Text

IR 05000282-13-003 & 05000306-13-003, 04/01/2013 - 06/30/2013, Prairie Island Nuclear Generating Plant, Unit 1 & 2, NRC Integrated Inspection Report and Notice of Violation
	ML13212A038
Person / Time
Site:	Prairie Island
Issue date:	07/30/2013
From:	Kenneth Riemer; NRC/RGN-III/DRP/B2
To:	Jeffery Lynch; Northern States Power Co
References
	IR-13-003
	Download: ML13212A038 (50)
	v • d • e

uly 30, 2013

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000282/2013003; 05000306/2013003 AND NOTICE OF VIOLATION

Dear Mr. Lynch:

On June 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed inspection report documents the inspection results which were discussed on July 11, 2013, with you and other members of your staff.

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

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

Based on the results of this inspection, the NRC has identified an issue that was evaluated under the risk significance determination process as having very low safety significance (Green). The NRC has also determined that a violation is associated with this issue. This violation was evaluated in accordance with the NRC Enforcement Policy. The current Enforcement Policy is included on the NRCs Web site at (http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html).

The violation is cited in the enclosed Notice of Violation (Notice) and the circumstances surrounding it are described in detail in the enclosed inspection report. The violation is being cited in the Notice because you failed to restore compliance with NRC regulations after the NRC identified a non-cited violation in 2011 and your identification of additional issues approximately 18 months ago.

You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. If you have additional information that you believe the NRC should consider, you may provide it in your response to the Notice. The NRCs review of your response to the Notice will also determine whether further enforcement action is necessary to ensure compliance with regulatory requirements. Based upon the results of this inspection, the NRC has also identified one additional issue that was evaluated under the risk significance determination process as having very low safety significance (Green). This finding was determined to involve a violation of NRC requirements.

This violation is being treated as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy. If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant.

In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant.

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

component of NRC's Agencywide Documents Access and Management System (ADAMS),

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). To the extent possible, your response should not include any personal privacy or proprietary information so that it can be made available to the Public without redaction.

Sincerely,

/RA /

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

Enclosure:

1. Inspection Report 05000282/2013003; 05000306/2013003 w/Attachment: Supplemental Information 2. Notice of Violation

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report No: 05000282/2013003; 05000306/2013003 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: April 1 through June 30, 2013 Inspectors: K. Stoedter, Senior Resident Inspector P. Zurawski, Resident Inspector T. Daun, Acting Resident Inspector V. Myers, Health Physicist M. Phalen, Senior Health Physicist Approved by: Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000282/2013003; 05000306/2013003; 04/01/2013 - 06/30/2013;

Prairie Island Nuclear Generating Plant, Units 1 and 2; Maintenance Effectiveness, Problem Identification and Resolution.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified by the inspectors. One finding was documented as a Notice of Violation. The remaining finding was considered a non-cited violation (NCV) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using IMC 0609, Significance Determination Process dated June 2, 2011.

Cross-cutting aspects are determined using IMC 0310, Components Within the Cross Cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A self-revealing finding of very low safety significance (Green) and an NCV of 10 CFR Part 50, Appendix B, Criterion V, Instruction, Procedures, and Drawings was identified on June 13, 2013, due to the failure to have drawings appropriate to the circumstances when performing maintenance on the D1 Diesel Generator Room Cooling Supply and Exhaust Fan Blade Pitch Controller. Specifically, Logic Diagram NF 40326-1, Interlock Logic Diagram Diesel Generator Room Cooling Unit 1 and 2, incorrectly indicated that the fan blade pitch position would change to the maximum flow position if the controller experienced a loss of signal condition. This incorrect information resulted in the D1 Diesel Generator being rendered inoperable for 30 minutes when the temperature transmitter was disconnected from the controller as part of the maintenance activity. The licensee subsequently restored the D1 diesel generator to service by reconnecting the transmitter to the controller.

The inspectors determined that this issue was more than minor because it was associated with the design control, configuration control and procedure quality attributes of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This issue was of very low safety significance because each question provided in IMC 0609, Appendix A, Exhibit 2,

Mitigating Systems Screening Questions, was answered no. The inspectors concluded that this issue was cross cutting in the Problem Identification and Resolution,

Operating Experience (OE) area because the licensee did not implement and institutionalize OE through changes to station processes, procedures, equipment, and training programs after experiencing a similar issue in 2012 (P.2(b)). (Section 1R12)

Green.

The inspectors identified a finding of very low safety significance (Green) and a violation of 10 CFR 50.65, due to the failure to demonstrate that the performance or condition of multiple SSCs was being effectively controlled through the performance of appropriate preventive maintenance. The licensee also failed to establish goals sufficient to provide reasonable assurance that two SSCs were capable of performing their intended safety function after their performance demonstrations became invalid.

Specifically, more than 350 evaluations written between January 2012 and April 2013 to demonstrate whether the performance or condition of specific SSCs was being effectively controlled remained unapproved as of May 2013. In addition, the performance demonstration for one SSC was allowed to remained unvalid for approximately one year before designating the SSC as an (a)(1) system. Corrective actions for this issue included approving the previous evaluations, establishing 50.65(a)(1) action plans when required, and establishing actions to improve the maintenance rule program.

