Text

IR 05000266-14-002; 05000301-14-002; on 01/01/2014 - 03/31/2014; Point Beach Nuclear Plant, Units 1 & 2; Inservice Inspection Activities; and Operability Determinations and Functional Assessments
	ML14127A185
Person / Time
Site:	Point Beach
Issue date:	05/07/2014
From:	Jamnes Cameron; Reactor Projects Region 3 Branch 4
To:	Mccartney E; Point Beach
References
	IR-14-002
	Download: ML14127A185 (52)
	v • d • e

UNITED STATES May 7, 2014

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2014002; 05000301/2014002

Dear Mr. McCartney:

On March 31, 2014, 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 April 9, and April 23, 2014, with you and other members of your staff.

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

If you contest the subject or severity of 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Point Beach Nuclear Plant. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Point Beach Nuclear Plant.

Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter (IMC) 0310. Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Point Beach Nuclear Plant.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and 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 Documents Access and Management System (ADAMS),

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

Sincerely,

/RA/

Jamnes L. Cameron, Chief Branch 4 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

IR 05000266/2014002; 05000301/2014002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000266; 05000301 License Nos: DPR-24; DPR-27 Report No: 05000266/2014002; 05000301/2014002 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: January 1, 2014, through March 31, 2014 Inspectors: K. Barclay, Acting Senior Resident Inspector B. Bartlett, Acting Senior Resident Inspector R. Elliott, Acting Resident Inspector V. Myers, Health Physicist T. Bilik, Senior Reactor Inspector Approved by: J. Cameron, Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000266/2014002; 05000301/2014002; 01/01/2014 - 03/31/2014; Point

Beach Nuclear Plant, Units 1 & 2; Inservice Inspection Activities; and Operability Determinations and Functional Assessments.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Three Green findings were identified by the inspectors. The findings were considered non-cited violations (NCVs) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green,

White, Yellow, Red) and determined using IMC 0609, Significance Determination Process (SDP) dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310,

Components Within the Cross Cutting Areas effective date January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

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

Appendix B, Criterion IX, Control of Special Processes, for a failure to provide sufficient magnetic field overlap to ensure 100 percent coverage while performing a magnetic particle examination (MT) on a steam generator feedwater nozzle weld. The examiner reexamined the area to meet the Code coverage and entered the issue into its Corrective Action Program (CAP) as action request (AR) 01951316.

The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the inspectors answered yes to the More-than-Minor question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern. Specifically, the required MT examination coverage/overlap was not verified/measured but rather assumed to be adequate by the examiner, and absent NRC intervention, would have returned the component to service for an indefinite period of service, which would have placed the nozzle/piping at increased risk for undetected cracking, leakage or component failure. In accordance with Table 2,

Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Initiating Events Cornerstone because leakage at this feedwater piping could be a transient initiator contributor.

The inspectors determined this finding was of very low safety significance (Green) 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 for Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered no to the screening question, Did the finding cause a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g., loss of condenser, loss of feedwater). The inspectors answered no to this question because the examiner re-examined the area of incomplete coverage and did not identify rejectable flaws. The inspectors determined that the primary cause of the failure to ensure sufficient field overlap while performing a MT examination was related to the cross-cutting component of Human Performance, Field Presence, because the licensee failed to provide oversight of work activities; including contractors and supplemental personnel. Specifically, proper oversight at the pre-job brief would have ensured the issue of overlap was discussed and understood.

The inspectors determined that proper oversight at the pre-job brief could have ensured the issue of overlap was discussed and understood. Additionally, good direct oversight of the test could have provided the ability to reinforce the correct method of performing the test as well as enabling the site to discover the error instead of the inspector identifying the problem [H.2]. (Section 1R08.b(1))

Cornerstone: Mitigating Systems

Green.

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

Appendix B, Criterion IX, Control of Special Processes, for a failure to measure the interpass temperature while performing welding on the auxiliary feedwater (AFW) piping system in accordance with welding procedure specifications (WPS) FP-PE-B31-P1P1-GTSM-001. Consequently, welding was performed without the Code and procedure required interpass temperature being monitored on a number of welds, a parameter which can affect the mechanical properties of the material being welded. To restore compliance, the welder proceeded to measure the interpass temperature and ensured that the temperature requirement would not have been exceeded. The licensee entered this issue into their CAP as AR 01950601.

