IR 05000445/2010006

IR 05000445-10-006, 05000446-10-006; May 24 - 28, 2010 and June 7 - 18, 2010; In-office June 1 - 4, 2010, Comanche Peak Nuclear Power Plant, Units 1 and 2: Baseline Inspection, NRC Inspection Procedure 71111.21, Component Design Bases Inspe

ML103230122
Person / Time
Site:	Comanche Peak
Issue date:	11/19/2010
From:	Caniano R Division of Reactor Safety IV
To:	Flores R Luminant Generation Co
References
EA-10-144 IR-10-006
Download: ML103230122 (66)

Text

UNITED STATES NUCLEAR REGULATORY COMM I SSI ON ber 19, 2010

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT - NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000445/2010006; 05000446/2010006; PRELIMINARY WHITE FINDING

Dear Mr. Flores:

On June 18, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed the onsite portion of a component design bases team inspection at the Comanche Peak Nuclear Power Plant. The enclosed inspection report documents the inspection findings. The team discussed the preliminary findings on June 18, 2010, with Mr. Ben Mays, Vice President, Nuclear Engineering and Support and other members of your staff. After additional in-office inspection, the team leader conducted a final telephonic exit on November 4, 2010, with Mr. Ben Mays, and other members of your staff.

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

The report discusses preliminary results of the inspection including a finding, which involves the failure to evaluate and then incorporate relevant operating experience information into station instructions, procedures, or drawings. This resulted in a condition where failure of the condensate storage tank diaphragm could block the suction to the auxiliary feedwater pumps.

The finding associated with this condition was assessed based on the best available information, including influential assumptions and vendor information, using the applicable significance determination process. The preliminary significance determination was based on Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, and indicated that the finding was of low to moderate safety significance (White). Additional details of the primary assumptions associated with the preliminary significance determination are documented in Attachment 2 of the enclosure.

The finding is also an apparent violation of NRC requirements and is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy. The current Enforcement Policy is included on the NRCs Web site at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.

Luminant Generation Company LLC -2-Before we make a final decision on this matter, we are providing you an opportunity to (1) to attend a Regulatory Conference where you can present to the NRC your perspectives on the facts and assumptions used by the NRC to arrive at the finding and its significance, at a Regulatory Conference or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 30 days of the receipt of this letter. If you decline to request a Regulatory Conference or submit a written response, you relinquish your right to appeal the final SDP determination, in that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of IMC 0609.

In accordance with NRC Inspection Manual Chapter 0609, we intend to complete our evaluation using the best available information and issue our final determination of safety significance within 90 calendar days of the date of this letter. The Significance Determination Process encourages an open dialogue between the NRC staff and the licensee. However, the dialogue should not impact the timeliness of the staffs final determination.

Because the NRC has not made a final determination in this matter, a Notice of Violation is not being issued for the inspection finding at this time. In addition, please be advised that the number and characterization of apparent violations described in the enclosed inspection report may change as a result of further NRC review.

This report also documents four NRC identified findings of very low safety significance (Green)

and one NRC-identified Severity Level IV violation. The findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with the NRC Enforcement Policy. If you contest the noncited violations or the significance of the noncited violations, 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, D.C.

20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Comanche Peak Nuclear Power Plant. In addition, if you disagree with the crosscutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at the Comanche Peak Nuclear Power Plant.

Please contact Mr. Thomas Farnholtz at (817) 860-8243 and in writing within 10 days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision.

The final resolution of this matter will be conveyed in separate correspondence

Luminant Generation Company LLC -3-In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosures will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Roy J. Caniano, Director Division of Reactor Safety Dockets: 50-445; 50-446 Licenses: NPF-87; NPF-89 Enclosure:

NRC Inspection: Report 05000445/2010006; 05000446/2010006 w/Attachments: Attachment 1: Supplemental Information Attachment 2: Phase 3 Analysis Attachment 3: Appendix M Analysis Attachment 4: Vendor Letter Mr. Fred W. Madden, Director Oversight and Regulatory Affairs Luminant Generation Company LLC P.O. Box 1002 Glen Rose, TX 76043 Timothy P. Matthews, Esq Morgan Lewis 1111 Pennsylvania Avenue, NW Washington, DC 20004 County Judge P.O. Box 851 Glen Rose, TX 76043 Mr. Richard A. Ratliff, Chief Bureau of Radiation Control Texas Department of Health P.O. Box 149347, Mail Code 2835 Austin, TX 78714-9347

Luminant Generation Company LLC -4-Environmental and Natural Resources Policy Director Office of the Governor P.O. Box 12428 Austin, TX 78711-3189 Honorable Walter Maynard County Judge P.O. Box 851 Glen Rose, TX 76043 Mr. Brian Almon Public Utility Commission William B. Travis Building P.O. Box 13326 Austin, TX 78711-3326 Ms. Susan M. Jablonski Office of Permitting, Remediation and Registration Texas Commission on Environmental Quality MC-122 P.O. Box 13087 Austin, TX 78711-3087 Anthony Jones Chief Boiler Inspector Texas Department of Licensing And Regulation Boiler Division E.O. Thompson State Office Building P.O. Box 12157 Austin, TX 78711 Chief, Technological Hazards Branch FEMA Region VI 800 North Loop 288 Federal Regional Center Denton, TX 76209

Luminant Generation Company LLC -5-Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

Deputy Regional Administrator (Chuck.Casto@nrc.gov)

DRP Director (Kriss.Kennedy@nrc.gov)

DRP Deputy Director (Anton.Vegel@nrc.gov)

DRS Director (Roy.Caniano@nrc.gov)

DRS Deputy Director (Troy.Pruett@nrc.gov)

Senior Resident Inspector (John.Kramer@nrc.gov)

Resident Inspector (Brian.Tindell@nrc.gov)

Branch Chief, DRP/A (Wayne.Walker.nrc.gov)

Senior Project Engineer, DRP/A (David.Proulx@nrc.gov)

Project Engineer, DRP/A (Laura.Micewski@nrc.gov)

CP Administrative Assistant (Sue.Sanner@nrc.gov)

Public Affairs Officer (Victor.Dricks@nrc.gov)

Public Affairs Officer (Lara.Uselding@nrc.gov)

Project Manager (Balwant.Singal@nrc.gov)

Branch Chief, DRS/TSB (Michael.Hay@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Congressional Affairs Officer (Jenny.Weil@nrc.gov)

Enforcement Officer (Ray.Kellar@nrc.gov)

Senior Reactor Analyst (Michael.Runyan@nrc.gov)

OEMail Resource Inspection Reports/MidCycle and EOC Letters to the following:

ROPreports Only inspection reports to the following:

OEDO RIV Coordinator (Geoffrey.Miller@nrc.gov)

R:\ ADAMS ML ADAMS: No X Yes X SUNSI Review Complete Reviewer Initials: WCS X Publicly Available X Non-Sensitive Non-publicly Available Sensitive SRI/EB1 RI/EB1 C:EB1 RI/EB2 SOE/OB RA/ACES WCSifre PAGoldberg TRFarnholtz JLWatkins KDClayton RLKellar

/RA/ /RA/ /RA/ /RA/ /RA/ /RA/

11/17/2010 11/17/2010 11/18/2010 11/18/2010 11/18/2010 11/18/2010 SRI/DRP C:DRP SRA/DRS RI/TSB D:DRS JGKramer WCWalker MFRunyan BBRice RJCaniano

/RA/ /RA/ /RA/ /RA/ /RA/

11/17/2010 11/18/2010 11/18/2010 11/18/2010 11/19/2010 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 50-445, 50-446 License: NPF-87, NPF-89 Report: 05000445/2010006 and 05000446/2010006 Licensee: Luminant Generation Company LLC Facility: Comanche Peak Nuclear Power Plant, Units 1 and 2 Location: FM-56, Glen Rose, Texas Dates: May 24 - 28, 2010 Onsite June 1 - 4, 2010 In-Office June 7 - 18, 2010 Onsite Team Leader: W. Sifre, Senior Reactor Inspector Inspectors: K. Clayton, Senior Operations Engineer P. Goldberg, Reactor Inspector J. Watkins, Reactor Inspector B. Rice, Reactor Inspector J. Leivo, NRC Contractor, Beckman and Associates M. Yeminy, NRC Contractor, Beckman and Associates Approved By: Roy J. Caniano, Director, Division of Reactor Safety-1- Enclosure

SUMMARY OF FINDINGS

IR 05000445/2010006, 05000446/2010006; May 24 - 28, 2010 and June 7 - 18, 2010; In-office

June 1 - 4, 2010, Comanche Peak Nuclear Power Plant, Units 1 and 2: baseline inspection,

NRC Inspection Procedure 71111.21, Component Design Bases Inspection.

