IR 05000266/2013003

IR 05000266-13-003, 05000301-13-003; 04/01/2013 - 06/30/2013: Point Beach Nuclear Plant, Units 1 and 2; Adverse Weather Protection; Flooding; Inservice Inspection; Maintenance Risk Assessment and Emergent Work Control; and, Surveillance Tes

ML13225A242
Person / Time
Site:	Point Beach
Issue date:	08/13/2013
From:	Patricia Pelke NRC/RGN-III/DRP/B6
To:	Meyer L Point Beach
References
IR-13-003
Download: ML13225A242 (82)

Text

August 13, 2013

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000266/2013003 AND 05000301/2013003

Dear Mr. Meyer:

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

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

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

Based on the results of the integrated inspection five NRC-identified findings and one self-revealed finding of very low safety significance (Green) were identified during this inspection. Five of these findings involved violations of NRC requirements. Also, two licensee-identified violations, which were determined to be of very low safety significance, are included in Section 4OA7 of this report. The NRC is treating these violations as non-cited violations (NCVs), consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Point Beach Nuclear Plant. If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III; and the NRC Resident Inspector at Point Beach Nuclear Plant.

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

component of NRC's Agencywide Document 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/

Patricia J. Pelke, Acting Chief Branch 6 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report 05000266/2013003; 05000301/2013003; w/Attachment: Supplemental Information

REGION III==

Docket Nos:

05000266; 05000301 License Nos:

DPR-24; DPR-27 Report No:

05000266/2013003; 05000301/2013003 Licensee:

NextEra Energy Point Beach, LLC Facility:

Point Beach Nuclear Plant, Units 1 and 2 Location:

Two Rivers, WI Dates:

April 1, 2013 through June 30, 2013 Inspectors:

S. Burton, Senior Resident Inspector

D. Betancourt, Acting Senior Resident Inspector

M. Thorpe-Kavanaugh, Resident Inspector

M. Holmberg, Reactor Inspector

J. Gilliam, Reactor Engineer

V. Myers, Health Physicist

J. Beavers, Emergency Preparedness Inspector

J. Laughlin, Emergency Preparedness Inspector, NSIR

E. Sanchez Santiago, Reactor Inspector

J. Steffes, Reactor Engineer

K. Barclay, Kewaunee Resident Inspector

Approved by:

Patricia J. Pelke, Acting Chief

Branch 6

Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000266/2013003, 05000301/2013003; 04/01/2013 - 06/30/2013:

Point Beach Nuclear Plant, Units 1 and 2; Adverse Weather Protection; Flooding; Inservice Inspection; Maintenance Risk Assessment and Emergent Work Control; and, Surveillance Testing.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Five findings were identified by the inspectors, and one finding was self-revealed. Five of these findings were considered non-cited violations (NCVs) of NRC regulations. The significance of inspection findings are indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process dated June 2, 2011.

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

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low safety significance for the licensees failure to maintain control over the proper storage and placement of materials that were classified as high winds/tornado hazards, in accordance with procedure NP 1.9.6, Plant Cleanliness and Storage. Specifically, the inspectors identified that the licensee failed to perform weekly high wind missile hazards inspections since April 17, 2013. As a result, unsecured wooden pallets, wooden planks, metal rods and a metallic desk were discovered by the inspectors near Units 1 and 2 transformer areas.

The issue was entered into the licensees corrective action program (CAP) for resolution as action request AR01882921. The licensee took immediate corrective action to remove and/or properly store the material after the tornado warning on June 17, 2013.

The inspectors determined the finding to be more than minor in accordance with IMC 0612, Appendix B, because if left uncorrected, the unsecured items would have the potential to lead to a more significant safety concern during high wind and tornado events. The inspectors determined the finding to be of very low safety significance because the inspectors answered No to each question listed in IMC 0609, Appendix A,

Exhibit 1, Initiating Event Screening Questions. The inspectors determined that the finding has a cross-cutting aspect in the area of human performance, work practices, because the licensee did not provide supervisory or management oversight of work activities such that nuclear safety was supported. Specifically, the licensee failed to provide appropriate oversight of work activities such that, when the program owner of the weekly high wind inspection changed, the requirement to perform weekly high winds tornado hazard walkdowns was not understood (H.4(c)). (Section 1R01.3)

Green.

The inspectors identified a finding of very low safety significance and an associated non-cited violation of 10 CFR 50, Appendix B, Criterion V for the licensees failure to follow procedure EN-AA-203-1001, Operability Determinations/Functionality Assessments. Specifically, following water leakage into the control room, the licensees immediate operability determination failed to evaluate the effect the leakage had on the control room envelope operability. Additionally, the licensee did not address the functionality of the degraded flood barrier and its impact on operability. This issue was entered into the CAP as AR01877185. Corrective actions for this issue included performing a test of the control room envelope to demonstrate that appropriate positive pressure could be maintained with the known degraded barrier, and repair of the degraded flood barrier following performance of a functionality assessment.

The inspectors determined the finding to be more than minor in accordance with IMC 0612, Appendix B, because it was associated with the Protection Against External Factors attribute of the Initiating Event Cornerstone, and adversely affected the Cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. The inspectors determined the finding to be of very low safety significance in accordance with IMC 0609,

Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Exhibit 1, because they answered No to the questions under Transient Initiators and External Event Initiators. The inspectors concluded that this finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because the licensee failed to thoroughly evaluate this problem such that the resolution addressed the cause and evaluated the condition for operability (P.1(c)).

(Section 1R06)

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion V, for failure to select an appropriately contoured ultrasonic examination search unit wedge in accordance with procedure NDE-173, PDI Generic Procedure for the Ultrasonic Examination of Austenitic Piping Welds. Consequently, three elbow-to-pipe socket welds on the chemical and volume control system (CVCS) line were examined with the incorrectly contoured search unit and this examination would not provide a demonstrated level of accuracy necessary to reliably detect and size thermal fatigue cracks. The licensee entered this condition into the CAP as AR 01860155. To restore compliance with NRC regulations, the licensee considered the option of repeating these weld examinations using a qualified ultrasonic examination technique or the option to seek NRC approval to deviate from the American Society of Mechanical Engineers (ASME) Code Section XI requirements for ultrasonic examination.

The inspectors determined the finding to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, issued September 7, 2012, because the inspectors answered Yes to the more-than-minor screening question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, the examination of three chemical and volume control system welds was presumed adequate and absent NRC intervention, would have been returned to service for an indefinite period of service, which would have placed the piping at increased risk for undetected thermal fatigue cracking, leakage, or component failure. In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Initiating Events Cornerstone because leakage at this chemical and volume control system letdown line could result in a primary system loss of coolant accident. The inspectors determined this finding was of very low safety significance based on answering No to the questions in Part A of Exhibit 1, Initiating Events Screening Questions, in IMC 0609, Attachment A, The Significance Determination Process (SDP) for Findings At-Power, issued on June 19, 2012. The inspectors answered these questions No because of the small diameter (2-inch) of the line and because the affected pipe welds were subjected to a VT-2 visual and penetrant testing (PT) examination that did not identify rejectable defects. The primary cause of the failure to select ultrasonic equipment (search unit contour) in accordance with procedure NDE-173 was related to the cross-cutting component of human performance, work practices, because the licensees management staff did not adequately set up clear expectations for procedure control and adherence for this activity. Specifically, insufficient direction was provided to vendor staff for simultaneous use of two procedures, NDE-178 and NDE-173, with different equipment requirements and restrictions (H.4(b)). (Section 1R08.b(2))

Cornerstone: Mitigating Systems

Green.

A self-revealed finding of very low safety significance and an associated non-cited violation of 10 CFR 50.65(a)(4) occurred on April 29, 2013, as a result of the licensees failure to properly manage and assess risk during a scheduled maintenance outage for emergency diesel generator G-04. Specifically, not all ongoing maintenance activities had been taken into account in the risk assessment for the in-progress maintenance activities and an unplanned entry into yellow risk occurred when they isolated bus D-40. The licensee entered this issue into the CAP as action request AR01870208. Corrective actions for this issue included restoring bus D-40 to service and initiating an evaluation of the issue through the condition reporting process.

The inspectors determined the finding to be more than minor because it was similar to Example 7.e of IMC 0612, Appendix E, Example of Minor Issues, dated August 11, 2009, and because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone. The finding also affected the Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, and Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The inspectors determined that the finding was a mitigating systems contributor; evaluated the risk deficit for each instance; and found that the issue screened as having very low safety significance. The inspectors determined that the finding has a cross-cutting aspect in the area of human performance, work control, because the licensee failed to appropriately plan and coordinate work activities. Specifically, when the licensee attempted to remove bus D-40 isolation work from the work schedule, the work package was not updated to reflect the change; and there was a failure to communicate and/or coordinate the changes in the work scope to the appropriate groups (H.3(b)).

(Section 1R13)

Green.

The inspectors identified a finding of very low safety significance and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V for the licensees failure to follow procedure FP-PE-90-01, Preventive Maintenance Program.

