IR 05000461/2009004

IR 05000461-09-004 on 07/01/09 - 09/30/09 for Clinton Power Station, Unit 1

ML093140512
Person / Time
Site:	Clinton
Issue date:	11/10/2009
From:	Ring M NRC/RGN-III/DRP/B1
To:	Pardee C Exelon Generation Co, Exelon Nuclear
References
FOIA/PA-2010-0209 IR-09-004
Download: ML093140512 (66)

Text

mber 10, 2009

SUBJECT:

CLINTON POWER STATION NRC INTEGRATED INSPECTION REPORT 05000461/2009-004

Dear Mr. Pardee:

On September 30, 2009, 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 October 15, 2009, with Mr. M. Kanavos 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 self-revealed and two NRC-identified findings of very low safety significance were identified. Two of these findings were determined to involve violations 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 all were entered into your Corrective Action Program (CAP), the NRC is treating the above violations as Non-Cited Violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy.

If you contest the subject or severity of an NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region 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 the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement to the Regional Administrator, Region III, and the NRC Resident Inspector at Clinton Power Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA Jamie C. Benjamin, Acting For/

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

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket No: 50-461 License No: NPF-62 Report No: 05000461/2009-004 Licensee: Exelon Generation Company, LLC Facility: Clinton Power Station, Unit 1 Location: Clinton, IL Dates: July 1 through September 30, 2009 Inspectors: B. Kemker, Senior Resident Inspector D. Lords, Resident Inspector J. Bozga, Reactor Inspector M. Mitchell, Health Physicist A. Scarbeary, Reactor Engineer S. Mischke, Resident Inspector, Illinois Emergency Management Agency Approved by: M. Ring, Chief Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000461/2009-004, 07/01/09 - 09/30/09, Clinton Power Station, Unit 1, Maintenance

Effectiveness, Operability Evaluations, Surveillance Testing.

This report covers a three-month period of inspection by the resident inspectors and announced baseline inspections by regional inspectors. One Severity Level IV Non-Cited Violation (NCV)and two Green findings, one of which had an associated NCV, 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: Mitigating Systems

Green.

A finding of very low safety significance was self-revealed on May 27, 2009, when fuel pool cooling system flow control valve 1FC004A failed closed. The licensee failed to implement effective corrective actions in response to the same failure mode for the valve that occurred on November 21, 2005. This resulted in the failure of 1FC004A once again and the subsequent loss of inventory from the containment upper pool and inoperability of the suppression pool makeup system. The licensee entered this issue into its corrective action program (CAP) to investigate the cause and to identify appropriate corrective actions. No violation of regulatory requirements was identified.

The finding was of more than minor significance because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and directly affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the May 2009 valve failure resulted in a loss of inventory from the containment upper pool and inoperability of the suppression pool makeup system, therefore impacting its availability for certain initiating events. The finding was of very low safety significance because the issue: (1) was not a design or qualification deficiency; (2) did not represent an actual loss of safety function of a system; (3) did not represent an actual loss of safety function of a single train for greater than its Technical Specification (TS) allowed outage time; (4) did not represent an actual loss of safety function of one or more non-TS trains of equipment designated as risk significant; and (5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors did not identify a cross-cutting area component related to this finding. (Section 1R12.b.1)

Cornerstone: Barrier Integrity

• Severity Level IV, The inspectors identified a Non-Cited Violation of 10 CFR 50.71,

Maintenance of Records, Making of Reports, associated with the licensees failure to correctly update the Updated Final Safety Analysis Report (UFSAR) when modifying TS requirements for the Control Room ventilation system during implementation of Improved Standard Technical Specifications. Specifically, the licensee failed to change the specified safety function description for the system to maintain positive pressure within the Control Room envelope with respect to adjacent areas during all operating modes, except when the system is in the recirculation mode or when the system is in the maximum outside air purge mode. This directly contributed to the licensees failure to correctly evaluate the operability of Control Room ventilation system Train B when the system was unable to maintain the Control Room envelope at a positive pressure relative to adjacent areas while operating in the normal mode. Subsequent evaluation by the inspectors determined that the safety function description in the UFSAR was inaccurate and the system was operable with the degraded/ nonconforming condition.

The licensee entered this violation into its CAP to investigate the cause and to identify appropriate corrective actions.

Because the issue affected the NRCs ability to perform its regulatory function, the violation was reviewed under the traditional enforcement process. In addition, the underlying technical issue was evaluated using the Significance Determination Process.

The finding was determined to be a Severity Level IV violation because it was similar to a Severity Level IV violation example in the NRC Enforcement Policy, Supplement I--

Reactor Operations. The finding would become a more significant safety concern if left uncorrected and was therefore more than a minor concern. Specifically, the failure to correctly evaluate a degraded/nonconforming condition potentially affecting the operability of a system, structure, or component (SSC) required to be operable by TS could reasonably result in an unrecognized condition of an SSC failing to fulfill a safety-related function. Because the Control Room ventilation system supports the radiological barrier function to protect operators inside the Control Room following certain design basis accidents, the inspectors concluded that this issue was associated with the Barrier Integrity Cornerstone. The finding was of very low safety significance because it involved only a degradation of the radiological barrier function provided for the Control Room. The inspectors did not identify a cross-cutting aspect related to this finding. (Section 1R15.b.1)

Green.

The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria V, Instructions,

Procedures, and Drawings, regarding the licensees failure to adequately implement periodic visual inspection requirements per procedure CPS 1019.07,

Leakage Reduction and Monitoring Program, to monitor and minimize leakage from piping systems connecting to the reactor coolant system. The inspectors also identified that the procedure itself was inappropriate to the circumstances because it did not provide for adequate and consistent performance of the piping system visual inspections and did not provide for sufficient objective quality evidence to demonstrate that the program requirements were met. The licensee entered this violation into its CAP to investigate the cause and to identify appropriate corrective actions.

The finding would become a more significant safety concern if left uncorrected and was therefore more than a minor concern. Specifically, the failure to adequately implement required leakage reduction and monitoring program controls to minimize leakage from reactor coolant sources outside of containment that could contain highly radioactive fluids during a serious transient or accident could reasonably result in higher doses to plant workers and higher potential offsite release levels. Because the leakage reduction and monitoring program is intended to contain highly radioactive fluids within piping systems outside containment, which supports the radiological barrier functions to protect plant workers and the public following serious transients or accidents, the inspectors concluded that this issue was associated with the Barrier Integrity Cornerstone.

The finding was of very low safety significance because it involved only a degradation of the radiological barrier function provided for the Auxiliary Building. The inspectors concluded that this finding affected the cross-cutting area of human performance because the licensee did not provide adequate procedural guidance and training to enable operators to correctly perform and document piping system visual inspections to implement its leakage reduction and monitoring program. As a result, the licensee did not have appropriate objective quality evidence to demonstrate that the program requirements were met. (IMC 0305 H.2(c)) (Section 1R22.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 CAP. The violation and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

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

On September 4, 2009, the licensee reduced power to about 82 percent to perform control rod pattern adjustments. The unit was returned to full power later the same day.

On September 13, 2009, the licensee reduced power to about 71 percent to perform control rod pattern adjustments, control rod settle testing, scram time testing, main turbine control/intermediate valve and main steam isolation valve testing. The unit was returned to full power later the same day.

On September 29, 2009, the licensee initiated a plant shutdown required by Technical Specification (TS) 3.4.5, RCS [Reactor Coolant System] Operational Leakage, due to a greater than 2 gallon-per-minute increase in unidentified leakage within the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

After the unit was shut down, the licensee entered the drywell and identified that the leak was from reactor core isolation cooling system inboard steam isolation valve 1F0063 stem packing.

The unit remained shutdown in Mode 4 (Cold Shutdown) at the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness For Impending Adverse Weather Condition - Tornado/High Winds

a. Inspection Scope

Since thunderstorms with potential tornados and high winds were forecast in the vicinity of Clinton Power Station on August 19, 2009, the inspectors reviewed the licensees overall preparations/protection for the expected conditions. The inspectors toured the plant grounds in the vicinity of the main power transformers, unit auxiliary transformers, reserve auxiliary transformer, emergency reserve auxiliary transformer, and static voltage-ampere reactive (VAR) compensators to look for loose debris, which, if present, could become missiles during a tornado or with high winds. During the inspections, the inspectors focused on plant-specific design features and the licensees procedure used to respond to tornado and high winds conditions.

This inspection constituted one readiness for impending adverse weather condition inspection sample as defined in Inspection Procedure (IP) 71111.01.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Standby Liquid Control System following restoration after testing;

• Division 3 Emergency Diesel Generator (single train risk-significant system); and

• Fire Protection Water Train B following restoration after testing.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones. The inspectors reviewed operating procedures, system diagrams, TS requirements, and the impact of ongoing work activities on redundant trains of equipment. The inspectors verified that conditions did not exist that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components were aligned correctly and available as necessary.

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

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

b. Findings

No findings of significance were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

The inspectors performed a complete system alignment inspection of the feedwater system to verify the functional capability of the system. This system was selected because a loss of feedwater event was considered to be a potentially safety-significant initiating event transient. The inspectors walked down the system to review mechanical and electrical equipment lineups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding work orders was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors verified that equipment alignment problems were entered into the licensees CAP with the appropriate characterization and significance.

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

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

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Fire Zone A1-b, Auxiliary Building General Access Area (North) -

Elevation 7370;

• Fire Zone D-4, Division 3 Diesel Generator Room - Elevation 7370;

• Fire Zone M-1, Division 1 Shutdown Service Water Pump Room -

Elevation 6990;

• Fire Zone R-1c, Radwaste [Radioactive Waste] Building General Access Area -

Elevations 7020 and 7200;

• Fire Zone A3-d, Non-Safety Switchgear Room (West) - Elevation 7620; and

• Fire Zone CB 3f, Division 1 Nuclear System Protection System Inverter Room -

Elevation 7810 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 CAP with the appropriate characterization and significance. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

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

b. Findings

No findings of significance were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

During an announced drill on August 12, 2009, associated with the Radwaste Building Ventilation System Equipment Room, the inspectors assessed the timeliness of the fire brigade in arriving at the scene, the fire fighting equipment brought to the scene, the donning of fire protective clothing, the effectiveness of communications, and the exercise of command and control by the fire brigade leader. The inspectors also assessed the acceptance criteria for the drill objectives, the rigor and thoroughness of the post-drill critique, and verified that fire protection drill issues were being entered into the licensee's CAP with the appropriate characterization and significance.

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

b. Findings

No findings of significance were identified.