The report covers an announced inspection by a team of four regional inspectors and two contractors. One Apparent Violation, one Severity Level IV violation, and four violations of very low safety significance were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process, and the crosscutting aspects were determined by using Inspection Manual Chapter 0310, Components within the Crosscutting Areas. Findings for which the Significance Determination Process does not apply may be Green or be assigned a Severity Level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

• Apparent Violation. The team identified an apparent violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, involving the failure of personnel to initiate a SmartForm to enter actual or potential adverse conditions into the corrective action program following receipt of operating experience. Specifically, in July 2002, the licensee received relevant information provided by the manufacturer of the Unit 1 and 2 condensate storage tank diaphragms to ensure the diaphragm integrity would be maintained but failed to enter the issue into the corrective action program as required by Comanche Peak Station Procedure STA-206, Review of Vendor Documents and Vendor Technical Manuals, Revision 20. In addition, in November 2007, the licensee received industry-operating experience regarding a condensate storage tank diaphragm failure at the Farley Nuclear Plant but failed to enter this issue into the corrective action program as required by Procedure STA-426, Industry Operating Experience Program, Revision 1. Because actions were not taken in response to the vendor and operating experience information, the diaphragm was susceptible to failure, which could cause a loss of suction to all three auxiliary feedwater pumps. This finding was entered into the licensees corrective action program as Condition Reports CR-2010-005508, CR-2010-005581 and CR-2010-005962.

The team determined that the failure to incorporate relevant operating experience information into station instructions, procedures, or drawings to maintain the condensate storage tank diaphragm in a configuration where its performance during accident conditions would preclude blockage of the suction pipes to the auxiliary feedwater pumps was a performance deficiency. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening, in accordance with Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding represented the degradation of equipment and functions specifically designed to mitigate the loss of feedwater and that during an event the loss would degrade or make inoperable all three of the auxiliary feedwater pumps. Therefore, the finding was potentially risk significant and a Phase 3 analysis was required. The preliminary significance determination was based on Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, and indicated that the finding was of low to moderate safety significance (White). This finding has a crosscutting aspect in the area of human performance, work practices, because the licensee did not define and effectively communicate expectations regarding procedural compliance and personnel following procedures involving evaluation of operating experience H.4(b)(Section1R21.2.2).

Green.

The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion XI, Test Control, which states, in part, that all testing required to demonstrate that structures, systems, components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents.

Specifically, as of June 18, 2010, the licensee failed to complete pre-operational testing required to demonstrate that the emergency diesel generator air start system receivers satisfied the requirements and acceptance limits contained in applicable design documents. This finding was entered into the licensees corrective action program as Condition Report CR-2010-005924.

The team determined that the failure to ensure that the testing required to demonstrate that the Unit 1 emergency diesel generator air start systems will perform satisfactorily in service and in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents was a performance deficiency. The finding was more than minor because it was associated with the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of safety systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Inspection Manual Chapter 0609, Attachment 4, Phase 1

- Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance (Section 1R21.2.4).

Green.

The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, which states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, as of June 18, 2010, the licensee failed to properly translate technical specification allowable diesel generator frequency range to design documents. This finding was entered into the licensees corrective action program as Condition Report CR-2010-005563.

The team determined that the failure to analyze the emergency diesel generators for operation over the entire range of allowed frequency was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Inspection Manual Chapter 0609, Attachment 4, Phase 1

- Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding has a crosscutting aspect in the area of problem identification and resolution because the licensee did not effectively incorporate operating experience into the preventive maintenance program for the emergency diesel generators. Specifically, the licensee failed to incorporate information provided in Information Notice 2008-02, which could have affected the capability of equipment such as safety related motor operated pumps to perform their safety function under the most limiting conditions

P.2(a)(Section 1R21.2.5).

Green.

The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control which states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, as of June 18, 2010, the licensee failed to perform an adequate hydrogen evolution calculation, for the safety-related and nonsafety-related batteries, using the most limiting expected condition of forcing maximum current into a fully charged battery which led to a ventilation system design that did not limit hydrogen accumulation to less than two percent of the total volume of the battery areas during all conditions. This finding was entered into the licensees corrective action program as condition reports CR-2010-005941, CR-2010-005941, and CR-2010-006561.

The team determined that the failure to adequately perform the hydrogen evolution calculation for the safety-related battery, using the most limiting condition, was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone attribute of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Manual Chapter 0609, Attachment 4, Phase 1

- Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance (Section 1R21.2.10).

• Severity Level IV. The team identified a noncited violation of 10 CFR 50.9,

Completeness and Accuracy of Information, which states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Specifically, on June 20, 2007, the licensee asserted in their response to Generic Letter 2007-01, Inaccessible or Underground Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients, Request 2, that Comanche Peak periodically performs visual inspection for corrosion and degradation of cable tray supports and a preventive maintenance program for inspection/removal of water from manholes. The team determined the licensee had no preventive maintenance program or procedures in place to govern the inspection or preventive maintenance activities described in their response, and there was no evidence that these manholes, raceways, and supports had ever been inspected prior to November 2009. This finding was entered into the licensees corrective action program as Condition Report CR-2010-005784.

The team determined that the failure to provide accurate information in the licensees response to Generic Letter 2007-01 was a performance deficiency. The finding is more than minor because the information was material to the NRCs decision-making processes. Specifically, the information requested by Generic Letter 2007-01 was to enable NRC staff to determine whether the applicable regulatory requirements identified in the generic letter (10 CFR Part 50, Appendix A, General Design Criteria 4, 17, and 18; 10 CFR 50.65(a)(1); 10 CFR Part 50, Appendix B, Criterion XI), were being met with regard to the operational readiness of critical systems that could cause a plant transient or mitigate accidents, and to obtain further information on cable failures (Section 1R21.3.2).

Green.

The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, which states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, as of June 18, 2010, the underground duct banks connecting the safeguards buildings to the service water intake structure had installed conduit seals at a low point in the cable manholes, thereby defeating the design requirement to avoid or minimize the accumulation of water in the duct banks. This configuration could result in long-term submergence of safety related medium voltage cables and long-term degradation or failure of the cables. This finding was entered into the licensees corrective action program as Condition Report CR-2010-005843.

The team determined that the failure to implement a design requirement to avoid or minimize accumulation of water in the underground duct banks was a performance deficiency. The finding is more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Inspection Manual Chapter 0609, Attachment 4,

Phase1 - Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance (Section 1R21.3.2).

REPORT DETAILS

REACTOR SAFETY

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

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

1R21 Component Design Bases Inspection

The team selected risk-significant components and operator actions for review using information contained in the licensees probabilistic risk assessment. In general, this included components and operator actions that had a risk achievement worth factor greater than two or a Birnbaum value greater than 1E-6. The items selected included components in both safety-related and nonsafety related systems including pumps, circuit breakers, heat exchangers, transformers, and valves. The team selected the risk significant operating experience to be inspected based on its collective past experience.

a. Inspection Scope

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

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

The team performed a margin assessment and detailed review of the selected risk significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design issues, margin reductions because of modifications, and margin reductions identified because of material condition issues. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as failed performance test results; significant corrective actions; repeated maintenance; 10 CFR 50.65(a)1 status; operable, but degraded, conditions; NRC resident inspector input of problem equipment; system health reports; industry operating experience; and licensee problem equipment lists. Consideration was also given to the uniqueness and

complexity of the design, operating experience, and the available defense in-depth margins.

The inspection procedure requires a review of 20 to 30 total samples that include 10 to 20 risk-significant and low design margin components, 3 to 5 relatively high-risk operator actions, and 4 to 6 operating experience issues. The sample selection for this inspection was 15 components, 4 operator actions, and 5 operating experience items.

The selected inspection items supported risk significant functions as follows:

(1) Electrical power to mitigation systems: The team selected several components in the offsite and onsite electrical power distribution systems to verify operability to supply alternating current

(ac) and direct current

(dc) power to risk significant and safety-related loads in support of safety system operation in response to initiating events such as loss of offsite power, station blackout, and a loss-of-coolant accident with offsite power available. The team also reviewed the licensees response to Information Notice 2002-12, Submerged Safety-Related Electrical Cables and Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients. As such the team selected:

(a) The emergency diesel generator air start system

(b) The 6.9 kV engineered safety features switchgear to determine the adequacy of the loading margins available for accident conditions.