This issue was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and concluded that this findings significance was best characterized by using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Based upon the fact that none of the equipment issues discussed above rose to a level of greater than very low safety significance, the inspectors determined that this issue was best characterized as having very low safety significance (Green). The inspectors concluded that this finding was cross cutting in the Problem Identification and Resolution, Corrective Action Program area because the licensee failed to take appropriate and timely corrective actions to address the issues identified in November 2011 (P.1(d)). (Section 4OA2.4)

Licensee-Identified Violations

No violations were identified.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at full power. On May 3, 2013, operations personnel lowered Unit 1 reactor power to approximately 40 percent to conduct turbine valve testing and clean the condenser water boxes. Unit 1 returned to full power operation on May 5, 2013.

Unit 2 also began the inspection period at full power. On May 17, 2013, operations personnel lowered Unit 2 reactor power to approximately 40 percent to conduct turbine valve testing and clean the condenser water boxes. Unit 2 returned to full power on May 20, 2013. On June 6 and 7, 2013, operations personnel began lowering reactor power due to discovering high vibrations on main generator stator end turn #7. Upon reaching approximately 80 percent power, generator stator end turn vibrations remained elevated. However, continued operation at the elevated vibration levels was supported by the turbine/generator manufacturer. Unit 2 remained at this reduced power level for the rest of the inspection period.

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

The coordination between the TSO and the plant during off-normal or emergency events;

The explanations for the events;

The estimates of when the offsite power system would be returned to a normal state; and

The notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

The actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;

The compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;

A re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and

The communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures.

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

.2 Summer Seasonal Readiness Preparations

a. Inspection Scope

The inspectors performed a review of the licensees preparations for summer weather for selected systems, including conditions that could lead to an extended drought.

During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions.

Additionally, the inspectors reviewed the Updated Safety Analysis Report (USAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant systems:

Auxiliary Building Ventilation;

Auxiliary Feedwater Pump Room Ventilation;

Battery Room Cooling; and

Unit Coolers for Buses 15, 16, 111 and 121.

This inspection constituted one seasonal adverse weather sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

.3 Readiness For Impending Adverse Weather Condition - Increased Heat Sink

Temperatures due to Limited Blowdown

a. Inspection Scope

The inspectors performed a detailed review of the licensees procedures and preparations for operating the facility during an extended period of time when the ultimate heat sink was experiencing elevated temperatures due to the limited blowdown to the river allowed by the National Pollutant Discharge Elimination System permit. The inspectors focused on plant specific design features and the implementation of procedures for responding to or mitigating the effects of these conditions on the operation of ventilation used to support the auxiliary feedwater system, the safety-related batteries, and safety-related switchgear. Inspection activities included a review of the licensees operating procedures, daily monitoring of the off-normal environmental conditions, and verification that the ventilation systems were maintaining temperatures below the system operability limits.

This inspection constituted one readiness for impending adverse weather condition sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

.4 External Flooding

a. Inspection Scope

On June 27, 2013, the licensee entered Procedure AB-4, Flooding, due to the three day predicted Mississippi River level being greater than 678 feet. The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions provided in the USAR for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable. Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site which would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also walked down underground bunkers/manholes subject to flooding that contained multiple train or multiple function risk-significant cables. The inspectors also reviewed the abnormal operating procedure (AOP) for mitigating the design basis flood to ensure it could be implemented as written.

An external flooding sample as defined in IP 71111.01-05 will not be counted during this inspection period as the inspection was ongoing at the conclusion of the period.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

121 Control Room Chiller;

Bus 16 and the Unit 1 Auxiliary Feedwater System; and

A Train Cooling Water Components.

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, USAR, Technical Specification (TS) requirements, outstanding work orders (WOs), CAPs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R05 Fire Protection

Main article: IP 71111.05

.1 Routine Resident Inspector Tours

Main article: IP 71111.05Q

a. Inspection Scope

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

Unit 1 Auxiliary Building Elevation 695 (Fire Zone 8);

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

Unit 1 Auxiliary Building Elevation 715 (Fire Zone 19);

Train A Event Monitoring Room (Fire Zone 26); and

Unit 1 Auxiliary Building Elevation 735 (Fire Zone 28).

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the 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 five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

Main article: IP 71111.05A

a. Inspection Scope

On June 1, 2013, the inspectors observed activation of the fire brigade as part of a quarterly drill. Based on this observation, the inspectors evaluated the readiness of the fire brigade to fight fires. The inspectors verified that the licensees staff identified deficiencies; openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

proper wearing of turnout gear and self-contained breathing apparatus;

proper use and layout of fire hoses;

employment of appropriate fire fighting techniques;

sufficient firefighting equipment brought to the scene;

effectiveness of fire brigade leader communications, command, and control;

search for victims and propagation of the fire into other plant areas;

smoke removal operations;

utilization of pre-planned strategies;

adherence to the pre-planned drill scenario; and

drill objectives.

Documents reviewed are listed in the Attachment to this report. These activities constituted one annual fire protection inspection sample as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

Main article: IP 71111.06

.1 Underground Vaults

a. Inspection Scope

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

Manhole for 13.8KV Cable Between the Switchyard and the Cooling Tower Substation Documents reviewed are listed in the Attachment to this report. This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

Main article: IP 71111.11Q

a. Inspection Scope

On May 10, 2013, the inspectors observed a crew of licensed operators in the simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

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

The crews performance in these areas was compared to pre-established operator 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 simulator sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

Main article: IP 71111.11Q

a. Inspection Scope

On April 6 and 13, 2013, the inspectors observed licensed operators in the control room during the performance of activities that required heightened awareness or were related to increased risk. During the first inspection, the inspectors observed activities associated with performing post-maintenance testing on the 11 reactor protection system motor generator set. On April 13 the inspectors observed the operators performing increased monitoring of ultimate heat sink indications during the arrival of a barge carrying the replacement steam generators. 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 alarms;

correct use and implementation of procedures;

control board manipulations; and

oversight and direction from supervisors.

