IR 05000317/2013005

IR 05000317/2013005, 05000318/2013005; 10/01/2013 - 12/31/2013; Calvert Cliffs Nuclear Power Plant (Ccnpp), Units 1 and 2; Operability Determination and Functionality Assessments, and Surveillance Testing

ML14038A305
Person / Time
Site:	Calvert Cliffs
Issue date:	02/07/2014
From:	Daniel Schroeder Reactor Projects Branch 1
To:	George Gellrich Constellation Energy Nuclear Group
Schroeder D
References
IR-13-005
Download: ML14038A305 (34)

Text

February 7, 2014

SUBJECT:

CALVERT CLIFFS NUCLEAR POWER PLANT UNITS 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000317/2013005 AND 05000318/2013005

Dear Mr. Gellrich:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Calvert Cliffs Nuclear Power Plant (CCNPP), Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on January 8, 2014, with you and other members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents two NRC-identified findings of very low safety significance (Green).

These findings were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest any NCV in this report, 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 I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspectors at CCNPP. In addition, if you disagree with the cross-cutting 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 I, and the NRC Resident Inspectors at CCNPP.

As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to Inspection Manual Chapter (IMC) 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

In accordance with Title 10 Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRCs 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 component of NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA AARosebrook by direction/

Daniel L. Schroeder, Chief Reactor Projects Branch 1 Division of Reactor Projects

Docket Nos:

50-317 and 50-318 License Nos: DPR-53 and DPR-69

Enclosure:

Inspection Report 05000317/2013005 and 05000318/2013005

w/Attachment: Supplementary Information

REGION I==

Docket Nos:

50-317 and 50-318

License Nos:

DPR-53 and DPR-69

Report Nos:

05000317/2013005 and 05000318/2013005

Licensee:

Constellation Energy Nuclear Group, LLC

Facility:

Calvert Cliffs Nuclear Power Plant, Units 1 and 2

Location:

Lusby, MD

Dates:

October 1, 2013 through December 31, 2013

Inspectors:

S. Kennedy, Senior Resident Inspector E. Torres, Resident Inspector J. DAntonio, Senior Operations Engineer M. Orr, Reactor Inspector P. Presby, Senior Operations Engineer R. Rolph, Health Physicist

Approved by:

Daniel L. Schroeder, Chief Reactor Projects Branch 1 Division of Reactor Projects

Enclosure

SUMMARY

IR 05000317/2013005, 05000318/2013005; 10/01/2013 - 12/31/2013; Calvert Cliffs Nuclear

Power Plant (CCNPP), Units 1 and 2; Operability Determination and Functionality Assessments, and Surveillance Testing.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Two Green findings, which were non-cited violations (NCVs), were identified. The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross-Cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRCs 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: Initiating Events

Green.

The inspectors identified an NCV of Technical Specification (TS) 5.4.1,

Procedures, because Constellation Energy Nuclear Group (CENG) failed to maintain adequate guidance in Emergency Operating Procedure (EOP) 8, Functional Recovery Procedure, and/or Abnormal Operating Procedure (AOP) 7J, Loss of 120 Volt Vital Alternating Current (AC) or 125 Volt Vital Direct Current (DC) Power. Specifically,

EOP-8 and/or AOP-7J did not contain adequate instructions to cross-tie the 480 volt AC vital buses to restore the 120 volt AC vital buses during a loss of offsite power (LOOP)event concurrent with a single failure of the 21 125 volt DC bus. As a result, the engineered safety features actuation system (ESFAS) and auxiliary feedwater actuation system (AFAS) would inadvertently actuate on both units if the 120 volt AC vital buses were not restored within a specified period of time. CENG staffs immediate corrective actions included entering this issue into their corrective action program (CAP).

Corrective actions planned include revising AOP-7J to add in steps to cross-tie the 480 volt AC vital buses.

The finding is more than minor because it is associated with the procedure quality attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, following a LOOP concurrent with a failure of the 21 DC bus, inadvertent ESFAS and AFAS actuations would occur on both units if power is not restored to the vital 120 volt AC buses. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 1, Initiating Events Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency was not reflective of current licensee performance. Specifically, the inspectors determined that this was a legacy procedure issue and did not note any recent reasonable opportunities for CENG personnel to identify this issue. (Section 1R15)

Cornerstone: Mitigating Systems

Green.

The inspectors identified an NCV of Title 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion XI, Test Control, because CENGs in-service test (IST)procedures did not provide instructions to preclude preconditioning of the containment air cooler (CAC) emergency outlet valves. Specifically, STP-O-065B-2, 21 SRW Subsystem Operability Test, was written such that a full stroke of the CAC emergency outlet valves was allowed prior to performance of the IST stroke time testing of the valves in the open direction. As a result, the 21 CAC emergency outlet valve, 2-CV-1582, was preconditioned during the last four surveillance tests performed on the valve and the 24 CAC emergency outlet valve, 2-CV-1593, was preconditioned during three of the last four surveillance tests performed on the valve. Immediate corrective actions included entering this issue in the CAP. Corrective actions included revising STP-O-065B to prevent future preconditioning of all the CAC emergency outlet valves.

