IR 05000461/2010004

IR 05000461-10-004; on 07/01/10 - 09/30/10; Clinton Power Station, Unit 1, NRC Integrated Inspection Report

ML103020027
Person / Time
Site:	Clinton
Issue date:	10/28/2010
From:	Ring M NRC/RGN-III/DRP/B1
To:	Pacilio M Exelon Nuclear, Exelon Generation Co
References
IR-10-004
Download: ML103020027 (52)

Text

October 28, 2010

SUBJECT:

CLINTON POWER STATION INTEGRATED INSPECTION REPORT 05000461/2010-004

Dear Mr. Pacilio:

On September 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Clinton Power Station. The enclosed report documents the results of this inspection, which were discussed on October 7, 2010, with Mr. F. Kearney, and other members of your staff.

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

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

Based on the results of this inspection, no findings of significance were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (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/

Mark A. Ring, Chief Branch 1 Division of Reactor Projects

Docket No. 50-461 License No. NPF-62

Enclosure:

Inspection Report 05000461/2010-004; w/Attachment: Supplemental Information

REGION III==

Docket No:

50-461 License No:

NPF-62 Report No:

05000461/2010-004 Licensee:

Exelon Generation Company, LLC Facility:

Clinton Power Station Location:

Clinton, IL Dates:

July 1, through September 30, 2010 Inspectors:

B. Kemker, Senior Resident Inspector

D. Lords, Resident Inspector

J. Bozga, Reactor Inspector

J. Draper, Reactor Engineer

D. Reeser, Operations Engineer

A. Scarbeary, Reactor Engineer

John Cassidy, Senior Health Physicist S. Mischke, Resident Inspector, Illinois Emergency Management Agency

Approved by:

M. Ring, Chief Branch 1 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000461/2010-004, 07/01/10 - 09/30/10; Clinton Power Station, Unit 1; Integrated

Inspection Report.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649,

Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings No findings of significance were identified.

Licensee-Identified Violations

No findings of significance were identified.

REPORT DETAILS

Summary of Plant Status

Unit 1 was operated at or near full power during the inspection period with the following exceptions.

On August 13, 2010, the licensee reduced power to about 95 percent due to condensate inlet temperature reaching 122 degrees Fahrenheit. The unit was returned to full power the following day after inlet temperature had decreased.

On August 30, 2010, the licensee reduced power to about 91.3 percent to insert control rods 16-25 and 44-45 and perform Hydraulic Control Unit (HCU) maintenance. The unit was returned to full power later the same day upon completion of testing.

On September 4, 2010, the licensee reduced power to about 80 percent to perform control rod sequence exchange, scram time testing, and main turbine control/intermediate valve and main steam isolation valve testing. The unit was returned to full power later the same day upon completion of testing.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness to Cope with External Flooding

a. Inspection Scope

The inspectors reviewed flood protection barriers and procedures for coping with external flooding at the plant. The Clinton Power Station has limited susceptibility to external flooding as described in Section 3.4.1.1 of the Updated Final Safety Analysis Report (UFSAR) and Section 5.2 of the Individual Plant Examination for External Events Report. The inspectors reviewed Clinton Power Station (CPS) 4303.02, Abnormal Lake Level, Revision 10, to assess the adequacy of the licensee response to external flooding conditions.

The inspectors conducted a walkdown of the Lake Screen House, including the shutdown service water pump rooms. The inspectors assessed the condition of water tight door seals; the sealing of equipment floor plugs, electrical conduits, holes or penetrations in floors and walls between the pump rooms; and the condition of room floor drains, sumps, and sump pumps.

In addition, the inspectors performed a walkdown of the Clinton Lake Dam with the cognizant engineer to inspect for any potential degraded conditions such as a build-up of debris at the spillways and ogee; a build-up of trees and shrubs on the downstream side of the dam that could possibly affect drainage; a build-up of sediment and debris on the rip-raps that could possibly cause deterioration of the retaining wall; and general material condition of signs, buoys, and lights. The inspectors also performed a general review and discussion of the Clinton Lake Dam Emergency Action Plan with the cognizant engineer, including flood alert levels, associated actions, and emergency notification requirements.

This inspection constituted one external flooding readiness inspection sample as defined in Inspection Procedure (IP) 71111.01.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Control Room Ventilation System Train A during maintenance on Control Room Ventilation System Train B;

• Standby Liquid Control System; and

• Division 3 Battery and Direct Current (DC) Power Distribution - single train risk-significant system following battery charger restoration from maintenance.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones. The inspectors reviewed operating procedures, system diagrams, Technical Specification (TS) requirements, and the impact of ongoing work activities on redundant trains of equipment. The inspectors verified that conditions did not exist 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 were aligned correctly and available as necessary.

In addition, the inspectors verified that equipment alignment problems were entered into the licensees corrective action program (CAP) with the appropriate characterization and significance. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

This inspection constituted three partial system walkdown inspection samples as defined in IP 71111.04.

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 Containment Combustible Gas Control 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 lineups, 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 work orders 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.

This inspection constituted one complete system walkdown sample as defined in IP 71111.04.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors performed fire protection tours in the following plant areas:

• Fire Zone CB-3c & CB-3g, Non-Safety Battery Rooms (West & East) -

Elevation 781'0";

• Fire Zone F-1h, Valve Room - Elevation 712'0";

• Fire Zone M-2b, Division 2 Shutdown Service Water Pump Room - Elevation 699'0"; and

• Fire Zone T-1m, Turbine Deck - Elevation 800'0".

The inspectors verified that transient combustibles and ignition sources were appropriately controlled and assessed the material condition of fire suppression systems, manual firefighting equipment, smoke detection systems, fire barriers and emergency lighting units. 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; that the licensees fire plan was in alignment with actual conditions; and that fire doors, dampers, and penetration seals appeared to be in satisfactory condition.

In addition, the inspectors verified that fire protection related problems were entered into the licensees CAP with the appropriate characterization and significance.

Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

This inspection constituted four quarterly fire protection inspection samples as defined in IP 71111.05AQ.

b. Findings

No findings of significance were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

During an announced drill on July 14, 2010, associated with the Control Building 7810 Elevation Insulation Shop Area, the inspectors assessed the timeliness of the fire brigade in arriving at the scene, the firefighting equipment brought to the scene, the donning of fire protective clothing, the effectiveness of communications, and the exercise of command and control by the fire brigade leader. The inspectors also assessed the acceptance criteria for the drill objectives, the rigor and thoroughness of the post-drill critique, and verified that fire protection drill issues were being entered into the licensee's CAP with the appropriate characterization and significance.

This inspection constituted one annual fire protection drill inspection sample as defined in IP 71111.05AQ.

b. Findings

No findings of significance were identified.

