IR 05000282/2011002

IR 05000282-11-002; 05000306-11-002; on 01/01/2011 - 03/31/2011; Prairie Island Nuclear Generating Plant, Units 1 and 2; Equipment Alignment and Operability Evaluations

ML111230133
Person / Time
Site:	Prairie Island
Issue date:	05/02/2011
From:	Jack Giessner Reactor Projects Region 3 Branch 4
To:	Schimmel M Northern States Power Co
Shared Package
IR 05000282/2011002, 05000306/2011002, 01/01/2011 - 03/31/2011, Prairie Island Nuclear Generating Plant, Units 1 and 2, Equipment Alignment and Operability Evaluations.	List:
References
IR-11-002
Download: ML111230133 (40)

Text

May 2, 2011

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000282/2011002; 05000306/2011002

Dear Mr. Schimmel:

On March 31, 2011, the U. S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on April 13, 2011, with you and other members of your staff.

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

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

Based on the results of this inspection, three NRC identified findings of very low safety significance were identified. Each finding involved a violation of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of any NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U. S. Nuclear Regulatory Commission Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant. In addition, if you disagree with the crosscutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/readingrm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

John B. Giessner, Chief Branch 4 Division of Reactor Projects Docket Nos. 50-282; 50-306;72-010 License Nos. DPR-42; DPR-60; SNM-2506

Enclosure:

Inspection Report 05000282/2011002; 05000306/2011002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report No: 05000282/2011002; 05000306/2011002 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: January 1 through March 31, 2011 Inspectors: K. Stoedter, Senior Resident Inspector P. Zurawski, Resident Inspector N. Feliz-Adorno, Reactor Engineer L. Kozak, Senior Reactor Analyst R. Langstaff, Fire Protection Inspector Approved by: John B. Giessner, Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000282/2011002; 05000306/2011002; 01/01/2011 - 03/31/2011; Prairie Island Nuclear

Generating Plant, Units 1 and 2; Equipment Alignment and Operability Evaluations.

This report covers a 3 month period of inspection by the resident inspectors. Three Green findings were identified by the inspectors. The findings were considered non-cited violations (NCVs) of NRC regulations. 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. Cross-cutting aspects were determined using IMC 0310, Components Within the Cross Cutting Areas. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

An inspector-identified finding of very low safety significance and a non-cited violation (NCV) of Technical Specification 5.4.1 was identified on February 8, 2011, due to the licensees failure to establish, implement, and maintain procedures for the fire protection program. Specifically, the licensee failed to implement combustible control requirements prior to storing flammable material in a safety-related area. As a result, a gas cylinder containing flammable material was stored in the D6 emergency diesel generator radiator fan room for 1 week without the required additional fire loading evaluation completed. Corrective actions for this issue included entry of this issue into the corrective action program (CAP), removal of the cylinders from the radiator fan room, and the completion of both a human performance and a causal investigation.

The inspectors determined that this finding was more than minor because the presence of the gas cylinders could result in a fire affecting the ventilation system for the D6 emergency diesel generator. The finding was associated with the Initiating Events Cornerstone attribute of Protection against External Factors (Fire) and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Using a Phase 2 SDP analysis, the inspectors calculated an upper bound change in CDF of 3.3x10-7, which is consistent with a finding of very low safety significance. The inspectors determined that this finding was crosscutting in the Human Performance,

Work Control area, because licensee personnel did not coordinate work activities consistent with nuclear safety, specifically in regard to the need to keep personnel apprised of the work impact and operational impact of the work activities. (H.3(b)).

(Section 1R04)

Cornerstone: Mitigating Systems

Green.

An inspector identified finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion V, was identified on February 9, 2011, due to the failure to follow Procedure FP-OP-OL-01. Specifically, the licensee did not complete an immediate operability determination for all safety-related equipment such as the emergency diesel generators and inverters discussed in CAP 1270104. After prompting by the inspectors, the licensee revised the immediate operability determination to ensure that all safety-related equipment was properly evaluated for continued operability. Corrective actions included entering of this issue into the corrective action program, revising the immediate operability determination, implementing a daily review of immediate operability determinations, and developing an operability determination/recommendation improvement program to implement additional performance improvement actions.

The inspectors determined that this finding was more than minor because it was an additional example of the significant programmatic concern documented in NRC Inspection Report finding NCV 05000282/2010002-002; 05000306/2010002-002.

