Text

IR 05000315-10-002; 05000316-10-002, on 01/01/2010 - 03/31/2010, D.C. Cook Nuclear Power Plant, Units 1 & 2; Problem Identification and Resolution
	ML101250243
Person / Time
Site:	Cook
Issue date:	05/05/2010
From:	Jamnes Cameron; NRC/RGN-III/DRP/B6
To:	Jensen J; Indiana Michigan Power Co
References
	IR-10-002
	Download: ML101250243 (69)
	v • d • e

May 5, 2010

SUBJECT:

D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2 INTEGRATED INSPECTION REPORT; 05000315/2010002; 05000316/2010002

Dear Mr. Jensen:

On March 31, 2010, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your D. C. Cook Nuclear Power Plant, Units 1 and 2. The enclosed report documents the inspection results, which were discussed on April 21, 2010, with Mr. L. Weber and other members of your staff.

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

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

The report documents one NRC-identified finding and one self-revealed finding of very low safety significance (Green). The NRC-identified finding was determined to involve a violation of NRC requirements. Additionally, two licensee-identified violations, which were determined to be of very low safety significance, are listed in this report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at D. C. Cook. In addition, if you disagree with the characterization of 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 III, and the NRC Resident Inspector at D.C. Cook. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Docket Nos. 50-315; 50-316 License Nos. DPR-58; DPR-74

Enclosure:

Inspection Report No. 05000315/2010002; 05000316/2010002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-315; 50-316 License Nos: DPR-58; DPR-74 Report Nos. 05000315/2010002; 05000316/2010002 Licensee: Indiana Michigan Power Company Facility: D. C. Cook Nuclear Power Plant, Units 1 and 2 Location: Bridgman, MI Dates: January 1 through March 31, 2010 Inspectors: J. Lennartz, Senior Resident Inspector P. LaFlamme, Resident Inspector T. Briley, Reactor Engineer T. Go, Health Physics Inspector M. Holmberg, Senior Reactor Inspector J. Jandovitz, Project Engineer D. McNeil, Senior Operations Engineer M. Mitchell, Health Physics Inspector A. Shaikh, Reactor Inspector C. Zoia, Operations Engineer Approved by: Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000315/2010002; 05000316/2010002; 01/01/2010 - 03/31/2010 D.C. Cook Nuclear Power

Plant, Units 1 & 2; Problem Identification and Resolution The inspection was conducted by resident and regional inspectors. The report covers a 3-month period of resident inspection. 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 July 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance was self-revealed for the failure to implement procedures for using mobile cranes and the failure to use human error prevention tools. Consequently, a mobile crane boom contacted and severed the middle phase of an overhead 12 kilovolt line in the owner controlled area W yard. This caused a loss of power to the fire pump house, which rendered the electric fire pump inoperable.

This finding was entered into the licensees corrective action program as Action Request (AR) 00860140. No violation of NRC requirements occurred.

This finding was more than minor because it was related to the external factors attribute (fire) of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability of systems that respond to initiating events.

Specifically, the electric fire pump was rendered inoperable and unavailable when power was lost to the fire pump house, which degraded the fire protection defense-in-depth strategies. The finding was of very low safety significance because the fire protection system performance was not affected in that both diesel-driven fire pumps were operable. This finding was associated with a cross cutting aspect in the area of human performance - work practices (H.4(c)). (Section 4OA2.3)

Green.

The inspectors identified one finding of very low safety significance with an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XVI,

Corrective Action. Specifically, licensee personnel failed to implement corrective actions for water intrusion into vaults below motor control centers containing safety-related cabling in a timely and effective manner. Consequently, safety-related cabling was exposed to a water environment that if left uncorrected could result in subsequent cable degradation. For corrective action, the licensee performed an inspection of all cable vaults throughout the plant. Also, licensee personnel initiated a root cause evaluation to focus on the leadership and organizational failures associated with the response to the wetted cables in the 1-ABD-A cable vault and the thoroughness of the extent of condition evaluation. This issue was entered into the licensees corrective action program as CR AR 2010-2558.

This finding affected the Mitigating Events cornerstone and was more than minor because the issue could become a more significant safety concern if left uncorrected.

Specifically, failure to implement corrective actions for water intrusion into cable vaults could result in subsequent degradation of safety-related cabling. This finding was of very low safety significance because the finding does not constitute a design or qualification deficiency, did not result in a loss of system safety function, and did not meet the seismic, flooding, and severe weather screening criteria. This finding was associated with a cross-cutting aspect in the area of problem identification and resolution- corrective action program (P.1(c)). (Section 4OA2.4)

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power until March 3 when the unit was shut down to Mode 3, Hot Standby, to commence Cycle 23 refueling outage. Unit 1 was in Mode 5, Cold Shutdown, when the inspection period ended.

Unit 2 was at full power the entire inspection period.

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

REACTOR SAFETY

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

Unit 2 east and west motor driven auxiliary feed water trains;

Unit 2 west containment spray and spray add system; and

Unit 1 AB emergency diesel generator.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the Corrective Action Program (CAP) with the appropriate significance characterization.

Documents reviewed are listed in the Attachment.

These activities constituted three partial system walkdown samples as defined in Inspection Procedure (IP) 71111.04-05.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

The inspectors performed a complete system alignment inspection of the Unit 1 containment spray system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.

Documents reviewed are listed in the Attachment.

These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Main article: IP 71111.05

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

Fire Zone 45, Unit 2 engineering safety system and motor control center rooms;

Fire Zone 127, Unit 1/2 technical support center uninterruptable power supply inverter and battery rooms;

Fire Zone 29E, Unit 1 motor control center for essential service water pumps;

Fire Zone 6N/M/S, Unit 1/2 auxiliary building elevation 587 west end;

Fire Zone 32, auxiliary building cask handling elevation 609; and

Fire Zone 42C, Unit 1 emergency power supply motor control room elevation 609.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

These activities constituted six quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings of significance were identified.

1R06 Flooding

Main article: IP 71111.06

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the condensate feed water system and auxiliary feed water system. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant areas to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

Unit 2 reactor cable tunnel quadrants three and four This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings of significance were identified.

1R07 Annual Heat Sink Performance

Main article: IP 71111.07

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees inspections and maintenance of the 1AB emergency diesel generator air after cooler heat exchangers. The inspectors verified that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against the acceptance criteria; and reviewed action requests (ARs) regarding heat sink problems to verify that the problems were entered into the licensee's CAP with the appropriate characterization. Select ARs were reviewed to verify that corrective actions were appropriate. Documents reviewed for this inspection are listed in the Attachment to this document.

This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08

For Unit 1, from March 9 through March 23, 2010, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, steam generator (SG) tubes, risk-significant piping and components, and containment systems. Additionally, the inspection included selected portions of Temporary Instruction (TI) 2515/172, Reactor Coolant System (RCS) Dissimilar Metal Butt Welds, to assess licensee activities associated with the mitigation of the RCS hot and cold leg nozzle welds using mechanical stress improvement (MSIP).

The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4, and 1R08.5 below, count as one inspection sample as defined by IP 71111.08-05.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors observed the following nondestructive examinations required by the American Society of Mechanical Engineers, (ASME)Section XI Code, and/or 10 CFR 50.55a to evaluate compliance with the ASME Code,Section XI, applicable ASME Code Case and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned, in accordance with the ASME Code or an NRC approved alternative requirement:

Manual ultrasonic examination (UT) of a 14-inch diameter pressurizer surge line pipe to pipe weld (1-RC-5-02S); and

Manual UT of the 3-inch diameter chemical and volume control system pipe to elbow welds (1-CS-92-25S and 1-CS-92-26S).

The inspectors observed the following nondestructive examinations conducted as part of the licensees industry initiative inspection programs for managing primary water stress corrosion cracking (PWSCC) in reactor coolant system components to determine if the examinations were conducted in accordance with the licensees augmented inspection program, industry guidance documents and associated licensee examination procedures and if any indications and defects were detected, to determine if these were dispositioned in accordance with approved procedures and NRC requirements.

Automated UT and Eddy Current testing (ET) of hot leg (HL) and cold leg (CL)nozzle-to-safe-end welds (1-RPV-2-01 and 1-RPV-1-02), in accordance with Materials Reliability Program (MRP)-139 Primary System Piping Butt Weld Inspection and Evaluation Guidelines.

The licensee had not identified any examinations during the previous outage with relevant/recordable conditions/indications accepted for continued service, so this inspection procedure attribute was not applicable.