The finding is more than minor because it is associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, preconditioning of the CAC emergency outlet valves prior to performing IST stroke time testing could mask valve degradation. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power,

Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating structure, system, and component (SSC), did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment, designated as having high safety significance in accordance with the maintenance rule program, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors determined that the finding has a cross-cutting aspect in the area of Human Performance, Resources, because CENG staff failed to ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, CENG staff did not provide a complete and accurate procedure that would preclude preconditioning of the CAC emergency outlet valves during in-service testing H.2(c). (Section 1R22)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On November 23, 2013, operators reduced power to 82 percent to perform main turbine valve testing. Operators returned the unit to 100 percent power the same day. The unit remained at or near 100 percent power for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power. The unit remained at or near 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of CENG staffs readiness for the onset of seasonal cold temperatures. The review focused on the 12 condensate storage tank and the emergency diesel generator (EDG) rooms. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), TSs, control room logs, and the CAP to determine what challenges cold temperatures and other seasonal weather conditions could have on these systems, and to ensure that CENG personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including CENGs seasonal weather preparation procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel had identified issues that could challenge the operability of the systems during cold weather conditions. Documents reviewed for each section of this inspection report are listed in the attachment.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

Partial System Walkdowns (71111.04Q - 2 samples)

a. Inspection Scope

==

The inspectors performed partial walkdowns of the following systems:

Unit 1, 11 loss of coolant incident filter with 12 loss of coolant incident filter out of service on October 3, 2013 Unit 2, 21A service water (SRW) heat exchanger with the 21B SRW heat exchanger out of service for maintenance on October 29, 2013

The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable procedures, system diagrams, the UFSAR, TSs, condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted the systems performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies.

The inspectors also reviewed whether CENG staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

==1R05 Fire Protection

Resident Inspector Quarterly Walkdowns (71111.05Q - 2 samples)

==

a. Inspection Scope

The inspectors conducted a tour of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that CENG personnel controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

Unit 1, turbine building, fire area TB, 27 elevation, room L27A on November 15, 2013

Unit 2, turbine building, fire area TB, 27 elevation, room L27B on November 15, 2013

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification Program (71111.11Q - 2 samples; 71111.11B - 1 sample)

==

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator testing on October 25, 2013, which included implementation of AOP-7E, Main Turbine Malfunction; AOP-1B, Control Element Assembly Malfunction; EOP-0, Post Trip Immediate Actions; EOP-2, Loss of Offsite Power; and EOP-8, Functional Recovery Procedure. The inspectors evaluated operator performance during the simulated events and verified completion of risk significant operator actions, including the use of AOPs and EOPs. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classifications made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed the load testing of the 23 inverter 1 on December 6, 2013, and the removal of the U-4000-21 transformer from service on December 10, 2013. Additionally, the inspectors observed procedure use and adherence, crew communications, and coordination of activities between work groups to verify that established expectations and standards were met.

b. Findings

No findings were identified.

.3 Biennial Review

a. Inspection Scope

The following inspection activities were performed using NUREG-1021, "Operator Licensing Examination Standards for Power Reactors," Revision 9, Supplement 1; and Inspection Procedure 71111, Attachment 71111.11B, Licensed Operator Requalification Program, Appendix A, Checklist for Evaluating Facility Testing Material, and Appendix B, Suggested Interview Topics.

A review was conducted of recent operating history documentation found in inspection reports, licensee event reports, CENGs CAP, and the most recent NRC plant issues matrix. The inspectors also reviewed specific events from the CAP, which indicated possible training deficiencies, to verify that they had been appropriately addressed. The Senior Resident Inspector was also consulted for insights regarding the licensed operators performance. These reviews did not detect any operational events that were indicative of possible training deficiencies.

Examination Results

The operating tests for the week of November 18, 2013, were reviewed for quality and performance.

On December 13, 2013, the results of the annual operating tests for year 2013 and the written exam for 2013 were reviewed to determine if pass fail/rates were consistent with the guidance in NUREG-1021, "Operator Licensing Examination Standards for Power Reactors," Revision 9, Supplement 1, and IMC 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process. The review verified the following:

Individual pass rates on the dynamic simulator test were greater than 80 percent (Pass rate was 92.6 percent)

Individual pass rates on the job performance measures of the operating exam were greater than 80 percent (Pass rate was 97.5 percent)

Individual pass rates on the written exam were greater than 80 percent (Pass rate was 97.5 percent)

More than 80 percent of the individuals passed all portions of the exam (90.2 percent of the individuals passed all portions of the examination)

Crew pass rates were greater than 80 percent (Pass rate was 93.3 percent)

Overall pass rate among individuals for all portions of the exam was greater than or equal to 80 percent (Overall pass rate was 92.6 percent)

Observations were made of the dynamic simulator exams and job performance measures administered during the week of November 18, 2013. These observations included facility evaluations of crew and individual performance during the dynamic simulator exams and individual performance of five job performance measures.

Remedial Training and Re-Examinations

The remediation plans for two individual operating examination failures and one crew failure were reviewed to assess the effectiveness of the remedial training.

Simulator Performance

Simulator performance and fidelity were reviewed for conformance to the reference plant control room.

