IR 05000445/2014003

IR 05000445-14-003, 05000446-14-003; 03/28/2014 - 06/26/2014; Comanche Peak Nuclear Power Plant, Units 1 & 2; Integrated Inspection Report, Plant Modifications, Refueling and Other Outage Activities, Radiological Hazard Assessment and Expos

ML14218A072
Person / Time
Site:	Comanche Peak
Issue date:	08/06/2014
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Flores R Luminant Generation Co
Walker W
References
EA-14-123 IR-14-003
Download: ML14218A072 (76)

Text

UNITED STATES ust 6, 2014

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000445/2014003 AND 05000446/2014003 AND NOTICE OF VIOLATION

Dear Mr. Flores:

On June 26, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Comanche Peak Nuclear Power Plant, Units 1 and 2. On July 8, 2014, the NRC inspectors discussed the results of this inspection with Mr. K. Peters, Site Vice President, and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented seven findings of very low safety significance (Green) in this report. Five of these findings involved a violation of NRC requirements. One of these violations was determined to be Severity Level IV under the traditional enforcement process. The NRC is treating four of the violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy, which can be found on the NRCs Web site at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.

The enclosed inspection report discusses a violation associated with a finding of very low safety significance (Green). The NRC evaluated this violation in accordance with Section 2.3.2.a of the NRC Enforcement Policy. We determined that this violation did not meet the criteria to be treated as a non-cited violation because you failed to implement corrective actions and restore compliance in a timely manner for two non-cited violations associated with the fire protection program.

The NRC has determined that the reason, corrective actions taken and planned to address recurrence, and the date when full compliance will be achieved for this violation is adequately addressed and captured on the docket in a letter from Luminant Generation Company, LLC, dated June 10, 2014 (ML14188C054). Therefore, you are not required to respond to this letter unless the description herein does not accurately reflect your corrective actions or your position.

In that case, or if you choose to provide additional information, you should follow the instructions specified in the enclosed Notice. Further, inspectors documented licensee-identified violations which were determined to be of very low safety significance in this report. The NRC is treating these violations as NCVs consistent with Section 2.3.2.a of the NRC Enforcement Policy.

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

If you disagree with a cross-cutting aspect assignment in this report, then 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 the Comanche Peak Nuclear Power Plant, Units 1 and 2.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's Rules of Practice and Procedure, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)

component of the NRC's Agencywide Documents 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/

Wayne C. Walker, Branch Chief Project Branch A Division of Reactor Projects Docket Nos.: 50-445, 50-446 License Nos.: NPF-87, NPF-89

Enclosure:

Inspection Report 05000445/2014003 and 05000446/2014003 w/Attachments:

1. Supplemental Information 2. Request for Information -

O

REGION IV==

Docket: 05000445, 05000446 License: NPF-87, NPF-89 Report: 05000445/2014003 and 05000446/2014003 Licensee: Luminant Generation Company LLC Facility: Comanche Peak Nuclear Power Plant, Units 1 and 2 Location: 6322 N. FM-56, Glen Rose, Texas Dates: March 28 through June 26, 2014 Inspectors: J. Kramer, Senior Resident Inspector R. Kumana, Resident Inspector D. Proulx, Senior Project Engineer W. Sifre, Senior Reactor Inspector M. Williams, Reactor Inspector L. Brandt, Reactor Inspector L. Carson II, Senior Health Physicist N. Greene, Ph.D., Health Physicist G. Guerra, CHP, Emergency Preparedness Inspector S. Alferink, Reactor Inspector J. Watkins, Reactor Inspector Approved By: Wayne Walker Chief, Project Branch A Division of Reactor Projects-3-

SUMMARY

IR 05000445/2014003, 05000446/2014003; 03/28/2014 - 06/26/2014; Comanche Peak Nuclear

Power Plant, Units 1 and 2; Integrated Inspection Report, Plant Modifications, Refueling and Other Outage Activities, Radiological Hazard Assessment and Exposure Controls, Problem Identification and Resolution, and Follow-up of Events and Notices of Enforcement Discretion The inspection activities described in this report were performed between March 28, 2014, and June 26, 2014, by the resident inspectors at the Comanche Peak Nuclear Power Plant and inspectors from the NRCs Region IV office. Seven findings of very low safety significance (Green) are documented in this report. Five of these findings involved violations of NRC requirements; one of these violations was determined to be Severity Level IV under the traditional enforcement process. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red), which is determined using Inspection Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects Within the Cross-Cutting Areas.

Violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.

Cornerstone: Initiating Events

Green.

The inspectors reviewed a self-revealing finding for the failure to follow the design modification process. The licensee implemented a design modification using incorrect technical information. The personnel who conducted the design modification walk-downs did not fully understand their responsibility and the licensees work organization did not ensure that anyone actually verified the physical details of the cable route. As a result, the design modification was inadequate and an incorrect cable was cut which caused a loss of all offsite power to the safety-related 6.9 kV busses on both units. The licensee suspended the modification activities, repaired the damaged offsite power cable, and restored offsite power to the safety-related 6.9 kV busses. The licensee entered the finding into the corrective action program as Condition Report CR-2013-012287.

The failure to follow the electronic design change process procedure was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and adversely 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. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 1, Initiating Event Screening Questions, the finding was determined to be of very low safety significance (Green) because although the finding involved the complete loss of a support system that caused an initiating event, it did not involve the loss of affected mitigation equipment. The finding has a human performance cross-cutting aspect associated with field presence because the licensee failed to ensure proper oversight of contractors to ensure deviations from standards and expectations were promptly corrected [H.2]. (Section 4OA3.2)

Green.

The inspectors reviewed a self-revealing finding for the failure to properly plan and review work activities to ensure equipment and personnel safety. Specifically, the licensee failed to ensure the work instructions met the requirements of Procedure STA-606, Control of Maintenance and Work Activities, Revision 32. As a result, during the implementation of a modification, personnel used an inadequate work instruction and cut the incorrect cable which caused a loss of all offsite power to the safety-related 6.9 kV busses on both units.

The licensee suspended the modification activities, repaired the damaged offsite power cable, and restored offsite power to the safety-related 6.9 kV busses. The licensee entered the finding into the corrective action program as Condition Report CR-2013-012287.

The failure to follow procedure and provide adequate work instructions was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Initiating Events Cornerstone and adversely 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. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 1, Initiating Event Screening Questions, the finding was determined to be of very low safety significance (Green) because although the finding involved the complete loss of a support system that caused an initiating event, it did not involve the loss of affected mitigation equipment. The finding has a human performance cross-cutting aspect associated with avoiding complacency because the licensee failed to ensure that work planning personnel planned for the possibility of mistakes and latent issues and did not implement appropriate error reduction tools [H.12]. (Section 4OA3.2)

Cornerstone: Mitigating Systems

Green.

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

Criterion V, Instructions, Procedures, and Drawings, for the failure to follow procedure for brazing copper joints. Specifically, personnel failed to follow procedure and exercise sufficient care to assure the copper tubing was not overheated during a brazing activity. As a result, personnel overheated copper joints and caused the inoperability of an uninterruptible power supply air conditioning unit when the component developed a leak.

The licensee repaired the leak to the uninterruptible power supply air conditioning unit. The licensee entered the finding into the corrective action program as Condition Report CR-2013-002298.

The failure to follow procedure for brazing copper tubing was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2,

Mitigating System Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding did not represent an actual loss of at least a single train of equipment for greater than its technical specification allowed outage time.

The inspectors determined that the finding was not representative of current license performance and no cross-cutting aspect was assigned. (Section 4OA2.2)

Green.

The inspectors identified a violation of License Condition 2.G for the failure to implement and maintain in effect all provisions of the approved fire protection program.

Specifically, the inspectors identified two examples where the licensee failed to implement corrective actions and restore compliance in a timely manner for two non-cited violations associated with the fire protection program. The licensee implemented compensatory measures that included: hourly fire watches, changes to the safe shutdown procedures, and administrative changes to the fire protection program. The licensee entered the finding into the corrective action program as Condition Report CR-2014-007713.

The failure to implement corrective actions and restore compliance in a timely manner for two violations associated with the fire protection program was a performance deficiency.

The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the potential loss of the credited charging pump or spurious opening of a power-operated relief valve adversely affected the availability, reliability, and capability of the systems required to achieve and maintain safe shutdown in the event of a fire. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, because it affected the ability to reach and maintain safe-shutdown conditions in case of a fire. A senior reactor analyst performed a Phase 3 evaluation to determine the risk significance of this finding. The senior reactor analyst determined this finding was of very low safety significance (Green). The finding has a human performance cross-cutting aspect associated with work management because the licensee failed to include the identification and management of risk commensurate to the work performed [H.5]. (Section 4OA2)

Cornerstone: Barrier Integrity

Green-Severity Level IV. The inspectors identified a non-cited violation of 10 CFR 50.59,

Changes, Tests, and Experiments, for failure to conduct an adequate written evaluation and submit a license amendment for a change to the facility that required a technical specification amendment. Specifically, the licensee changed Procedure NUC-211,

Surveillance of Region II Storage Limitations, Revision 1, to allow for storage of uprated fuel in Region II (high density racks) of the spent fuel pool using a methodology for fuel burnup penalties that had not been previously approved by the NRC and therefore, required an amendment to Technical Specification 3.7.17 Spent Fuel Assembly Storage prior to implementation. Subsequently, the licensee stopped all fuel movement in Region II of the spent fuel pool unless notifying the NRC prior to the movement. The licensee entered the finding into the corrective action program as Condition Report CR-2014-004693.

The failure to perform an adequate 10 CFR 50.59 evaluation and obtain prior NRC approval for a change to the facility that involved a change to the technical specifications was a performance deficiency. The inspectors concluded that this issue involved traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. This performance deficiency is more than minor because it was associated with the reactivity control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Because the significance determination process does not directly address spent fuel pool criticality, a senior reactor analyst evaluated this issue using Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Based on calculations provided by the licensee, the analyst determined that even with all uncertainties included in the calculations, the spent fuel pools would remain subcritical under all conditions, including a complete dilution of the borated water. The analyst qualitatively considered a completed dilution of the spent fuel pools to be a very low probability event. Therefore, the analyst concluded that this issue was of very low safety significance (Green). Because this issue was considered to be Green, it is treated as a Severity Level IV violation in traditional enforcement. The inspectors determined that the finding was not representative of current license performance and no cross-cutting aspect was assigned. (Section 1R18)

Green.

The inspectors reviewed a self-revealing non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to have documented instructions of a type appropriate to the circumstances when performing an activity affecting quality. Specifically, the licensee failed to have appropriate instructions for filling a Unit 2 component cooling water heat exchanger. As a result, component cooling water was inadvertently isolated to spent fuel pool heat exchanger X-02. The operators immediately stopped the filling activity and restored cooling water to the spent fuel pool heat exchanger. The licensee entered the finding into the corrective action procedure as Condition Report CR-2014-004111.

The failure to have appropriate instructions for filling a Unit 2 component cooling water heat exchanger was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that spent fuel pool design barriers protect the public from radionuclide releases caused by accidents or events. Using Inspection Manual Chapter 0609, Attachment 04,

Initial Characterization of Findings, and Appendix A, Exhibit 3, Barrier Integrity Screening Questions, the finding was determined to be of very low safety significance (Green)because the finding did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis. The finding has a human performance cross-cutting aspect associated with work management because the licensee failed to ensure that the work process identified and managed the risk commensurate with the work [H.5].

(Section 1R20)

Cornerstone: Occupational Radiation Safety

Green.

The inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.7.1 resulting from the licensees failure to control high radiation areas with radiation levels of 100 millirem per hour or greater on three separate occasions. In each instance, the licensee failed to adequately inform the worker of current radiological dose rates prior to entry and the worker entered a posted high radiation area without proper knowledge of the radiological conditions (dose rates). Consequently, the workers received unanticipated high dose rate alarms on their electronic alarming dosimeters at 563 millirem per hour, 274 millirem per hour, and at 750 millirem per hour, respectively. As immediate corrective actions, the licensee performed follow-up surveys, coached the involved individuals, and reviewed the radiologically controlled area entry card requirements. The licensee entered the three issues into the corrective action program as Condition Reports CR-2013-004154, CR-2014-003464, and CR-2014-003997.

The failure to provide workers with proper knowledge of high radiation area radiological conditions prior to entry is a performance deficiency. The performance deficiency is more than minor because it impacted the program and process attribute (exposure control) of the Occupational Radiation Safety Cornerstone and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation. Specifically, worker entry into high radiation areas without knowledge of the radiological conditions placed them at increased risk for unnecessary radiation exposure.

Using Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the finding was determined to be of very low safety significance (Green) because: (1) it was not an as low as is reasonably achievable finding, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. The finding has a human performance cross-cutting aspect associated with teamwork because the workers failed to demonstrate and execute a strong sense of communication and collaboration in connection with the operational activities involved in the finding to ensure nuclear safety was maintained

[H.4]. (Section 2RS1)

Licensee-Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and associated corrective action tracking numbers are listed in Section 4OA7 of this report.

PLANT STATUS

Unit 1 began the inspection period at approximately 100 percent power. On May 17, 2014, operators reduced reactor power to approximately 70 percent power for turbine valve testing.

The unit returned to approximately 100 percent power the same day and operated at that power level for the remainder of the inspection period.

Unit 2 began the inspection period at approximately 100 percent power. On March 29, 2014, the operators shut down Unit 2 to begin a scheduled refueling outage. On April 27, 2014, the outage ended when the main generator output breakers were closed and Unit 2 was placed on the grid. On April 29, 2014, the unit returned to approximately 100 percent power and operated at that power level for the remainder of the inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

On April 2, 2014, the inspectors completed an inspection of the stations readiness for impending adverse weather conditions. The inspectors performed a walk-down of the plant to evaluate the potential missile hazards and discussed the potential hazards with the outage control center personnel. The inspectors reviewed plant design features and the licensees procedures to respond to high winds. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant.

The inspectors used Operating Experience Smart Sample (OpESS) 2012/01, High Wind Generated Missile Hazards, as supplemental guidance for the inspection.

These activities constitute completion of one readiness for impending adverse weather conditions sample as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant systems:

April 14, 2014, Unit 2, residual heat removal pump 2-02 when residual heat removal pump 2-01 was unavailable due to maintenance May 1, 2014, Unit 2, diesel generator 2-01 following extended generator outage maintenance May 12, 2014, Unit 1, service water pump 1-02 when service water pump 1-01 was unavailable due to maintenance May 15, 2014, Unit 2, diesel generator 2-01 and motor driven auxiliary feedwater pumps 2-01 and 2-02 when the turbine driven auxiliary feedwater pump was unavailable due to corrective maintenance The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. The inspectors verified that critical portions of the systems were correctly aligned for the existing plant configuration.

These activities constitute completion of four partial system walk-down samples as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

The inspectors performed a complete system walk-down inspection of the Unit 2 turbine driven auxiliary feedwater system. The inspectors reviewed the licensees procedures and system design information to determine the correct turbine driven auxiliary feedwater system lineup for the existing plant configuration. The inspectors also reviewed the updated final safety analysis report, technical specifications, work orders, and condition reports applicable to the turbine driven auxiliary feedwater system. The inspectors visually verified that the system was correctly aligned for the existing plant configuration.

These activities constitute completion of one complete system walk-down sample as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on the following plant areas important to safety:

April 14, 2014, fire zone AA21a, component cooling water heat exchanger room June 18, 2014, fire zone EA57, Unit 1 inverter and battery room corridor June 18, 2014, fire zone EA54, Unit 2 inverter and battery room corridor June 18, 2014, fire zone AA21a, auxiliary building elevation 790 rooms For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.

These activities constitute completion of four quarterly inspection samples as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

On April 2, 2014, the inspectors completed an inspection of the stations ability to mitigate flooding due to internal causes. After reviewing the licensees flooding analysis, the inspectors chose the following plant areas containing risk-significant structures, systems, and components that were susceptible to flooding:

Safety chill water rooms 115A and 115B Uninterruptible power supply air conditioning rooms 115C and 115D The inspectors reviewed plant design features and licensee procedures for coping with internal flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether personnel actions credited for flood mitigation could be successfully accomplished.

These activities constitute completion of one flood protection measures inspection sample as defined in Inspection Procedure 71111.06.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

On April 23, 2014, the inspectors completed an inspection of the readiness and availability of risk-significant heat exchangers. The inspectors reviewed process data from the licensees instrumentation and performed a walk-down of the residual heat removal heat exchanger 2-02 to observe its performance and material condition.

These activities constitute completion of one heat sink performance annual review inspection sample as defined in Inspection Procedure 71111.07.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

The activities described in subsections 1 through 4 below constitute completion of one inservice inspection activities sample as defined in Inspection Procedure 71111.08.

.1 Nondestructive Examination Activities and Welding Activities

a. Inspection Scope

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Feedwater TCX-2-2203-H17-WA Magnetic Particle Residual Heat TCX-1-4101-12 Ultrasonic Removal Main Steam TCX-2-2400-H1 Visual (VT-3)

Main Steam TCX-2-2400-H9 Visual (VT-3)

Feedwater TCX-2-2203-H5-WA Magnetic Particle Main Steam TCX-2-2400-H1-WA Magnetic Particle Safety Injection TCX-1-4102-13 Ultrasonic Main Steam TCX-2-2400-H2 Visual (VT-3)

The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant TCX-1-4100-1 Ultrasonic, Eddy Current Hot leg Reactor Coolant TCX-1-4200-1 Ultrasonic, Eddy Current Hot leg Reactor Coolant TCX-1-4300-1 Ultrasonic, Eddy Current Hot leg Reactor Coolant TCX-1-4400-1 Ultrasonic, Eddy Current Hot leg Feedwater TCX-2-2203-H5-WA Magnetic Particle Safety Injection TCX-2-2581-H1-WA Dye Penetrant Residual Heat TCX-2-1120-1-4 Dye Penetrant Removal SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Safety Injection TCX-1-4600-4 Ultrasonic Safety Injection TCX-1-4600-15 Ultrasonic During the review and observation of each examination, the inspectors observed whether activities were performed in accordance with the American Society of Mechanical Engineers (ASME) Code requirements and applicable procedures. The inspectors also reviewed the qualifications of all nondestructive examination technicians performing the inspections to determine whether they were current.

The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Safety Injection 4408166 Gas Tungsten Arc Weld Safety Injection 4747766 Gas Tungsten Arc Weld The inspectors reviewed whether the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code Section IX requirements.

The inspectors also determined whether the essential variables were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications.

b. Findings

No findings were identified.

.2 Vessel Upper and Lower Head Penetration Inspection Activities

a. Inspection Scope

The inspectors reviewed the results of the licensees bare metal visual inspection of the reactor vessel upper and lower head penetrations to determine whether the licensee identified any evidence of boric acid challenging the structural integrity of the reactor head components and attachments. The inspectors also verified that the required inspection coverage was achieved and limitations were properly recorded. The inspectors reviewed whether the personnel performing the inspection were certified examiners to their respective nondestructive examination method.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees implementation of its boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensees boric acid corrosion control walk-down as specified in Procedure STA-737, Boric Acid Corrosion Detection and Evaluation, Revision 6. The inspectors reviewed whether the visual inspections emphasized locations where boric acid leaks could cause degradation of safety significant components, and whether the engineering evaluation used corrosion rates applicable to the affected components and properly assessed the effects of corrosion induced wastage on structural or pressure boundary integrity. The inspectors observed whether corrective actions taken were consistent with the ASME Code and 10 CFR Part 50 Appendix B requirements.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The inspectors reviewed the steam generator tube eddy current examination scope and expansion criteria to determine whether the criteria met technical specification requirements, Electric Power Research Institute guidelines, and commitments made to the NRC. The inspectors also reviewed whether the eddy current inspection scope included areas of degradations that were known to represent potential eddy current test challenges such as the top of tube sheet, tube support plates, and U-bends. The scope of the licensees eddy current examinations included:

34 percent full length bobbin coil 34 percent plus-point of row one and two U-bends 33.3 percent plus-point of hot-leg top of tube sheet 50 percent plus-point of dings/dents greater than or equal to five volts 50 percent plus-point of expanded tubes at baffle plate D 100 percent plus-point of expanded tubes at baffle plate B The inspectors reviewed the licensees identification of the following tube degradation mechanisms:

Anti-vibration bar wear Loose parts Residual high stress The inspectors observed portions of the eddy current testing being performed to determine whether:

(1) the appropriate probes were used for identifying the expected types of degradation,

(2) calibration requirements were followed, and

(3) probe travel speed was in accordance with procedural requirements. The inspectors performed a review of the site-specific qualifications for the techniques being used to determine whether eddy current test data analyses were adequately performed in accordance with Electric Power Research Institute and site-specific guidelines. The inspectors also reviewed the results of the steam generator secondary side sludge lancing and foreign object search and retrieval inspections.

The inspectors reviewed the licensees actions in response to identified loose parts. The licensee was able to remove all of the identified loose parts except one. The one part that could not be retrieved was identified as a legacy item in that it had been identified several refueling outages before and was being tracked. The part was trapped between three tubes and had not caused any discernable wear prior to the current refueling outage. Plus-point data indicated approximately 10 percent wear on one of the affected tubes due to the loose part. As a result, the licensee elected to stabilize and plug the three affected tubes.

Finally, the inspectors reviewed selected eddy current test data to verify that the analytical techniques used were adequate.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On May 19, 2014, the inspectors observed a simulator scenario performed by an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors also assessed the modeling and performance of the simulator during the scenario.

These activities constitute completion of one quarterly licensed operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

The inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity or risk. The inspectors observed the operators performance of the following activities:

April 21, 2014, Unit 2, reactor coolant system drain to midloop April 22, 2014, Unit 2, reactor coolant system vacuum fill April 26, 2014, Unit 2, preparations for entry into mode 2 May 22, 2014, Unit 1, control rod repositioning In addition, the inspectors assessed the operators adherence to plant procedures, including the conduct of operations procedure and other operations department policies.

These activities constitute completion of one quarterly licensed operator performance sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensees evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed when removing equipment for work:

April 21, 2014, Unit 2, outage risk assessment and management of orange risk during mid-loop operations May 12, 2014, Unit 1, train A service water and service water pump 2-02 discharge header to crosstie header isolation valve XSW-0029, The inspectors verified that these risk assessments were performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessments and verified that the licensee implemented appropriate risk management actions based on the result of the assessments.

These activities constitute completion of two maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following operability determinations and functionality assessments that the licensee performed for degraded or nonconforming structures, systems, or components:

Condition Report CR-2013-002298, Units 1 and 2, uninterruptible power supply air conditioning unit X-01 cycling Condition Report CR-2014-001919, Unit 1, diesel generator 1-01 lubricating oil pipe crack Condition Report CR-2014-004417, Unit 2, residual heat removal pump 2-02 snubber detached Condition Report CR-2014-005266, Unit 2, feedwater isolation valve solenoid valve failures Condition Report CR-2014-005903, Unit 2, service water pump 2-02 discharge header to crosstie header isolation valve XSW-0029 failure to open The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded structures, systems, or components to be operable or functional, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability or functionality. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability or functionality of the degraded structures, systems, or components.