The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the inspectors answered yes to the More-than-Minor question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern. Specifically, absent NRC intervention, the welder would have completed all of the welds without having measured the interpass temperature, a welding parameter which can affect the mechanical properties (e.g., impact properties) of some materials being welded, and could lead to a potential failure of the weld in service. In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating Systems Cornerstone because leakage at this AFW piping could degrade short term heat removal. The inspectors determined this finding was of very low safety significance (Green) based on answering no to the questions in Part A of Exhibit 1, Mitigating Systems Screening Questions, in IMC 0609, Attachment A, The Significance Determination Process for Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered, yes to the screening question If the finding is a deficiency affecting the design or qualification of a mitigating structures systems component (SSC),

does the SSC maintain its operability or functionality. The welder subsequently performed interpass temperature measurements and demonstrated that the temperature would remain below the required temperature of the welds in question, and the issue did not result in the actual loss of the operability or functionality of a safety system.

The inspectors determined that the primary cause of the failure to measure the interpass temperature in accordance with WPS FP-PE-B31-P1P1-GTSM-001 was related to the cross-cutting component of Problem Identification and Resolution, P.4 Trending. The organization failed to periodically analyze information from the corrective action program and other assessments in the aggregate to identify programmatic and common cause issues. Point Beach had experienced a number of issues related to welding in the weeks before the interpass temperature issue, leading to some 19 welding-related action request (ARs) being written. The total of these issues presented the site with the opportunity to evaluate if there were problems with the conduct of the welding program.

Resulting increased focus could have led to licensee identification of, or prevention of, the lack of taking temperatures. (Section 1R08.b(2))

Green.

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

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to follow procedures. Specifically, the licensee failed to perform a flood review, as required by NP 8.4.17, PBNP Flooding Barrier / Relief Path Program, Revision 15, when work activities in the G-02 EDG room left a lightweight wet floor safety sign that could have been transported during a license basis internal flood event and affected the flow capacity of the flood relief slots. The licensees short-term corrective actions included removing the material from the G-02 EDG room and communicating to station personnel the importance of not leaving susceptible material unattended. The licensee entered this issue into their CAP as AR 01960472.

The inspectors determined that the finding was more than minor, because, if left uncorrected, it could have the potential to become a more significant safety concern.

Specifically, if the licensee was not performing flood reviews for material left unattended during or after work activities, susceptible unattended material could be transported to credited flood relief dampers and impeded the design flow rate required for the dampers to protect safety related equipment. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 4, External Events Screening Questions, dated June 19, 2012. The inspectors answered yes to question 1 of External Events screening questions since the finding could potentially degrade one train of the emergency power system (a risk-significant system). Thus the inspectors consulted the regional Senior Risk Analyst (SRA).

The SRA performed a detailed risk evaluation using the Point Beach Standardized Plant Analysis Risk Model Version 8.22. For there to be a risk increase due to this deficiency there would have to be a LOOP coincident with a flood event that renders the G-O2 EDG unavailable. The SRA performed a bounding analysis assuming that the flood event occurred coincident with a LOOP. The exposure time for the deficient condition was not more than 15-days. Assuming a 15-day exposure time, the delta CDF was 9.3E-08/yr.

The dominant sequence involved a transient initiating event with a consequential LOOP and station blackout. Based on the result of the detailed risk evaluation, the issue was of very low risk significance (Green).

This finding has a cross-cutting aspect of Training (H.9) in the area of human performance, for failing to provide training and ensure knowledge transfer to maintain a knowledgeable workforce. Specifically, the licensee did not ensure that personnel were knowledgeable of need to control material that could transport during an internal flooding event, restrict flood relief paths, and affect flood mitigation features. (Section 1R15.b(1))

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit operated at or near full power throughout the quarter with one exception. On February 28, 2014 operators reduced power to 48 percent power for repairs to the 1P-28A main feed pump and 1LT-426 Pressurizer Level Transmitter. Operators restored power to 100 percent on March 4, 2014.