A sample of records for requalification training attendance, program feedback, reporting, and medical examinations were reviewed for compliance with license conditions and NRC regulations.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on SSC performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance work orders, and maintenance rule basis documents to ensure that CENG staff was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by CENG staff was reasonable. As applicable, for SSCs classified as (a)(1),the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that CENG staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

23 saltwater (SW) pump discharge check valve through wall leakage (CR-2013-

===007902)

Motor control center (MCC) 218T de-energized due to 2BRK52-20118 ground shield tripped (CR-2013-008974)

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed CENG staffs evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that CENG staff performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that CENG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that these assessments were accurate and complete. When CENG personnel performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Orange risk on Unit 1 due to the 12 SW header planned maintenance and severe weather conditions on October 7, 2013

P-13000-1, 13 kilovolt (kV) transformer, planned maintenance (Units 1 and 2) on November 19, 2013

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

11 loss of coolant incident filter bypass flow on October 2, 2013 (CR-2013-007736)

23 SW discharge check valve through wall leakage on October 4, 2013 (CR-2013-007902)

22A safety injection tank leak rate trend steadily increasing on November 7, 2013 (CR-2013-008845)

11 DC bus operability during swap to reserve battery on October 3, 2013 (CR-2013-006334)

The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to CENG staffs evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by CENG staff. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

Introduction:

The inspectors identified a Green NCV of TS 5.4.1, Procedures, because CENG staff failed to maintain adequate guidance in EOP-8 and/or AOP-7J. Specifically, EOP-8 and/or AOP-7J did not contain adequate instructions on how to cross-tie the 480 volt AC vital buses to restore the 120 volt AC vital buses (1Y02 and 2Y02) for a LOOP event concurrent with a single failure of the 21 125 volt DC bus. As a result, ESFAS and AFAS actuations would inadvertently occur on both units if the 120 volt AC vital buses are not restored in a specified period of time.

Description:

CCNPPs DC power distribution system consists of four safety-related 125 volt DC buses (11, 12, 21, and 22). Each bus has its own battery and provides DC power to loads on both units. These buses are further divided into trains. Train A consists of the 11 and 22 DC buses while train B includes the 12 and 21 DC buses. For train A the 11 DC bus is the main bus. For train B the 21 DC bus is the main bus. Note that this issue is relevant to only Train B, for reasons to be discussed later. The 21 DC bus loads include:

Control power for safety related 4kV buses 14 (Unit 1) and 24 (Unit 2)

2B EDG output breaker control power and field flash

14A/14B (Unit 1) and 24A/24B (Unit 2) safety-related 480 volt AC buses control power

1Y02 (Unit 1) and 2Y02 (Unit 2) safety-related 120 volt AC vital buses; 1Y02 and 2Y02 contain ESFAS sensor channel ZE, ESFAS actuation channel ZB, AFAS sensor channel ZE, and AFAS actuation channel ZB for each respective unit

The 12 DC bus loads include:

1B EDG output breaker control power and field flash

1Y03 and 2Y03 safety-related 120 volt AC vital buses; 1Y03 and 2Y03 contain ESFAS sensor channel ZF and AFAS sensor channel ZF for each respective unit

Train B emergency power sources are the 1B EDG and 2B EDG, via the 14 and 24 4kV buses to the 14A/B and 24A/B 480 volt AC buses through the 13 and 21 battery chargers for the 21 DC bus and through the 12 and 24 battery chargers for the 12 DC bus. ESFAS is designed to initiate the start of equipment which protects the public and plant personnel from the accidental release of radioactive fission products in the unlikely event of a loss of coolant accident (LOCA), main steam line break, or loss of feedwater incident. AFAS is designed to start the auxiliary feedwater (AFW) system upon detection of a very low level in either steam generator and it blocks AFW to a ruptured steam generator. ESFAS and AFAS actuation systems are divided into four sensor subsystems (channels ZD, ZE, ZF, and ZG) and two actuation subsystems (actuation channels ZA, and ZB). ESFAS also provides two logic subsystems for sequential loading of the diesel generators. A loss of power to an ESFAS or AFAS sensor channel will result in a trip signal of that sensor channel to the associated actuation channels, ZA or ZB. When two out of four sensor channels trip, the ESFAS and AFAS actuation channels will initiate actuation signals to safety related equipment. On a loss of power to actuation channel ZA or ZB, the affected channel would not send an actuation signal for equipment initiation.

On September 11, 2013, the inspectors identified that procedures used to address the single failure of the 21 DC bus concurrent with a LOOP were inadequate to properly restore electrical power to the vital 120 volt AC system. As a result, an inadvertent ESFAS actuation would occur on both units if the 120 volt AC vital buses are not restored in a specified period of time. Because of the configuration and design of the offsite electrical distribution system, the loss of both 13kV service transformers or the grid would result in a LOOP to both units. If the single failure during a LOOP event was a loss of the 21 DC bus, the immediate impact would be the loss of 120 volt AC vital buses, 1Y02 on Unit 1 and 2Y02 on Unit 2, both of which are powered from the 21 DC bus via inverters. The loss of 1Y02, 2Y02, and the 21 DC bus results in the loss of the ability to power the safety related 4kV buses, 14 and 24, via the 1B EDG and 2B EDG, respectively. The inability to power the 14 and 24 buses would be due to a loss of control power for safety related 4kV breakers; the loss of ESFAS ZB actuation channel which prevents the automatic start of the 1B EDG during an undervoltage condition and the loss of field flash for the 2B EDG. The loss of 1Y02 and 2Y02 would result in a trip of one sensor channel of ESFAS on each unit. Because 1B EDG and 2B EDG are not available to immediately supply the battery chargers for the 12 DC bus, the 12 DC bus would lose power after approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> into this event. The loss of the 12 DC bus would then result in the loss of the 1Y03 and 2Y03 120 volt AC vital buses on Unit 1 and Unit 2, respectively, once the batteries had been depleted. As a result of the loss of a second sensor channel of ESFAS and AFAS on each unit, inadvertent ESFAS and AFAS actuations would occur on both units due to meeting ESFAS two out of four coincidence logic on the ESFAS ZA actuation channel. An inadvertent ESFAS actuation includes safety injection actuation, containment isolation, steam generator isolation, containment spray actuation, recirculation actuation, and containment radiation signal.