1R06 Flooding Protection Measures

.1 Internal Flooding

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. 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 fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP 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:

• Diesel Generator Rooms; and

• Turbine Building Main Condenser Pits.

This inspection constituted one internal flooding inspection sample as defined in IP 71111.06.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed licensed operators during simulator training on August 11, 2010. The inspectors assessed the operators response to the simulated events focusing on alarm response, command and control of crew activities, communication practices, procedural adherence, and implementation of Emergency Plan requirements. The inspectors also observed the post-training critique to assess the ability of licensee evaluators and operating crews to self-identify performance deficiencies. The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements.

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

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated the licensees handling of selected degraded performance issues involving the following risk-significant structures, systems, and components (SSCs):

• Motor Operated Valves;

• Turbine Building Heating and Ventilation System; and

• Circulating Water System.

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the SSC performance or condition problems in terms of:

• Appropriate work practices;

• Identifying and addressing common cause failures;

• Scoping of SSCs in accordance with 10 CFR 50.65(b);

• Characterizing SSC reliability issues;

• Tracking SSC unavailability;

• Trending key parameters (condition monitoring);

• 10 CFR 50.65(a)(1) or (a)(2) classification and reclassification; and

• Appropriateness of performance criteria for SSC functions classified (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSC functions classified (a)(1).

In addition, the inspectors verified that problems associated with the effectiveness of plant maintenance were entered into the licensees CAP with the appropriate characterization and significance. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

The inspection constituted three maintenance effectiveness inspection samples as defined in IP 71111.12.

a. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensees evaluation and management of plant risk for 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:

• Planned maintenance on August 10th and 11th on Instrument Air Containment Isolation Valve 1IA012B;

• Emergent maintenance during the week of August 29th to address Division 1 Self Test System (STS) failures;

• Planned maintenance and testing during the week of September 13th on Residual Heat Removal System Trains 'B' and 'C';

• Emergent maintenance during the week of September 20th; on the Division 2 Diesel Generator and

• Planned Maintenance during the week of September 27th on the Division 1 Diesel Generator.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each of the above activities, the inspectors reviewed the scope of maintenance work in the plants daily schedule, reviewed Control Room logs, verified that plant risk assessments were completed as required by 10 CFR 50.65(a)(4) prior to commencing maintenance activities, discussed the results of the assessment with the licensees Probabilistic Risk Analyst and/or Shift Technical Advisor, and verified that plant conditions were consistent with the risk assessment assumptions. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify that risk analysis assumptions were valid, that redundant safety-related plant equipment necessary to minimize risk was available for use, and that applicable requirements were met.

In addition, the inspectors verified that maintenance risk related problems were entered into the licensees CAP with the appropriate significance characterization. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

This inspection constituted five maintenance risk assessment inspection samples as defined in IP 71111.13.

a. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• AR 01021972, "C1R12: Vacuum Breaker 1SX303B IST [Inservice Testing]

Failed Closing Test";

• AR 01093674, Actions Needed by OPS to Declare H2 System Operable;

• AR 01109546, Division 3 Battery Room is 68F and is an OOS Round;

• AR 00950308, "Non-Safety O-Rings Installed in Safety-Related / EQ

[Environmental Qualification] Valves"; and

• AR 01105478, "1G33F039 Spurious Actuation.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors verified that the conditions did not render the associated equipment inoperable or result in an unrecognized increase in plant risk. When applicable, the inspectors verified that the licensee appropriately applied TS limitations, appropriately returned the affected equipment to an operable status, and reviewed the licensees evaluation of the issues with respect to the regulatory reporting requirements. 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.

In addition, the inspectors verified that problems related to the operability of safety-related plant equipment were entered into the licensees CAP with the appropriate characterization and significance. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

This inspection constituted five operability evaluation inspection samples as defined in IP 71111.15.

b. Findings

(1) Apparent Interaction Between Non-Safety Related and Safety-Related Portions of the Nuclear System Protection System Causing Spurious Component Actuations Introduction The inspectors initiated an Unresolved Item (URI) pending further evaluation of a potential design control issue involving apparent interaction between non-safety related and safety-related portions of the Nuclear System Protection System (NSPS) causing spurious component actuations.

Discussion The licensee has recently experienced problems stemming from degrading power supplies in its NSPS STS. A reactor water cleanup (RT) system isolation occurred on August 24, 2010, and appears to have been caused by spurious valve actuations due to a degraded power supply on Division 1 STS. The STS is an automatic, on-line self-test system that pulses all the NSPS circuit cards to detect hardware failures. Each of the four divisional NSPS cabinets in the Control Room contains a microprocessor based self-test controller in whose memory are stored sets of input stimuli test patterns and expected output results. For each set of input patterns, the expected and actual outputs are compared. Any discrepancies are annunciated. These sets of test patterns comprehensively test all essential circuits and wiring within and between the NSPS cabinets, such that STS is able to determine the exact location of any failures in the safety-related hardware. The STS was designed to not influence the safety-related functions of the NSPS cards. According to Section 7.2.1.1.4.8 of the UFSAR, the STS is classified as safety associated, and its equipment is designed to meet the applicable IEEE and Regulatory Guides which apply to that classification. It was designed to meet the separation requirements of Regulatory Guide 1.75 and interfaces are supposedly by means of high impedance isolation devices to ensure that failures in the STS will not propagate to the safety equipment. However, it appears that a faulted STS can possibly affect the output of the NSPS load driver cards. In other words, failures in a non-safety related portion of the NSPS are able to cause spurious actuations of safety-related components.

In March 2010, CPS had a drywell cooling containment isolation event (EN#45901).

Like the event last March, the licensee initially thought that the spurious RT valve actuations were due to a bad NSPS load driver circuit card. The only spare card available was the exact same load driver card that had apparently failed in March 2010 and was refurbished by the vendor. However, neither the vendors testing nor the licensees on-site testing found anything wrong with that circuit card. The licensee replaced the load driver card suspected of causing the RT system isolation with the spare card. The licensee tested the removed card and again there was nothing found wrong with the card. The licensee then suspected that something else was the cause of the problem. The licensee subsequently found that the 5VDC power supply for the Division 1 STS had an output of about 3.1VDC and the ripple and noise were also excessive at about 1.4 Volts Alternating Current (VAC) (2,000% the acceptable maximum value). After some additional spurious valve movements (i.e., a reactor core isolation cooling (RCIC) system recirculation valve and a low pressure coolant injection system valve), the licensee powered down the Division 1 STS 5VDC power supply and installed a temporary modification to parallel a new 5VDC power supply to see if conditions improved. There have been no additional spurious valve actuations since then. The licensee then began monitoring the power supply voltages for all four NSPS divisions and found concerns with the 5VDC power supply for the Division 2 STS and it was then powered down. The licensee installed another temporary modification to parallel a new power supply to the Division 2 STS.

