IR 05000282/2012002

IR 05000282-12-002, 05000306-12-002; on 01/01/2012 - 03/31/2012; Prairie Island Nuclear Generating Plant, Units 1 and 2; Maintenance Effectiveness; Operability Evaluations; Event Followup, and Other Activities

ML12135A597
Person / Time
Site:	Prairie Island
Issue date:	05/14/2012
From:	Reimer K NRC/RGN-III/DRP/B2
To:	Schimmel M Northern States Power Co
References
EA-12-052 IR-12-002
Download: ML12135A597 (73)

Text

UNITED STATES May 14, 2012

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000282/2012002; 05000306/2012002 AND EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Schimmel:

On March 31, 2012, 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 12, 2012, 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.

Four NRC-identified and four self-revealed findings of very low safety significance (GREEN)

were identified during this inspection. Seven of these findings involved a violation of NRC requirements. Further, licensee-identified violations which were determined to be of very low safety significance are listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy.

If you contest these NCVs, you should provide a response within 30 day of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant. If you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at 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 NRCs Agencywide Document Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.htm/l (the Public Electronic Reading Room).

Sincerely,

/RA/

Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-282, 50-306 and 72-010 License Nos. DPR-42, DPR-60 and SNM-2506

Enclosure:

Inspection Report 05000282/2012002; 05000306/2012002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report No: 05000282/2012002; 05000306/2012002 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: January 1, 2012, through March 31, 2012 Inspectors: K. Stoedter, Senior Resident Inspector P. Zurawski, Resident Inspector J. Beavers, Emergency Preparedness Inspector A. Dunlop, Senior Engineering Inspector J. Jandovitz, Project Engineer - Branch 5 R. Langstaff, Fire Protection Inspector C. Moore, Operator Licensing Examiner V. Myers, Radiation Protection Inspector D. Passehl, Senior Risk Analyst M. Phalen, Senior Health Physics Inspector A. Shaikh, Engineering Materials Inspector D. Szwarc, Fire Protection Engineer C. Thomas, Senior Resident Inspector - Monticello Approved by: Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000282/2012002, 05000306/2012002; 01/01/2012-03/31/2012; Prairie Island Nuclear

Generating Plant, Units 1 and 2; Maintenance Effectiveness; Operability Evaluations;

Event Followup, and Other Activities.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Eight Green findings were identified by the inspectors. Seven of these 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. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

A self-revealed finding of very low safety significance and an NCV of Technical Specification (TS) 5.4.1 occurred on January 19, 2012, due to the safety-related breaker for the 21 reactor vessel gap cooling fan failing while in service. Specifically, preventive maintenance activities used to ensure the breaker remained operable were not performed in a timely manner. Corrective actions for this issue included repairing/replacing the breaker for the 21 reactor vessel gap cooling fan and performing an extent of condition review to determine whether timely preventive maintenance was completed on similar breakers.

The inspectors determined that this issue was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability (such as having to perform a reactor shutdown). The inspectors determined that the finding was of very low safety significance since it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The cause of this finding was determined to be cross-cutting in the Human Performance, Work Control area because the licensee failed to appropriately coordinate work activities to support the continued operability and reliability of breaker 212E-44 (H.3(b)). (Section 1R12.1)

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and an NCV of TS 3.8.1 was identified by the inspectors on February 23, 2012, due to the licensees failure to properly assess the continued operability of the D2 emergency diesel generator (EDG) following monthly surveillance testing. As a result, the D2 EDG was incorrectly declared operable with a known equipment deficiency. Corrective actions for this issue included declaring the D2 EDG inoperable, repairing the equipment deficiency, and requiring operability decisions to be reviewed by the shift manager.

The inspectors determined that this finding was more than minor because it was associated with the human performance and equipment performance attributes of the Mitigating Systems Cornerstone. In addition, the performance deficiency impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that this finding was of very low safety significance because each of the questions listed under the Mitigating Systems Cornerstone column of IMC 0609.04,

Table 4A could be answered no. The inspectors determined that this finding was cross-cutting in the Human Performance, Decision Making area because the licensee did not make a safety-significant and/or risk-significant decision using a systematic process when faced with uncertain or unexpected plant conditions to ensure that safety was maintained (H.1(a)). (Section 1R15.1b(1))

Green.

The inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion V, on January 19, 2012, due to the licensees failure to properly assess information contained in the Corrective Action Program (CAP) document 1322404 as required by Procedure FP-OP-OL-01,

Operability/Functionality Determination. Specifically, the CAP contained information that a safety-related breaker failed to operate due to a lack of lubrication. However, an extent of condition assessment was not included in CAP 1322404 nor was an operability recommendation assigned to evaluate the potential impact on similar equipment.

Corrective actions included performing an extent of condition review and ensuring that other safety-related equipment remained operable.

The inspectors determined that this issue was more than minor because, if left uncorrected, the failure to properly assess equipment operability could result in inappropriately leaving plant equipment in service (a more significant safety concern).

The inspectors determined that this finding was of very low safety significance because each of the questions listed under the Mitigating Systems Cornerstone column of IMC 0609.04, Table 4A could be answered no. This finding was determined to be cross-cutting in the Human Performance, Decision Making area because the licensee failed to use conservative assumptions when making decisions regarding the continued operability of the breakers discussed above (H.1(b)). (Section 1R15.1b(2))

Green.

A finding of very low safety significance was self revealed on January 7, 2012, due to chemistry personnel failing to comply with requirements contained in Procedure FP-G-DOC-03, Procedure Use and Adherence, prior to draining the sodium hypochlorite draw down tank. Specifically, personnel failed to identify that the procedure used during the draining activity was inadequate. The use of an inadequate procedure led to a pipe break, the release of sodium hypochlorite into a bermed area, and an Alert classification under the licensees emergency plan. No violations of NRC requirements were identified for this issue since the sodium hypochlorite system was non-safety related. Corrective actions for this issue included reviewing chemistry procedure adequacy and increasing supervisory oversight of chemistry activities.

The inspectors determined that this issue was more than minor because it was a precursor to a significant event. Specifically, the licensee declared an ALERT emergency action level due to the sodium hypochlorite spill. The inspectors concluded that the finding was of very low safety significance since all of the questions located in the Mitigating Systems Cornerstone column of IMC 0609.04, Table 4a were answered no. The inspectors determined that this finding was cross-cutting in the Human

Performance, Work Practices area because the licensee failed to ensure supervisory and management oversight of work activities such that nuclear safety was supported (H.4(c)). (Section 4OA3.1)

Green.

A finding of very low safety significance and an NCV of Condition 2.C.4 of the Unit 2 operating license was identified by the inspectors on November 8, 2011, due to the failure to implement and maintain in effect all provisions of the approved fire protection program. Specifically, a wall between the Bus 26 and Bus 27 rooms contained gaps such that it was not able to be credited as a 3-hour fire barrier.

Corrective actions for this issue included establishing a fire watch and repairing the gaps so that the fire barrier/wall provided the required protection.

The inspectors determined that this finding was more than minor because it affected the protection against external factors attribute of the Mitigating Systems Cornerstone.

This finding also affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance because no credible fire scenarios affecting the safe shutdown of Unit 2 existed, the distance between the gap and the safe shutdown equipment was large, and negligible combustible loading existed in the adjacent areas. No cross-cutting issue was identified since the cause of this finding occurred more than three years ago and was not reflective of current plant performance. (Section 4OA5.3)

Green.

A finding of very low safety significance and an NCV of TS 5.4.1 was identified by the inspectors between February 23 and March 27, 2012, due to the licensees failure to maintain the control room narrative logs as required by Procedure FP-OP-COO-19, Logkeeping. Specifically, control room log entries were not properly documented as late entries, failed to provide the basis for operational decisions, and failed to adequately discuss the status of plant equipment.

Corrective actions for this issue included daily management review of control room log entries and the correction of each identified logging deficiency.

The inspectors determined that this issue was more than minor because it was associated with the Mitigating System Cornerstone attribute of Configuration Control, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding was determined to be of very low safety significance because each of the questions contained in IMC 0609.04, Table 4A could be answered no. The inspectors concluded that this finding was cross-cutting in the Human Performance, Work Practices area since the licensee did not support the effective use of human error prevention techniques through proper documentation of activities.

(H.4(a)). (Section 4OA5.4)

Cornerstone: Emergency Preparedness

Green.

A self-revealed finding of very low safety significance and an NCV of 10 CFR 50.72(a)(4) was identified on January 7, 2012, due to the licensees failure to activate the Emergency Response Data System (ERDS) within one hour of an Alert declaration. Specifically, the ERDS was not made operable until 80 minutes after the Alert declaration due to task priority and equipment issues related to a system upgrade.

Corrective actions for this issue included emphasizing the timely activation of ERDS with emergency responders and repairing the system upgrade equipment issues.

The inspectors determined this performance deficiency was more than minor because it was associated with the emergency response organization performance attribute of the Emergency Preparedness Cornerstone and affected the cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was evaluated in accordance with IMC 0609, Appendix B, Emergency Preparedness SDP, that considers a failure to activate ERDS as a failure to implement. Using the Actual Event Implementation Problem Sheet 2, the inspectors determined the finding to be of very low safety significance because it was not a failure to implement a risk significant planning standard. This finding was determined to be cross-cutting in the CAP component of the Problem Identification and Resolution cross-cutting area because the licensee failed to take appropriate corrective actions to address a previously identified ERDS activation issue in a timely manner (P.1(d)). (Section 4OA3.1)

Green.

A self-revealed finding of very low safety significance and an NCV of 10 CFR 50.54(q) was identified on January 7, 2012, due to the licensees failure to follow and maintain their emergency plan in effect. The inspectors identified that the licensees Emergency Response Organization failed to provide adequate staffing for initial facility accident response through the timely augmentation of on-shift staffing as required by 10 CFR 50.47(b)(2). Specifically, four Radiological Protection positions and one Radiological Emergency Coordinator position were not staffed within the 30 minute commitment of Table 1, Guidance for Augmentation of Plant Emergency Organization, in the Prairie Island Emergency Plan. As an interim corrective action, individuals were placed on-shift to ensure that emergency response positions were filled within the required times.

The inspectors determined this performance deficiency was more than minor because it was associated with the emergency response organization performance attribute of the Emergency Preparedness Cornerstone. This finding also affected the cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency.

This finding was evaluated in accordance with IMC 0609, Appendix B, Emergency Preparedness SDP. Using the Actual Event Implementation Problem Sheet 2, the inspectors determined the finding to be of very low safety significance because it was not a failure to implement a risk significant planning standard. This finding was determined to be cross-cutting in the Human Performance, Decision Making area because the licensee failed to communicate the basis for decisions to personnel who have a need to know the information in order to perform work safely and in a timely manner (H.1(c)). (Section 4OA3.1)

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period operating at full power. On January 7, 2012, operations personnel declared an Alert due to a spill of approximately 520 gallons of sodium hypochlorite that created or had the potential to create toxic gas concentrations that were immediately dangerous to life and health (IDLH). This emergency declaration had no impact on Unit 1 operations. Specific details regarding this event are contained in Section 4OA3.1 of this report.

On January 25, 2012, Unit 1 experienced an unexpected reactivity event which resulted in lowering reactor power to 98.5 percent. The licensee determined that the reactivity event occurred due to inadequate preventive maintenance on a chemical and volume control system valve. Once the valve was repaired, operations personnel returned Unit 1 to full power.

