Text

IR 05000461-12-002, on 01/01/12 - 03/31/12; Clinton Power Station, Unit 1; Maintenance Effectiveness, Identification and Resolution of Problems
	ML12130A048
Person / Time
Site:	Clinton
Issue date:	05/08/2012
From:	Ring M; NRC/RGN-III/DRP/B1
To:	Pacilio M; Exelon Generation Co, Exelon Nuclear
References
	IR-12-002
	Download: ML12130A048 (60)
	v • d • e

UNITED STATES May 8, 2012

SUBJECT:

CLINTON POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000461/2012-002

Dear Mr. Pacilio:

On March 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Clinton Power Station. The enclosed report documents the inspection results, which were discussed on April 19, 2012, with Mr. W. Noll and other members of your staff.

This 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, one NRC-identified finding and one self-revealed finding of very low safety significance were identified. Each of these findings was determined to involve a violation of NRC requirements. Additionally, one licensee-identified violation, which was determined to be of very low safety significance, was reviewed by the inspectors and is listed in this report.

Because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating the above inspector-identified, self-revealed, and licensee-identified violations as non-cited violations (NCVs) consistent with Section 2.3.2 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 Clinton Power Station. In addition, if you disagree with a cross-cutting aspect assignment 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 Clinton Power Station. 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 Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Mark A. Ring, Branch Chief Branch 1 Division of Reactor Projects Docket No. 50-461 License No. NPF-62 cc w/encl: Distribution via ListServe

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket No: 50-461 License No: NPF-62 Report No: 05000461/2012-002 Licensee: Exelon Generation Company, LLC Facility: Clinton Power Station, Unit 1 Location: Clinton, IL Dates: January 1 through March 31, 2012 Inspectors: B. Kemker, Senior Resident Inspector D. Lords, Resident Inspector S. Bell, Health Physicist J. Bozga, Reactor Inspector C. Brown, Reactor Inspector J. Cassidy, Senior Health Physicist R. Orlikowski, Project Engineer D. Szwarc, Reactor Inspector S. Mischke, Resident Inspector, Illinois Emergency Management Agency Approved by: M. Ring, Chief Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000461/2012-002, 01/01/12 - 03/31/12; Clinton Power Station, Unit 1; Maintenance

Effectiveness, Identification and Resolution of Problems.

This report covers a three-month period of inspection by the resident inspectors and announced baseline inspections by regional inspectors. Two Green findings, each of which had an associated non-cited violation, were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. 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

Cornerstone: Initiating Events

Green.

A self-revealed finding of very low safety significance was identified with an associated non-cited violation of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. The licensee failed to incorporate operating experience into its preventive maintenance practices associated with steam bypass system control circuit cards. Specifically, during two operating experience driven initiatives performed by the licensee in 2001 and 2007, and once again on September 24, 2011, the licensee failed to implement any preventive maintenance activity for critical component circuit cards, which resulted in age-related failure and a reactor scram on November 29, 2011. The licensee initiated corrective actions to replace system circuit cards, perform periodic replacement/refurbishment maintenance activities, and trend circuit card performance during routine calibration.

The finding was of more than minor significance because it was sufficiently similar to IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, Example 7(c), in that this violation of 10 CFR 50.65(a)(3) had a consequence such as equipment problems attributable to failure to take industry operating experience into account when practicable. The finding was a licensee performance deficiency of very low safety significance because it: (1) did not contribute to the likelihood of a loss-of-coolant accident initiator, (2) did not contribute to both the likelihood of a reactor scram AND the likelihood that mitigation equipment or functions would not be available, and (3) did not increase the likelihood of a fire or internal/external flooding event. The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, in the area of work control, the licensee did not appropriately coordinate work activities by incorporating actions to plan work activities to support long-term equipment reliability by scheduling maintenance as more preventive than reactive. (IMC 0310 H.3(b)) (Section 4OA2.3.b.2)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a finding of very low safety significance with an associated non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings. The licensee failed to establish an adequate procedure to perform required leak rate testing for the Low Pressure Coolant Injection from Residual

Heat Removal A Check Valve. Specifically, the surveillance test procedure resulted in unacceptable preconditioning of the valve prior to a leak rate test measurement due to improper test sequencing. In addition, the licensee failed to correctly evaluate a failed leak rate test of the valve. The licensee entered this issue into its corrective action program for evaluation and initiated corrective actions to revise the test procedure and train engineering personnel.

The finding was of more than minor significance since it was associated with the Procedure Quality attribute for the containment and adversely affected the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Because the preconditioning altered the as-found condition of the check valve, the data collected through the performance of the surveillance test was not fully indicative of the true valve performance trend. Additionally, the licensees failure to correctly evaluate the initial failed leak rate test would become a more significant safety concern if left uncorrected because it could reasonably result in an unrecognized condition with a check valve failing to fulfill a safety-related function. Therefore, this performance deficiency had a direct effect on the licensees ability to fully assess the past operability, as well as the ability to trend as-found data for the purpose of assessing the reliability of the check valve. The finding was a licensee performance deficiency of very low safety significance because it would not result in exceeding the Technical Specification limit for reactor coolant system leakage and would not have likely affected mitigation systems resulting in a loss of safety function. In addition, the finding did not represent an actual open pathway in the physical integrity of the reactor containment. Based on consultation and review with the Regional Senior Reactor Analyst, the inspectors concluded that the finding did not result in an increase in the likelihood of an initiating event such as an inter-system loss-of-coolant accident or a containment bypass event because the redundant isolation valve and closed loop system piping passed leak rate measurement testing during the refueling outage with considerable margin. The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, the licensee did not have adequately trained and knowledgeable personnel available to correctly evaluate the cause of the initial failed leak rate measurement test and to ensure that appropriate actions to correct the test sequence in the procedure were identified.

(IMC 0310, H.2(b)) (Section 1R12.b.1)

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees corrective action program.

REPORT DETAILS

Summary of Plant Status

The unit was operated at or near full power during the inspection period with the following exceptions:

On February 4th, the licensee reduced power to about 90% to attempt recovery of a control rod that would not couple during plant start up from the refueling outage in December 2011.

The unit was returned to full power the same day.

On March 4th, the licensee reduced power to about 72% to perform control rod sequence exchange and main turbine control/stop/intermediate valve and main steam isolation valve testing. The unit was returned to full power the same day.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

Main article: IP 71111.04Q

a. Inspection Scope

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

Division 1 Diesel Generator (DG) during maintenance on the Division 2 DG;

Drywell Purge Train A during maintenance on Drywell Purge Train B; and

Residual Heat Removal (RHR) Train A during scheduled maintenance of RHR Train B.

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 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 Inspection Procedure (IP) 71111.04.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

Main article: IP 71111.04S

a. Inspection Scope

The inspectors performed a complete system alignment inspection of the Standby Liquid 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 as appropriate, mechanical and electrical equipment lineups, electrical power availability, system pressure and temperature indications, 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 corrective action program database to ensure that system equipment alignment problems were being identified and appropriately resolved.

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

b. Findings

No findings were identified.

1R05 Fire Protection

Main article: IP 71111.05

.1 Routine Resident Inspector Tours

Main article: IP 71111.05Q

a. Inspection Scope

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

Fire Zone T-1b, Condensate Booster Pump Room - Elevation 7120;

Fire Zone CB-6, Main Control Room Complex - Elevation 8000;

Fire Zone A-3f, Division 2 Switchgear Room - Elevation 7810;

Fire Zone A-2n, Division 1 Switchgear Room - Elevation 7810;

Fire Zone CB-1c, General Access and HVAC [Heating, Ventilation, and Air Conditioning] Area - Elevation 7190; and

Fire Zone D-5, Division 1 Diesel Generator Room - Elevation 7370".

The inspectors verified that transient combustibles and ignition sources were appropriately controlled and assessed the material condition of fire suppression systems, manual fire fighting 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 corrective action program 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 six quarterly fire protection inspection samples as defined in IP 71111.05AQ.

b. Findings

No findings were identified.

1R06 Flooding Protection Measures

Main article: IP 71111.06

.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 Updated Final Safety Analysis Report (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 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:

Shutdown Service Water (SX) Pump Rooms; and

Turbine Building Basement - Elevation 7020.

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

b. Findings

(1) Apparent Nonconforming Condition Affecting Circulating Water (CW) Pump Auto Stop Feature during a Flooding Event Introduction The inspectors opened an Unresolved Item (URI) pending evaluation of an issue that affects the function of a flood protection design feature intended to automatically stop running CW pumps in the event of flooding in the Turbine Building Condenser Pit.

Discussion As described in the UFSAR (Sections D3.6.4 and 10.4.5.5), each condenser cavity designed to contain flooding to Elevation 715 is equipped with a redundant system of level switches, which will alarm in the Control Room if the water level in the condenser cavity reaches an elevation of more than 1 foot (Elevation 710) above the condenser cavity floor at Elevation 709. These level switches will close a motor-operated valve in the floor drain piping between the condenser cavity and the Turbine Building floor drain sump to slow flooding of the Turbine Building. Isolating the condenser pit from the Turbine Building floor drain sump slows early flooding of the Turbine Building basement.

A second system of redundant level switches will automatically stop the CW pumps if the flood water reaches an elevation of 714 within the condenser cavity. An additional foot, from Elevation 714 to Elevation 715 remains to contain the water flow due to coast down of the CW pumps after they are initially shut off. Neither set of level switches are safety related; however, they are important internal flooding mitigation features as described in the UFSAR.