An inadvertent AFAS actuation would start the AFW system.

The inspectors reviewed the procedural guidance to address this event and identified that a critical step to restore the 120 volt AC buses was not provided in the procedures.

The following discussion is based on Unit 1; Unit 2 has similar steps that would be carried out simultaneously by Unit 2 operators. During this event, Unit 1 operators would enter EOP-8 due to the loss of the 21 DC bus. EOP-8 directs operators to AOP-7J. In general, the first step to restore the 21 DC bus is to determine the cause of the loss of power. The next major step is to energize 1Y02 from the inverter backup bus, 1Y11, per Operating Instruction (OI) 26B, 120 Volt Vital AC and Computer AC. OI-26B Section 6.4, Transferring a 120V Vital AC Bus from Its Inverter to the Inverter Backup Bus, Initial Condition, Step 2, requires operators to verify voltage on the inverter backup bus 1Y11. Inverter backup bus 1Y11 is normally powered from the 480 volt AC bus 14A via 480 volt AC MCC 104R. However, the inverter backup bus 1Y11 would be de-energized because the B train (1B EDG, 14 4kV bus, 14A 480 volt AC bus) would not be available.

1Y11 could be supplied from its alternate 480 volt AC power supply, MCC 114R and operators are trained to establish initial conditions prior to implementing a procedure.

However, OI-26B, Initial Condition 6 and 7, stated, if transferring a Unit 1/Unit 2 Vital AC Bus to the inverter backup bus, then MCC 104R/204R and MCC 114R/214R are not tied. Neither AOP-7J nor EOP-8 provides instructions to cross-tie MCC 104R to MCC 114R to energize 1Y02 through 1Y11. The final major step in AOP-7J is to energize the 21 DC bus after the cause of the problem has been identified and then restore power per OI-26A, 125 Volt Vital DC. Vital bus 1Y02 must be energized within the specified time (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for a LOOP event) to prevent an inadvertent ESFAS and AFAS actuations. The inadvertent ESFAS and AFAS actuations would occur on both units because the steps for Unit 2 are similar.

The inspectors determined that the event would be further complicated if a LOCA on either unit occurred coincidental with a LOOP with the single failure of the 21 DC bus, which is an event within the design bases of each unit. During this event, the battery on the 12 DC bus would be depleted within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (vice 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for the LOOP event) due to the additional loads started to address the LOCA. This would result in a loss of the second ESFAS and AFAS sensor channel on each unit and inadvertent ESFAS and AFAS actuations if the first channel is not restored within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

As stated above, the 11 and 21 DC buses are the main buses in the DC electrical distribution system. The inspectors noted that the 21 DC bus is the worst case single failure of the two buses because the inverter backup buses (1Y11 and 2Y11), from the 480 volt AC side, are normally powered from the 1B EDG and 2B EDG which would not be available to perform their safety function after the the loss of the 21 DC bus with a LOOP. In a loss of the 11 DC bus the 1B EDG and 2B EDG would still be available to power the inverter backup buses and thus, cross-tie of the 480 volt AC vital bus MCCs would not be necessary.

The inspectors concluded that EOP-8 and/or AOP-7J do not contain adequate instructions to cross-tie the 480 volt AC vital MCCs for this design basis event. The inspectors noted that CENG does have other procedures that could be used to perform the cross-tying step; however, these procedures are not referenced in EOP-8 and/or AOP-7J. In addition, the inspectors concluded that OI-26B Initial Condition 6 and 7 conflict with the conditions of this event that require cross-tying the 480 volt AC vital MCCs. The inspectors noted that cross-tie of the 480 volt AC vital MCCs is a significant step to restoration of the vital 120 volt AC channels (1Y02 and 2Y02).

Immediate corrective actions included entering this issue into CENGs CAP (CR-2013-007311 and CR-2013-007318). Corrective actions included revising AOP-7J and OI-26B to address the identified deficiencies. The revision to AOP-7J included the steps to cross-tie MCC 104R to 114R (MCC 204R to 214R for Unit 2) to energize the inverter backup bus 1Y11 (2Y11 for Unit 2). The revision to OI-26B included a note to operators clarifying that Initial Condition 6 and 7 do not apply during emergency conditions.

Analysis:

The inspectors determined that the failure to maintain adequate procedural guidance to address the loss of the 21 DC Bus with a LOOP was a performance deficiency that was within CENG staffs ability to foresee and correct and should have been prevented. Specifically, EOP-8 and/or AOP-7J did not provide instructions to cross tie the vital 480 volt AC MCCs which is a significant step to restoration of the vital 120 volt AC channels (1Y02 and 2Y02). The finding is more than minor because it is associated with the procedure quality attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, following a LOOP and a failure of the 21 DC bus, inadvertent ESFAS and AFAS actuations would occur on both units if power is not restored to 1Y02 and 2Y02. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 1, Initiating Events Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency was not reflective of current licensee performance. Specifically, the inspectors determined that this was a legacy procedure issue and did not note any recent reasonable opportunities for CENG personnel to identify this issue.