Unit 1 operated at full power for the remainder of the inspection period.

Unit 2 began the inspection period operating at full power. On January 7, 2012, operations personnel declared an Alert due to a spill of approximately 520 gallons of sodium hypochlorite which created or had the potential to create toxic gas concentrations which were IDLH.

This emergency declaration had no impact on Unit 2 operations. Specific details regarding the alert are contained in Section 4OA3.1 of this report. On February 13, 2012, Unit 2 began coastdown operations in preparation for refueling outage (RFO) 2R27. Over the next 8 days, reactor power was lowered from 100 percent to approximately 68 percent. On February 21, 2012, operations personnel began activities to shut down the Unit 2 reactor. As Unit 2 reached 11 percent power, operations personnel received alarms indicating that a high, high level condition was occurring in three feedwater heaters. Due to this condition, the operators manually tripped the reactor as required by the alarm response procedures. Major activities planned during 2R27 included the performance of a containment integrated leak rate test, replacement of both battery chargers, and maintenance on multiple pieces of safety-related equipment. On March 5, 2012, operations personnel declared a Notice of Unusual Event (NOUE) due to the detection of a reactor coolant system (RCS) leak of greater than 10 gallons per minute. Details regarding this event are contained in Section 4OA3.3 of this report.

Unit 2 remained shut down at the conclusion of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Auxiliary Building Special Ventilation System;

• Containment/Auxiliary Chiller System;

• D2 Emergency Diesel Generator (EDG); and

• D1 Emergency Diesel Generator (EDG).

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 Updated Safety Analysis Report (USAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition 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 were 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 four partial system walkdown samples as defined in Inspection Procedure (IP) 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

During the week of March 12, 2012, the inspectors performed a complete system walkdown inspection of the Unit 2 reactor vessel level instrumentation to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant while Unit 2 was shut down for a RFO.

The inspectors walked down the system to review equipment line ups, system pressure and temperature indications, as appropriate, component labeling, component and equipment hangers and supports, 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:

• Fire Area 32 - Train B Hot Shutdown Panel Area;

• Fire Area 58 - Unit 1 695 Foot Elevation Auxiliary Building;

• Fire Area 18 - Relay and Cable Spreading Room (Units 1 & 2); and

• Various Fire Protection Panels.

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 (OOS), 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 licensees 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. 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 four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

.1 Internal Flooding

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:

• 13kV Underground Vault Inspection.

Documents reviewed are listed in the Attachment to this report. This inspection constituted one underground vault sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the Unit 2 component cooling water heat exchangers to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk.

The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R08 Inservice Inspection (ISI) Activities

From February 27 through March 9, 2012, the inspectors conducted a review of the implementation of the licensees ISI Program for monitoring degradation of the Unit 2 RCS, steam generator tubes, emergency feedwater systems, risk-significant piping and components, and containment systems.

The inspections described in Sections 1R08.1 through 1R08.5 below constituted one ISI sample as defined by IP 71111.08-05.

.1 Piping Systems ISI

a. Inspection Scope

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

• Ultrasonic examination (UT) of Pressurizer Bottom Head to Shell Weld W-3;

• UT on the Pressurizer Surge Line Nozzle Inner Radius (IR) N1-IR;

• Visual examination of the Pressurizer Base W-6;

• Magnetic Particle examination of the Pressurizer Base Integral Attachment H1;

• UT of Safety Injection Discharge Line Elbow to Pipe Weld W-16; and

• Visual Examination of Auxiliary Feedwater Single Support AFWH-69.

The inspectors reviewed the following examination records with relevant/recordable conditions/indications identified by the licensee to determine if acceptance of these indications for continued service was in accordance with the ASME Code Section XI or an NRC-approved alternative:

• Report No. 2011P017, Surface examination (dye penetrant exam or (PT)) on Reactor Coolant System Integral Attachment H2/IA;

• Report No. 2004P033, PT on Reactor Coolant Pump Integral Attachment H-1/IA;

• Report No. 2011P011, PT on Volume Control System Integral Attachment H-1/IA; and

• Report No. 2011P023, PT on Welded Attachment of Pipe Support 1-RCVCH-9220.

The inspectors reviewed the following pressure boundary welds completed for risk significant Unit 2 systems to determine if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by the construction Code, ASME Section XI Code and NRC approved Code Cases. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of the ASME Code Section IX.

• WO 386516-04 Re-Welded Canopy after Boric Acid Deposit Removal; and

• WO 400618-01 Installation of Vent at High Point in Piping.

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the replaced Unit 2 vessel head no examinations (visual or non-visual) were required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D) requirements. Therefore, no examination was conducted by the licensee and no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control (BACC)

a. Inspection Scope

On February 22, 2011, the inspectors observed the licensee staff performing visual examinations of the Unit 2 reactor coolant and emergency core cooling systems within containment to determine if these visual examinations focused on locations where boric acid leaks could cause degradation of safety-significant components.

The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to determine if degraded components were documented in the CAP.

The inspectors also evaluated corrective actions for any degraded RCS components to determine if they met the ASME Section XI Code.

• BACC Evaluation 1248387 - 2FE-924 Unit 2 Safety Injection Reactor Vessel Injection Line Orifice;

• BACC Evaluation 1262814 - 145-041 11 Charging Pump Corrosion Evaluation; and

• BACC Evaluation 1307386 - 2RC-18-1 RCD B Hot Leg Drain to Reactor Coolant Drain Tank Indication Evaluation.

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

• CAP 1302101 - 13 Charging Pump Identified as Having Boric Acid Leakage;

• CAP 1273803 - 11 Safety Injection Pump Identified to Have Inboard Seal Leak;

• CAP 1270554 - 21 Residual Heat Removal (RHR) Pump Suction Line Identified as Having Boric Acid Indication;

• CAP 1227770 - 2RC-8-15 Loop Seal Drain for Pressurizer Safety Valve has Boric Acid Leakage; and

• CAP 1233486 - 2RC-8-31 Reactor Head Vent Flushing Valve has Boric Acid Indications.

b. Findings

No findings were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET data analysts, and reviewed documentation related to the SG ISI program to determine if:

• In-situ SG tube pressure testing screening criteria used were consistent with those identified in the Electric Power Research Institute (EPRI) TR-107620, Steam Generator In-Situ Pressure Test Guidelines, and that these criteria were properly applied to screen degraded SG tubes for in-situ pressure testing;

• the numbers and sizes of SG tube flaws/degradation identified was bounded by the licensees previous outage Operational Assessment predictions;

• the SG tube ET examination scope and expansion criteria were sufficient to meet the TS, and EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• the SG tube ET examination scope included potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to these SG tubes;

• the licensee identified new tube degradation mechanisms and implemented adequate extent of condition inspection scope and repairs for the new tube degradation mechanism;

• the licensee implemented repair methods which were consistent with the repair processes allowed in the plant TS requirements and to determine if qualified depth sizing methods were applied to degraded tubes accepted for continued service;

• the licensee implemented an inappropriate plug on detection tube repair threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);

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

• the ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• the licensee performed secondary side SG inspections for location and removal of foreign materials; and

• inaccessible foreign objects were left within the secondary side of the SGs, and if so, that the licensee implemented evaluations, which included the effects of foreign object migration and/or tube fretting damage.

The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

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

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

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

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

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On the afternoon of January 21, 2012, the inspectors observed a crew of licensed operators in the simulator during licensed operator requalification activities to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was 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 (EP) actions and notifications.

The crews performance in these areas was compared to pre-established operator action 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.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On February 21, 2012, the inspectors observed activities in the control room during the Unit 2 shutdown for RFO 2R27. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms (if applicable);

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and EP actions and notifications.

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk 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:

• Auxiliary Building Special Ventilation System;

• Steam Exclusion System; and

• 21 Reactor Vessel (RV) Gap Cooling Fan Breaker 212E-44.

The inspectors reviewed events 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 re-classification; 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

(1) Failure of Safety-Related Breaker 212E-44

Introduction:

A self-revealed finding of very low safety significance (Green) and a non-cited violation (NCV) of TS 5.4.1 occurred on January 19, 2012, due to the safety-related breaker for the 21 RV gap cooling fan failing while in service. Specifically, preventive maintenance (PM) activities used to ensure the breaker remained operable were not performed in a timely manner.

Description:

On January 19, 2012, operations personnel received a control room alarm when the 21 RV gap cooling fan tripped. The control room operators responded to the alarm, placed the remaining RV gap fan into operation, monitored temperatures to ensure that the inner concrete shield around the RV remained cool, and initiated a WO to have the condition repaired.

Approximately one week later, maintenance personnel determined that the 21 RV gap cooling fan tripped due to the failure of its safety-related power supply (breaker 212E-44). Specifically, maintenance personnel identified that the C phase of the breaker would not open and the breakers auxiliary contacts contained a substance believed to be hardened grease. The electricians documented the breakers condition in CAP 1322404. After replacing the defective/failed breaker parts, the electricians satisfactorily performed breaker as-left testing.

The inspectors discussed the maintenance work history for breaker 212E-44 with engineering personnel. During these discussions, the inspectors were informed that PM activities were last performed on December 9, 1998. The inspectors reviewed the current PM program requirements and found that breaker 212E-44 was to have PM activities completed every 12 years (by December 9, 2010). Since more than 13 years had elapsed, the inspectors questioned engineering personnel to determine why PM on breaker 212E-44 had not been performed. The inspectors were informed that breaker 212E-44 was scheduled for PM as part of an April 2010 RFO. However, this activity was removed from the outage schedule in March 2010 since the activity could be performed when the reactor was producing power. While the inspectors agreed that the activity could be performed when the reactor was at power, the work had not been performed.

Analysis:

The inspectors determined that the failure to perform PM on breaker 212E-44 in a timely manner was a performance deficiency that required an evaluation using the Significance Determination Program (SDP). The inspectors determined that this issue was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability (such as having to perform a reactor shutdown). The inspectors assessed the significance of this finding using IMC 0609.04, Table 4a. The inspectors determined that the finding was of very low safety significance (Green) since it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available.

The inspectors concluded that this finding was cross-cutting in the Human Performance, Work Control area because the licensee failed to appropriately coordinate work activities to support the continued operability and reliability of breaker 212E-44 (H.3(b)).

Enforcement:

Technical Specification 5.4.1 requires that written procedures be established, implemented and maintained covering the applicable procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978.

Section 9 of RG 1.33, Revision 2, Appendix A, February 1978, requires that maintenance that can affect the performance of safety-related equipment be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstance.

Contrary to the above, on January 19, 2012, the licensee failed to establish, implement and maintain procedures to perform PM on safety-related breaker 212E-44. As a result, the breaker failed while in service. Because this violation was of very low safety significance and it was entered into the CAP as CAP 1322404, this issue is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000306/2012002-01: Breaker 212E-44 Failure due to Lack of Preventive Maintenance). Corrective actions for this event included repairing/replacing the breaker for the RV gap cooling fan, performing an extent of condition review, and ensuring that PM activities for similar breakers were appropriately scheduled or completed.