At the end of this inspection period, the licensee was continuing to investigate this problem to identify appropriate corrective actions, consulting with the vendor, monitoring the STS power supplies, procuring new power supplies, and making plans to replace power supplies during the next forced or refueling outage. The licensee is evaluating this issue under AR 01105478. It would appear that the March 2010 drywell cooling containment isolation event was also related to this problem. The licensee wrote AR 01108387 to reevaluate the March 2010 event.

The inspectors discussed the apparent interaction between non-safety related and safety-related portions of the NSPS causing spurious component actuations with the licensee and questioned the adequacy of the design with respect to the applicable design requirements for separation. This issue is considered to be an URI pending additional review by the licensee and the inspectors (URI 05000461/2010004-01, Apparent Interaction Between Non-Safety Related and Safety-Related Portions of the NSPS Causing Spurious Component Actuations).

1R18 Plant Modifications

.1 Temporary Modifications

a. Inspection Scope

The inspectors reviewed the following temporary plant modifications:

• Engineering Change (EC) 380630, Provide Temporary Air Supply For 1N66F016A To Support Maintenance Of Valve I/P 1N66K001A,; and

• EC 381213, Temporary 5VDC Power Supply to Div 1 Self Test in 1H13-P661 Bay B.

The inspectors reviewed the temporary modifications and the associated 10 CFR 50.59 screening/evaluations against applicable system design basis documents, including the UFSAR and the TS to verify whether applicable design basis requirements were satisfied. The inspectors reviewed the Control Room logs and interviewed engineering and operations department personnel to understand the impact that implementation of the temporary modifications had on operability and availability of the affected plant SSCs.

The inspectors also reviewed a sample of action requests pertaining to temporary modifications to verify that problems were entered into the licensees CAP with the appropriate significance characterization and that corrective actions were appropriate.

This inspection constituted two temporary modification inspection samples as defined in IP 71111.18.

a. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• WO 01211045-01, "Replace Fire Pump 'A' Battery Charger Regulator Circuit Boards";

• WO 01279637-02, "PMT [Post-Maintenance Test] Fuel Pool Cooling Pump";

• WO 01011258-06, Operations PMT 1SX185A; and

• WO 01367024-02, Stroke Combustible Gas Control System Compressor 1A Suction Valve 1HG009A.

The inspectors reviewed the scope of the work performed and evaluated the adequacy of the specified post-maintenance testing. The inspectors verified that the post-maintenance testing was performed in accordance with approved procedures; that the procedures contained clear acceptance criteria, which demonstrated operational readiness and that the acceptance criteria was met; that appropriate test instrumentation was used; that the equipment was returned to its operational status following testing; and, that the test documentation was properly evaluated.

In addition, the inspectors reviewed CAP documents associated with post-maintenance testing to verify that identified problems were entered into the licensees CAP with the appropriate characterization. Selected action requests were reviewed to verify that the corrective actions were appropriate and implemented as scheduled.

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

Findings No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage Activities-Crane and Heavy Lift Inspection

a. Inspection Scope

(Closed) Unresolved Item 05000346/2009004-04 Reactor Pressure Vessel (RPV) Head Strongback, Dryer/Separator Strongback and RPV Head Lifting Lugs Did Not Demonstrate Single Failure Proof Requirements of NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, Section 5.1.6 During the 2009 crane and heavy lift inspection, the inspectors indentified an unresolved item (URI) concerning whether the design of the RPV head strongback, dryer/separator, strongback and RPV head lifting lugs was in conformance with the licensing and design basis for single failure proof requirements of NUREG-0612, Section 5.1.6. Specifically, these components did not meet design factors of safety versus yield and ultimate strengths consistent with the guidelines of NUREG-0612, Section 5.1.6. As a result, the inspectors identified several licensing basis excerpts that implied that the RPV head strongback, dryer/separator strongback and RPV head lifting lugs were in conformance with the single failure proof requirements of NUREG-0612, Section 5.1.6.

To resolve this concern, Region III inspectors generated a Task Interface Agreement (TIA) to obtain an official staff position from the Office of Nuclear Reactor Regulation (NRR) to determine the licensing basis requirements with respect to meeting single failure proof design criteria of NUREG-0612, Section 5.1.6 for the reactor pressure vessel head strongback, the dryer/separator strongback, and the reactor pressure vessel head lifting lugs at the Clinton Power Station.

The NRR staffs position was documented in TIA 2010-004, Final Response to Task Interface Agreement Single-Failure-Proof Design for Reactor Pressure Vessel Head Strongback, Dryer/Separator Strongback, and Reactor Pressure Vessel Head Lifting Lugs at Clinton Power Station, dated August 27, 2010, (ADAMS ML101890187).

The NRR staff reviewed applicable licensing basis information including licensee submittals and NRC safety evaluation reports, and concluded that licensee references to providing a safety factor of 10 for these components were either vague (too general in nature) or related to a future action that was superseded by subsequent correspondence. In addition, the related NRC safety evaluation report was not specific enough to conclude a commitment to the safety factors described in Section 5.1.6 of NUREG-0612. As a result, NRR concluded that the licensing basis of the special lifting devices is adequately described in the licensees updated safety analysis report.

The NRR staff found that the existing licensing basis of the special lifting devices and associated interfacing lift points provides a level of safety reasonably consistent with a low probability of handling system failure. The special lifting devices and interfacing lift points were constructed to industry standards and designed with reasonably large design margins. In addition, the special lifting devices were subject to proof load tests. As documented in NUREG-1774, A Survey of Crane Operating Experience at U.S. Nuclear Power Plants from 1968 through 2002, poor heavy loads program implementation and human performance errors caused most load drop events, and no load drop events resulted from structural failure of special lifting devices. Therefore, the NRR staff considers the existing licensing and design basis for the special lifting devices at CPS appropriate and acceptable.

Based on the review of the TIA 2010-004 response, the inspectors did not identify a performance deficiency or violation of NRC requirements, and this unresolved item is closed.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• CPS 9051.01, HPCS [High Pressure Core Spray System] Pump and Water Leg Pump Operability Test (IST, TI 2515/177 effort);

• CPS 9072.01, "Steam Bypass Valve Tests";

• CPS 2700.12, "Division 1 SX System Flow Balance Verification"; and

• CPS 9054.01C002, "RCIC High Pressure Operability Checks (IST).

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 USAR, 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 inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers 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.

In addition, the inspectors verified that surveillance testing problems were entered into the licensees CAP with the appropriate characterization and significance. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

Also, additional activities were performed during the review of CPS 9051.01, HPCS [High Pressure Core Spray System] Pump and Water Leg Pump Operability Test that were associated with TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems.