Enforcement:

TS 5.4.1, Procedures, states, in part, written procedures shall be established, implemented, and maintained covering the following activities: The applicable procedures recommended by Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978. Section 6 of Appendix A to RG 1.33, Procedures for Combating Emergencies and Other Significant Events, includes procedures for Loss of Electrical Power (and/or degraded power sources). Contrary to the above, prior to September 11, 2013, CENG staff did not establish, implement, and maintain adequate procedural guidance in EOP-8 and/or AOP-7J. Specifically, EOP-8 and/or AOP-7J did not provide instructions to cross-tie vital 480 volt AC MCCs which is a significant step in the restoration of the vital 120 volt AC channels (1Y02 and 2Y02) following a design bases LOOP with a single failure of the 21 DC bus. As a result, inadvertent ESFAS and AFAS actuations could occur on both units during this event. Immediate corrective actions included entering the issue into the CAP as CR-2013-007311 and CR-2013-007318. Planned corrective actions include revisions to AOP-7J and/or OI-26B.

Because this violation was of very low safety significance (Green) and was entered into CENGs CAP (CR-2013-007311 and CR-2013-007318), the issue is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV-05000317/318/2013005-01: Inadequate Emergency and Abnormal Operating Procedures for the Loss of the 21 DC Bus)

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistent with information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

Loss of coolant incident filter fan damper repair on October 3, 2013

11 AFW turbine trip linkage inspection and trip springs replacement on October 28, 2013

21 SW air compressor discharge relief valve (2RV5200A) replacement on November 14, 2013

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and CENGs procedural requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

STP-O-65B-2, 21 SRW subsystem valve test on October 15, 2013 (IST)

STP-I-525C-2, AFAS pipe rupture LOOP calibration steam generator channel ZE 21 steam generator motor train on November 4, 2013

STP-O-9A-1, AFAS equipment response time test on November 13, 2013

STP-O-7D-1, quarterly B train engineered safety features logic test on November 15, 2013

b. Findings

Introduction:

The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, because CENGs IST procedures did not provide instructions to preclude preconditioning of the CAC emergency outlet valves.

Description:

On August 12, 2013, during a review of STP-O-065B-2, 21 SRW Subsystem Operability Test, the inspectors identified that the procedure was written such that a full stroke of the CAC emergency outlet valves was allowed prior to performance of the IST stroke time testing of the valves in the open direction.

Per STP-O-065B-2, the CAC inlet valve is stroke time tested first. To set up for this test, the procedure directs the operator to shut and/or verify shut both the CAC normal outlet valve and the CAC emergency outlet valve. The CAC normal outlet valve is normally open. The CAC emergency outlet valve is normally closed but may be open depending on containment environmental conditions. If the emergency outlet valve was already open, the procedure required that operators place the valve in the closed position. After the inlet valve had been timed in both the open and shut directions, the procedure directed the operators to reposition both outlet valves at the discretion of the senior reactor operator prior to stroke time testing the emergency outlet valve open. The inspectors noted that the emergency outlet valve was often repositioned to the open position after the inlet valve had been stroke time tested. If the emergency outlet valve had been repositioned to the open position, then a full stroke of the valve had already occurred prior to its stroke time test. To determine if operators were preconditioning the emergency outlet valve, the inspectors reviewed computer trend data of SRW flow for four surveillance tests since December 2012. 21 CAC emergency outlet valve 2-CV-1582 and 24 CAC emergency outlet valve 2-CV-1593 were selected for this review. The inspectors noted, based on the trend data, that 2-CV-1582 was fully stroked prior to its IST stroke time open test during all four surveillance tests and that 2-CV-1593 was fully stroked prior to its IST stroke time open test during three of the four surveillances. The inspectors noted that this issue is applicable to both Unit 1 and Unit 2 since the procedures were similar.

The inspectors determined that the manner in which these valves were cycled was unacceptable preconditioning of the CAC emergency outlet valves. NRC Inspection Manual Part 9900 Technical Guidance, Maintenance - Preconditioning of Structures, Systems, And Components before Determining Operability, states in part, the NRC expects surveillances and testing process of SSCs to be evaluated in an as-found condition. It also defines preconditioning as the alteration, variation, manipulation, or adjustment of the physical condition of an SSC before Technical Specification surveillance or American Society of Mechanical Engineers code testing that will alter one or more of an SSCs operational parameters, which results in acceptable test results.

Such changes could mask the actual as-found condition of the SSC and possibly result in an inability to verify the operability of the SSC. In addition, unacceptable preconditioning could make it difficult to determine whether the SSC would perform its intended function during an event in which the SSC might be needed. It also states that, influencing test outcome by performing valve stroking, preventive maintenance, pump venting or draining, or manipulating SSCs does not meet the intent of the as-found testing expectations. The inspectors also noted that the finding is similar to the example (2)(b) under the unacceptable preconditioning discussion of the Part 9900 Technical Guidance, in that, inlet and outlet heat exchanger valves, with a safety function to open, were time stroke in the open direction using a single switch that cycle both valves at the same time. At the completion of one valve open stroke time, the other valve had been cycled in the open direction without recording the time results.

CENG entered this issue in their CAP (CR-2013-006504). Immediate corrective actions included submitting changes to the surveillance procedure to preclude preconditioning of the CAC emergency outlet valves.

Analysis:

The inspectors determined that the failure of CENG staff to provide a surveillance procedure to preclude preconditioning of the CAC emergency outlet valves was a performance deficiency that was within CENG staffs ability to foresee and correct and should have been prevented. The finding is more than minor because it is associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e.

core damage). Specifically, preconditioning of the CAC emergency outlet valve prior to performing IST stroke time testing could mask valve degradation. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions.