In addition, the failure to perform proper operability determinations could lead to worse errors, if not corrected. The inspectors concluded that this finding was of very low safety significance because it was not a design deficiency; it did not represent a loss of system safety function; it did not represent a loss of safety function for one train for greater than the Technical Specifications allowed outage time; and it did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event. This finding was determined to be crosscutting in the Problem Identification and Resolution, Corrective Action Program area, because the licensee had not taken appropriate corrective actions to address an adverse trend in operability determinations identified by the NRC in March 2010 (P.1(d)). (Section 1R15.1.b(1))

Green.

An inspector-identified finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion V, was identified due to the failure to properly complete an operability recommendation for the Unit 1 fuel oil system in accordance with Procedure FP-OP-OL-01, Operability/Functionality Determination. Specifically, the licensee used a mission time that was not supported by any licensing or design basis document. In addition, the new mission time was inappropriately considered an enhancement to operability. Once a supportable mission time was used, the licensee declare the Unit 1 fuel oil system inoperable due to having an inadequate fuel oil volume.

Corrective actions for this issue included entering of this issue into the corrective action program, increasing the fuel oil volume, and implementing an independent review group to review the adequacy of all operability recommendations.

The inspectors determined that this finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone. In addition, this finding impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Using a Phase 3 SDP evaluation, the regional senior reactor analyst determined that this finding was of very low safety significance because the Unit 1 emergency diesel generators would have been able to start and run for the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> assumed in the probabilistic risk assessment using the fuel oil contained in a single storage tank. This finding was determined to be crosscutting in the Problem Identification and Resolution, Corrective Action Program area, because the licensee failed to thoroughly evaluate this problem (including classifying, prioritizing and evaluating the condition for operability) such that the resolution addressed the cause (P.1(c)). (Section 1R15.1.b(2))

Licensee-Identified Violations

No violations of significance were identified.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at full power. On January 28, 2011, operations personnel lowered reactor power approximately one percent due to the unexpected failure to a feedwater control system power supply. After replacing the power supply, operations personnel returned Unit 1 to full power. On March 2, 2011, Unit 1 operated as slightly reduced power levels to support routine surveillance testing. Power levels were restored following the completion of the surveillance test.

Unit 2 began the inspection period at slightly reduced power due to maintenance on the 23 heater drain tank pump. Unit 2 returned to full power mid-day on January 1, 2011.

Unit 2 operated at or near full power levels for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 External Flooding

a. Inspection Scope

On March 20, 2011, the licensee entered Abnormal Procedure - 4, Flood, due to the 3-day projected Mississippi River level being greater than 678 feet. Upon receiving this information, the inspectors evaluated the design; material condition; and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions of flooding protection features provided in the Updated Safety Analysis Report (USAR). As part of this evaluation, the inspectors checked for obstructions that could prevent draining; checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation; and determined that barriers required to mitigate the flood were in place and functional/operable. Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site which would inhibit site drainage or allow water ingress past a barrier. The inspectors also reviewed the abnormal procedure for flooding to ensure it could be implemented as written. Documents reviewed are listed in the Attachment to this report.

Because this inspection was ongoing at the conclusion of the quarter, a sample was not credited for this inspection procedure.

b. Findings

No findings 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:

• D1 Emergency Diesel Generator (EDG);

• 12 Diesel Driven Cooling Water Pump (DDCLP) and Piping;

• D6 EDG Support Equipment;

• Battery Room Ventilation; and

• Unit 2 Safety Injection System.

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

These activities constituted five partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

Introduction:

An NRC-identified finding of very low safety significance (Green) and a non-cited violation (NCV) of TS 5.4.1 was identified for the failure to implement fire protection program procedures. Specifically, licensee personnel failed to follow procedures regarding the control of combustibles prior to storing flammable materials in the D6 EDG radiator fan room.

Description:

On February 8, 2011, the inspectors conducted a protected equipment walkdown of D6 EDG support equipment due to the opposite Unit 2 EDG being out of service. During the walkdown, the inspectors identified two gas cylinders in the D6 EDG radiator fan room. One cylinder contained acetylene and the other oxygen.

The inspectors immediately notified operations personnel. The operators removed the cylinders from the radiator fan room and initiated CAP 1269973.

An initial evaluation by the licensee determined that a contractor had been scheduled to install a new D6 EDG control room air conditioner compressor the previous week. After installation, the new compressor failed to operate as expected. The contractor stopped work activities and told the operations staff that troubleshooting was needed to determine why the compressor was not working. Operations personnel proceeded to stop all work associated with the compressor replacement in order to properly plan the troubleshooting activities. Due to the work stoppage, the contractor did not return to the jobsite. As a result, the two gas cylinders were left in the D6 radiator fan room. The licensees evaluation also found that procedural requirements provided in Administrative Work Instruction 5AWI 3.13.2, Fire Prevention, were not utilized. Specifically, Section 7.0 of 5AWI 3.13.2 stated that prior to the temporary storage of combustibles, the additional loading shall be reviewed through the use of a combustible control permit.