Unit 2 The unit operated at or near full power until March 16, 2014. On March 16, 2014, the operators reduced power in preparation for the March 17, 2014 shutdown and refueling outage 33. The unit was shut down for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

.1 (Closed) Unresolved Item (URI)05000266/2013002-01;05000301/2013002-01,

Flooding Impact of Loose Items Found on Roof Tops During the 2013 external flooding sample, the inspectors identified several large mats, pieces of metal equipment, loose scaffolding, piping, ladders, and other miscellaneous items on various rooftops. The inspectors were concerned that the loose items could clog various drains in the event of heavy precipitation and cause a flooding concern.

The licensee initiated AR 01855615 in response to the inspectors concerns. The review of the licensees evaluation of the condition was needed to determine whether barriers required to mitigate flooding were in place and functional as a result of the loose items identified.

The inspectors review of the licensees evaluation verified the licensees conclusion that the material found would not have caused water to pond on the building roofs in a quantity that would have challenged roofs structure or the flood barrier function of the roofs. This URI is closed.

This activity does not represent a completed inspection sample

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

Unit 2 residual heat removal (RHR) system train A with RHR train B out-of-service (OOS);

G-01 emergency diesel generator (EDG) with G-03 EDG OOS;

Unit 1 containment spray (CS) system train B with CS train A OOS; and

Unit 1 auxiliary feedwater (AFW) system train B with AFW train A OOS.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Final Safety Analysis Report (FSAR), Technical Specification (TS)requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions.

The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable.

The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies.

The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

The inspectors performed a complete system alignment inspection of the Unit 2 residual heat removal system, during an outage while it was aligned for shutdown cooling, to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R05 Fire Protection

Main article: IP 71111.05

.1 Routine Resident Inspector Tours

Main article: IP 71111.05Q

a. Inspection Scope

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

G-01 emergency diesel generator (EDG) Room, Fire Zone 308;

G-02 EDG Room, Fire Zone 309;

G-03 EDG Room and Support Rooms, Fire Zones 770-772, 774, 780, 785, 786;

1A-06 4160 Volt Vital Bus Room, Fire Zone 773;

G-04 EDG Room and Support Rooms, Fire Zones 775, 776, 778, 783, 784; and

2A-06 4160 Volt Vital Bus Room, Fire Zone 777.

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

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment 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 six quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

Main article: IP 71111.06

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed design documents, drawings, and the FSAR. The specific documents reviewed are listed in the Attachment 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 performed a walkdown of the following plant area(s) to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable:

Residual Heat Removal Pump Cubicles.

Documents reviewed during this inspection are listed in the Attachment to this report.

This inspection constituted one partial internal flooding sample as defined in IP 71111.06-05. This partial sample will be completed in the second quarter of 2014.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08P

From March 17, 2014 through March 26, 2014, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, steam generator tubes, emergency feedwater systems, risk significant piping and components and containment systems.

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

.1 Piping Systems ISI

a. Inspection Scope

The inspectors either observed or reviewed the following non-destructive examinations 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 if these were dispositioned in accordance with the ASME Code or an NRC approved alternative requirement:

magnetic particle (MT) examination of reactor coolant system (RC), feedwater nozzle extension-to-nozzle weld, SG-A-8;

visual examination (VT-3) of the 8 containment liner plates; and

liquid penetrant (PT) examination of a safety injection system welded attachment welds (SI-151R-3-2H1-IWA).

The inspectors reviewed the following examinations completed during the previous outage with relevant/recordable conditions/indications accepted for continued service to determine if acceptance was in accordance with the ASME Code Section XI or an NRC approved alternative:

Indication (PT) disposition of containment B pipe-to-elbow weld (CVC-02-LD-1001-29); and

Indication (VT) disposition of main-steam line rigid support EB-1-2H9.