Response to Information Notice 2007-34, Operating Experience Regarding Electrical Circuit Breakers

(c) The time delay relays for the 6.9Kv bus diesel generator start function

(d) The emergency diesel generator jacket water heat exchanger systems

(e) The 125 Vdc safety-related station batteries

(f) The 6.9 kV safeguard bus undervoltage relays

(g) The preferred feeder circuit Breakers T1EB2 / T1EB3 to the 480 Vac switchgear 1EB2

(h) The 125 Vdc Distribution Panel 1ED1 (1-5) fused disconnect switch

(2) Initiating events minimization:

(a) The condensate storage tank and the water volume available for auxiliary feedwater

(b) The auxiliary feedwater system flow control valves. Operator actions to isolate auxiliary feedwater flow to a steam generator fault inside containment within the required 10 minutes

(c) The component cooling water heat exchangers

(d) The residual heat removal recirculation isolation valves

(3) Decay heat removal:

(a) The safety chilled water chillers

(b) The service water pumps and motor operated Valves 1-HV-4286 / 4287 provide cooling water flow to remove decay heat. Response to Generic Letter 1989-13, Service Water System Problems Affecting Safety-Related Equipment

.2.1 Safety Chilled Water Chillers:

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report; design bases documents, calculations, and recent corrective and preventive maintenance of the safety chilled water chillers. These reviews were conducted to verify the adequacy of design for the room coolers, and to verify that heat will be adequately removed during operation of the equipment in the rooms. The team also conducted walkdowns of the room cooler areas to ensure adequate equipment physical condition. Specifically, the team reviewed:

• Heat load and heat removal calculations, including service water temperature and flow requirement calculations for the room coolers.

• Recent thermal performance test results, which included measurement of air and water flow rates, and a calculation of as-found heat exchanger fouling factors.

• Piping and instrumentation diagrams, vendor manual, and a sample of condition reports for the room cooler.

b. Findings

No findings were identified.

.2.2 Condensate Storage Tank

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations, recent corrective action documents, and technical specifications for the condensate storage tank including the water volume available for the auxiliary feedwater system. The inspection included a walkdown of the Unit 1 condensate storage tank and the suction piping for the auxiliary feedwater pumps. In addition, the inspection included a special observation of the condensate storage tank diaphragm, located inside the tank, once without and once with the use of a special camera. Specifically the team reviewed:

• The lowest level at which water is added to the condensate storage tank to increase inventory and the level at which water addition is stopped.

The inspectors reviewed these levels with respect to instrument uncertainties and the effect of the nitrogen pressure under the tank diaphragm on the level indication and the setpoints of the level instruments.

• The maintenance and operating history and practices associated with the condensate storage tank and diaphragm.

• The seismic analysis of the condensate storage tank with special emphasis on the seismic analysis of the ring supporting the diaphragm.

• The condensate storage tank diaphragm, the possibility of its failure and the consequences of such a failure. The inspectors paid special attention to the diaphragms density (specific gravity) and possible modes of failure.

The review included discussions with the diaphragm manufacturer and with other industry users of this type of diaphragm.

b. Findings

Failure to Incorporate Relevant Operating Experience Information into Station Procedures Regarding the Condensate Storage Tank and Diaphragm

Introduction.

The team identified an apparent violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to ensure that vendor information and operating experience were properly evaluated. The failure to properly assess operating experience for the Unit 1 condensate storage tank resulted in a condition where failure of the diaphragm could result in all three auxiliary feedwater pump suction lines from the condensate storage tank being blocked. This finding has a preliminary safety significance of low to moderate (White).

Description.

The team reviewed the condensate storage tank with special attention paid to the diaphragm (also referred to as a bladder) installed inside the tank including the possibility of its failure and the consequences of such a failure.

The purpose of the diaphragm is to maintain water chemistry, specifically dissolved oxygen, by ensuring separation between the water in the tank and the atmosphere. The team reviewed the diaphragms physical properties, operating parameters, and searched for possible modes of failure of the diaphragm that could affect safety related functions of the condensate storage tank. The search included discussions with the diaphragm manufacturer and with other users of this type of diaphragm.

The original diaphragm installed in the Unit 1 condensate storage tank was made of a rubber type material that was lighter than water. It was replaced in 1995 with a diaphragm made of a thermoplastic elastomer material which is heavier than water (specific gravity of 1.15 +/- 0.1). The new diaphragm is equipped with four floaters that keep the diaphragm from sinking to the bottom of the tank.

The team reviewed the licensees practice of adding nitrogen to the condensate storage tank from a nozzle under the waters surface including the effect on the waters surface, the status of the resultant bubble between the water surface and the diaphragm, and whether the nitrogen addition reached the space between the vertical section of the diaphragm and the tanks inner wall. This was important to ascertain whether the gas volume on the water surface communicated with the volume between the diaphragm and the condensate storage tank wall.

The licensee received an operating experience notification, dated July 29, 2002, in the form of a letter from the diaphragm vendor (see Attachment 4). The letter states, in part, that the diaphragm, to function freely without undue stress, must have some air remaining between the tank wall and the diaphragm material on the waterside. The letter also states that, Our concerns are greater for the absence of gases since we have observed the diaphragm material sticking tighter than wallpaper to the tank wall. The team reviewed procedure STA-206, Review of Vendor Documents and Vendor Technical Manuals, Revision 20, which was in place at the time the July 2002 letter was received. Section 6.2.2 of this procedure required that for vendor documents that impact site procedures or activities, the reviewer should ensure that an update document for the affected procedure or activity is issued. In addition, this section required that, if anytime during the vendor document review process it is discovered that actual or potential adverse conditions exist, the issue should be entered into the corrective action program. The team determined that the reviewer failed to recognize the potential significance of this vendor information to Comanche Peak, failed to enter this condition into the corrective action program, and failed to initiate appropriate procedure changes that would ensure that the condensate storage tank diaphragm was not placed in a condition that could result in failure of the diaphragm.

Because of a very high nitrogen bubble, the licensee ceased nitrogen injection to the Unit 1 condensate storage tank on March 15, 2010, while continuing to evacuate air from the tank. The team noted that the gas between the diaphragm and condensate storage tank wall was evacuated. The nitrogen bubble between the underside of the diaphragm and the water surface indicated that there was little or no communication between the area above the water surface and the area between the diaphragm and the tank wall.

The team noted that the regularly conducted inspections of the diaphragm done by the licensee were performed by removing an inspection port located at the top of the condensate storage tank and observing the top of the diaphragm.

However, due to the tank configuration, the vertical sides of the diaphragm were not visible. On June 11, 2010, the team and the licensee inspected the diaphragm with a camera that could be angled such that the entire diaphragms vertical section could be observed. The video produced during the inspection revealed that the vertical section of the diaphragm was tightly adhered to the condensate storage tank wall with a vacuum immediately under the top ring from which the diaphragm was hung. The vacuum was created because the licensee ceased nitrogen injection on March 15, 2010, but continued evacuation of the space between the condensate storage tank wall and the diaphragm in an attempt to reduce the size of the 48-inch high nitrogen bubble. As a result, the

licensee declared the Unit 1 condensate storage tank inoperable on June 11, 2010, and injected 275 cubic feet of nitrogen into the space between the tank wall and the diaphragm. Following the nitrogen injection the licensee declared the Unit 1 condensate storage tank operable.

The team noted that a condensate storage tank diaphragm failure had occurred at the Farley Nuclear Plant, on October 29, 2007. The failed diaphragm at Farley Nuclear Plant was the same type as that used in the condensate storage tank at the Comanche Peak facility. The modes of failure in that case were identified as

(1) the diaphragm was tightly stuck to the wall of the tank which prevented its free decent and ascent with the water level and

(2) three of the four floaters that kept the heavier-than-water diaphragm from sinking to the bottom of the tank were found dislodged from the pockets in the diaphragm and floating on the water surface. The floaters that were ejected were sealed on only three sides instead of the required four. The team determined that the floaters of the Comanche Peak condensate storage tank diaphragm were susceptible to the same failure because they were only sealed on three sides. The diaphragm that failed at Farley Nuclear Plant sank to the bottom of the tank resulting in the blocking of pump suction piping.

The team requested that the licensee search for operating experience identifying the failure at Farley Nuclear Plant. The licensee located an operating experience report notifying Comanche Peak of this failure. The notification was received in November 2007. The licensee had assigned notification number OE25829, and Level 2, which did not require a condition report and only required notification to the appropriate personnel. The operating experience was sent to the appropriate personnel for review, but no condition report was written and there was no documentation of their review. The team reviewed Procedure STA-426, Industry Operating Experience Program, Revision 1, which was in place at the time the November 2007 operating experience was received. Section 6.2.5 of this procedure required that individuals who receive distribution of operating experience should carefully examine the information for applicability to Comanche Peak programs, procedures, processes, and/or systems, structures, and components. If they determine that further evaluation is necessary or specific improvements need to be made to preclude the event from occurring at Comanche Peak, then the responsible individual should enter the issue into the corrective action program. The team determined that the reviewer failed to recognize the potential significance of this operating experience to Comanche Peak, failed to enter this condition into the corrective action program, and failed to initiate appropriate procedure changes that would ensure that the condensate storage tank diaphragm was not placed in a condition that could result in a similar failure as that seen at the Farley Nuclear Plant.