The inspectors reviewed weld related documents to determine if the licensee applied the pre-service nondestructive examination and acceptance criteria required by the construction Code. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of the ASME Code,Section IX for the following:

Class 2 weld for replacement of SG Number 4 stop valve MRV-240, Inlet Condensation Drain Shutoff Valve (1-MS-135-4)

b. Findings

No findings of significance were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the replaced Unit 1 vessel head, an examination was not required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D), so the inspectors did not conduct a review in this area.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed visual examinations of the Unit 1 RCS and emergency core cooling systems within containment to determine if these visual examinations focused on locations where boric acid leaks can cause degradation of safety significant components. Specifically, the inspectors looked for boric acid leakage on the RCS loop piping including the reactor coolant pumps and the RCS piping within the pressurizer enclosure.

The inspectors reviewed the following licensee evaluations of reactor coolant system connected components with boric acid deposits to determine if degraded components were documented in the corrective action program. The inspectors also evaluated corrective actions for any degraded reactor coolant system components to determine if they met the ASME Section XI:

CR 00839231; BA 13 Shaft Seal Of Reactor Coolant Pump (RCP) Number 3;

CR 00841127-01; BA Number 12 RCP Seal; and

CR 00860898; Valve 1-CS-320.

The inspectors reviewed the following work orders related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B:

WO 55328661-01; 1-PP-45-3 - RCP Repair Mechanical Seal Leak;

WO 55322828-08; 1-PP-45-3 - Refurbish Mechanical Seal Package;

WO 55330867-01; 1-PP-45-2 - RCP Clean Up Dry Boric Acid In Bowl;

WO 55330807-03; 1-PP-45-3 - Clean off Boric Acid Residue; and

WO 55352774-01; 1-CS-320 - Buildup of Boric Acid on Pipe Cap (inactive).

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The Unit 1 SGs were replaced in 2000, and no examinations were required this refueling outage pursuant to TS requirements 3.4.17 Steam Generator Tube Integrity, and 5.5.7 Steam Generator Program. Therefore, the licensee did not conduct SG tube examinations and only a portion of the NRC inspection procedure could be completed for this review area. Specifically, from March 8 - 25, 2010, the inspectors performed an on-site review of documentation related to the SG ISI program to determine if:

the size of SG tube flaws/degradation predicted by the licensees Operational Assessment would remain within structural integrity limits until the next scheduled tube inspection (e.g., until the end of the next operating cycle); and

primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons-per-day or the detection threshold during the previous operating cycle.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI/SG related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if:

the licensee had established an appropriate threshold for identifying ISI/SG related problems;

the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

.1 Resident Inspector Quarterly Review

Main article: IP 71111.11Q

a. Inspection Scope

On January 13-14, 2010, the inspectors observed several licensed operators perform job performance measures in the plant and in the plants simulator during licensed operator requalification examinations. The inspectors verified that operator performance was adequate, that evaluators were identifying and documenting operator performance problems, and that the examinations were being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

licensed operator performance;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures; and

control board manipulation.

The operators performance in these areas was compared to pre-established expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.

b. Findings

No findings of significance were identified.

Biennial Licensed Operator Requalification Inspection Completion of Sections

.2 through .10 constituted one biennial licensed operator

requalification inspection sample as defined in IP 71111.11B.

.2 Facility Operating History

.5 Examination Security

a. Inspection Scope

The inspectors observed and reviewed the licensees overall licensed operator requalification examination security program related to examination physical security (e.g., access restrictions and simulator considerations) and integrity (e.g., predictability and bias) to verify compliance with 10 CFR 55.49, Integrity of Examinations and Tests.

The inspectors also reviewed the facility licensees examination security procedure, any corrective actions related to past or present examination security problems at the facility, and the implementation of security and integrity measures (e.g., security agreements, sampling criteria, bank use, and test item repetition) throughout the examination process. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

A Senior Reactor Operator on the examination security agreement with examination specific knowledge provided evaluations for another operator that was preparing to take his biennial written examination and annual operating test. It was verified by training department personnel that the Senior Reactor Operator had not revealed any examination specific information to the operator during the course of the evaluations.

The operator was placed on the security agreement and directed not to discuss any evaluations covered by the Senior Reactor Operator on the security agreement with any other operators. The operator was required to take the same examination administered to the Senior Reactor Operator on examination security because he had no examination information for that examination. This examination security issue was documented in AR 00862681. Because no examination material was exposed to unauthorized personnel, no compromise or violation of examination security occurred. However, all examination security issues are required to be documented.

.6 Licensee Training Feedback System

a. Inspection Scope

The inspectors assessed the methods and effectiveness of the licensees processes for revising and maintaining its LORT Program up-to-date, including the use of feedback from plant events and industry experience information. The inspectors reviewed the licensees quality assurance oversight activities, including licensee training department self-assessment reports. The inspectors evaluated the licensees ability to assess the effectiveness of its LORT program and their ability to implement appropriate corrective actions. This evaluation was performed to verify compliance with 10 CFR 55.59(c) and the licensees SAT program. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.7 Licensee Remedial Training Program

a. Inspection Scope

The inspectors assessed the adequacy and effectiveness of the remedial training conducted since the previous biennial requalification examinations and the training from the current examination cycle to ensure that they addressed weaknesses in licensed operator or crew performance identified during training and plant operations. The inspectors reviewed remedial training procedures and individual remedial training plans.

This evaluation was performed in accordance with 10 CFR 55.59(c) and with respect to the licensees SAT program. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.8 Conformance with Operator License Conditions

a. Inspection Scope

The inspectors reviewed the facility and individual operator licensees' conformance with the requirements of 10 CFR Part 55. The inspectors reviewed the facility licensee's program for maintaining active operator licenses and to assess compliance with 10 CFR 55.53(e) and (f). The inspectors reviewed the procedural guidance and the process for tracking on-shift hours for licensed operators and which control room positions were granted watch-standing credit for maintaining active operator licenses.

The inspectors reviewed the facility licensee's LORT program to assess compliance with the requalification program requirements as described by 10 CFR 55.59(c). Additionally, medical records for twelve licensed operators were reviewed for compliance with 10 CFR 55.53(I). The documents reviewed during this inspection are listed in the

.

b. Findings

No findings of significance were identified.

.9 Conformance with Simulator Requirements Specified in 10 CFR 55.46

a. Inspection Scope

The inspectors assessed the adequacy of the licensees simulation facility (simulator)for use in operator licensing examinations and for satisfying experience requirements as prescribed in 10 CFR 55.46, Simulation Facilities. The inspectors also reviewed a sample of simulator performance test records (i.e., transient tests, malfunction tests, steady state tests, and core performance tests), simulator discrepancies, and the process for ensuring continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The inspectors reviewed and evaluated the discrepancy process to ensure that simulator fidelity was maintained. Open simulator discrepancies were reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59 operator actions as well as on nuclear and thermal hydraulic operating characteristics. The inspectors conducted interviews with members of the licensees simulator staff about the configuration control process and completed the IP 71111.11, Appendix C, checklist to evaluate whether or not the licensees plant-referenced simulator was operating adequately as required by 10 CFR 55.46(c) and (d). The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.10 Annual Operating Test Results

Main article: IP 71111.11B

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the biennial written examination, the individual Job Performance Measure operating tests, and the simulator operating tests (required to be given per 10 CFR 55.59(a)(2)) administered by the licensee from January 5, 2010, through February 5, 2010, as part of the licensees operator licensing requalification cycle. These results were compared to the thresholds established in Inspection Manual Chapter 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP)." The evaluations were also performed to determine if the licensee effectively implemented operator requalification guidelines established in NUREG-1021, Operator Licensing Examination Standards for Power Reactors, and Inspection Procedure 71111.11, Licensed Operator Requalification Program. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

a. Inspection Scope

The inspectors reviewed the licensees 10 CFR 50.65 (a)(3) periodic evaluation (PE)that was completed for the fourth quarter in 2007 thru the first quarter of 2009. The inspectors verified that the PE was completed within the time constraints of the maintenance rule; that the licensee reviewed (a)(1) goals, (a)(2) performance criteria and effectiveness of corrective actions; and that industry operating experience was taken into account where practicable. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly maintenance effectiveness sample as defined in IP 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

a. Inspection Scope

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

Activities during the week of January 11, 2010, which included: planned Unit 2 east essential service water pump motor replacement and preventive maintenance on the pump discharge valve; and, emergent maintenance to repair a steam leak on the turbine driven auxiliary feedwater pump steam supply vent valve 2-MS-421 and to replace a voltage regulator in Train B distributed ignition system.