The inspectors used Operating Experience Smart Sample (OpESS) FY2008-01, Negative Trend and Recurring Events Involving Emergency Diesel Generators in the evaluation of Condition Report CR-2014-001919.

These activities constitute completion of five operability determination and functionality assessment inspection samples as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed Unresolved Item 05000445/2012004-03; 05000446/2012004-03, Potential Failure to Follow 10 CFR 50.59 for a Change to the Spent Fuel Pool Configuration to determine if a violation existed for revising the procedure that controlled off-loading spent fuel bundles to the spent fuel pool. The inspectors identified a non-cited violation of NRC requirements. This unresolved item is closed.

b. Findings

Introduction.

The inspectors identified a non-cited violation of 10 CFR 50.59 for failure to conduct a written evaluation and submit a license amendment for a change to the facility that required a technical specification amendment. Specifically, the licensee changed Procedure NUC-211, Surveillance of Region II Storage Limitations, Revision 1, to allow for storage of uprated fuel in Region II (high density racks) of the spent fuel pool using a methodology for fuel burnup penalties that had not been previously approved by the NRC and therefore, required an amendment to Technical Specification 3.7.17 Spent Fuel Assembly Storage prior to implementation.

Description.

On August 28, 2007, the licensee submitted an application for a license amendment for a stretch power uprate of approximately six percent reactor power.

Included in this application was a proposed change to Technical Specification 3.7.17 to support the eventual loading of the power uprate fuel to the spent fuel pool and associated criticality analyses.

For ease of review, the spent fuel pool criticality analysis portion of the amendment was separated from the stretch power uprate amendment. The license amendment approving the licensed reactor power uprate was issued on June 27, 2008. However, based on an NRC technical staff request, the licensee submitted additional supplemental information for the spent fuel pool criticality analysis amendment on June 30, 2008. A formal request for additional information was issued by the NRC for the spent fuel pool criticality analysis amendment on November 19, 2008. The licensee submitted several separate responses to the request for additional information questions during 2008 and 2009. The NRC technical staff issued a draft denial of the spent fuel pool criticality analysis amendment by a letter dated July 10, 2009. In response to this draft denial of the license amendment, the licensee formally withdrew the license amendment by letter dated August 20, 2009, which was acknowledged by the NRC the next day.

Comanche Peak Units 1 and 2 both operated for two 18-month refueling intervals from 2009 to 2012 at the uprated reactor power conditions. However, the licensee had not resolved the issues associated with receiving a license amendment to allow for storage of the uprated fuel in the spent fuel pool.

In February 2009, the licensee performed a 10 CFR 50.59 screening of Procedure NUC-211 to address the potential storage of uprated fuel in the spent fuel pools if a license amendment was not approved by the end of the operating cycle. The licensee added a precaution to Procedure NUC-211 stating fuel assemblies from Unit 1 Cycle 14 and beyond, and assemblies from Unit 2 Cycle 12 and beyond, should NOT be stored in Region II until the Technical Specifications are revised to consider the effects of stretch power uprate conditions. The inspectors considered this precaution to be appropriate, because the Region II high density storage racks technical specification implemented a number of limitations on storage configurations based on fuel enrichment and fuel burnup. Procedure NUC-211 did allow for storage of uprated fuel in the low density fuel racks, which was analyzed for any storage configuration regardless of fuel enrichment.

The precautions of Procedure NUC-211, prohibiting the storage of uprated fuel in Region II of the spent fuel pool remained in effect for the duration of the first operating cycles following the approval of the power uprate. The first storage of Unit 1 uprated fuel to Region I (the low density-unrestricted racks) of the spent fuel pool occurred on April 3, 2010, following Unit 1 cycle 14.

The licensee determined that they did not have sufficient capacity in the spent fuel pools to discharge all fuel in Region I of the spent fuel racks and accommodate other fuel management considerations. Thus, the licensee contacted a vendor to determine if they could provide an analysis to justify movement of the uprated fuel to Region II of the spent fuel racks. On September 29, 2010, the vendor provided the licensee with the results of this analysis. This analysis stated that the burnup versus enrichment curves for Technical Specification 3.7.17 for storage of fuel in Region II of the spent fuel racks were nonconservative when applied to fuel depleted at uprated conditions. The uprated fuel remained in Region I (unrestricted low density racks) because of this information.

The vendor letter provided the licensee with proposed fuel burnup penalties to account for uprate conditions should the licensee desire to move the uprated spent fuel to Region II of the spent fuel pools.

In December 2010, the licensee relocated uprated spent fuel from Region I to Region II of the spent fuel pools. Since the fuel discharge curves for spent fuel subject to uprated conditions of Technical Specification 3.7.17 were nonconservative, the licensee incorrectly invoked the direction of NRC Administrative Letter 98-10 Dispositioning of Technical Specifications that are Insufficient to Ensure Plant Safety. The licensee noted that the NRC letter states that if a technical specification is found to be nonconservative, administrative controls to ensure nuclear safety is adequately protected is an acceptable short-term solution. The licensee believed that these compromise solutions of the administrative letter applied equally to current/past plant design as well as a desired future plant configuration. Thus, on December 15, 2010, the licensee revised Procedure NUC-211 to allow storage of uprated fuel in Region II of the spent fuel pools. The 10 CFR 50.59 screening incorrectly stated that a technical specification amendment was unnecessary. This method of applying burnup penalties was not reviewed and approved by the NRC and Technical Specification 3.7.17 was not considered valid for uprated fuel. Thus, the licensees change to Procedure NUC-211, that allowed the use of administrative controls to discharge uprated fuel to Region II of the spent fuel pools without prior NRC approval, was a violation of 10 CFR 50.59.

Analysis.

The licensees failure to perform an adequate 10 CFR 50.59 evaluation and obtain prior NRC approval for a change to the facility that involved a change to the technical specifications was a performance deficiency. The inspectors concluded that this issue involved traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. This performance deficiency is more than minor because it was associated with the reactivity control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Because the significance determination process does not directly address spent fuel pool criticality, a senior reactor analyst evaluated this issue using Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Based on calculations provided by the licensee, the analyst determined that even with all uncertainties included in the calculations, the spent fuel pools would remain subcritical under all conditions, including a complete dilution of the borated water. The analyst qualitatively considered a completed dilution of the spent fuel pools to be a very low probability event. Therefore, the analyst concluded that this issue was of very low safety significance (Green). Because this issue was considered to be of Green safety significance, it is treated as a Severity Level IV violation in traditional enforcement. The inspectors determined that the finding was not representative of current license performance and no cross-cutting aspect was assigned.

Enforcement.

Title 10 CFR Part 50.59 states, in part, that licensees may make changes to the facility as described in the safety analysis report, without prior NRC approval, provided the change does not involve a change to the technical specifications. Contrary to the above, on December 15, 2010, the licensee made a change to the facility that involved a change to the technical specifications without prior NRC approval.

Specifically, the licensee revised Procedure NUC-211 to allow storage of uprated fuel in Region II of the spent fuel pool and failed to obtain a license amendment to Technical Specification 3.7.17 Spent Fuel Assembly Storage prior to implementation.

Subsequently, the licensee stopped all fuel movement in Region II of the spent fuel pool unless notifying the NRC prior to the movement. Since the violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report CR-2014-004693, it is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000445/2014003-01; 05000446/2014003-01, Failure to Follow 10 CFR 50.59 for a Change to the Spent Fuel Pool Configuration.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities that affected risk-significant structures, systems, or components:

April 3, 2014, Unit 1, positive displacement charging pump testing following maintenance April 21, 2014, Unit 2, turbine driven auxiliary feedwater pump over-speed trip testing following maintenance April 22, 2014, Unit 2, diesel generator 2-01 testing following extended maintenance overhaul May 8, 2014, Units 1 and 2, control room air conditioning unit X-03 testing following maintenance May 12, 2014, Unit 1, service water pump 1-01 testing following maintenance The inspectors reviewed licensing and design basis documents for the structures, systems, or components and the maintenance and post-maintenance test procedures.

The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected structures, systems, or components.

These activities constitute completion of five post-maintenance testing samples as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors evaluated the licensees outage activities for the Unit 2 refueling outage conducted March 29 through April 27, 2014. The inspectors verified that the licensee considered risk in developing and implementing the outage plan, appropriately managed personnel fatigue, and developed mitigation strategies for losses of key safety functions.

This verification included the following:

Review of the licensees outage plan prior to the outage Monitoring of shut-down and cool-down activities Verification that the licensee maintained defense-in-depth during outage activities Observation and review of reduced-inventory and mid-loop activities Observation and review of fuel handling activities Monitoring of heat-up and startup activities The inspectors used Operating Experience Smart Sample (OpESS) 2007-03, Revision 2, Crane and Heavy Lift Inspection, Supplemental Guidance for IP-71111.20 as additional guidance for the inspection.

These activities constitute completion of one refueling and other outage activities inspection sample as defined in Inspection Procedure 71111.20.

b. Findings

Introduction.

The inspectors reviewed a Green self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to have documented instructions of a type appropriate to the circumstances when performing an activity affecting quality. Specifically, the licensee failed to have appropriate instructions for filling a Unit 2 component cooling water heat exchanger. As a result, cooling water was inadvertently isolated to a spent fuel pool heat exchanger.

Description.

On April 8, 2014, operators attempted to restore the Unit 2 train B component cooling water system to service following maintenance. With the component cooling water trains cross-connected, an operator began to fill train B by throttling open train B heat exchanger inlet valve 2CC-0055, a 24-inch butterfly valve. Almost immediately, the control room received a component cooling water surge tank empty alarm. The operating train A component cooling water system automatically isolated cooling to the non-safeguards loop of component cooling water, resulting in loss of cooling flow to spent fuel pool heat exchanger X-02. The control room operators immediately stopped the filling of train B and restored train A to service. The licensee maintained spent fuel pool cooling using spent fuel pool heat exchanger X-01, supplied by Unit 1. The non-safeguards loop of Unit 2 component cooling water was restored after approximately two minutes. During that time, the licensee entered an Orange shutdown risk profile as a result of having only one available train of spent fuel pool cooling available.

The licensee allowed system restoration to be performed using the clearance release process to control the activities for filling the system. The operators had discussed the sequence of repositioning valves as they removed clearance tags and were aware that opening the isolation valve would result in lowering surge tank level. However, the surge tank level was low when the work activity was started. The clearance release instructions directed the operator to Open 2CC-0055 slowly to ensure CCW surge tank level is able to be monitored and maintained. This valve was not effective at throttling flow.

The inspectors determined that the instructions provided were not appropriate to the circumstances. The inspectors identified the following deficiencies in the instructions.

The instructions did not include precautions to ensure there was enough water in the surge tank. The instructions should have specified a different valve to control the fill rate. In addition, the licensee operations and maintenance personnel did not fully consider and mitigate the risk of performing the system restoration.

The licensee entered the event into their corrective action procedure as Condition Report CR-2014-004111.

Analysis.

