Text

IR 05000282/2014005; 05000306/202014005, October 1, 2014 Through December 31, 2014, Prairie Island, Units 1 and 2, NRC Integrated Inspection Report
	ML15029A661
Person / Time
Site:	Prairie Island
Issue date:	01/29/2015
From:	Kenneth Riemer; Division Reactor Projects III
To:	Davison K; Northern States Power Co
References
	IR 2014005
	Download: ML15029A661 (67)
	v • d • e

UNITED STATES ary 29, 2015

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000282/2014005; 05000306/202014005

Dear Mr. Davison:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an 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 January 6, 2015, with you and other members of your staff.

Three NRC-identified findings of very low safety significance (Green) were identified during this inspection. These findings were determined to involve violations of NRC requirements. One licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of any NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission-Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant. In addition, if you disagree with the 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 Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, 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 NRCs Public Document Room or from the Publicly Available Records (PARS)

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

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

Sincerely,

/RA/

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

Enclosure:

Inspection Report 05000282/2014005; 05000306/2014005 w/Attachments:

Attachment 1: Supplemental Information Attachment 2: Inspection Checklist for Temporary Instruction 2515/189

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report No: 05000282/2014005; 05000306/2014005 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: October 1, 2014 through December 31, 2014 Inspectors: K. Stoedter, Senior Resident Inspector P. LaFlamme, Resident Inspector J. Beavers, Emergency Preparedness Inspector B. Boston, Reactor Engineer J. Bozga, Reactor Inspector R. Elliott, Reactor Engineer M. Holmberg, Reactor Inspector B. Jose, Reactor Inspector D. McNeil, Senior Operations Engineer V. Meghani, Reactor Inspector D. Passehl, Senior Reactor Analyst M. Phalen, Senior Health Physicist Approved by: K. Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000282/2014005; 05000306/2014005; 10/01/2014-12/31/2014; Prairie

Island Nuclear Generating Plant, Units 1 and 2; Adverse Weather, Inservice Inspection, and Surveillance Testing.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Three Green findings were identified by the inspectors. Each of the findings 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 Inspection Manual Chapter (IMC) 0310, Aspects Within the Cross-Cutting Areas effective date January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 5, dated February 2014.

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low safety significance and a NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, on October 21, 2014, due to the licensees failure to perform the reactor vessel weld ultrasonic examinations with procedures qualified in accordance with the American Society of Mechanical Engineers (ASME) Code. Corrective actions for this issue included entering the issue into the corrective action program (CAP) and considering the available options to restore compliance with the ASME Code.

The inspectors determined that this issue was more than minor because if left uncorrected, this deficiency had the potential to lead to a more significant safety concern. Specifically, the failure to properly qualify ultrasonic examination procedures prior to examining the Unit 1 reactor vessel welds could result in the failure to detect weld flaws. In turn, the undetected weld flaws could increase the risk of a loss of coolant accident. The inspectors concluded that this issue was of very low safety significance because Questions 1 and 2 provided in IMC 0609, Appendix A, Exhibit 1, Initiating Events Screening Questions, were answered No. In this case, the ultrasonic examination intended to detect weld degradation had not yet affected the ability of the reactor vessel to perform its design functions. This finding was cross-cutting in the Human Performance, Resources area because the licensee did not have adequate supervisory and management oversight of work activities to ensure that the procedures used during the ultrasonic examination of reactor vessel welds were properly qualified in accordance with the applicable ASME Code (H.2). (Section 1R08.1)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and a NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, on December 4, 2014, due to the licensees failure to follow procedure during the performance of test procedure (TP) 1637, Winter Plant Operation. Specifically, maintenance personnel failed to comply with a step within TP 1637 which directed that a tent and heater be installed around the Unit 2 cooling water (CL) discharge to grade header to prevent ice buildup and subsequent blockage during freezing conditions.

Consequently, the inspectors identified ice buildup on the CL header discharge orifice which if left uncorrected, could result in header blockage and subsequent inoperability.

Corrective actions for this issue included removing the ice buildup on the cooling water discharge header, installing a tent and heater in accordance with TP 1637, revising the associated procedures and performing an apparent cause evaluation.

The inspectors determined that this issue impacted the Mitigating Systems cornerstone and was more than minor because if left uncorrected, this issue could become a more significant safety concern. Specifically, with freezing conditions present coupled with the existence of leakage and resultant ice buildup on 20-CL-61, the potential existed for subsequent ice blockage if left uncorrected and resultant inoperability of the cooling water system. 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 finding was associated with a conservative bias cross cutting aspect in the human performance cross cutting area.

Specifically, operations and maintenance personnel did not utilize prudent decision making practices to ensure the cooling water header was adequately protected against freezing conditions (H.14). (Section 1R01)

Green.

The inspectors identified a finding of very low safety significance and a NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, on September 29, 2014, due to the licensees failure to follow procedure during the performance of SP 1335, D2 Diesel Generator 18 Month 24 Hour Load Test.

Specifically, operations personnel failed to comply with steps within SP 1335 which directed that the emergency diesel generators (EDGs) kVAR loading be adjusted until a power factor of less than or equal to 0.85 was achieved or Bus 16 voltage was between 4350 and 4375 volts. An extent of condition review determined that operations personnel failed to comply with a similar procedure step during the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months load test of the D1 EDG performed in May 2013. As a result, the licensee had to re-perform the tests, which resulted in additional EDG inoperability and unavailability. Corrective actions for this issue included training the operators on the need to maintain the power factor or bus voltage within limits during testing, requiring all data collected by the operations department during Technical Specification (TS) surveillance testing to be independently verified, and requiring all TS surveillance requirement results to be reviewed and approved by two senior reactor operators.

The inspectors determined that this finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone and impacted the cornerstones objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operations personnel were required to declare the D1 and D2 EDGs inoperable and unavailable to perform their safety functions while the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months load testing was re-performed. The inspectors concluded that 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. This finding was cross-cutting in the Human Performance, Avoid Complacency area because operations personnel failed to implement appropriate error reduction tools to ensure that the power factor or bus voltage requirements were met during the surveillance test (H.12).