Planned maintenance during the week of January 25, 2010, which included Unit 2 west essential service water pump replacement, Unit 2 containment spray surveillance testing, Unit 1 component cooling water pump preventive maintenance and Unit 1 charging pump motor preventive maintenance.

Emergent maintenance on the supplemental diesel generators during the weeks of February 15 and February 22, 2010.

Planned maintenance on March 15-16, 2010, which included Unit 1 essential service water dual pump outage to allow divers to clean the pump bays.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

These maintenance risk assessments and emergent work control activities constituted four samples as defined in IP 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

Main article: IP 71111.15

a. Inspection Scope

The inspectors reviewed the following issues:

AR 00849398, Small break loss of coolant accident assessment of reduced recirculation flow with residual heat removal system spray in service;

AR 09353013, Unit 1 SG stop valve 1-MRV-230 dump valve 1-MRV-231 leak-by;

AR 00861425, Over-thrust condition on east residual heat removal mini-flow line shutoff valve;

AR 00089572, Essential Service Water (ESW) water hammer;

AR 2010-1678, Un-wedging over-thrust condition;

AR 00813401, Gaps in the barrier between the turbine building and the screen house; and

AR 2010-1804, Reactor vessel core support lug bolting anomalies.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This operability inspection constituted seven samples as defined in IP 71111.15-05.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

Main article: IP 71111.18

.1 Permanent Plant Modifications

a. Inspection Scope

The following engineering design packages were reviewed and selected aspects were discussed with engineering personnel:

EC-0000049339, ESW Pump Reliability Upgrade Project for Unit 2 West Pump, 2-PP-7W

EC-0000049543, Generic Letter (GL) 2008-01 Vent Modification for the Unit 1 reactor coolant system high point vents on the RCP seal return lines.

The inspectors reviewed the design change package to verify the adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, implementation of the modification, and post-modification testing. The inspectors also verified that relevant procedures were properly updated and observed portions of ongoing and completed work activities to verify that installation was consistent with the design control documents.

The primary reason for the ESW modification, which included removing an 8-foot section from the pump suction column and installing a vortex suppressor at the bottom of the pump bowl, was to reduce pump vibration. The primary reason for the vent modification on the RCP seal return lines was to provide an adequate venting path during system fill which was performed in response to GL 2008-01 to address gas accumulation in the emergency core cooling system. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

Also, additional activities were performed during the evaluation of the engineering design package associated with TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. These activities are described in paragraph

.2 of this section.

This inspection constituted two permanent plant modification samples as defined in IP 71111.18-05.

b. Findings

No findings of significance were identified.

.2 Permanent Plant Modifications associated with Temporary Instruction 2515/177,

Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems.

a. Inspection Scope

and Documentation The following engineering design package associated with the scope of GL 2008-01, Managing gas accumulation in emergency core cooling, decay heat removal, and containment spray systems, was reviewed and selected aspects were discussed with engineering personnel:

EC-0000049543, GL 2008-01 Vent Modification for the Unit 1 reactor coolant system high point vents on the RCP seal return lines.

The inspectors verified that the licensing basis verification documents have either been updated or are in the process of being updated to reflect the modifications associated with the licensees resolution of GL 2008-01. Specifically, the inspectors verified that the licensees resolution has been incorporated into the UFSAR and is currently being evaluated for incorporation into the TS and TS Bases.

In addition, the inspectors verified that the drawings were up-to-date with respect to recent hardware changes and that any discrepancies between as-built configurations and the drawings were documented and entered into the CAP for resolution.

Similarly, the inspectors verified that Piping and Instrumentation Diagrams accurately described the subject systems, that they were up-to-date with respect to recent hardware changes, and any discrepancies between as-built configurations, the isometric drawings, and the Piping and Instrumentation Diagrams were documented and entered into the CAP for resolution.

Documents reviewed are listed in the Attachment to this report.

This inspection effort counts towards the completion of TI 2515/177 which will be closed in a later inspection report.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance testing for the following activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

Unit 2 control room air conditioning system south train humidifier heating element replacement;

Unit 2 distributed ignition system Train B voltage regulating unit replacement;

Unit 2 west essential service water pump replacement;

Unit 1/2 supplemental diesel generator control interface software update;

Unit 1 west centrifugal charging pump following impeller and mechanical seal replacement;

Unit 1 AB emergency diesel generator (EDG) 18-month maintenance;

Unit 1 CD EDG electronic governor replacement; and

Unit 1 CD battery charger, 1-BC-CD2, 10-year preventive maintenance to replace internal components.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TS, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted eight post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Outage Activities

Main article: IP 71111.20

.1 Refueling Outage Activities

a. Inspection Scope

On March 3, 2010, Unit 1 was shut down and Cycle 23 refueling outage commenced.

The inspectors began refueling outage inspection activities, which are expected to be completed and documented during the next inspection period. An inspection sample was not completed this inspection period.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

Unit 2 Train A distributed ignition system surveillance test (routine);

Unit 2 Train B distributed ignition system surveillance test (routine);

Unit 1 east control room pressurization and cleanup surveillance test (routine);

Unit 1 and Unit 2 reactor coolant system leak rate test (reactor coolant system leak detection);

Unit 1 main steam safety valve setpoint verification with lift assist device (in-service test);

Unit 1 residual heat removal system valve interlock verification test (routine); and

Unit 1 containment isolation valve local leak rate test surveillance (containment isolation valve).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

did preconditioning occur;

were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;

plant equipment calibration was correct, accurate, and properly documented;

as-left setpoints were within required ranges; and the calibration frequency were in accordance with TSs, the UFSAR, procedures, and applicable commitments;

measuring and test equipment calibration was current;

test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

test data and results were accurate, complete, within limits, and valid;

test equipment was removed after testing;

where applicable for in-service testing activities, testing was performed in accordance with the applicable version of Section XI, ASME code, and reference values were consistent with the system design basis;

where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

equipment was returned to a position or status required to support the performance of its safety functions; and

all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted four routine surveillance testing samples, one in-service testing sample, one reactor coolant system leak detection sample, and one containment isolation valve sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2RS0 1 Radiological Hazard Assessment and Exposure Controls

Main article: IP 71124.01

This inspection constituted a partial sample as defined in 71124.01.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee Performance Indicators (PIs) for the Occupational Exposure Cornerstone for followup. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings of significance were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors determined if there have been changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee has assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from three selected plant areas. The inspectors assessed whether the thoroughness and frequency of the surveys is appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility, including radioactive waste processing, storage, and handling areas to evaluate material conditions and performed independent radiation measurements to verify conditions.

The inspectors selected the following radiologically risk-significant work activities that involved exposure to radiation.

Mechanical Stress Improvement Process;

Refueling Activities;

Containment Scaffolding;

Shielding Activities; and

Valve Maintenance Activities.

For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

identification of hot particles;

the presence of alpha emitters;

the potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials (this evaluation may include licensee planned entry into non-routinely entered areas subject to previous contamination from failed fuel);

the hazards associated with work activities that could suddenly and severely increase radiological conditions; and

severe radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors selected the following air sample survey records to assess whether the samples were collected and counted in accordance with licensee procedures.

Reactor Coolant Pump 11;

Containment During Cavity Flood-up; and

Refuel Floor During Fuel Transfers.

The inspectors observed work in potential airborne areas and evaluated whether air samples were representative of the breathing air zone. The inspectors evaluated whether continuous air monitors were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspectors assessed whether the licensee had a program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

b. Findings

No findings of significance were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected three containers holding nonexempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether they are labeled and controlled in accordance with 10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g).

The inspectors reviewed the following radiation work permits (RWPs) used to access high radiation areas (HRAs) and evaluated the specified work control instructions or control barriers.

RWP 101106 U1C23 Reactor Nozzle Pits/Sandbox Reactor Cavity Mechanical Stress Improvement Process Activities;

RWP 101100 Refuel Cavity Decontamination Activities;

RWP 101142 Containment Scaffolding;

RWP 101153 Containment Radiation Protection Activities; and

RWP 101145 Valve Maintenance.

For these RWPs, the inspectors assessed whether allowable stay times or permissible dose (including from the intake of radioactive material) for radiologically significant work under each RWP was clearly identified. The inspectors evaluated whether electronic personal dosimeter alarm set-points were in conformance with survey indications and plant policy.

b. Findings

No findings of significance were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated material leaving the radiologically controlled area, and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use and evaluated whether the work was performed in accordance with plant procedures. The inspectors also reviewed whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site.