1R06 Flooding Protection Measures

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk-important plant design features and the licensees 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 service water systems. The inspectors also reviewed the licensees CAP documents with respect to past flooding protection-related issues 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 Pump Rooms;

• Auxiliary Building - Elevation 7070; and

• Radioactive Waste Pipe Tunnel - Elevation 7190.

This inspection constituted two internal flooding inspection samples as defined in IP 71111.06.

b. Findings

(1) Interconnecting Floor Drains Between the Residual Heat Removal (RHR) A Pump Room and Radwaste Pipe Tunnel Introduction The inspectors identified that floor drains in the RHR A Pump Room and the Radwaste Pipe Tunnel were apparently interconnected, which would potentially result in an unanalyzed condition. This issue is considered to be an Unresolved Item pending additional review by the licensee and the inspectors.

Discussion During review of plant drawings for floor drain system piping in the Emergency Core Cooling System (ECCS) and Reactor Core Isolation Cooling Pump Rooms on the 7070 elevation of the Auxiliary Building, the inspectors identified that floor drains in the RHR A Pump Room appeared to be connected via permanent 4 pipe embedded in the floor to floor drains in the Radwaste Pipe Tunnel, which is located along the western wall of the (adjacent) Control Building at the 7200 elevation. The inspectors noted that each of the separate pump rooms was supposedly designed to be isolated from other areas of the plant and not susceptible to flooding from sources external to the pump rooms.

The inspectors discussed this floor drain configuration with the licensee and questioned the adequacy of the design with respect to the potential for flooding. First, if the Radwaste Pipe Tunnel were to flood, would the floodwater in the Tunnel communicate with and cause flooding in the RHR A Pump Room? This could potentially affect operability of the RHR A pump. Second, if the RHR A Pump Room were to flood because of a postulated pump suction line break, would the suppression pool flood water escape the RHR A Pump Room and flow into the radwaste system via the Radwaste Pipe Tunnel? The inspectors noted that Section 3.8.4.1.1 of the UFSAR stated that the ECCS Pump Rooms are in flood protection compartments with watertight doors. In the event of a pipe rupture, the flooding in one compartment will not result in the flooding of any other compartment, and the failure of a pump suction line will not drain the suppression pool. Section D3.6.4 of the UFSAR stated that a postulated failure of any of the non-isolable portions of the ECCS pump suction lines to the suppression pool could result in flooding of a single ECCS cubicle to the high water level in the suppression pool (7315 elevation). If the floor drain piping exists as described by plant drawings and flooding in the RHR A Pump Room (from the suppression pool) were to occur, then the potential exists that cross-flooding could occur between the RHR A Pump Room and the Radwaste Pipe Tunnel. Flooding could potentially continue until the suppression pool level was below the Control Building floor drain level (7206 elevation). This would be below the suppression pool high water level assumed in Section D3.6.4.

At the end of the inspection period, the licensee had just begun investigating the inspectors questions and evaluating the condition. Inspection of the Radwaste Pipe Tunnel found that the floor drains in question were not plugged. No logbook entries were found in the Floor Drain Plug Log to indicate that the drains had been plugged at anytime in the past. The vertical piping which connects the floor drains from the Radwaste Pipe Tunnel to the RHR A Pump Room travels through the Low Pressure Core Spray Pump Room. This pipe was located as mapped on drawing A26-1000-03A at plant coordinates V-124 and the pipe was intact. No historical design change documents were posted against the plant drawings to indicate that the configuration was altered from the original plant design. Original engineering calculation (3C10-0485-001)and the 1990 Flood Analysis did not specifically discuss the potential for flood water entering (or leaving) the RHR A Pump Room via this drain line, although a statement was included which identified that flood water flow through 4 floor drain lines could be estimated at 100 gallons-per-minute (0.22 cubic feet-per-second).

During review, the licensee also discovered that a similar arrangement existed with floor drains on the west side of the Auxiliary Building in that the RHR C Pump Room floor drain piping communicates with the floor drains in the Auxiliary Building Floor Drain Tank Room and Pump Room. Those rooms are located south of the RHR C Pump Room on the other side of the watertight door, at the 7120 elevation.

To address the potential immediate operability concern, the licensee plugged the two floor drains in the Radwaste Pipe Tunnel to prevent communication with the floor drain system in the RHR A Pump Room per an engineering design change. This issue is considered to be an Unresolved Item (URI 05000461/2009004-01) pending additional review and resolution of open questions.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors observed licensed operators during simulator training on August 21, 2009. 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 of significance were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

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):

• Liquid Effluent Process Radiation Monitors;

• Reserve Auxiliary Transformer;

• Control Room, Containment and Plant Chilled Water Chiller Units;

• Spent Fuel Pool Cooling System Flow Control Valve 1FC004A; and

• Nuclear System Protection System.

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the 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 CAP with the appropriate characterization and significance. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

This inspection constituted five maintenance effectiveness inspection samples as defined in IP 71111.12.

b. Findings

(1) Ineffective Corrective Actions for Vibration Induced Stem/Disc Separation of Fuel Pool Cooling System Train 'A' Flow Control Valve 1FC004A Introduction A finding of very low safety significance (Green) was self-revealed on May 27, 2009, when fuel pool cooling system flow control valve 1FC004A failed closed. The licensee failed to implement effective corrective actions in response to the same failure mode for the valve that occurred on November 21, 2005. This resulted in the failure of 1FC004A once again and the subsequent loss of inventory from the containment upper pool and inoperability of the suppression pool makeup system. No violation of regulatory requirements was identified.

Description On May 27, 2009, the fuel pool cooling system Train 'A' flow control valve (1FC004A)failed closed, resulting in reduced makeup flow to the upper containment pool. During the resultant level transient, upper containment pool level lowered below the 8271 elevation, which is the entry condition for TS Limiting Condition for Operation (LCO) 3.6.2.4, Suppression Pool Makeup System, (with the steam dryer storage pool gate not open). Level was restored after about 38 minutes and the LCO action requirement was exited. The inspectors previously reviewed this event and documented a finding in NRC Inspection Report 05000461/2009003 associated with the licensees failure to recognize a potential loss of safety function for the suppression pool makeup system following the loss of upper containment pool inventory.

During this inspection period, the inspectors reviewed the licensees equipment apparent cause evaluation (EACE) for the valve failure (EACE 00924603) and interviewed engineering and mechanical maintenance personnel to understand why the valve failed.

The licensee disassembled the valve and determined that the valves disc had separated from the stem, which restricted flow through the valve and caused the loss of makeup water to the upper containment pool from the fuel pool cooling system surge tank.

The inspectors noted that 1FC004A had experienced this same failure mode on November 21, 2005. After that valve failure occurred, corrective actions were implemented or planned to be implemented to correct the causes identified in the licensees evaluation (EACE 00439211). One specific action item was to review and evaluate the configuration of the fuel pool cooling system at the pump suction to address the vibration issue. The result of this was an engineering review that concluded there was no vibration problem that caused the valve to fail. This conclusion directly contradicted the conclusions of both of the licensees EACEs from the November 2005 and May 2009 valve failures. No additional actions were taken in response to the vibration causal factor identified for the valve failure.

The inspectors concurred with the licensees conclusion in EACE 00924603 that after the 1FC004A valve stem/disc separation failure in November 2005, the system/pump vibration issues had never been adequately addressed by the licensee and that previous corrective actions were ineffective. The inspectors concluded that inadequate corrective actions to address the previously identified condition of system/pump vibration resulted in the subsequent failure of 1FC004A.

Analysis The inspectors determined that the licensees failure to implement effective corrective actions to correct an identified cause for the previous failure of 1FC004A in November 2005 was a performance deficiency warranting a significance evaluation.

The inspectors assessed this finding using the Significance Determination Process (SDP). The inspectors reviewed the examples of minor issues in Inspection Manual Chapter (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 failure to implement effective corrective actions was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The May 2009 valve failure resulted in a loss of inventory from the containment upper pool and inoperability of the suppression pool makeup system, therefore impacting its availability for certain initiating events. 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 this finding was a licensee performance deficiency of very low safety significance (Green) because the finding:

(1) was not a design or qualification deficiency;

(2) did not represent an actual loss of safety function of a system;

(3) did not represent an actual loss of safety function of a single train for greater than its TS allowed outage time;

(4) did not represent an actual loss of safety function of one or more non-TS trains of equipment designated as risk significant; and

(5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

Cross-cutting Aspects The inspectors concluded that the licensees failure to implement effective corrective actions after the November 2005 valve failure did not necessarily reflect current licensee performance because this issue and a potential organizational weakness were self-identified by the licensee in its evaluation for the most recent valve failure.

Therefore, no cross-cutting aspect was identified.

Enforcement No violation of regulatory requirements was identified. This issue is considered to be a finding (FIN 05000461/2009004-02). The licensee entered this finding into its CAP as Action Request (AR) 00924603.

(2) (Closed) URI 05000461/2008005-02, Maintenance Rule Scoping Question for Liquid Effluent Process Radiation Monitors During the fourth quarter of 2008, the inspectors reviewed equipment performance issues associated with radiation monitoring system instrumentation and found that Maintenance Rule evaluations were not being performed for liquid effluent process radiation monitor failures. The inspectors noted that liquid effluent process radiation monitors had not been included within the scope of the licensees Maintenance Rule Monitoring Program and sufficient information or justification was not provided in the licensees scoping determination documents to support the conclusion that was reached.

The inspectors noted that in accordance with 10 CFR 50.65(b)(2)(i), nonsafety-related SSCs that are used in plant Emergency Operating Procedures (EOPs) are required to be included in the scope of the licensees Maintenance Rule Monitoring Program.