(Section 1R22)

Licensee Identified Violations

A violation of very low safety significance or Severity Level IV that was identified by the licensee has been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees CAP. This violation and CAP tracking number is listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period operating at full power. On October 8, 2014, operations personnel shut down the Unit 1 reactor to perform Refueling Outage 1R29. Activities completed during the refueling outage included the reactor vessel baffle bolt inspection, the replacement of both reactor coolant pump seals and installation of a new transformer. Operations personnel returned the Unit 1 reactor to operation on November 20, 2014. The main generator was synchronized with the electrical grid at 9:56 p.m. on November 21, 2014.

The licensee began Forced Outage 1F2901CS on December 10, 2014, to address an increase in unidentified reactor coolant system leakage caused by degradation of the #12 reactor coolant pump seal. During this outage, the licensee removed the degraded pump seal and installed a replacement seal. Unit 1 was returned to operation on December 26, 2014.

Unit 2 operated at or near full power for the entire inspection period.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

Main article: IP 71111.01

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and the licensees implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather.

Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. 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. Cold weather protection, such as temporary enclosures and area heaters, was verified to be in operation where applicable. 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 CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

Plant screen house;

D1 and D2 EDG rooms;

D5 and D6 EDG building;

Auxiliary Building 735 elevation; and

Auxiliary Building 755 elevation.

This inspection constituted one winter seasonal readiness preparation sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance and a NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, on December 4, 2014, due to the licensees failure to follow procedure during the performance of TP 1637, Winter Plant Operation. Specifically, maintenance personnel failed to comply with Step 7.5.1 of TP 1637 which directed that a tent and heater be installed around the Unit 2 CL discharge to grade header to prevent ice buildup and subsequent blockage during freezing conditions. Consequently, the inspectors identified ice buildup on the CL header discharge orifice, which if left uncorrected, could result in header blockage and subsequent inoperability.

Description:

On December 4, 2014, while walking down cold weather protection actions performed by maintenance personnel, the inspectors identified ice buildup extruding from the Unit 2 cooling water discharge pipe (Line 20-CL-61). This safety related 20-inch diameter line terminated outside the auxiliary building and was exposed to outside environmental conditions. This line functioned as a drain path for cooling water flow if the normal return header from containment was blocked during accident conditions. Therefore, 20-CL-61 must remain free of any potential flow blockages. The inspectors noted that TP 1637, Winter Plant Operation, Step 7.5.1 stated in part, that a tent and heater be installed at the discharge line of 20-CL-61 in accordance with Temporary Modification 03T163 to mitigate ice buildup and subsequent blockage on the header discharge orifice. The inspectors additionally noted that the licensee had marked this step as not applicable and consequently had not installed the temporary modification around the discharge orifice section of 20-CL-61. The inspectors communicated their observation to the licensee and the licensee entered the issue into the corrective action program as CAP 1458832. In response to the inspectors observation, the licensee removed the ice buildup on the discharge orifice and installed a tent and heater on December 5, 2014.

While reviewing the issue further, the inspectors interviewed maintenance, operations and engineering staff. Through the interview process, the inspectors determined that maintenance personnel, with the permission of operations, made a decision in early fall of 2014 to not install the temporary modification per Step 7.5.1 of TP 1637. This decision was based on the absence of 20-CL-61 discharge orifice leakage during performance of SP 1159, Cooling Water Valves Quarterly Test, on September 9, 2014.

However, the licensee did acknowledge there had been previous identified leakage through 20-CL-61. The inspectors noted that during their walk down a trickle drip rate of water through the discharge orifice existed.

Analysis:

The inspectors determined that the failure to follow the procedural step contained in TP 1637, Winter Plant Operation, regarding installation of a tent and heater to mitigate the impacts of freezing conditions on safety-related equipment was a performance deficiency requiring an evaluation using the Significance Determination Process (SDP). The inspectors determined that this issue impacted the Mitigating Systems cornerstone and was more than minor because the line could become blocked with ice if the tent and heater were not installed.

The inspectors utilized IMC 0609, Significance Determination Process, 609.04, 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. The inspectors concluded that this finding was associated with a conservative bias cross cutting aspect in the human performance cross cutting area. Specifically, operations and maintenance personnel did not utilize prudent decision making practices to ensure the CL header was adequately protected against freezing conditions per TP 1637 (H.14).

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 procedures of a type appropriate to the circumstance and be accomplished in accordance with these procedures. The licensee established procedure TP 1637, Winter Plant Operation, Revision 48, as the implementing procedure to place the plant in a configuration conducive to winter operation to mitigate freezing conditions (an activity affecting quality). Procedure TP 1637 Step 7.5.1 stated, Install a tent and heater at the discharge of line 20-CL-61, in accordance with Temporary Modification 3T163. Contrary to the above, prior to December 4, 2014, the licensee failed to accomplish tent and heater installation in accordance with TP 1637.

Because this violation was of very low safety significance and was entered into the CAP as CAPs 1458832 and 1460360, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2014005-01; 05000306/2014005-01: Failure to Implement the Winter Plant Operation Procedure). Corrective actions for this issue included removing the ice buildup on the cooling water discharge header, installing a tent and heater in accordance with TP 1637, revising the associated procedures and performing an apparent cause evaluation.

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed a partial system walkdown of the following risk-significant system:

D1 EDG.

The inspectors selected this system based on its risk significance relative to the Reactor Safety Cornerstones at the time it was 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, 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 system incapable of performing its intended functions. The inspectors also walked down accessible portions of the system 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 CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

These activities constituted one partial system walkdown sample 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:

Fire Detection Zone 19, Unit 1 Auxiliary Building, Elevation 715;

Fire Detection Zone 28, Unit 1 Auxiliary Building, Elevation 735;

Fire Detection Zone 35, Unit 2 Battery Rooms, Elevation 695; and

Fire Detection Zone 87, Unit 1 Rod Drive Room, Elevation 735.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. 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

Main article: IP 71111.06

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the USAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a review of the following plant area(s) to assess the adequacy of internal flooding mitigation equipment and that the licensee complied with its commitments:

D1 and D2 EDG rooms including the room sump piping and check valves.

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

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

Main article: IP 71111.07

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the #11 component cooling water system heat exchanger 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 document.