This activity is described in bullet

.2 of this section.

This inspection constituted two in-service tests and two routine surveillance tests, for a total of four inspection samples as defined in IP 71111.22.

b. Findings

No findings of significance were identified.

.1 Surveillance Testing associated with Temporary Instruction (TI) 2515/177,

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

a. Inspection Scope

When reviewing CPS 9051.01, HPCS [High Pressure Core Spray System] Pump and Water Leg Pump Operability Test the inspectors verified that the procedure was acceptable for High Pressure Core Spray.

The inspectors reviewed the CPS procedure used for conducting surveillances and determination of void volumes to ensure that the void criteria was satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.a). Also, the inspectors reviewed the procedure used for filling and venting following conditions which may have introduced voids into the subject systems to verify that the procedures acceptably addressed testing for such voids and provided acceptable processes for their reduction or elimination (TI 2515/177, Section 04.03.b). Specifically, the inspectors verified that:

• Gas intrusion prevention, refill, venting, monitoring, trending, evaluation, and void correction activities were acceptably controlled by approved operating procedures (TI 2515/177, Section 04.03.c.1).

• Procedure ensured the system did not contain voids that may jeopardize operability (TI 2515/177, Section 04.03.c.2).

• Procedure established that void criteria were satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.c.3).

• The licensee entered changes into the CAP as needed to ensure acceptable response to issues. In addition, the inspectors confirmed that a clear schedule for completion is included for CAP entries that have not been completed (TI 2515/177, Section 04.03.c.5).

• Procedure included independent verification that critical steps were completed (TI 2515/177, Section 04.03.c.6).

The inspectors verified the following with respect to surveillance and void detection:

• Specified surveillance frequency was consistent with TS Surveillance Requirement (SR) requirements (TI 2515/177, Section 04.03.d.1).

• Surveillance frequencies were stated or, when conducted more often than required by TSs, the process for their determination was described (TI 2515/177, Section 04.03.d.2).

• Surveillance method was acceptably established to achieve the needed accuracy (TI 2515/177, Section 04.03.d.3).

• Surveillance procedure included up-to-date acceptance criteria (TI 2515/177, Section 04.03.d.4).

• Procedure included effective follow-up actions when acceptance criteria are exceeded or when trending indicates that criteria may be approached before the next scheduled surveillance (TI 2515/177, Section 04.03.d.5).

• Measured void volume uncertainty was considered when comparing test data to acceptance criteria (TI 2515/177, Section 04.03.d.6).

• Venting procedure and practice utilized criteria such as adequate venting durations and observing a steady stream of water (TI 2515/177, Section 04.03.d.7).

• An effective sequencing of void removal steps was followed to ensure that gas does not move into previously filled system volumes (TI 2515/177, Section 04.03.d.8).

• Qualitative void assessment methods included expectations that the void will be significantly less that allowed by acceptance criteria (TI 2515/177, Section 04.03.d.9).

• Venting results were trended periodically to confirm that the systems are sufficiently full of water and that the venting frequencies are adequate. The inspectors also verified that records on the quantity of gas at each location are maintained and trended as a means of preemptively identifying degrading gas accumulations (TI 2515/177, Section 04.03.d.10).

• Surveillances were conducted at any location where a void may form, including high points, dead legs, and locations under closed valves in vertical pipes (TI 2515/177, Section 04.03.d.11).

• The licensee ensured that systems were not pre-conditioned by other procedures that may cause a system to be filled, such as by testing, prior to the void surveillance (TI 2515/177, Section 04.03.d.12).

• Procedure included gas sampling for unexpected void increases if the source of the void is unknown and sampling is needed to assist in determining the source (TI 2515/177, Section 04.03.d.13).

The inspectors verified the following with respect to filling and venting:

• Revisions to fill and vent procedure to address new vents or different venting sequences were acceptably accomplished (TI 2515/177, Section 04.03.e.1).

• Fill and vent procedure provided instructions to modify restoration guidance to address changes in maintenance work scope or to reflect different boundaries from those assumed in the procedure (TI 2515/177, Section 04.03.e.2).

The inspectors verified the following with respect to void control:

• Void removal methods were acceptably addressed by approved procedures (TI 2515/177, Section 04.03.f.1).

• The licensee had reasonably ensured that the High Pressure Core Spray pump is free of damage following a gas-related event in which pump acceptance criteria was exceeded (TI 2515/177, Section 04.03.f.2).

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.

a. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a full scale emergency preparedness drill o July 27, 2010, and the conduct of an off-hours unannounced call-in drill on August 17, 2010, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. This drill was planned to be evaluated and was included in performance indicator data regarding drill and exercise performance. The inspectors observed emergency response operations in the Operations Simulator and Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensees drill critique to compare any inspector-observed weaknesses with those identified by the licensees staff in order to evaluate the critique and to verify whether the licensees staff was properly identifying weaknesses and entering them into the CAP.

This inspection constituted two emergency preparedness drill evaluation inspection samples as defined in IP 71114.06.

b. Findings

No findings of significance were identified.

2RS5 Radiation Monitoring Instrumentation

This inspection constituted one complete sample as defined in IP 71124.05-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the plant Final Safety Analysis Report to identify radiation instruments, associated with monitoring area radiological conditions, which included airborne radioactivity, process streams, effluents, materials/articles, and workers.

Additionally, the inspectors reviewed the instrumentation and the associated Technical Specification requirements for post-accident monitoring instrumentation including instruments used for remote emergency assessment.

The inspectors reviewed a listing 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 reviewed personnel contamination monitors and portal monitors including whole-body counters to detect workers internal contamination. The inspectors reviewed this list to assess whether an adequate number and type of instruments are available to support operations.

The inspectors reviewed licensee and third-party evaluation reports of the radiation monitoring program since the last inspection. These reports were reviewed for insights into the licensees program and to aid in selecting areas for review (smart sampling).

The inspectors reviewed procedures that govern instrument source checks and calibrations, focusing on instruments used for monitoring transient high radiological conditions, including instruments used for underwater surveys. The inspectors reviewed the calibration and source check procedures for adequacy and as an aid to smart sampling.

The inspectors reviewed the area radiation monitor alarm setpoint values and setpoint bases as provided in the Technical Specifications and the Final Safety Analysis Report.

The inspectors reviewed effluent monitor alarm setpoint bases and the calculation methods provided in the offsite dose calculation manual (ODCM).

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down effluent radiation monitoring systems, which included at least one liquid and one airborne system. Focus was placed on flow measurement devices and accessible point-of-discharge liquid and gaseous effluent monitors of the selected systems. The inspectors assessed whether the effluent/process monitor configurations align with ODCM descriptions and observed monitors for degradation and out-of-service tags.

