical seal and breaker coordination. The inspectors also conducted interviews with system engineering personnel to ensure the capability of this component to perform its required design basis function. Specifically the inspectors reviewed:

• Design bases documents for the residual heat removal system

• Maintenance records for the residual heat removal pumps and mechanical seals

• Performance records for the residual heat removal pumps

• Piping and instrumentation drawings for the residual heat removal and safety injection systems

• Calculations regarding head loss between the residual heat removal pump discharge and safety injection and charging pump takeoffs

• Calculations regarding residual heat removal pump operating point during hot leg recirculation

• Residual heat removal pump vibration trend data

• Residual heat removal pump circuit breaker coordination studies to ensure proper circuit coordination

b. Findings

No findings were identified.

.3.1 Inspection of Information Notice 92-18 - Potential for Loss of Remote Shutdown

Capability during a Control Room Fire

a. Inspection Scope

The inspectors reviewed the licensees evaluation of NRC Information Notice 92-18, Potential for Loss of Remote Shutdown Capability during a Control Room Fire, to verify that the review adequately addressed the industry operating experience. The inspectors

specifically reviewed selected components to verify circuit modifications properly eliminated the concerns identified in the Information Notice. The components selected were:

• Unit 2 charging pumps safety injection header isolation motor operated valve (2-8801A)

• Unit 2 containment recirculation sump to residual heat removal pump motor operated valve (2-8811A)

• Unit 2 refueling water storage tank to Residual Heat Removal Pump 2 isolation motor operated valve (2-8812A)

b. Findings

No findings were identified.

.3.2 Inspection of Information Notice 1997-90 - Use of Nonconservative Acceptance Criteria

in Safety-Related Pump Surveillance Tests

a. Inspection Scope

The inspectors reviewed the licensees evaluation of NRC Information Notice 1997-90, Use of Nonconservative Acceptance Criteria in Safety-Related Pump Surveillance Tests, to verify that the review adequately addressed the industry operating experience.

The inspectors determined that for the safety chilled water pumps, the licensees evaluation did not adequately addressed the operating experience and use of non-conservative IST acceptance criteria identified in the Information Notice. See Section 02.16 NCV 05000445;05000446/2013007-08 for a detailed description of this finding.

b. Findings

No findings were identified.

.3.3 Inspection of Information Notice 2012-11 - Age Related Capacitor Degradation

a. Inspection Scope

The inspectors reviewed the licensees evaluation of NRC Information Notice 2012-11, Age Related Capacitor Degradation, to verify that the review adequately addressed the industry operating experience. The inspectors verified that the licensees evaluation in CR-2012-007571 adequately addressed the issues in the Information Notice. The inspectors reviewed preventive maintenance plans and procedures for replacement of capacitors.

b. Findings

No findings were identified.

.4 Results of Reviews for Operator Actions:

The inspectors selected risk-significant components and operator actions for review using information contained in the licensees probabilistic risk assessment. This included components and operator actions that had a risk achievement worth factor greater than two or Birnbaum value greater than 1E-6.

a. Inspection Scope

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

The selected operator actions were:

• Manual fill of component cooling water surge tank on loss of instrument air

• Establish local auxiliary feedwater flow control valve control following loss of all AC power

• Establish local manual control of component cooling water to the safety chiller on loss of instrument air

• Stop reactor coolant pumps on a loss of component cooling water non-safeguards loop flow

• Manually align backup charger to Train "A" bus before the 1E battery depletes

• Align alternate power to valve 1-8702A, residual heat removal pump 1-01 recirculation isolation valve

• Transition to loss of coolant accident procedures within ten minutes of a large break loss of coolant accident

• Transfer to cold leg recirculation on large break loss of coolant accident

• Transfer containment spray system to recirculation mode

• Align alternate power diesel generators to the safety-related bus

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to appropriately incorporate the refueling water storage tank (RWST) vortexing design calculations 6 percent indicated level into the emergency operating procedures for switching containment spray pump suction from the RWST over to the containment sump to prevent damage to the pump.

Description.

The inspectors determined that the licensee had inadequately responded to a condition report written on February 28, 2013 (CR-2013-002031) expressing concern over the ability of operators to switch containment spray pump suction from the RWST over to the containment sump in the time span allocated for this in EOS-1.3A/B, given the known difficulties identified in accurately reading the analog type level indicator provided in the control room for this purpose. In reviewing the calculations backing up this operator action, the inspectors determined that the vortex calculation 16345-ME(8)-282, assumed a minimum water level of Elevation 814.1 ft. (~5.5 percent of instrumented volume). To achieve a needed increase in containment sump level after completion of the GSI-191 modifications to the sump suction strainers, the switch-over point was changed from 24 percent indicated volume to 6 percent indicated volume during the October 2006 RFO for Unit 2 and during the March 2007 RFO for Unit 1.