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 Activities

Main article: IP 71111.08P

From October 14-29, 2014, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the Unit 1 reactor coolant system (RCS), steam generator (SG) tubes, emergency feedwater systems, risk significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, IR08.4, and 1R08.5 below constituted one inservice inspection sample as defined in IP 71111.08-05.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors observed the following non-destructive examinations (NDEs) mandated by the ASME Section XI Code (or NRC approved alternative) to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to determine whether these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement:

Ultrasonic examination (UT) of reactor vessel welds W-2 (Upper shell to intermediate shell weld), W-4 (lower shell to lower head ring weld) and W-8 (inlet nozzle to shell weld at 148.5 degrees) (Section XI, Category B-A);

UT of 11 SG head to cylindrical ring weld W-1 (Section XI, Category B-B, Item B2.40) ;

UT of a risk-informed weld in the residual heat removal (RHR) system pipe-to-elbow weld W-6LSU (Code Case N-578, Category R-A , Item R1.20);

UT of a risk-informed weld in the main steam (MS) system pipe-to-elbow weld W-4 (Code Case N-578, Category R-A , Item R1.20); and

Dye penetrant examination of control rod drive mechanism latch housing welds CRD-16, 22, 26, and 32 (Section XI, Category B-O, Item B14.10).

The inspectors reviewed the following examination records with recordable indications accepted for continued service to determine whether acceptance was in accordance with the ASME Code Section XI or an NRC-approved alternative.

Unit 2 - Subsurface Indication Identified in SG-22 lower shell-to-tubesheet Weld 3 during Pre-service UT (Report No. 2013U040).

The inspectors reviewed records of the following pressure boundary welds completed for risk significant systems during the previous Unit 1 refueling outage to determine if the welding activities and any applicable NDE performed were completed in accordance with the ASME Code or NRC-approved alternative;

Weld 1 on line 1-RC-82 - Head Vent Flange Realignment (WO 469996-01); and

Welds 1 and 2 - Replacement of Valve RC-8-10 (WO 404174-01).

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for the licensees failure to perform the reactor vessel weld UT with procedures qualified in accordance with the ASME Code.

Description:

On October 21, 2014, the inspectors identified that the procedures used for conducting UT of the Unit 1 reactor vessel shell and nozzle-to-shell welds were not qualified in accordance with the Section XI of the ASME Code. The inspectors were concerned that the failure to examine the reactor vessel welds with qualified procedures could result in the failure to detect weld flaws. Undetected vessel flaws could increase the risk for design basis events such as a loss-of-coolant accident (LOCA).

Title 10 CFR 50.55a, Codes and Standards, required licensees to implement ASME Code Section XI, Appendix VIII, Performance Demonstration for Ultrasonic Examination Systems. This appendix established a process to qualify UT systems and associated procedures through detection of flaw sets implanted in weld mockups. In particular, the UT procedure must control the essential variables affecting the examination equipment configuration to ensure that flaws can be consistently detected and adequately sized.

Specifically, ASME Code Section XI, Appendix VIII, Paragraph VIII-2100, Procedure Requirements, states, in part, that the examination procedure shall specify the essential variables including the UT search unit cable type, maximum length and maximum number of connectors. To satisfy Appendix VIII, the licensees reactor vessel examination vendor had demonstrated that the UT procedures controlled the specialized equipment essential variables (including cable type and length) such that flaws in the reactor vessel weld mockups were successfully detected and sized. Specifically, on September 9, 2003, the licensees vendor demonstrated/qualified UT Procedures 54-ISI-801-00, Automated UT of PWR Vessel Shell Welds, Revision 0 and Procedure 54-ISI-855-02, Automated Ultrasonic Examination of Reactor Vessel Nozzle to Shell Welds and Inner Radius Regions from the Nozzle Bore, Revision 2 on weld mockups fabricated and controlled under the Electric Power Research Institute (EPRI)

Performance Demonstration Initiative Program.

On September 24, 2014, the licensee approved the latest revision to the vendor procedures including Procedure 54-ISI-801-02, Revision 2 and Procedure 54-ISI-855-04, Revision 4. On October 21, 2014, the inspectors identified these procedures allowed the substitution of a different cable type (Montrose cable instead of RG-174 cable) and established a lower maximum allowable cable length for the newly substituted cable type (28 feet). From October 18-23, 2014, the licensees vendor performed examination of the reactor vessel welds in accordance with these procedures and with the substitute Montrose cable installed between the remote pulser and the tool head containing the UT transducers. Because the licensees vendor procedure allowed substitution of a different cable type and had established a different maximum allowable length, this resulted in a change to these procedure essential variables. However, the licensees vendor had not performed a procedure demonstration in accordance with Supplement 4, Supplement 6 and Supplement 7 of Appendix VIII of ASME Code Section XI with the substitute Montrose cable to requalify the revised equipment configuration and confirm that it was effective for detection or sizing of weld flaws. Instead, the licensees vendor had documented internal comparison tests of their UT equipment performance with the substitute Montrose cable. The vendor UT system comparison tests were not an authorized alternative to an Appendix VIII procedure qualification in the 1998 Edition with 2000 Addenda of the ASME Section XI Code applicable to the licensees reactor vessel examinations. Further, these vendor tests were not consistent with the ASME Code Section XI, Appendix VIII, Supplement 1 test process which allowed for substitution of other specific UT system components (pulsers, receivers or search units) without procedure requalification.

Analysis:

The inspectors determined that failure to perform the reactor vessel weld UT examinations with a procedure qualified in accordance with the ASME Code was contrary to 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes and a performance deficiency. The inspectors determined that this issue was more than minor because if left uncorrected the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the failure to examine the Unit 1 reactor vessel with a qualified UT procedure could result in failure to detect vessel weld flaws.

Undetected vessel flaws could increase the risk for design basis events such as a LOCA.

The inspectors utilized IMC 0609, Appendix A, Exhibit 1, Initiating Events Screening Questions, and determined that this issue was of very low safety significance (Green)because Questions 1 and 2 were answered No. Specifically, the UT intended to detect weld degradation had not yet affected the ability of the reactor vessel to perform its design functions. The inspectors concluded that this issue was cross-cutting in the Human Performance, Field Presence area because the licensee did not have adequate supervisory and management oversight of work activities, including contractors and supplemental personnel to ensure that the vendor procedures used for UT of reactor vessel welds were properly qualified in accordance with the applicable Code (H.2).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, states, in part, measures shall be established to assure that special processes, including welding, heat treating, and nondestructive testing are controlled and accomplished by qualified personnel using qualified procedures in accordance with applicable codes, standards, specifications, criteria and other special requirements.