During review of Action Requests (ARs) 01192988 and 01197763, the inspectors noted that operators discussed a known design issue affecting the function of the CW pump auto stop feature. If CW Pump A has power removed then all CW pump tripping protection is lost during a flooding event. With power removed from CW Pump A, CW Pumps B and C would not auto stop during a flooding event because the tripping power comes through the CW Pump A tripping fuses. This appeared to the inspectors to be a nonconformance with the UFSAR description under the above specified circumstance. This design issue has apparently been known by operators for many years, yet no engineering evaluation was performed for the condition and no corrective action other than a procedure enhancement has been initiated by the licensee to address it. As stated in AR 01197763: Another lesson learned was to plan ahead for off service CW pumps and that if possible, do not have A CW Pump tagged out due to this removes the CW pump trip on high-high CW Pit level. The procedure for isolating a waterbox requires tagging out the off-service CW pump to preclude inadvertent start.

Having this trip defeated while performing an evolution with the potential to cause CW Pit flooding is contrary to good industrial safety practices.

The inspectors reviewed CPS 3113.01, Circulating Water (CW), Revision 37e, and noted that Step 4.11 described the condition. The High-High level (~714) in the Condenser Pit CW Pump Trip Circuitry is electrically powered by 1CW01PA DC

[direct current] control power. If the A pump is de-energized, then no CW pump tripping will be received from condenser pit flooding. The 710 floor drain sump floats which give Main Control Room alarm and 1TF013 valve closure would be the only indication of flooding.

The inspectors discussed this issue with the licensee and in response to the inspectors questions; the licensee initiated AR 01355130 to evaluate the design concern.

This issue is considered to be an Unresolved Item pending additional review of the licensees evaluation by the inspectors (URI 05000461/2012002-01, Evaluation of Apparent Nonconforming Condition Affecting Circulating Water Pump Auto Stop Feature during a Flooding Event).

1R07 Heat Sink Performance

Main article: IP 71111.07

.1 Annual Heat Sink Performance

Main article: IP 71111.07A

a. Inspection Scope

The inspectors reviewed the licensees thermal performance testing of the RHR B heat exchanger. The inspectors assessed the conduct of the test and the testing results to verify that no deficiencies existed that would adversely impact the heat exchangers ability to transfer heat to the SX system and to ensure that the licensee was adequately addressing problems that could affect the performance of the heat exchanger.

The inspectors observed portions of testing and reviewed documentation to verify that the acceptance criteria specified in procedure CPS 2700.20, RHR A(B) Heat Exchanger, 1E12B001A(B) Thermal Performance Test Covered by NRC Generic Letter 89-13, Revision 4b, were satisfactorily met.

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

b. Findings

No findings 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

The inspectors observed licensed operators during simulator training on March 14, 2012.

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.

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

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

Main article: IP 71111.11Q

a. Inspection Scope

On February 4, 2012, the inspectors observed licensed operators in the Control Room perform a power reduction to attempt recovery of a control rod that would not couple during plant start up from the refueling outage in December 2011. This was an activity that required heightened awareness, additional detailed planning, and involved increased operational risk. The inspectors evaluated the following areas:

Licensed operator performance;

Crews clarity and formality of communications;

Ability to take timely actions in the conservative direction;

Prioritization, interpretation, and verification of annunciators;

Correct use and implementation of procedures;

Control board manipulations;

Oversight and direction from supervisors; and

Ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications as applicable.

This inspection constituted one quarterly licensed operator heightened activity/risk inspection sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

a. Inspection Scope

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

Division 1 DG Failed To Start During Testing;

Low Pressure Coolant Injection (LPCI) from RHR A Check Valve 1E12-F041A Failed As-Found Leak Rate Measurement Test; and

Outboard Main Steam Isolation Valve Above Seat Drain Valve 1B21-F067B Failed To Shut During Testing.

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the structures, systems, and components (SSCs).

Specifically, the inspectors independently verified the licensee's handling of 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 licensee's corrective action program 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 maintenance effectiveness inspection samples as defined in IP 71111.12.

b. Findings

(1) Unacceptable Preconditioning of LPCI from RHR A Check Valve Prior to Leak Rate Test Measurement Introduction The inspectors identified a finding of very low safety significance with an associated non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. The licensee failed to establish an adequate procedure to perform required leak rate testing for the LPCI Train A discharge check valve. Specifically, the surveillance test procedure resulted in unacceptable preconditioning of the valve prior to a leak rate test measurement due to improper test sequencing. In addition, the licensee failed to correctly evaluate a failed leak rate test of the valve.

Discussion During the refueling outage on December 1, 2011, the licensee performed as-found leak rate measurement testing of reactor coolant system (RCS) pressure isolation valve (PIV)1E12-F041A, LPCI from RHR A Check Valve, in accordance with CPS 9843.01, ISI [Inservice Inspection] Category A Valve Leak Rate Test, Revision 35.

This surveillance test procedure was performed to satisfy TS Surveillance Requirement (TSSR) 3.4.6.1, which required the licensee to verify the equivalent leakage of each RCS PIV is 0.5 gallon-per-minute (gpm) per nominal inch of valve size up to a maximum of 5 gpm, at an RCS pressure 1000 pounds per square inch gauge (psig)and 1025 psig in accordance with the Inservice Testing (IST) Program. The licensees IST Program specified testing this valve once every 24-month refueling cycle during an outage. As described in the Bases for TS 3.4.6.1, the main purpose in establishing a leakage limit for the RCS PIVs is to prevent overpressure failure of the low pressure portions of connecting systems. The leakage limit is an indication of whether the PIVs between the RCS and the connecting systems are degraded or degrading. 1E12-F041A is also a primary containment isolation valve and must satisfy TSSR 3.6.1.3.10, which required the licensee to verify the combined leakage rate through hydrostatically tested lines that penetrated the primary containment is within limits established in accordance with the Primary Containment Leakage Rate Testing Program stipulated by TS 5.5.13 and 10 CFR 50, Appendix J, Primary Containment Leakage Testing for Light-Water Cooled Power Reactors.

During the test, 1E12-F041A would not pressurize due to an excessive amount of water passing through the valves seat at low pressure. Since the valve would not pressurize, the leak rate was initially determined to exceed the TSSR 3.4.6.1 limit of 5 gpm and operators documented the test failure in AR 01296786. The licensee subsequently cycled the check valve open and then closed with a torque wrench on the valves mechanical exerciser linkage to fully seat the valve and satisfactorily retested it.

The licensee completed an engineering evaluation (ECR 403032) following the initial leak rate test failure to review/accept the open stroke test as maintenance/flushing of the valve, which it deemed to satisfy the American Society of Mechanical Engineers (ASME) Operations and Maintenance (OM) Code requirements. The licensee also concluded in the engineering evaluation that the check valve was not preconditioned because the valve closed by its own means and is not assisted into the seat by the torque wrench.

The inspectors reviewed the licensees engineering evaluation for the failed as-found leak rate test and questioned whether the licensee correctly satisfied the ASME Code requirements. The inspectors noted that Paragraph ISTC-3630(f) of the ASME OM Code states, in part, that Valves with leakage rates exceeding the values specified by the Owner shall be declared inoperable and either repaired or replaced. A retest demonstrating acceptable operation shall be performed following any required corrective action before the valve is returned to service. It appeared to the inspectors that simply exercising the check valve to reseat it preconditioned the valve to pass a subsequent leak rate test, but it did not satisfy the Code requirement to either repair or replace the valve.

The inspectors discussed several questions regarding the testing of 1E12-F041A and the engineering evaluation with the licensee, which the licensee documented in AR 01326252:

1. Why did the check valve fail the as-found leak rate test? What was the cause?

2. How was the cause for the leak rate test failure corrected?

3. Did the licensee unacceptably precondition the valve by exercising it to get an

acceptable leak rate test result?

4. How was cycling the check valve with a torque wrench considered a repair or

replacement to satisfy the ASME Code requirement?

In response to the inspectors first two questions, the licensee determined that the check valve was unable to be pressurized for the leak rate test because the valves disc was not tightly seated due to previous testing performed on the redundant Train A LPCI isolation valve (1E12-F042A, LPCI from RHR A Shutoff Valve). 1E12-F042A is the upstream motor-operated isolation valve (MOV) on the containment penetration.

The test on 1E12-F042A pressurized the volume between the MOV and the check valve, causing the check valve to slightly lift and remain off of its seat. Since the check valve was not tightly seated when it was tested, pressurizing the test fill volume during the initial as-found leak rate test could not provide flow equivalent to that seen during normal operation with RCS pressure against the check valve. As a result, the low pressure/volume test source water went through the unseated check valve rather than force the disc back tightly against the valve seat. Had the licensee performed the leak rate test on 1E12-F041A before testing 1E12-F042A, the check valve would not have been disturbed and should have passed the initial as-found leak rate test.

CPS 9843.01 did not specify the testing sequence of the check valve and MOV (e.g., check valve before the MOV).