The inspectors reviewed the plants EOPs and discovered that the entry condition for EOP-9, Radioactivity Release Control, was any offsite liquid or gaseous release rate above the licensees Emergency Plan Radiological Effluent Alert level. The inspectors reviewed EP-AA-1003, Exelon Nuclear Radiological Emergency Plan Annex for Clinton Station, Revision 13, and found that one of the three Emergency Action Level threshold values under the Emergency Plan Radiological Effluent Alert level was a valid reading on any effluent monitor > 200 times the high alarm setpoint established by a current radioactivity discharge permit for 15 minutes. The inspectors discussed this criterion with two licensed senior reactor operators at the plant (the Shift Operations Superintendent and a Shift Manager) to understand which liquid effluent monitors would be used by operators to evaluate this criterion since no specific monitors were listed in the Emergency Action Level Matrix. Seven liquid effluent radiation monitors were initially identified to the inspectors, but later five monitors were found with specific references to the Emergency Plan Radiological Effluent Alert level and/or EOP-9 in several of the licensees annunciator response and operating procedures. These procedures included:

• CPS 3315.03, Radiation Monitoring, Revision 4a;

• CPS 4979.05, Abnormal Release of Radioactive Liquids, Revision 9a;

• CPS 5140.48, AR/PR [Area Radiation/Process Radiation] Annunciator - Plant Service Water Effluent - 1RIX-PR036, Revision 0;

• CPS 5140.50, AR/PR Annunciator - SX [Shutdown Service Water] Service Water Effluent A - 1RIX-PR038, Revision 0a;

• CPS 5140.51, AR/PR Annunciator - SX Service Water Effluent B -

1RIX-PR039, Revision 0a;

• CPS 5140.52, AR/PR Annunciator - FC [Fuel Pool Cooling] HX [Heat Exchanger] 1A Clg [Cooling] Wtr [Water] Effluent - 1RIX-PR004, Revision 0a; and

• CPS 5140.53, AR/PR Annunciator - FC HX 1B Clg Wtr Effluent - 1RIX-PR005, Revision 0a.

During discussions with licensed operators and with engineers, the inspectors received conflicting information regarding use of the liquid effluent radiation monitors for entry into EOP-9. The licensee wrote AR 00854497 to address questions raised by the inspectors regarding scoping of these liquid effluent process radiation monitors within its Maintenance Rule Monitoring Program and the inspectors opened URI 05000461/2008005-02 pending additional review.

The licensee subsequently determined that the above procedures incorrectly referenced and/or directed licensed operators to enter the Emergency Plan Radiological Effluent Alert level and/or EOP-9 based upon readings or alarms on the liquid effluent radiation monitors. The licensee concluded that entering the Emergency Plan Radiological Effluent Alert level and EOP-9 should be based upon the results of confirmatory grab samples taken after the liquid effluent radiation monitors showed increased levels or alarmed, but not solely based upon indications from the monitors. Therefore, the licensee also concluded that the nonsafety-related liquid effluent radiation monitors did not provide a significant mitigating function and should not be included in the scope of its Maintenance Rule Monitoring Program. The licensee revised the above procedures to remove references to the Emergency Plan Radiological Effluent Alert level and/or EOP-9. The Shift Operations Superintendent has provided a briefing to senior reactor operators on the liquid effluent radiation monitors and their relationship to the Emergency Plan Radiological Effluent Action Levels and EOP-9.

Title 10 CFR 50, Appendix B, Criteria V, Procedures, Instructions, 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.

Contrary to the above, the inspectors concluded that the aforementioned procedures were inappropriate to the circumstances because they provided incorrect guidance and direction for licensed operators to take in response to a potential release of liquid radioactivity to the environment since the procedures incorrectly referenced and/or directed licensed operators to enter the Emergency Plan Radiological Effluent Alert level and/or EOP-9 based upon readings or alarms on liquid effluent radiation monitors.

However, the inspectors could not envision any event scenario in which licensed operators would incorrectly declare an Alert and/or take inappropriate actions in response to an event based solely upon readings or alarms from the liquid effluent radiation monitors. Therefore, the inspectors concluded that this finding constitutes a violation of minor significance and it is not subject to formal enforcement action in accordance with Section IV of the NRC's Enforcement Policy. The licensee entered this violation into its CAP as AR 00905767. URI 05000461/2008005-02 is closed.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

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 July 7th to replace a Division 3 Nuclear System Protection System Logic Card;

• Emergent maintenance on July 28th following loss of the 138 Kilovolt line supplying the Emergency Reserve Auxiliary Transformer;

• Planned maintenance during the week of September 21st through 25th on the Division 3 Emergency Diesel Generator and Shutdown Service Water System;

• Emergent maintenance following a leak discovered on the Makeup Demineralizer Sump Underground Pipe to the Reaction Tank.

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

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

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

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• AR 00945313, Main Control Room Ventilation Differential Pressure Slightly Negative When on Train B in Normal Mode; and

• URI 050002009003-02, Review of Excess Flow Check Valve Operability Evaluation in Lieu of Testing.

The inspectors selected these potential operability issues based on the risk significance of the associated SSCs. The inspectors verified that the conditions did not render the associated SSCs 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 SSCs 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.

In addition, the inspectors verified that problems related to the operability of SSCs required to be operable by TS were entered into the licensees CAP with the appropriate characterization and significance. Selected action requests were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

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

b. Findings

(1) Control Room Ventilation System Train B Unable to Maintain the Control Room at a Positive Pressure Relative to Adjacent Areas While Operating in Normal Mode Introduction The inspectors identified a Severity Level IV, Green, Non-Cited Violation of 10 CFR 50.71, Maintenance of Records, Making of Reports, having very low safety significance. The licensee failed to correctly update the UFSAR when modifying TS requirements for the control room ventilation system during implementation of Improved Standard Technical Specifications (ITS) in License Amendment No. 95.

Specifically, the licensee failed to change the specified safety function description for the system to maintain positive pressure within the Control Room envelope with respect to adjacent areas during all operating modes, except when the system is in the recirculation mode or when the system is in the maximum outside air purge mode.

This directly contributed to the licensees failure to correctly evaluate the operability of Control Room ventilation system Train B when the system was unable to maintain the Control Room envelope at a positive pressure relative to adjacent areas while operating in the normal mode. Subsequent evaluation by the inspectors determined that the safety function description in the UFSAR was inaccurate and the system was operable with the degraded/nonconforming condition.

Description On July 23, 2009, the licensee identified that the Control Room ventilation system was unable to maintain the Control Room pressure greater than or equal to 0.125 inches water positive with respect to adjacent areas (i.e., +0.125 in. H2O differential pressure)with the B Train running in the normal mode. The condition identified by operators was that the system was operating with a slightly negative differential pressure. This was not in conformance with the design basis description in the UFSAR. Section 9.4.1.1.1, Safety Design Bases, Paragraph (c), stated that [t]he system is designed to maintain a positive pressure within the Control Room envelope with respect to the adjacent areas to preclude infiltration of unconditioned air, during all the operating modes except when the system is operating in recirculation mode or when the system is in the maximum outside air purge mode. Section 6.4.1, Design Basis, Paragraph (h), stated, in part, that

[d]uring normal operation, up to approximately 4,000 cubic feet per minute of outside air is introduced into the Control Room envelope to maintain greater than or equal to 0.125 in. H2O positive pressure with respect to the surrounding areas. The Operations Shift Manager requested that an operability evaluation be performed to validate that Control Room ventilation system Train B and the Control Room envelope would be operable while the system was running in the normal mode with a negative differential pressure.

In response to the Shift Managers request for an operability evaluation, the licensee drafted a functionality assessment, which concluded that the ability of the Control Room ventilation system to perform its TS function was not impacted and that only the UFSAR function to maintain positive pressure was impacted. The licensee therefore concluded that the system was fully operable. The inspectors reviewed the functionality assessment, discussed it with the licensee, and concluded that the licensee had failed to correctly address the operability question. In the functionality assessment, the licensee identified three safety functions described in the UFSAR for the Control Room ventilation system. Those safety function were:

(1) to maintain positive pressure during normal and high radiation (accident) conditions;

(2) to maintain Control Room temperature within design limits in normal and accident conditions; and,

(3) to assure that the dose to the operators inside the Control Room is within the limits specified by 10 CFR 50, Appendix A, Criterion 19, Control Room, for the duration of a design-basis accident.

The latter two functions were also described in the TS Bases for TS 3.7.3 and TS 3.7.4, but the first one was not. The licensee concluded in the functionality assessment that the capability of the Control Room ventilation system to maintain positive pressure during normal mode operating conditions was not required for the system to be considered operable because the function was not described in the TS Bases.

Based upon review of the design basis description in the UFSAR, the inspectors disagreed with the licensees conclusion that the capability of the Control Room ventilation system to maintain positive pressure during normal mode operating conditions was not required for the system to be considered operable. The inspectors also disagreed with the licensees distinction between a TS function and an UFSAR function for the purpose of evaluating the operability of a system required to be operable by the plants TS and found the licensees use of a functionality assessment in lieu of an operability evaluation was questionable. The inspectors disagreed with the licensees approach to evaluate functionality versus operability because the licensee had not yet determined the actual cause of the degraded/nonconforming condition; therefore, the potential impact on the systems specified safety functions was not definitively known. The inspectors also believed that the licensees distinction between a TS function and an UFSAR function was not consistent with the definition of Operable/Operability in the TS (i.e., capable of performing its specified safety function(s)). The inspectors reviewed the guidance contained in NRC Regulatory Issue Summary 2005-20, Revision to NRC Inspection Manual Part 9900 Technical Guidance, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, Revision 1; and, noted that in Section 3.10, Specified Function/Specified Safety Function, the specified function(s) of the system, subsystem, train, component or device is that specified safety function(s) in the current licensing basis for the facility.

The current licensing basis for the facility includes not only the TS Bases, but also the UFSAR. In addition, the inspectors noted that in Section 2.1, Scope of SSCs for Operability Determinations, Paragraph (a), that the scope of SSCs considered within the operability determination process included SSCs required to be operable by TS; and, in Section 2.2, Scope of SSCs for Functionality Assessments, that functionality assessments should be performed for SSCs not described in TS, but which warrant programmatic controls to ensure that SSC availability and reliability are maintained.

The inspectors questioned the licensees conclusion because the capability of the Control Room ventilation system to maintain the Control Room envelope in either the normal or high radiation modes at a positive pressure with respect to adjacent areas was described as a safety function in Section 9.4.1.1.1 of the UFSAR as well as in the licensees functionality assessment. Because Control Room ventilation system Train B was unable to meet this safety function, the licensee should have concluded that it was inoperable without a compensatory measure in place for the degraded/nonconforming condition. The licensee implemented a compensatory measure by propping open a door within the Control Room ventilation system envelope to restore pressure above

+0.125 in. H2O and maintain the B Train operable while operating in the normal mode.

The licensee tested Control Room ventilation system Train 'B' in the high radiation mode to demonstrate that it would maintain sufficient positive pressure. The inspectors therefore concluded that the system was operable, but degraded, with the compensatory measure in place.