(2) Repeat Failure of Steam Exclusion Dampers CD-34187 and CD-34188

Introduction:

The inspectors identified an unresolved item (URI) due to the repeated failure of steam exclusion (SE) dampers located on the 695 foot elevation of the auxiliary building.

Description:

On March 21, 2012, the licensee performed surveillance testing on the SE system as directed by Surveillance Procedure (SP) 1112, Steam Exclusion Damper Monthly Test. The purpose of the test was to ensure that SE dampers used to protect certain areas of the plant from a high energy line break (HELB) event closed as required.

During the test, the licensee identified that control dampers CD-34187 and CD-34188 failed to fully close. Specifically, both dampers contained several gaps between the damper blades. Operations personnel immediately declared the dampers non-functional and entered Technical Requirements Manual Limiting Condition for Operation (TLCO)3.7.1. Operations personnel closed both of the SE dampers to comply with the TLCO.

Both dampers remained OOS at the conclusion of the inspection period.

Over the last several months, the inspectors have reviewed multiple CAP documents regarding the failure of one or both of the control dampers. As a result, the inspectors were concerned that maintenance personnel may not be implementing appropriate work practices during the damper repairs and/or the licensee may not be properly identifying and addressing the potential for common cause damper failures. The inspectors reviewed the surveillance test history for control dampers CD-34187 and CD-34188 since September 2011. The inspectors determined that damper CD-34187 had failed its surveillance test two out of the last six times while CD-34188 had failed four of the last six tests. The licensee initiated CAPs 1326072 and 1330276 to document the issues with the SE dampers. The licensee was evaluating the potential maintenance issues at the conclusion of the inspection period. As a result, determinations regarding maintenance effectiveness and the potential for common cause failure will be considered unresolved pending a review of the licensees causal evaluation (URI 05000282/2012002-02; 05000306/2012002-02: Review of Steam Exclusion Damper Maintenance Effectiveness).

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:

• Unit 1 Pressurizer Level Controller due to an emergent issue;

• 22 Diesel Driven Cooling Water Pump 3-Way Valve due to an emergent issue;

• D5 EDG Motor Damper 32421 due to its failure to close;

• The movement of outage related materials over the spent fuel pool (SFP); and

• A trip of the SFP supplemental cooling system power supply.

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 Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• D2 EDG operability following the performance of SP 1305 on February 23, 2012;

• Auxiliary Building ventilation operability following the discovery of a non-conservative TS;

• Unit 1 Shield Building operability following the discovery of a missed mode restraint during a previous RFO;

• Continued operability of similar breakers following the discovery of hardened grease in Breaker 212E-44;

• Operability Recommendation (OPR) 1265904, Revision 2 - Battery Room Heatup Concerns;

• OPR 1266815, Revision 3 - Auxiliary Feedwater Pump Room Heatup Concerns; and

• OPR 1324369, Revisions 0 and 1 - Adequate Undervoltage Protection for Safety-Related Electrical Buses.

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 seven samples as defined in IP 71111.15-05.

b. Findings

(1) Failure to Properly Assess Operability of D2 EDG Following Surveillance Testing

Introduction:

A finding of very low safety significance (Green) and an NCV of TS 3.8.1 were identified by the inspectors on February 23, 2012, due to the licensees failure to properly assess the continued operability of the D2 EDG following monthly surveillance testing.

Description:

On February 23, 2012, operations personnel performed monthly surveillance testing of the D2 EDG using SP 1305, D2 Monthly Slow Start.

At 10:19 a.m., operations personnel entered TS 3.8.1, Condition B, as required by Step 7.7 of SP 1305. Entry into TS 3.8.1 required the operators to verify the correct breaker alignment and indicated power availability for each required electrical path within one hour and once per eight hours thereafter. Operations personnel completed the breaker alignment and power availability verifications at 10:35 a.m.

During a review of the control room logs on February 24, 2012, the inspectors noted that temperature controller (TC) TC-26303 had failed to provide an output during the performance of SP 1305. This TC was used to control airflow into the D2 EDG room by varying the cooling supply and exhaust fan blade pitch. The inspectors confirmed that operations personnel initiated Work Request 76994 to document the TC deficiency.

The inspectors also noted that the day-shift Unit 1 shift supervisor declared the D2 EDG operable following the completion of SP 1305. However at 9:50 p.m., the night-shift Unit 1 shift supervisor declared the D2 EDG inoperable due to the TC issue.

The inspectors questioned operations personnel regarding the decision to declare the D2 EDG operable following the performance of SP 1305 and the subsequent declaration of inoperability. The operations department informed the inspectors that the night-shift operations crew had received information that the TC had failed such that air flow was inadequate to support EDG operability. During a review of corrective action documents from February 23, the inspectors identified a CAP written by a non-licensed operator that was in the D2 EDG room during the performance of SP 1305. The CAP stated that the air flow into the D2 EDG room was less than expected and that the fan blade pitch was at the minimum position. The inspectors presented this information to the operations department. After further review, the operations department agreed that the D2 EDG should not have been declared operable following the completion of SP 1305. Due to the inappropriate operability declaration, operations personnel failed to perform the breaker alignment and power availability verification as required by TS within the required completion time.

Analysis:

The inspectors determined that the failure to properly assess the continued operability of the D2 EDG in accordance with TS 3.8.1 was a performance deficiency that required evaluation using the SDP. The inspectors determined that this finding was more than minor because it was associated with the human performance and equipment performance attributes of the Mitigating Systems Cornerstone. In addition, the performance deficiency impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors assessed this finding using IMC 0609.04, At-Power Significance Determination Process, Table 4a, and determined that this finding was of very low safety significance (Green) because each of the questions listed the Mitigating Systems Cornerstone column could be answered no. The inspectors determined that this finding was cross-cutting in the Human Performance, Decision Making area because the licensee did not make a safety-significant and/or risk-significant decision using a systematic process when faced with uncertain or unexpected plant conditions to ensure that safety was maintained (H.1(a)).

Enforcement:

Technical Specification 3.8.1 requires that two diesel generators capable of supplying the onsite 4 kilovolt safeguards distribution system be operable when the reactor is operating in Modes 1 through 4.

Technical Specification 3.8.1, Condition B, requires that the licensee verify the correct breaker alignment and indicated power availability for each required electrical path within one hour and once per eight hours thereafter.

Technical Specification 3.8.1, Condition F, requires that the reactor be placed in Mode 3 within six hours and be in Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> if the requirements of TS 3.8.1, Condition B are not met within the specified time.

Contrary to the above, on February 23, 2012, licensee personnel failed to properly assess the operability of the D2 EDG following surveillance testing. As a result, operations personnel failed to verify the correct breaker alignment and indicated power availability for each required electrical path within one hour and once per eight hours thereafter. In addition, operations personnel did not take action to place Unit 1 in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> since the appropriate operability declaration was not known.

Because this violation was of very low safety significance and it was entered into the CAP as CAP 1327207, this issue is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2012002-03: Failure to Properly Assess Operability of D2 EDG following Surveillance Testing).

Corrective actions for this issue included repairing the D2 EDG temperature controller, emphasizing improved communications between operations department crew members to ensure that information regarding identified equipment deficiencies were appropriately discussed and understood, and ensuring that operability discussions are held with the shift manager prior to making a final operability declaration.

(2) Failure to Properly Assess Operability of Similar Molded Case Circuit Breakers Following the Identification of Hardened Grease

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an NCV of 10 CFR Part 50, Appendix B, Criterion V, due to the licensees failure to properly assess information contained in CAP 1322404 as required by Procedure FP-OP-OL-01, Operability/Functionality Determination.

Description:

On January 26, 2012, the licensee initiated CAP 1322404 to document that safety-related breaker 212E-44 was found unable to function. Specifically, information contained in the CAP indicated that the breaker failed to function due to inadequate lubrication (dried up grease) and the C phase contacts being unable to open.

The inspectors reviewed CAP 1322404 on January 27, 2012. Immediately after reviewing the CAP document, the inspectors were concerned that other safety-related breakers could be susceptible to failure due to hardened grease. The inspectors printed out several copies of CAP 1322404 and discussed the contents of the CAP with multiple licensee individuals. Each individual stated that they were aware of the serious nature of CAP 1322404, that an evaluation was needed to ensure that other breakers were not susceptible to a similar failure, and that this information would be provided to the operations department in a timely manner so that the continued operability of breakers similar to breaker 212E-44 could be assessed.

On or about February 8, 2012, engineering personnel provided information to the inspectors regarding breakers that were similar to breaker 212E-44. Specifically, the inspectors were told that four breakers (which included breaker 212E-44) were scheduled for PM during the previous Unit 2 RFO. However, the PM was not completed because the maintenance activity could be performed when the reactor was in operation.

A review of the maintenance work history showed that two breakers received PM in 2010. The maintenance department planned to complete the PM on the remaining breaker within the following 10 days.

The inspectors reviewed Procedure FP-OP-OL-01, Operability/Functionality Determination, to determine the procedural requirements. Section 5.3.1.3.1 of the procedure stated that operability determinations/recommendations shall be sufficient to address the capability of the SSCs to perform their specified safety functions.

Step 5.3.1.3.2 directed that operability determinations/recommendations include the extent of condition for all similarly affected SSCs. Lastly, Step 5.3.1.1 stated the following:

"A prompt (follow-up) determination of operability shall be performed when additional information is needed to confirm operability.

Typically this is able to be completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of discovery."

Based upon the review of CAP 1322404 discussed above, the inspectors determined that the operability determination included in the CAP was not sufficient to address the capability of the SSCs to perform their specified safety function. Specifically, the determination failed to include an extent of condition assessment and no prompt operability determination was assigned to ensure that an extent of condition assessment was completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. While the information provided to the inspectors by the engineering department on February 8, 2012, was similar to an extent of condition review, an operability determination which included this information was not provided.

The inspectors were subsequently informed that the PM scheduled on the remaining susceptible breaker was removed from the work schedule due to a lack of resources to complete the work. However, the inspectors could not find any evidence to show that this information was communicated to the operations department so that operability impacts could be re-assessed.

Analysis:

The inspectors determined that the failure to properly assess the operability of breakers associated with CAP 1322404 as required by FP-OP-OL-01 was a performance deficiency that required an evaluation using the SDP. The finding impacted the Mitigating Systems Cornerstone. The inspectors determined that this issue was more than minor because, if left uncorrected, the failure to properly assess equipment operability could result in leaving plant equipment in service even though it was unable to perform its specified safety function (a more significant safety concern).

The inspectors performed a Phase 1 SDP screening using IMC 0609.04, Table 4a, Characterization Worksheet for Mitigating Systems, and determined that this finding was of very low safety significance (Green) because each of the questions contained under the Mitigating Systems column were answered no. This finding was determined to be cross-cutting in the Human Performance, Decision Making, Conservative Assumptions area because the licensee failed to use conservative assumptions when making decisions regarding the continued operability of the breakers discussed above (H.1(b)).

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. Section 5.3.1.3.1 of this procedure stated that operability determinations/recommendations shall be sufficient to address the capability of the SSCs to perform their specified safety functions. Step 5.3.1.3.2 directed that operability determinations/recommendations include the extent of condition for all similarly affected SSCs. Lastly, Step 5.3.1.1 stated that a prompt (follow-up) determination of operability shall be performed when additional information is needed to confirm operability.

Typically, this is completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of discovery.