The ASME Code Section XI, Appendix VIII, Performance Demonstration for Ultrasonic Examination Systems, Paragraph VIII-3140, Requalification, states When a change in an examination procedure causes an essential variable to exceed a qualified range, the examination procedure shall be re-qualified for the revised range.

Contrary to the above, from October 18-23, 2014, the licensee failed to establish measures to assure that nondestructive testing (specifically the ultrasonic testing discussed above) of the reactor vessel welds was controlled and accomplished by qualified personnel using qualified procedures in accordance with applicable codes, standards, specifications, criteria and other special requirements. Specifically, the licensee changed an essential variable range (cable type and maximum cable length) in Procedures 54-ISI-801-2 and 54-ISI-855-04 without re-qualifying the procedures for the revised range as required by Appendix VIII, of ASME Code Section XI. Because this violation was of a very low safety significance and was entered into the licensees CAP as CAP 1452407, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2014005-02: Unqualified Reactor Vessel Examination Procedures). The licensee was also evaluating two potential corrective actions to restore compliance with the ASME Code. Specifically, the licensee was considering requalification of the UT procedures by demonstration of the revised vendor UT equipment configuration to meet the ASME Code Section XI, Appendix VIII or seeking NRC-approval (e.g., relief request) to accept the examination as completed based on additional vendor tests to meet the ASME Code Section XI, Appendix VIII, Supplement 1 requirements. The inspectors noted that the licensee had until the end of the current Code interval (December 2015) to resolve this issue and complete a qualified examination of the Unit 1 reactor vessel welds.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the Unit 1 reactor vessel head, a bare metal visual (BMV) examination was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors observed the BMV examination conducted on the Unit 1 reactor vessel head penetration nozzles to determine if the activities were conducted in accordance with the requirements of ASME Code Case (CC) N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). Specifically, to determine:

If the required visual examination scope/coverage was achieved and limitations (if applicable were recorded), in accordance with the licensee procedures;

If the licensee criteria for visual examination quality and instructions for resolving interference and masking issues were adequate; and

For indications of potential through-wall leakage, that the licensee entered the condition into the corrective action system and implemented appropriate corrective actions.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

On October 8, 2014, the inspectors observed the licensee staff performing visual examinations of the Unit 1 reactor coolant and emergency core cooling systems within containment to determine if these visual examinations focused on locations where boric acid leaks can cause degradation of safety significant components.

The inspectors reviewed the following licensee evaluations of reactor coolant system components with boric acid deposits to determine if degraded components were documented in the corrective action system. The inspectors also evaluated corrective actions for any degraded reactor coolant system components to determine if they met the ASME Section XI Code.

CAP 1406178-Control Valve 31447 Failed Packing-11 Accumulator Test Line Isolation Valve; and

CAP 1396668-Safety Injection Valve SI-13-2 Packing Leak.

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 1356557-ASME Relevant Boric Acid Leak Valve on Motor Valve (MV)32231; and

CAP 1356583-Boric Acid Piping Flange Leak on MV-32096.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

For the Unit 1 SGs, no examination was required this refueling outage; therefore, the licensee did not conduct SG tube examinations and only a portion of the NRC inspection procedure could be completed for this review area. Specifically, the inspectors performed an on-site review of documentation to determine if the primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons-per-day or the detection threshold during the previous operating cycle.

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 are listed in the Attachment to this report.

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 December 29, 2014, the inspectors observed a crew of licensed operators in the plants 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 During Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On October 14, 2014, the inspectors observed activities associated with lifting and setting the reactor vessel head on its support stand in preparation for core offload. This was an activity that required heightened awareness and 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;

correct use and implementation of procedures;

polar crane 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.

.3 Annual Operating Test Results

Main article: IP 71111.11A

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Exam, administered by the licensee from July 21 through August 22, 2014, required by 10 CFR 55.59(a). The results for the exam were compared to the thresholds established in IMC 0609, Appendix I, Licensed Operator Requalification Significance Determination Process, to assess the overall adequacy of the licensees Licensed Operator Requalification Training Program to meet the requirements of 10 CFR 55.59. (02.02)

This inspection constituted one annual licensed operator requalification examination results sample as defined in IP 71111.11-05.

b. Findings

No findings were identified

1R12 Maintenance Effectiveness

Main article: IP 71111.12

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

Unit 2 containment fan coil units; and

Building maintenance and drain system.

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 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 two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

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 removing equipment for work:

Removal of the instrument air system from service during a Unit 1 reactor shut down.

This activity was selected based on its 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 one sample 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 Feedwater System (AFW) Part Installed in Incorrect Configuration;

Operability Recommendation (OPR) 1452767-12; Containment Isolation Valve Limit Switches in Auxiliary Building not in Equipment Qualification Program; Revision 0;

OPR 1441423-02; Void in Residual Heat Removal System at 1RH-13 Location; Revision 1;

Reverse Osmosis Piping to RWST Seismic Evaluation; and

12 Fan Coil Unit Spacer Offset Evaluation.

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 five 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 (EC) 23491-Vent Residual Heat Removal Sump B Suction Valve Bonnets to Eliminate Pressure Locking.

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 one permanent plant 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:

Performance testing following the #12 Battery replacement;

Testing of the loss of offsite power and safety injection actuation circuitry following planned maintenance;

12 component cooling 4KV breaker test following planned maintenance; and

Bus15 Load Sequence Testing following planned maintenance.

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.

1R20 Outage Activities

Main article: IP 71111.20

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 1 refueling outage (RFO), conducted October 8 through November 21, 2014, 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 out of service;

implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing;

installation and 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 spent fuel pool 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;

licensee fatigue management, as required by 10 CFR 26, Subpart I;

refueling activities, including fuel handling and sipping to detect fuel assembly leakage;

startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing; and

identification and resolution of problems related to RFO activities.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RFO sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

.2 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for a forced outage that began on December 10, 2014 and continued through the December 27, 2014. This outage was performed to address increased leakage on the #12 reactor coolant pump seal. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning and implementing the outage schedule.

The inspectors observed or reviewed the reactor shutdown and cooldown, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, startup and heatup activities, and identification and resolution of problems associated with the outage. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one other outage sample as defined in IP 71111.20-05.