Specifically, in 2009, when setting the preventive maintenance frequency for containment isolation valve 1MS-02083, the licensee determined that a 15-year frequency was appropriate instead of the recommended 10 years. The licensees justification was based on internal maintenance history showing good performance.

However, the inspectors review revealed that the maintenance history for this category of valves did not support this determination. The valve subsequently failed during surveillance on March 21, 2013, after 13 years of service. The licensee entered this issue into the CAP as AR01858451; corrective actions included replacing the valve and an action to review the preventive maintenance frequencies of critical solenoid-operated valves.

The inspectors determined that the finding was more than minor in accordance with IMC 0612, Appendix B, because it was associated with the Barrier Performance attribute of the Barrier Integrity Cornerstone, and adversely affected the Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated this finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Checklist 3, and determined that the finding was of very low safety significance because the inspectors determined that a quantitative assessment was not required. The inspectors did not identify a cross-cutting aspect associated with this finding because the finding did not reflect current performance due to the age of the performance deficiency. (Section 1R22)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a non-cited violation of 10 CFR 50.55a(g)(4), for failure to define acceptance criteria for containment visual examinations. Consequently, active containment liner degradation (pitting) was identified and the liner returned to service without defined criteria for accepting this condition. The licensee entered this issue into the CAP as action requests AR01858862 and AR01861158, and developed visual examination acceptance criteria to restore compliance with this NRC regulation.

The inspectors determined the finding to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening dated September 7, 2012, because it adversely affected the Barrier Integrity Cornerstone attribute of maintaining the functional integrity of containment. The inspectors also answered Yes to the more-than-minor screening question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, the lack of acceptance criteria in site procedures for containment visual examinations would become a more significant safety concern in that active liner degradation may not be properly evaluated and/or promptly corrected, resulting in a containment liner breach.

In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Barrier Integrity Cornerstone because the corrosion induced pitting degraded the containment barrier. The inspectors determined this finding was of very low safety significance based on answering No to the Exhibit 3, Barrier Integrity Screening Questions, in IMC 0609,

Attachment A, The Significance Determination Process (SDP) for Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered No to the screening question associated with an actual open pathway (e.g., breach) in the containment and No to the question associated with reduction in function of hydrogen igniters in containment. The inspectors determined that the primary cause of the failure to define containment visual examination acceptance criteria was related to the cross-cutting component of human performance, decision making, because licensee staff did not apply a systematic process, when faced with unexpected plant conditions, to ensure safety was maintained. Specifically, a systematic process for developing acceptance criteria was not applied for the containment visual examinations (H.1(a)). (Section 1R08.b(1))

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit began the inspection period shut down for refueling outage 34. The unit was re-started on April 17, 2013, and reached full power on April 22, 2013. The unit operated at or near full power for the remainder of the quarter, with the exception of a downpower to 50 percent on April 25, 2013, due to an oil leak repair to main feed pump 1P-28A.

Unit 2 The unit operated at or near full power throughout the quarter. A downpower to 48 percent occurred on May 20, 2013 for a biannual main turbine and governor valves turbine trip test.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate Alternating Current Power Systems

a. Inspection Scope

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

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

• the explanations for the events;

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

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

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

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

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

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

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

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

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

b. Findings

No findings were identified.

.2 Summer Seasonal Readiness Preparations

a. Inspection Scope

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

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

Additionally, the inspectors reviewed the Final Safety Analysis Report (FSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed CAP items to verify that the licensee had identified adverse weather issues at an appropriate threshold and entered them into their corrective action program in accordance with station corrective action procedures. The inspectors reviews focused specifically on the service water and component cooling water systems.

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

b. Findings

No findings were identified.

.3 Readiness for Impending Adverse Weather Condition - Tornado/Severe Thunderstorm

Watch

a. Inspection Scope

Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for June 17, 2013, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. The inspectors reviewed the actions taken by the licensee in response to the adverse weather condition while the associated meteorological tower was out-of-service (OOS). The inspectors reviewed the potential impact of the adverse weather conditions on safety-related equipment, in addition to the licensees emergency AC power systems. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the FSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of CAP items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

Failure to Control Materials Classified as High Winds/Tornado Hazards

Introduction:

The inspectors identified a finding of very low safety significance (Green)due to the licensees failure to maintain control over the placement and storage of materials classified as high winds/tornado hazards in the Units 1 and 2 transformer areas, in accordance with station procedures.

Description:

On June 17, 2013, a tornado warning was issued for Manitowoc County.

After the severe weather threat had been lifted for the site, the inspectors conducted a walkdown to evaluate the licensees preparedness for impending adverse weather conditions. During this walkdown, the inspectors identified several unsecured wooden pallets protruding from an open bin including two 4-by-4-inch wooden boards measuring approximately 11/2 to 2 feet in length; a 1/2-inch diameter section of pipe 2 feet long, laying in the bed of a truck; and an unsecured metal desk near the Units 1 and 2 345 kV [kilovolt] station transformer areas.

The inspectors reviewed the walkdown requirements in procedure NP 1.9.6, Plant Cleanliness and Storage, and noted the following:

• Section 4.10.1 stated that, Unsecured objects that can be picked up by 73 to 135 mph [miles per hour] winds and thrown against equipment with enough force to disable are considered missile hazards;

• Section 4.10.4(b) identified examples of common high wind missile hazards including, but not limited to, loose boards, overflowing dumpster materials, and unsecured parts;

• Section 4.10.3 stated that, All other outside areas within the Owner Controlled Area shall be free of high wind missile hazards, and specifically identified the Units 1 and 2 transformer areas as areas for concern; and

• Section 4.10.6 required weekly inspections for high wind missile hazards be performed by the facilities supervisor.

Based on this information, the inspectors were concerned that the unsecured materials could be picked up with high velocity winds, become missile hazards and impact the Units 1 and 2 transformers. The materials, together with the high winds, increased the potential to cause an unplanned turbine trip and reactor trip.

After the inspectors identified the unsecured materials to the work control center, all of the materials were promptly removed or secured in accordance with station procedures.

The licensee entered the issue into the CAP as action request (AR)01882921.

The inspectors requested prior weekly inspection reports to review which areas the licensee had been walked down, and what had been identified as hazards during those inspections. Through this review, the inspectors learned that the licensee had not performed any weekly high wind missile hazards inspections since April 17, 2013. The licensee entered the issue into the CAP as AR01883436 to document this deficiency; and explained that the previous program owner had transferred to a new work group.

The replacement program owner did not understand the requirement to perform weekly high wind missile hazard inspections; therefore, the inspections were not done.

Analysis:

The inspectors determined that the licensees failure to maintain control over the placement and storage of materials classified as high winds/tornado hazards in the Units 1 and 2 transformer areas was contrary to procedure NP 1.9.6 and was a performance deficiency warranting further review.

The inspectors determined that the finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the loose materials could become missile hazards during periods of high winds or tornado events, and cause a loss of offsite power or an unplanned reactor/turbine trip. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, 0609.04, Initial Characterization of Findings, dated June 19, 2012, Table 2, and checked Item B, transient initiator contributor, under the Initiating Events Cornerstone column. The inspectors then answered No to all questions in Table 3.

The finding was further evaluated using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, and answered No to all the questions listed in Exhibit 1. Therefore, the inspectors concluded the finding to be of very low safety significance (Green).

The inspectors determined that the finding had a cross-cutting aspect in the area of human performance, work practices, because the licensee failed to ensure supervisory and management oversight of work activities such that nuclear safety is supported (H.4(c)). Specifically, the licensee failed to provide appropriate oversight such that, when the program owner of the weekly high wind inspection changed, the requirement to perform weekly high winds tornado hazard walkdowns was not understood.

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as a Finding (FIN)

(FIN 05000266/2013003-01; 05000301/2013003-01, Failure to Control Materials Classified as High Winds/Tornado Hazards).

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• turbine-driven auxiliary feedwater (AFW) pump 2P-29 (Unit 2);

• emergency diesel generator (EDG) G-01 alignment post-testing (Units 1 and 2);

• component cooling water (CCW) post-maintenance testing (PMT) (Unit 1); and

• safety injection train A with train B OOS for testing (Unit 1).

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• fire zone 138 (auxiliary building 8-foot elevation);

• fire zone 770 EDG G-03);

• fire zone 305 (4160 vital switchgear room);

• fire zone 228 (D105 battery room); and

• fire zone 162 (Pipeway #4 valve gallery).

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

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

b. Findings

No findings were identified.

1R06 Flooding

.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 FSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the to this report. 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 walkdown of the following plant areas to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• AFW pump room; and

• control room.

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

b. Findings

Failure to Follow Operability Evaluation Process Following Water Leakage into the Control Room

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, due to the licensees failure to follow procedure EN-AA-203-1001, Operability Determinations/Functionality Assessments. Specifically, following water leakage into the control room, the licensees immediate operability determination failed to evaluate the effect the leakage had on the control room envelope (CRE) operability. Additionally, the licensee did not address the functionality of the degraded flood barrier and its impact on operability. After prompting by the inspectors, the licensee revised the immediate operability determination to ensure that all safety-related equipment was properly evaluated for continued operability.