Contrary to the above, on January 26, 2012, the licensee failed to perform an operability determination/recommendation that was sufficient to address the capability of the SSCs discussed above to perform their specified safety functions in that it failed to include an extent of condition review. In addition, a prompt determination of operability was not performed to confirm operability of similar breakers. Lastly, operability was not assessed when the licensee decided to cancel PM on one of the similar breakers.

Because this violation was of very low safety significance and it was entered into the CAP as CAP 1322404, this issue is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2012002-04; 05000306/2012002-04; Failure to Assess Operability of Circuit Breakers due to Inadequate Lubrication). Corrective actions for this issue included assessing continued operability and adding the PM task for the remaining breaker to the current Unit 2 RFO schedule.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modifications:

• Engineering Change 19503 - Install Manual Valve Bonnet on CV-31200; and

• SFP / Component Cooling Water Heat Exchanger Supplemental 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 are listed in the Attachment to this report.

This inspection constituted two 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 post-maintenance activities associated with the following components or systems to verify that procedures and test activities were adequate to ensure operability and functional capability:

• Actuator replacement for boric acid blender valve CV-31200;

• D2 EDG following replacement of a TC;

• D5 EDG ventilation system following maintenance on damper MD-32421;

• D6 EDG following RFO maintenance; and

• 21 battery charger following replacement.

These activities were selected based upon the SSC's ability to impact risk.

The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria was 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 TSs, 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 CAP 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 five post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 2 RFO which began on February 21, 2012, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth.

During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below. .

• Licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TS when taking equipment OOS;

• Configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error;

• Controls over the status and configuration of electrical systems to ensure that TS and OSP requirements were met, and controls over switchyard activities;

• Monitoring of decay heat removal processes, systems, and components;

• Controls to ensure that outage work was not impacting the ability of the operators to operate the SFP cooling system;

• Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss;

• Controls over activities that could affect reactivity;

• Maintenance of secondary containment as required by TS;

• Refueling and fuel handling activities; and

• Licensee identification and resolution of problems related to RFO activities.

Documents reviewed are listed in the Attachment to this report. An inspection sample was not credited for this inspection since the RFO was not complete at the conclusion of the inspection period.

b. Findings

A URI was identified and documented in Section 4OA3.3 of this report.

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(s) and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• SP 1027.2A - Nuclear Management Company Radiation Monitor Train A Calibration (routine);

• SP 1305 - D2 Monthly Slow Start (routine);

• SP 2155A - Component Cooling Water System Quarterly Test Train A (inservice test);

• SP 2286 - Sump A Pump Discharge Containment Isolation Valve Quarterly (RCS);

• SP 2361 - Exercising Feedwater Isolation and Feedwater Check Valves During Refueling Outage (containment isolation valve);

• SP 2369 - Unit 2 Residual Heat Removal System Alignment (routine);

• SP 2406 - Main Steam Valve Inservice Test (containment isolation valve); and

• SP 2431A - Trevitesting (routine).

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

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

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

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

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

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

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

Documents reviewed are listed in the Attachment to this report.

This inspection constituted four routine surveillance testing samples, one inservice testing sample, one RCS leak detection inspection sample, and two containment isolation valve samples 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 4, 2012, 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 (TSC) and the Emergency Operations Facility (EOF) 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 CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the 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 inspectors observed a simulator training evolution for licensed operators on the morning of January 21, 2012, and on February 4, 2012, which required emergency plan implementation by a licensee operations crew. 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 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 CAP. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.

The inspections discussed above constituted the completion of two licensee training evolutions with emergency preparedness drill samples as defined in IP 71114.06-05.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

.1 Inspection Planning (02.01)

This inspection constituted a partial sample as defined in IP 71124.01-05.

a. Inspection Scope

The inspectors reviewed the following licensee information to gain insights into current performance:

• performance indicators for the occupational exposure cornerstone;

• the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits);

• reports of operational occurrences related to occupational radiation safety since the last inspection; and

• audit and operational reports.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

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

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

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

• Unit 2 Containment Integrated Leak Rate Test;

• SFP Transfer Canal Work; and

• Chemistry Department Sampling and Laboratory

Analysis.

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

• identification of hot particles;

• the presence of alpha emitters;

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

• the hazards associated with work activities that could suddenly and severely increase radiological conditions and that the licensee had established a means to inform workers of changes that could significantly impact their occupational dose; and

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

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

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

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

• Unit 2 Containment Integrated Leak Rate Test;

• SFP Transfer Canal Work; and

• Chemistry Department Sampling and Laboratory

Analysis.

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

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

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

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitored potentially contaminated material leaving the radiological control 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, evaluated whether the work was performed in accordance with plant procedures, and whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

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

The inspectors reviewed the following RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures:

• Unit 2 Containment Integrated Leak Rate Test;

• SFP Transfer Canal Work; and

• Chemistry Department Sampling and laboratory

Analysis.

For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high-efficiency particulate air ventilation system operation.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools. The inspectors assessed whether appropriate controls (i.e., administrative and physical controls) were in place to preclude inadvertent removal of these materials from the pool.

b. Findings

No findings were identified.

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

a. Inspection Scope

The inspectors discussed the controls and procedures for high-risk high radiation areas and very high radiation areas with the radiation protection manager. The inspectors also discussed methods employed by the licensee to provide stricter control of very high radiation area access as specified in 10 CFR 20.1602, Control of Access to Very High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and Very High Radiation Areas of Nuclear Plants. The inspectors assessed whether any changes to licensee procedures substantially reduced the effectiveness and level of worker protection.

The inspectors discussed the controls in place for special areas that had the potential to become very high radiation areas during certain plant operations with first-line health physics supervisors (or equivalent positions having backshift health physics oversight authority). The inspectors assessed whether these plant operations required communication beforehand with the health physics group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including re-access authorization.

The inspectors evaluated licensee controls for very high radiation areas and areas with the potential to become very high radiation areas to ensure that an individual was not able to gain unauthorized access to the very high radiation area.

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed any problems with the corrective actions planned or taken with the radiation protection manager.

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all radiation protection work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the RWP controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection and found the cause of the event to be radiation protection technician error. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involved radiation monitoring and exposure controls.

The inspectors assessed the licensees process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS2 Occupational As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls

This inspection constituted a partial sample as defined in IP 71124.02-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

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

The inspectors reviewed the site-specific trends in collective exposures (using NUREG-0713, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and Other Facilities, and plant historical data) and source term (average contact dose rate with reactor coolant piping) measurements.

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

b. Findings

No findings were identified.

.2 Radiological Work Planning (02.02)

a. Inspection Scope

The inspectors selected the following work activities of the highest exposure significance:

• Unit 2 Containment Integrated Leak Rate Test;

• SFP Transfer Canal Work; and

• Chemistry Department Sampling and Laboratory

Analysis.

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors determined whether the licensee reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.

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

b. Findings

No findings were identified.

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

a. Inspection Scope

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

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

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

The inspectors evaluated the licensees method of adjusting exposure estimates, or re-planning work, when unexpected changes in scope or emergent work were encountered. The inspectors assessed whether adjustments to exposure estimates (intended dose) were based on sound radiation protection and ALARA principles or if they were just adjusted to account for failures to control the work. The inspectors evaluated whether the frequency of these adjustments called into question the adequacy of the original ALARA planning process.

b. Findings

No findings were identified.

.4 Problem Identification and Resolution (02.06)

a. Inspection Scope

The inspectors evaluated whether problems associated with ALARA planning and controls were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

This inspection constituted a partial sample as defined in IP 71124.06-05.

.1 Inspection Planning and Program Reviews (02.01)

Event Report and Effluent Report Reviews

a. Inspection Scope

The inspectors reviewed the Radiological Effluent Release Reports issued since the last inspection to determine if the reports were submitted as required by the Offsite Dose Calculation Manual (ODCM)/TSs. The inspectors reviewed anomalous results, unexpected trends, or abnormal releases identified by the licensee for further inspection to determine if they were evaluated, were entered in the CAP, and were adequately resolved.

The inspectors identified radioactive effluent monitor operability issues reported by the licensee as provided in effluent release reports. These issues were reviewed, as warranted, to determine if the issues were entered into the CAP and were adequately resolved.

b. Findings

No findings were identified.

Offsite Dose Calculation Manual and Updated Safety Analysis Report Review

a. Inspection Scope

The inspectors reviewed USAR descriptions of the radioactive effluent monitoring systems, treatment systems, and effluent flow paths so they could be evaluated during inspection walkdowns.

The inspectors reviewed changes to the ODCM made by the licensee since the last inspection against the guidance in NUREG-1301, 1302 and 0133, and Regulatory Guides 1.109, 1.21 and 4.1. When differences were identified, the inspectors reviewed the technical basis or evaluations of the change during the onsite inspection to determine whether they were technically justified and maintained effluent releases ALARA.

The inspectors reviewed licensee documentation to determine if the licensee had identified any non-radioactive systems that had become contaminated as disclosed either through an event report or the ODCM since the last inspection. This review provided an intelligent sample list for the onsite inspection of any 10 CFR 50.59 evaluations and allowed a determination if any newly contaminated systems had an unmonitored effluent discharge path to the environment, whether any required ODCM revisions were made to incorporate these new pathways, and whether the associated effluents were reported in accordance with Regulatory Guide 1.21.

b. Findings

No findings were identified.

Groundwater Protection Initiative (GPI) Program

a. Inspection Scope

The inspectors reviewed reported groundwater monitoring results and changes to the licensees program for identifying and controlling contaminated spills/leaks to groundwater.

b. Findings

No findings were identified.

Procedures, Special Reports, and Other Documents

a. Inspection Scope

The inspectors reviewed Licensee Event Reports (LERs), event reports and/or special reports related to the effluent program issued since the previous inspection to identify any additional focus areas for the inspection based on the scope/breadth of problems described in these reports.

The inspectors reviewed effluent program implementing procedures, particularly those associated with effluent sampling, effluent monitor set-point determinations, and dose calculations.

The inspectors reviewed copies of licensee and third party (independent) evaluation reports of the effluent monitoring program since the last inspection to gather insights into the licensees program and aid in selecting areas for inspection review (smart sampling).

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors determined if the licensee had made significant changes to their effluent release points, e.g., changes subject to a 10 CFR 50.59 review or changes that required NRC approval of alternate discharge points.

b. Findings

No findings were identified.

.3 Sampling and Analyses (02.03)

a. Inspection Scope

The inspectors selected effluent discharges made with inoperable (declared out-of-service) effluent radiation monitors to assess whether controls were in place to ensure compensatory sampling was performed consistent with the Radiological Effluent Technical Specifications (RETS)/ODCM and that those controls were adequate to prevent the release of unmonitored liquid and gaseous effluents.

b. Findings

No findings were identified.

.4 Dose Calculations (02.05)

a. Inspection Scope

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

to ensure the abnormal discharge was monitored by the discharge point effluent monitor.

Discharges made with inoperable effluent radiation monitors, or unmonitored leakages, were reviewed to ensure that an evaluation of the discharge was made to satisfy 10 CFR 20.1501 requirements.

b. Findings

No findings were identified.

.5 GPI Implementation (02.06)

a. Inspection Scope

The inspectors reviewed monitoring results of the GPI to determine if the licensee had implemented its program as intended and to identify any anomalous results.