The inspectors discussed the degraded/nonconforming condition of Control Room ventilation system Train B, the use of a functionality assessment in lieu of an operability evaluation to address an operability question, and the apparent incorrect conclusion reached by the licensee in the functionality assessment with the stations Nuclear Oversight Manager. In response to the inspectors questions, Nuclear Oversight reviewed the functionality assessment and determined that the licensee had not followed procedure OP-AA-108-115, Operability Determinations, Revision 9, because the use of a functionality assessment to address a degraded/nonconforming condition of an SSC described in TS appeared to be contrary to the procedures requirements since the procedure stated that the scope of SSCs considered within the operability determination process were those SSCs required to be operable by TS and that the Control Room ventilation system fell within this description. Nuclear Oversight further stated that the impact of this issue was that the condition was not evaluated per the full rigor of an operability evaluation and that the assessment did not consider the system to be nonconforming with respect to a portion of the current licensing basis. Nuclear Oversight documented its observations in AR 00950377.

On August 17th, the inspectors identified that with the compensatory measure still in place and with the B Train running in the normal mode, the Control Room ventilation system was again unable to maintain Control Room pressure above +0.125 in. H2O and questioned the Control Room operators. It appeared to the inspectors that the B Trains performance had further degraded and it might not be operable. The licensee documented the problem in an action request (AR 00954428); however, the licensee again failed to correctly address the operability question by relying on the conclusion from the functionality assessment in its prompt operability determination. The inspectors were still concerned because the licensee had not yet determined the actual cause of the degraded/nonconforming condition.

In response to the inspectors questions, the licensee completed an operability evaluation on August 21st. The inspectors reviewed the operability evaluation, discussed it with the licensee, and concurred with the licensees conclusion that the Control Room ventilation system was operable but degraded. However, the inspectors did not concur with the incorrect reasoning applied by the licensee to reach its conclusion. As with the functionality assessment, the licensee failed to consider that the specified safety function(s) may be described not only in the TS Bases, but also elsewhere in the current licensing basis. The evaluation concluded that the B Control Room ventilation train was operable because the degraded condition had no impact on the TS function, and that only the UFSAR function to maintain positive pressure was impacted. The operability evaluation again identified the same three safety functions described in the UFSAR, but stated that the capability of the Control Room ventilation system to maintain positive pressure during normal mode operations was not required for the system to be considered operable because the function was not described in the TS Bases.

During discussions with the engineer who authored the operability evaluation, the inspectors learned that the capability of the Control Room ventilation system to maintain a positive pressure in the normal mode of operation at the beginning of a design-basis accident was not assumed or credited in the UFSAR Chapter 15, Accident Analyses, or in any of the supporting analyses or calculations. So, according to the licensee, although the UFSAR in Chapter 9 described a safety function for the system to maintain positive pressure during all operating modes except when the system is in the recirculation mode or when the system is in the maximum outside air purge mode, that description was incorrect. During the licensees implementation of ITS, only the requirements for the high radiation mode of operation and the heat removal function of the normal mode of operation were retained in the TS based on the screening criteria; however, the licensee failed to correctly update the UFSAR to reflect the revised safety function description for the system. The inspectors therefore concluded that while the system was operable, the operability evaluation reached that conclusion for the wrong reason and the descriptions of the systems safety functions in the UFSAR, the functionality assessment, and the operability evaluation were incorrect. The licensee wrote AR 00965450 to address the aforementioned inaccuracies with the UFSAR and the operability evaluation.

At the end of this inspection period, the licensee was troubleshooting the problem with Control Room ventilation system Train B and was maintaining the compensatory measures in place so that the system would maintain Control Room pressure above

+0.125 in. H2O in normal mode as described in the UFSAR.

Analysis The inspectors determined that the failure to update the UFSAR to reflect the revised safety function description for the Control Room ventilation system was a performance deficiency warranting a significance evaluation. Because violations of 10 CFR 50.71 are considered to be violations that potentially impede or impact the regulatory process, they are dispositioned using the traditional enforcement process. This issue was determined to be a Severity Level IV violation since it was similar to a Severity Level IV violation example in the NRC Enforcement Policy. Specifically, NRC Enforcement Policy, Supplement 1, Example D6, states, A failure to update the FSAR as required by 10 CFR 50.71(e) in cases where the erroneous information is not used to make an unacceptable change to the facility or procedures.

In accordance with Section 7.3 of the NRC Enforcement Manual, the underlying technical issue was also evaluated under the SDP to determine the severity level of the violation. In this case, the inspectors determined that the underlying technical issue involved the licensees failure to correctly evaluate the operability of Control Room ventilation system Train B with an identified degraded/ nonconforming condition.

The inspectors reviewed the examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, and found two examples related to this issue. Examples 3j and 3k concluded that issues are generally not considered to be of minor significance when evaluation errors result in a reasonable doubt about the operability of a system or component, or when significant programmatic deficiencies are identified that could lead to worse errors if uncorrected. Consistent with the guidance in 0612, Appendix B, Issue Screening, the inspectors determined that the failure to correctly evaluate a degraded/nonconforming condition potentially affecting the operability of an SSC required to be operable by TS would become a more significant safety concern if left uncorrected and was therefore more than a minor concern, because it could reasonably result in an unrecognized condition of an SSC failing to fulfill a safety-related function. Because the Control Room ventilation system supports the radiological barrier functions to protect operators inside the Control Room following certain design basis accidents, the inspectors concluded that this issue was associated with the Barrier Integrity 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 involved only a degradation of the radiological barrier function provided for the Control Room.

Cross-Cutting Aspects The inspectors concluded that because the licensees failure to update the UFSAR to revise the safety function description for the Control Room ventilation system originated with the issuance of Amendment No. 95 for ITS in December 1994, it did not necessarily reflect current licensee performance and no cross-cutting aspect was identified.

Enforcement Title 10 CFR 50.71(e) requires, in part, that the licensee periodically update the UFSAR originally submitted as part of the application for the operating license to assure that the information included in the UFSAR contains the latest material developed. Contrary to the above, the licensee failed to correctly update the UFSAR when modifying TS requirements for the Control Room ventilation system following the issuance of License Amendment No. 95 for ITS on December 2, 1994. Specifically, the licensee failed to change the specified safety function description for the system in Section 9.4.1.1.1, Safety Design Bases, to maintain a positive pressure within the Control Room envelope with respect to adjacent areas during all operating modes except when the system is in the recirculation mode or when the system is in the maximum outside air purge mode to reflect the change to the TS requirements.

Because the underlying technical issue was of very low safety significance, this violation is being treated as a Severity Level IV, Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000461/2009004-03). The licensee entered this violation into its CAP as AR 00965450.

(2) (Closed) URI 05000461/2009003-02, Review of Excess Flow Check Valve Operability Evaluation In Lieu of Testing The licensee identified that nine excess flow check valves were incorrectly removed from its Inservice Testing Program in 2002. The valves have a safety function to re-open following a design basis accident to provide instrumentation assumed to be available post-accident. The valves had not been tested since the licensees refueling outage in 2000. The licensee successfully completed testing one of the check valves that could be tested with the unit on line, completed a risk evaluation, and scheduled the performance of the other eight missed surveillance tests in the next refueling outage. The licensee concluded that testing of the remaining eight valves would require cold shutdown conditions. The inspectors questioned the operability of the valves in lieu of testing since multiple test intervals had elapsed. Subsequently, the licensee revised the calculation defining the design basis function for the excess flow check valves to remove the active safety function of five of the check valves. Of the remaining four check valves that have an active safety function (1CM002B, 1E22-F332, 1E51-F377B, and 1SM008),one check valve (1E22-F332) was tested satisfactorily. The inspectors reviewed the licensees operability evaluation for the remaining three check valves and discussed the evaluation with the licensees staff. The inspectors did not believe that the licensees supporting basis for a reasonable expectation of operability provided a high degree of confidence that the valves remained operable; however, without actually testing the valves the inspectors were unable to prove that the valves were not operable.

The licensee subsequently tested the three valves satisfactorily during an unplanned forced outage that began on September 29th. Refer to Section 4OA7.1 of this report for details of the licensee-identified violation. URI 05000461/2009003-02 is closed.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• Planned maintenance to rebuild the Hydraulic Control Unit for Control Rod 16-09;

• Unplanned maintenance on Reactor Core Isolation Cooling System Valve 1E51-F077;

• Planned maintenance on the Division 3 Emergency Diesel Generator Fuel Oil Priming Pump; and

• Planned maintenance on the Division 3 Emergency Diesel Generator.

The inspectors reviewed the scope of the work performed and evaluated the adequacy of the specified PM testing. The inspectors verified that PM 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 verified that problems associated with PM testing were entered into the licensees CAP with the appropriate characterization and significance.

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

This inspection constituted four PM testing inspection samples as defined in IP 71111.19.

b. Findings

No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage Activities - Crane and Heavy Lift Inspection (OpESS FY 2007-03)

a. Inspection Scope

From June 22, 2009, through July 10, 2009, the inspector reviewed the licensees control of heavy loads program in conjunction with the NRCs Operating Experience Smart Sample (OpESS) FY2007-03, Revision 2, Crane and Heavy Lift Inspection, Supplemental Guidance for IP-71111.20, specifically related to the removal and installation of the reactor vessel head during refueling outages. The inspector performed the following activities listed below during the inspection.

• Reviewed the containment polar crane inspection, maintenance, and testing program;

• Reviewed a sample of records of reactor pressure vessel head strongback and dryer/separator strongback inspections completed prior to reactor disassembly and reactor head lift;

• Reviewed licensees submittals and commitments related to Generic Letters80-113 and 81-07, Control of Heavy Loads;

• Reviewed licensees procedures that control the total weight lifted by the containment building crane to remove and install the reactor vessel head during refueling operations and the Containment Building crane rated lift capacity;

• Reviewed licensees calculations of rigging and special lifting devices used to remove and install the reactor vessel head during refueling operations;

• Reviewed licensees procedures that control reactor vessel safe load path to remove and install the reactor vessel head during refueling operations;

• Reviewed licensees procedures that provide training and qualification of containment building crane operators;

• Reviewed licensees preventative maintenance program procedures of rigging and special lifting devices used to remove and install the reactor vessel head during refueling operations; and

• Reviewed licensees structural calculations for Containment Building crane and Containment Building crane trolley design to Seismic Category I requirements.

This inspection constituted one refueling outage inspection sample as defined in IP 71111.20.

b. Findings

(1) Reactor Pressure Vessel Head Strongback, Dryer/Separator Strongback and Reactor Pressure Vessel (RPV) Lifting Lugs Did Not Demonstrate Single Failure Proof Requirements of NUREG 0612, Control of Heavy Loads at Nuclear Power Plants, Section 5.1.6.