Description:

During routine CR reviews, the inspectors noted that on May 16, 2013, operations personnel initiated AR01875134 to document unexpected water leaking into the control room. The action request stated that water had dripped into the control room from the ceiling and found its way into Static Transfer Switch 43-Y01 and instrument bus panel 2Y-01. The source of the water was the draining of hoses after system restoration of an FP system that had undergone system flushing earlier during the same day.

Following identification of the condition by an operator, the licensee proceeded to stop the leakage, and contacted maintenance to inspect the panels to assess any potential damage. No adverse impact was identified. The licensee then determined that the Unit 2 red instrument bus 2Y-01 was operable because water had stopped entering the control room, and there was no damage identified. However, neither the operator logs nor the action request addressed the impact the leakage path had on the CREs ability to perform its safety function.

On May 22, 2012, the inspectors reviewed the information and contacted operations personnel to address the potential operability concerns regarding the CRE status. The inspectors were notified that the CRE is tested monthly to ensure that the envelope is intact; the CRE tested satisfactorily during the last performance, which occurred on April 30, 2013. Therefore, the licensee considered the CRE operable, since it had passed its last surveillance test. The inspectors expressed that, since the time of the degradation was not known, there might still be an impact on the CRE being capable of the required positive pressure for the control room. Additionally, the inspectors reviewed the FSAR, TSs, and TS bases. During the review the inspectors found information in FSAR Appendix A.7, Table A.7.1, which stated that the control room was a leak-tight structure: Floor waterproofing protects from CR HVAC [Control Room Heat and Ventilation] Room Flooding Sources.

Based upon the results of this review, the inspectors concluded that additional information was needed to address the capability of the CRE to perform its function, and that the licensee should evaluate the impact of the degraded flood barrier. The inspectors provided the results of their review to licensee management. The licensee then requested that an operability determination be performed and initiated AR01877719 and AR01877185 to document the inspectors concerns.

On May 24, 2013, the licensee performed a test of the CRE to demonstrate that appropriate positive pressure could be maintained with the known degraded barrier. The results of the test were satisfactory. The licensee then re-classified the operability determination to a functionality assessment of the degraded flood barrier. The barrier was determined to be nonfunctional in accordance with procedure NP 8.4.17, Flooding Barrier Control, and an hourly flood watch was instituted until the condition was repaired.

Corrective actions for this issue included performing a test of the CRE to demonstrate that appropriate positive pressure could be maintained with the known degraded barrier; performing a functionality assessment of the degraded flood barrier; and an action to develop a monitoring plan for operability screening of CRs.

Analysis:

The inspectors determined that the licensees failure to evaluate the effect of water leakage on CRE operability, as well as the failure to address the functionality of the degraded flood barrier and its impact on CRE operability, was a performance deficiency warranting further review.

The inspectors determined that this finding was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Protection Against External Factors attribute of the Initiating Event Cornerstone, and adversely affected the Cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and determined that IMC 0609, Appendix A, Exhibit 1, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, could be used to assess the significance. The finding was determined to be of very low safety significance (Green), because the inspectors answered No to the questions under Transient Initiators and External Event Initiators.

The inspectors determined that the finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because the licensee failed to thoroughly evaluate this problem such that the resolution addressed the cause and evaluated the condition for operability. Specifically, the licensee failed to recognize that although there was no longer an active leak, a degraded flood barrier could adversely affect CRE operability (P.1(c)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality be prescribed and accomplished by procedures appropriate to the circumstance, and shall be accomplished in accordance with those instructions and procedures. The licensee implemented the operability determination process (an activity affecting quality) using procedure EN-AA-203-1001, Operability Determination/Functionality Assessments, Revision 9:

Step 1.C, of Attachment 1, stated in part to document the basis for the declaration of operable or inoperable. This should include sufficient detail such that another Senior Reactor Operator or technically knowledgeable individual can understand the basis for the declaration.

Step 2.0.2, stated in part that, Functionality Assessments should be performed for SSCs [structures, systems, and components] not described in TS, but which are safety related or quality related and perform specified Current Licensing Basis functions described in the FSAR.

Contrary to the above, from May 16 to May 24, 2013, licensee personnel performed an operability determination on AR01875134, which was insufficient to address the capability of the CRE to perform its safety function. Specifically, the operability determination failed to address the ability to develop the required positive pressure for the control room. Additionally, the licensee failed to perform a functionality assessment of a flood barrier to perform its specified function as described in the FSAR. Because this violation was of very low safety significance, and it was entered into the licensees CAP as AR01877719 and AR01877185, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000266/2013003-02, 05000301/2013003-02; Failure to Follow Operability Evaluation Process Following Water Leakage into the Control Room).

1R08 Inservice Inspection Activities

From March 18 through April 16, 2013, 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; and risk significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, IR08.3, 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 and reviewed records of the following non-destructive examinations (NDE) mandated by the ASME Section XI Code 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 (UT) examination of ASME Code Class 2, risk informed (R-A),pipe-to-elbow welds, CVC-02-LD-1001-21, 29, and 30;

• PT examination of ASME Code Class 2, risk informed (R-A), pipe-to-elbow welds, CVC-02-LD-1001-21, 29, and 30;

• visual VT-2 examination of ASME Code Class 2, risk informed (R-A),pipe-to-elbow welds, CVC-02-LD-1001-21, 29, and 30; and

• visual VT-3 examination of chemical and volume control system (CVCS)support 39-14-PR.

The inspectors observed the following nondestructive examinations (NDE) conducted as part of the licensees industry initiative inspection programs for managing vessel internals cracking to determine whether the examinations were conducted in accordance with the licensees Augmented Inspection Program, industry guidance documents and associated licensee examination procedures, and if any indications and defects were detected, to determine whether these were dispositioned in accordance with approved procedures and NRC requirements:

• in-vessel UT examination of baffle bolts to meet industry standards MRP-228, Materials Reliability Program; Inspection Standard for PWR Internals, and MRP-227, Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines; and

• in-vessel remote underwater visual EVT-1 examination of circumferential core barrel welds No. 1 and 3 utilizing a remote camera and a fiberscope to meet industry standards MRP-228, Materials Reliability Program; Inspection Standard for PWR Internals and MRP-227 Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines.

During nondestructive surface and volumetric examinations performed since the previous refueling outage, the licensee had not identified any recordable indications.

Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors reviewed NDE records associated with the following pressure boundary welds completed for risk significant systems since the beginning of the last refueling outage to determine whether the licensee applied the pre-service NDE and acceptance criteria required by the Construction Code and ASME Code Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine whether the weld procedure was qualified in accordance with the requirements of Construction Code and the ASME Code Section IX:

• welds SW-1, -2, -3 and -4 associated with replacement of valve 1RC-00501C (WO 00395287); and

• welds SW-2 and -3 associated with replacement of valve SW-140 (WO 40120092).

b. Findings

(1) Lack of Acceptance Criteria for Containment Visual Examinations

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR 50.55a(g)(4), for failure to define acceptance criteria for containment visual examinations. Consequently, active containment liner degradation (pitting) was identified and returned to service without defined criteria for accepting this condition.

Description:

On March 21, 2013, the inspectors identified that the licensee failed to define acceptance criteria and incorporate these into the site procedure for containment visual examinations. The inspectors were concerned that without acceptance standards, unacceptable containment degradation may be returned to service and adversely affect containment leakage integrity.

A visual examination is performed in accordance with Article IWE of Section XI of the ASME Code to uncover any degradation that could affect the containment structural integrity or leak tightness. The licensee conducted visual examinations of both the Units 1 and 2 containments in accordance with procedure NDE-760 VT-1 and VT-3, Visual Examination of IWE Boundary Components (Metal Containment and Metallic Liners of Concrete Containment). The inspectors identified that this procedure and the associated program procedure, IWE Containment Inspection Program Second Interval, did not contain acceptance criteria for the general and detailed visual examinations as required by Article IWE-3000, Acceptance Standards, of Section XI of the ASME Code.

The inspectors reviewed the previous Unit 1 containment visual examination records completed in October 2011, to determine whether the lack of acceptance criteria had adversely affected containment integrity. The inspectors identified multiple visual examination reports (e.g., reports 2011VT-472, -633, -697 and -760) with service-related degradation recorded such as rust, pitting or flaking/peeling coatings that were returned to service without defined acceptance criteria. In reports 2011VT-671, -672, and -676, the licensee identified minor pitting and corrosion of the liner at the bottom of core bores in the concrete base matt area of containment, but had not included pictures with the examination reports. Consequently, active containment liner degradation (pitting) was identified and returned to service without defined criteria for accepting this condition.

Without a means (e.g., pictures or direct measurements) to compare with prior inspection results, the licensee could not accurately monitor the progress of corrosion-induced pitting of the liner in these areas. The inspectors did not have an immediate operability concern for the Unit 1 containment, based upon the documented minor nature of the corrosion and pitting and the application of UT to confirm the liner thickness at these locations. However, the type of UT applied would not be effective at monitoring the progress (e.g., depth) of pitting if the diameter of the corrosion pits remained small with respect to pit depth.