For anomalous results or missed samples, the inspectors assessed whether the licensee had identified and addressed deficiencies through the CAP.

The inspectors reviewed identified leakage or spill events and entries made into 10 CFR 50.75

(g) records. The inspectors reviewed evaluations of leaks or spills and reviewed any remediation actions taken for effectiveness. The inspectors reviewed onsite contamination events involving contamination of ground water and assessed whether the source of the leak or spill was identified and mitigated.

b. Findings

No findings were identified.

.6 Problem Identification and Resolution (02.07)

a. Inspection Scope

The inspectors assessed whether problems associated with the effluent monitoring and control program were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the CAP. In addition, the inspectors evaluated the appropriateness of the corrective actions for a selected sample of problems documented by the licensee involving radiation monitoring and exposure controls.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

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 performance indicator (PI) for Prairie Island Nuclear Generating Plant, Units 1 and 2, for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Inspection Reports for the period of time given above to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report 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 PI for Prairie Island Nuclear Generating Plant, Units 1 and 2, for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Inspection Reports for the period of time given above to validate the accuracy of the submittals.

The inspectors also reviewed the licensees issue report 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 Prairie Island Nuclear Generating Plant, Units 1 and 2, for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Inspection Reports for the period of time given above to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report 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.

.4 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the Safety System Functional Failures PI for Prairie Island Nuclear Generating Plant, Units 1 and 2, for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73" definitions and guidance, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Inspection Reports for the period of time given above to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report 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 to this report.

This inspection constituted two safety system functional failures samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.5 Reactor Coolant System Specific Activity

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Specific Activity PI for Prairie Island Nuclear Generating Plant, Units 1 and 2, for the period from the third quarter 2011 through the fourth quarter 2011. The inspectors used PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees RCS chemistry samples, TS requirements, issue reports, event reports, and NRC Integrated Inspection Reports to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI 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 a reactor coolant system sample. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two RCS specific activity samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.6 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences PI for the period from the third quarter 2011 through the fourth quarter 2011. The inspectors used PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods.

The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if indicator related data was adequately assessed and reported.

To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed the scope and breadth of the licensees data review and the results of those reviews with the radiation protection staff. The inspectors independently reviewed electronic personal dosimetry dose rate and accumulated dose alarms, 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. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one occupational exposure control effectiveness sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.7 Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent

Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent TS (RETS)/Offsite Dose Calculation Manual (ODCM) Radiological Effluent Occurrences PI for the period from the third quarter 2011 through the fourth quarter 2011.

The inspectors used PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences 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 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.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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 (CAP)

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 was 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 CAP 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 CAP 1308866 - Cooling Water

Strainers Control Train Separation

a. Inspection Scope

On October 18, 2011, the licensee initiated CAP 1308866 as part of an extent of cause review. The extent of cause review was performed as part of the corrective actions to address a White finding associated with the Unit 1 safety-related battery chargers as documented in NRC Inspection Reports 05000282/2010005; 05000306/2010005 and 05000282/2011010; 05000306/2011010. The inspectors reviewed CAP 1308866 and discussed the CAP evaluation and completion with engineering personnel.

The inspectors also reviewed the results of the CAP against design and licensing basis information contained in the USAR, TS, design basis documents, and previously issued plant specific NRC Task Interface Agreements. Documents reviewed are provided in the to this report.

This review constituted one selected issue sample as required by IP 71152.

b. Observations and Findings

During the 1990s the licensee completed a review of their design basis documents.

This review resulted in the initiation of questions called Follow-On Items (FOIs).

In June 1993, the licensee initiated FOI A0797 to document that the loss of Electrical Panel 136 could result in the inability to automatically backwash the cooling water strainers. The inability to backwash the strainers could eventually inhibit cooling water flow to multiple safety-related systems. This FOI also documented that the June 1993 operating procedures failed to contain information regarding cooling water strainer operation.

As part of the extent of cause review discussed above, the licensee developed a systematic process to re-assess the FOIs. During the FOI review, the licensee initiated CAP 1308866 to document concerns regarding the completion of FOI A0797.

Specifically, the licensee was concerned that actions taken in response to FOI A0797 were similar to the actions initially taken to address the battery charger design deficiencies.

The licensee completed actions associated with CAP 1308866 on November 15, 2011.

The inspectors reviewed the completed actions and determined that the licensee had not fully evaluated the information contained within CAP 1308866 due to poor communications within the engineering department. Specifically, CAP recommendations to review the adequacy of the strainer backwash operability declaration, whether cooling water system procedure changes made in 1993 were compensatory measures, and whether manual operation of the strainers following the loss of Electrical Panel 136 needed to be evaluated as a manual action in place of an automatic action (or as a time critical operator action) were not addressed. However, the engineering department was assigned a condition evaluation to evaluate whether the cooling water strainer backwash control system met electrical separation requirements.

The inspectors discussed the recommended CAP actions and the condition evaluation with representatives from the engineering and operations departments. The engineers interviewed stated that they requested clarification regarding the differences between the CAPs recommended actions and the condition evaluation assignment with both engineering and CAP personnel. The engineers were instructed to evaluate whether the electrical separation was adequate. Based upon discussions with the inspectors, engineering and operations department personnel recognized that the recommendations made in CAP 1308866 needed to be addressed. Corrective action document 1308866 was re-opened following the discussion with the inspectors.

(1) Review of Electrical Separation Requirements The inspectors reviewed the electrical separation requirements for safety-related equipment, current and historical cooling water strainer backwash circuitry drawings, and the Prairie Island Safety Evaluation Report written by the NRC prior to issuing the original operating licenses. The inspectors determined that the cooling water system design was reviewed and approved by the NRC prior to plant operation. In addition, the cooling water strainer backwash control logic and electrical design had not been modified since initial plant construction. As a result, the strainer backwash design continued to meet the electrical separation requirements in place when the plant was built.

(2) Adequacy of 1993 Operability Declaration The inspectors reviewed the operability declaration provided in FOI A0797 and determined that while it met the 1993 standards, it did not meet current operability standards. Since the operability evaluation performed in 1993 met the standards in place during this time, the corresponding cooling water system procedure changes were not compensatory measures. The inspectors determined that the failure of the 1993 operability evaluation to meet current standards was not a violation since the licensee was not required to maintain historical documents consistent with current standards.

However, the licensee performed an additional operability review when CAP 1308866 was initiated. The inspectors reviewed the most recent operability declaration and had no concerns.

(3) Review of Manual Actions Following the Loss of Electrical Panel 136 The inspectors questioned engineering personnel to determine whether manual actions would be needed to address a loss of Electrical Panel 136 as part of an internal or an external event. The inspectors reviewed Engineering Change 19738, Evaluation of Operator Actions for Cooling Water Strainer Backwash, Revision 0. With regards to external events such as flooding or a seismic event, the licensee determined that the current licensing and design bases do not require a single failure be assumed concurrent with an external event. Similar statements were also included as part of several Prairie Island specific NRC Task Interface Agreements (TIAs). The inspectors discussed the need to assume a single failure concurrent with an external event with individuals in the NRCs Office of Nuclear Reactor Regulation (NRR). The NRR individuals reviewed the TIA information in conjunction with licensing and design basis information and determined that a single failure did not need to be assumed concurrent with an external event. As a result, the licensee would not have to assume a loss of Electrical Panel 136 during these types of events and operator action would not be required to ensure that the cooling water strainers continued to backwash automatically.

Conversely, the licensee was required to assume a single failure as part of an internal event (such as a loss of coolant accident). During these types of events, the cooling water system load was minimized to ensure that safety-related equipment remained cooled. The minimization of cooling water load resulted in reducing the amount of debris introduced into the cooling water strainer. Due to the amount of debris introduced being lower, the time between strainer backwash cycles would increase. The inspectors reviewed the cooling water strainer backwash logic design and determined that the strainers backwashed in series when differential pressure reached four pounds in any one of the four strainers. If Electrical Panel 136 were to fail coincident with an internal event, the cooling water strainers would not automatically backwash. However, operators would be alerted to a strainer issue by the receipt of a control room alarm once the differential pressure in any strainer reached eight pounds (which was below the strainer design pressure). After receiving the alarm, operations personnel would be directed (through procedural guidance) to place switches associated with each strainer in its emergency position. Once this action was completed, one train of cooling water strainers would maintain the ability to automatically backwash to clear the accumulated debris. Based upon current strainer operating conditions, and the fact that the action to place the strainer backwash switches in the emergency position was a proceduralized and simple action, the inspectors concluded that operations personnel would have adequate time to address a loss of Electrical Panel 136 prior to any disruption in cooling water flow. As a result, these actions did not constitute a manual action in place of an automatic action and they were not time critical.

Based upon the information discussed above, no findings were identified.

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

.1 Alert Declared due to Report/Detection of Toxic Gases

a. Inspection Scope

On January 5, 2012, at 0353, the Shift Manager declared an Alert emergency classification due to receiving a report/detecting a toxic gas release in the Chlorine House which reached, or had the potential to reach, concentrations that were IDLH.

The inspectors monitored the licensees response to this event from the control room and the TSC. Upon termination of the event, the inspectors reviewed relevant documents and performed interviews to assess the adequacy of the licensees response to ensure all regulatory requirements were met. Documents reviewed in this inspection are listed in the Attachment.

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

b. Findings

Introduction:

Three self-revealed findings of very low safety significance (Green) with two associated NCVs of NRC requirements were identified. The findings were as follows:

• The failure to follow procedure use and adherence requirements while operating the sodium hypochlorite system;

• The failure to activate the Emergency Response Data System (ERDS) within one hour; and

• The failure to provide adequate staffing for initial facility accident response through the timely augmentation of on-shift staffing as required by 10 CFR 50.47(b)(2).

Description:

During the early morning hours of January 5, 2012, the night-shift chemistry technician performed activities to prepare the sodium hypochlorite system for planned maintenance. As part of these activities, the technician drained the sodium hypochlorite draw down tank using Procedure RPIP 3011, Operation of the Sodium Hypochlorite/Chemical Additive Feed System. Draining the draw down tank required the manipulation of several valves that were located underneath floor grating. In order to complete this task, the chemistry technician removed the floor grating and placed it next to the floor opening as a reminder to return the valves to their normal position once the draw down tank was drained. As the draining commenced, the chemistry technician identified that the bucket being used would not be big enough to hold the entire contents of the draw down tank. As the technician turned to reach for another bucket, he stepped down into the floor opening, landed on a polyvinylidene fluoride (pvdf) pipe containing sodium hypochlorite, and caused the pipe to break.

At 0320, the chemistry technician informed the control room that he had stepped on a pipe in the Chlorine House, caused the pipe to break, and that the pipe break would result in spilling approximately 500 gallons of sodium hypochlorite into a concrete berm inside the Chlorine House. Operations personnel immediately entered Abnormal Operating Procedure D14.4 AOP1, Chemical Leak or Spill, assembled the fire brigade to respond to the spill, and requested that the chemistry technician perform sampling to aid in determining whether the spill had resulted in a toxic environment that was, or had the potential to result in, an atmosphere that was IDLH. After learning that the chemistry technician had been sprayed with sodium hypochlorite, the control room directed the technician to shower prior to performing the sampling activities. The control room then directed the on-shift radiation protection (RP) technician to perform air quality monitoring using a confined space air monitor.