The action taken on March 15, 2010, to discontinue nitrogen injection and continue evacuation was performed in accordance Procedure COP-303A, Condensate, Revision 11, Procedure Change Notice 5. The team reviewed this procedure and noted that it contained no specific cautions or other information regarding the concerns specified in the July 2002 vendor letter or the November 2007 operating experience notification for the Farley Nuclear Plant diaphragm failure. The lack of specific instructions regarding nitrogen injection into the condensate storage tank combined with less than complete inspections

of the diaphragm resulted in placing the diaphragm in a condition that could potentially result in its failure.

A failure of the diaphragm, similar to the failure that had occurred at the Farley Nuclear Plant, would most likely occur during tank drawdown or during an accident when the auxiliary feedwater pumps are required to operate. The two suction nozzles of the three auxiliary feedwater pumps are located less than three feet apart near the bottom of the tank.

Because of the inspection, the licensee took corrective actions to change the way the diaphragm bubble was inspected, increased the frequency of material inspections, and changed the method of adding nitrogen to the condensate storage tank.

Analysis.

The team determined that the failure to incorporate relevant operating experience information into station instructions, procedures, or drawings to maintain the condensate storage tank diaphragm in a configuration where its performance during accident conditions would preclude blockage of the suction pipes to the auxiliary feedwater pumps was a performance deficiency. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening, in accordance with Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding represented the degradation of equipment and functions specifically designed to mitigate the loss of feedwater and that during an event the loss would degrade or make inoperable all three of the auxiliary feedwater pumps. Therefore, the finding was potentially risk significant and a Phase 3 analysis was required (see Attachment 2). The preliminary significance determination was based on Inspection Manual Chapter 0609, Appendix M, Significance Determination Process using Qualitative Criteria, and indicated that the finding was of low to moderate safety significance (White) (see Attachment 3). This finding has a crosscutting aspect in the area of human performance, work practices, because the licensee did not define and effectively communicate expectations regarding procedural compliance and personnel following procedures involving evaluation of operating experience H.4(b).

Enforcement.

The team identified an apparent violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, which states, in part, that Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Comanche Peak Station Procedure STA-206, Review of Vendor Documents and Vendor Technical Manuals, Revision 20, Section 6.2.2 stated, in part, If anytime during the vendor document review process it is discovered that actual or potential adverse conditions exist, a SmartForm shall be initiated.

Comanche Peak Station Procedure STA-426, Industry Operating Experience Program, Revision 1, Section 6.2.5 stated, in part, Individuals who receive distribution of industry operating experience should carefully examine the

information for applicability to Comanche Peak programs, procedures, processes, and/or systems, structures, and components. If they determine that further evaluation is necessary or specific improvements need to be made to preclude the event from occurring at Comanche Peak, then the responsible individual should generate a SmartForm. Contrary to the above, on two occasions, the licensee failed to initiate a SmartForm to enter actual or potential adverse conditions into the corrective action program. Specifically, in July 2002, the licensee received relevant information provided by the manufacturer of the Unit 1 and 2 condensate storage tank diaphragms but failed to enter this issue into the corrective action program or to incorporate this information into station procedures. In addition, in November 2007, the licensee received industry-operating experience regarding a condensate storage tank diaphragm failure at the Farley Nuclear Plant but failed to enter this issue into the corrective action program or to incorporate this information into station procedures governing the operation of the Unit 1 condensate storage tank diaphragm. The purpose of establishing these measures was to avoid damage to the diaphragm, which could then sink to the bottom of the condensate storage tank and potentially cause a loss of suction to all three auxiliary feedwater pumps. This finding was entered into the licensees corrective action program as Condition Reports CR-2010-005508, CR-2010-005581 and CR-2010-005962. Pending completion of a final significance determination, the performance deficiency will be considered an apparent violation, AV 05000445/2010006-01, Failure to Incorporate Relevant Operating Experience Information into Station Procedures Regarding the Condensate Storage Tank and Diaphragm.

.2.3 Residual Heat Removal Isolation Valves 8701A, 8701B, 8702A, 8702B

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations and recent corrective action documents for the residual heat removal isolation Valves 8701A, 8701B, 8702A, and 8702B. Specifically, the team reviewed:

• The valve modifications, safety analyses, system drawings, specifications, test data, system health reports, and operating surveillance procedures.

• The valve vendor manual and related vendor correspondence and system drawings.

• The valve maintenance, and operational requirements related to valve design pressure, torque and stem thrust requirements, and permissive set points for system pressure.

• The design calculations and documentation of periodic surveillance tests were reviewed to verify that design performance requirements were satisfied.

• Maintenance, in-service testing, corrective actions and design change histories were reviewed to assess the potential for component degradation and resulting impact on design margins and performance.

b. Findings

No findings were identified.

.2.4 Emergency Diesel Generator Air Start System

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, maintenance history, operational requirements, modifications, system drawings, specifications, test data, system health, as well as operating and surveillance procedures. The team concentrated its efforts on the air start systems capability of performing its safety function, i.e., delivering a motive force necessary to start the emergency diesel generator and having the capacity to provide 5 start attempts without recharging as required by license basis documents. The team also conducted walkdowns of portions of the emergency diesel generator air start system to verify that the installed configuration was consistent with design basis information and visually inspected the material condition of the air start systems. Specifically, the team reviewed:

• The diesel generator vendor manual, related vendor correspondence, and system drawings related to the air start system.

• Design calculations and documentation of periodic surveillance tests and pre-operational tests to verify that design performance requirements were satisfied.

• Maintenance, in-service testing, corrective actions, and design change histories to assess the potential for component degradation and resulting impact on design margins and performance.

b. Findings

Inadequate Test Control of the Diesel Generator Air Starting System

Introduction.

The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, related to the air start systems for both Unit 1 emergency diesel generators. Specifically, the inspectors identified that the pre-operational test for each diesel generator starting air system was not properly designed and implemented to demonstrate that the system as-built configuration satisfied the requirements described in the Updated Final Safety Analysis Report. This resulted in the failure to ensure each diesel generator air receiver is capable of starting the diesel engine five consecutive times without recharging the receivers.

Description.

The design basis for the air start system, as stated in the Updated Final Safety Analysis Report, Section 9.5.6.2, System Description, Revision 102, is that each diesel generator has two 100 percent capacity air systems. Each system includes an air receiver that is sized to store enough air for five starts with an initial nominal air receiver pressure between 220 psig and 250 psig. Additionally, the Updated Final Safety Analysis Report states in Section 9.5.4.4, Inspection and Testing Requirements, that prior to plant initial operation, the diesel generators are installed and thoroughly tested to demonstrate their ability to perform as designed.

The inspectors reviewed factory test results and pre-operational test results that the licensee performed to demonstrate that the design basis was satisfied at the time the plant was constructed. During the review of the factory test data, the inspectors noted that there was no documentation verifying that the factory tests were an accurate representation of the as-built configuration of the Unit 1 emergency diesel generators or that the test was performed in a manner that was in accordance with the licensees license basis.

The inspectors reviewed pre-operational test procedures and results and determined that the test did not adequately demonstrate that the Unit 1 emergency diesel generator air start systems met the design requirement of having the capability of cranking a cold diesel five times without recharging the receivers. The test procedure was inadequate in that it allowed the use of the air compressor in between start attempts. Specifically, in Procedure OPT-214A, Diesel Generator Operability Test, Revision 19, steps 7.1.16 and 7.2.16 stated, in part, If the air pressure has fallen, place the Diesel Generator Air Compressor 1 switchin the Hand position and allow the pressure to return to the value recorded on Data Sheet 1.

The inspectors could not determine from the test data whether or not the air compressor was used to adjust the air pressure between start attempts.

However, since the procedure allowed such actions the test results were unreliable. Furthermore, a review of the pre-operational test results revealed that the test start point of 244 psig and 248 psig for DG 1-01 and DG 1-02 respectively was nonconservative in that it did not bound the normal operating pressure band of 220 psig to 250 psig.