The licensee documented this issue in the CAP as AR01858862 and AR01861158. At the conclusion of the inspection, the licensees corrective actions under consideration included: coating the pitted liner areas to stop further corrosion, and development of acceptance criteria for the containment visual examinations. The inspectors also identified inconsistencies in recording relevant conditions documented in the visual examination reports, which could inhibit proper evaluation of containment degradation.

For example:

• in reports 2011VT-473 and -633, the licensee recorded rust as a relevant indication, and in reports 2011VT-671, -672 and -676, the licensee recorded pitting and corrosion as a non-recordable condition. For these reports, the licensee did not measure or evaluate the depth of the pitting/corrosion identified;

• in report 2011VT-668, the licensee recorded light surface rust as a non-relevant condition; and in report 2011VT-604, the licensee recorded light surface corrosion as a non-applicable condition;

• in reports 2011VT-472 and -663, the licensee recorded flaking paint as a relevant indication; and in examination report 2011VT-528, the licensee recorded a large area of paint flaked off as a non-applicable condition;

• in report 2011VT-682, the licensee documented the examination of the moisture barrier seal for the concrete interface at the 8-foot elevation in containment and had checked the conditions of tears and surface cracks as not applicable; and

• in report 2011VT-699 the licensee-identified gouges and damage to threads for the containment equipment hatch nuts and replaced these nuts, but did not identify this as a recordable/rejectable condition on the examination report.

The licensee entered these documentation inconsistencies into the CAP as AR01859126.

Analysis:

The inspectors determined that the licensees failure to define acceptance criteria required by the ASME Code Section XI in site procedures for containment visual examinations was a performance deficiency that warranted a significance evaluation.

The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it adversely affected the Barrier Integrity Cornerstone attribute of maintaining the functional integrity of containment. The inspectors also answered Yes to the more-than-minor screening question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, the lack of acceptance criteria in site procedures for containment visual examinations would become a more significant safety concern in that active liner degradation may not be properly evaluated and/or promptly corrected, resulting in a containment liner breach.

In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 1609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, the inspectors checked the box under the Barrier Integrity Cornerstone because the corrosion induced pitting degraded the containment barrier.

The inspectors determined this finding was of very low safety significance (Green) based on answering No to the Exhibit 3 Barrier Integrity Screening Questions, in IMC 0609, A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012. Specifically, the inspectors answered No to the screening question associated with an actual open pathway (e.g., breach) in the containment and No to the question associated with reduction in function of hydrogen igniters in containment.

The inspectors determined that the primary cause of the failure to define containment visual examination acceptance criteria was related to the cross-cutting component of human performance, decision making, because the licensee did not apply a systematic process when faced with unexpected plant conditions, to ensure safety was maintained (H.1(a)). Specifically, a systematic process for developing acceptance criteria was not applied for the containment visual examinations.

Enforcement:

The inspectors identified an NCV of 10 CFR 50.55a(g)(4), Inservice Inspection Requirements, having a very low safety significance (Green), for the licensees failure to define acceptance criteria for containment visual examinations.

Title 10 CFR 50.55a(g)(4) requires, in part, that throughout the service life of a pressurized water-cooled nuclear power facility, components must meet the requirements set forth in the ASME Code Section XI. The ASME Code 2001 Edition, 2003 Addenda of Section XI, Articles IWE-3510.1 and IWE-3511.1, required The Owner shall define acceptance criteria for the visual examination of containment surfaces.

Contrary to the above, as of April 3, 2013, the licensee failed to define acceptance criteria for the visual examination of containment surfaces. At the conclusion of the inspection, the licensee developed visual examination acceptance criteria to restore compliance with this NRC regulation. Because of the very low safety significance and because the licensee entered this issue into the CAP as AR01858862 and AR01861158, it is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy (NCV 05000266/2013003-03; 05000301/2013003-03, Lack of Acceptance Criteria for Containment Visual Examinations).

(2) Incorrect Equipment Selected for Ultrasonic Examination

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, for failure to select an appropriately contoured UT search unit wedge in accordance with procedure NDE-173, PDI Generic Procedure for the Ultrasonic Examination of Austenitic Piping Welds. Consequently, three elbow-to-pipe socket welds on the CVCS line for Unit 1 were examined with the incorrectly contoured UT search unit and this examination would not provide a demonstrated level of quality necessary to reliably detect and size thermal fatigue cracks.

Description:

On March 26, 2013, the inspectors identified that the licensees vendor failed to perform circumferential UT examinations at three CVCS socket welds (CVC-02-LD-1001-21, -29, and -30) with an appropriately contoured search unit (ultrasonic transducer) wedge (shaped plastic shoe attached to the search unit).

Specifically, the licensees vendor selected a UT search unit wedge contoured to fit a pipe of 4-inch outside diameter and applied it to a pipe with a 21/2-inch outside diameter, which exceeded the maximum contour allowed by the procedure. Because wedge contour was an essential procedure variable, the inspectors were concerned that the examination as performed, would not provide a demonstrated level of accuracy necessary to reliably detect and size thermal fatigue cracking which may exist at these weld locations.

The licensee submitted a letter dated March 19, 2013, to the NRC Request for Approval of Risk-Informed/Safety Based Inservice Inspection Alternative for Class 1 and 2 Piping in Accordance with 10 CFR 50.55a(a)(3)(i). In Section 3.4 of this letter, the licensee stated, The changes included changing the number and location of inspections, and in many cases improving the effectiveness of the inspection to account for the findings of the RIS_B [Risk Based] degradation mechanism. For example, examinations of locations subject to thermal fatigue will be conducted on expanded volume and will be focused to enhance the probability of detection during the inspection process. In Section 3.3.4 of this letter, the licensee stated, Consistent with previously approved RIS_B submittals, PBNP [Point Beach Nuclear Plant] will calculate coverage and use additional examinations or techniques in the same manner it has for traditional Section XI examinations. And in Section 3.5, the licensee stated, The applicable aspects of the ASME Code not affected by this change will be retained, such as inspection methods. Therefore, the licensee intended to apply the ASME Code Section XI qualified inspection methods when conducting volumetric examinations including those used to detect thermal fatigue.

Historically, the licensee conducted examinations of pipe base metal at socket weld locations that were subject to thermal fatigue in accordance procedure NDE-178, Ultrasonic Examination for Thermal Fatigue Cracking in Accordance with MRP-146 OR MRP-192, which allowed applying search unit wedges contoured for twice the nominal pipe diameter. However, this procedure did not demonstrate that it was capable of detecting cracks in accordance with the ASME Code Section XI. Therefore, the licensee elected to supplement this procedure by selecting an equipment configuration in accordance with a second procedure (NDE-173, PDI Generic Procedure for the Ultrasonic Examination of Austenitic Piping Welds), which contained the essential procedure variables from the generic procedure PDI-UT-2, PDI Generic Procedure for the Ultrasonic Examination of Austenitic Piping Welds, Revision E, that did demonstrate that it was capable of detecting cracks in accordance with the ASME Code Section XI.

On March 26, 2013, the licensee completed UT examinations at pipe-to-elbow socket welds (CVC-02-LD-1001-21, -29, and -30) subject to thermal fatigue cracking under their risk-based Inservice Inspection (ISI) Program (Category R-A, Item R1.11S). However, the inspectors identified that an incorrectly contoured (e.g., curved) wedge was applied for the circumferential scans. Specifically, Step 5.5.2 of the applicable qualified procedure NDE-173, PDI Generic Procedure for the Ultrasonic Examination of Austenitic Piping Welds, required that when contoured search units are used, the contouring shall not exceed the nominal pipe diameter dimension as defined in the following table. For the 21/2-inch diameter CVCS pipe, the maximum contour allowed by this table, was a wedge with a 31/2-inch diameter contour and the circumferential scans were completed with a wedge contoured for a 4-inch diameter pipe. Wedge shape is an essential procedure variable as defined by the ASME Code Section XI, Appendix VIII, Article III-2100, Procedure Requirements, Step d(2)(c). Thus, the failure to apply the correctly shaped wedge would invalidate the ASME Code Section XI procedure qualification necessary to reliably detect or size cracks.

The licensee documented this issue in the CAP as AR01860155. To credit these weld examinations for the risk-based ISI Program, the licensee considered completing a qualified UT examination, or requesting NRC approval for an alternative to the ASME Code Section XI qualified UT examination. The inspectors did not have a near term concern for the operability of the CVCS pipe because the affected pipe welds were subjected to VT-2 visual and PT examinations and no rejectable defects were identified.

The licensee also provided the inspectors a copy of an Electric Power Research Institute (EPRI) Technical Report, Materials Reliability Program: NDE Technology for Detection of Thermal Fatigue Damage in Piping (MRP-23, Revision 1), which compared the differences in procedure essential variables between the Generic Industry Procedure (PDI-UT-2) qualified by Section XI, Appendix VIII methods to detect cracking and the non-demonstrated generic procedure for detection of thermal fatigue cracking (EPRI-NDEC-UT) and concluded these two procedures were equivalent. However, the use of a technical report to justify a deviation from the ASME Code Section XI requirements could only be applied after review and approval by the NRC the Office of Nuclear Reactor Regulation to ensure the basis established would provide an adequate level of assurance for detection of thermal fatigue cracking.