After monitoring the air quality inside and outside the Chlorine House for approximately five minutes, the RP technician placed the air monitor just inside the Chlorine House so that he could perform additional activities. At 0350, fire brigade personnel located near the Chlorine House heard the air monitor alarming and reported this condition to the control room. In addition, the fire brigade members reported smelling a strong stench of chlorine.

At 0353, the shift manager declared an Alert due to receiving a report/detecting a toxic gas release in the Chlorine House which reached, or had the potential to reach, concentrations that were IDLH. Although environmental sampling of the area using Drager tubes had not been completed, the shift manager believed that the alarming air monitor, the strong smell of chlorine, and the fact that the spill occurred in a building adjacent to safety-related equipment satisfied the requirements to declare the Alert.

The licensee activated their emergency response organization (ERO) to aid in responding to the event. All emergency response facilities were declared operational within the required 60 minutes. However, five individuals that were required to respond to the plant within 30 minutes failed to respond within the required time. In addition, the ERDS system (which was required to be activated within 60 minutes) was not placed into service until 80 minutes into the event. Per facility logs, the initial activation attempts, which were not successful, occurred at 0353, 62 minutes after the Alert declaration. The connection failure was determined to be in the Beta testing of the new Virtual Private Network (VPN) and supporting software interfering with the ERDS modem. After resolving the issue, the ERDS was eventually activated at 0513, 20 minutes after the one hour specified in 10 CFR 50.72(a)(4).

The inspectors monitored activities in the control room, the TSC, and at the Chlorine House to assess the performance of the ERO. The inspectors also monitored the licensees efforts to remove the spilled liquid from the Chlorine House. The licensee terminated the Alert event at 1408 on January 5, 2012.

The licensee performed a root cause evaluation on the activities in the Chlorine House and determined that the pipe break occurred because the chemistry technician demonstrated an inaccurate risk perception during the performance of activities to drain the draw down tank. The inspectors reviewed the root cause report and concluded that this event occurred due to the failure to follow the licensees procedure use and adherence requirements. Specifically, Step 5.2.1 of Procedure FP-G-DOC-03, Procedure Use and Adherence, stated that procedure users shall review a procedure prior to use and obtain supervisor clarification of any steps not understood. In addition, Step 3.3.1 required that procedure users review procedure requirements prior to starting a job to identify potential problems. The inspectors determined that the chemistry technician failed to comply with Steps 5.2.1 and 3.3.1 of Procedure FP-G-DOC-03.

Specifically, the inspectors reviewed RPIP 3011 and determined that it failed to contain information regarding the steps needed to drain the draw down tank. The procedural inadequacies were not identified by the chemistry technician because chemistry department management and supervision have not provided adequate oversight to ensure that procedure use and adherence requirements were met.

(1) Failure to Follow Procedure Use and Adherence Requirements

Analysis:

The inspectors determined that the failure to implement the requirements contained in FP-G-DOC-03 was a performance deficiency that required evaluation using the SDP. The inspectors determined that this issue was more than minor because it was a precursor to a significant event. Specifically, the licensee declared an ALERT emergency action level due to the sodium hypochlorite spill. The inspectors determined that this issue was associated with the Mitigating Systems Cornerstone since toxic substances have the potential to impact the licensees ability to operate safety-related equipment.

The inspectors assessed this finding using IMC 0609.04, Table 4a, Characterization Worksheet for the Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstone, and concluded that the finding was of very low safety significance (Green)since all of the questions located in the Mitigating Systems Cornerstone column were answered no. (FIN 05000282/2012002-05; 05000306/2012002-05: Failure to Implement Procedure Use and Adherence Requirements While Draining Sodium Hypochlorite Draw Down Tank). The inspectors determined that this finding was cross-cutting in the Human Performance, Work Practices area because the licensee failed to ensure supervisory and management oversight of work activities such that nuclear safety was supported (H.4(c)).

Enforcement:

The inspectors determined that a violation of NRC requirements did not occur due to the sodium hypochlorite system, and the associated procedures, were non-safety related.

(2) Failure to Timely Augment the On-Shift Staffing

Analysis:

As discussed above, the licensee failed to augment on-shift staffing in a timely manner upon declaration of an Alert. Specifically, four RP positions and one Radiological Emergency Coordinator (REC) position were not staffed within the 30 minute commitment of Table 1, Guidance for Augmentation of Plant Emergency Organization, of the Prairie Island Emergency Plan. The inspectors determined that the licensees failure to timely augment on-shift staffing within 30 minutes of the Alert declaration per Table 1 was a performance deficiency as it was within the licensees ability to foresee and correct.

The inspectors determined this performance deficiency was more than minor because it was associated with the ERO Performance attribute of the Emergency Preparedness Cornerstone and affected the cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was evaluated in accordance with IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process. Using the Actual Event Implementation Problem Sheet 2, the inspectors determined the finding to be of very low safety significance (Green) because it was not a failure to implement a risk significant planning standard. This finding was determined to be cross-cutting in the Human Performance, Decision Making area because the licensee failed to communicate the basis for decisions to personnel who have a need to know the information in order to perform work safely and in a timely manner. (H.1(c)).

Enforcement:

Title 10 CFR 50.54(q) requires that the facility shall follow and maintain in effect Emergency Plans which meet the standards in 10 CFR 50.47(b).

Title 10 CFR 50.47(b)(2), states, On-shift facility licensee responsibilities for emergency response are unambiguously defined, adequate staffing to provide initial facility accident response in key functional areas is maintained at all times, timely augmentation of response capabilities is available and the interfaces among various onsite response activities and offsite support and response activities are specified. The Prairie Island Emergency Plan states, A plant emergency organization is designated to augment the normal operating crew. Provisions have been made for rapid assignment of plant personnel to the plant emergency organization during emergency situations.

The Prairie Island Plant Emergency Organization is shown in Figure 2. Various areas of responsibility are assigned to segments of the plant staff during emergency situations as depicted in Table 1 and Table 2. Table 1 shows the personnel available on-shift and the capability for additional personnel within 30 minutes and 60 minutes of notification, which included RP and REC positions. Table 1 follows the guidance established by Table B-1 in NUREG-0654.

Contrary to the above, on January 5, 2012, the Prairie Island ERO failed to provide timely augmentation of on-shift staff after declaring an alert at the Prairie Island Nuclear Generating Plant. Four RP positions and one REC position were not staffed within the 30 minute commitment of Table 1. Because this violation was of very low safety significance and it was entered into the licensees CAP as CAPs 1319852 and 1319857, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 5000282/2012002-06; 05000306/2012002-06; Failure to Timely Augment On-Shift Staff). Corrective actions for this issue included placing additional radiation protection staff members on each shift to ensure that emergency plan positions would be filled within the required time.

(3) Emergency Response Data System Activation (ERDS)

Analysis:

During the January 5, 2012, Alert declaration, the licensee failed to activate the ERDS within one hour. Specifically, the ERDS was not made operable until 80 minutes after the Alert declaration due to task priority and equipment issues related to a system upgrade. The inspectors determined that the licensees failure to activate the ERDS within one hour of the Alert declaration was a performance deficiency as it was within the licensees ability to foresee and correct.

The inspectors determined this performance deficiency was more than minor because it was associated with the ERO Performance attribute of the Emergency Preparedness Cornerstone and affected the cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was evaluated in accordance with IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, that considers a failure to activate ERDS as a failure to implement. Using the Actual Event Implementation Problem Sheet 2, the inspectors determined the finding to be of very low safety significance (Green) because it was not a failure to implement a risk significant planning standard. This finding was determined to be cross-cutting in the Problem Identification and Resolution, Corrective Action Program area because the licensee failed to take appropriate corrective actions to address a previously identified issue in a timely manner. (P.1 (d)).

Enforcement:

Title 10 CFR 50.72(a)(4), states, that the licensee shall activate the ERDS as soon as possible but no later than one hour after declaring an Emergency Class of alert, site area emergency, or general emergency.

Contrary to the above, on January 5, 2012, the Prairie Island ERO failed to activate the ERDS within one hour after declaring an alert at the Prairie Island Nuclear Generating Plant. Because this violation was of very low safety significance, and it was entered into the licensees CAP as CAP 1319866, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 5000282/2012002-07; 05000306/2012002-07; Failure to Timely Activate ERDS).

Corrective actions for this issue included emphasizing the timely activation of ERDS with emergency responders and repairing the system upgrade equipment issues.

.2 Unit 2 Manual Reactor Trip During Shutdown for Outage 2R27

a. Inspection Scope

The inspectors reviewed the licensees response to a Unit 2 manual reactor trip from approximately 11.5 percent power which occurred on February 21, 2012.

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

b. Findings

Introduction:

A URI was identified due to the licensees root cause investigation remaining in progress at the conclusion of the inspection period.

Description:

On February 21, 2012, the licensee conducted a normal shutdown in preparation for refueling outage 2R27. When Unit 2 reactor power reached approximately 11.42 percent, operations personnel manually tripped the reactor due to the receipt of high-high level indications and alarms on multiple feedwater heaters.

The inspectors were in the control room when the reactor trip occurred. The inspectors observed the operators respond to the event to ensure that the licensees procedures were followed. The inspectors also observed equipment parameters available in the control room to ensure that the reactor and the associated equipment responded as expected following the reactor trip. The licensee documented the need to manually trip the reactor as CAP 1325986. The licensee was continuing to determine the cause of the high-high feedwater heater level at the conclusion of the inspection period. As a result, the inspectors determined that this issue should be considered a URI pending the review of the licensees causal investigation report and the proposed corrective actions (URI 05000306/2012002-08: Unit 2 Reactor Trip during Shutdown for Outage 2R27).

.3 Notice of Unusual Event Declared due to Reactor Coolant System (RCS) Leakage

Greater Than 10 Gallons Per Minute

a. Inspection Scope

On March 6, 2012, operations personnel declared a Notice of Unusual Event due to receiving an indication that Unit 2 RCS leakage was greater than 10 gallons per minute.

The inspectors were in the control room when the event was declared. The inspectors observed the operators respond to the event to ensure that the licensees procedural requirements were followed. The inspectors also monitored available control room indications to determine whether any equipment complications occurred while the operators were responding to the event. None were identified. The inspectors initial review of this event determined that a leak in the RCS had not occurred. However, it appeared that the procedures used to drain a portion of the RCS and the Unit 2 reactor head vent piping may be deficient. Both the inspectors and the licensees review of this event were ongoing at the conclusion of the inspection period. As a result, this item will be carried as a URI pending the inspectors review of the licensees root cause evaluation report and the proposed corrective actions (URI 05000306/2012002-09:

Review of Root Cause Evaluation for March 6, 2012, Notice of Unusual Event).

.4 CV-31200 Blender Valve Malfunction

a. Inspection Scope

On January 25, 2012, the licensee commenced a blend to the 11 refueling water storage tank in preparation to perform a bleed and feed on the 11 safety injection accumulator.

Licensed operators monitored RCS parameters and noted reductions in both power and RCS temperature. The total reactor power decrease was approximately 0.95 percent and the RCS average temperature decrease was approximately 0.7 degrees Fahrenheit.

No TS limits were exceeded during the event. The licensee initiated CAP 1322144 to document this reactivity event.