Introduction The inspectors identified an Unresolved Item concerning whether the design of the RPV head strongback, dryer/separator strongback and RPV head lifting lugs was in conformance with the licensing and design basis for single failure proof requirements of NUREG 0612, Section 5.1.6. Specifically, the RPV head strongback, dryer/separator strongback and RPV head lifting lugs did not meet design factors of safety versus yield and ultimate strengths consistent with the guidelines of NUREG 0612, Section 5.1.6.

Description The inspectors reviewed the following licensee submittals:

1. Illinois Power Letter U-0249 L30-81 (06-19)-L to NRC, Subject: December 22, 1980, letter on Control of Heavy Loads, June 22, 1981; 2. Illinois Power Letter U-0294 L30-81 (09-25)-L to NRC, Subject: Clinton Power Station Units 1 and 2 Docket Nos. 50-461 and 50-462, September 25, 1981;

3. Illinois Power Letter U-06850982-L L30-83 (12-21)-L to NRC, Subject: Clinton

Power Station Unit 1 Control of Heavy Loads (NUREG-0612), December 21, 1983; and

4. Illinois Power Letter U-0800 L30-85(02-21)-6 B48-85(02-21)-6 1A.120 to NRC,

Subject: Clinton Power Station Unit 1 Control of Heavy Loads (NUREG-0612),

February 21, 1985.

As a result of this review, the inspectors identified several assurances from the licensee that the RPV head strongback, dryer/separator strongback and RPV head lifting lugs were in conformance with the single failure proof requirements of NUREG 0612, Section 5.1.6.

• The letter dated June 22, 1981, identified the RPV head strongback and dryer/separator strongback as carrying heavy loads such as the RPV head, drywell head, steam dryer and steam separator over safety-related equipment.

The licensee had evaluated the hazard of either of the RPV head strongback or dryer separator being dropped as a heavy load over safe shutdown equipment and determined the likelihood of handling system failure for this load is extremely small (i.e., Section 5.1.6 NUREG 0612 satisfied).

• The letter dated September 25, 1981, responded to an NRC request to provide an evaluation of the lifting devices for each single-failure-proof handling system with respect to the guidelines of NUREG 0612, Section 5.1.6. The licensees response was that the two lifting devices are currently anticipated to be used to accomplish lifts with the polar crane over the refueling floor. Both are supplied by General Electric. They are the steam separator/dryer strongback and the RPV head carousel strongback. Each strongback is provided with four lift points to the load. General Electric states that two of the four attachments are capable of supporting the load. A single failure is considered as the loss of one lift point only. The strongbacks are attached to the polar crane redundant sister hook through the use of a hook box on top of the strongbacks and through two six-inch-diameter link pins. General Electric terms the strongbacks single-failure proof.

• The letter dated September 25, 1981, responded to an NRC request to provide an evaluation of the interfacing lift points with respect to the guidelines of NUREG 0612, Section 5.1.6. The licensees response was that the four lifting lugs are used on the RPV head. After failing two lugs, each of the remaining two lugs would have to support 63,100 pounds. These two remaining lugs are assumed to be opposed on the head so that the head would remain level.

Based on a tensile strength of 80,000 psi and a cross-sectional analysis on the lug only 18 inches squared, the remaining two lugs in cross-section have a design margin of approximately 22. The cross-sectional area above also applies to the steam separator and the steam dryer lugs.

• The letter dated December 21, 1983, responded to an NRC request, which stated that the dryer/separator strongbacks load test does not meet the formal requirements of a 150 percent test. The 125 percent load test may be acceptable, however, more information should be provided. Basically, if the device is Single-Failure-Proof, a description of the device and the meaning of the load test is needed. If the device isnt Single-Failure-Proof, the device description should be accompanied by a discussion of potential load drop consequences. The licensees response was that the strongback will be upgraded to a factor of safety of ten in compliance with Section 5.1.6(1a),

Single Failure Proof Handling Systems, of NUREG-0612.

• The letter dated February 21, 1985, responded to an NRC request to confirm the actual number of special lifting devices. Verify that each meets American National Standards Institute (ANSI) N14.6-1978 and all are designed for static plus maximum dynamic loads. The licensees response was two special lifting devices will be used at Clinton, the RPV head strongback and the RPV dryer/separator strongback, both of which have been designed and supplied by General Electric to accomplish their intended reactor vessel servicing and refueling functions. Both strongbacks are designed to be single failure proof and should adequately comply with NUREG 0612, Paragraph 5.1.1(4).

The inspectors were concerned that the RPV head strongback, dryer/separator strongback and RPV head lifting lugs did not meet design factors of safety versus yield and ultimate strengths consistent with the guidelines of NUREG 0612, Section 5.1.6.

In order to meet the intent of NUREG 0612, Section 5.1.6, the following design factors were satisfied:

(a) Provide redundancy or duality such that a single lift point failure will not result in uncontrolled lowering of the load; lift points should have a design safety factor with respect to ultimate strength of five times the maximum combined concurrent static and dynamic load after taking the single lift point failure. Additionally, the device should have a design safety factor with respect to yield strength of three after taking the single lift point failure; or

(b) a non-redundant or non-dual lift point system should have a design safety factor of ten times the maximum combined concurrent static and dynamic load. Additionally, the device should have a design safety factor with respect to yield strength of six. If the design factors were not satisfied, these guidelines require that entire heavy load path be analyzed for a heavy load drop and the results show that dropping a heavy load such as the RPV head, drywell head, steam dryer and steam separator did not create an unacceptable risk. The intent was to ensure safe handling of heavy loads in areas where a load drop could impact fuel in the reactor core, or equipment that may be required to achieve safe shutdown or permit continued decay heat removal.

In response to the concern, the licensee initiated AR 00938280 on July 2, 2009.

This issue is considered an Unresolved Item (URI 05000461/2009004-04)pending additional inspector discussion with the Office of Nuclear Reactor Regulation staff to determine licensing basis requirements for Clinton Power Station, specifically whether these lifting devices needed to meet NUREG 0612 Section 5.1.6.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• CPS 9051.01, High Pressure Core Spray System Pump and High Pressure Core Spray Water Leg Pump Operability, (Inservice Test);

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

• CPS 1019.07, Leakage Reduction and Monitoring Program, (RCS Leakage Detection);

• CPS 9015.01, Standby Liquid Control System Operability, (Inservice Test);

• CPS 9080.25, DG [Diesel Generator] 1B Test Mode Override, Load Reject Operability, and Idle Speed Override; and

• CPS 9843.01V020, Leak Rate Testing of HPCS [High Pressure Core Spray] Full Flow Test Line.

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 the safety analysis and design basis assumptions, and that test acceptance criteria were satisfied.

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

This inspection constituted two In-Service Test, two RCS leakage detection, and two routine surveillance tests for a total of six inspection samples as defined in IP 71111.22.

b. Findings

(1) Failure the Adequately Implement Requirements of the Leakage Reduction and Monitoring Program Introduction The inspectors identified a finding of very low safety significance (Green) with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, regarding the licensees failure to adequately implement periodic visual inspection requirements to monitor and minimize leakage from piping systems connecting to the RCS.

Description The inspectors reviewed the licensees implementation of the leakage reduction and monitoring program for reactor coolant sources outside of containment required by TS 5.5.2. This program provides controls to minimize leakage from portions of piping systems outside of containment that could contain highly radioactive fluids during a serious transient or accident to levels as low as practicable, thereby limiting dose to plant workers and potential offsite release levels. As part of the program requirements, the licensee performed visual inspections of piping systems connecting to the RCS using individual work orders (WO) for each system/train to identify sources of leakage.

During this inspection, the inspectors identified several instances where the licensee failed to correctly implement the procedural requirements in CPS 1019.07, Leakage Reduction and Monitoring Program, Revision 4c, while conducting visual inspections of the piping systems. The inspectors also identified that the procedure itself was inappropriate to the circumstances because it did not provide for adequate and consistent performance of the piping system visual inspections and did not provide for sufficient objective quality evidence to demonstrate that the program requirements were met. For example:

(a) The inspectors identified multiple examples where the piping system inspection boundaries were not clearly described in the completed test packages to enable reviewers to ascertain whether program requirements for visual inspections were met.

The inspectors reviewed UFSAR, Appendix D, Requirements Resulting from TMI-2

[Three Mile Island Unit 2] Accident,Section III.D.1.1, Integrity of Systems Outside Containment Likely to Contain Radioactive Material, which specified the regulatory requirements for the leakage reduction and monitoring program, and noted that the inspection boundaries for applicable systems connecting with the RCS included in the program were clearly described. The inspectors found that in many of the completed test packages, the only descriptions of the inspection boundaries on the data sheets were for those portions of the systems that were not visually inspected for leakage.

Some of the completed test packages referenced highlighted portions of plant piping drawings or Appendix A worksheets that were not attached to the completed test packages to describe the portions of the piping systems that were visually inspected.

The licensee had no expectation to maintain these drawings and worksheets as part of the quality records. Completed test packages for the reactor core isolation cooling system (WO 01055288-01) and RHR Train B (WO 01030493-01) contained no information in the inspection boundary portion of the data sheets. The inspectors noted that Step 8.2.1.2.b in CPS 1019.07 required the licensee to complete a data sheet for each system inspected. With only two exceptions, the inspectors were unable to tell by reviewing the completed test packages whether completed visual inspections met the program requirements due to inadequate, incomplete test documentation.

Specific examples included: WO 00916590-01, dated October 15, 2007; WO 00972149-01, dated April 22, 2008; WO 01015198-01, dated September 17, 2008; WO 01047559-01, dated January 6, 2009; WO 00916896-01, dated October, 15, 2007; WO 00909779-01, dated January 14, 2008; WO 00909780-01, dated January 14, 2008; WO 01055288-01, dated November 5, 2008; WO 01030493-01, dated December 11, 2008; WO 00909781 01, dated January 12, 2008; WO 01057104-01, dated February 18, 2009; WO 01104245 01, dated March 5, 2009; and WO 00975345-01, dated July 29, 2008.

(b) The inspectors noted that CPS 1019.07 allowed excluding some portions of the piping systems from visual inspection. Step 2.1.2 stated, in part, that, portions of systems located inside the Auxiliary Building may not require an inspection due to the limited accessibility of these areas and because of ALARA [as low as reasonably achievable] considerations. This exclusion appeared to be consistent with the licensees commitment to implement its leakage reduction and monitoring program as described in the UFSAR.Section III.D.1.1 of the UFSAR provided such an allowance, but stipulated that leakage is detected by direct observation where practical and that when ALARA or other considerations dictate, leakage will be collected. However, the licensees procedure did not provide appropriate guidance to enable operators to appropriately and consistently determine which portions of the piping systems could be excluded from visual inspections due to ALARA or other considerations. As a result, the inspectors found inconsistencies with the areas excluded from the piping system inspections that could not be explained by the licensee and no justifications were provided in the completed test packages for the areas excluded. For example, the inspectors noted that the hydrogen recombiner system piping in the Reactor Water Cleanup Mezzanine was excluded from visual inspection, presumably for ALARA considerations (WO 01104245-01 and WO 01057104-01); however, Train A RHR system piping in the Reactor Water Cleanup Mezzanine was visually inspected (WO 00975346-01). In addition, the Train A hydrogen recombiner piping on the 737 elevation of the Auxiliary Building was visually inspected, but the Train B hydrogen recombiner piping on the 737 elevation of the Auxiliary Building was not visually inspected.