Analysis:

The inspectors determined that the licensees failure to select UT equipment (search unit wedge shape) in accordance with procedure NDE-173 during examination of CVCS welds was a performance deficiency that warranted a significance evaluation.

The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix B, because the inspectors answered Yes to the more-than-minor screening question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, the examination of three CVCS welds was presumed adequate and absent NRC intervention, would have been returned to service for an indefinite period of service, which would have placed the piping at increased risk for undetected thermal fatigue cracking, leakage, or component failure. In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 1609, Attachment 4, the inspectors checked the box under the Initiating Events Cornerstone because leakage at this CVCS letdown line could result in a primary system Loss of Coolant Accident (LOCA).

The inspectors determined this finding was of very low safety significance (Green) based on answering No to the questions in IMC 0609, Attachment A, Part A of Exhibit 1.

Specifically, the inspectors answered No to the screening question After a reasonable assessment of degradation could the finding result in exceeding the Reactor Coolant System (RCS) leak rate for small LOCA, and No to the screening question After a reasonable assessment of degradation, could the finding have likely affected other systems used to mitigate a LOCA resulting in a total loss of their function (e.g.,

Interfacing System LOCA)? The inspectors answered No to these questions because of the small diameter (2-inch) of the line and because the affected pipe welds were subjected to a VT-2 visual and PT examination that did not identify rejectable defects.

The inspectors determined that the primary cause of the failure to select UT equipment (search unit contour) in accordance with procedure NDE-173 was related to the cross-cutting component of human performance, work practices, because the licensee did not adequately set up clear expectations for procedure control and adherence for this activity (Item H.4(b)). Specifically, insufficient direction was provided to vendor staff for simultaneous use of two procedures NDE-178 and NDE-173 with different equipment requirements and restrictions.

Enforcement:

The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion V, for the licensees failure to select UT equipment (search unit wedge) in accordance with procedure NDE-173 during examination of CVCS welds.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions Procedures and Drawings, which states in part that Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure NDE-173, PDI Generic Procedure for the Ultrasonic Examination of Austenitic Piping Welds, Revision 13, Step 5.5.2 stated, Search unit contouring shall not exceed the nominal pipe diameter dimension as defined in the following table, and this table required that, Maximum increase in contour diameter over the outside pipe diameter (inches) - 1.0 inch.

Contrary to the above, on March 26, 2013, while performing UT examinations on three CVCS pipe welds with a 2.5-inch outside diameter, the licensee completed circumferential scans using a search unit contoured to fit a 4-inch outside pipe diameter, which exceeded the maximum allowable contour (3.5-inch outside pipe diameter). To restore compliance with NRC regulations, the licensee considered the option of repeating these weld examinations using a qualified UT technique or the option to seek NRC approval to deviate from the ASME Code Section XI requirements for UT examination. Because of the very low safety significance and because the licensee entered this issue into the CAP as AR01860155, it is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy (NCV 05000266/2013003-04; Incorrect Equipment Selected for Ultrasonic Examination).

.2 Reactor Pressure Vessel Upper Head (RPVUH) Penetration Inspection Activities

a. Inspection Scope

For the Unit 1 reactor vessel head, no examination was required pursuant to 10 CFR 50.55a(g)(6)(ii)(D) for the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control (BACC)

a. Inspection Scope

On March 18, 2013, the inspectors observed the licensees BACC visual examinations for portions of the RCS, connected systems at the 21-foot elevation in containment, and verified whether these visual examinations emphasized locations where boric acid (BA)leaks can cause degradation of safety significant components.

The inspectors reviewed the following licensee evaluations of RCS components with BA deposits to determine whether degraded components were documented in the corrective action system. The inspectors also evaluated corrective actions for any degraded RCS components to determine whether they met the component Construction Code, ASME Section XI Code, and/or NRC approved alternative:

• BA Evaluation of the Reactor Coolant Pump Seal Water Return Filter Outlet (1CV-315); and

• BA Evaluation of the Incore Thimble Seal Table (1Z-042).

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

• AR01711126, Purification System Inlet Isolation; and

• AR01692592, Pipe Fittings at 1PT-447.

b. Findings

No findings were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

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

• the numbers and sizes of SG tube flaws/degradation identified was consistent with the licensees previous outage operational assessment predictions;

• the SG tube ET examination scope and expansion criteria were sufficient to meet the TSs and EPRI Document 1013706, Pressurized Water Reactor Steam Generator Examination Guidelines;

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

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

• the licensee implemented qualified depth sizing methods to degraded tubes accepted for continued service;

• the ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI Document 1013706, Pressurized Water Reactor Steam Generator Examination Guidelines; and

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

The licensee did not perform in-situ pressure testing; did not have SG tube leakage above 3 gallons-per-day during the previous operating cycle; did not leave foreign objects on the secondary side of the SG; and no repairs were required on any of the SG tubes. Therefore, no NRC review was completed for these inspection attributes.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems entered into the licensees CAP, and conducted interviews with licensee staff to determine whether:

• the licensee had established an appropriate threshold for identifying ISI-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. Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On April 24, 2013, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

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

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

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On April 16, 2013, the inspectors observed reactor startup activities in the control room.

This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board and equipment manipulations;

• oversight and direction from supervisors; and

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

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• function-oriented approach for the 4160V [volt] system;

• function-oriented approach for the radiation monitoring system;

• problem-oriented approach for 13.8 kV [kilovolt] system; and

• function-oriented approach for source range monitors.

The inspectors reviewed events, such as where ineffective equipment maintenance had resulted or could have 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 four completed quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• risk management during week of startup (April 15, 2013);

• risk management for use of assigned operator during service water pump OOS;

• risk management during Emergency Diesel Generator (EDG) G-04 extended maintenance outage; and

• risk management during week of May 20, 2013.

These activities were selected based on the 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 four samples as defined in IP 71111.13-05.

b. Findings

Failure to Implement Risk Management Actions During Bus D-40 Outage

Introduction:

A self-revealed finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(4) was identified because the licensee failed to properly manage and assess risk during a scheduled maintenance outage for Emergency Diesel Generator (EDG) G-04, at which time bus D-40 was isolated.

Specifically, the licensee failed to follow licensee procedures for management of risk and account for all activities identified within the scope of scheduled work for G-04, which included the isolation of bus D-40. Subsequently, when the licensee isolated bus D-40 and an unplanned entry into yellow risk condition was entered and risk mitigation activities were not taken.

Description:

On April 29, 2013, the licensee performed tagging evolutions to support maintenance activities, as required by the workplan for the EDG G-04 outage. While hanging tags for 125 V direct current (DC) bus D-40, the control room received several unexpected alarms. Upon receipt of the alarms, the licensee entered multiple related limiting conditions for operation (LCOs), and evaluated the cause of the alarms.

Specifically, the licensee entered TS LCO 3.3.4, Loss of Power Diesel Generator Start Instrumentation, Condition A and B; TS LCO 3.5.2 Emergency Core Cooling System (ECCS) Operating, Condition A; and TS LCO 3.8.1, AC Sources-Operating, Condition E. The licensee determined the cause of the alarms to be the de-energizing of bus D-40. The licensee took prompt action to discontinue the tagging evolution, restore the bus to service (because the danger tag had not been hung) and exit the associated LCOs. The duration of the event was approximately six minutes.

The inspectors reviewed licensee procedure NP 10.3.7, On-Line Safety Assessment, and found that it outlined the requirements for performing safety assessments for equipment that is made or becomes unavailable on an operating unit. Specifically, NP 10.3.7, Step 2.1, stated that when a risk-significant SSC is made unavailable while a unit is at power, an assessment shall be performed to determine the overall effect of the planned or actual plant configuration on the level of safety of the plant. In addition, Step 2.1 stated that the results of this assessment shall be used in plant decision making to manage the level, duration, and long term impact of safety decreases. Also, the procedure specifically stated that the shift technical advisor was responsible for performing assessments using the safety monitor program as a predictive tool for 24-hour schedule look ahead evaluations and for schedule changes that occur during a shift, and for supporting the shift manager and probabilistic risk assessment (PRA)group with long-term plant safety monitoring by performing safety monitor plant configuration updates as necessary to ensure the program remains current with real plant status.

The inspectors determined that the licensee failed to properly assess and manage the increase in risk from the proposed maintenance activities in accordance with this procedure, as well as the maintenance rule, because the bus D-40 isolation was not included in the online safety monitor program, even though the information regarding the bus D-40 isolation was contained in the work package, and was authorized to begin by the shift technical advisor. Specifically, the inspectors reviewed the risk evaluation performed using the online safety monitor and found that the evolution would have caused the risk profile to be a higher licensee-established risk category (i.e. yellow versus green). The inspectors determined that had the licensee properly entered the bus D-40 outage into the online safety monitor tool used for assessing and managing risk, then the risk color change would have been identified; alternate risk management actions would have been required, including ensuring that the risk significant activity was understood by the involved personnel; contingency plans documented; and shift management approval received prior to starting the work activity.