In this case, a combustible control permit had not been utilized.

Analysis:

The inspectors determined that the failure to implement the requirements of 5AWI 3.13.2 prior to storing the two gas cylinders in the D6 radiator room was a performance deficiency that impacted the Initiating Events Cornerstone and required evaluation using the SDP.

The inspectors determined the finding was more than minor because it was associated with the Initiating Events Cornerstone attribute of Protection against External Factors (Fire), and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, one gas cylinder stored in the D6 radiator fan room contained flammable material which introduced an explosion hazard to the D6 radiator fan room and presented a challenge to critical safety functions during power operations.

In accordance with IMC 0609, Significance Determination Process, 0609.04, Phase 1 Initial Screening and Characterization of Findings, Table 3b, question 1, the inspectors determined the finding degraded the fire protection defense-in-depth strategies. Therefore, screening under IMC 0609, Appendix F, Fire Protection Significance Determination Process, was required. The finding impacted the Fire Prevention and Administrative Controls Finding category.

Based on review of IMC 0609, Appendix F, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, the inspectors determined that the degradation rating for the combustible controls program associated with the finding was high, because acetylene is more flammable than a low flashpoint combustible liquid.

The inspectors performed a Phase 2 SDP analysis and determined that the duration factor (DF) was 1.92 x 10-2 (7 days / 365 days). The fire frequency (F) for the ignition source was determined to be 1.7 x 10-3 per year based on the transients high frequency listed in IMC 0609, Appendix F, Attachment 4, Fire Ignition Source Mapping Information: Fire Frequency, Counting Instructions, Applicable Fire Severity Characteristics, and Applicable Manual Fire Suppression Curves. The transients high frequency was used instead of the transients medium frequency as required by Task 2.4.2 of IMC 0609, Appendix F, to account for findings associated with the combustible controls programs. The inspectors used a value of 1 x 10-2 for the conditional core damage probability (CCDP) based on Table 2.1.1, Total Unavailability Values for Safe Shutdown Path Based Screening CCDP, of IMC 0609, Appendix F.

The inspectors noted that the value for CCDP was conservative, because a fire affecting the EDG would not result in loss of offsite power nor would it initiate a plant transient.

Based on these values, the inspectors calculated an upper bound change in core damage frequency (CDF) of 3.3 x 10-7 which is consistent with a finding of very low safety significance (i.e., Green).

The inspectors also concluded that this finding was crosscutting in the Human Performance, Work Control area, because licensee personnel did not coordinate work activities consistent with nuclear safety. Specifically, the licensee did not incorporate actions addressing the need to keep personnel apprised of the work impact and operational impact of the work activities. (H.3(b)).

Enforcement:

Technical Specification 5.4.1.d requires that written procedures be established, implemented, and maintained covering implementation of the Fire Protection Program.

Procedure 5AWI 3.13.2, Fire Prevention, establishes fire prevention requirements consistent with regulatory commitments. Step 5.7.2 of 5AWI 3.13.2 required, in part, that work supervisors complete a combustible control permit when storing or staging combustibles or ignition sources. Additionally, Section 7.0 of 5AWI 3.13.2 required that prior to the temporary storage of combustibles, the additional loading shall be reviewed through the use of a combustible control permit.

Contrary to the above, on February 1, 2011, a maintenance work supervisor failed to complete a combustible control permit prior to storing combustibles (two gas cylinders, one containing flammable material) in the D6 radiator fan room. In addition, the additional loading caused by storing the two gas cylinders in the fan room was not reviewed through the use of a combustible control permit prior to placing the cylinders in the room. Because this violation was of very low safety significance and it was entered into the CAP as CAP 1215434, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000306/2011002-01; Flammable Gas Cylinder Stored in Safety-Related Area). Corrective actions for this issue included removing the gas cylinders from the safety-related area on February 8 and conducting human performance event and causal investigations.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

During March 2011, the inspectors performed a complete system alignment inspection of the D5/D6 ventilation system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment (PRA). The inspectors walked down the system to review mechanical and electrical equipment line ups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Unit 1 715 Auxiliary Building (Fire Zones 19 & 108);

• Unit 2 715 Auxiliary Building (Fire Zone 46);

• Bus 15 and 16 Switchgear Rooms (Fire Zone 11);

• Relay and Cable Spreading Room (Fire Zone 12);

• Computer Room (Fire Zone 14); and

• Auxiliary Feedwater Pump Rooms (Fire Zone 2).