The pre-operational testing results were as follows:

Table 1: Unit 1, Diesel Generator 1-01 Start Attempt Starting Air Pressure (psig) Remaining Air Pressure (psig)244 220 220 202 202 184 184 168 168 155 Table 2: Unit 1, Diesel Generator 1-02 Start Attempt Starting Air Pressure (psig) Remaining Air Pressure (psig)248 224 224 202 202 184 184 169 169 154 During a review of past results from surveillance procedure OPT-214A, the inspectors found that the receiver pressure was consistently below the pre-

operational test starting pressures of DG 1-01 and DG 1-02. Specifically, in 50 percent of the surveillance tests reviewed, the air receiver pressure was below 240 psig. The starting pressures used in the Unit 1 pre-operational test for diesel generators do not bound the normal operating conditions of the emergency diesel air start systems. Upon questioning, the licensee stated that it was their understanding that the five-start capability for each receiver was a sizing criteria used to purchase the receivers and that demonstrating the capability for five starts per receiver was not required.

The inspectors reviewed applicable documentation that described the initial licensing basis for the emergency diesel generator air start systems. Design Basis Document DBD-ME-011, Diesel Generator Sets, Revision 30, states, in part, that the diesel generator sets air start system shall be designed to start the diesel generator set when required and shall meet the requirements of Standard Review Plan Section 9.5.6. Acceptance Criteria 4g in Section 9.5.6 of the Standard Review Plan requires that as a minimum, the air starting system should be capable of cranking a cold diesel engine five times without recharging the receiver(s). The air starting system capacity should be determined as follows:

(1) each cranking cycle duration should be approximately three seconds; (2)consist of two to three engine revolutions; or

(3) air start requirements per engine start provided by the engine manufacturer, whichever air start requirement is larger.

NRC Safety Evaluation Report (NUREG - 0787) related to the operation of Comanche Peak, Section 9.5.6, states that each emergency diesel generator has an independent and redundant air-starting system consisting of two separate full-capacity air-starting subsystems each with sufficient storage capacity to provide a minimum of five consecutive cold engine starts. Thus, the requirements of 10 CFR 50, Appendix A, General Design Criteria 17 were not met.

The inspectors determined that the five-start capability for each receiver was an initial design requirement and was required to be demonstrated via appropriate testing in order to satisfy 10 CFR 50, Appendix A, General Design Criteria 17.

The inspectors determined that the failure to ensure that all testing required to demonstrate that the emergency diesel air start system will perform satisfactorily in service was identified and performed in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents was a violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control.

Analysis.

The team determined that the failure to ensure that the testing required to demonstrate that Unit 1 emergency diesel generator sets air start systems will perform satisfactorily in service and in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents was a performance deficiency. The finding was more than minor because it was associated with the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of safety systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding was

of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance.

Enforcement.

The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, which states, in part, that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Contrary to the above, the licensee failed to ensure that all testing required to demonstrate that structures, systems, and components would perform satisfactorily in service is identified and performed in accordance with written test procedures, which incorporate the requirements and acceptance limits contained in applicable design documents. Specifically, as of June 2010, the licensee failed to ensure that pre-operational testing required to demonstrate that the emergency diesel generator air start system receivers satisfied the requirements and acceptance limits contained in applicable design documents. This finding was entered into the licensees corrective action program as Condition Report CR-2010-005924. Because this finding is of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 05000445/2010006-002, Inadequate Test Control of the Diesel Generator Air Starting System.

.2.5 Service Water Pumps

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design bases documents, calculations, corrective maintenance, and post-maintenance tests of the service water pumps to ensure that the equipment was capable of meeting design requirements. The inspectors reviewed calculations related to pump flow, head, and net positive suction head and compared them to requirements to ensure that the pumps were capable of functioning as required especially under loss of offsite power with electrical power supply from the emergency diesel generators. This included the range of emergency diesel generator frequency allowed by technical specifications for unrestricted plant operation. Specifically the team reviewed:

• Piping and instrumentation diagrams and pump alignment requirements

• Pump capacity and number of pumps required for accident mitigation

• Correlation between calculated requirements, test acceptance criteria, and test results

b. Findings

Inadequate Analysis of Emergency Diesel Generator Frequency

Introduction.

The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because the licensees safety analysis failed to account for the full range of emergency diesel generator frequency allowed by Technical Specifications. Specifically, the licensee analyzed the performance of the service water pumps and all safety related pumps assuming operation at a frequency of 60 Hertz.

Description.

The Comanche Peak Technical Specifications allow unrestricted plant operation with emergency diesel generator frequency between 58.8 and 61.2 Hertz (60 Hertz +/-2 percent). This frequency range is not accounted for in the safety analysis. The performance of motor operated pumps varies with the speed of the pump, which is directly affected by the frequency of the emergency diesel generators alternating current. Low frequency will result in a lower flow rate and lower developed head while high frequency will result in a greater flow rate and a higher developed head. The inspectors determined that the licensees system calculations and safety analyses used a specific diesel frequency of 60 Hertz. Comanche Peak Engineering Report ER-ME-109, Evaluation of Safety Related Pump Degradation Issues, Revision 1 stated that a frequency other than 60 Hertz may cause accident or consequences to be outside the bounding limits of the accident analyses. The same is true for the systems [that directly support accident mitigation] such as the Component Cooling Water and Station Service Water pumps. Nevertheless, the licensee did not take steps to correct the condition by using the bounding +/-2 percent frequency for all safety related centrifugal pumps.

The team determined that the failure to include the allowable diesel generator frequency of 58.8 Hertz (60 Hertz -2 percent) is nonconservative because the pumps will be operating at a two percent lower flow rate and a lower developed head of about four percent. The overall effect is equivalent to a pump degradation of 4.5 percent as documented in Section 7.3 of Engineering Report ER-ME-109.

The team also determined that the failure to include the allowable diesel generator frequency of 61.2 Hertz (60 Hertz +2 percent) is nonconservative because it will cause the pumps to operate at a higher flow rate and pressure. A two percent higher flow rate will cause the centrifugal pumps to require greater net positive suction head than originally assumed. Operating at a higher frequency could cause vortex formation to occur earlier (at a higher tank water level) than assumed, resulting in the water supply being available for a shorter duration. In addition, diesel fuel would be consumed by the emergency diesel generator at a greater rate making the available fuel last for a shorter duration.

The licensee issued Condition Report CR-2008-000934-00, to address NRC Information Notice 2008-02 Findings Identified During Component Design Bases Inspections. One of the issues addressed in the condition report is emergency diesel generator frequency, but the licensee failed to note the vulnerability where

the safety analysis did not account for the frequency range allowed by Technical Specifications. Moreover, the licensee reviewed the issue of emergency diesel generator frequency in their self-assessment in preparation for this inspection.

The issue was identified at other nuclear power plants, but the licensees self-assessment failed to identify it as a concern at Comanche Peak.

Analysis.

The team determined that the failure to analyze the emergency diesel generators for operation over the entire range of allowed frequency was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Inspection Manual Chapter 0609, Attachment 4, Phase 1 -

Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. Specifically, the licensee has procedures in place that require operators to take specific action to manually maintain the proper frequency range. This finding has a crosscutting aspect in the area of Problem Identification and Resolution because the licensee did not effectively incorporate pertinent operating experience into the preventive maintenance program for the emergency diesel generators. Specifically the licensee failed to incorporate industry-operating experience, which could have affected the capability of equipment to perform their safety function under the most limiting conditions P.2(a).

Enforcement.

The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, the licensee failed to ensure that measures were established to ensure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, as of June 18, 2010, the licensee failed to properly translate Technical Specification allowable frequency range to design documents. This finding was entered into the licensees corrective action program as Condition Report CR-2010-005563. Because this finding was determined to be of very low safety significance and was entered into the licensees corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 05000445,05000446/2010006-03, Inadequate Analysis of Emergency Diesel Generator Frequency.

.2.6 Component Cooling Water Heat Exchanger 'A'

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design bases documents, calculations, and recent corrective and preventive maintenance of the Train A component cooling water heat exchanger. Specifically, the team reviewed:

• Accuracy of test results, impact of instrument calibration, instrument uncertainties, tube plugging, water temperature (tube and shell sides),and fouling factor.

• Design basis heat load sizing analysis to verify the capability to meet design basis heat removal requirements.

• Heat exchanger design documentation, including specifications, data sheets, and applicable design calculations for agreement with the design basis, safety analysis, and testing requirements.

• Vendor manual requirements for agreement with operating and maintenance procedures and records.

• Current system health report, trend data, inspection frequency, applicable operating experience, as well as significant corrective action documents and their impact on design basis margin.

b. Findings

No findings were identified.