The inspectors determined that this finding was of very low safety significance (Green)because the finding did not affect the design or qualification of a mitigating SSC, did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant, in accordance with maintenance rule program, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The inspectors determined that the finding has a cross-cutting aspect in the area of Human Performance, Resources, because CENG staff failed to ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, CENG staff did not provide a complete and accurate procedure that would preclude preconditioning of the CAC emergency outlet valves during in-service testing H.2(c).

Enforcement:

10 CFR 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 SSCs 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. It further states that, test procedures shall include provisions for assuring that all prerequisites for the given test have been met, that adequate test instrumentation is available and used, and that the test is performed under suitable environmental conditions. Contrary to the above, prior to August 12, 2013, CENG staff did not assure that all testing to demonstrate that CAC emergency outlet valves would perform satisfactorily in service was identified in a written test procedure and the test procedure did not include provisions for assuring all prerequisites for the given test had been met. Specifically, STP-O-65B-1 and STP-O-065B-2, SRW Subsystem Operability Test, did not include instructions to preclude preconditioning of the CAC emergency outlet valves prior to performance of stroke time testing of the valves which could result in masking valve degradation. Immediate corrective actions included entering this issue in the CAP as CR-2013-006504. Corrective actions included the revision of these procedures to prevent unacceptable preconditioning of the CAC emergency outlet valves. Because this violation was of very low safety significance (Green) and was entered into CENGs CAP (CR-2013-006504), the issue is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy.

(NCV-05000317/318/2013005-02: Preconditioning of Containment Air Coolers Emergency Outlet Valves)

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

From December 11 - 13, 2013, the inspectors reviewed and assessed CENG staffs performance in assessing the radiological hazards and exposure control in the workplace.

The inspectors used the requirements in 10 CFR 20 and guidance in RG 8.38, Control of Access to High and Very High Radiation Areas for Nuclear Plants; CCNPP TS; and CENGs procedures required by TS as criteria for determining compliance.

Inspection Planning

The inspectors reviewed CENG staffs performance indicators (PIs) for 2012 and the first three quarters of 2013 for the occupational exposure cornerstone for CCNPP.

Radiological Hazard Assessment

The inspectors reviewed the last two radiological surveys from the waste gas decay tanks, the charging pump rooms, and the 69 auxiliary building. The inspectors evaluated the adequacy and frequency of the surveys.

There were no opportunities during the inspection period for the inspectors to observe work in potential airborne radioactivity areas or to evaluate the adequacy of associated air sample measurements.

Instructions to Workers

The inspectors selected five containers holding non-exempt licensed radioactive materials. The inspectors assessed whether the containers were labeled and controlled in accordance with regulatory requirements.

Contamination and Radioactive Material Control

The inspectors evaluated whether any recent transactions involving nationally tracked sources were reported as required.

Risk-Significant High Radiation Areas and Very High Radiation Area Controls

The inspectors discussed with the Radiation Protection Manager the controls and procedures for high-risk high radiation areas and very high radiation areas (VHRAs).

The inspectors assessed whether any changes to CENG staffs relevant procedures reduced the effectiveness of worker protection.

The inspectors discussed with a first-line health physics supervisor the controls in place for special areas that have the potential to become VHRAs during certain plant operations. The inspectors evaluated CENG staffs controls for VHRAs and areas with the potential to become VHRAs to ensure that an individual was not able to gain unauthorized access to these VHRAs.

b. Findings

No findings were identified.

2RS2 Occupational As Low As Reasonably Achievable (ALARA) Planning and Controls

a. Inspection Scope

From December 11 - 13, 2013, the inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures As Low As Reasonably Achievable (ALARA). The inspectors used the requirements in 10 CFR 20, RG 8.8, Information Relevant to Ensuring that Occupational Radiation Exposures at Nuclear Power Plants will be ALARA, RG 8.10, Operating Philosophy for Maintaining Occupational Radiation Exposure ALARA, CCNPP TSs, and CENGs procedures required by TSs as criteria for determining compliance.

Radiological Work Planning

The inspectors selected the following work activities that had the highest exposure significance:

Unit 2 General Safety Initiative - 191 Project

Minor maintenance performed during a Unit 2 refueling outage

Scaffold activities performed during a Unit 2 refueling outage

Reactor path minor maintenance during a Unit 2 refueling outage

Reactor coolant pump maintenance during a Unit 2 refueling outage

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure reduction requirements for the above work activities. The inspectors compared the results achieved (dose rate reductions, actual dose) with the intended dose established in CENG staffs ALARA planning for these work activities. The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the radiation protection group actual person-hours for the work activity, and evaluated the accuracy of these time estimates. The inspectors assessed the reasons for any inconsistencies between intended and actual work activity doses.

The inspectors determined whether post-job reviews were conducted to identify lessons learned and verified that suggestions for improving dose and contamination reduction techniques were entered into CENGs CAP.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with

Complications===

a. Inspection Scope

The inspectors reviewed CENG staffs submittal of the Unit 1 and Unit 2 Initiating Events Cornerstone for the following systems for the period of October 1, 2012 through September 30, 2013:

Unit 1 unplanned scrams (IE01)

Unit 2 unplanned scrams (IE01)

Unit 1 unplanned power changes (IE03)

Unit 2 unplanned power changes (IE03)

Unit 1 unplanned scrams with complications (IE04)

Unit 2 unplanned scrams with complications (IE04)

To determine the accuracy of the PI data reported during the inspection period, the inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors also reviewed CENGs operator narrative logs, maintenance planning schedules, CRs, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness (1 sample)

a. Inspection Scope

From December 11 - 13, 2013, the inspectors sampled CENG staffs submittals for the occupational exposure control effectiveness (OR01) PI for the period from the fourth quarter 2012 through the third quarter 2013. The inspectors used the definitions and guidance contained in the Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the PI data reported.