The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.

b. Findings

No findings of significance were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, RWPs, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys (including system breach radiation, contamination, and airborne surveys),radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of electronic personal dosimeters in high noise areas as high radiation area monitoring devices.

The inspectors assessed whether radiation monitoring devices were placed on the individuals body consistent with licensee procedures. The inspectors evaluation whether the dosimeter was placed in the location of highest expected dose or that the licensee is properly employing an NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients. During the on-site inspection there were no work areas with significant dose rate gradients.

Main article: IP 71124.02

This inspection constitutes a partial sample as defined in IP 71124.02-5.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed pertinent information regarding plant collective exposure history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants 3-year rolling average collective exposure.

The inspectors reviewed the site-specific trends in collective exposures (using NUREG-0713, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and Other Facilities, and plant historical data) and source term (average contact dose rate with reactor coolant piping) measurements (using Electric Power Research Institute TR-108737, BWR Iron Control Monitoring Interim Report, issued December 1998, and/or plant historical data, when available).

The inspectors reviewed site-specific procedures associated with maintaining occupational exposures ALARA, which included a review of processes used to estimate and track exposures from specific work activities.

b. Findings

No findings of significance were identified.

.2 Radiological Work Planning (02.02)

a. Inspection Scope

The inspectors selected five work activities of the highest exposure significance, some with greater than 5 person-rem of exposure. The inspectors determined whether the licensee reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances. The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements.

The inspectors assessed whether the licensees planning identified appropriate dose mitigation features; considered alternate mitigation features; and defined reasonable dose goals. The inspectors evaluated whether the licensees ALARA assessment had taken into account decreased worker efficiency from use of respiratory protective devices and/or heat stress mitigation equipment (e.g., ice vests). The inspectors determined whether the licensees work planning considered the use of remote technologies (such as teledosimetry, remote visual monitoring, and robotics) as a means to reduce dose and the use of dose reduction insights from industry operating experience and plant-specific lessons learned. The inspectors evaluated the integration of ALARA requirements into work procedure and RWP documents.

b. Findings

No findings of significance were identified.

.3 Verification of Dose Estimates and Exposure Tracking Systems (02.03)

a. Inspection Scope

The inspectors reviewed the assumptions and basis (including dose rate and man-hour estimates) for the current annual collective exposure estimate for reasonable accuracy for select ALARA work packages. The inspectors reviewed applicable procedures to determine the methodology for estimating exposures from specific work activities and the intended dose outcome.

The inspectors assessed whether the licensee had established measures to track, trend, and if necessary to reduce, occupational doses for ongoing work activities.

The inspectors evaluated whether trigger points or criteria were established to prompt additional reviews and/or additional ALARA planning and controls.

Main article: IP 71124.05

This inspection constitutes partial sample as defined in IP 71124.05.

.1 Inspection Planning and Identification of Instrumentation (02.01)

a. Inspection Scope

The inspectors reviewed the plants UFSAR to identify radiation instruments associated with monitoring area radiological conditions including airborne radioactivity, process streams, effluents, materials/articles, and workers. Additionally, the inspectors reviewed the instrumentation and the associated TS requirements for post-accident monitoring instrumentation including instruments used for remote emergency assessment.

The inspectors obtained a listing and review of in-service survey instrumentation including air samplers and small article monitors, along with instruments used to detect and analyze workers external contamination. Additionally, the inspectors also reviewed personnel contamination monitors and a portal monitor including whole-body counters (WBCs) to detect workers internal contamination. From a review of the list, the inspectors were to determine if the licensee had an adequate number and type of instruments to support plant operations.

The inspectors obtained and reviewed through a smart sampling of the licensees independent evaluation reports of the radiation monitoring program since the last inspection. This review included audits of the licensees onsite calibration facility.

The inspectors obtained and reviewed copies of the procedures that govern instrument source checks and calibrations, and focused on instruments used for monitoring transient high radiological conditions, including instruments used for underwater surveys and area radiation monitors. These procedures were reviewed for the basis of alarm set-point values, as provided in the TSs, UFSAR, and the set-point basis as provided in the offsite dose calculation manual (ODCM).

b. Findings

No findings of significance were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors performed walkdowns of the following five effluent radiation monitoring systems (liquid and airborne system):

Westinghouse liquid process monitor;

Mid range noble gas monitors;

Eberline Sample Particulate Iodine and noble gas area monitors;

Unit 1 east and west component cooling water radiation monitors; and

Victoreen containment monitors.

The inspectors also inspected the flow measurement devices and all accessible point-of-discharge liquid and gaseous effluent monitors of the selected systems. The inspectors also verified that effluent/process monitor configurations aligned with ODCM descriptions and none of the monitors were out-of-service or degraded.

The inspectors selected a minimum of 10 portable survey instruments during the inspection to verify calibration and source check stickers and to assess instrument material condition and operability. The inspectors observed licensee staff demonstrated source checks for various types of portable survey instruments and the source checks were performed at the appropriate scales (low and high range). The inspectors walked down a minimum of 18 area radiation monitors and continuous air monitors to determine whether they are appropriately positioned to the areas they were intended to monitor.

Selectively, the inspectors compared monitor response via local or remote control room indications with actual area conditions for consistency.

The inspectors selected three personnel contamination monitors, portal monitors, and small article monitors, and verified that the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

b. Findings

No findings of significance were identified.

.3 Calibration and Testing Program (02.03)

Process and Effluent Monitors

a. Inspection Scope

The inspectors selected five effluent monitor instruments (such as gaseous and liquid)and verified that channel calibration and functional tests were performed consistent with radiological effluent TS/ODCM. The inspectors verified that:

(a) the licensee calibrated its monitors with National Institute of Standards and Technology (NIST) traceable sources;

(b) the primary calibrations were adequately represented the plant nuclide mix;

(c) when secondary calibration sources were used, the sources were verified by the primary calibration; and

The inspectors reviewed calibration documentation for several portable survey instruments, ARMs, electronic dosimetry and air samplers or CAMs. Calibration methods and detector measurement geometry, as applicable, were evaluated to determine whether the calibration methods used for these instruments was consistent with the licensee's procedures.

The inspectors reviewed documentation to verify that problems associated with radiation monitoring instrumentation are being identified by the licensee at an appropriate threshold and are properly addressed for resolution in the licensees corrective action program. The inspectors referenced Inspection Procedure 71152, Identification and Resolution of Problems, for additional guidance. In addition to the above, the inspectors verified whether the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring instrumentation were appropriate.

The inspectors reviewed corrective action program reports related to exposure significant radiological incidents that involved radiation monitoring instrument deficiencies since the last inspection in this area. Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

Initial problem identification, characterization, and tracking;

Disposition of operability/reportability issues;

Evaluation of safety-significance/risk and priority for resolution;

Identification of repetitive problems;

Identification of contributing causes;

Identification and implementation of effective corrective actions;

Resolution of Non-Cited Violations tracked in the corrective action system; and

Implementation/consideration of risk significant operational experience feedback.

The inspectors determined if the licensees self-assessment activities were identifying and addressing repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours PI for both units from the first quarter of 2009 through the fourth quarter of 2009.

Main article: IP 71152

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

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: the complete and accurate identification of the problem; that timeliness was commensurate with the safety significance; that evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the attached List of Documents Reviewed.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily CR packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings of significance were identified.

.3 Selected Issue Follow-up Inspection: AR 00861410 Root Cause Evaluation

a. Inspection Scope

The inspectors selected the following for an in-depth review:

AR 00860140, Root Cause Analysis Report, Mobile Crane Severed 12 kilo volt (KV) Line in W-Yard, November 2009 The inspectors discussed the evaluations and associated corrective actions with licensee personnel and verified the following attributes during their review of the root cause evaluation:

complete and accurate identification of the problem in a timely manner commensurate with its safety significance and ease of discovery;

consideration of the extent of condition, generic implications, common cause and previous occurrences;

classification and prioritization of the resolution of the problem, commensurate with safety significance;

identification of the root and contributing causes of the problem; and

identification of corrective actions, which were appropriately focused to correct the problem.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

Introduction:

A finding of very low safety significance was self-revealed for the failure to implement procedures for using mobile cranes to move material and the failure to use human error prevention tools. Consequently, a mobile crane boom contacted and severed an overhead 12KV line while moving materials in the owner controlled area.

This caused a loss of power to the fire pump house and the electric fire pump, which rendered the electric fire pump inoperable. No violation of regulatory requirements occurred.

Description:

On November 4, 2009, during night shift, a mobile crane struck the middle phase of a 12KV line while moving materials in the owner controlled area W yard.