The inspectors noted that Inspection Manual Technical Guidance Part 9900 defines unacceptable preconditioning, in part, as: The alteration, variation, manipulation, or adjustment of the physical condition of an SSC before or during TS surveillance or ASME Code testing that will alter one or more of an SSCs operational parameters, which results in acceptable test results. Such changes could mask the actual as found condition of the SSC and possibly result in an inability to verify the operability of the SSC. In addition, unacceptable preconditioning could make it difficult to determine whether the SSC would perform its intended function during an event in which the SSC might be needed. The Part 9900 Technical Guidance further states that influencing test outcome by performing valve stroking does not meet the intent of the as-found testing expectations described in NUREG-1482, Guidelines for Inservice Testing at Nuclear Power Plants, (April 1995), and may be unacceptable.

The inspectors also noted that manually cycling a check valve prior to performing an as-found leak rate measurement was also not in accordance with the licensees Appendix J Program and IST Program procedural guidance. CPS 1305.01, Primary Containment Leakage Rate Testing Program, Revision 10, Step 4.5, states, in part, Preconditioning of components prior to leak rate testing is not allowed. In addition, ER-AA-321-1007, IST Program Corporate Technical Positions, Attachment 1, CTP-IST-001, Preconditioning of IST Program Components, Revision 0, states, in part, Manipulation of a check valve or a vacuum breaker that uses a mechanical exerciser to measure breakaway force prior to surveillance testing would be unacceptable preconditioning.

In response to the inspectors last two questions, the licensee noted that Paragraph ISTC-3630 states that valve closure before seat leakage testing shall be by using the valve operator with no additional closing force applied and concluded that exercising 1E12-F041A with a torque wrench on the mechanical exerciser linkage was acceptable preconditioning to establish the test conditions for an as-found leak rate test of the check valve since the previous test of 1E12-F042A had unseated the check valve; and, therefore its initial determination of an as-found test failure in AR 01296786 was incorrect. The licensee further concluded that exercising 1E12-F041A with a torque wrench was not a repair and would not meet the Code requirement; however, it was done to detect a possible valve problem that may require maintenance. The licensee therefore considered the initial leak rate measurement test to be an invalid test and the second leak rate measurement test to be the as-found test.

The inspectors acknowledged the licensees position and agreed that the Code would allow valve closure before seat leakage testing; however, the inspectors believed that that provision is to allow for closing a normally open valve when necessary to establish conditions for testing it. In this case, had the licensee tested 1E12-F041A before testing 1E12-F042A, the check valve should have already been tightly seated and there would have been no need to exercise it closed. Therefore, the inspectors concluded that exercising check valve 1E12-F041A closed was unacceptable preconditioning prior to an as-found leak rate test measurement since it should have been unnecessary to do so and the licensees surveillance test procedure was not appropriate to the circumstances because it did not properly sequence testing of 1E12-F041A before testing 1E12-F042A.

Because exercising 1E12-F041A prior to measuring the leak rate unacceptably preconditioned the check valve, the as-found leak rate test results were invalid. The test results, however, could be considered an acceptable as-left leak rate measurement and; therefore, no safety concern remains for the next operating cycle.

In addition, the inspectors concluded that the initial engineering evaluation, ECR 403032, incorrectly evaluated the failed leak rate measurement test of 1E12-F041A. The engineering evaluation should have identified that the problem was due to the test sequencing and evaluated the preconditioning concern prior to exercising the check valve closed and re-performing the leak rate measurement. As stated in NUREG-1482, Section 3.5.2, As noted in the inspection guidance, the licensee should have evaluated and documented the activity as acceptable preconditioning before performing the testing. Had it actually been a failed leak rate test rather than an invalid leak rate test, the inspectors also determined that ECR 403032 incorrectly concluded that exercising the check valve with a torque wrench on the mechanical exerciser met the Code requirement to either repair or replace the valve.

The licensee initiated several corrective actions to address this issue including:

1. Revision to CPS 9843.01 to ensure the correct testing sequence for RCS PIVs to

test the check valve prior to testing the other inline valve to prevent lifting the check valve off its seat.

2. Revision to CPS 9843.01 to provide guidance for engineering evaluation of leak rate

testing results that exceed the acceptance criteria to ensure the Corrective Action requirements in Paragraph ISTC-3630(f) to either repair or replace the valve are met.

3. Discussion with IST engineering peers regarding check valve exercising not

satisfying the Code requirement for Corrective Action following a leak rate test failure.

4. Revision to applicable licensee IST procedure(s) to incorporate corrective actions to

address the performance issues discussed above.

Analysis The inspectors determined that the licensees failure to establish an adequate surveillance test procedure to perform required leak rate testing for 1E12-F041A under suitable environmental conditions and to correctly evaluate the initial failed leak rate test was a performance deficiency warranting a significance evaluation. The inspectors reviewed the examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, and found 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 the finding was associated with the Procedure Quality attribute for the containment and adversely affected the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, exercising the check valve prior to performing an as-found leak rate measurement masked the actual as-found condition of the valve, invalidating the test results. Because the preconditioning altered the as-found condition of the check valve, the data collected through the performance of the surveillance test was not fully indicative of the true valve performance trend. Additionally, the licensees failure to correctly evaluate the initial failed leak rate test would become a more significant safety concern if left uncorrected because it could reasonably result in an unrecognized condition with a check valve failing to fulfill a safety-related function.

Therefore, this performance deficiency had a direct effect on the licensees ability to fully assess the past operability, as well as the ability to trend as found data for the purpose of assessing the reliability of the check valve. The inspectors performed a Phase 1 SDP review of this finding using the guidance provided in IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. In accordance with Table 4a, Characterization Worksheet for IE [Initiating Events], MS [Mitigating Systems],

and BI [Barrier Integrity] Cornerstones, the inspectors determined that that this finding was a licensee performance deficiency of very low safety significance (Green) because the finding would not result in exceeding the TS limit for RCS leakage and would not have likely affected mitigation systems resulting in a loss of safety function. In addition, the finding did not represent an actual open pathway in the physical integrity of the reactor containment. Based on consultation and review with the Regional Senior Reactor Analyst, the inspectors concluded that the finding did not result in an increase in the likelihood of an initiating event such as an inter-system loss-of-coolant accident (LOCA) or a containment bypass event because the redundant isolation valve and closed loop system piping passed leak rate measurement testing during the refueling outage with considerable margin.

The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, the licensee did not have adequately trained and knowledgeable personnel available to correctly evaluate the cause of the initial failed leak rate measurement test and to ensure that appropriate actions to correct the test sequence in the procedure were identified. (IMC 0310, H.2(b))

Enforcement 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

10 CFR 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents.

Test procedures shall include provisions for assuring that all prerequisites for the given test have been met and that the test is performed under suitable environmental conditions.

Contrary to the above, surveillance test procedure CPS 9843.01, ISI Category A Valve Leak Rate Test, Revision 35, was not appropriate to the circumstances because it did not ensure leak rate measurement testing of LPCI from RHR A Check Valve 1E12-F041A on December 1, 2011, was performed under suitable environmental conditions. Specifically, the test procedure did not appropriately ensure that the sequence of testing 1E12-F041A was prior to testing the redundant LPCI isolation valve (1E12-F042A, LPCI from RHR A Shutoff Valve). This resulted in an invalid as-found leak rate measurement and unacceptable preconditioning of 1E12-F041A in order to re-perform the leak rate test measurement. Because of the very low safety significance, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000461/2012002-02, Unacceptable Preconditioning of Low Pressure Coolant Injection from Residual Heat Removal A Check Valve Prior to Leak Rate Test Measurement). The licensee entered this violation into its corrective action program as AR 01326252 and AR 01355132.

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 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:

Emergent maintenance on January 18 on the Division 3 DG;

Emergent maintenance during the week of January 23-27 on the 1A Reheater Drain Tank Level Controller, Control Room Ventilation Train B Chiller, and on the 4160 Volt Bus 1A1 DG feeder breaker;

Planned maintenance during the week of February 6-10 on the Division 2 DG, Spent Fuel Pool Cooling Pump B, Standby Gas Treatment Train B, Diving Operations at the Lake Screen House, and Co-60 Project Cask Loading and Transportation;

Planned maintenance during the week of February 27 - March 2 on Containment Spray Train B, the Division 1 DG, Standby Gas Treatment Train B, and emergent maintenance on Control Room Ventilation Train A Chiller and Division 1 DG Ventilation System; and

Planned maintenance during the week of March 19-23 on the Division 3 DG and SX System.

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 corrective action program 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.

b. Findings

No findings were identified.

1R15 Operability Evaluations

Main article: IP 71111.15

a. Inspection Scope

The inspectors reviewed the following issues:

AR 01285559, Incorrect Actuator Weight in Seismic Qualification of MOV";

AR 01308448, C1R13LL - No Activity To Place 1RlX-PR008A-D In Service;

AR 01304146, Circulating Water Level Floats Partially Failed 3813.01 Section 8.1.3";

EC 387458, Impact of Transient Items in the Plant, and EC 387241, Transient Items Inside Primary Containment During Mode 3 (Prior to C1R13);and

EC 387664, AR 01323827: Potential Design Vulnerability: Single Open Phase.

The inspectors selected these potential operability/functionality 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 issue 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 evaluation. When applicable, the inspectors also verified that the licensee appropriately assessed the functionality of SSCs that perform specified functions described in the UFSAR, Operations Requirements Manual, Emergency Plan, Fire Protection Plan, regulatory commitments, or other elements of the current licensing basis when degraded or nonconforming conditions were identified.