The licensees failure to have appropriate instructions for filling a Unit 2 component cooling water heat exchanger was a performance deficiency. As a result, when filling the train B cooling water heat exchanger, component cooling water flow was inadvertently isolated to a spent fuel pool heat exchanger. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that spent fuel pool design barriers protect the public from radionuclide releases caused by accidents or events. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 3, Barrier Integrity Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis, did not result from a fuel handling error, and did not result in a loss of spent fuel pool level. The finding has a human performance cross-cutting aspect associated with work management because the licensee failed to ensure that the work process identified and managed the risk commensurate with the work [H.5].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions. Contrary to the above, on April 8, 2014, licensee personnel performed an activity affecting quality and failed to accomplish the activity in accordance with documented instructions of a type appropriate to the circumstances. Specifically, the licensee used the clearance release process to control the activities for filling a component cooling water system and caused a loss of cooling water flow to a spent fuel pool heat exchanger. Since the violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report CR-2014-004111, it is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000446/2014003-02, Failure to Provide Appropriate Instructions for Filling the Component Cooling Water System.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed the following risk-significant surveillance tests and reviewed test results to verify that the tests adequately demonstrated that the structures, systems, and components were capable of performing their safety functions:

Pump or Valve Inservice Test April 22, 2014, Unit 2, inservice testing of reactor and pressurizer head vents in accordance with Procedure OPT-505B, Reactor Coolant System Valve Operability Test, Revision 5 Containment Isolation Valve Test April 16, 2014, Unit 2, containment isolation valve testing in accordance with Procedure OPT-815B, Appendix J Leak Rate Test of Penetration 2-MIII-0006 (2-8105 and 2-8381), Revision 3 Reactor Coolant System Leakage Detection Surveillance Testing May 2, 2014, Unit 1, water inventory balance in accordance with Procedure OPT-303, Reactor Coolant System Water Inventory, Revision 14 Other Surveillance Testing March 17, 2014, Units 1 and 2, control room envelope testing in accordance with Procedure PPT-SX-7525A/B, Control Room Envelope Inleakage Using Tracer Gas, Revision 0 April 2, 2014, Unit 2, containment integrity verification prior to refueling in accordance with Procedure OPT-408B, Refueling Containment Penetration Verification, Revision 6 April 3, 2014, Unit 2, safety injection with loss of offsite power testing in accordance with Procedure OPT-435B, Train B Integrated Test Sequence, Revision 8 April 26, 2014, Unit 2, reactor coolant system pressure boundary leakage testing in accordance with Procedure OPT-616B, RCS Pressure Boundary Leakage Test for Loop 4 CL Injection Valves, Revision 2 May 13, 2014, Unit 1, reactor coolant dose equivalent iodine activity sample in accordance with Procedure CHM-120, Primary Chemistry, Revision 15 The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected structures, systems, and components following testing.

These activities constitute completion of eight surveillance testing inspection samples (one pump or valve inservice testing sample, one containment isolation valve test sample, one reactor coolant system leakage detection surveillance test sample, and five other surveillance testing samples) as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors verified the adequacy of the licensees methods for testing the alert and notification system. The inspectors interviewed licensee personnel responsible for the maintenance of the alert and notification system and reviewed a sample of corrective action system reports written for alert and notification system problems. The inspectors compared the licensees alert and notification system testing program with criteria in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1; Federal Emergency Management Agency Report REP-10, Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants; and the licensees current Federal Emergency Management Agency approved alert and notification system design report, Final Report - Alert and Notification System for Comanche Peak Steam Electric Station, dated September 28, 2004.

These activities constituted completion of one alert and notification system evaluation sample as defined in Inspection Procedure 71114.02.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors verified the licensees emergency response organization on-shift and augmentation staffing levels were in accordance with the licensees emergency plan commitments. The inspectors reviewed documentation and discussed with licensee staff the operability of primary and backup systems for augmenting the on-shift emergency response staff to verify the adequacy of the licensees methods for staffing emergency response facilities, including the licensees ability to staff pre-planned alternate facilities.

The inspectors also reviewed records of emergency response organization augmentation tests and events to determine whether the licensee had maintained a capability to staff emergency response facilities within emergency plan timeliness commitments.

These activities constitute completion of one emergency response organization staffing and augmentation testing sample as defined in Inspection Procedure 71114.03.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed the following for the period July 2012 to April 2014:

After-action reports for emergency classifications and events After-action evaluation reports for licensee drills and exercises Independent audits and surveillances of the licensees emergency preparedness program Self-assessments of the emergency preparedness program conducted by the licensee Drill and exercise performance issues entered into the licensees corrective action program Emergency preparedness program issues entered into the licensees corrective action program Maintenance records for equipment supporting the emergency preparedness program Emergency response organization and emergency planner training records The inspectors reviewed summaries of 462 corrective action program reports associated with emergency preparedness and selected 66 to review against program requirements, to determine the licensees ability to identify, evaluate, and correct problems in accordance with planning standard 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E, IV.F. The inspectors verified that the licensee accurately and appropriately identified and corrected emergency preparedness weaknesses during critiques and assessments.

The inspectors reviewed records pertaining to the maintenance of equipment and facilities used to implement the emergency plan to determine the licensees ability to maintain equipment in accordance with the requirements of 10 CFR 50.47(b)(8) and 10 CFR Part 50, Appendix E, IV.E. The inspectors verified that equipment and facilities were maintained in accordance with the commitments of the licensees emergency plan.

These activities constitute completion of one maintenance of emergency preparedness sample as defined in Inspection Procedure 71114.05.

b. Findings

Introduction.

The inspectors identified an unresolved item related to maintaining the effectiveness of the licensees emergency plan that meets planning standard 50.47(b)(4), which requires, in part, that a standard emergency classification and action level scheme is in use by the licensee. Specifically, several main steam line monitors were out of service for extended periods of time without apparent contingency actions in place to ensure the correct emergency action level would be implemented.

Description.

On November 20, 2013, the licensee initiated Condition Report CR-2013-011914 identifying that the main steam line radiation monitors had a trend of being out-of-service for significant time periods. Monitor 1-RE-2328 was out of service for 110 and 210 days on two separate occasions. Monitor 1-RE-2326 was out of service for 77 and 157 days on two separate occasions. Monitor 1-RE-2325 was out of service for 61 days. Four other monitors from the two units had been out of service, some more than once, for periods of five days or less. There are four online main steam line monitors for each unit. The licensee addressed the trend by trouble-shooting, repairing, and replacing detectors.

The main steam line radiation monitors are important to emergency preparedness because they are inputs into the emergency action levels and define the initiating conditions related to abnormal radiation releases/radiation effluent emergency declarations.

The inspectors determined that the licensee had taken appropriate action to initiate corrective action and repair. The licensee also tracked the out of service time of the monitors as operational focus items and in the station tactical equipment issues list. All eight main steam line monitors are currently in service with zero out of service days in 2014. However, there was no evidence that contingency actions were implemented to maintain the approved emergency action level scheme when the monitors were out of service.

Title 10 CFR 50.54(q) requires licensees to maintain the effectiveness of an emergency plan that meets the requirements in the planning standards of 50.47(b). Title 10 CFR 50.47(b)(4) requires a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by the nuclear facility licensee.

This issue was identified as an unresolved item because the NRC has not determined whether the licensee has adequately implemented planning standard 10 CFR 50.47(b)(4). Specifically, the NRC has not determined whether the emergency action level initiating condition was rendered ineffective, such that, any general emergency would not be declared for a particular off-normal event in an accurate and timely manner or in a degraded manner.

The licensee has entered this issue into the corrective action program as Condition Report CR-2014-005874. This issue is identified as unresolved item URI 05000445/2014003-03; 05000446/2014003-03, Maintenance of a Standard Action Level Scheme for Main Steam Line Monitors.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors assessed the licensees performance in assessing the radiological hazards in the workplace associated with licensed activities. The inspectors assessed the licensees implementation of appropriate radiation monitoring and exposure control measures for both individual and collective exposures. The inspectors walked down various portions of the plant and performed independent radiation dose rate measurements. The inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors reviewed licensee performance in the following areas:

The hazard assessment program, including a review of the licensees evaluations of changes in plant operations and radiological surveys to detect dose rates, airborne radioactivity, and surface contamination levels Instructions and notices to workers, including labeling or marking containers of radioactive material, radiation work permits, actions for electronic dosimeter alarms, and changes to radiological conditions Programs and processes for control of sealed sources and release of potentially contaminated material from the radiologically controlled area, including survey performance, instrument sensitivity, release criteria, procedural guidance, and sealed source accountability Radiological hazards control and work coverage, including the adequacy of surveys, radiation protection job coverage and contamination controls, the use of electronic dosimeters in high noise areas, dosimetry placement, airborne radioactivity monitoring, controls for highly activated or contaminated materials (non-fuel) stored within spent fuel and other storage pools, and posting and physical controls for high radiation areas and very high radiation areas Radiation worker and radiation protection technician performance with respect to radiation protection work requirements Audits, self-assessments, and corrective action documents related to radiological hazard assessment and exposure controls since the last inspection These activities constitute completion of one radiological hazard assessment and exposure controls sample as defined in Inspection Procedure 71124.01.

b. Findings

Introduction.

The inspectors reviewed a Green self-revealing non-cited violation of Technical Specification 5.7.1 resulting from the licensees failure, on three separate occasions, to properly inform workers of the high radiation area radiological conditions prior to entry. As a result, workers entered posted high radiation areas with greater than expected dose rates and received dose rate alarms.

Description.

On April 14, 2013, March 30, 2014, and April 7, 2014, workers entered posted high radiation areas without proper knowledge of the radiological conditions (dose rates) in the areas accessed. As a result, the electronic alarming dosimeters worn by the workers alarmed on high dose rate.

On April 14, 2013, a worker received an unanticipated dose rate alarm while painting in the northeast corridor, 808 foot elevation, of the Unit 1 containment. The worker was performing duties in the radiologically controlled area on radiation work permit 2013-1216, task 2, which allowed entry into high radiation areas. The setpoints on the radiation work permit were 40 millirem for the dose alarm and 150 millirem per hour for the dose rate alarm. A radiation protection technician briefed the worker on the general area radiological conditions and some regions of the cavity drain line near valve XSF-0028 using available survey records. Survey 13-04-0038, dated April 1, 2013, showed a maximum of 420 millirem per hour on contact and 100 millirem per hour at 30 cm for the valve XSF-0028 area. However, Condition Report CR-2013-004154 stated that the worker was briefed that conditions were 250 millirem per hour on contact and 85 millirem per hour general area near the cavity drain line. The worker was not informed that the rates near the open end of the drain line were 600 millirem per hour on contact and 85 millirem per hour near the open end of the drain line. According to the licensee, this was an oversight by the radiation protection technician performing the briefing. It was determined that as the worker kneeled to access a hanger to paint, the worker was within a few inches of the pipe opening, at which time the worker received a dose rate alarm of 563 millirem per hour. The radiation work permit instructions required the worker to immediately exit the area and contact radiation protection if an unanticipated electronic dosimeter dose rate alarm was received. In this case, the worker failed to hear the dosimeter alarm as a result of background noise and thus, did not immediately exit the area and contact radiation protection as required. The worker received a total of 6.1 millirem dose during the radiologically controlled area entry.

On March 30, 2014, an operator received an unanticipated dose rate alarm while performing valve line-up work on the 905 foot elevation of the Unit 2 containment pressurizer cubicle (Room 2-161E). The operator entered Room 2-161E to attach the locked valve tag after completing a valve line-up. Initially the operator did not notice any valves nearby, but saw some on the other side of the pressurizer cubicle. However, as the operator stepped closer to the valves, the operator immediately received a dose rate alarm of 274 millirem per hour. The operator was performing duties on radiation work permit 2014-2101, task 2, which allowed entry into high radiation areas. The setpoints on this radiation work permit were 30 millirem for the dose alarm and 250 millirem per hour for the dose rate alarm. The operator had been briefed on the general area radiological conditions of the pressurizer cubicle, which were originally in alignment with the setpoints, but the operator was not made aware of the changing radiological conditions and elevated dose rates associated with a crud burst in progress. Condition Report CR-2014-003464 stated that radiation protection should have been aware of the ongoing crud burst and should have performed a survey prior to informing the worker of the dose rates. The follow-up survey, Survey 14-03-0722, dated March 30, 2014, showed a maximum dose rate of 520 millirem per hour on contact and 350 millirem per hour in the pressurizer cubicle general area. The radiation work permit instructions required that the worker immediately exit the area and contact radiation protection if an unanticipated electronic dosimeter dose rate alarm is received. In this case, the worker backed out of Room 2-161E, but failed to immediately contact radiation protection regarding the dose rate alarm. After receiving the dose rate alarm, the worker continued to another room (the spray valve room) on the other side of the pressurizer cubicle in search of the other valve for tagout. The worker received a total of 8.0 millirem dose during the radiologically controlled area entry.