The inspectors discussed this event with operations personnel, reviewed operator actions in response to the event, and reviewed the maintenance work history of valve CV-31200. The licensee determined that the unplanned reactivity event occurred due to inadequate preventative maintenance (PM) of the valve. Specifically, the licensee concluded the valve leaked by in the closed position due to a worn valve actuator.

The inspectors reviewed the licensees CAP database and found that a similar issue had occurred in late 2011. Corrective actions for the previous issue included the development and implementation of PM activities for valve (including CV-31200).

However, the licensee had not had adequate time to implement the corrective actions.

The licensee initiated and completed actions to replace the defective valve actuator as well as evaluate the extent of condition for similar valves. Seven similar valves were identified. The licensee conducted reviews to ensure the required PM had been scheduled/completed for those valves. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

.5 (Closed) LER 05000282/2007-002-00: Unanalyzed Condition Due to Manual Actions

that Do Not Comply with 10 CFR Part 50, Appendix R On June 4, 2007, the licensee identified that they were relying on unapproved manual actions to mitigate potential damage to safe shutdown equipment. The licensee stated that a fire in the Unit 1 Administration Building Electrical and Piping Area (Fire Area 29)could result in the loss of control of diesel-driven cooling water pumps 12 and 22 and associated equipment. As part of ongoing work to support transition to 10 CFR 50.48(c)the licensee identified, in the event of a fire, that manual actions may be necessary to locally operate the diesel-driven cooling water pumps and the associated equipment.

The plant has five cooling water pumps, two direct diesel engine-driven and three electric motor-driven. The two diesel driven pumps are common to both Units 1 and 2.

A safety injection signal from either units Train A or Train B will start the 12 diesel driven pump or the 22 diesel driven pump, respectively. A fire in Fire Area 29 could damage the control circuits for both diesel driven pumps, as well as their respective backwash controls. This would necessitate the use of local manual actions to control the equipment. However, the use of these manual actions did not meet the requirements of 10 CFR Part 50, Appendix R, for non-alternative shutdown areas as discussed in Regulatory Issue Summary 2006-10, Regulatory Expectations with Appendix R Paragraph III.G.2 Operator Manual Actions.

The licensee entered this issue into their CAP as CAP 1095071, Non-Compliant Manual Actions in FA 29, dated June 4, 2007, and took credit for the existing procedural guidance as a compensatory measure for the 10 CFR Part 50, Appendix R non-compliance. In addition, the licensee planned to assess the issue as part of their transition to 10 CFR 50.48(c). The inspectors concluded that the licensees corrective actions, both taken and planned, were appropriate and reasonable. Enforcement aspects of this LER are discussed in Section 4OA7. Documents reviewed as part of this inspection are listed in the Attachment to this report. This LER is closed.

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

4OA5 Other Activities

.1 (Closed) URI 05000282/2011005-03; 05000306/2011005-03: Residual Heat Removal

(RHR) Pit Sump Pumps and Instrumentation Maintenance Rule Applicability

a. Inspection Scope

As discussed in Inspection Report 05000282/2011005; 05000306/2011005, the inspectors questioned whether the RHR system sump pumps and level switches were required to be included within the scope of the maintenance rule since they may function following an internal flooding event to ensure that at least one train of RHR continued to perform its safety function. The failure to include these components within the maintenance rule program could lead to potential equipment issues remaining unaddressed.

b. Findings

The licensee provided the inspectors with an evaluation of the design and licensing basis information for the RHR system, the RHR sump pit pumps and level switches, and how this information applied to the maintenance rule. The inspectors reviewed this information and concluded that the RHR pit sump pumps and level switches were not relied upon to preserve the function of the RHR system following an internal flooding event. As a result, the performance of the RHR pit sump pumps and level switches was not required to be monitored as part of the maintenance rule program. No findings or violations were identified. This unresolved item is closed.

.2 (Closed) URI 05000282/2011005-05; 05000306/2011005-05: Operability of Safety

Related Systems Following the Identification of Gaps in Redundant Steam Exclusion Dampers

a. Inspection Scope

During an event follow-up inspection performed during the fourth quarter of 2011, the inspectors questioned the past operability of multiple safety-related systems following the identification of gaps in redundant steam exclusion (SE) dampers.

The Prairie Island Nuclear Plant contained multiple SE dampers in various areas of the plant. The SE dampers were required to close following a high-energy line break (HELB) to ensure that safety-related equipment was protected from the effects of steam.

As discussed in NRC Inspection Report 05000282/2011005; 05000306/2011005, the licensee found gaps in SE dampers CD-34187 and CD-34188 during the performance of monthly surveillance testing. Based upon the presence of the gaps, the inspectors questioned whether the amount of steam that could pass through the gaps could impact the performance of the safety-related systems if a HELB were to occur.

b. Findings

The licensee performed a heat up analysis of the area using the Generation of Thermal Hydraulic Information for Containments (GOTHIC) computer program which assumed that the dampers discussed above contained gaps that were equal to those measured during the surveillance testing. The results of the analysis showed that the safety-related equipment would have remained protected from the effects of a HELB.

The licensee repaired the gaps before returning both SE dampers to service.

No findings or violations were identified. This URI is closed.

.3 (Closed) URI 05000306/2011005-02: Appendix R Fire Barrier Degraded Between Fire

Areas 118 and 128

a. Inspection Scope

As discussed in Inspection Report 05000282/2011005; 05000306/2011005, the inspectors identified that a wall which separated Fire Areas 118 and 128 contained gaps.

As a result, the licensee was unable to credit the wall as a qualified 3-hour fire barrier.

The inspectors also documented that a potential design deficiency could possibly result in the failure of both safe shutdown trains being rendered inoperable due to a fire in the above locations. The licensee evaluated the impact of the degraded fire barrier to ensure that appropriate actions were taken to return the barrier to a functional status.

The inspectors reviewed the licensees evaluation for technical adequacy and to determine whether any performance deficiencies existed.

b. Findings

Introduction:

A finding of very low safety significance (Green) and an NCV of Unit 2 Operating License Condition 2.C.(4) was identified by the inspectors on November 8, 2011, due to the failure to implement and maintain in effect all provisions of the approved fire protection program. Specifically, the inspectors identified a missing fire barrier in a 3-hour rated wall separating two fire areas containing safe shutdown equipment.

Description:

On November 8, 2011, the inspectors identified that the barrier between two fire areas (118 and 128) was degraded such that it failed to provide the required 3-hour fire rating. Fire Area 118 contained Electrical Bus 26, which was used to power Unit 2, Train B, safe shutdown equipment. Fire Area 128 contained Electrical Bus 27 which was used to provide power to the 121 motor driven cooling water pump.

Plant design allowed Electrical Bus 27 to be powered from either Electrical Bus 25 (Train A safe shutdown equipment) or Electrical Bus 26.

The inspectors questioned licensee personnel regarding the adequacy of the fire barrier between Fire Areas 118 and 128. The licensee confirmed that the beam at the top of the wall between the two fire areas was not filled with a fire rated material and, therefore could not be considered a 3-hour rated fire barrier. The licensee initiated CAP 1312153 to document the fire impairment and established an hourly fire watch as a compensatory measure. The fire watch remained in place until actions were taken to permanently correct the fire barrier. The licensee completed a root cause evaluation and determined that the gap had existed since original construction of the D5/D6 emergency diesel generator (EDG) Building in the early 1990s due to poor closure of this modification.

The licensee also performed fire modeling which showed that the missing fire barrier would not have impacted Bus 25 safe shutdown equipment. As a result, one train of safe shutdown would have remained free from fire damage.

Analysis:

The inspectors determined the gap in the required 3-hour fire barrier represented a performance deficiency that impacted the Mitigating Systems Cornerstone and required evaluation using the Significance Determination Process (SDP).

The inspectors determined the finding was more than minor because it was associated with the Mitigating System Cornerstone attribute of Protection Against External Factors (Fire), and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the gap in the required 3-hour wall presented a challenge to ensure the availability of a system to respond to an initiating event.

In accordance with IMC 0609, Significance Determination Process, 0609.04, Phase 1 Initial Screening and Characterization of Findings, Table 3b, 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 inspectors reviewed IMC 0609, Appendix F and determined that the finding impacted the Fire Confinement Finding Category. Based on review of IMC 0609, Appendix F, 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, the inspectors determined that the degradation rating associated with the finding was low since the gap in the fire barrier was small and the licensees fire modeling did not result in a credible fire scenario for fire propagation or equipment effects due to heated gases. As a result, this finding was determined to be of very low safety significance (Green) based upon the guidance contained in Step 1.3 of IMC 0609, Appendix F, Attachment 2. No cross cutting aspect was assigned to this finding because the cause of this issue occurred more than three years ago and was not reflective of current plant performance.

Enforcement:

Unit 2 Operating License condition 2.C.(4) required the licensee to implement and maintain in effect all provisions of the approved fire protection program as described in the USAR. Updated Safety Analysis Report Section 10.3.1.1, Design Basis, stated NRCs basic criterion for fire protection as set forth in GDC 3, Appendix A to 10 CFR 50 became applicable to the Prairie Island Nuclear Generating Plant on October 29, 1980. General Design Criterion 3 stated, in part, that structures, systems, and components important to safety shall be designed and located to minimize the probability and effect of fires. Procedure F5, Appendix F, established requirements for the wall between fire area 118 and 128 as 3-hour rated.

Contrary to the above, on November 8, 2011, the inspectors identified gaps between the top of a wall and the ceiling that make up the 3-hour fire barrier between the Unit 2 Bus 26 and 27 rooms (Fire areas 118 and 128). The wall gap represented a degradation of a defense-in-depth fire protection element and compromised the 3-hour fire barrier separation requirements. Since the finding was of very low safety significance and had been entered into the licensees corrective action program as CAP 1312153, this violation was treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2012002-10: Inadequate Three Hour Fire Barrier between Bus 26 and Bus 27 Rooms). Corrective actions for this issue included establishing a fire watch and repairing the fire barrier.

.4 Review of Control Room Operating Logs

a. Inspection Scope

The inspectors performed a daily review of control room operating logs to ensure that the log entries were complete, portrayed an accurate representation of control room activities, and complied with the requirements contained in FP-OP-COO-19, Logkeeping.

b. Findings

Introduction:

A finding of very low safety significance (Green) and an NCV of TS 5.4.1 were identified by the inspectors due to the licensees failure to implement Procedure FP-OP-COO-19, Logkeeping. Specifically, licensee personnel failed to promptly record log entries, properly annotate late entries, document the basis for major operational decisions, and provide the reason for changes in equipment status.

Description:

During the period of February 23, 2012, through March 27, 2012, the inspectors identified several instances where the licensee failed to ensure narrative operational logs fully recorded the data necessary for an accurate history of the plant.

These included:

• On March 27, 2012, at 0358, the licensee performed and logged a risk assessment for Unit 1 resulting in a yellow risk rate category. This assessment was based, in part, on isolating the 12 component cooling water heat exchanger.

At approximately 0605 during the licensees control room turnover meeting, the inspectors determined the 12 CC heat exchanger work was not being performed as anticipated. The inspectors noted this deviation to licensee management since the logs did not reflect an updated risk evaluation. The licensee had also noted the incorrect log entry during their daily control room log review. The licensee reviewed this issue and found that other out of service (OOS) equipment had not been appropriately documented within the log entry.