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

Main article: IP 71111.12

.1 Routine Quarterly Evaluations

Main article: IP 71111.12Q

a. Inspection Scope

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

D5/D6 Emergency Diesel Ventilation System;

21 Inverter; and

D1 Diesel Generator Room Cooling Supply and Exhaust Fan Pitch Controller.

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

implementing appropriate work practices;

identifying and addressing common cause failures;

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

characterizing system reliability issues for performance;

charging unavailability for performance;

trending key parameters for condition monitoring;

ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

verifying appropriate performance criteria for 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

Introduction:

A self-revealing finding of very low safety significance (Green) and a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instruction, Procedures, and Drawings was identified for the failure to have appropriate drawings when performing maintenance on the D1 Diesel Generator Room Cooling Supply and Exhaust Fan Blade Pitch Controller. Specifically, Logic Diagram NF-40326-1, Interlock Logic Diagram Diesel Generator Room Cooling Unit 1 and 2, for the safety-related controller incorrectly indicated that the pitch would reposition to a maximum flow condition upon a loss of signal. The inaccurate drawing information resulted in the D1 Diesel Generator being rendered inoperable for 30 minutes when a component was disconnected in preparation for refurbishing the D1 Diesel Generator Room Temperature Transmitter (22017).

Description:

On June 13, 2013, the licensee was performing WO 459086, Refurbish Temperature Transmitter, for the D1 Diesel Generator Room Cooling Supply and Exhaust Fan Pitch Controller. A caution statement was included in the work instruction to ensure conditions for failing the fan blades open were met prior to disconnecting the temperature transmitter. The controlled drawing for the D1 Diesel Generator Room Cooling Supply and Exhaust Fan Blade Pitch Control Logic (NF-40326-1) was also attached to the WO indicating that pitch position fails to maximum flow with loss of signal. In accordance with Job Step 2 of WO 459086, the licensee started to determinate the D1 Diesel Generator Room Temperature Transmitter. Though not required by the WO, a licensee technician was stationed to observe the fan blade pitch and noted that the blades were changing position to the minimum flow position when the power supply wire was removed from the temperature transmitter. The control room was notified and the licensee declared the D1 Diesel Generator inoperable. Action was then taken to reconnect the power supply wire returning the temperature transmitter to service, and the D1 Diesel Generator was declared operable.

The inspectors performed a search of the licensees CAP and identified a similar event from February 23, 2012 in which the D2 Temperature Controller was not responding properly during Surveillance Procedure (SP) 1305 (CAPs 1320653 and 1326344). The Equipment Cause Evaluation for this event determined that the installed Electronic Signal Receiver (ESR) on the blade pitch positioners for the D1 and D2 Diesel ventilation systems would drive the positioner to the minimum flow configuration on a loss of signal. Actions were assigned to implement changes to the positioner to ensure that the pitch position failed to the maximum flow condition on the loss of signal by April 4, 2013. On March 27, 2013, the action completion date was extended to December 31, 2013, due to the low risk for extending the assignment since the configuration change only affects the system if the system fails. No actions were assigned to update Logic Diagram NF-40326-1.

Analysis:

The inspectors determined that the failure to have instructions, procedures, and drawings of a type appropriate to the circumstances for an activity affecting quality was a performance deficiency associated with the Mitigating Systems Cornerstone. The inspectors determined that this issue was more than minor because it was associated with the design control, configuration control and procedure quality attributes of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the D1 Diesel Generator was unexpectedly rendered inoperable.

The inspectors utilized IMC 0609, Significance Determination Process, 0609.04, Initial Characterization of Findings, and determined that this issue was of very low safety significance (Green) because each question provided in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, was answered no. Specifically, this issue did not affect the design of the ventilation system nor did it result in a loss of safety function for greater than the TS allowed outage time.

The inspectors determined that this issue had a cross cutting aspect in the Problem Identification and Resolution, Operating Experience (OE) area because the licensee did not implement and institutionalize OE through changes to station processes, procedures, equipment, and training programs (P.2(b)). Specifically, the licensee took no action to revise the affected logic diagram after identifying the loss of signal position information was incorrect after a similar issue in 2012.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, and drawings, of a type appropriate to the circumstances and be accomplished in accordance with these procedures. The licensee established WO 459086, Refurbish Temperature Transmitter, as the implementing procedure for removing and refurbishing the D1 Diesel Generator Room Temperature Transmitter, an activity affecting quality.

Contrary to the above, on June 13, 2013, the licensee failed to have instructions, procedures and drawings appropriate to the circumstance when performing maintenance on the D1 Diesel Generator Room Temperature Transmitter. Specifically, Logic Diagram NF-40326-1 failed to contain correct information regarding the positioning of the D1 Diesel Generator Room Cooling Supply and Exhaust Fan Pitch during a loss of signal condition. As a result, the D1 Diesel Generator was rendered inoperable for approximately 30 minutes when the fan pitch failed to the minimum flow condition immediately after power was removed from the temperature transmitter (creating a loss of signal).

Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CAP 1386519, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2013003-01: Improper Work Instructions Rendered D1 EDG Inoperable). Corrective actions for this issue included initiating a drawing change to revise logic diagram NF-40326-1, returning the temperature transmitter to service, and suspending additional work on the temperature transmitter until an Apparent Cause Evaluation (ACE) is completed.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

.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 performing work:

Planned maintenance on the 21 Cooling Water Strainer;

Emergent work on the 11 Generator Seal Oil Pump;

Planned maintenance on the 22 Cooling Water Strainer;

Planned maintenance on the Unit 1 Reactor Makeup Switch; and

Fuel handling concurrent with emergent maintenance on the 122 Control Room Chiller.

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

Main article: IP 71111.15

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

Auxiliary Building Ventilation Damper CD-34042;

11 Turbine Driven Auxiliary Feedwater Pump Lube Oil Pump Cycling;

Emergency Diesel Generator Lube Oil Inventory Tracking; and

D1 Supply and Exhaust Fan Blade Pitch Positioners.

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 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 four samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

Main article: IP 71111.18

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification:

Engineering Change 21846 - Temporarily Blank Off Auxiliary Building Ventilation Damper CD-34042.

The inspectors reviewed the configuration change and associated 10 CFR 50.59 safety evaluation screening against the design basis, the USAR, and the TS to verify that the modification did not affect the operability or availability of the affected system. The inspectors observed ongoing and completed work activities to ensure that the modification was installed as directed and consistent with the design control documents; the modification operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modification did not impact the operability of any interfacing system. 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 one temporary modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

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

D5 EDG testing after injector replacement;

11 Reactor Protection System Motor Generator Set testing after maintenance;

11 Battery Room Special Ventilation testing; and

22 Component Cooling Water Pump testing following pump seal replacement.

These activities were selected based upon the structure, system, or component'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 were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against 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 corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

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

2R-11 Radiation Monitor / Unit 2 Containment/Reactor Coolant System (RCS)

Leakage Walkdown (RCS Leakage);

SP 1035B - Reactor Protection Logic Test at Power - Train B (routine);

SP 1055.2 - 122 Control Room Clean Up Ventilation System Filter Removal Efficiency Test (routine);

SP 1112 - Steam Exclusion Monthly Damper Test (routine);

SP 2090B - 22 Containment Spray Pump Quarterly Test (routine);

SP 2095 - Bus 26 Load Sequencer Test (routine);

SP 2102 - 22 Turbine-Driven AFW Pump Monthly Test (IST); and

SP 2305 - D6 Diesel Generator Monthly Slow Start Test (routine)

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

did preconditioning occur;

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

acceptance criteria were 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 six routine surveillance testing samples, one inservice testing sample, and one RCS leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Main article: IP 71114.06

.1 Training Observation

a. Inspection Scope

The inspector observed a simulator training evolution for licensed operators on May 14, 2013, which required emergency plan implementation. 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 corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.

This inspection of the licensees training evolution with emergency preparedness drill aspects constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

RADIATION SAFETY

2RS5 Radiation Monitoring Instrumentation

Main article: IP 71124.05

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the USAR to identify radiation instruments associated with monitoring area radiological conditions, including airborne radioactivity, process streams, effluents, materials/articles, and workers. Additionally, the inspectors reviewed the instrumentation and the associated TS requirements for post-accident monitoring instrumentation, including instruments used for remote emergency assessment.

The inspectors reviewed a listing of in-service survey instrumentation, including air samplers and small article monitors, along with instruments used to detect and analyze workers external contamination. Additionally, the inspectors reviewed personnel contamination monitors and portal monitors, including whole-body counters, to detect workers internal contamination. The inspectors reviewed this list to assess whether an adequate number and type of instruments were available to support operations.

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

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

The inspectors reviewed the area radiation monitor alarm setpoint values and setpoint basis, as provided in the TS and the USAR.

The inspectors reviewed effluent monitor alarm setpoint bases and the calculational methods provided in the Offsite Dose Calculation Manual (ODCM).

This inspection constituted a partial sample as defined in IP 71124.05-05.

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

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

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

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

The inspectors walked down area radiation monitors and continuous air monitors to determine whether they were appropriately positioned, relative to the radiation sources or areas they were intended to monitor. Selectively, the inspectors compared monitor response (via local or remote control room indications) with actual area conditions for consistency.

The inspectors selected personnel contamination monitors, portal monitors, and small article monitors and evaluated whether the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

b. Findings

No findings were identified.

.3 Calibration and Testing Program (02.03)

Process Effluent Monitors

a. Inspection Scope

The inspectors selected effluent monitor instruments (e.g., gaseous and liquid) and evaluated whether channel calibration and functional tests were performed consistent with radiological effluent TS/ODCM. The inspectors assessed whether:

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

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

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

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

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

b. Findings

No findings were identified.

.4 Problem Identification and Resolution (02.04)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring instrumentation 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 involve radiation monitoring instrumentation.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program

Main article: IP 71124.07

This inspection constituted one complete sample as defined in Inspection Procedure 71124.07-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the annual radiological environmental operating reports and the results of any licensee assessments since the last inspection to assess whether the Radiological Environmental Monitoring Program (REMP) was implemented in accordance with the TS and the ODCM. This review included reported changes to the ODCM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, Inter-Laboratory Comparison Program, and analysis of data.

The inspectors reviewed the ODCM to identify locations of environmental monitoring stations.

The inspectors reviewed the USAR for information regarding the REMP and meteorological monitoring instrumentation.

The inspectors reviewed quality assurance audit results of the program to assist in choosing inspection smart samples and audits and technical evaluations performed on the vendor Laboratory Program.