On April 7, 2014, an operator received an unanticipated dose rate alarm while performing work in the valve gallery (Room X-213) of the auxiliary building piping area, 832 foot elevation. The operator was briefed using Survey 14-03-0785, dated March 31, 2014, which showed maximum dose rates of 200 millirem per hour on contact and 18 millirem per hour general area. However, this survey did not include the specific radiological conditions near the valves and piping in the work location. The licensee stated that this was an oversight by the radiation protection representative performing the briefing. Thus, the operator was unaware of the maximum dose rates near the valves and piping of 2.5 rem per hour on contact and 721 millirem per hour general area, as documented on Survey 14-03-0556, dated March 26, 2014. These dose rates were identified after a recent resin transfer near the resin sluice line valve. As the operator entered this area to hang valve tags, the operator received a dose rate alarm of 750 millirem per hour. The worker was performing duties in the radiologically controlled area on radiation work permit 2014-2101, task 2, which allowed entry into high radiation areas. The setpoints on this radiation work permit were 30 millirem for the dose alarm and 250 millirem per hour for the dose rate alarm. Condition Report CR-2014-003997 indicates that the briefing should have included specific information about valves and piping per Survey 14-03-0556 and Survey 14-03-0528, and the dose rate setpoint should have been increased to a level commensurate with the actual work area conditions. The worker received a total of 5.5 millirem dose during the radiologically controlled area entry.

As immediate corrective actions for each of these events, the licensee performed follow-up surveys, coached the involved individuals, and reviewed the radiologically controlled area requirements. As noted above, these three issues were entered into the licensees corrective action program as Condition Reports CR-2013-004154, CR-2014-003464, and CR-2014-003997, respectively.

Analysis.

The failure to provide workers with proper knowledge of high radiation area radiological conditions prior to entry is a performance deficiency. The performance deficiency is more than minor and a violation of Technical Specification 5.7.1 because it impacted the program and process attribute (exposure control) of the Occupational Radiation Safety Cornerstone and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation.

Specifically, worker entry into high radiation areas without knowledge of the radiological conditions placed them at increased risk for unnecessary radiation exposure.

Example 6(h) of IMC 0612, Appendix E, describes a similar example to this performance issue where the workers were authorized to work in a high radiation area, but were not made aware of the radiological conditions as authorized by their radiation work permit.

Therefore, as provided in Example 6(h), the inspectors determined that the performance deficiency was more than minor. Using Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the inspectors determined the violation has very low safety significance because:

(1) it was not an as low as is reasonably achievable (ALARA) finding,

(2) there was no overexposure, (3)there was no substantial potential for an overexposure, and

(4) the ability to assess dose was not compromised. This finding has a human performance cross-cutting aspect associated with teamwork because the workers failed to demonstrate and execute a strong sense of communication and collaboration in connection with the operational activities involved in this violation in order to ensure nuclear safety was maintained [H.4].

Enforcement.

Technical Specification 5.7.1, Sections

(b) and

(e) require, in part, that

(b) access to, and activities in, high radiation areas shall be controlled by means of a radiation work permit that includes specification of radiation dose rates in the immediate work areas and

(e) entry into high radiation areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them.

Contrary to the above, on April 14, 2013, March 30, 2014, and April 7, 2014, workers entered high radiation areas with radiation dose rates in excess of the established controls in the radiation work permit and without being made knowledgeable of these elevated dose rates in the immediate work areas. Specifically, on these three occasions, workers entered high radiation areas with dose rates of 100 millirem per hour or greater (563 millirem per hour, 274 millirem per hour, and 750 millirem per hour)without being informed of these dose rates and in excess of electronic alarming dosimeter setpoints established in the radiation work permits for controlling worker dose.

Since this violation is of very low safety significance and was entered into the licensees corrective action program as Condition Reports CR-2013-004154, CR-2014-003464, and CR-2014-003997, it is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000445/2014003-04; 05000446/2014003-04, Failure to Adequately Brief Workers on Radiological Conditions Prior to Entry into High Radiation Areas.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed licensee performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). During the inspection, the inspectors interviewed licensee personnel and reviewed licensee performance in the following areas:

Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements ALARA work activity evaluations/postjob reviews, exposure estimates, and exposure mitigation requirements The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas by reviewing condition reports and performance audits Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection These activities constitute completion of one occupational ALARA planning and controls sample as defined in Inspection Procedure 71124.02.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, and Occupational Radiation Safety

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures (MS05)

a. Inspection Scope

The inspectors reviewed licensee event reports, maintenance rule evaluations, and other records that could indicate whether safety system functional failures had occurred for the period of April 2013 through March 2014. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to determine the accuracy of the data reported.

These activities constituted completion of two safety system functional failures performance indicator samples, one per unit, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors reviewed the licensees reactor coolant system chemistry sample analyses for the period of April 2013 through March 2014 to verify the accuracy and completeness of the reported data. The inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample on May 13, 2014. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted completion of two reactor coolant system specific activity performance indicator samples, one per unit, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Reactor Coolant System Total Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system total leakage for the period of April 2013 through March 2014 to verify the accuracy and completeness of the reported data. The inspectors observed the performance of Procedure OPT-303, Reactor Coolant System Water Inventory, Revision 14 on May 2, 2014. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted completion of two reactor coolant system total leakage performance indicator samples, one per unit, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.4 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors verified there were no unplanned exposures or losses of radiological control of locked high radiation areas and very high radiation areas during the period of October 1, 2013, to December 31, 2013. The inspectors reviewed a sample of radiologically controlled area exit transactions showing exposures greater than 100 millirem. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted completion of the one occupational exposure control effectiveness performance indicator sample as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.5 Radiological Effluent Technical Specifications (RETS)/Offsite Dose Calculation Manual

(ODCM) Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed corrective action program records for liquid or gaseous effluent releases that occurred between October 1, 2013, and December 31, 2013, and were reported to the NRC to verify the performance indicator data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the radiological effluent technical specifications (RETS)/offsite dose calculation manual (ODCM) radiological effluent occurrences performance indicator as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.6 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspectors reviewed the licensees evaluated exercises and selected drill and training evolutions that occurred between the third quarter 2012 and first quarter 2014 to verify the accuracy of the licensees data for classification, notification, and protective action recommendation opportunities. The inspectors reviewed a sample of the licensees completed classifications, notifications, and protective action recommendations to verify their timeliness and accuracy. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.

These activities constituted completion of one drill/exercise performance indicator sample as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.7 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspectors reviewed the licensees records for participation in drill and training evolutions between the third quarter 2012 and first quarter 2014 to verify the accuracy of the licensees data for drill participation opportunities. The inspectors verified that all members of the licensees emergency response organization in the identified key positions had been counted in the reported performance indicator data. The inspectors reviewed the licensees bases for reporting the percentage of emergency response organization members who participated in a drill. The inspectors reviewed drill attendance records and verified a sample of those reported as participating. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.

These activities constituted completion of one emergency response organization drill participation performance indicator sample as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.8 Alert and Notification System Reliability (EP03)

a. Inspection Scope

The inspectors reviewed the licensees records of alert and notification system tests conducted between the third quarter 2012 and first quarter 2014 to verify the accuracy of the licensees data for siren system testing opportunities. The inspectors reviewed procedural guidance on assessing alert and notification system opportunities and the results of periodic alert and notification system operability tests. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.

These activities constituted completion of one alert and notification system reliability performance indicator sample as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected the issue associated with the failure of the uninterruptible power supply air conditioning unit X-01 for an in-depth follow-up. The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the corrective actions and that the actions were adequate to correct the condition.

The inspectors selected the issue associated with the licensees planned and completed corrective actions for previously identified non-cited violations associated with the fire protection program. The inspectors follow-up included:

On February 7, 2014, the licensee made a decision to defer a fire protection modification associated with non-cited Violation 2009004-04, Inadequate Postfire Safe Shutdown Procedure. This deferral was discussed in Section 4OA2 of Inspection Report 05000445/2014008 and 05000446/2014008.

On June 10, 2014, the licensee submitted letter TXX-14070, Revised Completion Date for the Comanche Peak Multiple Spurious Operation Circuit Interactions Resolution Implementation Plan. In this letter, the licensee notified the NRC of the deferral of eight fire protection modifications. Six of the modifications were associated with Unit 2 and two of the modifications were associated with Unit 1.

The inspectors reviewed the licensees justification for deferral; compensatory measures; updated modification plan, schedule, and documentation; and a cause analysis associated with the implementation of other fire protection modifications.

The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to restore compliance.

The inspectors assessed the timeliness of the planned corrective actions in accordance with the guidance in Inspection Manual Chapter 0326, Operability Determinations and Functionality Assessments for Conditions Adverse to Quality or Safety, dated January 31, 2014.

These activities constitute completion of two annual follow-up of selected issues samples as defined in Inspection Procedure 71152.

b. Findings

1) Failure to Follow Procedure for Brazing Copper Tubing

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to follow procedure for brazing copper joints. Specifically, personnel failed to follow procedure and exercise sufficient care to assure the copper tubing was not overheated during a brazing activity. As a result, personnel overheated the copper joints and caused the inoperability of an uninterruptible power supply air conditioning unit when the component developed a leak.

Description.

On March 5, 2013, the inspectors observed that the component cooling water supply valve for the uninterruptible power supply air conditioning unit X-01 was cycling. The inspectors informed the licensee of the observation. The licensee found a small pin-hole leak on the bottom of the condenser and observed a low refrigerant level in the condenser. The licensee declared the air conditioning unit inoperable and repaired the leak.

The licensee performed a past operability review of the uninterruptible power supply heating, ventilation, and air conditioning system. The system consists of dedicated uninterruptible power supply room emergency fan coil units in each room and two electrical independent and redundant air conditioning trains that, either of which, can support all four safety-related uninterruptible power supply rooms. This gives the system a unique 300 percent capability. Even with air conditioning unit X-01 inoperable, the licensee concluded that the required actions were always met for Technical Specification 3.7.20, two uninterruptible power supply heating, ventilation, and air conditioning trains. The inspectors reviewed the past operability and did not identify any discrepancies in the licensees conclusion.

The inspectors reviewed the licensees cause evaluation and determined that the likely cause of the component failure was excessive heating of the copper fittings during the brazing process when installing a replacement heat exchanger. Procedure MSG-1001, Fabrication, Installation, Repairs, Replacement, and Modifications of Piping Systems, Revision 0, provides the requirements and criteria for repairs and replacement of piping systems. Step 8.21.1 requires, in part, that when brazing 3/4-inch diameter and larger copper tubing, to exercise care to assure the tubing is not overheated. The inspectors concluded that personnel overheated the copper tubing and caused the inoperability of an uninterruptible power supply air conditioning unit.

Analysis.

The licensees failure to follow procedure for brazing copper tubing was a performance deficiency. Specifically, personnel failed exercise sufficient care to assure the copper tubing was not overheated, resulting in the subsequent failure of the copper tubing. The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2, Mitigating System Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding did not represent a loss of a system or function and the finding did not represent an actual loss of at least a single train for greater than its technical specification allowed outage time.