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

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

b. Findings

No findings were identified.

1R06 Flooding

.1 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged; that splices were intact; and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to flooding:

• 13.8 kV Manhole Ground Water/Structural Inspection.

This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On March 12, 2011, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

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

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• D1 EDG;

• Cooling Water to the Containment Fan Coil Units; and

• 123 Station Air Compressor.

The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems, and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted three quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

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 the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Planned Maintenance on CT12, the D2 EDG, and a Cooling Water Strainer;

• Planned Maintenance on the 21 Auxiliary Feedwater Pump, Substation Maintenance, and Emergent Replacement of a Feedwater System Power Supply;

• Planned Maintenance on the D5 EDG, the 21 Auxiliary Feedwater Pump, the Component Cooling Water System, and the 11 Residual Heat Removal Pump;

• Planned Maintenance on the 21 Residual Heat Removal System, the 121 Station Air Compressor and Motor Valve MV32079 (11 Refueling Water Storage Tank to the Safety Injection Pumps); and

• Planned Maintenance on the 22 DDCLP, Breaker 131, the Unit 1 B Feedwater Regulating Valve Bypass Valve, and Radiation Monitor 2R11.

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

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

b. Findings

No findings were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Operability Recommendation (OPR) 1246406-01 - Increased Leakage from Auxiliary Feedwater System Check Valves;

• OPR 1262356-02 - Degraded Grease in Actuator and Gearbox for Motor Valve 32144;

• OPR 1264535-01 - Q-List Classification of D5 and D6 EDG Fuel Oil Backup Pumps;

• OPR 1265904-01 - Safeguards Battery Operability Following a High Energy Line Break/Loss of Offsite Power Event;

• OPR 1263345-01 - Unit 1 Fuel Oil System Common Mode Failure;

• OPR 1266815-02 - Operability of Equipment in the Auxiliary Feedwater Pump Room Following a High Energy Line Break/Loss of Offsite Power Event;

• OPR 1266138; 11 Containment Spray Pump Motor Thread Engagement;

• Immediate Operability for CAP 1270104 - Battery Sizing Calculations did not Account for Inverter Loading; and

• Immediate Operability for CAP 1277155 - Loud Bang in Safety Injection Pump Room when 22 Residual Heat Removal Pump Started.

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

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

b. Findings

(1) Incomplete Immediate Operability Determination for CAP 1270104

Introduction:

An inspector-identified finding of very low safety significance (Green) and an NCV of 10 CFR Part 50, Appendix B, Criterion V, was identified due to the failure to follow Procedure FP-OP-OL-01, Operability/Functionality Determination. Specifically, the licensee did not complete an immediate operability determination for all safety-related equipment such as the EDGs and inverters discussed in CAP 1270104.

After prompting by the inspectors, the licensee revised the immediate operability determination to ensure that all safety-related equipment was appropriately evaluated for continued operability.

Discussion: On February 9, 2011, the licensee initiated CAP 1270104 after discovering that assumptions used in two Unit 1 battery sizing calculations were incorrect. The calculations assumed that following specific events the safety-related inverters would be powered by the direct current (DC) system (the safety-related batteries) for approximately 1 minute. After this 1 minute period, the calculation assumed that the inverters would return to being supplied by the alternating current (AC) system. Actual plant data showed that the AC input breakers for the Unit 1 inverters had a history of opening due to experiencing high input voltage. As a result, the inverters remained powered by the safety-related batteries for much longer than one minute. The licensee was concerned that the batteries may not have been appropriately sized to carry the inverters and other required loads.

Operations personnel performed an immediate operability determination for the issue discussed in CAP 1270104 on February 9, 2011. Based upon their review of the CAP, the operators believed that the components of concern were the Unit 1 safety-related batteries. The operators concluded that the Unit 1 batteries remained operable because the battery capacity was large enough to meet the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> mission time described in the licensing and design bases. The inspectors reviewed CAP 1270104 and the immediate operability determination, and had the following concerns:

• The immediate operability determination failed to provide information regarding whether the inverters remained operable with the AC input breakers open; and

• CAP 1270104 stated that the inverter AC input breakers were opening due to EDG voltage regulator overshoot. However, the immediate operability determination did not address the impact of this overshoot on EDG operability or the continued operability of other safety-related equipment powered by the EDG during design basis events.