The inspectors selected portable survey instruments that were in use or available for issuance and assessed calibration and source check stickers for currency, instrument material condition, and operability.

The inspectors observed licensee staff performance as the staff demonstrated source checks for various types of portable survey instruments. The inspectors assessed whether high-range instruments are source checked on all appropriate scales.

The inspectors walked down area radiation monitors and continuous air monitors to determine whether they are appropriately positioned relative to the radiation sources or 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 personnel contamination monitors, portal monitors, and small article monitors and evaluated whether the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

b. Findings

No findings were identified.

Process and Effluent Monitors

a. Inspection Scope

The inspectors selected effluent monitor instruments (such as gaseous and liquid) and evaluated whether channel calibration and functional tests were performed consistent with radiological effluent Technical Specifications/ODCM. The inspectors assessed whether:

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

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

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

(d) the licensees channel calibrations encompassed the instruments alarm set-points.

The inspectors assessed whether the effluent monitor alarm setpoints are established as provided in the ODCM and station procedures.

The inspectors evaluated the basis for changes to effluent monitor setpoints to ensure that an adequate justification exists.

b. Findings

No findings were identified.

Laboratory Instrumentation

a. Inspection Scope

The inspectors assessed laboratory analytical instruments used for radiological analyses to determine whether daily performance checks and calibration data indicate that the frequency of the calibrations is adequate and there are no indications of degraded instrument performance.

The inspectors assessed whether appropriate corrective actions are implemented in response to indications of degraded instrument performance.

b. Findings

No findings were identified.

Whole Body Counter

a. Inspection Scope

The inspectors reviewed the methods and sources used to perform whole body count functional checks before daily use of the instrument and assessed whether check sources were appropriate and aligned with the plants isotopic mix.

The inspectors reviewed whole body count calibration records since the last inspection and evaluated whether calibration sources were representative of the plant source term and that appropriate calibration phantoms were used. The inspectors looked for anomalous results or other indications of instrument performance problems.

b. Findings

No findings were identified.

Post-Accident Monitoring Instrumentation

a. Inspection Scope

Inspectors selected drywell and containment high-range monitors and reviewed the calibration documentation since the last inspection.

The inspectors assessed whether an electronic calibration was completed for all range decades above 10 rem/hour and whether at least one decade at or below 10 rem/hour was calibrated using an appropriate radiation source.

The inspectors assessed whether calibration acceptance criteria are reasonable, accounting for the large measuring range, and meeting the intended purpose of the instruments.

The inspectors selected two effluent/process monitors that are relied on by the licensee in its emergency operating procedures as a basis for triggering emergency action levels and subsequent emergency classifications, or to make protective action recommendations during an accident. The inspectors evaluated the adequacy of the calibration and availability of these instruments.

The inspectors reviewed the licensees capability to collect high-range, post-accident iodine effluent samples.

As available, the inspectors observed electronic and radiation calibrations of these instruments to verify conformity with the licensees calibration and test protocols.

b. Findings

No findings were identified.

Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors

a. Inspection Scope

For each type of these instruments used on site, the inspectors assessed whether the alarm setpoint values are reasonable under the circumstances to ensure that licensed material is not released from the site.

The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine whether the licensees methods were consistent with the manufacturers recommendations.

b. Findings

No findings were identified.

Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors

a. Inspection Scope

The inspectors reviewed calibration documentation for at least one of each type of instrument. For portable survey instruments and area radiation monitors, the inspectors reviewed detector measurement geometry and calibration methods and had the licensee demonstrate use of its instrument calibrator.

As available, the inspectors selected portable survey instruments that did not meet acceptance criteria during calibration or source checks to assess whether the licensee had taken appropriate corrective action for instruments found significantly out of calibration (greater than 50 percent). The inspectors evaluated whether the licensee had evaluated the possible consequences of instrument use since the last successful calibration or source check.

b. Findings

No findings were identified.

Instrument Calibrator

a. Inspection Scope

As applicable, the inspectors reviewed the current output values for the licensees portable survey and area radiation monitor instrument calibrator unit(s). The inspectors assessed whether the licensee periodically measures calibrator output over the range of the instruments used through measurements by ion chamber/electrometer.

The inspectors assessed whether the measuring devices have been calibrated by a facility using National Institute of Standards and Technology traceable sources and whether corrective factors for these measuring devices were properly applied by the licensee in its output verification.

b. Findings

No findings were identified.

Calibration and Check Sources

a. Inspection Scope

The inspectors reviewed the licensees Title 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, source term to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

b. Findings

No findings were identified.

.4 Problem Identification and Resolution (02.04)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring instrumentation are being identified by the licensee at an appropriate threshold and are properly addressed for resolution in the licensee CAP. The inspectors assessed whether corrective actions taken by licensee were appropriate.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Review of Submitted Quarterly Data

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the Second Quarter 2010 Performance Indicators for any obvious inconsistencies prior to its public release in accordance with IMC 0608, Performance Indicator Program.

This inspection was not considered to be an inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.2 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors verified the Reactor Coolant System (RCS) Leakage Performance Indicator for Unit 1. The inspectors reviewed the licensees RCS leakage tracking surveillance test data from October 1, 2009, through June 30, 2010, to validate the accuracy of the licensees submittals. The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator and none were identified.

This inspection constituted one RCS Leakage Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.3 Mitigating Systems Performance Index - Emergency Alternating Current (AC)

Power System

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported Mitigating Systems Performance Index (MSPI) - Emergency AC Power System Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, Licensee Event Reports (LERs), and maintenance and test data from July 2009 through June 2010, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

This inspection constituted one MSPI - Emergency AC Power System Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.4 Mitigating Systems Performance Index - High Pressure Injection Systems

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI - High Pressure Injection Systems Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from July 2009 through June 2010, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

This inspection constituted one MSPI - High Pressure Injection System Performance Indicator verification injection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.5 Mitigating Systems Performance Index - Heat Removal System

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI - Heat Removal System Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from July 2009 through June 2010, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

This inspection constitutes one MSPI Heat Removal System Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.6 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI - Residual Heat Removal System Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from July 2009 through June 2010, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

This inspection constitutes one MSPI - Residual Heat Removal System Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.7 Reactor Coolant System Specific Activity

a. Inspection Scope

The inspectors sampled licensee submittals for the Reactor Coolant System (RCS)

Specific Activity performance indicator for the period of July 2009 through August 2010.

The inspectors used Performance Indicator (PI) definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees RCS chemistry samples, Technical Specification requirements, issue reports, event reports, and NRC Integrated Inspection Reports for the period of July 2009 through August 2010 to determine if indicator results were accurately reported. Documents reviewed are listed in the to this report.