In addition, the inspectors verified that problems related to the operability or functionality of safety-related plant equipment were entered into the licensees corrective action program 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

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

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 01278457-01, 1SX012A Thrust Verification and MOV Clean/Inspect";

WO 01278458-01, 1SX062A Thrust Verification and MOV Clean/Inspect";

WO 01517195-03, "Control Room HVAC Chiller B";

WO 01324596-01, "Replace / Bench Test / Adjust 1DO05A";

WO 01318718-01, "C1R13 Valcor Valve Modifications 1PS038"; and

WO 01347808-02, "Operations Post-Maintenance Test 0SA01D Dryer."

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 corrective action program documents associated with post-maintenance testing to verify that identified problems were entered into the licensee's corrective action program with the appropriate characterization.

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

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

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 9000.01D001, Control Room Surveillance Log - Mode 1,2,3 Data Sheet, Section 8.9, Reactor Coolant System - Operational Leakage; (RCS Leakage)

CPS 9070.01, Control Room Heating Ventilation and Air Conditioning Air Filter Package Operability Test Run; (Routine Test)

CPS 9080.12, "Diesel Generator Fuel Oil Transfer Pump Operability";

(Inservice Test)

CPS 9080.14, Diesel Generator 1C 24-Hour Run and Hot Restart - Operability";

(Routine Test)

CPS 9053.04C001, "RHR Loop A Valve Operability"; and (Inservice Test)

CPS 9061.01, Shutdown Service Water Operability Test. (Inservice Test)

The inspectors observed selected portions of the test activities to verify that the testing was accomplished in accordance with plant procedures. The inspectors reviewed the test methodology and documentation to verify that equipment performance was consistent with safety analysis and design basis assumptions, and that testing acceptance criteria were satisfied.

In addition, the inspectors verified that surveillance testing problems were entered into the licensees corrective action program 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 one RCS leakage test, three in-service tests, and two routine surveillance tests for a total of six surveillance testing inspection samples as defined in IP 71111.22.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstone: Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

Main article: IP 71124.01

This inspection constituted a partial sample as defined in IP 71124.01.

.1 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 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 selected plant areas and evaluated whether the thoroughness and frequency of the surveys where 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.

Cobalt-60 Harvesting and Packaging; and

RHR Valve Refurbishment.

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 that the licensee has established a means to inform workers of changes that could significantly impact their occupational dose; and

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

b. Findings

No findings were identified.

.2 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected various containers holding non-exempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether the containers were labeled and controlled in accordance with 10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g), Exemptions To Labeling Requirement.

The inspectors reviewed the following radiation work permits used to access high radiation areas and evaluated the specified work control instructions or control barriers:

RWP 10012088, Cobalt-60 Harvesting"; and

RWP 10013165, 2012 RHR / LPCS [Low Pressure Core Spray] / HPCS

[High Pressure Core Spray] / SX / RCIC [Reactor Core Isolation Cooling]

Scope of Work.

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

The inspectors reviewed selected occurrences where a workers electronic personal dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the corrective action program and dose evaluations were conducted as appropriate.

For work activities that could suddenly and severely increase radiological conditions, the inspectors assessed the licensees means to inform workers of changes that could significantly impact their occupational dose.

b. Findings

Transportation (71124.08) This inspection constituted a partial sample as defined in IP 71124.08.

.1 Shipment Preparation (02.05)

a. Inspection Scope

The inspectors observed shipment packaging, surveying, labeling, emergency instructions, shipping papers, and licensee verification of shipment readiness.

The inspectors assessed whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensees procedures for cask loading and closure procedures were consistent with the vendors current approved procedures.

The inspectors observed radiation workers during the conduct of radioactive waste processing and radioactive material shipment preparation and receipt activities.

The inspectors assessed whether the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to:

The licensees response to NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, dated August 10, 1979; and

Title 49 CFR Part 172, Hazardous Materials Table, Special Provisions, Hazardous Materials Communication, Emergency Response Information, Training Requirements, and Security Plans, Subpart H, Training.

Main article: IP 71152

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

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 corrective action program 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 corrective action program 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 were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors reviewed repetitive or closely related issues documented in the licensees corrective action program to look for trends not previously identified.

The inspectors also reviewed action requests regarding licensee-identified potential trends to verify that corrective actions were effective in addressing the trends and implemented in a timely manner commensurate with the significance.

This inspection constituted one semi-annual trend review inspection sample as defined in IP 71152.

b. Assessment and Observations

(1) Overall Effectiveness of Trending Program The inspectors determined that the licensees trending program was generally effective at identifying, monitoring, and correcting adverse performance trends. The inspectors reviewed several common cause and operational and technical decision making evaluations performed by the licensee to evaluate potential adverse performance and equipment trends. In general, these evaluations were performed well and identified appropriate corrective actions to address adverse trends that were identified.

The inspectors identified one new adverse trend that was not already identified by the licensee and entered into its corrective action program.

(2) Adverse Trend in Maintaining Acceptable Environmental Conditions in the Records Storage Vault The inspectors noted that the licensees records management staff has documented numerous (at least 24) action requests over the past 11/2 years identifying deviations from temperature and humidity limits for the records storage vault and questioned whether the licensee was adequately addressing this relatively long-standing condition adverse to quality. Maintaining appropriate environmental conditions in the records storage vault is important to prevent long-term degradation of quality records stored within it, and as such, is required by the licensees procedures that implement 10 CFR 50, Appendix B, Criterion II, Quality Assurance Program, including NO-AA-10, Quality Assurance Topical Report, Revision 86; and, RM-AA-101-1008, Processing and Storage of Records, Revision 5. These procedures reference ASME NQA-1, Quality Assurance Program Requirements for Nuclear Facilities, 1994, which the licensee committed to comply with in UFSAR Chapter 17, Quality Assurance.

NQA-1, Supplement 17S-1, Supplementary Requirements for Quality Assurance Records, Section 4.4, Storage Facilities, states, in part, that records shall be stored in facilities constructed and maintained in a manner which minimizes the risk of damage or destruction from environmental conditions such as high and low temperatures and humidity.

Based on review of relevant action requests, material condition and work history of the records storage vault HVAC unit and humidifier, and discussions with several of the licensees staff, the inspectors determined that the licensee has not been timely in correcting this problem. The inspectors reviewed the licensees functionality assessment of this condition that was recently completed on February 24, 2012.

While this functionality assessment was not completed in a very timely manner, it did appropriately evaluate the nonconforming condition. An earlier functionality assessment was also completed in October 2011 when humidity in the vault was high.

That assessment concluded that the vault HVAC system was not controlling relative humidity consistent with UFSAR Section 9.4.12.1.2 values. Because there has been no discernable damage to date of quality records in the vault attributable to temperature and humidity the inspectors concluded that this issue was of minor significance.

The licensee currently has scheduled replacement of the records storage vault HVAC unit in May 2012.

(3) Continuing Adverse Trend in Evaluating Degraded/Nonconforming Plant Conditions for Operability, Functionality and/or Reportability The inspectors noted that an adverse trend has continued involving the licensees evaluation of degraded/nonconforming plant conditions for operability, functionality and/or reportability. The inspectors have identified several examples of poor quality evaluations as well as the absence of evaluations for degraded/nonconforming conditions during this inspection period. The inspectors first identified and documented this adverse trend three years ago. Past semi-annual trend reviews documented in inspection reports (NRC Inspection Reports 05000461/2011004, 05000461/2010005 and 05000461/2009005) discussed examples of deficiencies with licensee evaluations when degraded or nonconforming conditions were discovered. The licensees Nuclear Oversight organization has also noted this adverse performance trend in the past and has documented many specific examples of it. An Elevation Letter was issued by Nuclear Oversight in 2010 and was subsequently closed after corrective actions were implemented.

The inspectors have documented several findings related to this adverse performance trend over the past three years. These findings include FIN 05000461/2009003-01, NCV 05000461/2009004-03, NCV 05000461/2010003-01, FIN 05000461/2010003-03, NCV 05000461/2011004-04, FIN 05000461/2011004-05. Additional occurrences of incomplete or inadequate operability, functionality and/or reportability evaluations were identified by the inspectors, but were not documented because the individual issues were determined to be of minor safety significance.

Additional examples the inspectors identified during this inspection period, which were determined to be of minor safety significance included:

AR 01300208 - No functionality assessment was performed as requested by the Operations Shift Manager in the action request for a degraded/non-conforming condition affecting operation of sump pumps in all three SX Pump Rooms.

AR 01192988 - An apparent nonconforming condition involving the design of a flood protection feature for auto stopping the CW pumps has been known by plant operators for many years as identified in the action request. This issue is further discussed in Section 1R06.1 of this inspection report. No evaluation was performed for the condition and no corrective action other than a procedure enhancement was initiated by the licensee to address it.

AR 01315336 and AR 01337692 - During a Diesel Fire Pump A surveillance test; engine coolant temperature never reached the normal operating range of 160°F to 200°F. The acceptance criterion in Step 9.2.2.1 of the surveillance test procedure was not met, yet the surveillance test was signed off by operators as satisfactory with no explanation in the test record and no functionality assessment was performed.

AR 01302633 and AR 01324027 - Motor-operated valve 1B21-F067B (Train B Main Steam Line Drain Valve) failed to shut during surveillance testing.