Between February 10 and 24, 2011, the inspectors held several discussions with licensee management and operations personnel regarding the incomplete immediate operability determination for CAP 1270104. The inspectors discussed that the immediate operability determination did not comply with Step 5.3.1 of Procedure FP-OP-OL-01, which required that immediate determinations of operability be performed for all SSCs that were required to be operable by TS. Based upon the concerns identified by the inspectors, operations personnel updated the immediate operability determination on February 24, 2011. The revised determination stated that the inverters remained operable because the AC input breakers were not required for operability. The EDGs were also determined to be operable based upon successful testing and the absence of any data showing a potential equipment failure due to a voltage transient.

Analysis:

The inspectors determined that the failure to perform a complete immediate operability determination for CAP 1270104 as required by Procedure FP-OP-OL-01 was a performance deficiency that required an evaluation using the SDP. This finding impacted the Mitigating Systems Cornerstone. The inspectors determined that this issue was more than minor, because it was an additional example of the significant programmatic concern discussed in Inspection Report finding NCV 05000282/2010002-002; 05000306/2010002-002. The failure to perform proper operability determinations could lead to worse errors if not corrected (a more significant safety concern). The inspectors performed a Phase 1 SDP screening using Manual Chapter 0609, 4, Table 4a, Characterization Worksheet for MS, and determined that this finding was of very low safety significance (Green) because it was not a design deficiency; it did not represent a loss of system safety function; it did not represent a loss of safety function for one train of equipment for greater than the TS allowed outage time; and it did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event. This finding was determined to be crosscutting in the Problem Identification and Resolution, CAP area because the licensee has not taken appropriate corrective actions to address an adverse trend in operability determinations identified by the NRC in March 2010 (P.1(d)).

Enforcement:

Criterion V of 10 CFR Part 50, Appendix B, requires, in part, that activities affecting quality be prescribed and accomplished by procedures appropriate to the circumstance. The licensee implemented the operability determination process (an activity affecting quality) using Procedure FP-OP-OL-01, Operability/Functionality Determinations. Step 5.3.1 of FP-OP-OL-01, Revision 9, stated that immediate determinations of operability shall be performed for all SSCs that were required to be operable by TS upon the discovery of potential degraded conditions, nonconforming conditions or unanalyzed conditions.

Contrary to the above, on February 9, 2011, licensee personnel failed to perform an immediate operability determination for all SSCs discussed in CAP 1270104. Because this violation was of very low safety significance and it was entered into the corrective action program as CAP 1274156, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2011002-02; Failure to Appropriately Complete an Operability Recommendation on Unit 1 Battery Calculations). Corrective actions for this issue included revising the immediate operability determination to ensure it discussed all SSCs of concern, implementing a daily review of immediate operability determinations, and developing an operability determination/recommendation improvement program to implement additional performance improvement actions.

(2) Failure to Complete Operability Recommendation in Accordance with Procedures

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, due to the failure to properly complete an OPR for the Unit 1 fuel oil system in accordance with Procedure FP-OP-OL-01, Operability/Functionality Determination. Specifically, the licensee used a mission time within the OPR which was not supported by any licensing or design bases documentation. The licensee also inappropriately considered the use of a revised mission time to be an enhancement to operability.

Description:

The Unit 1 fuel oil system consists of six interconnected tanks each containing a specified volume of fuel oil. Each tank has an associated pump.

Per USAR Section 10.3.13, the tanks are used to supply fuel oil to one DDCLP and ensure that an EDG can provide power at the maximum loss of coolant accident loading for 14 days. The USAR also stated that only four of the six fuel oil tanks were required to support the operation discussed above.

On December 17, 2010, operations personnel initiated CAP 1263345 to document that a single failure could cause two of the fuel oil pumps to fail. As a result, the fuel oil volume contained in the tanks associated with the failed pumps could not be used to support the operation of a DDCLP and an EDG. The shift manager performed an immediate operability call and concluded that the fuel oil system remained operable. The shift manager also requested that engineering personnel complete an OPR for the fuel oil system.

Revision 0 to OPR 1263345-01 was completed on January 7, 2011. Revision 1 of the OPR was completed on January 19, 2011. During a control room tour in early February, the inspectors reviewed an operating information document which requested that operations personnel verify that only a seven day fuel oil supply remained in specific combinations of four out of six fuel oil tanks. The inspectors were concerned by this operating information as it conflicted with the information provided in the USAR. The inspectors immediately informed the shift manager of the conflicting information. The inspectors also performed an additional review of OPR 1263345-01 and found it contained the following information:

• the 14 day fuel oil supply was only required during flooding of the Mississippi River;

• single failures were not required to be assumed for external events such as a flood; and

• all other events/design basis accidents required a seven day fuel oil supply.