This inspection constituted one RCS specific activity sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.8 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences performance indicator for the period of July 2009 through August 2010.

The inspectors used PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods.

The inspectors reviewed electronic dosimetry dose rate, accumulated dose alarm, dose reports, and the dose assignments for any intakes that occurred for selected dates between July 2009 through August 2010 to determine whether indicator results were accurately reported. The inspectors also conducted walkdowns of numerous locked high radiation area and very high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one occupational radiological occurrence sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.9 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent Technical Specification (RETS)/Offsite Dose Calculation Manual (ODCM) Radiological Effluent Occurrences performance indicator for the period of July 2009 through August 2010.

The inspectors used PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods.

The inspectors reviewed the licensees issue report database and selected individual reports generated, since this indicator was last reviewed to identify any potential occurrences of unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between July 2009 through August 2010 to determine if indicator results were accurately reported. The inspectors also assessed whether the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose were appropriate.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RETS/ODCM radiological effluent occurrences sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a.

Inspection As 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. Some minor issues were entered into the licensees CAP as a result of the inspectors observations; however, they are not discussed in this report.

This inspection was not considered to be an inspection sample as defined in IP 71152.

b. Findings

No findings of significance were identified.

.2 Annual In-Depth Review Sample

a. Inspection Scope

The inspectors selected the following action requests for in-depth review:

• AR 01082317, ITS Surveillance Scheduled Within 1 Hour of End of 25%

Overrun;

• AR 00992875,NRC FIN 2009004-02: Ineffective Corrective Actions for 1FC004A Stem/Disc Failure.

The inspectors verified the following attributes during their review of the licensee's corrective actions for the above action requests and other related action requests:

• 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;

• Evaluation and disposition of operability/reportability issues;

• 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.

The inspectors discussed the corrective actions and associated action request evaluations with licensee personnel.

This inspection constituted two annual in-depth review samples as defined in IP 71152.

b. Findings and Observations

(1) Use of the 25% Extension Allowance When Scheduling/Performing TS Surveillances and Local Leak Rate Testing Introduction During routine plant status reviews, the inspectors recognized what appeared to be a relatively large number of TS surveillances and local leak rate testing (LLRT) activities scheduled/performed using the 25% test interval extension allowed by TS Surveillance Requirement (SR) 3.0.2 and the licensees Containment Leakage Rate Testing Program.

The inspectors requested data from the licensee and reviewed it to determine whether the licensees practice of routinely scheduling/performing the testing within the 25%

extension period was in compliance with the applicable regulatory requirements.

Because the inspectors found no clear limitations on the use of the 25% extension in the current licensing basis, no violation of regulatory requirements was identified.

Discussion For TS surveillances, TSSR 3.0.2 states, in part, that the specified frequency for each SR is met if the surveillance is performed within 1.25 times the interval specified in the frequency as measured from the previous performance. That means, for example, that a surveillance test with a specified frequency of 92 days would be met if it is performed within 115 days of the previous performance. According to the TS Bases for SR 3.0.2,

[t]he provisions of SR 3.0.2 are not intended to be used repeatedly merely as an operational convenience to extend surveillance intervals (other than those consistent with refueling intervals) or periodic completion time intervals beyond those specified.

There is a similar provision in Operations Requirements Manual (ORM) 1.3.2 for a 25%

extension of the test interval for ORM surveillances.

In response to the inspectors questions, the licensee provided data for TS and ORM surveillances performed within the 25% extension for the first half of 2010. This included testing during a refueling outage period (January-February 2010). The licensees data showed that 22.8% (412 of 1804) surveillances were performed within the 25%

extension. While reviewing the data, the inspectors noted the licensee included the 7-day frequency and shorter frequency surveillances routinely performed in operator logs, chemistry sampling, and electrician battery checks in the data. By their nature, these surveillances were rarely performed using the 25% extension. Excluding these surveillance activities from the data and focusing on surveillances with frequencies greater than or equal to 30 days, the 22.8% figure would be about 35%.

In response the inspectors questions and concerns raised with the performance of surveillances within the 25% extension period, the licensee wrote AR 01098830 to evaluate the use of the 25% extension for TS and ORM surveillances by performing a common cause evaluation. The inspectors reviewed the licensees common cause evaluation when it was completed. The licensee concluded in its evaluation that analysis of TS and ORM surveillance performance data indicates, that by simple numbers, CPS makes too much use of the surveillance grace period. The licensee reviewed data from 2007 through 2010 and the data for 2007, 2008, and 2009 was similar to 2010. The results ranged from 22.1% to 26.5%. The licensee found a number of common causes involving scheduling practices (e.g., use of a 13-week Cycle Plan, bundling of work, flex work, and resource leveling) and schedule disruptions (e.g., forced outages, late refueling outage preparations, and outage recovery). For instance, the licensee found that every third performance of a monthly surveillance was scheduled using the 25% extension because the standard maintenance 13-week Cycle Plan is broken into two 4-week blocks followed by one 5-week block. Other scheduling practices contributing to use of the 25% extension period included:

1. It was common for a surveillance to be scheduled in the proper work week according

to the Cycle Plan, and to be performed in that week, but after the due date;

2. Quarterly surveillances were being performed using the 25% extension due to

resource leveling and bundling of the testing with other work; and

3. Surveillances were not being performed when they come due, even when the work

week was divisionally compatible (e.g., testing on Division 1 equipment during a Division 1 work week).

Based on the prevalence of surveillance testing performed within the 25% extension period, the inspectors discussed with several of the NRC staff in the Office of Nuclear Reactor Regulation whether the licensee was in compliance with TSSR 3.0.2. Based on the collegial review, the inspectors concluded that while it was certainly questionable whether the licensee was meeting the intent as stated in the TS Bases for the use of the 25% extension, there was no actual limitation stipulated in TSSR 3.0.2. In other words, the licensee was in literal compliance with the requirement.

For containment isolation valve LLRT activities, TSSR 3.6.1.1 requires, in part, that the licensee perform required visual examinations and leakage rate testing in accordance with the Containment Leakage Rate Testing Program. The Containment Leakage Rate Testing Program is described in TS 5.5.13. Technical Specification 5.5.13 requires, in part, the licensee to establish a program for leakage rate testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B.