The inspectors either observed or reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last refuelling outage to determine if the licensee applied the preservice non-destructive examinations 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 if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX:

weld repair/replacement of Class 3, auxiliary feedwater system (AFW) cross-tie piping weld (3 DB-3, Weld 2);

weld repair/replacement of Class 1, reactor coolant system (RC) seal weld valve bonnet (2SI-0853B); and

weld repair/replacement of Class 3, to cut and cap SW penetration 2CPP-38.

b. Findings

(1) A Failure to Provide Sufficient Field Overlap to Ensure 100 Percent Coverage

Introduction:

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for a failure to provide sufficient magnetic field overlap to ensure 100 percent coverage while performing a MT. Consequently, the examination area on the nozzle-to-pipe weld on the steam generator feedwater nozzle was being examined without adequate coverage of the required exam area.

Description:

The inspectors identified that the licensee Non-Destructive Examination (NDE) examiner failed to establish adequate magnetic field overlap to ensure that 100 percent coverage was achieved while performing a dry particle MT examination using the A/C yoke technique. An MT examination is performed in accordance with the Article IWA of Section XI of the ASME Code to detect surface breaking flaws that could affect the structural integrity or leak tightness of the system. The examiner conducted the MT in accordance with Procedure NDE-350, Magnetic Particle Examination Alternating Current (A/C) Yoke, which specified a licensee-developed methodology used to establish a spacing/distance (the yoke interval between subsequent yoke repositioning)to ensure that Code required overlap was achieved. The methodology to establish the yoke distance/spacing had been demonstrated by the licensee to ensure adequate overlap.

The examination area included the weld and the area 1/2 on either side of the toe of the weld. The examiner had placed the yoke parallel to the weld (on both sides of the weld)and had assumed that the field would be sufficient to extend beyond the center line of the weld based on the demonstrated methodology. However, the weld was 2.5 wide and a check of the distance needed to ensure field overlap showed that it was inadequate, falling short of the centerline of the weld. The inspectors were concerned that without adequate overlap, the examination could fail to reliably detect rejectable flaws prior to returning the Unit to service and adversely affect the integrity of the system. The examiner re-examined the area to meet the Code coverage and entered the issue into its CAP as AR 01951316.

Analysis:

The inspectors determined that the failure to provide sufficient field overlap as required by the ASME Code Section XI and site procedure 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 the inspectors answered yes to the More-than-Minor question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern". Specifically, the MT examination coverage was assumed to be adequate by the examiner, and absent NRC intervention, would have returned the component to service for an indefinite period of service, which would have placed the nozzle/piping at increased risk for undetected cracking, leakage or component failure. In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 609, 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Initiating Events Cornerstone because leakage at the steam generator feedwater nozzle weld could be a transient initiator contributor.

The inspectors determined this finding was of very low safety significance (Green) based on answering no to the questions in Part B of Exhibit 1, Initiating Events Screening Questions, in IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered no to the screening question Did the finding cause a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g., loss of condenser, loss of feedwater)". The inspectors answered no to this question because the examiner re-examined the area of incomplete coverage and did not identify rejectable flaws.

The inspectors determined that the primary cause of the failure to ensure sufficient field overlap while performing a MT examination was related to the cross-cutting component of Human Performance, [H.2] Field Presence: Leaders are commonly seen in the work areas of the plant observing, coaching, and reinforcing standards and expectations.

Deviations from standards and expectations are corrected promptly. Senior managers ensure supervisory and management oversight of work activities, including contractors and supplemental personnel. Proper oversight at the pre-job brief would have ensured the issue of overlap was discussed and understood. Additionally, good direct oversight of the test would have provided the ability to reinforce the correct method of performing the test as well as enabling the site to discover the error instead of the inspector identifying the problem.

Enforcement:

On March 23, 2014, the inspectors identified a NCV of 10 CFR Part 50, Appendix B, Criterion IX, for a licensees failure to ensure that sufficient field overlap was achieved while performing an MT examination as required by ASME Code and procedure NDE-350.

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

Procedure NDE-350, Magnetic Particle Examination Alternating Current (A/C) Yoke, used to perform the MT examination on the steam generator (SG) feedwater (FW)nozzle weld, Step 5.3.3, includes in part a requirement that all examinations shall be conducted with sufficient overlap to assure 100 percent coverage at the required sensitivity.