The inspectors reviewed the licensees past operability/reportability evaluation and identified several quality issues with it, including incorrect assumptions and information (e.g., the valve is normally opened vice closed and the cause of the problem was attributed to torque switch contacts vice stem grease).

AR 01304146 - A functional test to verify the function of flood protection level switches in the Turbine Building Condenser Pit was completed at the end of the C1R13 refueling outage with an unsatisfactory result. The licensee deferred correcting the problem prior to start-up without performing an evaluation of the non-conforming condition and providing explicit justification as required by OP-AA-108-115, Operability Determinations, Revision 11. The functionality assessment completed by system engineering after the refueling outage did not correctly evaluate the condition; however, a condition evaluation completed by the Instrument Maintenance Manager provided an appropriate evaluation and explanation of the unsatisfactory test results.

Due to the fact that examples of this adverse performance trend continue to be identified by the inspectors as well as by the licensee and they have been entered into the licensees corrective action program, and that separate findings have been documented when an inadequate evaluation has risen to a more than minor significance threshold, no additional finding of significance was identified at this time.

.3 Annual In-depth Review Samples

a. Inspection Scope

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

AR 01309488, 1TGCV1: ECR [Engineering Change Request] for TCV#1

[Turbine Control Valve #1] Oscillations and Impact to EH [Electro-Hydraulic]

Pressure";

AR 01297701, "Inadvertent Actuation Of Level 1 & 2 Logic"; and

AR 01295617-05, "Automatic Scram on High Pressure During Approach to Unit Shutdown."

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 three annual in-depth review inspection samples as defined in IP 71152.

b. Findings and Observations

(1) Influence of Schedule Pressure on Decision to Accept Out-Of-Specification Calibration Data for a Turbine Control Valve Resulted in a Challenge to Operators During Plant Start Up from the Refueling Outage Introduction The inspectors reviewed the licensees apparent cause evaluation for an inaccurate engineering assessment of a nonconforming condition affecting performance of the main turbine control valves (TCVs) during plant startup from the C1R13 refueling outage in December 2011. Although No findings were identified from the self-revealed event, the inspectors noted that scheduling pressure influenced the licensees decision making to accept the condition rather than correct it during the refueling outage. The inspectors observations from review of this issue are discussed below.

Discussion During the C1R13 refueling outage, instrument maintenance craftsmen calibrated the response of the TCVs. After completing the valve calibrations, the as-left results for TCV#1 were not within the limits specified in the procedure. The licensee evaluated and accepted the out-of-specification calibration data for TCV#1 rather than correcting the valves response by recalibrating the valves response curve. As stated in the licensees apparent cause evaluation, recalibration to bring the response curve back into specification would have required additional instrument maintenance resources and additional outage scope, potentially affecting the outage duration. An Engineering Change Request (ECR 0004031170) documented acceptance of the out-of-specification calibration data for TCV#1 and provided guidance to operators. Subsequently, on December 25th during power ascension at about 80% reactor power, the TCVs started oscillating severely. This caused an excessive demand on the TCV electro-hydraulic control (EHC) system (i.e., beyond the capacity of a single EHC pump) causing system pressure to drop significantly. This also caused reactor power to oscillate as indicated on the average power range monitors. Operators manually started the standby EHC pump to restore pressure. As operators raised power above about 83%,

TCV oscillations subsided and operators were able to shut off the standby EHC pump.

Following this event, the licensee wrote AR 01309488 to document the flawed engineering assessment of the non-conforming condition during the refueling outage and completed an apparent cause evaluation to determine why the engineering evaluation failed to identify the adverse impact on the EHC system that challenged operators during the power ascension. The licensee concluded that the apparent cause was that the engineering team assembled to evaluate the as-left calibration results narrowly focused on the acceptability of the calibration data, which limited their analysis to pressure control concerns. The team did not evaluate the aggregate impact on the EHC system but limited their scope to TCV#1 as a component. As a result, they did not identify the possible unintended consequences. The licensee identified several corrective actions including:

(1) reperformance of the engineering evaluation to assess the TCV oscillations at about 80% power with recommendations for operators to mitigate operational impact,

(2) read and sign briefing materials for engineering staff to address lessons learned, and

(3) revision to plant operating procedures with instructions to run two EHC pumps when the plant is operated near 80% reactor power.

The inspectors identified one particular aspect of the engineering teams evaluation that was mentioned in the apparent cause evaluation, but was not identified by the licensee as a contributing cause. It was apparent to the inspectors that schedule pressure influenced the decision making process that led to the licensees decision to accept the out-of-specification calibration data for TCV#1 vice recalibrating the response curve to correct it. The engineering teams thought process apparently focused on how to justify accepting the non-conforming condition in order to avoid expending time and limited instrument maintenance resources near the end of the refueling outage. The inspectors noted that this thought process led to a non-conservative decision with an unintended consequence. As stated in the apparent cause evaluation:

This technical call was primarily focused on the acceptability of current TCV#1 readings and not require [sic] any rework if we can live with the current readings.

The result of the discussion was that the TCV#1 as-left curve was acceptable for unit operation even though not as good as desired. A recommendation was made to make an attempt to recalibrate if time permits [emphasis added] in the outage. The Outage Control Center was notified about the possibility of rework.

The scope was unable to be completed during C1R13.

Until the problem can be corrected during an outage, the licensee has proceduralized an operator workaround to start the standby EHC pump when operating near 80% reactor power to avoid loss of EHC pressure due to excessive TCV oscillations. Inasmuch as operators were able to correctly respond to the TCV oscillations and resultant loss of EHC pressure in accordance with plant response procedures, the inspectors concluded that this issue was of minor safety significance.

(2) Failure to Incorporate Operating Experience into Preventive Maintenance (PM) Activities Associated with Steam Bypass System Circuit Cards Introduction A finding of very low safety significance with an associated non-cited violation of 10 CFR\ 50.65 was self-revealed when the failure of a Bypass Valve Demand (BVD)card caused Turbine Bypass Valve (BPV) #1 to suddenly close and isolate steam flow from the reactor to the main condenser, causing reactor pressure to exceed the automatic reactor scram setpoint. The card failure occurred, in part, due to the licensees failure to perform preventive maintenance on the component throughout the history of plant operation. The automatic scram occurred on November 29, 2011, with the unit at 16.1% power while operators were shutting down the reactor to commence a refueling outage.

Discussion On November 29, 2011, operators were reducing main generator load to 50 Megawatts in order to trip the main turbine to start refueling outage C1R13. BPV #1 had begun opening and was approximately 8 percent open when it ramped closed contrary to system demand. Due to the loss of the steam flow path through the bypass valve to the main condenser, reactor pressure rose to the automatic scram setpoint resulting in a reactor scram. Troubleshooting determined that BPV #1 closed due to the failure of a BVD card in the Steam Bypass and Pressure Control (SBPC) system. The cause of the card failure was attributed to the licensees failure to replace or refurbish the BVD card prior to it failing. The installed BVD cards were original plant equipment and were therefore greater than 24 years old. The licensee performed a calculation which determined these components have a mean time between failures of 20 years.

The licensees root cause report identified this as an end-of-life failure of the BVD card.

The inspectors questioned why no PM had ever been performed on these circuit cards.

The inspectors were told that the components were scoped within the Maintenance Rule, which requires that licensees monitor the performance of SSCs sufficient to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions. These particular circuit cards had never been assigned equipment identification numbers and consequently had no classification within the licensees PM process. Components of this type are not evaluated by the licensee for PM activities.

By default, components such as these BVD cards are treated as run-to-failure and are only evaluated when their failure becomes classified as a Maintenance Rule Functional Failure. In such cases, the monitoring performed by the licensee in order to satisfy the requirements of 10 CFR 50.65 is performed at the plant level. This is permissible within the guidance provided in NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2, which states, in part, under Section 9.3.2, Remaining non-risk significant SSCs (those normally operating) are addressed under (a)(2) and performance is monitored against plant level criteria. For example, automatic reactor scrams may be established as the performance criteria that are to be monitored to demonstrate the effectiveness of preventive maintenance for a given system.

However, Section 8.2.1.5 of NUMARC 93-01 also provides specific guidance for non-safety related SSCs whose failure causes a reactor scram such as the BVD card that failed on November 29th. It states, in part, that, A utility should rely on actual plant-specific and industry wide operating experience [This] operating experience is reviewed for plant-specific applicability and, where appropriate, is included in utility specific programs and procedures. It is appropriate to use this information to the extent practical to preclude unacceptable performance experienced in the industry from being repeated. Section 12.1 of this guidance also states that adjustment in PM activities shall be made under required 10 CFR 50.65(a)(3) reviews where necessary to ensure that the objective of preventing failures of SSCs through maintenance is appropriately balanced with minimizing unavailability. The licensees root cause report for the November 29th scram identified two operating experience driven projects that it performed in 2001 and 2007. These Plant Material Condition Excellence Initiative (PMCEI) assessments failed to correctly classify these critical circuit cards within the licensees PM process. In addition, AR 01117617, Lack of PMs for Steam Bypass System Circuit Cards, documented a more recent failure by the licensee to incorporate this same operating experience into its PM activities. In the action request, the system engineer identified that troubleshooting BPV position transmitter cards revealed that the circuit cards had been replaced during the PMCEI Project, but no periodic PM was ever generated. He also noted that there were no PMs for periodic replacement of other circuit cards within the panel.