(c) The inspectors identified that CPS 1019.07 lacked sufficient details to ensure that the licensees leakage reduction and monitoring program would be implemented correctly. The procedure did not identify which portions of the piping systems could be excluded for ALARA or other considerations, did not define dose and/or dose rate limits for piping system inspections that would justify their exclusion, did not provide any examples or other guidance describing what would be acceptable other considerations for excluding portions of piping systems from visual inspections other than limited accessibility, did not identify which portions of the piping systems could be excluded because of limited accessibility, and did not provide any steps or guidance to ensure that leakage would be collected for any portions of the piping systems excluded from visual inspections.

(d) The inspectors identified multiple examples where some portions of the piping systems were not visually inspected and no evaluation was completed as required by the licensees procedure. The inspectors noted that CPS 1019.07, Steps 4.2 and 8.2.1.2.g stated, in part, that, if the entire system cannot be inspected, document the reason on the data sheet and evaluate the leakage potential and alternate methods of leakage detection. However, the licensee did not document the reason on the data sheet and did not perform an evaluation for any portions of the piping systems that were not visually inspected. Specific examples included: WO 00916590-01, dated October 15, 2007; WO 01055288-01, dated November 5, 2008; WO 01030493-01, dated December 11, 2008; WO 01057104-01, dated February 18, 2009; WO 01104245-01, dated March 5, 2009; and WO 00975345-01, dated July 29, 2008.

Analysis The inspectors determined that the licensees failure to adequately implement the leakage reduction and monitoring program for reactor coolant sources outside of containment was a licensee performance deficiency warranting a significance evaluation. The inspectors assessed this finding using the SDP. 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, Appendix B, Issue Screening, the inspectors determined that a failure to correct these leakage reduction and monitoring program procedure implementation issues could become a more significant safety concern if left uncorrected and was therefore more than a minor concern because it could reasonably result in higher doses to plant workers and higher potential offsite release levels. Because the leakage reduction and monitoring program is intended to contain highly radioactive fluids within piping systems outside containment, which supports the radiological barrier functions to protect plant workers and the public following serious transients or accidents, the inspectors concluded that this issue was associated with the Barrier Integrity Cornerstone. The inspectors performed a Phase 1 SDP review of this finding using the guidance provided in IMC 0609, 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 involved only a degradation of the radiological barrier function provided for the Auxiliary Building.

Cross-Cutting Aspects The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, the licensee did not provide adequate procedural guidance and training to enable operators to correctly perform and document piping system visual inspections to implement its leakage reduction and monitoring program. As a result, the licensee did not have appropriate objective quality evidence to demonstrate that the program requirements were met. (IMC 0305 H.2(c))

Enforcement Title 10 CFR 50, Appendix B, Criteria 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.

Contrary to the above:

(a) The licensee failed to implement the requirements of CPS 1019.07, Leakage Reduction and Monitoring Program, Revision 4c. Specifically, the licensee failed on multiple occasions to document the reason on the procedure data sheet and to evaluate the leakage potential and alternate methods of leakage detection when excluding portions of the piping systems from visual inspections as required by Steps 4.2 and 8.2.1.2.g. Specific examples included: WO 00916590-01, dated October 15, 2007; WO 01055288-01, dated November 5, 2008; WO 01030493-01, dated December 11, 2008; WO 01057104-01, dated February 18, 2009; WO 01104245-01, dated March 5, 2009; and WO 00975345-01, dated July 29, 2008.

(b) The licensee failed to implement the requirements of CPS 1019.07, Leakage Reduction and Monitoring Program, Revision 4c. Specifically, the licensee failed on multiple occasions to complete the procedure data sheet as required by Step 8.2.1.2.b by not adequately describing the inspection boundary. On two occasions, the inspection boundary description was left blank, on other occasions the inspection boundary referenced highlighted portions of plant drawings or worksheets that were not maintained with the quality records, and on several other occasions the inspection boundary description only listed portions of the systems that were not visually inspected for leakage. Specific examples included: WO 00916590-01, dated October 15, 2007; WO 00972149-01, dated April 22, 2008; WO 01015198-01, dated September 17, 2008; WO 01047559-01, dated January 6, 2009; WO 00909779-01, dated January 14, 2008; WO 00909780-01, dated January 14, 2008; WO 01055288-01, dated November 5, 2008; WO 01030493-01, dated December 11, 2008; WO 01057104-01, dated February 18, 2009; WO 01104245-01, dated March 5, 2009; WO 00916896-01, dated October, 15, 2007; WO 00909781-01, dated January 12, 2008; and WO 00975345-01, dated July 29, 2008.

(c) Procedure CPS 1019.07 used for implementing the licensees leakage reduction and monitoring program for reactor coolant sources outside of containment as required by TS 5.5.2 was not appropriate to the circumstances because it lacked sufficient details to ensure that the program would be implemented correctly. Specifically, the procedure did not identify which portions of the piping systems could be excluded from visual inspections for ALARA or other considerations, did not define dose and/or dose rate limits for piping system inspections that would justify their exclusion, did not provide any examples or other guidance describing what would be acceptable other considerations for excluding portions of piping systems from visual inspections other than limited accessibility, did not identify which portions of the piping systems could be excluded because of limited accessibility, and did not provide any steps or guidance to ensure that leakage would be collected for any portions of the piping systems excluded from visual inspections.

Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000461/2009004-05). The licensee entered this violation into its CAP as AR 00965450.

1EP6 Drill Evaluation

.1 Simulator-Based Training Observation

a. Inspection Scope

The inspectors observed a simulator-based training evolution for licensed operators on September 23, 2009, which required Emergency Plan implementation by the operators.

This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the operators. The inspectors also attended the post-training critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the operators performance and to ensure that the licensees evaluators noted the same issues and entered them into the CAP.

This inspection constituted one emergency preparedness simulator-based training observation inspection sample as defined in IP 71114.06.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors also reviewed the licensees physical and programmatic controls for highly activated and/or contaminated materials (non-fuel) stored within the spent fuel pool or other storage pools.

This inspection constituted one sample as defined in IP 71121.01.

b. Findings

No findings of significance were identified.

2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the configuration of the licensees gaseous and liquid effluent processing systems to confirm that radiological discharges were properly mitigated, monitored, and evaluated with respect to public exposure. The inspectors reviewed the performance requirements contained in General Design Criteria 60 and 64 of Appendix A to 10 CFR Part 50 and in the licensees Radiological Effluent Technical Specifications (RETS) and Offsite Dose Calculation Manual (ODCM). The inspectors also reviewed any abnormal radioactive gaseous or liquid discharges and any conditions since the last inspection when effluent radiation monitors were out-of-service to verify that the required compensatory measures were implemented. Additionally, the inspectors reviewed the licensee=s quality control program to verify that the radioactive effluent sampling and analysis requirements were satisfied and that discharges of radioactive materials were adequately quantified and evaluated.

The inspectors reviewed each of the radiological effluent controls program requirements to verify that the requirements were implemented as described in the licensees RETS.

For selected system modification (since the last inspection), the inspectors reviewed changes to the liquid or gaseous radioactive waste system design, procedures, or operation, as described in the UFSAR and plant procedures.

The inspectors reviewed changes to the ODCM made by the licensee since the last inspection to ensure consistency was maintained with respect to guidance in NUREG-1301, 1302 and 0133 and Regulatory Guides 1.109, 1.21 and 4.1.

If differences were identified, the inspectors reviewed the licensees technical basis or evaluations to verify that the changes were technically justified and documented.

The inspectors reviewed the radiological effluent release reports for 2007 and 2008 in order to determine if anomalous or unexpected results were identified by the licensee, entered in the CAP and adequately resolved.

The inspectors reviewed any significant changes in reported dose values from the previous radiological effluent release report, and the inspectors evaluated the factors, which may have resulted in the change. If the change was not explained as being influenced by an operational issue (e.g., fuel integrity, extended outage, or major decontamination efforts), the inspectors independently assessed the licensee=s offsite dose calculations to verify that the licensees calculations were adequately performed and were consistent with regulatory requirements.

The inspectors reviewed the licensees correlation between the effluent release reports and the environmental monitoring results, as provided in Section IV.B.2 of Appendix I to 10 CFR Part 50.

This inspection constituted one sample as defined in IP 71122.01.

b. Findings

No findings of significance were identified.

.2 Onsite Inspection

a. Inspection Scope

The inspectors performed a walkdown of selected components of the gaseous and liquid discharge systems (e.g., gas compressors, demineralizers and filters (in use or in standby), tanks, and vessels) and reviewed current system configuration with respect to the description in the UFSAR. The inspectors evaluated temporary waste processing activities, system modifications, and the equipment material condition. For equipment or areas that were not readily accessible, the inspectors reviewed the licensee's material condition surveillance records, as applicable. The inspectors reviewed any changes that were made to the liquid or gaseous waste systems to verify that the licensee adequately evaluated the changes and maintained effluent releases ALARA.

During system walkdowns, the inspectors assessed the operability of selected point of discharge effluent radiation monitoring instruments and flow measurement devices.

The effluent radiation monitor alarm set point values were reviewed to verify that the set points were consistent with RETS/ODCM requirements.

For effluent monitoring instrumentation, the inspectors reviewed documentation to verify the adequacy of methods and monitoring of effluents, including any changes to effluent radiation monitor set-points. The inspectors evaluated the calculation methodology and the basis for the changes to verify the adequacy of the licensees justification.

The inspectors observed the licensees sampling of liquid and gaseous radioactive waste (e.g., sampling of waste steams) and observed selected portions of the routine processing and discharge of radioactive effluents if those activities occurred during the onsite inspection. Additionally, the inspectors reviewed several radioactive effluent discharge permits, assessed whether the appropriate treatment equipment was used and whether the radioactive effluent was processed and discharged in accordance with RETS/ODCM requirements, including the projected doses to members of the public.