.2.7 Emergency Diesel Generator Jacket Water System

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design bases documents, calculations, corrective maintenance and post-maintenance tests of the emergency diesel generator jacket water heat exchangers to ensure that the equipment was capable of meeting design requirements. The team also performed walkdowns of the heat exchanger areas. Specifically the team reviewed:

• Calculations for heat exchanger fouling, and the minimum allowable flow.

• Design calculations and documentation of periodic surveillance tests to verify that design performance requirements were satisfied.

• Maintenance, in-service testing, corrective actions, and design change histories to assess the potential for component degradation and the resulting impact on design margins and performance.

b. Findings

No findings were identified.

.2.8 6.9 Kv Switchgear

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design bases documents, calculations, corrective maintenance and post-maintenance tests of the nonsafety-related and safety-related portions of the 6.9 Kv switchgear to verify the capability to supply electrical power to safety-related loads. The team performed a visual non-intrusive inspection to assess the installation configuration, material condition, and potential vulnerability to hazards.

Specifically, the team reviewed:

• Selected calculations of record that established the electrical loading for the 6.9 Kv switchgear for design basis events to assess the adequacy of the loading margins available for accident conditions.

• Preventive maintenance procedures and the results of the most recent preventive maintenance and refurbishment activities for circuit breakers T1EB2 (serves 480 Vac switchgear 1EB2), T1EB3 (serves 480 Vac switchgear 1EB2), 1APSWS (service water pump motor feeder), and 1EA2-1 (preferred source breaker), to confirm that the activities were consistent with selected vendor manual requirements and that as-found conditions were being properly dispositioned.

• Recent system health reports and a selected sample of condition reports.

b. Findings

No findings were identified.

.2.9 6.9 kV Safeguard Bus Diesel Start Time Delay Relays

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations and recent corrective action documents for the 6.9kV safeguard bus diesel start time delay relays. The team performed non-intrusive visual inspections of selected sequencer cabinets to identify and evaluate material condition and potential vulnerability to external hazards, such as seismic interactions, and flooding. Specifically, the team reviewed:

• Potential vulnerabilities to common cause failures and their consequences. This included a review of selected portions of schematic diagrams to identify potential common cause failure modes resulting from power supply failures or other circuit failures.

• Associated health reports, component replacement status and history.

• Surveillance test procedures and records.

• Selected condition reports associated with the relays, to assess the reliability of the components.

b. Findings

No findings were identified.

.2.10 125 Vdc Safety-Related Station Batteries

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, and calculations for the 125 Vdc safety-related station batteries. The team performed non-intrusive visual inspections, and witnessed a weekly surveillance test performed by the licensee. The team also walked down the battery room areas to evaluate potential vulnerability to external hazards such as hydrogen accumulation, seismic interactions, and flooding. The team interviewed the system engineer regarding equipment history and conditions.

Specifically, the team reviewed:

• Methodology, assumptions, and selected design inputs and results for the battery sizing and 125 Vdc panel loading and voltage drop calculations, to confirm that the batteries would have sufficient capability for supporting design basis events and station blackout events.

• Hydrogen evolution calculations and heating, ventilation, and air conditioning calculations for the battery rooms, to evaluate the capability for controlling hydrogen concentration below acceptable levels under design basis conditions.

• Surveillance procedures and selected results for the weekly, monthly, and quarterly surveillance tests; the 18-month surveillance tests, the service discharge tests, performance discharge tests; and modified performance discharge tests.

• Recent system health reports and a selected sample of condition reports.

b. Findings

Inadequate Evaluation of Hydrogen Generation for Safety-Related and Nonsafety-Related Batteries

Introduction.

The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because the licensee failed to perform an adequate hydrogen evolution calculation, for the safety-related and nonsafety-related batteries, using the most limiting expected condition of forcing maximum current into a fully charged battery which led to a ventilation system design that

did not limit hydrogen accumulation to less than 2 percent of the total volume of the battery areas during all conditions.

Description.

The inspectors reviewed the calculations associated with the hydrogen generation associated with the Unit 1 and Unit 2 safety and nonsafety-related batteries and battery room ventilation. The team identified a nonconservative calculation, which led to a ventilation system design that did not limit hydrogen accumulation to less than 2 percent of the total volume of the battery areas during all conditions as described in their design basis documents.

The inspectors determined that all of the safety-related and nonsafety-related battery rooms are connected via a common corridor air space through held open fire doors into each battery room. Licensee calculation number X-EB-HV-15, Hydrogen Level in Battery Rooms, Units 1 and 2, determined hydrogen evolution in the 125Vdc safety-related and nonsafety-related battery rooms. This calculation contained several nonconservative assumptions or design inputs.

Specifically, during a loss of offsite power event and loss of coolant accident event when temperatures in the battery rooms can reach 120 degrees Fahrenheit, the hydrogen accumulation in the battery rooms will exceed two percent of the total volume of the battery area when forcing maximum available current into a fully charged battery, which can occur due to a failure of the current limiting feature of the battery charger. The nonconservatism assumptions in this calculation were as follows:

(1) The licensee assumed the equalized current for the charger was the maximum current from the charger. This assumption results in a comparatively small value of hydrogen generation. However, both calculation X-EB-HV-15 and IEEE Standard 484(referenced in the calculation), state that the worst-case condition exists when forcing maximum current into a fully charged battery such as during a charger failure. This condition would result in a much higher hydrogen evolution rate.

(2) Calculation X-EB-HV-15 did not properly account for the increase in hydrogen evolution rates at the design basis ambient temperature of 120 degrees Fahrenheit for a loss of coolant accident with a loss of offsite power.

(3) Calculation X-EB-HV-15 assumed that the equipment room supply fans would be providing suction to the battery room exhaust fans during a loss of offsite power. However, these fans are nonsafety class and may not be available during a loss of offsite power. This results in a substantially lower airflow through the battery rooms.

(4) Calculation X-EB-HV-15 did not evaluate the airflows, heat loading, and projected room temperatures using as built and design bases conditions of airflows.

(5) The licensee did not consider the hazards introduced to the Class 1E system batteries by the non-Class 1E batteries with similar hydrogen evolution issues that share the same air space due to the open doors.

Analysis.

The team determined that the failure to adequately perform the hydrogen evolution calculation for the safety-related and nonsafety-related batteries, using the most limiting condition, was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone attribute of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Inspection Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance.

Enforcement.

The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control which states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis, as specified in the license application, for those structures, systems, and components to which this Appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, the licensee failed to establish measures to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, as of June 18, 2010, the licensee failed to perform an adequate hydrogen evolution calculation, for the safety-related and nonsafety-related batteries, using the most limiting expected condition of forcing maximum current into a fully charged battery which led to a ventilation system design that did not limit hydrogen accumulation to less than 2 percent of the total volume of the battery areas during all conditions. This finding was entered into the licensees corrective action program as condition reports CR-2010-005941, CR-2010-005941, and CR-2010-006561. Because this finding was determined to be of very low safety significance and was entered into the licensees corrective action program, this violation is being treated as a noncited violation consistent with the NRC Enforcement Policy: NCV 05000445,05000446/2010006-04, Inadequate Evaluation of Hydrogen Generation for Safety-Related and Nonsafety-Related Batteries.

.2.11 Protective Undervoltage Relays 27-2A/1EA2, 27-2A/1EA1, 27-2B/1EA1

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations and recent corrective action documents for the selected protective undervoltage relays. The team performed non-intrusive visual inspections to identify and evaluate external material condition as well as

potential vulnerability to external hazards, such as vulnerability to post-accident radiation dose effects on protective relays, seismic interactions, and flooding.

Specifically, the team reviewed:

• Selected schematic diagrams and calculations of record for establishing the setpoints for the 6.9 kV Safeguard Bus undervoltage relays used for motor trip (dead bus status), alternate source breaker closure, and starting the emergency diesel generator, to confirm that the relays would drop out at low voltage and perform their safety functions in accordance with the design basis.

• A sample of recent surveillance test results to confirm implementation of the setpoints in accordance with the calculations and to assess the condition of the relays.

• Recent system health reports and associated actions.

b. Findings

No findings were identified.

.2.12 Preferred Feeder Breakers T1EB2 / T1EB3 to 480 Vac Switchgear 1EB2

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations and recent condition reports for the selected breakers.

Specifically, the team reviewed:

• Preventive maintenance procedures and the results of the most recent preventive maintenance and refurbishment activities, to confirm that they were consistent with selected vendor manual requirements and that, as-found conditions were being properly dispositioned.

• Recent system health reports and associated actions.

b. Findings

No findings were identified.