The inspectors determined that the finding was not representative of current licensee performance and no cross-cutting aspect was assigned.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Procedure MSG-1001, Fabrication, Installation, Repairs, Replacement, and Modifications of Piping Systems, Revision 0, provides the requirements and criteria for repairs and replacement of piping systems. Step 8.21.1 requires, in part, that when brazing 3/4 inch diameter and larger copper tubing, to exercise care to assure the tubing is not overheated. Contrary to the above, on September 25, 2009, licensee personnel performed an activity affecting quality and failed to accomplish the activity in accordance with documented procedures.

Specifically, personnel failed to follow Procedure MSG-1001, Step 8.21.1 and exercise care to assure the copper tubing was not overheated. On March 13, 2013, the licensee completed the repair to the air conditioning unit. Since the violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report CR-2013-002298, it is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000445/2014003-05; 05000446/2014003-05, Failure to Follow Procedure for Brazing Copper Tubing.

2) Failure to Correct Fire Protection Violations in a Timely Manner

Introduction.

The inspectors identified a Green violation of License Condition 2.G for the failure to implement and maintain in effect all provisions of the approved fire protection program. Specifically, the inspectors identified two examples where the licensee failed to implement corrective actions and restore compliance in a timely manner for two non-cited violations associated with the fire protection program.

Description.

The inspectors reviewed the licensees planned and completed corrective actions for previously identified non-cited violations associated with the fire protection program. The inspectors identified two examples where the licensee failed to implement corrective actions and restore compliance in a timely manner.

Example 1: Non-Cited Violation 2009004-04, Inadequate Postfire Safe Shutdown Procedure During the 2008 triennial fire protection inspection, the team identified a concern with the potential loss of the charging pump relied upon for an alternative shutdown due to a loss of suction. Specifically, the team was concerned that the spurious closure of one of the volume control tank outlet valves (LCV-112B or LCV-112C) prior to the opening of one of the refueling water storage tank outlet valves (LCV-112D or LCV-112E) would result in a loss of suction and loss of the charging pump. The team documented this issue as Unresolved Item 2008006-01 on July 3, 2008. This unresolved item was subsequently closed as non-cited Violation 2009004-04 on October 27, 2009.

As a corrective action for this violation, the licensee developed plant modifications.

These modifications were designed to:

Install hot short prevention cable in the control room and cable spreading room for all four valves Install new control switches at the remote shutdown panel and shutdown transfer panel for valves LCV-112B and LCV-112D to allow control of these valves from the remote shutdown panel Reconfigure the control circuits for the valves to comply with the requirements of Information Notice 92-18, Potential for Loss of Remote Shutdown Capability During a Control Room Fire Remove the 3HR cable in the power and control circuits for valve LCV-112B These modifications were originally scheduled to be completed in 2014 during the spring outage for Unit 2 (2RF14) and the fall outage for Unit 1 (1RF17). On February 7, 2014, the licensee made a decision to delay the modification for Unit 2 from 2RF14 to 2RF15.

During the 2014 triennial fire protection inspection, the team reviewed the licensees rationale for delaying the Unit 2 modification. At that time, the team determined that a performance deficiency existed because the corrective actions for the original fire protection violation for Unit 2 were untimely. The team noted that the enforcement aspect of this performance deficiency would be documented in a future integrated inspection report with the closure of Licensee Event Report 05000445/2013-003-00 since the underlying cause of the delay was associated with problems with the modification process that were revealed during the December 4, 2013, loss of offsite power event. Licensee Event Report 05000445/2013-003-00 is described and closed in Section 4OA3.1 of this report.

The licensee later made a decision to delay the modification for Unit 1 from 1RF17 to 1RF18. The licensee made this decision on May 29, 2014, and notified the NRC of the deferrals on June 10, 2014.

During this inspection, the inspectors reviewed the licensees rationale for deferring the Unit 1 modification. The inspectors determined that the licensee was unable to meet the outage milestones for 1RF17 due to the implementation of corrective actions associated with the December 4, 2013, event. The inspectors determined that the corrective actions for the original fire protection violation for Unit 1 were also untimely. Specifically, the inspectors determined that the corrective actions were untimely since the violation has existed more than 5 years without the licensee restoring full compliance for both units.

Example 2: Non-Cited Violation 2011007-02, Failure to Mitigate or Correct Potential Single Spurious Failures During the 2011 triennial fire protection inspection, the team identified that electrical cables for the pressurizer power-operated relief valves and associated block valves were installed in many of the same cable trays, leaving the plant susceptible to fire damage that could spuriously open the power-operated relief valve and prevent the ability to shut the block valve. The team documented this issue as non-cited Violation 2011007-02 on May 17, 2011.

As a corrective action for this violation, the licensee developed several plant modifications. These modifications were designed to prevent the spurious operation of the power-operated relief valves through the use of hot short prevention cable and a radiant energy shield inside containment and hot short prevention cable and Thermo-Lag outside containment. These modifications were originally scheduled to be completed in 2014 during the spring outage for Unit 2 (2RF14) and the fall outage for Unit 1 (1RF17).

During the spring outage, the licensee was unable to implement all of the modification for Unit 2. Specifically, the licensee identified a Kellem grip inside a conduit attached to a junction box inside containment. This junction box was associated with power-operated relief valve 2-PCV-0455A. The licensee evaluated the condition and determined that the Kellem grip could not be removed without the risk of damaging the other cables. On April 15, 2014, the licensee decided to defer and redesign the modification for Unit 2 from outage 2RF14 to 2RF15.

The inspectors determined that the licensee was able to implement the modification for power-operated relief valve 2-PCV-0456 outside containment. However, the licensee did not fully implement the modification for power-operated relief valve 2-PCV-0455A outside containment due to a miscommunication when deferring the modification. The licensee will complete the majority of the work for 2-PCV-0455A outside containment at power prior to the next refueling outage.

During this inspection, the inspectors reviewed the licensees rationale for deferring the Unit 2 modification. The inspectors determined that the licensee could have reasonably foreseen and corrected the issue with the Kellem grip since this information was in the electronic cable and raceway data system (GENESIS). The inspectors determined that the corrective actions were untimely since the violation has existed more than three years without the licensee restoring full compliance for Unit 2.

Analysis.

The failure to implement corrective actions and restore compliance in a timely manner for two violations associated with the fire protection program was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the potential loss of the credited charging pump or spurious opening of a power-operated relief valve adversely affected the availability, reliability, and capability of the systems required to achieve and maintain safe shutdown in the event of a fire.

Example 1: Non-Cited Violation 2009004-04, Inadequate Postfire Safe Shutdown Procedure The inspectors evaluated the risk significance of this example using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, because it affected the ability to reach and maintain safe shutdown conditions in case of a fire. A senior reactor analyst performed a Phase 3 evaluation to determine the risk significance of this example since it involved a postulated control room fire that led to control room evacuation.

The analyst used the fire ignition frequency for the control room (FIFCR) and the cable spreading room (FIFCSR) listed in the Comanche Peak Steam Electric Station Individual Plant Examination of External Events for Severe Accident Vulnerabilities, Revision 0, as the best available information. The analyst multiplied each fire ignition frequency by a severity factor (SF) and a nonsuppression probability. For the control room, the nonsuppression probability (NPCR) indicated the probability that operators failed to extinguish the fire within 20 minutes (assuming 2 minutes for detection), which required control room evacuation. For the cable spreading room, the nonsuppression probability indicated the probability that the automatic Halon system failed (NPCSR-A) and the probability that the fire brigade failed to manually suppress the fire prior to damage that required control room evacuation (NPCSR-M). The resulting control room (FCR-EVAC) and cable spreading room (FCSR-EVAC) evacuation frequencies were:

FCR-EVAC = FIFCR

• SF

• NPCR

= 1.9E-2/yr

• 0.1

• 0.013

= 2.5E-5/yr FCSR-EVAC = FIFCSR

• SF

• NPCSR-A

• NPCSR-M

= 3.2E-3/yr

• 0.1

• 0.05

• 0.24

= 3.8E-6/yr The licensee confirmed that the Unit 2 control room has 116 electrical panels for both Unit 2 and common equipment, and the cable spreading room has 80 cabinets (54 termination racks and 26 electrical panels). The circuits for the volume control tank outlet valves are located in six different panels in the control room, one of which contains cables for both valves, and two termination cabinets in the cable spreading room.

Additionally, at least one hot short would have to occur in a cabinet or panel to cause one of the valves to spuriously close. The analyst used a value of 0.6 for the conditional probability of this hot short. The analyst obtained this value from Inspection Manual Chapter 0609, Appendix F, Table 2.8.3, PSP Factors Dependent on Cable Type and Failure Mode.

The analyst noted that this alternative shutdown scenario would only impact risk if the credited centrifugal charging pump was running at the time of the postulated fire. The analyst estimated that the probability the credited charging pump was running (PPUMP) to be 0.5. The analyst calculated a bounding change in core damage frequency for the control room (CDFCR) and cable spreading room (CDFCSR) as follows:

CDFCR = FCR-EVAC

• PPUMP * ((5/116)

• 0.6 + (1/116) * (0.6 + 0.6 - 0.62))

= 2.5E-5/yr

• 0.5

• 0.033

= 4.1E-7/yr CDFCSR = FCSR-EVAC

• PPUMP * (2/80)

• 0.6

= 3.8E-6/yr

• 0.5

• 0.015

= 2.9E-8/yr Because the postulated fire ignition frequencies for the control room and cable spreading room are independent of each other, the total change in core damage frequency can be determined by a simple addition of the change in core damage frequency from the two rooms calculated separately. The resulting overall change in core damage frequency for this example was calculated to have an upper bound of 4.4E-7/yr (Green).

This frequency was considered to be bounding because it assumed:

A fire induced hot short in the applicable cabinets would cause a volume control tank outlet valve to spuriously close The conditional core damage probability given either a control room or cable spreading room fire with evacuation and the spurious closure of a volume control tank outlet valve was equal to one The performance deficiency accounted for the entire change in core damage frequency (i.e., the base line core damage frequency for this event was zero)

In accordance with the guidance in Inspection Manual Chapter 0609, Appendix H, Containment Integrity Significance Determination Process, dated May 6, 2004, the senior risk analyst screened the performance deficiency for its potential risk contribution to large early release frequency since the bounding change in core damage frequency provided a risk significance estimate greater than 1E-7/yr. Given that Comanche Peak has a large, dry containment and that control room abandonment sequences do not include steam generator tube ruptures or intersystem loss of coolant accidents, the analyst determined that this example was not significant with respect to large early release frequency. The analyst determined this example was of very low risk significance (Green).

Example 2: Non-Cited Violation 2011007-02, Failure to Mitigate or Correct Potential Single Spurious Failures The inspectors evaluated the risk significance of this example using Inspection Manual Chapter 0609, Appendix F, because it affected the ability to reach and maintain safe-shutdown conditions in case of a fire. A senior reactor analyst performed a Phase 3 evaluation to determine the risk significance of this finding since it involved multiple fire areas.

The analyst performed a bounding evaluation based on the walk-down and results for this issue during the 2011 triennial fire protection inspection. The 2011 evaluation for this issue was bounding for the current evaluation because it considered fire scenarios that affected both power-operated relief valves, whereas the current finding is associated only with power-operated relief valve 2-PCV-0455A.

The analyst noted that the 2011 evaluation included two transient fire scenarios that were included based on the temporary storage of transient combustibles adjacent to vertical cable trays. During this inspection, the inspectors walked down the area and confirmed that there were no temporary combustibles stored in these areas. Therefore, the analyst removed these scenarios from the evaluation. The analyst included the remaining nine fire damage scenarios included in the 2011 evaluation.