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:

Surveillance Procedure (SP) 1001AA and SP 2001AA-Unit 1 and Unit 2 Reactor Coolant System Leakage Determination (RCS Leak Detection);

SP 1071-Reactor Coolant System Integrity Test (RCS Leak Detection);

SP 1092A-Safety Injection Check Valve Test (Head Off) Part A-High Head Flow Path Verification (In-service Test);

SP 1331-12 motor driven AFW Pump Auto Start and Functional Refueling Outage Test (Routine);

SP 1335-D2 Diesel Generator 18 Month 24 Hour Load Test (Routine); and

SP 2130B-Train B Containment Vacuum Breaker Test (Containment Isolation).

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 were 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 two routine surveillance-testing samples, one inservice testing sample; two RCS leak detection inspection samples, and one containment isolation valve sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance and a NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, on September 29, 2014, due to the licensees failure to follow procedure during the performance of SP 1335, D2 Diesel Generator 18 Month 24 Hour Load Test.

Specifically, operations personnel failed to comply with steps within SP 1335 which directed that the EDGs kVAR loading be adjusted until a power factor of less than or equal to 0.85 was achieved or Bus 16 voltage was between 4350 and 4375 volts. As a result, the licensee had to re-perform the test which resulted in additional EDG inoperability and unavailability.

Description:

On September 29, 2014, operations personnel performed a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months test on the D2 EDG using Procedure SP 1335, D2 Diesel Generator 18 Month 24 Hour Load Test. The inspectors observed portions of the test and requested a copy of the completed procedure for review. While reviewing the documented test results two days later, the inspectors identified that operations personnel had not established a power factor of less than or equal to 0.85 or maintained Bus 16 voltage between 4350 and 4375 volts as directed by the procedure and as required by TS Surveillance Requirement 3.8.1.9. In addition, the operations departments review of the test results had not identified the failure to meet the above requirements. Based upon this information, the inspectors were concerned that the licensee had not properly completed the surveillance test.

The inspectors immediately discussed their concerns with operations personnel. The operators performed an independent review of the test results and agreed that the test had not been properly completed or reviewed. The licensee reviewed the results of previously performed 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months load tests on the Unit 1 and Unit 2 EDGs and determined that the Unit 2 EDGs had been tested satisfactorily. However, the power factor and/or bus voltage requirements had not been met when the Unit 1 EDGs were tested on May 12, 2013 (for the D1 EDG) and November 30, 2012 (for the D2 EDG). The licensee determined that the last satisfactory 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months load tests occurred on May 30, 2011 (for D1) and November 25, 2011 (for D2). The licensee immediately entered TS Surveillance Requirement 3.0.3 which allowed the D1 and D2 EDG 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months load tests to be considered missed surveillances. The licensee satisfactorily re-performed the 24-hour load tests on October 7, 2014 (for D1) and October 5, 2014 (for D2).

Analysis:

The inspectors determined that the failure to follow the procedural steps contained in SP 1334, D1 DG 18 Month 24 Hour Load Test, and SP 1335 regarding establishing and maintaining a power factor of less than or equal to 0.85 or a bus voltage between 3450 and 3475 volts was a performance deficiency requiring an evaluating using the SDP. The inspectors determined that this finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone and impacted the cornerstones objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operations personnel were required to declare the D1 and D2 EDGs inoperable and unavailable to perform their safety functions while the 24-hour load testing was re-performed due to the need to operate the EDGs in parallel with the electrical grid.

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. The inspectors determined that this finding was cross-cutting in the Human Performance, Avoid Complacency area because operations personnel failed to implement appropriate error reduction tools to ensure that the power factor requirements were met (H.12).

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 procedures of a type appropriate to the circumstance and be accomplished in accordance with these procedures. The licensee performed the 24-hour load test of the D1 and D2 EDGs (an activity affecting quality) using Procedures SP 1334 and SP 1335. Multiple steps throughout both procedures direct that the EDG kVAR loading be adjusted until a power factor of less than or equal to 0.85 is achieved or until bus voltage is between 4350 and 4375 volts, which ever condition is reached first. Contrary to the above, between November 30, 2012, and September 29, 2014, the licensee failed to establish a power factor of less than or equal to 0.85 or a bus voltage between 4350 and 4375 volts during 24-hour load tests on the Unit 1 EDGs.

Because this violation was of very low safety significance and was entered into the CAP as CAP 1449139, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2014005-03: Power Factor not met during Unit 1 EDG Surveillance Testing). Corrective actions for this issue included providing additional training on the need to maintain the power factor during testing, requiring all data collected by the operations department during TS surveillance testing to be independently verified, and requiring all TS surveillance requirement results to be reviewed and approved by two senior reactor operators.

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

.1 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspectors performed an in-office review of the latest revisions to the Emergency Plan and Emergency Plan Implementing Procedures as listed in the Attachment to this report.

The licensee transmitted the Emergency Plan and Emergency Action Level revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. The NRC review was not documented in a Safety Evaluation Report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection.

Documents reviewed are listed in the Attachment to this report.

This emergency action level and emergency plan change inspection constituted one sample as defined in IP 71114.04-06.

b. Findings

No findings were identified.

RADIATION SAFETY

2RS1 Radiological Hazard Assessment and Exposure Controls

Main article: IP 71124.01

This inspection constituted one complete radiological hazard assessment and exposure control sample as defined in IP 71124.01-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators (PIs) for the Occupational Exposure Cornerstone for follow-up. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors determined if there have been changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee assessed the potential impact of these changes and 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 were appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility, including radioactive waste processing, storage, and handling areas to evaluate material conditions and performed independent radiation measurements to verify conditions.

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

Filter Changes 1R29;

Reactor Vessel Disassembly/Reassembly 1R29;

Incore and Seal Table Work 1R29;

Work in Sump-C 1R29; and

10-Year ISI/Corrosion Inspection 1R29.

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

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:

RWP 141006; Filter Changes 1R29;

RWP 141200; Reactor Vessel Disassembly/Reassembly 1R29;

RWP 141401; Incore and Seal Table Work 1R29;

RWP 141402; Work in Sump-C 1R29; and

RWP 141502; 10 Year ISI/Corrosion Inspection 1R29.

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 (EPD) alarm set-points were in conformance with survey indications and plant policy.

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

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

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors 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 and 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.

The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was guidance on how to respond to an alarm that indicates the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters. The inspectors assessed whether or not the licensee has established a de facto release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high-radiation background area.

The inspectors selected several sealed sources from the licensees inventory records and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, RWPs, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of EPDs in high noise areas as high radiation area monitoring devices.