.2.13 Service Water Motor Operated Valves 1-HV-4286 / 4287 (electrical inspection only)

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations and recent corrective action documents for the selected motor operated valves. The team performed visual inspections of the motor operated valves to identify and evaluate visible material condition as well as potential vulnerability to external hazards, such as seismic interactions, and flooding. Specifically, the team reviewed:

• Electrical calculations to confirm that adequate voltage would be available at the motor terminals for design basis conditions.

• Schematic diagrams to evaluate potential vulnerability to common cause failures and to evaluate testability of circuit functions as evidenced by surveillance procedures.

• Recent system health reports associated with the motor operated valves.

b. Findings

No findings were identified.

.2.14 125 Vdc Distribution Panel 1ED1 Fused Disconnect Switch

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations and recent corrective action documents for the selected 125Vdc fused disconnect switch. Specifically, the team reviewed:

• Calculations that established the ratings of the fuse and disconnect switch as well as the design and qualification documentation for the cable reduction splice installed within the 125 Vdc distribution panel.

• Schematic diagrams and alarm response procedures to confirm that a blown fuse or misaligned disconnect switch would be alarmed and identifiable in the control room.

• Recent 125 Vdc system health reports.

• Recent work orders governing the preventive maintenance of these components, and performed a non-intrusive visual inspection of a corresponding fused disconnect switch and splice on distribution panel 2ED2, to assess material condition, consistency of the configuration with design and qualification basis, cable supports, and potential vulnerability to hazards.

b. Findings

No findings were identified.

.2.15 Auxiliary Feedwater System Flow Control Valves

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report, design basis documents, calculations and recent corrective action documents for the auxiliary feedwater system flow control valves. Specifically, the team reviewed:

• Calculations for sizing the valve air accumulators to provide sufficient air and time to hold a valve closed when there is a faulted steam generator.

• Work orders for replacement of parts, and testing in accordance with Section XI of the ASME Boiler and Pressure Vessel Code.

• Stroke times and vendor information.

b. Findings

No findings were identified.

.3.1 NRC Generic Letter 1989-13 "Service Water System Problems Affecting Safety Related

Equipment"

a. Inspection Scope

The team reviewed the licensee's responses to Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment," and its compliance with the commitments specified in the responses. The team reviewed the program document and methodology, the validity of practicing frequent testing in lieu of using the design service water temperature when projecting performance to accident conditions, and the validity of the specified frequency of testing with respect to the available margin in fouling factor. The inspectors also reviewed the practice of cleaning the heat exchanger when the margin is low and also every refueling outage. The team reviewed the chemical treatment of the water, scheduled inspections and tests, as well as trending of the fouling factor, trending of service water temperature, and trending of available margin. The review of the generic letter was performed with respect to the programs and actions taken affecting the component cooling water heat exchanger.

b. Findings

No findings were identified.

.3.2 NRC Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that

Disable Accident Mitigation Systems or Cause Plant Transients

a. Inspection Scope

The team reviewed the licensee's responses to Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients, and its compliance with the commitments specified in the responses. The licensees response to the generic letter reported one such cable failure of undetermined cause and location, the C phase feeder to the motor for service water pump 1-01, and described the licensees inspection, testing, and monitoring programs. To assess the licensees disposition of issues identified in the generic letter, the team selected the service water pump motor feeder cables and reviewed associated documents, including:

manhole, duct bank, and raceway drawings; available medium voltage cable specifications; available documentation associated with dewatering and inspection of manholes; available megger test data and procedures for cable and motor testing; and corrective action history associated with any cable degradation or failures since 2005. The team reviewed the type of insulation systems for the replacement cable, to assess vulnerability to prolonged submergence. The team also visually inspected the condition of two of the fourteen manholes (MH1EB1, MH1EB2) and associated cables and raceways, and interviewed cognizant licensee staff regarding operating history and past conditions.

b. Findings

(1) Failure to Provide Accurate Information in Response to Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients

Introduction.

The team identified a Severity Level IV noncited violation of 10 CFR 50.9, Completeness and Accuracy of Information, because the licensees June 20, 2007 response to Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients, did not accurately describe the licensees programs, procedures, or practices for inspection, testing, and monitoring programs to detect the degradation of inaccessible or underground power cables that support emergency diesel generators, offsite power, essential service water, service water, component cooling water, and other systems that are in the scope of 10 CFR 50.65 (the Maintenance Rule).

Description.

The licensees June 20, 2007 response to Generic Letter 2007-01, Request 2, stated that Comanche Peak, periodically performs visual inspection for corrosion and degradation of cable tray supports and a preventive maintenance program for inspection/removal of water from manholes. These actions help to eliminate or minimize conditions known to impact cable degradation rates for cables that are within the scope of 10 CFR 50.65.

The team identified the following:

The licensee had no preventive maintenance program or procedures in place to govern the inspection or preventive maintenance activities described in their response, and there was no evidence that these manholes, raceways, and supports had ever been inspected prior to November 2009, as the licensee indicated in their response to Generic Letter 2007-01. During these recent inspections and dewatering activities (using portable pumps), the licensee identified evidence that medium voltage safety-related cables (6900 Vac service water pump motor feeders) had been completely submerged in one Train A manhole and in four Train B manholes.

The licensee also stated in their response to Request 2, that The underground ductwork at Comanche Peak is designed to slope toward manholes to avoid accumulation of water in the duct banks. The conduits embedded in concrete floors/walls inside the plant are sealed to prevent intrusion of water inside the conduits. These features eliminate or minimize cable exposure to environment of concern known to impact cable degradation rates identified in this generic letter.

The team determined from visual inspection of the conduits entering manholes 1EB1 and 1EB2; review of the results of the licensees November 2009 inspections; and review of design and construction documents, that water could enter the underground conduit and accumulate in the duct banks, because of the conduit and conduit seal configuration. The licensee concluded from inspections completed in November, 2009, that the metallic conduit that encloses the cables is not watertight, and allows water to enter and flood the underground conduits, particularly from water entering from a sandy filler zone between the duct bank and cable vault structures, or between the duct banks and building structures (for example, the safeguards buildings and the service water intake structure). In addition, the team concluded from visual inspections of MH1EB1 and MH1EB2 and from design documents that the conduits that slope downward to the manholes from the service water intake structure and from the Unit 1 safeguards building were sealed at the manhole, which could result in prolonged submergence of cables within underground conduit. The team determined that this conduit and seal configuration was a design deficiency from original construction.

Analysis.

The team determined that the failure to provide accurate information in the licensees response to Generic Letter 2007-01 was a performance deficiency. The finding is more than minor because the information was material to the NRCs decision-making processes.

Specifically, the information requested by Generic Letter 2007-01 was to enable NRC staff to determine whether the applicable regulatory requirements identified in the generic letter (10 CFR Part 50, Appendix A, General Design Criteria 4, 17, and 18; 10 CFR 50.65(a)(1);10 CFR Part 50, Appendix B, Criterion XI), were being met with regard to the operational readiness of critical systems that could cause a plant transient or mitigate accidents, and to obtain further information on cable failures.

Enforcement.

The team identified a Severity Level IV noncited violation of 10 CFR 50.9, Completeness and Accuracy of Information, which states, in part, that information provided to the Commission be complete and accurate in all material respects. Contrary to the above, the licensee failed to provide information that was complete and accurate in all respects. Specifically, on June 20, 2007, the licensees response to Generic Letter 2007-01, Request 2, specified that Comanche Peak periodically performs visual inspection for corrosion and degradation of cable tray supports and a preventive maintenance program for inspection/removal of water from manholes. The licensee had no preventive maintenance program or procedures in place to govern the

inspection or preventive maintenance activities described in their response, and there was no evidence that these manholes, raceways, and supports had ever been inspected prior to November 2009. The licensee has entered this violation into their corrective action program as Condition Report CR-2010-005784. The finding was characterized as a Severity Level IV violation in accordance with the NRC Enforcement Policy. Because this finding was determined to be of Severity Level IV safety significance and was entered into the licensees corrective action program, this violation is being treated as a noncited violation, consistent with the NRC Enforcement Policy: NCV 05000445;05000446/2010006-05, Failure to Provide Accurate Information in Response to Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients.

(2) Failure to Implement Design Features for Precluding or Minimizing Long-Term Accumulation of Water in Underground Conduits Containing Medium Voltage Safety Related Cables

Introduction.

The team identified a Green noncited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, because the licensee installed conduit seals at a low point in the safety related cable manholes, thereby defeating the design requirement to avoid or minimize the accumulation of water in the duct banks. This configuration could result in long-term submergence of safety-related medium voltage cables and long-term degradation or failure of the cables.

Description.