To assess the adequacy of CENG staffs PI data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry accumulated dose alarms, dose reports, and dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized PI occurrences. The inspectors also conducted walkdowns of numerous locked high radiation area and VHRA entrances to determine the adequacy of the controls in place for these areas.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that CENG personnel entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP.

b. Findings and Observations

No findings were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by CENG personnel outside of the CAP, such as trend reports, PIs, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or CAP backlogs. The inspectors also reviewed CENGs CAP database for the second and third quarters of 2013 to assess CRs written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the NRCs daily CR review (Section 4OA2.1). The inspectors reviewed CENG staffs quarterly trend report for the third quarter of 2013, conducted under CNG-CA-1.01-1007, Performance Improvement Trending and Analysis, to verify that CENG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.

b. Findings and Observations

No findings were identified.

The inspectors evaluated a sample of departments that are required to provide input into the quarterly trend reports, which included maintenance and operations departments.

This review included a sample of issues and events that occurred over the course of the past two quarters to objectively determine whether issues were appropriately considered or ruled as emerging or adverse trends, and in some cases, verified the appropriate disposition of resolved trends. The inspectors verified that these issues were addressed within the scope of the CAP, or through department review and documentation in the quarterly trend report for overall assessment. For example, CENG staff identified a negative trend in the quality of written work instructions that is impacting maintenance personnel in the field. The inspectors verified that CENG staff had corrective actions in place to address this trend. These corrective actions include the implementation of focus teams to improve work orders; monthly work order quality meetings; and review of site and fleet procedures for conflicting guidance (CR-2013-006373). CENG personnel identified a declining trend in the area of configuration control involving component mispositioning and safety tagging events. Five component mispositions were identified during Unit 2 outage and two level 2 safety tagging events were identified in September 2013. The inspectors verified that CENG staff had corrective actions in place to address this trend. Corrective actions include monthly configuration control oversight board meetings; focused deep observations; and the usage of CNG-OP-1.01-GL006, Guidelines for Performing Clearance Activities, by work order workers.

Additionally, the inspectors identified an increase in inadequate maintenance rule functional failure (MRFF) evaluations. Within the past five months, the inspectors identified four of five inadequate MRFF evaluations. CENG personnel initiated CR-2013-006941 to document and evaluate this trend. An apparent cause evaluation was performed and determined that MRFFs were missed because CRs were not routed to the responsible system engineers to perform maintenance rule evaluations. Corrective actions to resolve this negative trend include that all hardware related CRs, on a system within the scope of the maintenance rule, would be routed to the to the system engineer to determine if a maintenance rule evaluation is required.

.3 Annual Sample:

Review of the Operator Workaround Program

a. Inspection Scope

The inspectors reviewed the cumulative effects of the existing operator workarounds, operator burdens, existing operator aids and disabled alarms, and open main control room deficiencies to identify any affect on EOP operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel had identified, assessed, and reviewed operator workarounds as specified in CNG-OP-1.01-2010, Operator Workaround/Challenge Control.

b. Findings and Observations

No findings were identified.

The inspectors determined that operator workarounds were classified, tracked, and assessed in accordance with CENGs procedures.

.4 Annual Sample:

1A EDG Inoperability and Combustion Pipe Penetration Boot Seal Degradation

a. Inspection Scope

The inspectors performed an in-depth review of CENG staffs evaluations and the effectiveness of the corrective actions associated with the 1A EDG becoming inoperable during Hurricane Irene on the evening of August 27, 2011. Specifically, wind-driven rain passed through floor penetrations and entered the 1A2 speed switch connector causing the switch to short-circuit. CENG staff completed a root causal analysis (CR-2011-008708) and determined the root cause to be improper installation and design of the penetration around the 1A2 combustion air intake pipe on the 80 elevation of the 1A EDG building. An additional contributing cause was determined to be configuration control of the floor drains on that level, in particular, having sock filters installed in those drains to collect dust and debris. CR-2012-000468 and CR-2012-005544 were issued after CENG staff identified that there was no documentation associated with the impact of wind-driven rain on the 1A EDG building and that the 1A EDG intake pipe floor penetration pipe boots were not leak tight.

The inspectors assessed CENG staffs problem identification threshold, associated root cause analyses and evaluations, extent of condition reviews, and the prioritization and timeliness of actions to evaluate whether they were appropriately identifying, characterizing, and correcting problems associated with the issue; and whether the planned or completed corrective actions were appropriate and met the requirements of their CAP. The inspectors compared the actions taken to the requirements of CENGs CAP and 10 CFR 50, Appendix B. The inspectors reviewed the applicable CRs and associated documents, including calculations, work orders, and post-maintenance test results. Specifically, the inspectors reviewed CENG staffs identification of weaknesses and corrective actions to prevent recurrence, as well as additional actions to address other probable and contributing causes identified in the root cause evaluation. The inspectors also performed field walkdowns of the 1A EDG building including the generator, tandem diesel engines, and associated systems to assess their material condition. In addition the inspectors interviewed engineering personnel to assess the acceptability and effectiveness of the implemented corrective actions.

b. Findings and Observations

No findings were identified.