The inspectors reviewed the Annual Effluent Release Report and the 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste report, to determine whether the licensee was sampling as appropriate, for the predominant and dose-causing radionuclides likely to be released in effluents.

b. Findings

No findings were identified.

.2 Site Inspection (02.02)

a. Inspection Scope

The inspectors walked down select air sampling stations and thermoluminescent dosimeter (TLD) monitoring stations to determine whether they were located as described in the ODCM and to determine the equipment material condition. Consistent with smart sampling, the air sampling stations were selected based on the locations with the highest Atmospheric Dispersion Values (X/Q) and Metrologies (D/Q) wind sectors and TLDs were selected based on the most risk-significant locations, (e.g., those that have the highest potential for public dose impact).

For the air samplers and TLDs selected, the inspectors reviewed the calibration and maintenance records to evaluate whether they demonstrated adequate operability of these components. Additionally, the review included the calibration and maintenance records of select composite water samplers.

The inspectors assessed whether the licensee had initiated sampling of other appropriate media upon loss of a required sampling station.

The inspectors observed the collection and preparation of environmental samples from different environmental media (e.g., ground and surface water, milk, vegetation, sediment, and soil) as available to verify that environmental sampling is representative of the release pathways as specified in the ODCM and if sampling techniques were in accordance with procedures.

Based on direct observation and review of records, the inspectors assessed whether the meteorological instruments were operable, calibrated, and maintained, in accordance with guidance contained in the USAR, NRC Regulatory Guide 1.23, Meteorological Monitoring Programs for Nuclear Power Plants, and licensee procedures. The inspectors assessed whether the meteorological data readout and recording instruments in the control room and, if applicable, at the tower, were operable.

The inspectors verified that missed and/or anomalous environmental samples were identified and reported in the annual environmental monitoring report. The inspectors selected events that involved a missed sample, inoperable sampler, lost TLD or anomalous measurement to verify that the licensee has identified the cause and implemented corrective actions. The inspectors reviewed the licensees assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection (LLDs)) and reviewed the associated radioactive effluent release data that was the source of the released material.

The inspectors selected SSCs that involved or could reasonably involve licensed material for which there was a credible mechanism for licensed material to reach ground water, and verified that the licensee had implemented a sampling and monitoring program sufficient to detect leakage of these SSCs to ground water.

The inspectors verified that records, as required by 10 CFR 50.75, Reporting and Recordkeeping for Decommissioning Planning, Section (g), of leaks, spills, and remediation since the previous inspection were retained in a retrievable manner.

The inspectors reviewed any significant changes made by the licensee to the ODCM as the result of changes to the land census, long-term meteorological conditions (3-year average), or modifications to the sampler stations since the last inspection. The inspectors reviewed technical justifications for any changed sampling locations to verify that the licensee performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment. The inspectors verified that the appropriate detection sensitivities with respect to TS/ODCM were used for counting samples (i.e., the samples meet the TS/ODCM required LLDs).

The inspectors reviewed the results of the vendors Quality Control Program, including the Inter-laboratory Comparison Program to evaluate the adequacy of environmental sample analyses performed by the licensee. The inspectors assessed whether the inter-laboratory comparison test included the media/nuclide mix appropriate for the facility. If applicable, the inspectors reviewed the licensees determination of any bias to the data and the overall effect on the REMP.

b. Findings

No findings were identified.

.3 Identification and Resolution of Problems (02.03)

a. Inspection Scope

The inspectors verified that problems associated with the REMP were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. Additionally, the inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involved the REMP.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Mitigating Systems Performance Index - High Pressure Injection Systems

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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

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

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of January 1 through June 30, 2013, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted a single semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection: Review of Corrective Actions Taken to Address

Previously Identified Maintenance Rule Deficiencies

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized an increase in the number of CAPs being written regarding the maintenance rule program.

Since the inspectors and the licensee had identified maintenance rule program deficiencies in September and November 2011 respectively, the inspectors reviewed the circumstances surrounding the recently written CAPs and the status of the licensees previous corrective actions to determine whether the licensee was in compliance with 10 CFR 50.65.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance (Green),and a violation of 10 CFR 50.65, due to the failure to demonstrate that the performance or condition of SSCs was being effectively controlled through the performance of appropriate preventive maintenance. In addition, the licensee failed to establish goals sufficient to provide reasonable assurance that two SSCs were capable of performing their intended safety function after their performance demonstrations became invalid.

Description:

In July 1996 10 CFR 50.65, commonly referred to as the maintenance rule, went into effect. The maintenance rule required all reactor licensees to monitor the performance or condition of specific SSCs against established criteria to demonstrate that maintenance was being effectively performed and that the SSCs remained capable of performing their intended safety function(s). These SSCs are commonly referred to as (a)(2) SSCs. If the licensee was unable to demonstrate that the performance or condition of an SSC was being effectively controlled through maintenance, the licensee designated the SSC as (a)(1), developed an action plan, and established additional performance goals to improve the SSCs performance.