The recommended action of AR 011176 was for engineering to evaluate the circuit cards in the SBPC system for periodic replacement. The action was to be completed by November 18, 2010, but was delayed on three separate occasions due to other emergent actions and other priorities. Eventually, on May 20, 2011, the issue was closed by an action to create a one-time replacement work order to be performed in 2014. The system engineer noted in the action request that the life of the circuit cards is approximately 16 years. At that time, the cards had been in service for 23 years.

The licensee initiated corrective actions to replace both BVD cards during the refueling outage, perform periodic replacement/refurbishment maintenance activities, and trend circuit card performance during routine calibration. Refer to Section 4OA3.3 of this inspection report for a review and closure of the LER associated with the reactor scram.

Analysis The inspectors determined that the licensees failure to evaluate and take into account, where practical, industry operating experience associated with preventive maintenance on critical component circuit cards in the SBPC system was a performance deficiency warranting a significance evaluation. The inspectors reviewed the examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, and found this issue sufficiently similar to guidance provided in Example 7(c) in that this violation of 10 CFR 50.65(a)(3) had a consequence such as equipment problems attributable to failure to take industry operating experience into account when practicable. Specifically, industry operating experience driven reviews were performed focused upon critical circuit card replacement to prevent age-related failures and the licensee failed to apply this knowledge to the BVD cards on three separate occasions, eventually resulting in a reactor scram due to age-related failure.

Therefore, the inspectors concluded that this finding was of more than minor safety significance. Because the performance issue caused a reactor scram, the inspectors determined that the finding was associated with the Initiating Events Cornerstone.

The inspectors performed a Phase 1 SDP review of this finding using the guidance provided in IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. In accordance with Table 4a, Characterization Worksheet for IE, MS, and BI Cornerstones, the inspectors determined that this finding was a licensee performance deficiency of very low safety significance (Green) because the finding:

(1) did not contribute to the likelihood of a loss-of-coolant accident initiator,

(2) did not contribute to both the likelihood of a reactor scram AND the likelihood that mitigation equipment or functions would not be available, and

(3) did not increase the likelihood of a fire or internal/external flooding event.

The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, in the area of work control, the licensee did not appropriately coordinate work activities by incorporating actions to plan work activities to support long-term equipment reliability by scheduling maintenance as more preventive than reactive.

(IMC 0310 H.3(b))

Enforcement 10 CFR 50.65(a)(3) states, in part, that performance and condition monitoring activities and associated goals and preventive maintenance activities shall be evaluated at least every refueling cycle provided the interval between evaluations does not exceed 24 months. The evaluations shall take into account, where practical, industry-wide operating experience. Adjustments shall be made where necessary to ensure that the objective of preventing failures of SSCs through maintenance is appropriately balanced against the objective of minimizing unavailability of SSCs due to monitoring or preventive maintenance.

Contrary to the above, on three occasions, in 2001 and 2007 and most recently on September 24, 2011, the licensee failed to incorporate operating experience when it was practical to do so. Because of the very low safety significance, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000461/2012002-04, Failure to Incorporate Operating Experience into Preventive Maintenance Activities). The licensee entered this violation into its corrective action program as AR 01295617.

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

Main article: IP 71153

.1 (Closed) LER 05000461/2011-005-00, Missed Surveillance Due To Preconditioning

Valve Prior To Leak Rate Test On December 1, 2011, the inspectors observed the licensees performance of surveillance testing that was accomplished in accordance with CPS 9861.05D010, RCIC Turbine Exhaust Water Leak Rate Test Data Sheet (S-MC039k12), Revision 24.

This surveillance test procedure was performed to satisfy TSSR 3.6.1.3.10 for RCIC turbine exhaust check valve 1E51-F040, which required the licensee to verify the combined leakage rate through hydrostatically tested lines that penetrated the primary containment is within limits established in accordance with the Primary Containment Leakage Rate Testing Program stipulated by TS 5.5.13 and 10 CFR 50, Appendix J, Primary Containment Leakage Testing for Light-Water Cooled Power Reactors.

This Category A check valve was also tested to satisfy the IST Program requirements in TS 5.5.6 and 10 CFR 50.55a, Paragraph f, Inservice testing requirements. The test was intended to be an as-found leak rate measurement prior to the performance of maintenance during the refueling outage.

During test preparation, the inspectors observed an operator cycle the check valve from closed to open and then back to close. Exercising the valve in this manner using the installed mechanical exerciser just prior to measuring the leak rate was directed by Step 8.2.2.2.a of the test procedure. This unacceptably preconditioned the valve prior to conducting the leak rate measurement since it masked the as-found condition and it was not necessary to place the system in the configuration for testing. Consequently, the surveillance test result was invalid. An acceptable leak rate measurement was performed after maintenance was completed; therefore, no safety concern remains for the next operating cycle. The licensee initiated a corrective action to revise CPS 9861.05D010 to ensure that 1E51-F040 is not exercised prior to as-found leak rate testing and completed an extent of condition evaluation to review other leak rate testing procedures for possible unacceptable preconditioning practices. No additional examples were found.

The surveillance test was determined to be a missed surveillance, which the licensee subsequently reported as an operation or condition prohibited by the plants TS in accordance with 10 CFR 50.73(a)(2)(i)(B). The inspectors previously reviewed this issue and documented a non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings in NRC Inspection Report 05000461/2011005 for the licensees failure to establish an adequate procedure to perform required leak rate testing for the RCIC turbine exhaust check valve. The inspectors determined that the information provided in LER 05000461/2011-005-00 did not raise any new issues or change the conclusion of the initial review. Therefore, the violation of TSSR 3.6.1.3.10 and TS 5.5.6 described in this LER will not be separately documented.

LER 05000461/2011-005-00 is closed.

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

.2 (Closed) LER 05000461/2011-006-00, Condition Prohibited by Technical Specifications

Due to Missed Surveillance During the refueling outage on December 7, 2011, the licensee performed leak rate measurement testing of RCS PIV 1E12-F042C, LPCI from RHR C Shutoff Valve, in accordance with CPS 9843.01, ISI Category A Valve Leak Rate Test, Revision 35.

This surveillance test procedure was performed to satisfy TSSR 3.4.6.1, which required the licensee to verify the equivalent leakage of each RCS PIV is 0.5 gpm per nominal inch of valve size up to a maximum of 5 gpm, at an RCS pressure 1000 pounds per square inch gauge (psig) and 1025 psig in accordance with the IST Program.

1E12-F042C is also a primary containment isolation valve and must satisfy TSSR 3.6.1.3.10, which required the licensee to verify the combined leakage rate through hydrostatically tested lines that penetrated the primary containment is within limits established in accordance with the Primary Containment Leakage Rate Testing Program stipulated by TS 5.5.13 and 10 CFR 50, Appendix J, Primary Containment Leakage Testing for Light-Water Cooled Power Reactors. During the test, the valve would not pressurize due to an excessive amount of water passing through the seat at low pressure. Since the valve would not pressurize, the leak rate was determined to exceed the TSSR 3.4.6.1 limit of 5 gpm. The licensee subsequently repaired the valve and satisfactorily retested it. The licensee determined the cause to be due to wear on the guide ribs and excessive disc to rib clearances, such that the disc became cocked when closing and it did not fully seat.

In April 2011, the inspectors reviewed CPS 9843.01 and the completed test packages for RCS PIV testing performed during the previous refueling outage in January/February 2010 and identified that the licensee had failed to correctly incorporate the required test pressure limits of the TSSR into the surveillance test procedure and subsequently tested multiple RCS PIVs, including 1E12-F042C, at pressures greater than the maximum test pressure of 1025 psig, invalidating the testing. The licensee correctly addressed these missed TS surveillances in accordance with TSSR 3.0.3. The inspectors reviewed this issue and documented a non-cited violation of TSSR 3.4.6.1 in NRC Inspection Report 05000461/2011003.

Because leak rate testing of 1E12-F042C during the December 2011 refueling outage failed to meet the TSSR 3.4.6.1 limit, the valve was considered to have been inoperable and TS 3.4.6, which required the RCS PIV leakage to be within the specified limit with Unit 1 operating in Modes 1 and 2, not met for the previous operating cycle.

The licensee reported this as an operation or condition prohibited by the plants TS in accordance with 10 CFR 50.73(a)(2)(i)(B). The inspectors determined that the information provided in LER 05000461/2011-006-00 did not raise any new issues or change the conclusion of the initial review. A licensee identified non-cited violation of TS 3.4.6 and TS 3.6.1.3 is discussed in Section 4OA7.1 of this inspection report.

LER 05000461/2011-006-00 is closed.

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

.3 (Closed) LER 05000461/2011-004-00, Automatic Reactor Scram During Removal of

Main Generator On November 29, 2011, operators were reducing main generator load to 50 Megawatts in order to trip the main turbine to start refueling outage C1R13. BPV #1 had begun opening and was approximately 8 percent open when it ramped closed contrary to system demand. Due to the loss of the steam flow path through the BPV to the main condenser, reactor pressure rose to the automatic scram setpoint of 1065 psig, resulting in a reactor scram. Operators shortly established control of reactor pressure by taking manual control of the BPV utilizing the BPV opening jack. No safety relief valves lifted as a result of the pressure increase. The licensee reported this event as a condition that resulted in the automatic actuation of the reactor protection system in accordance with 10 CFR 50.73(a)(2)(iv)(A).