Contrary to the above, while performing a MT examination on a SG FW weld, the inspectors determined that the examiner failed to provide sufficient overlap while orienting the yoke parallel to the weld. To restore compliance, the examiner reexamined the area to ensure that the field overlap met the Code coverage requirements.

Because of the very low safety significance and because the licensee entered this issue into their CAP (AR 01951316), it is being treated as a NCV consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000266/2014002-01; 05000301/2014002-01; A Failure to Provide Sufficient Field Overlap to Ensure 100 Percent Coverage)

(2) Failure to Measure Interpass Temperature

Introduction:

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for a failure to measure the interpass temperature while performing welding on the auxiliary feedwater (AFW) piping system.

Consequently, welding was performed without the Code and procedure required interpass temperature being monitored, a parameter which can affect the mechanical properties of the material being welded.

Description:

The inspectors identified that the vendor welder had failed to measure the interpass temperature while performing gas tungsten arc welding (GTAW) on AFW piping. The inspectors also noted that there were no temperature measuring devices in the area. Welding is to be performed in accordance with the requirements of ASME Section IX to ensure that a sound weld is produced. The welder was to perform the welding activities in accordance with welding procedure specification (WPS) FP-PE-B31-P1P1-GTSM-001, which specified an interpass temperature of 600°F to ensure that temperature was not exceeded on the workpiece between passes. Furthermore, General Welding Procedure FP-PE-WLD-02, used in conjunction with the WPS, requires that the interpass temperature be measured. Multiple passes were being performed on a number of welds as part of a modification to the system. Based on experience the welder believed the temperature requirements would not be exceeded. The inspectors were concerned that the practice of failing to measure the interpass temperature as required by both the Code and procedure, could impact the quality of the welds and lead to susceptible material failing while in service, and thereby adversely affect the integrity of the system. The interpass temperature was subsequently measured and was determined not to have exceeded that allowed by procedure. The issue was entered into the licensees CAP as AR 01950601.

Analysis:

The inspectors determined that the failure to measure the weld interpass temperature as required by the ASME Code Section IX and site procedures 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 the inspectors answered yes to the More-than-Minor question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern".

Specifically, the interpass temperature measurement was not performed but instead the welder relied on the skill of the craft to determine that the required interpass temperature had not been exceeded. Absent NRC intervention, the welder would have completed all of the welds without having measured the interpass temperature, a welding parameter which can affect the mechanical properties (e.g., impact properties)of some materials being welded, and could lead to a potential failure of the weld in service. In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating Systems Cornerstone because leakage at this AFW piping could degrade short term heat removal.

The inspectors determined this finding was of very low safety significance (Green) based on answering yes to the questions in Part A of Exhibit 2, Mitigating Systems Screening Questions, in IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered yes to the screening question If the finding is a deficiency affecting the design or qualification of a mitigating SSC, does the SSC maintain its operability or functionality".

The welder subsequently performed interpass temperature measurements and demonstrated that the temperature would remain below the required temperature of the welds in question, and the issue did not result in the actual loss of the operability or functionality of a safety system.

The inspectors determined that the primary cause of the failure to measure the interpass temperature while performing a manual welding process was related to the cross-cutting component of Problem Identification and Resolution (P), P.4. Trending: The organization periodically analyzes information from the CAP and other assessments in the aggregate to identify programmatic and common cause issues (PI.4). Point Beach had experienced issues with welding in the prior couple of weeks before the interpass temperature issue. These included failed radiographs (RTs) of welds (five different days), missed training, and weld rod issuance problems, leading to some 19 welding-related ARs being written. As an example, while observing other welding related activities, the inspectors noted that it was not clear that the welder or a Quality Control person tasked with verifying the piping fit-up prior to welding, fully understood the fit-up tolerance requirements. (This was captured in AR 01950601). While none these issues are directly related to the lack of taking interpass temperatures; the total of these issues presented the site with the opportunity to evaluate if there were problems with the conduct of the welding program. The resulting increased focus could have led to licensee identification of, or prevention of, the lack of taking temperatures.