The line was severed, which caused a loss of power to several onsite buildings including the fire pump house. The loss of power to the fire pump house caused the east diesel-driven fire pump to start on low fire header pressure due to loss of power to the pegging pump and rendered the electric fire pump inoperable as per Technical Requirements Manual 8.7.5, Fire Suppression Water System. The electric fire pump was returned to an operable status approximately 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months later when power was restored to the fire pump house, which satisfied Technical Requirements Manual 8.7.5 action requirements. The east and west diesel-driven fire pump remained operable the entire time.

Further investigation determined that several human errors, inappropriate decisions, and broken barriers (e.g., procedures, training, oversight, and work management) all contributed to this incident. Licensee supervisory oversight of the supplemental workers performing the task was lacking, which the inspectors concluded was considered a primary contributor. Also, the crane operator qualification/training was considered to be ineffective because the need to verify adequate clearance for overhead lines and obstacles that could be inadvertently contacted was not considered.

The procedures specific to mobile crane use and rigging (PMP-5020-MHP-001, Lifting and Rigging Program, Revision 11, and MHI-5027, Operation of Mobile Cranes, Revision 5), were not used because the workers decided to use the mobile crane when the equipment designated for use in the work order task (rental SkyTrack fork lift) was not available in the field. However, supervision was not consulted, potential new hazards were not considered, and a new pre-job brief was not conducted for the change.

Consequently, no signal person or spotter was focused on the boom when raising or backing up; the job hazard analysis did not identify overhead power lines in the work area; and lighting in the area was not adequate for performing mobile crane activities at night. As a result, the workers did not see the overhead power lines and the crane boom contacted and severed the middle phase of the 12KV line.

Analysis:

The inspectors concluded that the failure to implement plant procedures for using a mobile crane and the failure to use human error prevention tools was a licensee performance deficiency that warranted an evaluation in accordance with the significance determination process.

The inspectors reviewed the samples of minor issues in Inspection Manual Chapter (IMC) 0612, Power Reactors Inspection Reports, Appendix E, Examples of Minor Issues, and determined that there were no examples related to this issue. Using the guidance contained in IMC 0612, Appendix B, Issue Screening, the inspectors determined that the performance deficiency was more than minor because it was associated with the fire external factors attribute and affected the mitigating system cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the failure to implement plant procedures for using mobile cranes and the failure to use human error prevention tools resulted in a crane boom contacting and severing an overhead 12KV line. Consequently, power was lost to the fire pump house, which rendered the electric fire pump inoperable and unavailable.

In accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, Table 3b, the inspectors determined the finding degraded the fire protection defense-in-depth strategies.

Therefore, the inspectors evaluated the finding using IMC 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors assumed a LOW degradation rating for this finding in step 1.2, because system performance was not affected as both diesel-driven fire pumps remained operable to provide water to the stations fire protection system, if required. Therefore, the finding screened as Green (very low safety significance).

Cross Cutting Aspect The inspectors concluded that this finding has a cross cutting aspect in the area of human performance - work practices. Licensee personnel failed to ensure supervisory and management oversight of contract workers using a mobile crane such that nuclear safety was supported (H.4(c)).

Enforcement:

Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement. This issue was entered into the licensees corrective action program as AR 00860140. Because this finding does not involve a violation of regulatory requirements and has very low safety significance, it is identified as a finding (FIN 05000315/2010002-01; 05000316/2010002-01, Failure to Implement Plant Procedures for Using a Mobile Crane.)

.4 Selected Issue Follow-up Inspection: Condition Report 00864717

a. Inspection Scope

The inspectors selected the following for an in-depth review:

Water intrusion into cable vaults containing safety-related cabling.

The inspectors discussed the evaluations and associated corrective actions with licensee personnel and verified the following attributes during their review of CRs that were generated for water intrusion into cable vaults:

complete and accurate identification of the problem in a timely manner commensurate with its safety significance and ease of discovery;

consideration of the extent of condition, generic implications, common cause and previous occurrences;

classification and prioritization of the resolution of the problem, commensurate with safety significance;

identification of the root and contributing causes of the problem; and

identification of corrective actions, which were appropriately focused to correct the problem.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

Introduction The inspectors identified a finding of very low safety significance (Green) with an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. Specifically, licensee personnel failed to implement corrective actions for water intrusion into vaults containing safety-related cabling in a timely and effective manner.

Description On February 8, 2010, during the performance of an auxiliary building tour, the inspectors identified water in the vault below motor control center 1-ABV-A on the 587 foot elevation in the auxiliary building, which contained safety-related cabling. The inspectors notified the licensee of the water present in the cable vault and the issue was entered into the licensees corrective action program as AR 00864717. Subsequent investigation performed by the inspectors revealed that a history of water intrusion into cable vaults throughout the plant existed. Several CRs and work requests generated since 2001 identified water in cable vaults containing safety and non-safety related cabling. The inspectors noted that AR 00116111 generated on September 20, 2005, identified water present in two cable vaults that had been previously identified and entered into the licensees corrective program in 2001.

The inspectors reviewed several additional CRs and noted that AR 00846761 generated on February 20, 2009, documented licensee identified submerged cabling in the 1-ABD-A cable vault located in the Unit 1 AB EDG room. The inspectors noted that per the AR, the condition had been previously identified in 2008. On February 8, 2010, the inspectors conducted a walkdown and noted that water was still present.

Subsequent review by the inspectors revealed that the licensees extent of condition consisted only of reviewing previously performed and documented walkdowns of cable vaults throughout the plant. In addition, the inspectors verified with licensee personnel that plant walkdowns to look for water in cable vaults had not been performed during the extent of condition evaluation. Therefore, the inspectors determined the extent of condition evaluation was inadequate.

Additionally, the inspectors noted that although some corrective actions were taken to address the water intrusion issue, actions did not include subsequent walkdown inspections to verify that water intrusion into cable vaults had been mitigated appropriately. Consequently, timely and effective corrective actions had not been implemented to address the long history of water intrusion into cable vaults containing safety-related cabling.

Analysis The inspectors determined that failure to implement corrective actions in a timely and effective manner to prevent water intrusion into cable vaults containing safety-related cabling was a licensee performance deficiency that warranted an evaluation in accordance with the SDP.

The inspectors reviewed the samples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, and determined that there were no examples related to this issue. Consistent with the guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that this issue could become a more significant safety concern if left uncorrected and was therefore more than minor. Specifically, failure to implement corrective actions for water intrusion into cable vaults could result in subsequent degradation of safety-related cabling.

Because this issue involved safety-related cabling which could affect systems required for safe shutdown, the inspectors concluded that this finding was associated with the Mitigating System cornerstone. The inspectors performed a Phase 1 SDP review using the guidance provided in IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Using the Mitigating System cornerstone column in Table 4a, Characterization Worksheet for Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones, the inspectors determined that this finding screened as Green, very low safety significance, because the finding does not constitute a design or qualification deficiency, did not result in a loss of system safety function, and did not meet the seismic, flooding, and severe weather screening criteria on Table 4b.

Cross-Cutting Aspect The inspectors concluded that this finding has a cross-cutting aspect in the area of problem identification and resolution - corrective action program (P.1(c)). Licensee personal failed to thoroughly evaluate water intrusion into cable vaults containing safety-related cabling. Consequently, the resolution did not adequately address the cause and extent of condition.

Enforcement The CFR, Title 10, Part 50 Appendix B, Criterion XVI, Corrective Action, requires in part that conditions adverse to quality are promptly identified and corrected.

Contrary to the above, between February 20, 2009, and February 8, 2010, licensee personnel failed to implement corrective actions for water intrusion into vaults containing safety-related cabling in timely and effective manner. Consequently, safety related cabling was exposed to a water environment that if left uncorrected could result in subsequent cable degradation. For corrective action, the licensee performed an inspection of all cable vaults throughout the plant. Also, licensee personnel initiated a root cause evaluation to focus on the leadership and organizational failures associated with the response to the wetted cables in the 1-ABD-A cable vault and the thoroughness of the extent of condition evaluation. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy. This finding was entered into the licensee's corrective action program as AR 20102558 (NCV 05000315/2010002-02; 05000316/2010002-02, Failure to Implement Corrective Actions in a Timely and Effective Manner).