The licensee recognized the evolution would result in a higher risk condition on Unit 2.

The licensee, in an effort to manage the risk, intended to remove the associated activity from the work schedule. Additional reviews determined that although the licensee intended to remove the maintenance activity from the schedule, the licensee failed to correct the work package to remove the bus D-40 isolation related to the planned work.

The shift technical advisor failed to account for the bus D-40 isolation in the online safety monitor.

The licensee entered this issue into the CAP as AR01870208 for evaluation and development of corrective actions. Additionally, the licensee took immediate corrective actions to address the issue by restoring the bus D-40 to service, initiated an evaluation of the issue through the condition reporting process, and evaluated the issue for performance clock resets.

Analysis:

The inspectors determined that the licensees failure to properly manage and assess risk for work activities associated with the isolation of bus D-40, was contrary to 10 CFR 50.65 (a)(4), and was a performance deficiency warranting further review.

The inspectors determined that the finding was more than minor because it was similar to Example 7.e of IMC 0612, Appendix E, Example of Minor Issues, dated August 11, 2009, and because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone. The finding adversely affected the Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, SDP, Attachment 0609.04, Initial Characterization of Findings, Table 2 and 3, dated June 19, 2012 and Appendix K, Maintenance Risk Assessment And Risk Management Significance Determination Process, dated May 19, 2005. The inspectors determined that the finding was a mitigating systems contributor, evaluated the risk deficit for each instance, and found that the issue screened as having very low safety significance (Green).

The inspectors determined that the finding has a cross-cutting aspect in the area of human performance, work control, because the licensee failed to appropriately plan and coordinate work activities (H.3(b)). Specifically, when the licensee attempted to remove the bus D-40 isolation work from the schedule, they did not update the work package to reflect the change and there was a failure to communicate and/or coordinate the changes in the work scope to the appropriate groups. The inspectors reviewed the licensees assessment for the proposed cross-cutting aspect, and found that the licensees assessment was consistent with the inspectors assessment of the condition.

Enforcement:

Title 10 CFR 50.65 (a)(4) requires, in part, that before performing maintenance activities (including, but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance) the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

Procedure NP 10.3.7 outlined the requirements for performing safety assessments for equipment that is made or becomes unavailable on an operating unit.

Contrary to the above, on April 29, 2013, the licensee failed to properly assess and manage the increase in risk associated with the removal of bus D-40 from service. As a result, the licensees risk assessment did not include all in-progress maintenance, and the appropriate risk management actions for this work activity were not implemented.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low safety significance (Green) and was entered into the licensees CAP as AR01870208. (NCV 05000266/2013003-05; 05000301/2013003-05, Failure to Implement Risk Management Actions During Bus D-40 Outage).

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following operability issues:

• operability of spray additive tank vacuum breakers;

• operability of the 13.8 kilovolt breakers;

• operability of refueling water storage tank outlet valve increased loading;

• operability of control room charcoal filters;

• operability/functionality of crossover steam dump check valve with no post maintenance testing (PMT) after maintenance; and

• operability of D-07, D-08, and D-09 battery chargers operability during external flooding event.

The inspectors selected these potential operability/functionality 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 TSs and FSAR 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 six samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

The inspectors reviewed the following modification:

• permanent modification to emergency preparedness seismic monitors The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design-basis, the FSAR, and the TSs, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. 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 modification sample as defined in IP 71111.18 05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing (PMT)

a. Inspection Scope

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

• PMT of control rod stationary coils after failed test (Unit 1);

• PMT of 1RH-700 RCS to P-10 A/B residual heat removal pump suction header operator valve following maintenance (Unit 1); and

• 2P-29 PMT following 2AF-2002 gasket replacement [partial] (Unit 2).

These activities were selected based upon the SSCs ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the FSAR, 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 PMTs 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 two complete and one partial PMT samples and as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

On March 18, 2013, Unit 1 shut down for a refueling outage (RFO) U1R34, and returned to full power on April 22, 2013. The inspectors confirmed 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 compliance with the applicable TSs when taking equipment OOS;

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

• controls over the status and configuration of TS systems to ensure that TS requirements were met;

• control of 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;

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

• refueling activities;

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

• licensee 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.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• EDG G-04 air check valve surveillance (inservice testing (IST));

• Operations Refueling Test (ORT) 3A, safety injection actuation with loss of engineering safeguards AC (train A) Unit 1 (routine);

• EDG G-01surveillance (routine);

• Unit 1 containment isolation valves (CIVs) quarterly surveillance (CIV);

• Unit 1 containment humidity indicator RCS leakage (RCS).

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

• did preconditioning occur;

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

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

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

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the FSAR, 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 ASME Code Section XI, 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 IST sample, one CIV sample, and one RCS leak detection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

Failure to Account for Plant-Specific Maintenance History in the Development of Preventive Maintenance Frequency

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR 50, Appendix B, Criterion V, due to the licensees failure to follow procedure FP-PE-90-01, Preventive Maintenance Program.

Specifically, in 2009, when setting the preventive maintenance (PM) frequency for valve 1MS-02083 [HX-1A SG Sample Isolation Control], a containment isolation valve, the licensee determined that a 15-year frequency was appropriate instead of the recommended 10 years. The licensees justification was based on internal maintenance history showing good performance. However, the inspectors review revealed that the maintenance history for this category of valves did not support this determination. The valve subsequently failed during surveillance on March 21, 2013, after 13 years of service.

Description:

On March 21, 2013, during performance of surveillance ORT-3A, Safety Injection Actuation with Loss of Engineering Safeguard AC (train A) Unit 1, valve 1MS-2083 failed to stroke close upon the receipt of the test signal.

Valve 1MS-2083 is a solenoid valve that receives an automatic closure signal to provide containment isolation following a loss of coolant accident. Additionally, the valve is required to close in order to perform its safety-related function to maintain pressure boundary integrity following a steam break. This valve had been in service since April 2000. Since Unit 1 was in Mode 5 at the moment of the failure, the valve was not required to be operable at the point of discovery.

Following the failure, the licensee initiated AR01858451 to document the valves failure to stroke close during the surveillance and the replacement of the valve. The licensee also started an apparent cause evaluation (ACE) under the same action request to investigate the failure. The ACE determined that the most probable cause of the failure was binding of the internals. Inspection of the internals showed no debris or evidence of corrosion. The ACE also mentioned that the PM frequency was 15 years for 1MS-02083, as well as other Category 1 (high safety significant) and Category 2 (active, safety-related, and not high safety significant) air operated valves that are normally energized. The licensee established the PM frequency in August 2009 during a PM optimization project. As a result of the project, the licensee determined that a 15-year frequency was appropriate, instead of the recommended 10 years from the EPRI, due to maintenance history showing good performance for 1MS-02083 and time-testing during quarterly tests. The licensee concluded that, had they followed the EPRI guidelines, the failure would not have occurred.

The inspectors reviewed AR01267677 and the service history of 1MS-02083, and observed that the valve had failed in 2000, and was rebuilt after 12 years of service.

Additionally, AR01267677 stated that when the vendor was contacted, they had indicated that for each solenoid-operated valve, there should be specific change-out frequencies based on area temperatures and radiation exposure. The inspectors found no evaluation of area temperatures or radiation exposure. The licensee determined that for Categories 1 and 2 solenoid-operated valves, there had been 10 documented failures, with the shortest service duration being 9 years of service. Based upon the information described above as well as the maintenance history, the inspectors concluded that licensees recommendation that all Categories 1 and 2 solenoid-operated valves be replaced on a 15-year frequency instead of the recommended 10 years, was not justified, as required by station procedure FP-PE-PM-01, Preventive Maintenance Program. These weaknesses had not been uncovered by the licensee during their review. The inspectors considered that they added value in the identification of previously unknown weaknesses in the licensees evaluation, and corrective actions associated with this issue. The licensees conclusion focused only in following the EPRI guidelines, and did not look into the programmatic aspect of not following the PM procedure, and the incomplete evaluation of the maintenance history. The licensees corrective actions for this issue included replacement of 1MS-2083 and an action to review the PM frequencies of critical solenoid-operated valves for adequacy.

Analysis:

The inspectors determined that the failure to evaluate the maintenance history of 1MS-02083 and similar valves when setting its PM frequency, as required by procedure FP-PE-PM-01, was a performance deficiency warranting further review.

The inspectors determined that this finding was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Barrier Performance attribute of the Barrier Integrity Cornerstone, and adversely affected the Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated this finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Checklist 3, dated February 28, 2005. The inspectors determined the finding to be of very low safety significance (Green), because the inspectors determined that a quantitative assessment was not required. The inspectors did not identify a cross-cutting aspect associated with this finding because the finding did not reflect current performance due to the age of the performance deficiency.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality be prescribed and accomplished by procedures appropriate to the circumstance and in accordance with those instructions and procedures. Procedure FP-PE-PM-01, Step 4.2.2, requires, in part, that critical and minor equipment shall have a documented, retrievable basis that includes justification for PM scope. The following should be considered when creating the basis: a) EPRI PM Basis Document/Templates (latest revision), b) plant-specific maintenance history, and d) vendor recommendations.