The analyst determined that the cabling associated with the emergency core cooling system in the nonaffected train was not located within the affected zone of the fire. The analyst made a bounding assumption that all equipment in either train A or train B was lost due to the fire scenario by failing the train A or train B 6.9-kV busses. The analyst used the Comanche Peak SPAR model, Revision 8.28, downloaded July 1, 2014, to calculate the conditional core damage probability for each fire scenario that included the affected power-operated relief valve and its associated block valve failed open with no recovery. The analyst used a cutset truncation of 1E-13. The following table summarizes the Phase 3 evaluation results:

Fire Ignition Ignition Source CCDP CDF Frequency 2EA2 1.88E-6 1.13E-2 2.12E-8 2EA2 (HEAF) 1.62E-6 1.13E-2 1.83E-8 2EB3-2 1.08E-6 1.03E-2 1.11E-8 2EB4-2 1.08E-6 1.13E-2 1.22E-8 T2EB3 1.08E-7 1.03E-2 1.11E-9 Transients - 832 3.06E-6 1.03E-2 3.15E-8 Transients - 832 3.40E-7 1.03E-2 3.50E-9 Transients - 852 3.06E-6 1.13E-2 3.46E-8 Transients - 852 3.40E-7 1.13E-2 3.84E-9 Total 1.37E-7 The resulting overall change in core damage frequency for this example was calculated to have an upper bound of 1.37E-7/yr (Green).

In accordance with the guidance in Inspection Manual Chapter 0609, Appendix H, the senior risk analyst screened the performance deficiency for its potential risk contribution to large early release frequency since the bounding change in core damage frequency provided a risk significance estimate greater than 1E-7/yr. Given that Comanche Peak has a large, dry containment and that these scenarios do not include steam generator tube ruptures or intersystem loss of coolant accidents, the analyst determined that this example was not significant with respect to large early release frequency. The analyst determined this example was of very low risk significance (Green).

The finding has a human performance cross-cutting aspect associated with work management because the licensee failed to include the identification and management of risk commensurate to the work performed [H.5].

Enforcement.

License Condition 2.G for Unit 1 requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report through Amendment 78 and as approved in the Safety Evaluation Report and its supplements through Supplement 24.

License Condition 2.G for Unit 2 requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report through Amendment 87 and as approved in the Safety Evaluation Report and its supplements through Supplement 27.

Section 13.3B.5, Quality Assurance Program, of the Final Safety Analysis Report describes the fire protection quality assurance program. The fire protection quality assurance program states that measures shall be established to ensure that conditions adverse to fire protection such as failures, malfunctions, deficiencies or deviations, defective components, uncontrolled combustible material and nonconformances are promptly identified, reported, and corrected.

Contrary to the above, prior to June 19, 2014, the licensee failed to ensure that two conditions adverse to fire protection were promptly corrected. Specifically, the licensee failed to implement corrective actions and restore compliance in a timely manner for two violations associated with the fire protection program. These violations were non-cited Violation 05000445/2009004-04; 05000446/2009004-04, Inadequate Postfire Safe Shutdown Procedure, and non-cited Violation 05000445/2011007-02; 05000446/2011007-02, Failure to Mitigate or Correct Potential Single Spurious Failures. The licensees corrective actions were untimely since the conditions adverse to fire protection have existed for more than 5 years and 3 years, respectively.

The licensee entered this issue into its corrective action program as Condition Report CR-2014-007713. The licensee maintained the compensatory measures that were in place for these issues. These compensatory measures include hourly fire watches, changes to the safe shutdown procedures, and administrative changes to the fire protection program.

Because the licensee failed to restore compliance within a reasonable period of time after these violations were initially identified, this violation is being treated as a cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy. This is a violation of License Condition 2.G for Units 1 and 2. A Notice of Violation is included with this report: VIO 05000445/2014003-06; 05000446/2014003-06, Failure to Correct Fire Protection Violations in a Timely Manner.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

The following activities constitute completion of four follow-up of events and notices of enforcement discretion samples as defined in Inspection Procedure 71153.

.1 (Closed) Licensee Event Report 05000445/2013-003-00, Auto Start of Both Units

Auxiliary Feedwater Pumps and Emergency Diesel Generators Due to a Loss of Both Units Safeguards Electrical Power

a. Inspection Scope

The inspectors performed a review of a licensee event report documenting an activation of emergency systems that occurred on December 4, 2013, in which the diesel generators and auxiliary feedwater pumps started on a loss of both sources of offsite power. The inspectors examined associated procedures, work orders, condition reports, and the licensees root cause analysis of the event.

b. Findings

1) Failure to Follow the Site Design Modification Procedures

Introduction.

The inspectors reviewed a Green self-revealing finding for the licensees failure to follow the design modification process. The license implemented a design modification using incorrect technical information. As a result, the design modification was inadequate and both units lost all offsite power to the safety-related 6.9 kV busses during the implementation of the modification.

Description.

In 2012, the licensee initiated a permanent design modification of the offsite AC power system to add transformer XST1A which could be used in place of transformer XST1. The modification was implemented using Procedure ECE-5.01 Design Control Program, Revision 24, and Procedure ECE-5.01-08 Electronic Design Change Process, Revision 17. The modification was performed by contractor personnel.

As part of the design process, the licensee conducted field walk-downs to identify locations of cables and switch boxes. The contractor organization used personnel to conduct the walk-down. One was an engineer-in-training who had been in the organization for several months, and one was a superintendent who had worked at the site for several years. The route for the transformer XST1 cables going to Unit 2 passed through an infrequently accessed overhead cable space. Approximately halfway along this path, the Unit 2 cables from startup transformer XST2 entered the space. The cables then exited the overhead space and into the Unit 2 normal switchgear room. The personnel who conducted the walk-down incorrectly identified the cables from transformer XST2 as being the cables from transformer XST1.

The responsible engineer accepted the inputs from the engineer-in-training without independently verifying the accuracy. The responsible engineer did not perform a complete walk-down of the modification. The inputs were then used to develop drawings and work orders that formed the bases for the modification. Procedure ECE-5.01-08, step 3.1.3.2 required, in part, that the responsible engineer provides sufficient details to fully describe the change. The details provided were insufficient because they were incorrect.

On July 18, 2012, the licensee approved the first version of the design modification. All further design work in Unit 2, including work locations, was based on the incorrect information. The design included installation of switch boxes where the cables from transformers XST1, transformer XST1A, and the safety busses would terminate to allow the busses to be supplied by either transformer. These boxes were incorrectly installed in the path of the transformer XST2. This design error contributed to the workers cutting the cables for transformer XST2 instead of transformer XST1, resulting in a loss of offsite power to both units.

After the loss of offsite power, the licensee immediately stopped all work associated with the modification. The inspectors reviewed the design modification and drawings, performed walk-downs of the transformer cables, and interviewed the responsible personnel. The inspectors determined that the personnel who conducted the walk-downs did not fully understand their responsibility, and that the licensees work organization did not ensure that anyone actually verified the physical details of the cable route. Although the licensee had an expectation that a qualified engineer would verify the details of the change, a qualified engineer did not verify the details, and instead relied on an engineer-in-training engineer and a senior worker.

Analysis.

The licensees failure to follow the electronic design change process procedure was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and adversely 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. Using Inspection Manual Chapter 0609, 04, Initial Characterization of Findings, and Appendix A, Exhibit 1, Initiating Event Screening Questions, the finding was determined to be of very low safety significance (Green) because although the finding involved the complete loss of a support system that caused an initiating event, it did not involve the loss of affected mitigation equipment. The finding has a human performance cross-cutting aspect associated with field presence because the licensee failed to ensure proper oversight of contractors to ensure deviations from standards and expectations were promptly corrected [H.2].

Enforcement.

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. The licensee entered the finding into the corrective action program as Condition Report CR-2013-012287. The issue is being characterized as finding, FIN 05000445/2014003-07; 05000446/2014003-07, Failure to Follow the Site Design Modification Procedures.

2) Failure to Follow Procedure to Provide Adequate Work Instructions

Introduction.

The inspectors reviewed a Green self-revealing finding for the failure to properly plan and review work activities to ensure equipment and personnel safety.

Specifically, the licensee failed to ensure the work instructions met the requirements of Procedure STA-606, Control of Maintenance and Work Activities, Revision 32. As a result, during the implementation of the modification, personnel used an inadequate work instruction and cut the incorrect cable which caused both units to lose all offsite power to the safety-related 6.9 kV busses.

Description.

On December 4, 2013, transformer XST2 was supplying offsite power to both units while transformer XST1 was out of service. Workers attempted to connect power supply cables from transformer XST1 to newly installed switch boxes 04Y and 05Y in the Unit 2 normal switchgear room. The workers were not aware that the switch boxes 04Y and 05Y had been installed in the wrong location. The workers at switch box 05Y cut into an energized 6.9 kV cable from transformer XST2, resulting in the transformer isolating from the safety-related busses of both units and a complete loss of offsite power to safety-related busses.

The inspectors reviewed the work instructions provided to the workers. The inspectors determined that the licensees work instructions did not meet the requirements of Procedure STA-606, Control of Maintenance and Work Activities, Revision 32.

Step 6.7.5 of the procedure requires, in part, that:

(1) equipment is made safe for work to proceed; the equipment was not made safe because the work instructions did not include appropriate steps to verify the cables were de-energized

(2) adequate work instructions are prescribed that identify critical steps and industry operating experience is used; adequate work instructions were not prescribed and the work instruction failed to adequately incorporate recent operating experience involving workers cutting a wrong cable on October 30, 2013, and

(3) proper inspection or verification requirements are designated; proper verification requirements were not designated.

Analysis.

The licensees failure to follow procedure and provide adequate work instructions was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Initiating Events Cornerstone and adversely 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. Using Inspection Manual Chapter 0609, 04, Initial Characterization of Findings, and Appendix A, Exhibit 3, Initiating Event Screening Questions, the finding was determined to be of very low safety significance (Green) because although the finding involved the complete loss of a support system that caused an initiating event, it did not involve the loss of affected mitigation equipment. The finding has a human performance cross-cutting aspect associated with avoiding complacency, in that, the licensee failed to ensure that work planning personnel planned for the possibility of mistakes and latent issues and did not implement appropriate error reduction tools [H.12].

Enforcement.

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. The licensee entered the finding into the corrective action program as Condition Report CR-2013-012287. The issue is being characterized as finding, FIN 05000445/2014003-08; 05000446/2014003-08, Failure to Follow Procedure to Provide Adequate Work Instructions.

.2 (Closed) Licensee Event Report 05000445/2014-002-00, Noncompliance with Pressure

and Temperature Limits Report During Vacuum Fill The licensee event report documented a condition where the reactor coolant system pressure, temperature, and heatup and cooldown rates were not maintained with the limits of the pressure and temperature limits report. The pressure and temperature limits report only describes pressures equal to or greater than zero pounds per square inch gage. However, since early 1996, the licensee had been performing a vacuum fill of the reactor coolant system during refueling outages and lowered pressure below zero pounds per square inch gage. Technical Specification 3.4.3 RCS Pressure and Temperature (P/T) Limits, limiting condition for operation requires that, RCS pressure, RCS temperature, and RCS heatup and cooldown rates shall be maintained within the limits specified in the PTLR. If the limiting condition for operation cannot be met, Required Action C.1 requires the licensee to immediately initiate action to restore parameters to within limits. The licensee failed to restore the required parameters immediately. A contractor for the licensee revised pressure and temperature limits report. In March 2014, the licensee approved the revised document. On April 2, 2014, the licensee implemented Revision 3 of the pressure and temperature limits report that changed the lowest pressure value from zero pounds per square inch gage to -14.7 pounds per square inch gage. The enforcement aspects of this finding are discussed in Section 4OA7.1. This licensee event report is closed.