Two anomalies occurred during the transient. The first was a trip of the motor driven feedwater pump and main turbine at +52 inches reactor vessel narrow range level, and second was the absence of a reverse power generator trip. Subsequent review did not identify any failed or degraded components within the feedwater level control system.

The motor driven feedwater pump and main turbine trip had no safety consequence.

The consequence of the failure of a reverse power generator trip to occur was that the main generator was motored for approximately 90 seconds before operators manually tripped main generator output circuit breakers 4506 and 4510. Two reverse power relays did not actuate as expected, most likely due to high megavolt amps reactive output power and low megawatt input while the generator was motoring. Motoring the main generator for 90 seconds had no safety impact.

Troubleshooting determined that BPV #1 closed due to a BVD circuit card failure.

The cause of the card failure was attributed to the licensees failure to replace or refurbish the BVD card prior to age-related failure. The installed BVD cards were original plant equipment and therefore greater than 24 years old. A calculation performed by the licensee determined these components have a mean time between failures of 20 years. The inspectors reviewed the licensees root cause investigation of the scram. This investigation identified two operating experience driven projects performed in 2001 and 2007. These assessments failed to correctly classify these critical BVD circuit cards within the licensees PM process. It is noteworthy that the licensees root cause investigation failed to address the recent AR 01117617, which identified the lack of PMs for the SBPC circuit cards. The performance issues related to this event are discussed in Section 4OA2.3.b.2 of this inspection report.

LER 05000461/2011-005-00 is closed.

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

.4 Licensee Event Notification 47544, "H2 [Hydrogen] Leak from Main Generator and

NOUE [Notice of Unusual Event] Declared" On December 21, 2011, during preparations to synchronize the main generator to the grid, the automatic voltage regulator (AVR) was placed into service. Concurrent with the field flash, main generator hydrogen pressure began to significantly decrease.

Generator hydrogen pressure had been stable at 49 psig and reached its lowest value of 27.2 psig during the licensees troubleshooting efforts to restore pressure.

Personnel were dispatched to identify the source of the hydrogen leak. At 5:52 p.m.

Central Standard Time (CST) reports from personnel in the Turbine Building identified high hydrogen levels and the Turbine Building was evacuated. An NOUE was declared at 5:57 p.m. CST and State notification was completed at 6:09 p.m. CST.

Turbine Building roof vents were opened to ventilate the Turbine Building and all elevations were verified to be clear of hydrogen. Access to the Turbine Building was restored and the NOUE was terminated at 6:38 p.m. CST. The NRC was notified of the declaration of the NOUE at 6:56 p.m. CST.

The cause of the hydrogen leak was determined to be that a portion of a hydrogen seal became mispositioned and allowed hydrogen to be lost through the seal as a result of shaft movement when the AVR was energized. Movement of the turbine generator shaft during AVR startup will occur due to adding current to the field flash circuit.

Leakage resulting from this cause would not be detected in the Turbine Building since the hydrogen would then travel through its design path through the seal oil system and out the roof vent. The inspectors concluded that given the circumstances of the event, the operating shift made an appropriately conservative declaration and responded adequately. However, the State notification was made at 6:09 p.m. CST and the NRC was notified at 6:56 p.m. CST, a difference of 47 minutes. Also, the event notification made to the NRC of the Unusual Event declaration was 59 minutes after the NOUE was declared. Per 10 CFR 50.72 (a)(1)(i) and 10 CFR 50.72 (a)(3), the licensee shall notify the NRC immediately after notification of the appropriate State or local agencies and not later than one hour after the time the licensee declares one of the Emergency Classes.

The inspectors concluded that the issue of timeliness of notification was of minor safety significance. The issue was entered into the licensees corrective action program as AR 01307258.

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

.5 Licensee Event Notification 47587, "Invalid Actuation of General Containment Isolation

Signals" On January 12, 2012, the licensee notified the NRC via telephone that an invalid actuation of general containment isolation signals had occurred affecting containment isolation valves in more than one system and emergency service water systems that normally do not run and that serve as ultimate heat sinks. The event occurred on December 4, 2011 at 6:09 a.m. CST during refueling outage activities. The telephone notification was made in accordance with 10 CFR 50.73(a)(1) and was within the 60-day reporting requirement.

The inspectors reviewed the event notification, prompt investigation, apparent cause evaluation (AR 01297701), and the action request documented for the event.

The inspectors noted several performance deficiencies associated with the event in the area of work control. Specifically, maintenance technicians exceeded the scope of work that was authorized, inadequate work instructions were accepted, and work activities proceeded on even after unexpected annunciator alarms caused by the event were received. However, no performance deficiency of more than minor safety significance was identified with this issue. This was primarily due to the fact that the plant was in a shutdown condition at the time of the event and the affected SSCs were not required to be operable.

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

.6 (Closed) LER 05000461/2011-001-00, Postulated Spurious High Pressure Core Spray

Initiation Result Unanalyzed On February 8, 2011, the licensee identified that the HPCS system could spuriously initiate due to fire-induced hot short cable damage to two automatic initiation logic instrument cables routed in the same raceway. As a result, the reactor would fill and flood the main steam lines because shorting of the control cables would prevent HPCS pump shutdown and closure of the injection valve. The licensee determined that the main steam relief valves and associated down-comers were not analyzed for stresses as a result of two-phase flow at high pressure.

Subsequent to the licensees issuance of LER 05000461/2011-001-00, the licensee completed an analysis that determined the acceptability of a spurious HPCS initiation.

The inspectors reviewed the analysis and did not identify any safety significant concerns.

The concern identified in this LER was similar to the concern identified by the NRC in URI 05000461/2005006-01. Additional information regarding the analysis is discussed as part of the closure of URI 05000461/2005006-01 in Section 4OA5.3.

LER 05000461/2011-001-00 is closed.

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

4OA5 Other Activities

.1 Review of Institute of Nuclear Power Operations (INPO) / World Association of Nuclear

Operators (WANO) Assessment Report The inspectors completed a review of the INPO/WANO Evaluation Report for the Clinton Power Station assessment conducted in December 2010. During this review, the inspectors did not identify any new safety significant issues.

.2 Review of INPO Training Accreditation Reports

The inspectors completed a review of the INPO Operations Training Accreditation Board Report dated March 22, 2012, and the INPO Maintenance and Technical Training Accreditation Board Report dated June 10, 2009. During this review, the inspectors did not identify any new safety significant issues.

.3 (Closed) URI 05000461/2005006-01, Postulated Fire-Induced Circuit Failures Resulting

in Potential Spurious Actuation of Division III HPCS Pump 1E22-C001 and Discharge Valve 1E22-F004 During the NRCs 2005 triennial fire protection baseline inspection the inspectors identified an URI associated with potential fire-induced electrical failures in the HPCS system. The inspectors postulated that a fire in the Division III switchgear room (located in Fire Zone CB-5a) could result in fire-induced electrical circuit faults in the control cables and control logic of the HPCS pump and a discharge valve. This could result in the inability to shut-off the pump and stop it from continuously injecting into the core. The inspectors requested that the licensee evaluate the potential scenario of a HPCS reactor overfill event and determine if the plant can achieve and maintain safe shutdown under such a scenario.

As a result of the inspectors concerns, the licensee performed an evaluation as part of EC 386645, Analysis of Reactor Overfill Impact on Main Steam Piping and SRVs

[Safety Relief Valves] Due to Fire Induced Spurious HPCS Operation, Revision 0, and determined that safe shutdown would not be impacted under a HPCS reactor overfill event. The spurious operation of HPCS and a failure of discharge valve 1E22-F004 to close would result in continuous water flow into the reactor. Water and steam would flow through the SRVs rather than steam only as a result of a reactor overfill event.

The licensee determined in calculations IP-M-0792, MSRV [Main Steam Relief Valve]

Discharge Transient Force Analysis for Reactor Overfill, Revision 0, and IP-M-0793, Piping Stress Analysis for SRV Discharge Transient Forces, Revision 0, that there would be no adverse impact on the main steam piping and SRVs as a result of a reactor overfill event.

The licensee concluded that no manual actions were required to control HPCS injection and that safe shutdown could be achieved during a HPCS reactor overfill event.

In calculation IP-M-0792, the licensee calculated the transient hydraulic forces generated in the main steam SRV discharge lines as a result of a reactor overfill event.

The licensee then determined the impact of the transient hydraulic forces on the main steam piping in calculation IP-M-0793. The licensee determined that the SRVs and main steam piping would withstand stresses associated with increased flow of water resulting from a reactor overfill condition. The inspectors reviewed the analyses and the calculated stresses on the SRVs and main stream piping as a result of a HPCS reactor overfill event and did not identify any safety significant findings.

URI 05000461/2005006-01 is closed.

4OA6 Management Meetings

.1 Resident Inspectors Exit Meeting

The inspectors presented the inspection results to W. Noll and other members of the licensees staff at the conclusion of the inspection on April 19, 2012. The licensee acknowledged the findings presented. Proprietary information was examined during this inspection, but is not specifically discussed in this report.