Neither instrument uncertainty nor tank drawdown during the switchover was adequately considered when the 6 percent level was selected. The inspectors determined that for an as-read tank level of 6 percent, actual tank level could be as low as approximately 2.3 percent. Furthermore, the inspectors noted that since EOS-1.3A/B stated that RWST level is to be less than 6 percent before action is taken to open the containment sump isolation valves, therefore; RWST level could be allowed to fall into the vortexing region while containment spray pump suction is still being taken from the tank.

Using several different models of the suction sparger header internal to the RWST, the vortex calculation had determined the minimum required submergence to be in the range of approximately -0.7 percent to +2.6 percent of instrumented tank volume. On this basis, the adjusted minimum switchover level (i.e., 2.3 percent as noted above)would appear to be non-conservative. However, based on further discussion with the licensee, the inspectors agreed that more realistic modeling in the vortex and drawdown calculations would yield positive margin on available submergence at a switchover point of 6 percent (as read) tank volume. To resolve the inspectors concerns regarding the wording in EOS-1.3A/B, an operations shift order was issued to ensure that switchover shall commence immediately upon reaching an as-read tank level of 6 percent on either of the two tank level indicators.

Analysis.

The licensees failure to appropriately incorporate the RWST vortexing design calculations 6 percent indicated level into the emergency operating procedures for switching containment spray pump suction from the RWST to the containment sump to prevent damage to the pumps was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Procedure Quality attribute and adversely affected the

cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Emergency Operating Procedure EOS-1.3A/B allowed the operators the ability to delay transfer of containment spray pump suction source which could have caused damage to the pumps due to vortexing. In accordance with Inspection Manual Chapter (IMC) 0609, 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating Systems Cornerstone. Using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was not a design deficiency and did not result in the loss of operability or functionality. This finding did not have a cross-cutting aspect because the change to the procedure due to the addition of the sump strainers occurred in 2006 and 2007, and did not reflect current licensee performance.

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, measures shall be establish to assure that the design basis for systems, structures, and components are correctly translated into specifications, drawings, procedures and instructions. Contrary to the above, since 2006 and 2007, the licensee failed to assure that the design basis for systems, structures, and components are correctly translated into specifications, drawings, procedures and instructions. Specifically, the licensee failed to appropriately incorporate the RWST vortexing design calculations 6 percent indicated level into the emergency operating procedures for switching containment spray pump suction from the RWST to the containment sump to prevent damage to the pumps. The violation did not present an immediate safety concern because the licensee issued an Operation Shift Order, to ensure that switchover shall commence immediately upon reaching an as-read tank level of 6 percent on either of the two tank level indicators. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensees corrective action program as Condition Report CR-2013-005739. (NCV 05000445;05000446/2013007-10; Failure to Incorporate the Refueling Water Storage Tank Vortexing Design Calculation into the Emergency Operating Procedures for Containment Spray Pump Operation)

4OA2 Identification and Resolution

a. Inspection Scope

The inspectors reviewed condition reports associated with the selected components, operator actions and operating experience notifications.

b. Findings

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensee's failure to correct a condition adverse to quality in a timely manner that involved updating design basis

calculations for safety-related equipment to include the allowed technical specification frequency range of +/- 2 percent for the emergency diesel generators.

Description.

The inspectors reviewed corrective actions associated with a non-cited violation written in report 05000445; 05000446/2010006, titled, Inadequate Analysis of Emergency Diesel Generator Frequency. The inspectors reviewed the corrective actions taken and the timeline for the remaining of the corrective actions. The licensee performed an evaluation of margins that focused on emergency core cooling system equipment to ensure that the equipment could perform their design basis function that included the allowed technical specification frequency range of +/- 2 percent for the emergency diesel generators. The licensee did not evaluate all components with this allowed frequency range for steady state conditions. The licensee controls steady state frequency with the emergency diesel generator governor to a small range of +/-0.1 hertz.

The evaluation that the licensee performed concluded that there is a negligible effect on components when controlling to this steady state frequency range.

Future corrective actions are associated with the licensee and the Pressurized Water Reactors Owners Group initiative (submitted on May 1, 2012) which is to discuss with the NRC an action to change the technical specifications to address differentiating steady state and transient frequency ranges. This issue was identified June 18, 2010, and the NRC issued Information Notice 2008-02 that discussed the allowed technical specification frequency range for the emergency diesel generator. Therefore, the inspectors concluded, since the corrective actions are still not complete, the actions to correct a previously identified non-cited violation were not completed in a timely manner.

The licensee entered this issue of concern into their corrective action program as Condition Report CR-2013-006604.

Analysis.