The inspectors assessed whether radiation monitoring devices were placed on the individuals body 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 application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

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

RWP 141006; Filter Changes 1R29;

RWP 141200; Reactor Vessel Disassembly / Reassembly 1R29;

RWP 141401; Incore and Seal Table Work 1R29;

RWP 141402; Work in Sump-C 1R29; and

RWP 141502; 10 Year ISI/Corrosion Inspection 1R29.

For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, and 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 (i.e., 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.

The inspectors examined the posting and physical controls for selected high radiation areas and very-high radiation areas to verify conformance with the occupational performance indicator.

b. Findings

No findings were identified.

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

The inspectors sampled licensee submittals for the Occupational Exposure Control Effectiveness performance indicator for the period from the third quarter 2013 through the third quarter 2014. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, 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 the indicator related data was adequately assessed and reported. The inspectors discussed with radiation protection staff the scope and breadth of its data review and the results of those reviews, to assess the adequacy of the licensees PI data collection and analyses,. The inspectors independently reviewed EPD dose rate and accumulated dose alarms and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very-high radiation area entrances to determine the adequacy of the controls in place for these areas. 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.

.6 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent Technical Specification (RETS)/Offsite Dose Calculation Manual (ODCM), Radiological Effluent Occurrences PI for the period from the third quarter 2013 through the third quarter 2014.

The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees CAP 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

This review constituted one 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 Snubber Performance Testing following

Unsatisfactory Visual Examinations

a. Inspection Scope

During the Unit 1 refueling outage, the licensee performed visual examinations on multiple snubbers to confirm that the snubbers were functional. As part of the daily corrective action document review, the inspectors noted multiple documents associated with deficiencies found during the snubber visual examinations. The inspectors discussed these CAPs with the licensees engineering staff. In addition, the inspectors compared the subsequent snubber performance test results to industry standards to determine whether each snubber would have been able to perform its function during the last Unit 1 operating cycle. The test results were also used to determine whether the snubbers were acceptable for re-installation.

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

b. Findings

No findings were identified.

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

Main article: IP 71153

.1 (Closed) Licensee Event Report 05000282/2014-001-00: D1/D2 Emergency Diesel

Generators Inoperable Due to Outside Air Temperature Greater than 97 Degrees

a. Inspection Scope

The inspectors reviewed the circumstances surrounding the identification that the D1 and D2 EDGs were inoperable multiple times over a three year period due to specific temperature transmitters and controllers not being qualified for continued operation at post-turbine building high energy line break (HELB) room temperatures. Documents reviewed are listed in the Attachment to this report. This licensee event report (LER) is closed.

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

b. Findings

During a review of two previously completed engineering changes, the licensee identified that the changes had not fully evaluated all components located in the D1 and D2 EDG rooms for continued operability/functionality following a HELB in the turbine building. The licensees turbine building HELB analyses showed that the D1 and D2 EDG room temperatures could reach 130 degrees Fahrenheit (0F) if the outside air temperature was greater than 1030F when the HELB occurred. However, a temperature transmitter and temperature controller located in each EDG room were only qualified for operation up to a room temperature of 1200F. Based upon this information, the licensee determined that the EDG room temperature following a HELB would exceed 1200F if the outside air temperature was greater than 970F when the HELB occurred.

The licensee reviewed the daily maximum outside air temperatures recorded over the previous 3 years and determined that the D1 and D2 EDGs would have been inoperable for 415 minutes in 2011, 520 minutes in 2012, and 43 minutes in 2013 due to the outside air temperature exceeding 970F.

The licensee conducted additional performance testing of the temperature transmitters and controllers to determine if they would remain functional when room temperature reached 1300F. The performance testing results showed that the temperature transmitters and controllers continued to operate at room temperatures of 1300F or less.

Therefore, the information contained in the licensees current HELB analysis was met and the EDGs remained operable.

On October 27, 2014, the licensee submitted a letter to the NRC requesting that the above LER be cancelled based upon the performance test results. The inspectors reviewed the licensees letter and the performance test results. Based upon the results of this review, the inspectors agreed with the licensees assessment and the D1 and D2 EDGs (including the temperature transmitters and controllers) remained capable of performing their functions following a HELB as long as the outside air temperature remained less than or equal to 1030F. Since none of the maximum outside air temperatures recorded over the last three years exceeded 1030F, no violations of NRC requirements occurred and this LER is closed.

.2 (Closed) Licensee Event Report 05000306/2014-001-00: Unanalyzed Condition Due to

Removal of Multiple Steam Generator Lateral Support Shims and Bumpers

a. Inspection Scope

The inspectors reviewed the circumstances which led to the removal of multiple steam generator lateral support shims and bumpers on December 31, 2013. The removal of these components resulted in the Unit 2 reactor coolant system being declared inoperable since the systems configuration had not been appropriately analyzed for continued operation. 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.

b. Findings

The enforcement aspects of this issue are discussed in Section 4OA7 of this inspection report.

.3 (Closed) Licensee Event Report 05000306/2014-001-01: Unanalyzed Condition Due to

Removal of Multiple Steam Generator Lateral Shims and Bumpers

a. Inspection Scope

The licensee provided supplemental information to the NRC on June 20, 2014, regarding the event reported in LER 05000306/2014-001-00. The inspectors reviewed this information as part of the inspection activities performed to close the LER discussed in Sections 4OA3.2 and 4OA7 of this report. Documents reviewed are listed in the to this report. This LER is closed.

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

b. Findings

The enforcement aspects of this issue are discussed in Section 4OA7 of this inspection report.

4OA5 Other Activities

.1 (Closed) Temporary Instruction 2515/189, Inspection to Determine Compliance of

Dynamic Restraint (Snubber) Program with 10 CFR 50.55a Regulatory Requirements for In-service Examination and Testing of Snubbers

a. Inspection Scope

The inspectors conducted an inspection of the Prairie Island snubber program in accordance with temporary instruction (TI) 2515/189 to verify that the program was in compliance with the requirements of Title 10 of the Code of Federal Regulations 50.55a, as discussed in Regulatory Information Summary (RIS) 2010-06, In-service Inspection and Testing of Dynamic Restraints (Snubbers). The inspectors reviewed Prairie Islands response to RIS 2010-06 and verified the actions taken were appropriate.