Based upon the results of a Prairie Island Specific Task Interface Agreement, the inspectors agreed that a single failure was not required to be assumed for an external flooding event. However, the inspectors did not agree with the OPR statements regarding the required fuel oil supply during all other events or that the adoption of a seven day fuel oil requirement was an enhancement to operability. The inspectors reviewed the USAR, TS, and TS Bases and found the following information in USAR, Section 10.3.13.1.2.1:

The Unit 1 design minimum storage capacity of diesel fuel oil is based on EDG operating at the loads stated in Table 8.4-1, Emergency Diesel Generator Loading During Unit 1 Loss of Coolant Accident/Design Basis Accident Coincident with a Loss of Offsite Power, plus one DDCLP for 14 days.

In addition, the following information was found in the TS Bases:

Each unit is provided with a fuel oil capacity sufficient to operate the diesel generator for a period of 14 days while the EDG is supplying maximum post loss of coolant accident load demand as discussed in the USAR.

Stored diesel fuel oil is required to have sufficient supply for one diesel generator on each unit to operate for 14 days. It is also required to meet specific standards for quality. This requirement, in conjunction with an ability to obtain replacement supplies within 14 days, supports the availability of the EDGs required to shut down the reactor and to maintain it in a safe condition for an anticipated operational occurrence or a postulated design basis accident with a loss of offsite power.

Lastly, the basis for TS surveillance requirements regarding fuel oil indicated that there was an adequate fuel oil inventory in the storage tanks to support operation of an EDG and a cooling water pump for 14 days. None of the documents reviewed indicated that the 14 days only applied to an external flooding event.

Based upon the results of this review, the inspectors concluded that OPR 1263345-01 was not sufficient to address the capability of the fuel oil system, the EDG or the cooling water pump to perform their specified safety functions. The inspectors provided the results of their review to licensee management. After multiple additional licensee reviews, operations personnel declared the Unit 1 fuel oil system inoperable, changed procedures to allow additional fuel oil to be added to the Unit 1 fuel oil tanks, and transferred fuel oil to the tanks such that the fuel oil volume contained with the specific combinations of tanks was enough to operate the loads specific in USAR Table 8.4-1 for 14 days.

Analysis:

The inspectors determined that the failure to appropriately complete an OPR following the discovery of a single failure vulnerability on the Unit 1 fuel oil system was a performance deficiency that required evaluation using the SDP. This issue impacted the Mitigating Systems Cornerstone. The inspectors determined that this issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone. In addition, this finding impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors performed a Phase 1 SDP evaluation using MC 0609, Attachment 4, Table 4a, Characterization Worksheet For IE, MS, and BI Cornerstones, and determined that a Phase 2 evaluation was needed because the finding resulted in a loss of system safety function. The inspectors performed a SDP Phase 2 evaluation using the pre-solved SDP worksheets for Prairie Island and a greater than 30 day exposure time. The results of this evaluation showed that this finding was potentially greater than green. As a result, a Region III senior reactor analyst (SRA) was contacted to perform an SDP Phase 3 analysis.

The SRA reviewed the finding and determined that although the fuel oil system was inoperable during this period, enough fuel oil remained available to allow an EDG to start and run for the defined 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> PRA mission time. As a result, there was no change in CDF for internal events, and the finding was determined to be of very low safety significance (Green). The inspectors concluded that this finding was crosscutting in the Problem Identification and Resolution CAP area because the licensee failed to thoroughly evaluate this problem (including classifying, prioritizing, and evaluating the condition for operability) such that the resolution addressed the cause (P.1(c)).

Enforcement:

Criterion V of 10 CFR Part 50, Appendix B, requires, in part, that activities affecting quality be prescribed and accomplished by procedures appropriate to the circumstance. The licensee implemented the operability determination process (an activity affecting quality) using Procedure FP-OP-OL-01, Operability/Functionality Determinations. Step 5.3.1.3 of FP-OP-OL-01, Revision 8, stated that an operability recommendation shall be sufficient to address the capability of the SSC to perform its specified safety function.

Contrary to the above, on January 7, 2011, licensee personnel performed an operability recommendation on CAP 1263345 which was not sufficient to address the capability of the Unit 1 fuel oil system and its supported equipment to perform their specified safety functions. Specifically, the operability recommendation failed to address the ability of the fuel oil system to supply an EDG operating at maximum post-loss of coolant accident loads and a DDCLP for 14 days following a design basis event. Because this violation was of very low safety significance and it was entered into your corrective action program as CAP 1270101, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2011002-03; Failure to Appropriately Complete an Operability Recommendation on the Unit 1 Fuel Oil System). Corrective actions for this issue included declaring the fuel oil system inoperable until a 14 day supply of fuel oil was contained within specific combinations of fuel oil tanks and implementing an independent review group to review the adequacy of all operability recommendations.