The licensee's failure to correct a condition adverse to quality in a timely manner that involved updating design basis calculations for safety-related equipment to include the allowed technical specification frequency range of +/- 2 percent for the emergency diesel generators was a performance deficiency. The performance deficiency is more-than-minor because it was associated with the Reactor Safety, Mitigating Systems Cornerstone, Design Control attribute and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the calculations to support safety-related equipment did not include allowed technical specification frequency range for the emergency diesel generators to ensure the equipment would be capable of performing their safety-related functions. In accordance with Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the finding affected the Mitigating System Cornerstone. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, the inspectors determined the finding was of very low (Green) safety significance because the finding was a deficiency affecting the design or qualification that did not result in the safety-related equipment losing operability or functionality. This finding had 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 updating

design basis calculations to include technical specification allowed emergency diesel generator frequency range in a timely manner, commensurate with their safety significance. P.1(d)

Enforcement.

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, since May 2010, measures were not established to assure that conditions adverse to quality were promptly identified and corrected. Specifically, the licensee failed to correct a condition adverse to quality in a timely manner that involved updating design basis calculations for safety-related equipment to include the allowed technical specification frequency range of +/- 2 percent for the emergency diesel generators. The violation did not present an immediate safety concern because the licensee confirmed that the safety-related equipment had enough design margin to ensure design basis functions would be maintained. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low (Green) safety significance and was entered into the licensee's corrective action program as Condition Report CR-2013-006604.

(NCV 05000445;05000446/2013007-11; Failure to Correct Design Calculations to Incorporate Technical Specification Allowed Frequency Range for the Emergency Diesel Generator in a Timely Manner)

4OA6 Meetings, Including Exit

On June 20, 2013, the team leader presented the preliminary inspection results to Mr. Flores, Senior Vice President and Chief Nuclear Officer, and other members of the licensees 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.

4OA7 Licensee Identified Violations

No findings were identified.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

I. Ahmad, Design Engineering Analysis

D. Ambrose, Corrective Action Program Manager

J. Bain, Equipment Reliability Supervisor

J. Brady, Design Engineer

D. Davis, Director, Special Projects

R. Flores, Senior Vice President and Chief Nuclear Officer

T. Gibbs, Safeteam Manager

S. Harvey, Interim Work Control/Outage Manager

J. Henderson, Engineering Smart Team Manager

J. Hicks, Regulatory Affairs

T. Hope, Nuclear Licensing Manager

K. Kirwin, Nuclear Oversight

J. Lamarca, Project Manager

F. Madden, Director, Nuclear Oversight and Regulatory Affairs

L. Meller, Operations Day Shift Supervisor

G. Merka, Regulatory Affairs

W. Moore, Director, Nuclear Training

B. Patrick, Director, Maintenance

J. Patton, Nuclear Oversight Manager

K. Peters, Site Vice President

W. Reppa, Director, Site Engineering

M. Shirey, Engineering

M. Smith, Director, Nuclear Operations

S. Smith, Plant Manager

R. Sorrell, System Engineer

J. Taylor, Technical Support Manager

G Techentine, Mechanical/Program Reliability Manager

D. Volkening, Quality Assurance Audit Supervisor

D. Whitsitt, System Engineer

L. Windham, Design Engineering Analysis Manager

NRC personnel

J. Kramer, Senior Resident Inspector

G. Replogle, Senior Reactor Analyst

M. Williams, Resident Inspector

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000445; NCV Inadequate Calculations and Procedures for Offsite

05000446/2013007-01 Power Availability (1R21.2.1)

05000445; NCV Inadequate Voltage Calculations for the 125 VDC

05000446/2013007-02 and 120 VAC Buses (1R21.2.2)

05000445; NCV Failure To Establish 10 CFR 50.65(a)(1)

05000446/2013007-03 Performance Goals for the APDGs (1R21.2.3)

05000445; SLIV Failure to Update the FSAR for the APDGs in

05000446/2013007-04 Accordance with Regulatory Guide 1.70-1995 (1R21.2.3)

05000445; NCV Failure to Analyze Effect of System Harmonics on

05000446/2013007-05 Degraded Voltage Relays (1R21.2.5)

05000445; NCV Failure to Perform Adequate Operability

05000446/2013007-06 Assessments (1R21.2.5)

05000445; NCV Failure to Provide Appropriate Acceptance Criteria

05000446/2013007-07 and Testing Procedure Instructions (1R21.2.8)

05000445; NCV Failure to Provide Appropriate Acceptance Criteria

05000446/2013007-08 for the Safety Chill Water Pumps (1R21.2.16)

05000445; NCV Failure to Identify Fouling on the Emergency Diesel

05000446/2013007-09 Generator Building Exhaust Ventilation Screens (1R21.2.17)

05000445; NCV Failure to Incorporate the Refueling Water Storage

05000446/2013007-10 Tank Vortexing Design Calculation into the Emergency Operating Procedures for Containment Spray Pump Operation (1R21.4)

05000445; NCV Failure to Correct Design Calculations to Incorporate

05000446/2013007-11 Technical Specification Allowed Frequency Range for the Emergency Diesel Generator in a Timely Manner (4OA2)

Attachment