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

.2 (Open) NRC TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling,

Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)

a. Inspection Scope

During the Unit 1 refueling outage, on March 22 - 26, 2010, the inspectors conducted a walkdown of normally inaccessible portion of piping of the reactor coolant seal injection system in sufficient detail to reasonably assure the acceptability of the licensees walk downs (TI 2515/177, Section 04.02.d). The reactor coolant pump seal injection system is part of the chemical volume and control system and is supplied by and returned to the high head safety injection centrifugal charging pumps. The inspectors also verified that the information obtained during the licensees walkdown was consistent with the items identified during the inspectors independent walkdown (TI 2515/177, Section 04.02.c.3).

In addition, the inspectors verified that the licensee had isometric drawings that describe the reactor coolant pump seal injection system configurations and had acceptably confirmed the accuracy of the drawings (TI 2515/177, Section 04.02.a). The inspectors verified the following related to the isometric drawings:

High point vents were identified.

High points that do not have vents were acceptably recognizable.

Other areas where gas can accumulate and potentially impact subject system operability, such as at orifices and check valves in horizontal pipes, were acceptably described in the drawings or in referenced documentation.

All pipes and fittings were clearly shown.

The drawings were up-to-date with respect to recent hardware changes and that any discrepancies between as-built configurations and the drawings were documented and entered into the CAP for resolution.

The inspectors verified that piping and instrumentation diagrams accurately described the subject systems, that they were up-to-date with respect to recent hardware changes, and any discrepancies between as-built configurations, the isometric drawings, and the piping and instrumentation diagrams were documented and entered into the CAP for resolution (TI 2515/177, Section 04.02.b).

In addition, as documented in Section 1R18, the inspectors confirmed the acceptability of the described licensees actions regarding a plant modification.

These inspection efforts count towards the completion of TI 2515/177 which will be closed in a later Inspection Report. The NRC staff (Office of Nuclear Reactor Regulation

- NRR) completed their review of the licensees GL 2008-01 responses as documented in letter dated February 26, 2010, accession number ML100540139. TI 2515/177 is intended to be confirmatory in nature.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.3 Reactor Coolant System Dissimilar Metal Butt Welds (TI 2515/172)

a. Inspection Scope

The NRC has issued several Bulletins and an Order since 2001 related to the occurrence of PWSCC in reactor coolant system components and welds containing Alloy 600/82/182. In September of 2005, the Electric Power Research Institute issued MRP-139 Primary System Piping Butt Weld Inspection and Evaluation Guidelines.

The MRP-139 provided licensees with industry guidance for augmented volumetric examination of dissimilar metal butt welds (DMBW) in pressurized water reactor (PWR)primary systems containing Alloy 600/82/182 materials susceptible to PWSCC.

In April of 2008, the NRC performed a review of the Unit 1 DMBWs in accordance with TI 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds to evaluate the licensees implementation of MRP-139 for the Unit 1 DMBWs (reference NRC report 05000315/2008003; 05000316/2008003). Subsequently, the licensee developed revised plans for inspection and mitigation of the Unit 1 reactor vessel (RV) inlet and outlet nozzle DMBWs. Therefore, from March 8 - 25, 2010, the inspectors performed a review in accordance with select portions of TI 2515/172 as described below;

Section 03.01 of TI/172 - Implementation of the Baseline MRP-139 Inspections.

The inspectors conducted a review for the Units 1 RV inlet and outlet nozzle DMBWs, to determine if the licensee completed the baseline volumetric examinations in accordance with MRP-139.

Section 03.02 of TI/172 - Evaluation of Volumetric Examinations. The inspectors observed licensee volumetric examinations of the Unit 1 RV inlet and outlet nozzle DMBWs to determine if these examinations were completed in accordance with Section 5.1 of MRP-139.

Section 03.04 of TI/172 - MSIP. The inspectors observed the MSIP completed on the Unit 1 RV inlet and outlet nozzles to determine if the MSIP process applied was consistent with the MSIP design/qualification report. The inspectors also reviewed the licensees basis for not performing volumetric and surface examinations of the RV inlet nozzle DMBWs prior to the application of MSIP.

Section 03.06 of TI/172 - Inservice Inspection Program. The inspectors reviewed the licensees inservice inspection program for the RV inlet and outlet nozzles to determine if these welds were placed in examination categories consistent with MRP-139 and to identify any deviations from MRP-139 examination requirements.

The documents reviewed by the inspector for this inspection are listed in the Attachment to this report.

b. Observations Summary: D. C. Cook Unit 1 is a Westinghouse four loop design plant with DMBWs containing Inconel Alloy 82/182 material on six pressurizer nozzles and eight RV nozzles. By the end of 2006, the licensee had completed mitigation for each of the Unit 1 pressurizer nozzle DMBWs by installation of a full structural weld overlay that included a performance demonstration initiative (PDI) qualified UT pre-service examination for the required weld volume. The licensee elected to perform MSIP on the eight Unit 1 RV nozzle DMBWs as a mitigation technique. The inspectors observed the licensee performing MSIP on hot and cold leg DMBWs and recorded relevant observations for the applicable TI 2515/172 questions as discussed below.

Based on the schedule of DMBW examinations under MRP-139, examinations were required for the Unit 1 hot leg DMBWs prior to the current refueling outage, but not performed. The licensee submitted their basis for this deviation from MRP-139 as discussed below.

In accordance with requirements of TI 2515/172, Revision 0, the inspectors evaluated and answered the following questions:

a. For MRP-139 Baseline Inspections:

1a.

Have the baseline inspections been performed or are they scheduled to be performed in accordance with MRP-139 guidance?

No. For Unit 1, the DMBWs at pressurizer temperatures were mitigated using full structural overlays by the end of 2006, which complied with the MRP-139 schedule. The remaining Unit 1 DMBWs containing Inconel Alloy 82/182 material was the RV inlet and outlet nozzle-to-safe-end welds (four of each).

Inspection of the RV inlet and outlet nozzle welds in March of 2010, complied with the MRP-139 schedule for the inlet nozzles, but not for the RV outlet nozzle welds. The RV outlet nozzle DMBWs were required to be inspected by December 31, 2009, and the licensee submitted a technical justification to Electric Power Research Institute for this deviation from the inspection schedule as discussed below in item 2.

1b.

Were the baseline inspections of the pressurizer temperature DMBWs of the nine plants listed in 03.01.b completed during the spring 2008 outages?

Not Applicable. D. C. Cook Unit 1 was not among the population of nine plants scheduled for inspection and mitigation of DMBWs in the spring 2008 outages.

Is the licensee planning to take any deviations from the MRP-139 baseline inspection requirements of MRP-139? If so, what deviations are planned, what is the general basis for the deviation, and was the NEI- 03-08 process for filing a deviation followed?

Yes. The RV outlet nozzle DMBWs were required by MRP-139 to have been inspected by December 31, 2009. Instead, the licensee volumetrically examined these four welds with PDI qualified UT techniques in March of 2010.

On September 25, 2009, the licensee had submitted a technical justification to Electric Power Research Institute for the deviation from the MRP-139 inspection schedule required for Alloy 82/182 butt welds in piping greater than 14 inch nominal pipe size operating at hot leg temperatures (e.g., applicable to the four RV outlet nozzle welds). The licensees technical justification included credit for the following:

implementing an enhanced leakage detection program in accordance with the Pressurized Water Reactor Owners Group recommendations;

no visual indications of cracking detected during the bare metal visual examinations of these welds completed in 2008; and

reduced normal operating pressures and temperatures since 1989 and the extended forced Unit 1 outage in 2009, which would be expected to reduce PWSCC growth rates.

b. For Each Examination Inspected, was the Activity:

Performed in accordance with the examination guidelines in MRP-139, Section 5.1, for unmitigated welds or mechanical stress improvement welds and consistent with NRC staff relief request authorization for weld overlaid welds?

Yes. The inspectors observed the UT and ET of the Unit 1 HL nozzle DM weld 1-RPV-2-01 pre-MSIP and the CL nozzle welds 1-RPV-1-02 post MSIP. The UT examination was completed with PDI qualified procedures that met Section XI, Appendix VIII as modified and accepted by the NRC in a letter dated February 16, 2006. These examinations met the requirements of MRP-139 Section 5.1. Specifically, the licensee had confirmed the applicability of the qualified UT process to their site specific configurations as documented in WDI-TJ-1043 Demonstration Report/Technical Basis Document: Ultrasonic Examination of Cook Unit 1 Reactor Pressure Vessel Nozzle to Safe-End Welds from the ID Surface Through a Welded Protective Layer. The inspectors noted that this document also identified potential limitations in examination of the HL and CL nozzle DM welds caused by the inside nozzle geometry, which had a step change in diameter created by a cladding layer. Coverage of the ultrasonic examinations ranged from 94.87 percent to 96.70 percent on the four outlet nozzle DM welds and from 96.79 percent to 99.71 percent on the four inlet nozzle DM welds.