During the third quarter of 2011, the inspectors documented a finding of very low safety significance (Green) and an NCV of 10 CFR 50.65 as part of NRC Inspection Report 05000282/2011004; 05000306/2011004. Specifically, the licensee had failed to properly scope, monitor the performance or condition, and establish goals for the radiation monitoring system as required by 10 CFR 50.65. The licensee initiated CAPs 1303302 and 1304984 to document the inspectors issues On November 11, 2011, engineering personnel initiated CAP 1312835 to document that external reviews of the maintenance rule program (including reviews performed by the NRC) had brought the quality of the program into question. On February 15, 2012, the licensee completed a maintenance rule program evaluation and determined the following:

Timeliness of action plan development, approval and implementation was lacking;

Personnel knowledge of maintenance rule responsibilities was lacking;

Some high safety significant SSCs and low safety significant standby SSCs were inappropriately monitored at the system level rather than at the train level;

Some high safety significant SSCs did not have proper performance criteria to allow balancing of availability and reliability as required by 10 CFR 50.65(a)(3);

Due to numerous SSC scoping deficiencies, a 10 CFR 50.65(b) compliant re-scoping effort was needed for 107 SSCs.

On March 9, 2012, the licensees performance assessment review board (PARB)upgraded the significance level of CAP 1312835 from the second highest level (B) to the highest level (A). On March 13, 2012, corporate engineering initiated an A level CAP, CAP 1329077, due to identifying significant regulatory vulnerability within the Prairie Island and Monticello maintenance rule programs. Based upon this CAP, the licensee performed a root cause evaluation to determine the causes for the programmatic deficiencies and to develop fleet-wide corrective actions. The root cause evaluation team also addressed the deficiencies identified in CAP 1312835.

Fleet Level Root Cause Evaluation 1329077 was completed on June 29, 2012. The root cause evaluators determined that the significant maintenance rule programmatic issues identified at each station were caused by the following:

Corporate level and plant specific implementation procedures lacked adequate guidance to effectively implement the maintenance rule program;

Maintenance rule program assessments were not performed due to the failure to follow existing procedures;

Lack of management understanding regarding industry standards pertaining to the maintenance rule;

Diminished corporate oversight of the maintenance rule program;

Management overconfidence in maintenance rule program adequacy;

Key maintenance rule program individuals had a lack of knowledge regarding implementation of the rule; and

Failure to update the maintenance rule basis document as required.

The licensee established the following CAPRs to address the root cause report:

Develop and implement maintenance rule procedures to address the following:

action plans (as required by 10 CFR 50.65(a)(1), monitoring (as required by 10 CFR 50.65(a)(2), maintenance rule SSC scoping, conduct of the maintenance rule expert panel (MREP), and performance of the 10 CFR 50.65(a)(3)assessment;

Perform re-scoping of SSCs to the revised maintenance rule guidance;

Revise the program health evaluation criteria included in Procedure FP-PE-PHS-01, Program Health Process;

Revise Procedure FP-PE-PHS-01 to specify the frequency of self assessments and benchmarking activities for regulatory driven programs; and

Conduct a review of lessons learned from this event as part of the leadership development program to emphasize the importance of supervisory and management engagement in ensuring that daily activities are executed in accordance with established procedures, regulatory requirements and management expectations.

In mid-2012, the licensee discussed the maintenance rule issues, root cause evaluation results, proposed corrective actions, and corrective action completion dates with the inspectors. The licensee indicated that in its current state, Prairie Islands maintenance rule program was not meeting the regulatory requirements specified in 10 CFR 50.65.

However, the licensee planned to complete the CAPRs discussed above by December 31, 2012.

In March and April 2013 the inspectors reviewed CAPs indicating a large number of documents in the maintenance rule program backlog. Specifically, CAPs 1376163 and 1376499 indicated there were more than 170 items dating back to July 2012 that had not been reviewed. Additional CAP subjects included items such as procedure noncompliance issues, an overall lack of action regarding the need for maintenance rule action plans, and the untimely updating of maintenance rule SSC unavailability and unreliability data. Based on this information, the licensee decided to develop an additional plan to correct the issues. However, this plan was not scheduled for development until May 1, 2013. The inspectors also noted that many of the CAPs reviewed were given a C or D significance level (the two lowest levels) by the corrective action screening team. The assignment of extremely low significance levels concerned the inspectors because it resulted in the licensees failure to take action to restore compliance with the maintenance rule.

Based upon the above concerns, the inspectors reviewed the status of corrective actions contained in CAPs 1312835 and 1329077. The inspectors found that the procedure revisions were complete. However, the maintenance rule re-scoping effort was not complete. According to a copy of CAP 1329077 printed on April 30, 2013, the re-scoping effort completion date was extended from December 31, 2012 to March 31, 2013 even though 104 of the 107 SSCs had been re-scoped as of January 31, 2013.

On February 27, 2013, notes were added to CAP 1329077 indicating that the completion of the re-scoping effort by March 31 was in jeopardy due to competing priorities.

Approximately one month later, the re-scoping effort completion date was changed to September 27, 2013. The CAP indicated that the due date change was needed because resources within the engineering department were reassigned to a project of higher priority. Another portion of CAP 1329077 indicated that the due date was changed due to potentially incomplete work by the individual performing the re-scoping activities. The inspectors discussed the revised due dates with engineering management and the individual. The inspectors found that the re-scoping effort due date was changed because 74 of the 104 completed re-scoping documents could not be found. While the licensee was aware of the missing documents in late March or early April 2013, the licensee had not written a CAP regarding the missing documents until May 8, 2013 (after prompting by the inspectors). In addition, the higher priority project discussed in the due date extension request was the preparation for and completion of an unrelated NRC inspection. The inspectors considered the due date extension to be inappropriate as the licensee viewed preparing for and completing an NRC inspection to be a higher priority than restoring compliance with an NRC regulation.