Additionally, Step 4.4.3 states that If an applicable PM template exists for the component being evaluated, then determine the appropriate PM tasks based on the failure consequence, service environment Contrary to the above, from August 2009 to March 19, 2013, licensee personnel failed to document a complete justification for the selection of the PM frequency, an activity affecting quality. Additionally, the information used as a justification was inaccurate in that internal operating experience for the maintenance history of 1MS-02083 and similar valves showed that failures had occurred as early as 9 years of service; valve 1MS-02083 it showed a replacement after 12 years of service. Because this violation is of very low safety significance and the licensee entered it into the CAP as AR01858451, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000266/2013003-06; Failure to Account for Plant-Specific Maintenance History in the Development of Preventive Maintenance Frequency).

1EP2 Alert and Notification System Evaluation

.1 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors held discussions with Emergency Preparedness (EP) staff regarding the operation, maintenance, and periodic testing of the primary and backup Alert and Notification System (ANS) in the plume pathway Emergency Planning Zone. The inspectors reviewed monthly trend reports and siren test failure records from September 2011 through April 2013. Information gathered during document reviews and interviews was used to determine whether the ANS equipment was maintained and tested in accordance with emergency plan commitments and procedures. Documents reviewed are listed in the Attachment to this report.

This ANS evaluation inspection constituted one sample as defined in IP 71114.02-06.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

.1 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors reviewed and discussed with plant EP staff the Emergency Plan Commitments and Procedures for Emergency Response Organization (ERO) on-shift and augmentation staffing levels. A sample of the EP training records, approximately 12 ERO personnel assigned to key and support positions, were reviewed to determine the status of their training as it related to their assigned ERO positions. The inspectors reviewed the ERO Augmentation System and activation process, the primary and alternate methods of initiating ERO activation, unannounced off-hour augmentation tests from September 2011 through April 2013, and the provisions for maintaining the plants ERO roster.

The inspectors reviewed a sample of corrective actions related to the facilitys ERO staffing and Augmentation System Program and activities from September 2011 through April 2013 to determine whether corrective actions were completed in accordance with the site's CAP. Documents reviewed are listed in the Attachment to this report.

This ERO staffing and augmentation system inspection constituted one sample as defined in IP 71114.03-06.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The Nuclear Security and Incident Response (NSIR) headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS Accession Numbers ML13077A438, ML13107B368, ML13107B350, ML13123A335, and ML13126A102, as listed in the Attachment to this report.

The licensee determined that, in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. 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 plan review inspection constituted one sample as defined in IP 71114.04-05.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

.1 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed a sample of nuclear oversight staffs audits of the EP program to determine whether these independent assessments met the requirements of 10 CFR 50.54(t). The inspectors also reviewed critique reports and samples of CAP records associated with the 2012 Biennial Exercise, as well as various EP drills conducted, in order to determine that the licensee fulfilled its drill commitments and to evaluate the licensees efforts to identify, track, and resolve concerns identified during these activities. The inspectors reviewed a sample of EP items and corrective actions related to the facilitys EP Program and activities between September 2011 through April 2013, to determine whether corrective actions were completed in accordance with the site's CAP. Documents reviewed are listed in the Attachment to this report.

This correction of EP weaknesses and deficiencies inspection constituted one sample as defined in IP 71114.05-06.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill May 30, 2013, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Technical Support Center and the Operations Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

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

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted one complete 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 (RP) 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 whether 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 has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

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

The inspectors 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:

• reactor cavity decontamination;

• transfer canal work; and

• steam generator eddy current.

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 has 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:

• 13-1005, General Maintenance Activities;

• 13-1010, Cavity Activities;

• 13-1021, Valve Maintenance Activities; and

• 13-1023, S/G Eddy Current.

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

The inspectors reviewed selected occurrences where a workers electronic personal dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the 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, RP job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of electronic personal dosimeters 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:

• 13-1005, General Maintenance Activities;

• 13-1010, Cavity Activities; and

• 13-1023, S/G Eddy Current For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high-efficiency particulate air ventilation system operation.

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

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)

a. Inspection Scope

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

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

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

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance with respect to stated RP work requirements. The inspectors assessed whether workers were aware of the radiological conditions in their workplace and the RWPs/limits in place, and whether their performance reflected the level of radiological hazards present.

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

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

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

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

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

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

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

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

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

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed pertinent information regarding plant collective exposure history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants 3-year rolling average collective exposure.

The inspectors reviewed the site-specific trends in collective exposures and source term measurements.

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

b. Findings

No findings were identified.

.2 Radiological Work Planning (02.02)

a. Inspection Scope

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

• scaffolding outage activities;

• SG eddy current; and

• remove/reinstall reactor vessel head.

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

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

b. Findings

No findings were identified.

.3 Radiation Worker Performance (02.05)

a. Inspection Scope

The inspectors observed radiation worker and RP technician performance during work activities being performed in radiation areas, airborne radioactivity areas, or high radiation areas. The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice (e.g., workers are familiar with the work activity scope and tools to be used, workers used ALARA low-dose waiting areas) and whether there were any procedure compliance issues (e.g., workers are not complying with work activity controls). The inspectors observed radiation worker performance to assess whether the training and skill level was sufficient with respect to the radiological hazards and the work involved.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications Performance Indicators (PI) for Units 1 and 2, for the second quarter 2012 through the first quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals. The inspectors also reviewed the licensees CAP to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

.2 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Leakage PI for Units 1 and 2, for the second quarter 2012 through the first quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance contained in NEI 99-02 were used.

The inspectors reviewed the licensees operator logs, RCS leakage tracking data, issue reports, event reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors also reviewed the licensees CAP to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two reactor coolant system leakage samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences PI for the period from the first quarter 2012 through the first quarter 2013.

The inspectors used PI definitions and guidance contained in NEI 99-02 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry 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 to this report.

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

b. Findings

No findings were identified.

.4 Drill/Exercise Performance (DEP)

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill/Exercise PI for the period from the first quarter 2012 through first quarter 2013. The inspectors used PI definitions and guidance contained in NEI 99-02, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees records and processes including procedural guidance on assessing opportunities for the PI; assessments of PI opportunities during pre-designated control room simulator training sessions, performance during the 2012 Biennial Exercise, and performance during other drills associated with the PI to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one DEP sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.5 Emergency Response Organization Readiness

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill/Exercise PI for the period from the first quarter 2012 through first quarter 2013. The inspectors used PI definitions and guidance contained in NEI 99-02 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees records and processes including procedural guidance on assessing opportunities for the PI; performance during the 2012 Biennial Exercise and other drills; and revisions of the roster of personnel assigned to key ERO positions to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one ERO readiness sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.6 Alert and Notification System (ANS) Reliability

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill/Exercise PI for the period from the first quarter 2012 through first quarter 2013. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees records and processes including procedural guidance on assessing opportunities for the PI and results of periodic ANS operability tests to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine whether any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one ANS reliability sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

a. Inspection Scope

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

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

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

b. Findings

No findings were identified.

.2 Daily CAP Reviews

a. Inspection Scope

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

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

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the period of the third quarter 2012 through first quarter 2013, although some examples expanded beyond those dates where the scope of the trend warranted.

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

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

b. Findings

No findings were identified.

.4 Annual Sample:

Review of Operator Workarounds

a. Inspection Scope

The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of the operator workarounds (OWAs) on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.

The inspectors performed a review of the cumulative effects of OWAs. The documents listed in the Attachment to this report were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee had identified operator challenges at an appropriate threshold, had entered them into their CAP, and proposed or implemented appropriate and timely corrective actions which addressed each issue.

Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified OWAs.

This review constituted one operator workaround annual inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report (LER) 05000266/2013-002-00:

Condition Prohibited by Technical Specifications

a. Inspection Scope

On April 13, 2013, Unit 1 entered Mode 4 with the sodium hydroxide tank outlet valve closed. The valve isolated the flow path for both trains of spray additive tank equipment, which resulted in not meeting the requirements of LCO 3.6.7, Spray Additive System.

The mode change with required inoperable equipment resulted in a violation of LCO 3.0.4. The incorrect position was discovered by a Senior Reactor Operator who was validating tags in the field. 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

A licensee-identified NCV is documented in Section 4OA7 of this inspection report.

.2 (Closed) LER 05000266/2013-001-00:

Loss of Offsite Power to Unit 1 Safeguard Buses

a. Inspection Scope

On February 6, 2013, at 11:32 CST, Unit 1 experienced an undervoltage condition on the 4.16kV safeguard buses 1-A05 and 1-A06. This condition resulted in all four EDGs auto-starting, and the automatic loading of EDGs G-01 and G-03 onto buses 1A-05 and 1A-06. The condition was caused by the opening of all three phases of a high side circuit switcher to the high-voltage auxiliary transformer 1X-03, which in turn caused a degraded voltage condition to safeguard buses 1-A05 and 1-A06. The resident inspectors responded to the control room to monitor this event. Offsite power was restored to 1-A05 at 12:49 p.m. and to 1-A06 at 12:57 p.m. through a redundant path.