.2 Interim Exit Meetings

Interim exit meetings were conducted for:

The Radiological Hazard Assessment and Exposure Controls; Radioactive Solid Waste Processing; and Radioactive Material Handling, Storage, and Transportation Inspection with Mr. W. Noll and other members of the licensees staff at the conclusion of the inspection on March 2, 2012.

The review associated with URI 05000461/2005006-01, Postulated Fire-Induced Circuit Failures Resulting in Potential Spurious Actuation of Division III HPCS Pump 1E22-C001 and Discharge Valve 1E22-F004, and LER 05000461/2011-001-00, Postulated Spurious High Pressure Core Spray Initiation Result Unanalyzed, with Ms. K. Baker and other members of the licensees staff on February 17, 2012.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements, which meets the criteria of Section 2.3.2 of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation.

.1 Violation of TS 3.4.6 and TS 3.6.1.3 Due to Missed Surveillance of an RCS PIV

TS 3.4.6 requires, in part, that the leakage from each RCS PIV shall be within limits in Modes 1, 2, and 3. TS 3.4.6, Condition A, states that with one or more flow paths with leakage from one or more RCS PIVs not within the limit, isolate the high pressure portion of the affected system from the low pressure portion by use of one closed manual, deactivated automatic, or check valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . TS 3.4.6, Condition B, states that if the required action and associated completion time of Condition A is not met, be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

TS 3.6.1.3 requires, in part, that each primary containment isolation valve be operable in Modes 1, 2, and 3. TS 3.6.1.3, Condition C, states, in part, that with one or more penetration flow paths with leakage rate not within limit, restore leakage rate to within the limit within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . TS 3.6.1.3, Condition E, states, in part, that if the required action and associated completion time of Condition C is not met, be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

Contrary to the above, RCS PIV 1E12-F042C was found with leakage in excess of the limit during leak rate measurement surveillance testing on December 7, 2011.

The licensee determined the cause for the failure was due to wear on the valve guide ribs and excessive disc to rib clearances, such that the disc became cocked when closing and it did not fully seat. In addition, testing of this valve during the previous operating cycle to satisfy TSSR 3.4.6.1 was not correctly performed, for which the licensee had taken action in accordance with TSSR 3.0.3. Based on the cause determination and the previous missed surveillance of 1E12-F042C, the inspectors concluded that this valve had not been capable of performing its specified safety function (and thus was inoperable) for a period of time before its discovery longer than allowed by TS 3.4.6 and TS 3.6.1.3. The inspectors performed a Phase 1 SDP review of this finding using the guidance provided in IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. In accordance with Table 4a, Characterization Worksheet for IE, MS, and BI Cornerstones, the inspectors determined that that this finding was a licensee performance deficiency of very low safety significance (Green) because the finding would not result in exceeding the TS limit for RCS leakage and would not have likely affected mitigation systems resulting in a loss of safety function. In addition, the finding did not represent an actual open pathway in the physical integrity of the reactor containment. Based on consultation and review with the Regional Senior Reactor Analyst, the inspectors concluded that the valve test failure did not result in an increase in the likelihood of an initiating event such as an inter-system LOCA or a containment bypass event because the redundant isolation valve and closed loop system piping passed leak rate measurement testing during the refueling outage with considerable margin.

This violation of TS 3.4.6 and TS 3.6.1.3 is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy. The licensee entered this violation into its corrective action program as AR 01305725. The licensee submitted LER 05000461/2011-006-00 to report this issue as a condition prohibited by TS.

Refer to Section 4OA3.2 of this inspection report for the review and closure of the LER.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

R. Bair, Shift Operations Superintendent

K. Baker, Senior Manager Design Engineering

T. Chalmers, Work Management Director

J. Cunningham, Operations Director

C. Dunn, Regulatory Assurance Manager

R. Frantz, Regulatory Assurance

M. Heger, Mechanical Design Branch Manager

N. Hightower, Radiation Protection Operations Manager

D. Kemper, Engineering Director

K. Leffel, Operations Support Manager

S. Mohundro, Engineering Programs Manager

W. Noll, Site Vice President

T. Parrent, Fire Protection & Appendix J Program Engineer

J. Peterson, Regulatory Assurance

C. Rocha, Nuclear Oversight Manager

J. Smith, Senior Manager Plant Engineering

T. Stoner, Maintenance Director

J. Stovall, Radiation Protection Manager

B. Taber, Plant Manager

J. Ufert, Fire Marshall

T. Veitch, Chemistry Manager

Attachment

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened

05000461/2012002-01 URI Evaluation of Apparent Nonconforming Condition Affecting Circulating Water Pump Auto Stop Feature during a Flooding Event (Section 1R06.b.1)

05000461/2012002-02 NCV Unacceptable Preconditioning of Low Pressure Coolant Injection from Residual Heat Removal A Check Valve Prior to Leak Rate Test Measurement (Section 1R12.b.1)

05000461/2012002-03 URI Incomplete ED Dose Rate Alarm Evaluation (Section 2RS1.2)

05000461/2012002-04 NCV Failure to Incorporate Operating Experience into Preventive Maintenance Activities (Section 4OA2.3.b.2)

Closed

05000461/2012002-02 NCV Unacceptable Preconditioning of Low Pressure Coolant Injection from Residual Heat Removal A Check Valve Prior to Leak Rate Test Measurement (Section 1R12.b.1)

05000461/2012002-04 NCV Failure to Incorporate Operating Experience into Preventive Maintenance Activities (Section 4OA2.3.b.2)

05000461/2011-005-00 LER Missed Surveillance Due To Preconditioning Valve Prior To Leak Rate Test (Section 4OA3.1)

05000461/2011-006-00 LER Condition Prohibited by Technical Specifications Due to Missed Surveillance (Section 4OA3.2)

05000461/2011-004-00 LER Automatic Reactor Scram During Removal of Main Generator (Section 4OA3.3)

05000461/2011-01-00 LER Postulated Spurious High Pressure Core Spray Initiation Result Unanalyzed (Section 4OA3.6)

05000461/2005006-01 URI Postulated Fire-Induced Circuit Failures Resulting in Potential Spurious Actuation of Division III HPCS Pump 1E22-C001 and Discharge Valve 1E22-F004 (Section 4OA5.3)

Discussed

05000461/2009003-01 FIN Failure to Evaluate Safety Function of Suppression Pool Makeup System (Section 4OA2.2.b.3)

05000461/2009004-03 NCV Failure to Update the Final Safety Analysis Report (Section 4OA2.2.b.3)

05000461/2010003-01 NCV Failure to Satisfy 10 CFR 50.72 and 50.73 Reporting Requirements (Section 4OA2.2.b.3)

05000461/2010003-03 FIN Operability Assessment of Inservice Testing Surveillance Discrepancies for Excess Flow Check Valve (Section 4OA2.2.b.3)

05000461/2011004-04 NCV Failure to meet Technical Specification 3.7.3 for Operability of Control Room Ventilation System (Section 4OA2.2.b.3)

05000461/2011004-05 FIN Failure to Evaluate Operability of Control Room Ventilation System for Degraded Flow Condition (Section 4OA2.2.b.3)

Attachment

05000461/2011005-04 NCV Unacceptable Preconditioning of Reactor Core Isolation Cooling System Check Valve Prior to Leak Rate Test Measurement (Section 4OA3.1)

05000461/2011003-02 NCV Failure to Meet Surveillance Testing Requirement for Reactor Coolant System Pressure Isolation Valves (Section 4OA3.2)

Attachment

LIST OF DOCUMENTS REVIEWED

IR 05000461/2012002

Text

SUBJECT:

Dear Mr. Pacilio:

REGION III

SUMMARY OF FINDINGS

NRC-Identified

Cornerstone: Initiating Events

Cornerstone: Barrier Integrity

Licensee-Identified Violations

REPORT DETAILS

Summary of Plant Status

REACTOR SAFETY

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

b. Findings

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

b. Findings

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

b. Findings

1R06 Flooding Protection Measures

.1 Internal Flooding

a. Inspection Scope

b. Findings

1R07 Heat Sink Performance

.1 Annual Heat Sink Performance

a. Inspection Scope

b. Findings

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

b. Findings

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

b. Findings

1R12 Maintenance Effectiveness

a. Inspection Scope

b. Findings

1. Why did the check valve fail the as-found leak rate test? What was the cause?

2. How was the cause for the leak rate test failure corrected?

3. Did the licensee unacceptably precondition the valve by exercising it to get an

4. How was cycling the check valve with a torque wrench considered a repair or

1. Revision to CPS 9843.01 to ensure the correct testing sequence for RCS PIVs to

2. Revision to CPS 9843.01 to provide guidance for engineering evaluation of leak rate

3. Discussion with IST engineering peers regarding check valve exercising not

4. Revision to applicable licensee IST procedure(s) to incorporate corrective actions to

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

b. Findings

1R15 Operability Evaluations

a. Inspection Scope

b. Findings

1R19 Post-Maintenance Testing

a. Inspection Scope

b. Findings

1R22 Surveillance Testing

a. Inspection Scope

b. Findings

RADIATION SAFETY

Cornerstone: Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

.1 Radiological Hazard Assessment (02.02)

a. Inspection Scope

b. Findings

.2 Instructions to Workers (02.03)

a. Inspection Scope

b. Findings

.3 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

b. Findings

.4 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

b. Findings

.5 Risk-Significant High Radiation Area and Very-High Radiation Area Controls (02.06)

a. Inspection Scope

b. Findings