This log entry was not in compliance with Steps 5.3.1.1, 5.3.1.5 and 5.3.1.7(l) of the logkeeping procedure.

• On March 19, 2012, at 2138, the licensee logged an issue where shutdown safety risk required re-evaluation due to a diesel generator associated with the spent fuel pool (SFP) supplemental cooling system not providing power.

However, the inspectors were unable to find a log entry which clearly delineated the updated shutdown safety risk. The inspectors questioned the licensee about the updated risk evaluation at approximately 0620 on March 20, 2012. At 0928, the licensee documented the updated risk evaluation in the control room logs.

The initial failure to document this log entry was not in compliance with Steps 5.3.1.1 and 5.3.1.7(l) of the logkeeping procedure.

• On March 9, 2012, at 0939, a control room log entry documented that activities were completed for back seating the 21 reactor coolant pump and that RCS level decreased due to the activities. The entry further indicated that the activities were secured and that RCS level stopped decreasing. The total reduction in RCS level was approximately 1 inch. During a review of control room logs performed several days later, the inspectors questioned the licensees response to the loss of RCS level since other RCS level control issues had recently occurred. The licensee informed the inspectors that the RCS level decrease associated with the back seating activity was an expected condition that was discussed at the pre-job briefing. The inspectors questioned why these details were not included in the log entry. A late log entry was made several days later to document the expected condition. The failure to document the reduction in RCS level as an expected condition did not comply with Steps 5.3.1.5 and 5.3.1.7(l) of the logkeeping procedure.

• On February 24, 2012, at 0130 and 0138, log entries were made to document the entry into and exiting of TS Limiting Condition for Operation (LCO) 3.0.5 for SE damper testing. During a review of control room logs by the oncoming shift, the day-shift Shift Supervisor identified that the entering and exiting of TS LCO 3.0.5 was not correct. Instead, the night shift should have entered TLCO 3.0.e.

Although the day-shift Shift Supervisor updated the incorrect log entries, the method used to perform the update failed to comply with Step 5.3.1.2.

Specifically, the day-shift Shift Supervisor indicated that the updated entries were made after the fact. However, both log entries were time stamped with the same date and time as the original log entries. As a result, there was no way to determine when the updated log entries were made.

• On February 23, 2012, at 2355, a log entry was made to document that the R-28 SFP radiation monitor had been taken OOS due to a failed surveillance.

Procedure C11 required radiation levels in the area to be monitored continuously with new fuel stored out of the water. The procedure also required the installation of a portable radiation monitor if R-28 failed. Based upon the log entries, it appeared that operations became aware of the requirement to install the portable radiation monitor nearly four hours after declaring R-28 inoperable.

An additional log entry documented that the portable radiation monitor was installed at 0445 on February 24, 2012. During a review of control room logs on February 24, 2012, the inspectors questioned whether operations personnel were knowledgeable of the C11 procedural requirements due to the long period of time that elapsed between declaring R-28 inoperable and installing the radiation monitor. The inspectors were informed that R-28 was removed from service for surveillance testing at 2355 on February 23. However, the monitor did not fail its surveillance testing until several hours later. Based upon this information, the inspectors determined that the log entry did not provide an accurate history of plant operation as required by Steps 5.3.1.7(b) and 5.3.1.7(l)of the logkeeping procedure.

• On February, 23, 2012, at 1323, a log entry was made to exit TS 3.8.1.B for the D2 EDG based upon satisfactory completion of a monthly surveillance. During the surveillance test, local operators noted an issue with a temperature controller that controlled the amount of cooling inside the D2 EDG room. The inspectors noted that the log entry made to exit the TS failed to include the basis for determining that the temperature controller had no impact on the D2 EDG. As a result, the inspectors identified that this log entry failed to meet the requirements of Step 5.3.1.5 of the logkeeping procedure. Night-shift operations personnel subsequently declared the D2 EDG inoperable due to the temperature controller issue.

Analysis:

The inspectors determined that inadequate/incorrect control room log entries represented a performance deficiency that impacted the Mitigating Systems Cornerstone and required evaluation using the SDP. The inspectors determined the finding was more than minor because it was associated with the Mitigating System Cornerstone attribute of Configuration Control, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, narrative operational logs do not fully record the data necessary for an accurate history of the plant and present a challenge to ensure operator knowledge of operating equipment lineup. This finding was determined to be of very low safety significance (Green) because each of the screening questions contained in IMC 0609.04, Table 4A could be answered no. The inspectors concluded that this finding was cross-cutting in the Human Performance, Work Practices area since the licensee did not support the effective use of human error prevention techniques through proper documentation of activities. (H.4(a)).

Enforcement:

Technical Specification 5.4.1 required that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Section 1, required that administrative procedures be established, implemented and maintained for log entries.

Procedure FP-OP-COO-19 established the licensees log entry requirements.

Contrary to the above, between February 23 and March 27, 2012, procedural requirements contained in Procedure FP-OP-COO-19 were not implemented to ensure operational narrative logs fully record the data necessary for an accurate history of plant operation. Because this violation was of very low safety significance and it was entered into the CAP as CAP 1328236, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000282/2012002-11:

Inadequate Operational Log Entries). Corrective actions for this issue included a daily review of control room log entries to ensure that procedural requirements were met, providing feedback to operations personnel that were not meeting the procedural requirements, and correcting any inaccurate/inadequate log entries.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 12, 2012, the inspectors presented the inspection results to M. Schimmel, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• the results of the review associated with LER 2007-002, Unanalyzed Condition due to Manual Actions that Do Not Comply with 10 CFR Part 50, Appendix R, with the Engineering Programs Manager, Mr. C. Lane, on February 17, 2012.

• the inspection results for the areas of radiological hazard assessment and exposure controls; occupational ALARA planning and controls; radioactive gaseous and liquid effluent treatment; and RCS specific activity, occupational exposure control effectiveness, and RETS/ODCM radiological effluent occurrences performance indicator verification with Mr. M. Schimmel, Site Vice-President, on March 2, 2012.

• The results of the inservice inspection with Plant Manager, Mr. S. Northard on March 16, 2012.

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

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) or Severity Level IV were identified by the licensee and were violations of NRC requirements which met the criteria of the NRC Enforcement Policy for being dispositioned as NCVs.

• The following violation that affects 10 CFR 50.48 was identified by the licensee and is a violation of NRC requirements. This violation has been screened and determined to warrant enforcement discretion per the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues. A violation of 10 CFR Part 50, Appendix R, Section III.G.2 was identified by the licensee for the failure to ensure that one train of systems necessary to achieve and maintain hot shutdown conditions from either the control room or emergency control station is free of fire damage. Specifically, due to inadequate cable separation, there was a potential for a fire in the Administration Building Electrical and Piping Area to damage control cables of diesel-driven cooling water pumps 12 and 22 and associated equipment. On June 4, 2007, the licensee identified that they were relying on unapproved manual actions to mitigate potential damage to safe shutdown equipment. The Region III Senior Risk Analysts completed a risk-assessment evaluation and determined that the issue was not of high safety significance (i.e., the violation was less than Red) using SAPHIRE Version 8.0.7.17 and the Prairie Island Standardized Plant Analysis Risk (SPAR) model (Version 8.17).

• Title 10 CFR Part 50, Appendix B, Criterion V, requires that activities affecting quality be performed in accordance with instructions, procedures and drawings appropriate to the circumstance. Contrary to the above, on March 25, 2012, post-maintenance testing was performed on motor operated valve 32030 (the 22 turbine driven auxiliary feedwater pump suction cooling water supply valve) without using instructions, procedures, or drawings appropriate to the circumstance. As a result, cooling water was introduced into both Unit 2 steam generators. The inspectors determined that this issue was of very low safety significance (Green) because Unit 2 was shut down when this issue occurred, the Unit 2 steam generators were not operable, and the licensee flushed the cooling water from the steam generators to ensure it would not have any lasting impacts on steam generator tube integrity.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Schimmel, Site Vice President

K. Davison, Director - Site Operations

P. Huffman, Site Engineering Director

S. Sharp, Assistant Plant Manager

T. Allen, Senior Manager Site Engineering

J. Anderson, Regulatory Affairs Manager

C. Bough, Chemistry and Environmental Manager

B. Boyer, Radiation Protection Manager

R. Clow, Welding Program Engineer

K. DeFusco, Emergency Preparedness Manager

T. Downing, ISI Programs Engineer

L. Drenth, Boric Acid Programs Engineer

J. Eckholt, Licensing Engineer

D. Goble, Safety and Human Performance Manager

J. Hamilton, Security Manager

C. Lane, Engineering Programs Manager

J. Lash, Nuclear Oversight Manager

S. Lappegaard, Production Planning Manager

M. Milly, Maintenance Manager

S. Northard, Plant Manager

K. Peterson, Business Support Manager

D. Potter, NDE/ISI Fleet Supervisor

A. Pullam, Training Manager

S. Redner, Steam Generator Project Manager

J. Ricker, Inspections and Materials Supervisor

J. Ruttar, Operations Manager

P. Wildenborg, Heath Physicist

J. Wren, NDE Program Engineering Analyst

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

T. Wengert, Project Manager, Office of Nuclear Reactor Regulation

Attachment

LIST OF ITEMS

Opened

05000306/2012002-01 NCV Breaker 212E-44 Failure due to Lack of Preventive Maintenance

05000282/2012002-02; URI Review Of Steam Exclusion Damper Maintenance

05000306/2012002-02 Effectiveness

05000282/2012002-03 NCV Failure to Properly Assess Operability of D2 EDG following Surveillance Testing

05000282/2012002-04; NCV Failure to Assess Operability of Circuit Breakers due to

05000306/2012002-04 Inadequate Lubrication

05000282/2012002-05; FIN Failure to Implement Procedure Use and Adherence

05000306/2012002-05 Requirements While Draining Sodium Hypochlorite Draw Down Tank

05000282/2012002-06; NCV Failure to Timely Augment the On-Shift Staffing

05000306/2012002-06

05000282/2012002-07; NCV Failure to Timely Activate ERDS

05000306/2012002-07

05000306/2012002-08 URI Unit 2 Manual Reactor Trip During Shutdown for Outage 2R27

05000306/2012002-09 URI Review of Root Cause Evaluation for March 6, 2012, Notice of Unusual Event

05000282/2012002-10 NCV Inadequate Three Hour Fire Barrier Between Bus 26 And Bus 27 Rooms

05000282/2012002-11 NCV Inadequate Operational Log Entries

Closed

05000282/2012002-06; NCV Failure to Timely Augment the On-Shift Staffing

05000306/2012002-06

05000282/2012002-07; NCV Failure to Timely Activate ERDS 1

05000306/2012002-07

05000282/2007-002-00 LER Unanalyzed Condition Due to Manual Actions that Do Not Comply with 10 CFR Part 50, Appendix R

05000282/2011005-03; URI RHR Pit Sump Pumps and Instrumentation Maintenance

05000306/2011005-03 Rule Applicability

05000282/2011005-05; URI Operability of Safety Related Systems Following the

05000306/2011005-05 Identification of Gaps in Redundant Steam Exclusion Dampers

05000306/2011005-02 URI Appendix R Fire Barrier Degraded Between Fire Areas 118 and 128 Attachment