The inspectors selected a sample of sixteen snubbers based on risk-informed insights, performance history, plant conditions and accessibility. For the selected snubbers, the inspectors reviewed a portion of the most recent in-service visual examination records and functional test records during the current 10 year ISI interval and performed a walkdown of select snubbers for independent verification. The inspectors also observed in field visual examination of snubbers. The inspector verified that the personnel performing the visual examinations were qualified to perform the activity. The inspectors also observed three in-process bench tests of the selected snubbers and verified that the test parameters met the acceptance criteria specified in the Prairie Island test procedure. The inspectors reviewed the process for snubber service life monitoring at Prairie Island and determined that the selected snubbers were being monitored and maintained appropriately. The inspectors also reviewed a sample of corrective action documents identified during the examination and testing of snubbers to verify that issues were entered into the CAP and properly evaluated for resolution.

The licensees Snubber Inservice Examination and Testing Program was inspected in accordance with Section 03.02 of the TI and responses to specific questions found in 1 of TI 2515/189 were submitted to the NRC Headquarters staff and included as Attachment 2 to this inspection report.

This TI is closed.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 6, 2015, the inspectors presented the inspection results to Mr. K. Davison 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 TI 2515/189 with the Mr. S. Sharp, Director of Site Operations, on October 10, 2014.

The inspection results for the areas of inservice inspection with Mr. K. Davison, Site Vice-President, on October 29, 2014.

The inspection results for the areas of radiological hazard assessment and exposure controls; and RCS specific activity, occupational exposure control effectiveness, and RETS/ODCM radiological effluent occurrences performance indicator verification with Mr. S. Sharp, Director of Site Operations, on November 6, 2014.

The inspection results for the area of license operator annual examination results with Mr. T. Ouret, General Supervisor Operations Training, on November 14, 2014.

The inspection results for the annual review of Emergency Action Level and Emergency Plan Changes with Ms. N. Penman, Acting Emergency Preparedness Manager, via telephone on December 5, 2014.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) or Severity Level IV was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

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 circumstance and be accomplished in accordance with these instructions, procedures and drawings. Contrary to the above, on December 30, 2013, the licensee identified that plant personnel performed Unit 2 SG hot gap checks, an activity affecting quality, without having documented instructions, procedures and drawings appropriate to the circumstance. Specifically, the design drawings failed to include information indicating that only one set of steam generator upper lateral support shims and bumpers was to be removed at a time during the hot gap clearance checks. Due to this deficiency, the workers removed all of the steam generator shims and bumpers which resulted in making the Unit 2 RCS inoperable and placing the unit in an unanalyzed condition.

The inspectors determined that the licensees failure to have drawings appropriate to the circumstance for performing the hot gap clearance checks was a performance deficiency. The performance deficiency was evaluated in accordance with IMC 0612, Appendix B, Issue Screening. The inspectors determined that the performance deficiency did not involve a violation that impeded the regulatory process or contributed to actual safety consequences.

The inspectors determined that the finding was more than minor because it impacted the design control and configuration control attributes of the initiating events cornerstone. In addition, the finding impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Table 3-SDP APPENDIX ROUTER. The inspectors answered No to all the questions listed in Table 3; therefore, the risk evaluation continued with IMC 0609 Appendix A, The Significance Determination Process For Findings At-Power. Under the Initiating Events Cornerstone for Exhibit 1, the inspectors answered Yes to the question, After a reasonable assessment of degradation, could the finding result in exceeding the RCS leak rate for a small break LOCA? Therefore, the inspectors contacted the Region III Senior Reactor Analysts (SRAs) for a detailed risk evaluation.

The SRAs performed a detailed risk evaluation for the effect of the missing SG shims on Unit 2 with regard to the change in core damage frequency (CDF). The evaluation assumed certain initiating events (such as seismic events) would impart a significant load upon the steam generators causing their displacement, which in turn could lead to breaks in the reactor coolant primary piping or secondary system piping.

The SRAs reviewed the licensees risk evaluation for this issue as documented in:

PRA Document No. V.SPA.14.010, Unit 2 SG Shim SDP Calculation, Rev. 1;

PRA Document No. V.SPA.14.011, U2 SG Secondary Break Size Threshold, Rev. 1; and

PRA Document No. V.SPA.14.009, Unit 2 SG Shim SDP-MSLB and MFLB Initiating Event Frequency Development, Rev. 1.

Based on review of the above licensee documents and input from the inspectors, the SRAs determined that the following initiating events would result in a change in CDF:

Seismic Events;

Large Loss of Coolant Accident Events;

Main Steamline Breaks in Containment; and

Main Feedwater Line Breaks in Containment.

Other initiating events, such as steam generator tube ruptures and medium and small break LOCAs were determined not to result in a change in risk due to the missing shims. Following a steam generator tube rupture, imparted loads were small enough such that the connected primary and secondary piping were expected to remain intact and functional. Similarly, following medium and small break LOCAs the steam generators, secondary piping, and the unaffected primary loop were expected to remain intact and functional.

According to the licensees Unit 2 SG Shim SDP Calculation referenced above, the duration when all shims on each SG were removed to the time when all of the shims were re-installed was about 20.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . The calculation did not state the time when the first shim was removed; therefore, the SRAs doubled this exposure time and assumed 41 hour4.74537e-4 days 0.0114 hours 6.779101e-5 weeks 1.56005e-5 months duration for the exposure time for this finding, which was a conservative assumption. Also, the SRAs conservatively assumed that the initiating events subject to this analysis proceed directly to core damage without credit for mitigation or recovery (i.e., conditional core damage probability (CCDP) is 1.0).

Seismic Events The licensee screened out seismic events of magnitude greater than the design basis earthquake of level 0.12g for contributing to a change in CDF. Their analysis showed the primary and secondary side piping would remain intact and functional during seismic events less than 0.12g. The inspectors and SRAs accepted this assumption. The Risk Assessment of Operational Events Handbook listed the frequency of 0.08g and greater seismic events, and 0.15g and greater seismic events, as 1.907E-04/yr and 7.272E-05/yr respectively.

Interpolating these values on a logarithmic scale resulted in a frequency occurrence for seismic events greater than 0.12g to be 1.024E-04/yr. Assuming a conditional core damage probability of 1.0, the seismic contribution to the risk increase was taken to be frequency of the seismic event during the exposure time or 4.79E-07/yr as calculated below:

CDFseismic = [1.024E-04/yr] * [41/8760] = 4.79E-07/yr.