The inspectors determined that CENG personnel appropriately identified the cause of the 1A EDG failure and contributing factors, and properly evaluated the matter in accordance with CENGs procedures. The inspectors reviewed CENG staffs Root Cause Analysis Report and several of the related CRs, calculations, and evaluations and concluded CENG staff had appropriately evaluated the problems and identified the necessary corrective actions. The inspectors determined that the corrective actions were reasonable and addressed the probable and contributing causes.

The inspectors found CENG staffs conclusion that the 1A EDG building floor drain system is adequately designed for the maximum expected rainfall, provided that a filter that is subject to plugging is not inserted into the drains, to be reasonable. The inspectors found CENG staffs actions to both remove the floor drain sock filters and additionally install a 2-inch berm around the intake pipe floor penetrations (FP-308 and FP-309) to be appropriate and conservative. The inspectors found CENG staffs actions to preclude recurrence of the flooding situation on the 80 elevation and prevent water from reaching the diesel engines and instrumentation to be reasonable.

The inspectors reviewed the completed work, evaluations, and testing regarding the floor penetration boot seals. The boot seal assemblies are safety related as they serve to maintain the pressure boundary between the environment and the floors below the 80 elevation. In addition, the boot seals are intended to inhibit tornado-induced decompression of the rooms below. Post-maintenance testing revealed some minor leakage past the seal assemblies. The inspectors reviewed the design of the Promatec seal assemblies, CENG staffs evaluation of sealants, and CENG staffs evaluation quantifying the slight leakage past the seals. The inspectors determined that the assumptions CENG used throughout the calculations when evaluating 1A EDG building pressure changes during a tornado exhibited acceptable conservatism. Given the conservative inputs (i.e. size of a gap, temperature, discharge coefficient, and duration of the tornado), the inspectors found CENG staffs conclusion, that the 1A EDG building resultant pressure change was negligible, to be reasonable.

Notwithstanding, the inspectors noted an error in one of the interim calculations. CENG staff entered the issue into their CAP, immediately made the appropriate corrections and re-evaluated the pressure change across the seals to ensure the final conclusions remained valid. The inspectors reviewed the new interim calculation and determined there was no impact on the final conclusion or results of the technical evaluation.

Overall, the inspectors found that the 1A EDG issues had been accurately documented within the CAP. The inspectors determined that CENG personnel performed appropriate extent of condition reviews as well as internal and external operating experience reviews to assess the potential impact on other EDG system components. The inspectors determined that CENG staffs associated technical evaluations were sufficiently thorough and were based on focused plant walkdowns, vendor guidance, sound engineering judgment, testing, and relevant operating experience. The inspectors concluded that CENG staffs assigned corrective actions were aligned with the identified causal factors, reasonable, appropriately documented, and adequately tracked for completion. Based on the documents reviewed, plant walkdowns and engineer interviews, the inspectors noted that CENG personnel identified problems and entered them into the CAP at a low threshold.

4OA5 Other Activities

In Inspection Report 05000317, 05000318/2012004 (ADAMS Accession Number ML12311A197) issued on November 6, 2012, the completion of two biennial samples for Inspection Procedure 71124.05, Radiation Monitoring Instrumentation, and Inspection Procedure 71124.06, Gaseous and Liquid Effluent Treatment, were documented in Section 2RS5 and 2RS6, respectively. However, these samples were not entered into the NRCs Reactor Program System used to track sample completion. The completion of these samples will be documented in the Reactor Program System associated with this inspection report since Inspection Cycle 42 (January 1, 2012 - December 31, 2012)has been closed. All required samples were completed in the biennial inspection period from January 1, 2012 - December 31, 2013. This entry is administrative in nature only.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 8, 2014, the inspectors presented the inspection results to Mr. George Gellrich, Site Vice President, and other members of the CENG staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

CENG Personnel

G. Gellrich, Site Vice President

M. Flaherty, Plant General Manager

D. Baker, Supervisor, Electrical & Controls System Engineering

P. Beavers, General Supervisor, Operations Training

R. Bleacher, Operations Technical Writer, Operations Support

C. Blue, ALARA Supervisor

H. Crockett, Supervisor, Engineering

H. Daman, Manager, Maintenance

K. Robinson, Manager, Engineering Services

J. Detchamendy, Supervisor, Radiation Protection

B. Erdman, Supervisor, Radiation Protection

J. Gaffey, Senior Mechanical Design Engineer

J. Gaines, General Supervisor, Shift Operations

B. Hartle, Operations Technical Procedures Leader, Operations Support

S. Henry, Manager, Operations

J. Jaeger, Licensed Operator Instructor/Examiner

A. Kelly, Supervisor, Licensed Operator Requalification Training

B. Lang, Principal Engineer, Engineering

D. Lauver, Director, Licensing

D. Lavato, Principal Operations Instructor/Exam Developer

M. Moore, Manager, Nuclear Training

C. Neyman, Senior Engineering Analyst, Licensing

D. Robertson, Simulator Tester

A. Simpson, Supervisor, Licensing

K. Thompson, Medical Group, Nurse Practitioner

T. Unkle, Engineering Analyst, Licensing

J. York, General Supervisor, Radiation Protection

LIST OF ITEMS

Opened and Closed

05000317/318/2013005-01 NCV Inadequate Emergency and Abnormal Operating Procedures for the Loss of the 21 DC Bus (Section 1R15)

05000317/318/2013005-02 NCV Preconditioning of Containment Air Coolers Emergency Outlet Valves (Section 1R22)