This program shall be in accordance with the guidelines contained in Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995. In RG 1.163, the NRC approved Nuclear Energy Institute (NEI) 94-01, "Industry Guideline for Implementing Performance-based Option of 10 CFR Part 50, Appendix J,"

Revision 0, as an acceptable method for complying with the provisions of Option B in 10 CFR Part 50, Appendix J. The licensee implemented its Containment Leakage Rate Testing Program using ER-AA-380, "Primary Containment Leakrate Testing Program," Revision 7. ER-AA-380, Step 1.4 states, in part, that the procedure provides the bases for conforming to RG 1.163 by establishing leakage testing intervals based on the criteria in NEI 94-01. ER-AA-380, Step 4.5.2.3 states, in part, that intervals for Type C testing of containment isolation valves may be extended by up to 25% of the test interval, not to exceed 15 months, for refueling outage surveillances only. ER-AA-380, Step 4.5.2.4 further states, in part, that extension of the test interval for non-outage surveillances shall not be used repeatedly. Section 10.1 of NEI 94-01 allows the licensee to extend the Type C testing intervals by 25% (not to exceed 15 months), but states no limitation. Section 11.3 of NEI 94-01, however, specifies with regard to the 25% extension that it may be allowed on a limited basis for scheduling purposes only.

The NRC staff in RG 1.163 took no exception to the 25% extension allowed by NEI 94-01 and stated in the Federal Register notice that promulgated the final rule incorporating the Option B Performance-Based Requirements into Appendix J, that

[b]y allowing the 25% margin in testing frequency requirements, the NRC has provided the flexibility to accommodate longer fuel cycles.

In response to the inspectors questions, the licensee provided performance data for LLRT surveillances performed within the 25% extension for the last 5 years.

The inspectors requested 5 years worth of data since most LLRT activities were performed during refueling outages and many Type C tests have 5-year test frequencies. The licensees data showed that about 35% (174 of 495) of all LLRT surveillances were performed within the 25% extension. While reviewing the data, the inspectors noted that the licensee included LLRT activities (some electrical penetrations and selected refueling frequency tests) that were not allowed to make use of the 25%

extension. These 82 LLRT activities were all reported as performed on the due date.

Including these LLRT activities in the total skewed the data since there was no extension available for them. Excluding these LLRT surveillance activities from the data, the 35%

figure would be about 43%.

The inspectors noted that the LLRT data for Type C testing of containment isolation valves with a 5-year frequency reflected a very high proportion of tests performed within the 25% extension period. RG 1.163 states that the NEI guidance in Section 11.3.2 for selecting extended test intervals greater than 60 months for Type C tested components is not endorsed by the NRC. That limits the maximum test interval for Type C tested components to 5 years. Since CPS Unit 1 is on a 2-year refueling cycle, rather than performing many of the 5-year LLRTs that require shutdown plant conditions early at the 4-year point, the licensee has been scheduling/performing them later at the 6-year point.

While most, but not all, of the 5-year LLRTs require shutdown plant conditions to perform, over the past 5 years 60% (84 of 140) of all 5-year frequency LLRTs were performed within the 25% extension and just over half of those (48 of the 84) were scheduled/performed near the 6-year point.

The inspectors discussed this observation with the licensee. The licensees position was that by limiting the use of the 25% extension to only those valves that have demonstrated by their performance that they are eligible to be on an extended frequency and, by only applying the 25% extension in order to be able to schedule testing when the valves can be tested (i.e., during refueling outages), it has met the intent of the NEI guidance and Appendix J, Option B. The licensees procedure has restricted or in some cases prohibited the use of the 25% extension for non-outage tests.

As with TS surveillance testing performed within the 25% extension period, the inspectors concluded that it was a questionable practice to schedule/perform a large proportion of LLRT activities using the 25% extension period, and in particular to schedule a large number of Type C containment valve tests at the 6-year point.

However, absent any other regulatory guidance, the language in Section 11.3 of NEI 94-01 regarding use of the 25% extension on a limited basis for scheduling purposes only was too ambiguous for the inspectors to conclude that the licensee did not meet the regulatory requirements. Based on reviewing LLRT data over the past 5 years, it would appear that the licensee scheduled testing such that tests were performed on a reasonably staggered basis. In addition, there have not been a large number of test failures, which would indicate that valve testing intervals and preventive maintenance were generally appropriate.

.3 Annual Review of Operator Workarounds

a. Inspection Scope

The inspectors performed an in-depth review of operator workarounds and assessed the cumulative effect of existing workarounds and other operator burdens. The inspectors reviewed operator workarounds, challenges, control room deficiencies, temporary modifications, and lit and disabled annunciators. The inspectors verified that operator workarounds were being identified at an appropriate threshold; that the workarounds did not adversely impact operators ability to implement abnormal and emergency operating procedures; and, that the cumulative effect of operator burdens did not adversely impact mitigating system functions. The inspectors also reviewed action requests to verify that appropriate corrective actions were proposed or implemented in a timely manner commensurate with the significance of the issue.

This inspection constituted one annual operator workaround review inspection sample as defined in IP 71152.

b. Findings and Observations

No findings of significance were identified.

.4 Selected Issue Follow-Up Inspection Associated with Temporary Instruction (TI)

2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems; AR 01091157 Change Generic Letter 2008 Air Void Ultrasonic Test Frequency from Monthly to Quarterly

a. Inspection Scope

and Documentation During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting a decision to change the performance frequency for ultrasonic tests (UT), which the station had committed to performing in response to NRC Generic Letter (GL) 2008-01.

Inspectors observed the UT methodology and actual test performance. Inspectors also observed the usage of test equipment, reviewed the data obtained, and validated the adequacy of the locations chosen for analysis. Inspectors verified that results obtained supported the decision made to reduce this test frequency and that the station maintained compliance with all regulatory commitments provided in response to GL 2008-01. The inspectors verified that the selected CAP entry acceptably addressed the areas of concern associated with the scope of GL 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (TI 2515/177, Section 04.01).

This review constituted one annual in-depth problem identification and resolution sample as defined in IP 71152. In addition, 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.

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

.1 (Closed) LER 05000461/2010-002-01, Excessive Leakage Through Feedwater Isolation

Valve 1B21F032B, Supplement 1 On February 3, 2010, after Unit 1 had entered Mode 2 during plant startup from the C1R12 refueling outage, the licensee identified that the LLRT performed on feedwater containment isolation check valve 1B21F032B had failed the acceptance criterion in TSSR 3.6.1.3.11. Technical Specification Surveillance Requirement 3.6.1.3.11 required that the combined leakage rate for both primary containment feedwater penetrations be less than or equal to 2.0 gallons-per-minute (gpm). The measured leakage rate for the penetration with 1B21F032B was 2.5 gpm. The licensee originally reported this valve test failure in LER 05000461/2010-002-00 as a condition that resulted in the nuclear power plant being in an unanalyzed condition that significantly degraded plant safety in accordance with 10 CFR50.73(b)(3)(ii), and as a condition that could have prevented the fulfillment of the safety function of structures or systems needed to control the release of radioactive material and mitigate the consequences of an accident in accordance with 10 CFR 50.73(a)(2)(v). The performance issues related to this event were discussed in NRC Inspection Report 05000461/2010-003. The inspectors documented a licensee-identified non-cited violation (NCV) of TS 3.6.1.3 for operating with 1E21F032B inoperable as a result of the licensees failure to implement appropriate preventive maintenance and a licensee-identified NCV of 10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, for the licensees failure to provide appropriate quantitative or qualitative acceptance criteria in CPS 9861.05D014, LLRT Data Sheet for 1MC010, Revision 2.