The inspectors also found that the CAPR associated with discussing the lessons learned with the Prairie Island leadership team was closed shown as complete. Specifically, CAP assignment 1329077-07 was documented as completed on October 26, 2012.

However, the inspectors found that the lessons learned had not been shared with the Prairie Island leadership. In fact, the assignment to share the lessons learned had been repeatedly extended such that it was not scheduled for completion until September 20, 2013 (almost two years after the initial maintenance rule problems were discovered).

The inspectors determined that the failure to complete the re-scoping efforts, share the lessons learned, and perform periodic and timely MREP meetings had contributed to the failure to demonstrate that the performance or condition of SSCs was being effectively controlled through the performance of appropriate preventive maintenance and the failure to establish goals sufficient to provide reasonable assurance that such SSCs were capable of performing their intended safety function after the performance demonstration became invalid. This conclusion was based upon the following examples:

On May 10, 2012, the D5/D6 diesel ventilation system (ZG system) experienced a maintenance preventable functional failure as documented in CAP 1292975.

Four months later, the MREP reviewed the ZG systems performance and directed that an (a)(1) action plan be developed by October 12, 2012. The inspectors determined that although the (a)(1) action plan was developed by the system engineer by the specified due date, the action plan was not reviewed by the expert panel until January 25, 2013. At the January 25, 2013 MREP meeting, the MREP tabled the ZG system (a)(1) action plan based on the belief that the ZG system re-scoping effort would be completed shortly and that the re-scoping effort would change the ZG systems performance criteria such that the system would no longer be (a)(1). The (a)(1) action plan remained unapproved until May 3, 2013. As a result, goals sufficient to provide reasonable assurance that the ZG system was capable of performing its intended safety function were not established until approximately one year after its performance demonstration became invalid.

On February 14, 2013, the 21 inverter tripped during installation of fuses on instrument 2N42. This condition required 73 hours8.449074e-4 days 0.0203 hours 1.207011e-4 weeks 2.77765e-5 months and 27 minutes to repair.

Four days later engineering personnel initiated CAP 1370660 to document that a maintenance rule (a)(1) determination was required because the time needed to repair the 21 inverter exceeded the maintenance rule unavailability limit of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months in a two year period. Due to a lack of MREP meetings, the licensee failed to establish goals sufficient to provide reasonable assurance that the 21 inverter remained capable of fulfilling its intended functions until April 29, 2013. The licensee documented this issue in CAP 1374696.

The inspectors determined that managements failure to support attendance at scheduled MREP meetings also contributed to the failure to monitor the performance or condition of multiple SSCs. As of May 2, 2013, the failure to hold routine MREP meetings had resulted in more than 350 (a)(2) performance demonstrations dating back to January 2012 being unapproved. The inspectors noted that the maintenance rule coordinator had written several CAPs regarding the failure to hold MREP meetings. In most cases, these CAPs were assigned the lowest significance level and closed to trend.

The inspectors also reviewed the licensees resolution of NCV 05000282/2011004-01; 05000306/2011004-01 and CAPs 1303302 and 1304984. The inspectors found that although both CAPs indicated that the corrective actions associated with the NCV were complete, no actions had been taken to correct the violation of NRC requirements.

Specifically, the inspectors found that the corrective actions proposed in CAPs 1303302 and 1304984 were closed to the maintenance rule SSC re-scoping effort captured in CAP Assignment 1312835-06. This CAP assignment remained incomplete as of the conclusion of this inspection.

On May 28, 2013, the licensee initiated CAP 1384508 to document a programmatic breakdown of the Prairie Island maintenance rule program based upon the inspectors concerns. In early May, the licensee began holding weekly MREP meetings to review the 358 items in the maintenance rule backlog. As of June 20, 2013, 103 items were left to review. To aid in the improvement efforts, the licensee reassigned engineering personnel to provide daily oversight of maintenance rule activities. The licensee also planned to hire additional resources to ensure that the re-scoping effort was completed by September 27, 2013.

Analysis:

The inspectors determined that the failure to demonstrate that the performance or condition of SSCs was being effectively controlled through the performance of appropriate preventive maintenance and the failure to establish goals sufficient to provide reasonable assurance that such SSCs were capable of performing their intended safety function after the performance demonstration became invalid was a performance deficiency that was within the licensees ability to foresee and correct. This issue was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone. This finding also impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to properly scope SSCs into the maintenance rule program and the untimely evaluation of SSC condition or performance resulted in the failure to establish goals sufficient to provide reasonable assurance that SSCs were capable of performing their intended safety function after their performance demonstrations became invalid.

The inspectors utilized IMC 0609, Significance Determination Process, 0609.04, Initial Characterization of Findings, and concluded that this findings significance was best characterized by using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Based upon the fact that none of the equipment issues discussed above rose to a level of greater than very low safety significance, the inspectors determined that this issue was best characterized as having very low safety significance (Green). The inspectors concluded that this finding was cross cutting in the Problem Identification and Resolution, Corrective Action Program area because the licensee failed to take appropriate and timely corrective actions to address the issues identified in November 2011 (P.1(d)).

Enforcement:

Title 10 CFR 50.65(a)(1), requires, in part, that the holders of an operating license shall monitor the performance or condition of SSCs within the scope of the rule as defined by 10 CFR 50.65(b), against licensee-established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions.

Title 10 CFR 50.65(a)(2) states, in part, that monitoring as specified in 10 CFR 50.65(a)(1) is not required where it has been demonstrated that the performance or condition of an SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended functions.