The inspectors reviewed the licensees actions in response to the event, the immediate corrective actions, and the root cause evaluation report. 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

No findings were identified.

4OA5 Other Activities

.1 Temporary Instructions 2515/182 - Review of the Industry Initiative to Control

Degradation of Underground Piping and Tanks (Closed)

a. Inspection Scope

Leakage from buried and underground pipes has resulted in ground water contamination incidents with associated heightened NRC and public interest. The industry issued a guidance document, NEI 09-14, Guideline for the Management of Buried Piping Integrity, (ADAMS Accession No. ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued Revision 1 to NEI 09-14 (ADAMS Accession No. ML110700122), with an expanded scope of components which included underground piping that was not in direct contact with the soil and underground tanks.

On November 17, 2011, the NRC issued TI-2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.

From June 17-21, 2013, the inspectors conducted a review of records and procedures related to the licensees program for buried pipe, underground pipe, and tanks in accordance with Phase II of TI-2515/182. This review was done to confirm that the licensees program contained attributes consistent with Sections 3.3 A and 3.3 B of NEI 09-14 and to confirm that these attributes were scheduled and/or completed by the NEI 09-14 Revision 1 deadlines. To determine if the program attribute was accomplished in a manner which reflected good or poor practices in program management, the inspectors interviewed licensee staff responsible for the buried pipe program. Additionally, the inspectors performed a walkdown of rectifiers, used for the operation and maintenance of the cathodic protection system and observed excavation of buried piping in preparation for testing.

Based upon the scope of the review described above, Phase II of TI-2515/182 was completed.

b.

Observations The licensees Buried Piping And Underground Piping And Tanks Program was inspected in accordance with Paragraph 03.02.a of the TI and it was confirmed that activities which correspond to completion dates specified in the program which have passed since the Phase I inspection was conducted, have been completed. Additionally, the licensees Buried Piping and Underground Piping and Tanks Program was inspected in accordance with Paragraph 03.02.b of the TI and responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf, was submitted to the NRC Headquarters staff.

c. Findings

No findings were identified.

4OA6 Management Meetings

Exit Meeting Summary

On July 11, 2013, the inspectors presented the inspection results to Mr. L. Meyer, and other members of the licensee staff. The licensee acknowledged the issues presented.

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

.2 Interim Exit Meetings

Interim exits were conducted for:

• the results of the inservice inspection with Mr. C. Trezise on April 3, 2013;

• the inspection results for the areas of radiological hazard assessment and exposure controls; occupational ALARA planning and controls; and occupational exposure control effectiveness PI verification with Mr. L. Meyer on April 12, 2013;

• the results of the EP program inspection with Mr. L. Meyer on May 2, 2013;

• the results of the TI-2515/182, The Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, with Mr. L. Meyer on June 21, 2013.

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

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as an NCV:

• Title 10 CFR 50.54(q)(2) requires that a holder of a nuclear power reactor operating license follow and maintain the effectiveness of an emergency plan that meets the requirements in Appendix E to this part and the planning standards of 10 CFR 50.47(b). The Point Beach Nuclear Plant Emergency Plan Implementing Procedure EPIP 1.2, Emergency Classification, Section 5.1 states in part, Review the basis for the selected Emergency Action Level (EAL) to determine/confirm that the EAL applies, and, If an event meets the threshold of the EAL, then classify the emergency. Contrary to the above, on April 25, 2012, the licensee failed to follow its Emergency Plan during an actual emergency and that resulted in a failure to properly implement EALs. Specifically, inaccurate communications resulted in the over classification of an alert emergency classification level based on (EAL) HA3.1.

Using Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process, dated February 24, 2012, Section 4.0 Actual Event Implementation Issue (Failure to Implement), and the inspectors determined that the violation was not greater than very low safety significance (Green) because no public official protective actions were implemented as a result of this event over classification. The issue is documented in the licensees Corrective Action Program as AR 01759720.

• The licensee identified a finding of very low safety significance (Green) and an associated NCV of Limiting Condition for Operability (LCO) 3.0.4. Licensee LCO 3.0.4 states in part, When an LCO is not met, entry into a MODE or other specified condition in the applicability shall only be made: When the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Contrary to this, on April 14, 2013, the Unit 1 entered Mode 4 with the Spray Additive System inoperable and LCO 3.6.7 did not permit continued operation in Mode 4 with the system inoperable. Specifically, the outage senior reactor operator elected to walkdown all existing tags prior to Uni1 transitioning from Mode 4 to Mode 3. The senior reactor operator identified a tag was hung on 1SI-831A, Spray Additive Tank Outlet Valve, and was unsure about the purpose of the tag because the system was required to be operable in Mode 4. Investigations showed that the tag should have been removed prior to entry into Mode 4, but was left hung due to a sequencing error between the Mode change checklist and the tagging process. The licensee immediately entered the LCO 3.6.7, Spray Additive System, restored the system alignment and exited the LCO; this evolution lasted approximately 16 minutes. This issue was entered into the licensees CAP as AR01865777 and immediate corrective actions to restore the system to operable were taken, and a root cause evaluation was assigned.

The inspectors determined the performance deficiency to be more than minor in accordance with IMC 0612, Appendix B, because it was associated with the configuration control attribute of the Mitigating Systems Cornerstone. The finding also affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, with the Spray Additive Tank outlet valve closed it rendered the Spray Additive System inoperable in Mode 4. The inspectors and the R-III Senior Reactor Analyst reviewed IMC 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process, and determined that a Quantitative Assessment was not required; close spaces the issue was of very low safety significance.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

L. Meyer, Site Vice President

R. Wright, Plant General Manager

A. Watry, Buried Piping Program Owner

B. Jensen, NDE Level III

B. Scherwinski, Licensing

C. Trezise, Engineering Director

E. Schmidt, Programs Engineering Supervisor

F. Hennessy, Performance Improvement Manager

G. Strharsky, Emergency Preparedness Manager

G. Vickery, Operations Director

H. Hanneman, Acting Licensing Manager

J. Keltner, Chemistry Manager

J. Lewandowski, Nuclear Oversight Supervisor

K. Locke, Licensing

K. Longston, Emergency Preparedness Coordinator

L. Germann, Emergency Preparedness Coordinator

M. Millen, Licensing Manager

P. Polfleit, Fleet Emergency Preparedness Specialist

R. Baird, Acting Training Manager

R. Harrsch, Work Management Manager

R. Welty, Radiation Protection Manager

S. Catron, Fleet Licensing Manager

S. Forsha, Reactor Vessel Program Engineer

S. Wall, Emergency Preparedness Training Instructor

Nuclear Regulatory Commission

P. Pelke, Acting Branch Chief, Division of Reactor Projects, Branch 6

LIST OF ITEMS

Opened

05000266/2013003-01;

05000301/2013003-01 FIN Failure to Control Materials Classified as High Winds/Tornado Hazards (Section 1R01.03)

05000266/2013003-02;

05000301/2013003-02 NCV Failure to Follow Operability Evaluation Process Following Water Leakage into the Control Room (Section 1R06)

05000266/2013003-03;

05000301/2013003-03, NCV Lack of Acceptance Criteria for Containment Visual Examinations (Section 1R08.1(1))

05000266/2013003-04 NCV Incorrect Equipment Selected for Ultrasonic Examination (Section 1R08.1(2))

05000266/2013003-05

05000301/2013003-05 NCV Failure to Implement Risk Management Actions During Bus D-40 Outage (Section 1R13)

05000266/2013003-06 NCV Failure to Account for Plant-Specific Maintenance History in the Development of Preventive Maintenance Frequency (Section 1R22)

Closed

05000266/2013003-01;

05000301/2013003-01 FIN Failure to Control Materials Classified as High Winds/Tornado Hazards (Section 1R01.03)

05000266/2013003-02;

05000301/2013003-02 NCV Failure to Follow Operability Evaluation Process Following Water Leakage into the Control Room (Section 1R06)

05000266/2013003-03;

05000301/2013003-03, NCV Lack of Acceptance Criteria for Containment Visual Examinations (Section 1R08.1(1))

05000266/2013003-04 NCV Incorrect Equipment Selected for Ultrasonic Examination (Section 1R08.1(2))

05000266/2013003-05

05000301/2013003-05 NCV Failure to Implement Risk Management Actions During Bus D-40 Outage (Section 1R13)

05000266/2013003-06 NCV Failure to Account for Plant-Specific Maintenance History in the Development of Preventive Maintenance Frequency (Section 1R22)

05000266/2013-002-00 LER Condition Prohibited by Technical Specifications

05000266/2013-001-00 LER Loss of Offsite Power to Unit 1 Safeguard Buses TI 2515/182 TI Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks (Closed)