The inspectors interviewed staff concerning effluent discharges made with inoperable (declared out-of-service) effluent radiation monitors to determine if appropriate compensatory sampling and radiological analyses were conducted at the frequency specified in the RETS/ODCM. For compensatory sampling methods, the inspectors reviewed the licensees practices to determine if representative samples were obtained and if the licensee routinely relied on the use of compensatory sampling in lieu of adequate system maintenance or calibration of effluent monitors.

The inspectors reviewed surveillance test results for nonsafety-related ventilation and gaseous discharge systems (high efficiency particulate air and charcoal filtration) to verify that the systems were operating within the specified acceptance criteria. In addition, the inspectors assessed the methodology the licensee used to determine the stack/vent flow rates to verify that the flow rates were consistent with the RETS/ODCM.

The inspectors reviewed the licensees program for identifying any normally non-radioactive systems that may have become radioactively contaminated to determine if evaluations (e.g., 10 CFR 50.59 evaluations) were performed per IE Bulletin 80-10.

The inspectors did not identify unidentified contaminated systems that may have been unmonitored discharge pathways to the environment.

The inspectors reviewed instrument maintenance and calibration records (i.e., both installed and counting room equipment) associated with effluent monitoring and reviewed quality control records for the radiation measurement instruments.

The inspectors performed this review to identify any degraded equipment performance and to assess corrective actions, as applicable.

The inspectors reviewed the radionuclides that were included by the licensee in its effluent source term to determine if all applicable radionuclides were included (within detectability standards) in the licensees evaluation of effluents. The inspectors reviewed waste stream analyses (10 CFR Part 61 analyses) to determine if hard-to-detect radionuclides were also included in the source term analysis.

The inspectors reviewed a selection of monthly, quarterly, and annual dose calculations to ensure that the licensee had properly demonstrated compliance with 10 CFR Part 50, Appendix I, and RETS dose criteria.

The inspectors reviewed licensee records to identify any abnormal gaseous or liquid tank discharges (e.g., discharges resulting from misaligned valves, valve leak-by, etc.)

to determine if the licensee had implemented the required actions. The inspectors determined if abnormal discharges were assessed and reported as part of the Annual Radioactive Effluent Release Report consistent with Regulatory Guide 1.21.

The inspectors reviewed the licensees effluent sampling records (sampling locations, sample analyses results, flow rates, and source term) for radioactive liquid and gaseous effluents to verify that the licensees information satisfied the requirements of 10 CFR 20.1501.

This inspection constituted one sample as defined in IP 71122.01.

b. Findings

No findings of significance were identified.

.3 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, Licensee Event Reports (LERs), and Special Reports related to the radioactive effluent treatment and monitoring program since the last inspection to determine if identified problems were entered into the CAP for resolution. The inspectors also assessed whether the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

The inspectors reviewed corrective action reports from the radioactive effluent treatment and monitoring program since the previous inspection, interviewed staff, and reviewed documents to determine if the following activities were conducted in an effective and timely manner commensurate with their importance to safety and risk:

• initial problem identification, characterization, and tracking;

• disposition of operability/reportability issues;

• evaluation of safety significance/risk and priority for resolution;

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

• resolution of Non-Cited Violations tracked in the CAP;

• implementation/consideration of risk-significant operational experience feedback; and

• ensuring problems were identified, characterized, prioritized, entered into a corrective action, and resolved.

This inspection constituted one sample as defined in IP 71122.01.

b. Findings

No findings of significance were identified.

2PS3 Radiological Environmental Monitoring Program And Radioactive Material Control Program (71122.03)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the most current Annual Environmental Monitoring Report and licensee assessment results to verify that the Radiological Environmental Monitoring Program (REMP) was implemented as required by TS and the ODCM. The inspectors reviewed the report for changes to the ODCM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, interlaboratory comparison program, and analysis of data. The inspectors reviewed the ODCM to identify environmental monitoring stations and reviewed licensee self-assessments, audits, LERs, and inter-laboratory comparison program results. The inspectors reviewed the UFSAR for information regarding the environmental monitoring program and meteorological monitoring instrumentation.

The inspectors reviewed the scope of the licensees audit program to verify that it met the requirements of 10 CFR 20.1101(c).

This inspection constituted one sample as defined in IP 71122.03.

b. Findings

No findings of significance were identified.

.2 Onsite Inspection

a. Inspection Scope

The inspectors walked 30 percent of the air sampling stations and approximately 10 percent of the thermoluminescence dosimeter (TLD) monitoring stations to determine whether they were located as described in the ODCM and to determine the equipment material condition.

This inspection constituted one sample as defined in IP 71122.03.

The inspectors observed the collection and preparation of a variety of environmental samples (e.g., ground and surface water, milk, vegetation, sediment, and soil) and verified that environmental sampling was representative of the release pathways as specified in the ODCM and that sampling techniques were in accordance with procedures.

This inspection constituted one sample as defined in IP 71122.03.

The inspectors verified that the meteorological instruments were operable, calibrated, and maintained in accordance with guidance contained in the UFSAR, NRC Safety Guide 23, and licensee procedures. The inspectors verified that the meteorological data readout and recording instruments in the control room and at the tower were operable. The inspectors compared readout data (i.e., wind speed, wind direction, and delta temperature) in the Control Room and at the meteorological tower to identify if there were any line loss differences.

This inspection constituted one sample as defined in IP 71122.03.

The inspectors reviewed each event documented in the Annual Environmental Monitoring Report, which involved a missed sample, inoperable sampler, lost TLD, or anomalous measurement for the cause and corrective actions and conducted a review of the licensees assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection (LLDs)). The inspectors reviewed the associated radioactive effluent release data that was the likely source of the released material.

This inspection constituted one sample as defined in IP 71122.03.

The inspectors reviewed significant changes made by the licensee to the ODCM as the result of changes to the land census or sampler station modifications since the last inspection. The inspectors reviewed technical justifications for changed sampling locations. The inspectors verified that the licensee performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment. There were no significant changes to the ODCM.

This inspection constituted one sample as defined in IP 71122.03.

The inspectors reviewed the calibration and maintenance records for five air samplers and composite water samplers. The inspectors reviewed calibration records for the environmental sample radiation measurement instrumentation (i.e., count room). The inspectors verified that the appropriate detection sensitivities with respect to TS/ODCM were utilized for counting samples (i.e., the samples meet the TS/ODCM required LLDs).

The inspectors reviewed quality control charts for maintaining radiation measurement instrument status and actions taken for degrading detector performance.

The inspectors reviewed the results of the REMP sample vendors quality control program including the interlaboratory comparison program to verify the adequacy of the vendors program and the corrective actions for any identified deficiencies. The inspectors reviewed audits and technical evaluations the licensee performed on the vendors program. The inspectors reviewed audit results of the program to determine whether the licensee met the TS/ODCM requirements.

This inspection constituted one sample as defined in IP 71122.03.

b. Findings

No findings of significance were identified.

.3 Unrestricted Release of Material from the Radiologically Controlled Area

a. Inspection Scope

The inspectors observed several locations where the licensee monitors potentially contaminated material leaving the Radiologically Controlled Area, and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use to verify that the work was performed in accordance with plant procedures.

This inspection constituted one sample as defined in IP 71122.03.

The inspectors verified that the radiation monitoring instrumentation was appropriate for the radiation types present and was calibrated with appropriate radiation sources. The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material and verified that there was guidance on how to respond to an alarm which indicates the presence of licensed radioactive material. The inspectors reviewed the licensees equipment to ensure the radiation detection sensitivities were consistent with the NRC guidance contained in IE Circular 81-07 and IE Information Notice 85-92 for surface contamination and HPPOS-221 for volumetrically contaminated material. The inspectors verified that the licensee performed radiation surveys to detect radionuclides that decay via electron capture. The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters (i.e., counting times and background radiation levels). The inspectors verified that the licensee had not established a release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high radiation background area.

This inspection constituted one sample as defined in IP 71122.03.

b. Findings

No findings of significance were identified.

.4 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, LERs, and Special Reports related to the radiological environmental monitoring program since the last inspection to determine if identified problems were entered into the CAP for resolution.

The inspectors also verified that the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

The inspectors also reviewed corrective action reports from the radioactive effluent treatment and monitoring program since the previous inspection, interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

• initial problem identification, characterization, and tracking;

• disposition of operability/reportability issues;

• evaluation of safety significance/risk and priority for resolution;

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

• resolution of Non-Cited Violations tracked in the CAP; and

• implementation/consideration of risk-significant operational experience feedback.

This inspection constituted one sample as defined in IP 71122.03.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Review of Submitted Quarterly Data

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the Second Quarter 2009 Performance Indicators for any obvious inconsistencies prior to its public release in accordance with IMC 0608, "Performance Indicator Program."

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

b. Findings

No findings of significance were identified.

.2 Mitigating Systems Performance Index - Emergency AC [Alternating Current] Power

System

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported Mitigating Systems Performance Index (MSPI) - Emergency AC Power System Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from April 2008 through June 2009, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

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

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

b. Findings

No findings of significance were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection Systems

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI - High Pressure Injection Systems Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from April 2008 through June 2009, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

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

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

b. Findings

No findings of significance were identified.

.4 Mitigating Systems Performance Index - Heat Removal System

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI - Heat Removal System Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from April 2008 through June 2009, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

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

b. Findings

No findings of significance were identified.

.5 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI - Residual Heat Removal System Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from April 2008 through June 2009, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

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

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

b. Findings

No findings of significance were identified.

.6 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI - Cooling Water Systems Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from April 2008 through June 2009, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

This inspection constitutes one MSPI - Cooling Water System Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.7 Reactor Coolant System (RCS) Specific Activity

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Specific Activity Performance Indicator for the period from the Third Quarter 2008 through the Second Quarter 2009.

To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in the NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used.

The inspectors reviewed the licensees RCS chemistry samples, TS requirements, action requests, LERs and NRC Inspection Reports for the period of Third Quarter 2008 through the Second Quarter 2009, to validate the accuracy of the submittals.

The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze an RCS sample.

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

b. Findings

No findings of significance were identified.

.8 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences Performance Indicator for the period from the Third Quarter 2008 through the Second Quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees assessment of the performance indicator for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensees performance indicator data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review, and the results of those reviews. The inspectors independently reviewed electronic dosimetry dose rate and accumulated dose alarm and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas.

This inspection constituted one Occupational Radiological Occurrences Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

.9 RETS/ODCM Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the RETS/ODCM Radiological Effluent Occurrences Performance Indicator for the period of July, 2008 through July, 2009. The inspectors used performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, to determine the accuracy of the performance indicator data reported during those periods. The inspectors reviewed the licensees CAP database and selected individual action requests generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates for the period of July, 2008 through July, 2009 to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose.