The licensee submitted Supplement 1 to the original LER to revise the reporting requirements to include an operation or condition prohibited by the plants TSs in accordance with 10 CFR 50.73(a)(2)(i)(B) and to include additional information regarding the corrective actions.

Licensee Event Report 05000461/2010-002-01 is closed.

This inspection constituted one event follow-up inspection sample as defined in IP 71153.

.2 (Closed) LER 05000461/2008-003-01, Excessive Leakage Through Feedwater Isolation

Valve 1B21F032A, Supplement 1 On January 28, 2008, an LLRT performed on feedwater primary containment isolation check valve 1B21F032A failed the acceptance criterion in TSSR 3.6.1.3.11. The licensee performed maintenance on the valve and retested it satisfactorily. During the root cause evaluation of an LLRT failure for the opposite train feedwater primary containment isolation check valve (1E21F032B) during the Cycle 12 refueling outage in January 2010, the licensee recognized that an LER was never submitted to report the 1B21F032A test failure two years before. The licensee subsequently reported the 1B21F032A test failure in LER 05000461/2008-003-00 as a condition that resulted in the nuclear power plant being in an unanalyzed condition that significantly degraded plant safety in accordance with 10 CFR50.73(b)(3)(ii) and as a condition that could have prevented the fulfillment of the safety function of structures or systems needed to control the release of radioactive material and mitigate the consequences of an accident in accordance with 10 CFR 50.73(a)(2)(v). The performance issues related to this event were discussed in NRC Inspection Report 05000461/2010-003. The inspectors documented a licensee-identified NCV of 10 CFR 50.73(a)(1) for the licensees failure to submit a required LER within 60 days after discovery of the 1E21F032A LLRT failure and a licensee-identified NCV of TS 3.6.1.3 for operating with 1E21F032A inoperable as a result of the licensees failure to implement appropriate preventive maintenance.

The licensee submitted Supplement 1 to the original LER to revise the reporting requirements to include an operation or condition prohibited by the plants TSs in accordance with 10 CFR 50.73(a)(2)(i)(B) and to include additional information regarding the corrective actions.

Licensee Event Report 05000461/2008-003-01 is closed.

This inspection constituted one event follow-up inspection sample as defined in IP 71153.

4OA5 Other Activities

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

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

As documented in Section 1R22, the inspectors confirmed the acceptability of the described licensees actions. This inspection effort counts towards the completion of TI 2515/177, which will be closed in a later Inspection Report.

.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)

As documented in Section 4OA2, the inspectors confirmed the acceptability of the described licensees actions. This inspection effort counts towards the completion of TI 2515/177, which will be closed in a later Inspection Report.

.3 (Closed) Temporary Instruction 2515/179, Verification of Licensee Responses to NRC

Requirement for Inventories of Materials Tracked in the National Source Tracking System Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

a. Inspection Scope

The inspectors confirmed that the licensee reported the initial inventories of sealed sources pursuant to 10 CFR 20.2207 and verified that the National Source Tracking System database correctly reflected the Category 1 and 2 sealed sources in custody of the licensee. Inspectors interviewed personnel and performed the following:

• Reviewed the licensees source inventory;

• Verified the presence of any Category 1 or 2 sources;

• Reviewed procedures for and evaluated the effectiveness of storage and handling of sources;

• Reviewed documents involving transactions of sources; and

• Assessed the adequacy of licensee maintenance, posting, and labeling of nationally tracked sources.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Resident Inspectors Exit Meeting

The inspectors presented the inspection results to Mr. F. Kearney and other members of the licensees staff at the conclusion of the inspection on October 7, 2010. The licensee acknowledged the findings presented. Proprietary information was examined during this inspection, but is not specifically discussed in this report.

.2 Interim Exit Meeting Summary (IP 71111.20)

On September 14, 2010, the inspector presented the Crane and Heavy Lift inspection results to Mr. F. Pournia, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that licensee several design documents generated by contractors were considered proprietary. It was agreed that all electronic and paper copies of these proprietary documents would be shredded.

.3 Interim Exit Meeting

On September 24, 2010, the results of an inspection of the radiation monitoring instrumentation program, performance indicator verification, and verification of licensee responses to NRC requirement for inventories of materials tracked in the National Source Tracking System pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207) were discussed with Mr. F. Kearney, and other members of your staff.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Baker, Design Engineering Senior Manager

R. Campbell, RP Technical Specialist

T. Chalmers, Operations Director

J. Cunningham, Security Manager

A. Darelius, EP Manager

J. Domitrovich, Work Management Director

C. Dunn, Shift Operations Superintendent

S. Fatora, Maintenance Director

R. Frantz, Regulatory Assurance

S. Gackstetter, Training Director

W. Hafiz, Design Engineering

G. Hall, Performance Improvement Program Manager

M. Heger, Mechanical/Structural Design Engineering Manager

N. Hightower, Radiological Engineering Manager

M. Kanavos, Plant Manager

D. Kemper, Regulatory Affairs Manager

F. Kearney, Site Vice President

D. Kemper; Regulatory Assurance Manager

S. Lakebrink, Mechanical Design Engineering

K. Leffel, Operations Support Manager

S. ORiley, EP Coordinator

J. Peterson, Regulatory Assurance

F. Pournia, Engineering Director

J. Rappeport, Chemistry Manager

S. Soliman, Senior Chemist

J. Stovall, Radiation Protection Manager

J. Ufert, Fire Marshall

C. VanDenburgh, Nuclear Oversight Manager

LIST OF ITEMS

Opened

05000461/2010004-01 URI Apparent Interaction Between Non-Safety Related and Safety-Related Portions of the NSPS Causing Spurious Component Actuations (Section 1R15.b.(1))

Closed

05000461/2010-002-01 LER Excessive Leakage Through Feedwater Isolation Valve 1B21F032B (Section 4OA3.1)

05000461/2008-003-01 LER Excessive Leakage Through Feedwater Isolation Valve 1B21F032A (Section 4OA3.2)

05000461/2009004-04 URI RPV Head Strongback, Dryer/Separator Strongback and RPV Head Lifting Lugs Did Not Demonstrate Single Failure Proof Requirements of NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, Section 5.1.6

Discussed

None