Performed by qualified personnel? (Briefly describe the personnel training/qualification process used by the licensee for this activity.)

Yes. The licensees contractors that completed UT of the HL and CL nozzle DMBWs were qualified to the applicable PDI requirements.

Performed such that deficiencies were identified, dispositioned, and resolved?

Not applicable, no deficiencies were identified as a result of the inspections.

c. For Each Weld Overlay Inspected, was the Activity:

Performed in accordance with ASME Code welding requirements and consistent with NRC staff relief request authorizations? Has the licensee submitted a relief request and obtained NRR staff authorization to install the weld overlays?

Not Applicable. The licensee did not perform overlays during the Unit 1 refueling outage.

Performed by qualified personnel? (Briefly describe the personnel training/qualification process used by the licensee for this activity.)

Not Applicable. The licensee did not perform overlays during the Unit 1 refueling outage.

Performed such that deficiencies were identified, dispositioned, and resolved?

Not Applicable. The licensee did not perform overlays during the Unit 1 refueling outage.

d. For Each Mechanical Stress Improvement Used by the Licensee During the Outage, was the Activity Performed in Accordance with a Documented Qualification Report for Stress Improvement Processes and in Accordance with Demonstrated Procedures? Specifically,

Are the nozzle, weld, safe-end, and pipe configurations as applicable, consistent with the configuration addressed in the qualification report?

Yes. Based on review of piping specifications, vessel specifications and as built drawings, the HL and CL nozzle configurations were consistent with configurations documented in the licensees vendor MSIP qualification reports 4628-4-001-00 Analytical Verification of MSIP For RV Hot Leg Nozzle Safe-End Weld DC Cook Unit 1 and 4628-4-002-00 Analytical Verification of MSIP For RV Cold Leg Nozzle Safe-End Weld DC Cook Unit 1.

Does the SI qualification report address the location radial loading is applied, the applied load, and the effect that plastic deformation of the pipe configuration may have on the ability to conduct volumetric examinations?

Yes. The licensees vendor evaluated the effects of MSIP in qualification reports 4628-4-001-00, Analytical Verification of MSIP For RV Hot Leg Nozzle Safe-End Weld DC Cook Unit 1, and 4628-4-002-00, Analytical Verification of MSIP For RV Cold Leg Nozzle Safe-End Weld DC Cook Unit 1, which documented the results of 2d finite element analysis models. Specifically, these reports included tables and figures depicting the redistribution of residual pipe wall stresses based on the radial loading for a range of radial pipe displacements as measured by a permanent change in pipe circumference (e.g., plastic deformation). The licensee measured the pipe circumference following the application of MSIP to confirm that the expected change in pipe circumference had occurred. The licensee determined that MSIP was a maintenance activity that did not require review under 10 CFR 50.59 and hence, did not perform a written safety evaluation for this activity. However, the licensee had not considered the MSIP process with respect to application of original Construction Code requirements for bending and forming pipe. This issue is considered an unresolved item as discussed in Section C below.

No. The MSIP qualification reports did not address the effect of MSIP on the ability to conduct a volumetric examination. Because the majority of the plastically deformed piping occurred several inches away from the DM welds, the MSIP process did not effect the examinations, which were conducted from the inside diameter. However, the inspectors could not determine how the MSIP would effect future examinations conducted on the DM or adjacent similar metal pipe welds conducted from the outside diameter. The licensee reported that they intended to do all future examinations of the DM welds from the inside pipe surface.

3. Do the licensees inspection procedure records document that a volumetric

examination per the ASME Code Section XI, Appendix VIII was performed prior to and after application of the SI?

Yes. For the hot leg nozzle DMBWs, the licensee performed pre and post MSIP Section XI, Appendix VIII, qualified UT examinations (as modified by an NRC approved ASME Code relief request) without limitations from the inside surface of these piping welds.

No. For the cold leg nozzle DMBWs, the licensee performed only a post MSIP Section XI, Appendix VIII, qualified UT (as modified by an NRC approved ASME Code relief request) and an ET examination from the inside surface of these piping welds. Because only a post MSIP examination was completed for these welds, it was possible that weld cracks (if they existed) may have not been detected by the UT.

Specifically, NRC sponsored technical report, Technical Letter Report Analysis of Ultrasonic Data on Piping Cracks at Ignalina Nuclear Power Plant Before and After Applying a Mechanical Stress Improvement Process JCN-N6319, Task 2, issued in February 2008, (reference ADAMS ML081270142) concluded that, "This limited data set suggests that performing MSIP may have a significant effect upon ultrasonic examination data. The use of MSIP on cracked welds should be carefully considered from the viewpoint of future inservice inspections.

All cracks in a pipe where MSIP is applied will likely become more difficult to detect and show a shorter length after MSIP. Some cracks disappear completely after MSIP, even in a relatively easy-to-inspect material such as the titanium-stabilized stainless steel inspected during this study. Cracks are not healed by the MSIP process as the metal does not re-bond, and a crack may in fact have a higher growth rate if it exists in the tensile region caused by MSIP."

The ASME has issued ASME Code Case N-770, which has provisions to accept post-MSIP UT examinations for these particular nozzles if supplemented by ET.

The Code Case specifies that the ET examination meet ASME Code Section XI, Appendix IV. The licensees vendor provided a memorandum, WDI-TJ-1045, dated March 2010, which discussed how the ET examination performed met the intent of Appendix IV of Section XI. However, the inspectors noted deviations

from Appendix IV with respect to the use of a +Point probe, demonstration flaw sizes, and the use of an aluminum calibration standard.

However, these activities are governed by an industry initiative and MRP-139 does not require a pre-MSIP examination of these welds. In addition, use of the Code Case is not required by NRC regulations. The inspector discussed this outcome with pertinent NRC Office of Nuclear Reactor Regulation staff, who routinely interact with industry representatives with respect to MRP-139, for their possible consideration in industry discussions.

e. For the Inservice Inspection Program:

Has the licensee prepared an MRP-139 Inservice Inspection Program? If not, briefly summarize the licensees basis for not having a documented program and when the licensee plans to complete preparation of the program.

This program review was previously completed by the NRC (reference NRC Report 05000315/2008003; 05000316/2008003).

In the MRP-139 Inservice Inspection Program, are the welds appropriately categorized in accordance with MRP-139? If any welds are not appropriately categorized, briefly explain the discrepancies.

Yes. For the hot leg and cold leg nozzle DM welds after MSIP, no cracking was detected; therefore they were placed into the inspection Category C in accordance with MRP-139. However, the inspectors could not conclude that Category C (a mitigated non-cracked inspection category) was appropriate as discussed in Item d.3 above even though the CL nozzle DMBWs met the MRP-139 requirements to be placed into this inspection category.

In the MRP-139 Inservice Inspection Program, are the inservice inspection frequencies, which may differ between the first and second intervals after the MRP-139 baseline inspection, consistent with the inservice inspections frequencies called for by MRP-139?

This program review was previously completed by the NRC (reference NRC Report 05000315/2008003; 05000316/2008003).

If any welds are categorized as H or I, briefly explain the licensees basis of the categorization and the licensees plans for addressing potential PWSCC.

This program review was previously completed by the NRC (reference NRC Report 05000315/2008003; 05000316/2008003).

If the licensee is planning to take deviations from the inservice inspection requirements of MRP-139, what are the deviations and what are the general bases for the deviations? Was the NEI 03-08 process for filing deviations followed?

Yes. The licensee was required by MRP-139 to complete a baseline examination for the Unit 1 hot leg DMBWs prior to the current refueling outage, but elected to not perform this baseline examination until the current outage. The licensee basis for this deviation is discussed in Item A.2 above and the licensee followed the NEI 03-08 process for this deviation.

c. Findings

c.1 Construction Code Requirements For Bending Not applied to MSIP of RCS Pipe

Introduction:

The inspectors identified an unresolved item (URI) related to the licensees decision to not apply the reactor coolant system construction Code requirements for bending/forming to the MSIP process used on the RCS HL and CL nozzles.