Contrary to the above, from September 2011 through June 30, 2013, the licensee failed to demonstrate that the performance or condition SSCs specified in 10 CFR 50.65(b)were being effectively controlled through the performance of appropriate preventive maintenance and that associated goals were established when (a)(2) preventive maintenance demonstrations became invalid. This resulted in the untimely evaluation of more than 350 deficient conditions to determine whether the conditions impacted the licensees ability to demonstrate that the performance or condition of SSCs was being effectively controlled through the performance of preventive maintenance. In addition, actions were not taken to establish goals sufficient to provide reasonable assurance that the radiation monitor system, the ZG system and the 21 inverter remained capable of fulfilling their intended functions when their performance demonstrations became invalid (NOV 05000282/2013003-02; 05000306/2013003-02: Failure to Monitor SSC Performance as Required by 10 CFR 50.65).

Although the licensee entered this issue into their corrective action program as CAP 1384508, this issue is being treated as a cited violation because the licensee failed to restore compliance within a reasonable amount of time after identifying multiple violations of the maintenance rule in November 2011, including NOV 05000282/201104 and 05000306/201104. Corrective actions for this issue included holding weekly MREP meetings to reduce the maintenance rule backlog, improving MREP meeting attendance, reassigning engineering personnel to provide daily oversight of maintenance rule activities, sharing the lessons learned from the November 2011 issue with the licensees leadership team, and hiring additional resources to ensure that the re-scoping effort was completed by September 27, 2013.

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

Main article: IP 71153

.1 (Closed) Licensee Event Report (LER) 05000306/2012-001-01: Unit 2 Manual Reactor

Trip due to Feedwater Heater Hi-Hi Alarm The event discussed in the LER above was originally documented as a self-revealing finding of very low safety significance (Green) and an NCV in NRC Inspection Report 05000282/2012003; 05000306/2012003. On March 20, 2013, the licensee submitted an LER supplement to the NRC to provide further information regarding the cause of the manual reactor trip. The inspectors reviewed the LER supplement and determined that the information provided did not change the inspectors original assessment of this event. Documents reviewed 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.

.2 (Closed) LER 05000306/2012-002-01: Unit 2 Emergency Diesel Generators Inoperable

Due to Missing Flood Control Barrier Seal The event discussed in the LER above was originally documented as a licensee identified NCV in NRC Inspection Report 05000282/2012005; 05000306/2012005. On April 4, 2013, the licensee submitted an LER supplement to the NRC to provide further information regarding this event. The inspectors reviewed the LER supplement and determined that the information provided did not change the inspectors original assessment of the event. Documents reviewed 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.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 11, 2013, the inspectors presented the inspection results to Mr. J. Lynch 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 inspection results for the area of radiological environmental monitoring with J. Lynch, Site Vice President, on May 10, 2013.

The inspection results for the area of radiation monitoring instrumentation with S. Sharp, Plant Manager, on June 28, 2013.

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.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Lynch, Site Vice President

K. Davison, Director - Site Operations

A. Mitchell, Site Engineering Director

S. Sharp, Plant Manager

T. Allen, Assistant Plant Manager

J. Anderson, Regulatory Affairs Manager

J. Boesch, Maintenance Manager

T. Borgen, Training Manager

B. Boyer, Radiation Protection Manager

F. Calia, Performance Assessment Manager

K. DeFusco, Emergency Preparedness Manager

D. Gauger, Chemistry/Environmental Manager

J. Hamilton, Security Manager

J. Lash, Nuclear Oversight Manager

S. Lappegaard, Production Planning Manager

B. Meek, Safety and Human Performance Manager

K. Peterson, Business Support Manager

J. Ruttar, Operations Manager

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

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

Attachment

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened

05000282/2013003-01 NCV Improper Work Instructions Rendered D1 EDG Inoperable (1R12)

05000282/2013003-02; NOV Failure to Monitor SSCs as Required by 10 CFR 50.65

05000306/2013003-02 (4OA2)

Closed

05000282/2013003-01 NCV Improper Work Instructions Rendered D1 EDG Inoperable (Section 1R12)

05000306/2012-001-01 LER Unit 2 Manual Reactor Trip due to Feedwater Heater Hi-Hi Alarm (Section 4OA3)

05000306/2012-002-01 LER Unit 2 Emergency Diesel Generators Inoperable due to Missing Flood Control Barrier Seal (Section 4OA3)

Attachment

LIST OF DOCUMENTS REVIEWED

IR 05000282/2013003

Text

SUBJECT:

Dear Mr. Lynch:

Enclosure:

SUMMARY OF FINDINGS

NRC-Identified

Cornerstone: Mitigating Systems

Licensee-Identified Violations

REPORT DETAILS

Summary of Plant Status

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

b. Findings

.2 Summer Seasonal Readiness Preparations

a. Inspection Scope

b. Findings

.3 Readiness For Impending Adverse Weather Condition - Increased Heat Sink

a. Inspection Scope

b. Findings

.4 External Flooding

a. Inspection Scope

b. Findings

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

b. Findings

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

b. Findings

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

b. Findings

1R06 Flooding

.1 Underground Vaults

a. Inspection Scope

b. Findings

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

b. Findings

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

b. Findings

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

b. Findings

Introduction:

Description:

Analysis:

Enforcement:

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

b. Findings

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

b. Findings

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

b. Findings

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

b. Findings

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

b. Findings

1EP6 Drill Evaluation

.1 Training Observation

a. Inspection Scope

b. Findings