Large Loss of Coolant Accidents The SRAs used the Prairie Island Standardized Plant Analysis Risk (SPAR)

Model Version 8.19 to obtain the frequency of a large loss of coolant accident (LLOCA). The SPAR model lists the frequency of LLOCAs as 2.50E-06/yr.

Assuming a conditional core damage probability of 1.0, the LLOCA contribution to the risk increase was taken to be frequency of the LLOCA during the exposure time or 1.17E-08/yr as calculated below:

CDFlloca = [2.50E-06/yr] * [41/8760] = 1.17E-08/yr.

Main Steamline Breaks in Containment For main steamline (MSL) breaks in containment, the licensee performed an evaluation that determined that only pipe breaks of certain sections of 5.5-inch diameter pipe and larger could result in loadings large enough to impact the change in CDF. The inspectors and SRAs accepted this assumption. The licensee calculated a MSL break initiating event frequency for 4-inch equivalent diameter piping for this analysis using EPRI Report 3002000079, Pipe Rupture Frequencies for Internal Flooding Probabilistic Risk Assessments (PRAs),

Revision 3, and other plant documents and drawings. The licensee calculated a MSL break frequency of 4.45E-05/yr. Assuming a conditional core damage probability of 1.0, the MSL break contribution to the risk increase was taken to be frequency of the MSL break during the exposure time, or 2.08E-07/yr:

CDFMSLB = [4.45E-05/yr] * [41/8760] = 2.08E-07/yr.

Main Feedwater Line Breaks in Containment For main feedwater line (MFL) breaks in containment, the licensee performed an evaluation that determined that only pipe breaks of certain sections of 5.5-inch diameter pipe and larger could result in loadings large enough to impact the change in CDF. The inspectors and SRAs accepted this assumption. The licensee calculated a MFL break initiating event frequency for 4-inch equivalent diameter piping for this analysis using EPRI Report 3002000079 and other plant documents and drawings. The licensee calculated a MFL break frequency of 3.53E-06/yr. Assuming a conditional core damage probability of 1.0, the MFL break contribution to the risk increase was taken to be frequency of the MFL break during the exposure time, or 1.65E-08/yr:

CDFMFLB = [3.53E-06/yr] * [41/8760] = 1.65E-08/yr.

Results The total change in CDF (i.e., CDF) represents the sum of the individual CDF values above, or 7.16E-07/yr. In regards to Large Early Release Frequency (LERF), IMC 0609 Appendix H, Containment Integrity Significance Determination Process, was used to determine the potential risk contribution due to LERF. Prairie Island is a two loop Westinghouse pressurized water reactor with a large dry containment. Sequences important to LERF include steam generator tube rupture events and inter-system LOCA events. These were not the dominant core damage sequences for this finding. Therefore, the risk significance due to the change in CDF and LERF was determined to be of very low safety significance (GREEN).

The licensee documented this issue in the corrective action program as CAP 1412886. Corrective actions included re-installing the shims and bumpers, performing additional hot gap adjustments, and revising the upper lateral support drawings to specifically state that only one shim and bumper package can be removed at a time.

ATTACHMENTS:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Davison, Site Vice President

S. Sharp, Director Site Operations

J. Hallenbeck, Engineering Director

C. Younie, Plant Manager

G. Johnson, Senior Manager Site Engineering

T. Allen, Assistant Plant Manager

J. Anderson, Regulatory Affairs Manager

J. Boesch, Production Planning Manager

T. Borgen, Training Manager

B. Boyer, Radiation Protection Manager

H. Butterworth, Nuclear Oversight Manager

F. Calia, Business Support Manager

C. Childress, Maintenance Manager

J. Corwin, Security Manager

D. Gauger, Chemistry/Environmental Manager

S. Martin, Performance Assessment Manager

B. Meek, Safety and Human Performance Manager

N. Penman, Acting Emergency Preparedness Manager

J. Ruttar, Operations Manager

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

S. Wall, Project Manager, Office of Nuclear Reactor Regulation

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened

05000282/2014005-01; NCV Failure to Implement the Winter Plant Operation

05000306/2014005-01 Procedure (Section 1R01)

05000282/2014005-02 NCV Unqualified Reactor Vessel Examination Procedures (Section 1R08)

05000282/2014005-03 NCV Failure to Follow Procedures during EDG 24 Hour Load Test (Section 1R22)

Closed

05000282/2014005-01; NCV Failure to Implement the Winter Plant Operation

05000306/2014005-01 Procedure (Section 1R01)

05000282/2014005-02 NCV Unqualified Reactor Vessel Examination Procedures (Section 1R08)

05000282/2014005-03 NCV Failure to Follow Procedures during EDG 24 Hour Load Test (Section 1R22)

05000282/2014-001-00 LER D1/D2 Emergency Diesel Generators Inoperable due to Outside Air Temperature Greater than 97 Degrees

05000306/2014-001-00 LER Unanalyzed Condition due to Removal of Multiple Steam Generator Lateral Support Shims and Bumpers

05000306/2014-001-01 LER Unanalyzed Condition due to Removal of Multiple Steam Generator Lateral Support Shims and Bumpers 2515/189 TI Inspection to Determine Compliance of Dynamic Restraint (Snubber) Program with 10 CFR 50.55a Regulatory Requirements for In-service Examination and Testing of Snubbers

LIST OF DOCUMENTS REVIEWED

IR 05000282/2014005

Text

SUBJECT:

Dear Mr. Davison:

Enclosure:

SUMMARY OF FINDINGS

Cornerstone: Initiating Events

Cornerstone: Mitigating Systems

Licensee Identified Violations

REPORT DETAILS

Summary of Plant Status

REACTOR SAFETY

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

b. Findings

Introduction:

Description:

Analysis:

Enforcement:

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

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

b. Findings

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

b. Findings

1R08 Inservice Inspection Activities

.1 Piping Systems Inservice Inspection

a. Inspection Scope

b. Findings

Introduction:

Description:

Analysis:

Enforcement:

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

b. Findings

.3 Boric Acid Corrosion Control

a. Inspection Scope

b. Findings

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

b. Findings

.5 Identification and Resolution of Problems

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 During Periods of Heightened Activity or Risk

a. Inspection Scope

b. Findings

.3 Annual Operating Test Results

a. Inspection Scope

b. Findings

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

b. Findings

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