.3 (Closed) Licensee Event Report 05000446/2014-001-00, Cable Routing Unanalyzed for

Fire Safe Shutdown Barrier On April 18, 2014, the licensee identified that a Unit 2 fire safe shutdown cable was routed through a cable tray that was not protected by a fire barrier. Specifically, the licensee identified that cable EO223531 was routed through fire area SB in a cable tray that was not protected by the required 1-hour fire barrier (i.e., Thermo-Lag). This cable was part of the control circuit for motor-operated valve 2-8811A, the train A containment recirculation sump isolation valve. The licensee utilized an electronic cable and raceway data system (GENESIS) to determine that cable EO223531 needed to be protected with a fire barrier.

The licensee determined that cable EO223531 was not protected because the cable routing information in GENESIS did not match the field routing. The licensee reviewed the original cable pull cards from construction and verified that the information in GENESIS matched the information on the pull cards; however, the pull cards did not match the field routing. The licensee concluded that this condition existed since construction.

The inspectors interviewed the licensees engineering staff and reviewed the associated apparent cause evaluation. The inspectors performed an independent search of the corrective action program for condition reports associated with the GENESIS program in order to verify there was reasonable assurance that the licensee understood the extent of condition. The inspectors also determined that the licensee had previously performed fire protection modifications involving 189 cables and did not identify any other cable routing discrepancies.

The licensee took immediate actions to stop the implementation of the fire protection modification associated with this cable while a new modification was developed. The licensee continued to implement a roving fire watch as a compensatory action. The enforcement aspects of this finding are discussed in Section 4OA7.2. This licensee event report is closed.

.4 Unusual Event

a. Inspection Scope

On June 11, 2014, at 9:40 pm, the control room received indication of a Halon actuation in the Unit 2 cable spreading room. The licensee dispatched personnel to the cable spreading room and verified no fire existed. At 9:54 pm, operators declared an unusual event as a result of a Halon release into the Unit 2 cable spreading room and the lowering of oxygen levels below a safe habitable level, HU3.1. The inspectors responded to the control room to assess the operators performance and procedure usage. The inspectors verified the licensee entered the correct emergency classification. The inspectors observed the operators efforts to remove the Halon gas from the cable spreading room. The inspectors discussed the event with operations management and the control room staff. On June 12, 2014 at 3:30 am, the licensee restored habitability of the cable spreading room and exited the unusual event.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000445/2013005-03; 05000446/2013005-03, Notice of

Enforcement Discretion 13-4-004 for a Loss of Both Required Offsite Power Circuits

a. Inspection Scope

The inspectors performed a review of the circumstances associated with the granting of Notice of Enforcement Discretion 13-4-004 for Luminant Generation Company, LLC telephonically on December 5, 2013. The notice of enforcement discretion granted an additional 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> to restore compliance with Technical Specification 3.8.1, AC Sources - Operating. The inspectors verified the licensees oral assertions, including the likely cause and compensatory measures, and verified the notice of enforcement discretion request was consistent with the staffs policy and guidance. The licensee documented the issue in Licensee Event Report 05000445/2013-003-00. The inspectors closed the licensee event report in Section 4OA3.1 of this report.

b. Findings

No findings were identified.

.2 Impact of Financial Conditions on Continued Safe Performance

a. Inspection Scope

In that the licensees parent company, Energy Future Holdings, was under bankruptcy protection/reorganization during the inspection period, NRC Region IV conducted special reviews of processes at Comanche Peak. The inspectors evaluated several aspects of the licensees operations to determine whether the financial condition of the station impacted plant safety. The factors reviewed included:

(1) impact on staffing,

(2) corrective maintenance backlog,

(3) changes to the planned maintenance schedule,

(4) corrective action program implementation, and

(5) reduction in outage scope, including risk-significant modifications. In particular, the inspectors verified that licensee personnel continued to identify problems at an appropriate threshold and enter these problems into the corrective action program for resolution. The inspectors also verified that the licensee continued to develop and implement corrective actions commensurate with the significance of the problems identified.

The special review of processes at Comanche Peak included continuous reviews by the Resident Inspectors, as well as the specialist-led baseline inspections completed during the inspection period which are documented previously in this report.

b. Findings

No findings were identified.

4OA6 Meetings

Exit Meeting Summary

On April 10, 2014, the inspectors presented the radiation safety inspection results to Mr. K. Peters, Site Vice President, and other members of the licensee staff. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On April 18, 2014, the inspectors presented the inservice inspection activities inspection results to Mr. B. Mays, Assistant to the Chief Nuclear Officer, and other members of the licensee staff. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On May 8, 2014, the inspectors presented the results of the onsite inspection of the emergency preparedness program to Mr. F. Madden, Director, External Affairs, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On July 1, 2014, the inspectors presented the inspection results associated with the failure to correct fire protection violations in a timely manner to Mr. T. Hope, Manager, Regulatory Affairs, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On July 8, 2014, the inspectors presented the resident inspection results to Mr. K. Peters, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors acknowledged review of proprietary material during the inspection. No proprietary information was documented in the report.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as non-cited violations.

.1 Noncompliance with Pressure and Temperature Limits Report During Vacuum Fill

Technical Specification 3.4.3 RCS Pressure and Temperature (P/T) Limits, limiting condition for operation requires that, RCS pressure, RCS temperature, and RCS heatup and cooldown rates shall be maintained within the limits specified in the PTLR. If the limiting condition for operation cannot be met, Required Action C.1 requires, in part, that the licensee immediately initiate action to restore parameters to within limits. Contrary to the above, from 1996 until April 8, 2014, the licensee failed to immediately initiate action to restore parameters to within limits of the pressure and temperature limits report when operating outside the limits. Specifically, the licensee failed to maintain the parameters within the limits of the pressure and temperature limits report during a reactor coolant system vacuum evolution. The finding was more than minor because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that the reactor coolant system protect the public from radionuclide released caused by accidents or events. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, Exhibit 4, Barrier Integrity Screen Questions, the finding was determined to be of very low safety significance (Green) because the finding did not challenge the reactor coolant system barrier. The violation was entered into the licensees corrective action program as Condition Report CR-2014-000960. This is the enforcement aspect of the licensee event report discussed in Section 4OA3.2.

.2 Cable Routing Unanalyzed for Fire Safe Shutdown Barrier

License Condition 2.G for Unit 2 requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report through Amendment 87 and as approved in the Safety Evaluation Report and its supplements through Supplement 27. Section 9.5.1.3, Fire Hazard Analysis Evaluation, of the Final Safety Analysis Report references the Comanche Peak Nuclear Power Plant Fire Protection Report.Section II of the Fire Protection Report is the Fire Hazards Analysis Report. Section 4.5, Fire Protection Features for Fire Safe Shutdown, of the Fire Hazards Analysis Report specifies the allowable methods of ensuring that one of the redundant sets of systems necessary to achieve and maintain hot standby conditions is free of fire damage. Section 4.5.2.c, states, in part, that, enclosures of cables (if not one hour fire rated cables) and equipment and associated nonsafety circuits of components of redundant sets of systems in a fire barrier have a 1-hour rating. In addition, fire detectors and automatic fire suppressions systems adequate for hazards in the fire area are installed.

Appendix A, CPNPP Fire Protection Program Separation Criteria Comparison Table, of the Fire Protection Report specifies that the separation method per Section 4.5 of the Fire Hazards Analysis Report utilized in fire area SB is method 2.c.

Contrary to the above, prior to June 19, 2014, the licensee failed to ensure that an associated nonsafety circuit in fire area SB was enclosed in a fire barrier having a 1-hour rating. Specifically, the licensee failed to ensure that cable EO223531, a cable in the control circuit for the train A containment recirculation sump isolation valve, was enclosed in a fire barrier having a 1-hour fire rating. The licensee documented this issue in Condition Report CR-2014-004721. This violation was determined to be of very low safety significance (Green) based on Inspection Manual Chapter 0609, Appendix F, 1, Fire Protection Significance Determination Process Phase 1 Worksheet, Question 1.4.4.A. This is the enforcement aspect of the licensee event report discussed in Section 4OA3.3.

.3 Hot Short Prevention Cable Shield Conductor

License Condition 2.G for Unit 2 requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report through Amendment 87 and as approved in the Safety Evaluation Report and its supplements through Supplement 27. Section 13.3B.5, Quality Assurance Program, of the Final Safety Analysis Report describes the fire protection quality assurance program. The fire protection quality assurance program states that measures shall be established to ensure that conditions adverse to fire protection such as failures, malfunctions, deficiencies or deviations, defective components, uncontrolled combustible material and nonconformances are promptly identified, reported, and corrected. Contrary to the above, prior to June 19, 2014, the licensee failed to ensure that a condition adverse to fire protection was promptly corrected. Specifically, the licensee failed to properly connect the shield conductor for the hot short prevention cable that was installed as part of a modification to resolve a fire protection nonconformance. The licensee identified that the modification design connected the hot short prevention cable shield conductor to the plant ground instead of the dc negative potential. The licensee identified this issue in Condition Report CR-2014-005198. The senior reactor analyst determined this violation was of very low safety significance (Green) based on a bounding Phase 3 evaluation.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Flores, Senior Vice President and Chief Nuclear Officer

S. Bradley, Manager, Radiation Protection

D. Goodwin, Director, Work Management

T. Hope, Manager, Regulatory Affairs

J. Hull, Manager, Emergency Preparedness

F. Madden, Director, External Affairs

B. Mays, Assistant Chief Nuclear Officer

T. McCool, Vice President, Engineering and Support

D. McGaughey, Director, Performance Improvement

B. Moore, Director, Nuclear Training

K. Nickerson, Director, Engineering Support

B. Patrick, Director, Maintenance

J. Patton, Manager, Nuclear Oversight

K. Peters, Site Vice President

B. Reppa, Director, Site Engineering

S. Sewell, Plant Manager

M. Smith, Director, Nuclear Operations

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000445/2014003-03 URI Maintenance of a Standard Action Level Scheme for Main

05000446/2014003-03 Steam Line Monitors (Section 1EP5)

05000445/2014003-06 VIO Failure to Correct Fire Protection Violations in a Timely

05000446/2014003-06 Manner (Section 4OA2.2)

Opened and Closed

05000445/2014003-01 NCV Failure to Follow 10 CFR 50.59 for a Change to the Spent

05000446/2014003-01 Fuel Pool Configuration (Section 1R18)

05000446/2014003-02 NCV Failure to Provide Appropriate Instructions for Filling the Component Cooling Water System (Section 1R20)

05000445/2014003-04 NCV Failure to Adequately Brief Workers on Radiological

05000446/2014003-04 Conditions Prior to Entry into High Radiation Areas (Section 2RS1)

05000445/2014003-05 NCV Failure to Follow Procedure for Brazing Copper Tubing

05000446/2014003-05 (Section 4OA2.2)

05000445/2014003-07 FIN Failure to Follow the Site Design Modification Procedures

05000446/2014003-07 (Section 4OA3.1)

05000445/2014003-08 FIN Failure to Follow Procedure to Provide Adequate Work

05000446/2014003-08 Instructions (Section 4OA3.1)

Closed

05000445/2012004-03 URI Potential Failure to Follow 10 CFR 50.59 for a Change to the

05000446/2012004-03 Spent Fuel Pool Configuration (Section 1R18)

05000445/2013005-03 URI Notice of Enforcement Discretion 13-4-004 for a Loss of

05000446/2013005-03 Both Required Offsite Power Circuits (Section 4OA5.1)

05000445/2013-003-00 LER Auto Start of Both Units Auxiliary Feedwater Pumps and Emergency Diesel generators Due to a Loss of Both Units Safeguards Electrical Power (Section 4OA3.1)

05000445/2014-002-00 LER Noncompliance With Pressure and Temperature Limits Report During Vacuum Fill (Section 4OA3.2)

05000446/2014-001-00 LER Cable Routing Unanalyzed for Fire Safe Shutdown Barrier (Section 4OA3.3)