1R18 Plant Modifications

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modifications:

• Engineering Change (EC) 17435 - 21 Shield Building Ventilation Exhaust Damper; and

• EC 17616 - Temporary Battery Room Cooling.

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the USAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• 22 DDCLP;

• 21 Auxiliary Feedwater Pump;

• Feedwater System Power Supply;

• D5 EDG;

• 121 Station Air Compressor;

• 11 Residual Heat Removal;

• Motor Operated Valve from the 11 Refueling Water Storage Tank to the Unit 1 Safety Injection System; and

• 12 MDAFW Pump Auxiliary Lube Oil Pump.

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

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• SP 2090A; 21 Containment Spray Pump Quarterly Test (inservice testing (IST));

• SP 1218; Monthly 4kV Bus 15 Undervoltage Relay Test (routine);

• SP 1106A; 12 Diesel Cooling Water Pump Monthly Test (routine);

• SP 2089A; 21 Residual Heat Removal Pump and Suction Valve from Refueling Water Storage Tank Quarterly Test (routine);

• SP 1295; D1 Diesel Generator 6 Month Fast Start Test (routine); and

• SP 1544; Containment at Power Quarterly Inspection (reactor coolant system (RCS)).

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

• did preconditioning occur;

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

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

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

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

• measuring and test equipment calibration was current;

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

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

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

• test equipment was removed after testing;

• where applicable for IST activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;

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

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

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

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

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

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

Documents reviewed are listed in the Attachment to this report.

This inspection constituted four routine surveillance testing samples, one IST sample, and one RCS leak detection inspection sample as defined in IP 71111.22, Sections 02 and 05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on February 15, 2011, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings were identified.

.2 Training Observation

a. Inspection Scope

The inspector observed a simulator training evolution for licensed operators on January 29, 2011, which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator (PI) data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew.

The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.

This inspection of the licensees training evolution with emergency preparedness drill aspects constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours PI for both units made during 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 9902, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, corrective action documents, event reports and NRC Inspection Reports to validate the accuracy of the submittals. The inspectors also reviewed the licensees corrective action database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two unplanned scrams per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications performance indicator for both units made during 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI Document 9902, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, corrective action documents, event reports and NRC Inspection Reports to validate the accuracy of the submittals. The inspectors also reviewed the licensees corrective action database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two unplanned scrams with complications samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Transients per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours PI for both units made during 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI Document 9902, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, corrective action documents, event reports and NRC Inspection Reports to validate the accuracy of the submittals. The inspectors also reviewed the licensees corrective action database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two unplanned transients per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

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

a. Inspection Scope

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

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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

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

b. Findings

No findings were identified.

.3 Selected Issue Follow-Up Inspection: Review of Licensee Actions to Correct Right

Angle Drive Gear Oil Cooler Fouling

a. Inspection Scope

During the fourth quarter of 2009, the inspectors identified an adverse trend regarding macro fouling of the 12/22 DDCLP right angle drive gear oil coolers. The cause of the macro fouling was related to unstrained water used to cool the right angle drive gear cooler and shell fouling of the tube sheet resulting from zebra mussel treatments.

As a result of the corrective action process, the licensee installed a modification which strained the cooling water used by the right angle drive cooler units. Work associated with this modification was completed in September 2010, using EC 15150. The first opportunity to inspect the internals of a right angle gear drive gear oil cooler was in March 2011, during planned maintenance on the 22 DDCLP. Prior to the planned maintenance, the inspectors reviewed EC 15150 and previously generated corrective action records associated with fouling of the drive units. Additionally, the inspectors evaluated the as-found condition of the internal surfaces of the 22 DDCLP right angle drive gear oil cooler to evaluate the effectiveness of the modification. These inspections determined that the licensees actions to strain the cooling water to the drive unit coolers were effective. Documents reviewed in this inspection are listed in the Attachment to this report.

This review constituted one in-depth problem identification and resolution sample as defined in IP 7115205.

b. Findings

No findings were identified.