Description:

On March 5, 2010, the licensee completed a 50.59 Applicability determination (2010-0062) for EC-0000048752 MSIP for Reactor Pressure Vessel Hot and Cold Leg Nozzle Dissimilar Metal Welds. In this document, the licensee concluded that MSIP was a maintenance activity, which restored the applicable system, structure, or component to the as-designed condition. The RV inlet nozzles have a 27.5-inch inside diameter and contained a DM weld (Inconel 82/182), which joins the nozzle to a stainless steel safe-end that is welded to a cast stainless steel RCS pipe elbow. The RV outlet nozzles have a 29-inch inside diameter and contained a DM weld (Inconel 82/182), which joins the nozzle to a stainless steel safe-end that is welded to a centrifugally cast stainless steel pipe. From March 15 - 17, 2010, the licensee applied the MSIP process to the HL piping adjacent to the HL nozzle DM welds and on the CL pipe elbows adjacent to the nozzle DM welds. The MSIP process applied a radial pressure to permanently reduce the inside and outside diameter of the RCS piping by approximately 1/2 inch. This pipe forming operation, results in a compressive residual stress at the nearby DM nozzle welds which reduces the weld susceptibility to PWSCC.

On March 10, 2010, the inspectors identified that the licensee had not considered and hence not implemented the RCS construction Code requirements for bending or forming pipe. The RCS piping construction Code was (USAS B31.1 1967 Edition) identified in the UFSAR, Section 4.1.6, Codes and Standards. Article 129, Bending and Forming, of the B31.1 Code contained requirements for post bending examinations and heat treatment for stress relief. Specifically, Article 129.1 stated Pipe may be bent to any radius which will result in a bend surface free of cracks, as determined by a method of inspection specified in the design, and substantially free of buckles. And Article 129.3.3 stated Cold Bending and forming of carbon steel having a wall thickness of 1/4 inch and heavier, and all ferritic alloy pipe in nominal pipe sizes of 4 inches and larger or 1/2 inch wall thickness or heavier, shall require a stress relieving treatment. The licensee did not perform inspections (PT of external and internal surfaces) in accordance with the applicable pipe and elbow design specifications following bending to verify that the surfaces were free of cracks or buckles. The licensee also did not perform a stress relief treatment for the piping areas subject to bending/forming.

The licensee provided a white paper, AEP-10-49, dated March 19, 2010, to support their decision to not apply these requirements. The summary is provided below:

Applicable construction Codes for vessels and piping were reviewed in order to address the question of whether there are any requirements that would preclude the use of MSIP. The question was raised because of a concern whether a potential compliance issue with the original construction Code might be raised by application of MSIP. There were no rules found that would categorize MSIP as a bending or forming process, as described by the applicable Codes.

Even if the argument is made that MSIP is a forming operation, of sorts, the Code rules exempt the affected materials from any required post-forming heat treatment and retesting of mechanical properties. The piping and safe-end materials are exempt from post-forming heat treatment by the piping Code.

They are also exempt in the vessel Code because they are exempt from impact test requirements. This exemption also eliminates the need for qualification of forming operations on austenitic stainless steel and non-ferrous materials. There are no additional Code requirements for re-examination of materials formed during fabrication. The ASME Section III rules for time of examination of piping, tubular products and fittings, which apply to the piping and safe-end, only require examination to be performed after the final heat treatment required by the material specification. No other requirements impose a re-examination of materials after fabrication operations. Strains imparted to the safe-end and weld region are in the austenitic stainless steel or non-ferrous nickel base weld metal of the weldment being mitigated. These materials are exempt from post-forming heat treatment requirements in the applicable piping and vessel Codes of construction.

This issue is a URI pending completion of NRC reviews to determine the applicability of the construction code requirements for the MSIP process (URI 05000315/2010002-03; Construction Code Requirements For Bending Not applied to MSIP of RCS Pipe).

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 21, 2010, the inspectors presented the inspection results to Mr. L. Weber, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

The results of the licensed operator requalification training program inspection with Mr. L. Weber, Site Vice President, on January 29, 2010;

The licensed operator requalification training biennial written examination and annual operating test results with Mr. B. Evans, Operations Training Manager, via telephone on February 17, 2010;

Radiation monitoring instrumentation protective equipment and the close-out of the licensee-identified violations were discussed with Mr. L. Weber, Site Vice President on January 29, 2010.

The results of the Radiological Hazard Assessment and Exposure Controls and the Occupational ALARA Planning and Controls program inspection with Mr. L. Weber, Site Vice President, on March 12, 2010.

The results of the inservice inspection with Mr. R. Hruby, Site Support Services Vice President, and other members of the licensee staff on March 23, 2010.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee and are a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

Technical Requirements Manual 8.7.10, Fire Rated Assemblies, states that all fire rated assemblies separating safe shutdown fire areas and associated penetration sealing devices shall be operable at all times or a fire watch shall patrol the affected area once per hour. Contrary to the above, on January 29, 2010, two auxiliary building freight elevator fire doors, which separated safe shutdown fire areas, were found propped open on the 573 and 650 elevations during the licensees daily fire door inspection. Fire protection was not previously notified of this condition. Consequently, an hourly fire watch patrol was not established until approximately 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months after the doors were initially propped open. This incident was documented in the licensees corrective action program as AR 00864154. Immediate corrective actions included adding the doors to the hourly fire watch tour. This violation was of very low safety significance because the violation does not affect the ability to reach and maintain hot shutdown conditions.

Technical Specification 5.4.1 requires that written procedures be established, implemented, and maintained for activities provided in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Procedures specified in Regulatory Guide 1.33 include radiation protection procedures for access control into radiological areas which are provided by licensee procedure PMP-6010-RPP-003, "High, Locked High and Very High Radiation Areas Access,"

Revision 18. Section 3.7 of that procedure requires that high radiation areas be locked unless being accessed by workers and the workers verify the gate/door/ladder locks were locked upon exiting the area. Contrary to this requirement, between June 10 & 11, 2007, two high radiation areas were not locked and secured on the Unit 1 and Unit 2 letdown heat exchanger rooms.

The problem was discovered by RP staff on June 11, 2007, during routine surveillance walkdowns. The licensees follow-up investigation found that an RP technician performing a routine survey of the rooms on June 10, 2007, failed to physically challenge the gates when the individual exited the areas. The investigation found that no other personnel entered either room after the RP technician completed the surveys. The licensee concluded that the RP technician who left the gates unlocked relied on the automatic closure mechanism to secure the gates behind him. One gate was not fully latched and the other was partially blocked by a chain attached to the gate. The issue was documented in the licensee's corrective action program as AR 00814626.

Corrective actions included enhanced oversight of high radiation area egress controls by RP supervision and improved postings on doors/gates. The finding was determined to be of very low safety significance because it was not an ALARA planning issue, there was no overexposure nor potential for an overexposure, and the licensee's ability to assess worker dose was not compromised.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Brown, Director of Chemistry, Environmental and Radiation Protection

M. Carlson, Engineering Director

R. Ebright, Director, Training

B. Evans, Operations Training Manager

D. Foster, Environmental General Supervisor

J. Gebbie, Plant Manager

R, Hall, ISI Program Engineer

J. Harris, Radiation Protection Supervisor

R. Hruby, Site Support Services Vice President

C. Hutchinson, Manager, Emergency Preparedness and Security

C. Lane, Engineering Manager

C. Moeller, Radiation Protection Manager

J. Newmiller, Licensing Activities Coordinator

J. Nimtz, Senior Licensing Activities Coordinator

S. Partin, Maintenance Manager

R. Pickard, Engineering Program Supervisor

D. Raye, Radiation Protection Instrument Supervisor

J. Ross, Operations Director

T. Vriezema, Simulator Supervisor

D. Walton, Emergency Preparedness Coordinator

L. Weber, Site Vice President

R. West, Licensing Activity Coordinator

J. Winnier, RMS System Engineer

C. Wohlgamuth, Environmental Supervisor, Radiological Environmental Monitoring Program

Coordinator

Nuclear Regulatory Commission

Billy

C. Dickson, Plant Support Team Branch Chief, DRS/RIII

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000315/2010002-01; FIN Failure to Implement Plant Procedures for Using a Mobile

05000316/2010002-01, Crane (4OA2.3)

05000315/2010002-02 NCV Failure to Implement Corrective Actions in a Timely and

05000316/2010002-02 Effective Manner (4OA2.4)

05000315/2010002-03 URI Construction Code Requirements For Bending Not applied to MSIP of RCS Pipe (4OA5.3)

Attachment

Closed

05000315/2010002-01; FIN Failure to Implement Plant Procedures for Using a Mobile

05000316/2010002-01, Crane (4OA2.3)

05000315/2010002-02 NCV Failure to Implement Corrective Actions in a Timely and

05000316/2010002-02 Effective Manner (4OA2.4)

Discussed

NONE Attachment

LIST OF DOCUMENTS REVIEWED