This inspection constituted one RETS/ODCM Radiological Effluent Occurrences Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.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 CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Some minor issues were entered into the licensees CAP as a result of the inspectors observations; however, they are not discussed in this report.

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

b. Findings

No findings of significance were identified.

.2 Annual Review of Operator Workarounds

a. Inspection Scope

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

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

b. Findings and Observations

Introduction No findings of significance were identified.

Observations The inspectors met with the site Operator Challenge/Workaround Coordinator, reviewed documents, and attended a Workaround Review Board. The Workaround Review Board was well organized and conducted a thorough review of potential workaround issues.

Board participants were well prepared and knowledgeable of the concerns associated with each of the items discussed. Appropriate follow-up was done when questions arose during the review. In general, the inspectors found that documents and action request items were well maintained and tracked with a good awareness of timelines and milestones. However, the inspectors found some examples of incomplete documentation in the licensees CAP database for actions taken to evaluate and address potential operator workarounds or challenges. The inspectors noted that the licensee had recently completed a concerted effort to review operating procedures for proceduralized operator burdens; however, the licensee has not yet had sufficient time to fully evaluate and address the potential burdens identified.

The inspectors noted that at the end of August 2009, the licensee was tracking 2 operator workarounds and 4 operator challenges. In addition, the licensee was tracking 45 Control Room deficiencies and 84 Control Room tags. While the numbers of Control Room deficiencies and tags appears to be high, the licensee made progress over the previous two months in reducing those numbers from 53 Control Room deficiencies and 136 Control Room tags at the end of June 2009. There were 19 pages tracked in the licensees Operator Burden Aggregate Assessment Report, with nearly 100 total operator burdens. Operator burdens included operator workarounds, operator challenges, Control Room deficiencies, temporary configuration changes, out-of-specification log readings, adverse condition monitoring plans, operational technical decision-making assessments, and operability evaluations.

While evaluating the cumulative effect of operator burdens on the operators, the inspectors noted that at the end of August there were 11 active Control Room compensatory actions that required operators to look at over 70 data points at least once per shift, with over 40 points requiring hourly monitoring by the operators.

In addition, there were 25 compensatory actions outside of the Control Room for the non-licensed operators to monitor. The inspectors concluded that while the relatively high number of operator burdens created additional work, distractions, and challenges for operators, there did not appear to be a significant impact on plant safety because operators were effectively managing the burdens. However, further reducing the total number of operator burdens and maintaining them at a lower level would be prudent.

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

.1 (Closed) LER 05000461/2009-001-00, Safety Function Lost Due to Capacitor Failure on

Circuit Card On July 2, 2009, the licensee identified that the high pressure core spray pump and associated Division 3 emergency diesel generator and Division 3 shutdown service water pump were rendered inoperable due to the failure of a logic circuit card in the nuclear protection system that would prevent automatic initiation of high pressure core spray and automatic start of the Division 3 emergency diesel generator and Division 3 shutdown service water pump. The cause for the circuit card failure was premature failure of a ceramic capacitor in the circuit due to a manufacturing anomaly that limited the expected lifetime of the capacitor. The licensee completed replacement of the failed circuit card and restored the high pressure core spray pump, Division 3 emergency diesel generator and Division 3 shutdown service water pump to an operable status within the applicable TS allowed outage time. The licensee reported this event as a condition that could have prevented fulfillment of the high pressure core spray system safety function in accordance with 10 CFR 50.73(a)(2)(v)(D). No findings of significance and no violations of regulatory requirements were identified.

LER 05000461/2009-001-00 is closed.

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

.2 Unit 1 Technical Specification Required Shutdown Due to Unidentified Leakage from the

Reactor Coolant System

a. Inspection Scope

On September 29, 2009, operators initiated a plant shutdown required by TS 3.4.5, RCS Operational Leakage, due to a greater than 2 gallon-per-minute increase in unidentified leakage within the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. After the unit was shut down, the licensee entered the drywell and identified that the leak was from the reactor core isolation cooling inboard steam isolation valve 1F0063 stem packing.

The inspectors evaluated Control Room operator performance during portions of the plant shutdown. This evaluation included direct observation in the Control Room, review of Control Room operators use of plant operating procedures, and review of initial actions taken to assess the event. The inspectors interviewed plant personnel and reviewed applicable portions of the TS, plant procedures, Control Room logs, equipment configurations, plant process computer data, and forced outage plan.

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

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted the following observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours.

• Multiple tours of operations within the security alarm stations;

• Tours of selected security officer response posts;

• Direct observation of personnel entry screening operations within the plants Main Access Facility; and

• Security force shift turnover activities.

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

b. Findings

No findings of significance were identified.

4OA6 Management Meetings

.1 Resident Inspectors Exit Meeting

The inspectors presented the inspection results to Mr. M. Kanavos and other members of the licensees staff at the conclusion of the inspection on October 15, 2009.

The licensee acknowledged the findings presented. Proprietary information was examined during this inspection, but is not specifically discussed in this report.

.2 Interim Exit Meeting

Interim exits were conducted for:

• Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems Inspection with Mr. F. Kearney and other members of the licensees staff on August 7, 2009. The inspector confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

• Radiological Environmental Monitoring Program and Radioactive Material Control Program Inspection with Mr. F. Kearney and other members of the licensees staff on September 4, 2009. The inspector confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

• Crane and Heavy Lift Inspection with Mr. F. Kearney and other members of the licensees staff on July 10, 2009. The licensee acknowledged the issues presented.

The licensee confirmed that design calculations generated by contractors were considered proprietary. It was agreed that all paper copies of these proprietary documents would be shredded, and all electronic files of these proprietary documents would be deleted when no longer needed.

4OA7 Licensee-Identified Violations

.1 Failure to Perform Inservice Testing of Excess Flow Check Valves

10 CFR 50.55a, Paragraph (f)(4)(ii) requires, in part, Inservice tests to verify operational readiness of pumps and valves, whose function is required for safety . . . must comply with the requirements of the latest edition and addenda of the Code incorporated by reference in paragraph

(b) of this section. . . .

The applicable Code for the current Clinton Power Station Inservice Test Program interval for testing valves is the 1989 Edition of American Society of Mechanical Engineers (ASME)Section XI, Subsection IWV, Inservice Testing of Valves in Nuclear Power Plants, which references the ASME/ANSI Operations and Maintenance Code (OMa 1988, Part 10).

OMa 1988, Part 10, Paragraph 4.1 requires, in part, that valves with remote position indicators shall be observed locally at least once every 2 years to verify that the valve operation is accurately indicated. In addition, OMa 1988, Part 10, Paragraph 4.3.2.2 requires, in part, that each check valve shall be exercised or examined in a manner which verifies obturator travel to the closed, full-open or partially open position required to fulfill its function.

Contrary to the above, the licensee incorrectly removed nine excess flow check valves (1CM002A, 1CM002B, 1CM003A, 1E22-F330, 1E22-F332, 1E51-F377A, 1E51-F377B, 1SM008 and 1SM009) from its Inservice Testing Program in 2002 and subsequently failed to perform testing required by the Code. The licensee entered this violation into its CAP as AR 00846540. The finding was determined to be of very low safety significance (Green) because the finding was a design or qualification deficiency determined not to result in loss of operability or availability.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Bunte, Design Engineering Manager

T. Chalmers, Operations Director

S. Clary, Engineering Programs Manager

J. Cunningham, Acting Operations Director

J. Domitrovich, Maintenance Director

R. Frantz, Regulatory Assurance

M. Gandhi, Design Engineering

W. Hafiz, Design Engineering

M. Heger, Mechanical/Structural Design Engineering Manager

N. Hightower, Radiological Engineering Manager

D. Kemper, Regulatory Affairs Manager

K. Leffel, Operations Support Manager

D. Lillyman, Engineering Response Team

M. Kanavos, Plant Manager

M. Kassar, Exelon Corporate Crane Specialist

F. Kearney, Site Vice President

J. Kouski, SRO Fuel Handling

S. Kowalski, Engineering Response Manager

J. Peterson, Regulatory Assurance

M. Reandeau, Shift Operations Superintendent

J. Stovall, Radiation Protection Manager

J. Ufert, Fire Marshall

C. VanDenburgh, Nuclear Oversight Manager

R. Weber, Engineering Director

C. Williamson, Security Manager

R. Zacholski, Operations Services Manager

Attachment

LIST OF ITEMS

Opened

05000461/2009004-01 URI Interconnecting Floor Drains Between the Residual Heat Removal A Pump Room and Radwaste Pipe Tunnel (Section 1R06.b.1)

05000461/2009004-02 FIN Ineffective Corrective Actions for Vibration Induced Stem/Disc Separation of Fuel Pool Cooling System Train 'A' Flow Control Valve 1FC004A (Section 1R12.b.1)

05000461/2009004-03 NCV Failure to Update the Final Safety Analysis Report (Section 1R15.b.1)

05000461/2009004-05 NCV Failure the Adequately Implement Requirements of the Leakage Reduction and Monitoring Program (Section 1R22.b.1)

05000461/2009004-04 URI RPV Head Strongback, Dryer/Separator Strongback and RPV Head Lifting Lugs Did Not Demonstrate Single Failure Proof Requirements of NUREG 0612, Control of Heavy Loads at Nuclear Power Plants, Section 5.1.6 (Section 1R20.b.1)

Closed

05000461/2009004-02 FIN Ineffective Corrective Actions for Vibration Induced Stem/Disc Separation of Fuel Pool Cooling System Train 'A' Flow Control Valve 1FC004A (Section 1R12.b.1)

05000461/2008005-02 URI Maintenance Rule Scoping Question for Liquid Effluent Process Radiation Monitors (Section 1R12.b.2)

05000461/2009004-03 NCV Failure to Update the Final Safety Analysis Report (Section 1R15.b.1)

05000461/2009003-02 URI Review of Excess Flow Check Valve Operability Evaluation In Lieu of Testing (Section 1R15.b.2)

05000461/2009004-05 NCV Failure the Adequately Implement Requirements of the Leakage Reduction and Monitoring Program (Section 1R22.b.1)

05000461/2009-001-00 LER Safety Function Lost Due to Capacitor Failure on Circuit Card (Section 4OA3.1)

Discussed

05000461/2009003-01 NCV Failure to Evaluate Safety Function of Suppression Pool Makeup System (Section 1R12.b.1)

Attachment