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

.1 Unit 1 Turbine Building Evacuation Due to Potential Hydrogen Leak

a. Inspection Scope

On January 29, 2011, at 10:02, Unit 1 operations entered 1C22.1 AOP1, Loss of Turbine Generator Seal Oil System Unit 1, due to possible hydrogen leakage from the main turbine generator. The inspectors reviewed the control room logs, corrective action documents, and procedures to determine the initiating event and whether the licensed operators had appropriately implemented procedures. The Inspectors also reviewed the sequence of events to ensure that the licensee had appropriately evaluated plant conditions against the emergency action level (EAL) matrix. Emergency action level HU3.1, along with the applicable bases, was reviewed to determine if the above event met the classification criteria for an unusual event. Specifically, EAL HU3.1 required that the licensee declare an unusual event if there is a report or detection of toxic or flammable gases that has or could enter the site area boundary in amounts that can affect normal plant operation. The inspectors discussed this EAL with operations personnel and determined that this EAL was reviewed as part of the operating crews response to the hydrogen seal oil issue. The crew determined the unusual event classification criteria was not met since there was never an actual report or detection of a toxic or flammable gas which affected normal plant operation. Documents reviewed in this inspection are listed in the Attachment to this report.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA5 Other

.1 (Open) Unresolved Item 05000282/2011002-04; 05000306/2011002-04; Evaluation of

Equipment Stored near Safety-Related Equipment

Introduction:

The inspectors identified an Unresolved Item (URI) concerning the evaluation of scaffolding stored adjacent to safety-related equipment in the auxiliary building.

Description:

On February 17, 2011, the inspectors performed a walkdown of the auxiliary building 715 elevation. During the walkdown, the inspectors noted a large amount of scaffolding in a room designated as the SVC EQUIP STG AREA. The inspectors raised a concern that the scaffold equipment was in the vicinity of electrical equipment designated as safety related via orange or green color coding. Specifically, the inspectors questioned whether the scaffolding had been evaluated for movement during a seismic event such that the resulting scaffold movement did not have a detrimental effect on the adjacent safety-related equipment. The inspectors communicated this concern to the licensee and CAP 1272888 was generated to document the condition.

The licensees engineering staff initially believed that all of the auxiliary building scaffold storage areas had been previously evaluated. However, the licensee was unable to find these evaluations. As a result, engineering personnel walked down the storage area in question and performed a calculation to determine whether the steel conduit, and cables inside, would be damaged as a result of scaffold movement due to a seismic event. The calculation concluded that, although the conduit would deform, there was reasonable expectation the cable inside would not crush and cutting of the cables/ insulation would be precluded, since the conduit deformation would not be a knife-edge type failure. In addition to this calculation, the licensee also constructed a metal barrier between the scaffold material and the adjacent safety-related equipment.

At the conclusion of the inspection period, the licensee was in the process reconstituting the evaluations for the remaining auxiliary building scaffold storage areas. The licensee modified CAP 1272888 to capture this action, which was scheduled for completion in mid-April 2011. As a result, this item was considered to be unresolved pending a review of the licensees engineering evaluations (URI 05000282/2011002-04; 05000306/2011002-04; Evaluation of Equipment Stored near Safety-Related Equipment).

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 13, 2011, the inspectors presented the inspection results to Mr. M. Schimmel and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Schimmel, Site Vice President

K. Davison, Plant Manager

T. Roddey, Site Engineering Director

J. Anderson, Regulatory Affairs Manager

C. Bough, Chemistry and Environmental Manager

B. Boyer, Radiation Protection Manager

K. DeFusco, Emergency Preparedness Manager

D. Goble, Safety and Human Performance Manager

J. Hamilton, Security Manager

J. Lash, Nuclear Oversight Manager

M. Milly, Maintenance Manager

J. Muth, Operations Manager

S. Northard, Performance Improvement Manager

K. Peterson, Business Support Manager

A. Pullam, Training Manager

R. Womack, Production Planning Manager (Acting)

Nuclear Regulatory Commission

J. Giessner, Chief, Reactor Projects Branch 4

T. Wengert, Project Manager, NRR

LIST OF ITEMS

Opened

05000306/2011002-01 NCV Flammable Gas Cylinders Stored in Safety-Related Area (Section 1R04)

05000282/2011002-02 NCV Failure to Appropriately Complete an Operability Recommendation for the Unit 1 Battery Calculations (Section 1R15)

05000282/2011002-03 NCV Failure to Appropriately Complete an Operability Recommendation on the Unit 1 Fuel Oil System (Section 1R15)

05000282/2011002-04; URI Evaluation of Equipment Stored near Safety-Related

05000306/2011002-04 Equipment (Section 4OA5)

Closed

05000306/2011002-01 NCV Flammable Gas Cylinders Stored in Safety-Related Area (Section 1R04)

05000282/2011002-02 NCV Failure to Appropriately Complete an Operability Recommendation for the Unit 1 Battery Calculations (Section 1R15)

Attachment

05000282/2011002-03 NCV Failure to Appropriately Complete an Operability Recommendation on the Unit 1 Fuel Oil System (Section 1R15)

Attachment