The licensees June 20, 2007 response to Generic Letter 2007-01, Request 2, stated that The underground ductwork at Comanche Peak is designed to slope toward manholes to avoid accumulation of water in the duct banks. The conduits embedded in concrete floors/walls inside the plant are sealed to prevent intrusion of water inside the conduits. These features eliminate or minimize cable exposure to environment of concern known to impact cable degradation rates identified in this generic letter. More recently, while evaluating flooding conditions observed in the manholes during licensee inspections in November, 2009, the licensee concluded in the corrective action plan for Evaluation EVAL-2009-005076, performed November 19, 2009 to support resolution of Condition Report CR-2009-005076-00, and Evaluation EVAL-2009-006801, performed January 7, 2010, that the design of the duct banks encourages drainage from the conduits to the cable vaults. On that basis, the licensee determined that no corrective action was required.

The team performed visual inspection of the conduits entering manholes MH1EB1 and MH1EB2. The team also reviewed the design and construction documents associated with the manholes and the results of the licensees November 2009 inspections of the manholes. The team determined that contrary to the licensees assertion water could enter the underground conduit and accumulate in the duct banks, because of a deficient conduit and conduit seal configuration. The team concluded that the conduits, which slope downward to the manholes from the service

water intake structure and from the Unit 1 safeguards building, were sealed at the manhole entrance, which could result in prolonged submergence of cables within the underground conduits. The team determined this conduit and seal configuration was a design deficiency from original construction.

Analysis.

The team determined that the failure to implement a design requirement to avoid or minimize accumulation of water in the underground duct banks was a performance deficiency. The finding is more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 screening in accordance with Manual Chapter 0609, Attachment 4, Phase1 - Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because it was a design or qualification issue confirmed not to result in a loss of operability or functionality, it did not result in the loss of a system safety function, it did not represent the loss of a single train for greater than technical specification allowed outage time, it did not represent a loss of one or more non-technical specification risk significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding did not have a crosscutting aspect because the most significant contributor did not reflect current licensee performance.

Enforcement.

The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states in part, measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures and instructions. Contrary to the above, the licensee failed to establish measures to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures and instructions. Specifically, as of June 18, 2010, the underground duct banks connecting the safeguards buildings to the service water intake structure had installed conduit seals at a low point in the cable manholes, thereby defeating the design requirement to avoid or minimize the accumulation of water in the duct banks as specified in NRC Generic Letter 2007-01. This configuration could result in long-term submergence of safety-related medium voltage cables and long-term degradation or failure of the cables. This finding was entered into the licensees corrective action program as Condition Report CR-2010-005843. Because this finding was determined to be of very low safety significance and was entered into the licensees corrective action program, this violation is being treated as a noncited violation, consistent with the NRC Enforcement Policy: NCV 05000445;05000446/2010006-06, Failure to Implement Design Features for Precluding or Minimizing Long-Term Accumulation of Water in Underground Conduits Containing Medium Voltage Safety-Related Cables.

.3.3 NRC Information Notice 2002-12, Submerged Safety-Related Electrical Cables

a. Inspection Scope

The team reviewed the licensees evaluation and disposition of NRC Information Notice 2002-12, Submerged Safety-Related Electric Cables. This activity was conducted under the same program and reviewed in conjunction with Generic Letter 2007-01, discussed in Section 1R21.3.2 above.

b. Findings

No findings were identified.

.3.4 NRC Information Notice 2007-34, Operating Experience Regarding Electric Circuit

Breakers

a. Inspection Scope

The team reviewed the licensees documented evaluation and disposition of NRC Information Notice 2007-34, Operating Experience Regarding Electric Circuit Breakers under their operating experience program for each of the issues identified in this information notice. The team selectively reviewed condition reports identified by the licensees queries of their corrective action database for the 6900 Vac switchgear, to determine whether the licensee responses were effective in avoiding the problems discussed in the information notice. The team also interviewed the 6900 Vac system engineer to identify and discuss equipment repair history and refurbishment.

b. Findings

No findings were identified.

.3.5 NRC Information Notice 2008-02, Findings Identified During Component Design Bases

Inspections

a. Inspection Scope

The team reviewed the licensees documented evaluation and disposition of NRC Information Notice 2008-02, Findings Identified During Component Design Bases Inspections under their operating experience program for each of the issues identified in this information notice.

The team selectively reviewed condition reports identified by the licensees queries of their corrective action database for the issues discussed in the information notice, to determine whether the licensees responses were effective in avoiding the problems discussed in the information notice.

b. Findings

No findings were identified.

.4 Results of Reviews for Operator Actions

a. Inspection Scope

The team reviewed four risk significance operator actions as follows:

• Isolate Auxiliary Feedwater Flow to a Steam Generator Fault Inside Containment within Ten Minutes as Required by the Finals Safety Analysis Report. The team observed a simulator job performance measure to isolate auxiliary feedwater flow to a faulted steam generator. The activity was satisfactorily performed within the required ten minutes as described in the final safety analysis report.

• Isolate a Ruptured Steam Generator within Thirteen Minutes of Event Initiation as Required by the Final Safety Analysis Report. The team observed a simulator job performance measure to isolate ruptured steam generator. The activity was satisfactorily performed within the required thirteen minutes as described in the final safety analysis report.

• Initiate a Cool Down within Five Minutes of Isolating a Ruptured Steam Generator as Required by the Final Safety Analysis Report. The team observed a simulator job performance measure to initiate a cool down within five minutes of isolating a ruptured steam generator. The activity was satisfactorily performed within the required five minutes as described in the final safety analysis report.

• During a Station Blackout, One Emergency Diesel Generator is Running but not on the Bus Due to a Low Voltage/Frequency Condition. The team observed a simulator job performance measure to address one diesel generator running but not connected to the bus due to a low voltage/frequency condition during a station blackout.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On June 18, 2010, the team leader presented the preliminary inspection results to Mr. B. Mays, Vice President, Nuclear Engineering and Support, and other members of the licensees staff.

On November 4, 2010, the team leader conducted a telephonic final exit meeting with Mr. B. Mays, Vice President, Nuclear Engineering and Support and other members of the licensees staff. The licensee acknowledged the findings during each meeting.

While some proprietary information was reviewed during this inspection, no proprietary information was included in this report.

4OA7 Licensee-Identified Violations

None.

s: Supplemental Information

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

I. Ahmad, Consulting Engineer

J. Back, Operating Experience Coordinator

D. Davis, Projects Manager

C. Feist, Consulting Engineer

D. Goodwin, Director Engineering Support

A. Hall, Operations Support Manager

J. Henderson, Engineering Smart Team Manager

J. Hicks, Regulatory Affairs

T. Hope, Nuclear Licensing Manager

H. Joiner, Operating Experience Supervisor

D. Kross, Plant Manager

F. Madden, Director Nuclear Oversight and Regulatory Affairs

S. Maier, Alliance Manager

A. Martin, Consulting Engineer

B. Mays, Vice President Nuclear Engineering and Support

G. Merka, Regulatory Affairs

J. Meyer, Technical Support Manager

D. Moore, Director Shaw Engineering and Technical Support

B. Patrick, Director Maintenance

W. Reppa, System Engineering Manager

S. Sewell, Director Nuclear Operations

R. Smith, Director Nuclear Training

S. Smith, Plant Manager

J. Smith, System Engineer

G. Techentine, System Engineer

T. Terryah, System Engineering Manager, Balance of Plant

T. Tigner, CAP Supervisor

L. Windham, Consulting Engineer

L. Yeager, Design Engineering Analysis Manager

NRC Personnel

J. Kramer, Senior Resident Inspector

B. Tindell, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000445/2010006-001 AV Failure to Incorporate Relevant Operating Experience Information into Station Procedures Regarding the Condensate Storage Tank and Diaphragm (Section 1R21.2.2)

A1- 1 - Attachment 1

Opened and Closed

05000445/2010006-002 NCV Inadequate Test Control of the Diesel Generator Air Starting System (Section 1R21.2.4)

05000445;05000446/2010006-003 NCV Inadequate Analysis of Emergency Diesel Generator Frequency (Section 1R21.2.5)

05000445;05000446/2010006-004 NCV Inadequate Evaluation of Hydrogen Generation for Safety-Related and NonSafety-Related Batteries (Section 1R21.2.10)

05000445;05000446/2010006-005 NCV Failure to Provide Accurate Information in Response to Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients (Section 1R21.3.2)

05000445;05000446/2010006-006 NCV Failure to Implement Design Features for Precluding or Minimizing Long-Term Accumulation of Water in Underground Conduits Containing Medium Voltage Safety Related Cables (Section 1R21.3.2)