Enforcement:

On March 20, 2014, the inspectors identified a NCV of 10 CFR Part 50, Appendix B, Criterion IX, for a welders failure to measure interpass temperature while performing a number of welds on the AFW system as required by ASME Code and WPS FP-PE-B31-P1P1-GTSM-001.

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

WPS FP-PE-B31-P1P1-GTSM-001, used to perform welding on the Class 3, AFW cross-tie piping welds, includes an interpass temperature of 600°F.

General Welding Procedure FP-PE-WLD-02, used in conjunction with WPS FP-PE-B31-P1P1-GTSM-001, in Paragraph 4.11.4(a), Temperature Measurement, states in part that interpass temperature shall be measured on the surface of the base material within approximately 1 inch on the side from which welding will be performed.

Contrary to the above, while performing welding on the auxiliary feedwater system cross-tie piping welds, the welder failed to measure the interpass temperature as required, but rather relied on engineering judgment. To restore compliance, the welder proceeded to measure the interpass temperature and ensured that the requirement had not been exceeded.

Because of the very low safety significance and because the licensee entered this issue into their Corrective Action Program as AR 01950601, it is being treated as a NCV consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000266/2014002-02; 05000301/2014002-02; Failure to Measure Interpass Temperature)

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

A bare metal visual (BMV) examination and a non-visual examination were required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

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

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

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

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

The inspectors observed a number of non-visual examinations conducted on the reactor vessel head penetrations to determine if the activities were conducted in accordance with the requirements of ASME CC N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D).

Specifically, to determine:

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

if the UT examination equipment and procedures used were demonstrated by blind demonstration testing;

for indications or defects identified, that the licensee documented the conditions in examination reports and/or entered this condition into the corrective action system and implemented appropriate corrective actions; and

for indications accepted for continued service, that the licensee evaluation and acceptance criteria were in accordance with the ASME Section XI Code, 10 CFR 50.55a(g)(6)(ii)(D) or an NRC approved alternative.

The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed an independent walkdown of the reactor coolant system and related lines in the containment, which had received a recent licensee boric acid walkdown and verified whether the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components.

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

CV-00358, White Boric Acid on Body-to-Bonnet Joint and;

RH-00742; White Boric Acid on Body-to-Bonnet Joint.

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

AR 01861448; Boric Acid on 1HX-011B Bolting;

AR 01880754; Boric Acid Leak on 2HX-37A 2P-14A CS Pump Seal Water HX; and

AR 01949325; Clean Inspect Boric Acid on Bottom of 2LT-495.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

No exams were required this outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

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

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

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

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

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

Main article: IP 71111.11Q

a. Inspection Scope

On February 11, 2014, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

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

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

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

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

Main article: IP 71111.11Q

a. Inspection Scope

On March 19, 2014, the inspectors observed activities in the control room during reactor coolant system drain down in preparation for refueling activities. These were activities that required heightened awareness or were related to increased risk. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

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

correct use and implementation of procedures;

control board (or equipment) manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

AFW system;

fire protection system; and

gas turbine.

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

implementing appropriate work practices;

identifying and addressing common cause failures;

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

characterizing system reliability issues for performance;

charging unavailability for performance;

trending key parameters for condition monitoring;

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

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

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

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

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

January 28, gas turbine and diesel fire pump unavailable;

February 25, service air compressor K-3A, residual heat removal (RHR) train X, and battery D-106 unavailable; and

February 26, safety injection train B, service air compressor K-3A, containment spray train B, and the turbine driven AFW pump unavailable.

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

This maintenance risk assessment and emergent work control activity constituted three samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

Main article: IP 71111.15

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issue:

Incorrect sized fuse for control of turbine-driven auxiliary feedwater trip throttle valves 1(2) MS-2082;

Unit 1 pressurizer level transmitter 1LT-426 as found calibration out of tolerance;

Subsoil drain cleanout covers not water tight;

Subsoil drainage system is blocked;

Increase in load profile for battery D-106 and battery D-305 supplying bus D-04 (partial); and

Unit 1 and 2 containment dome trusses differ from design (partial).

The inspectors selected this potential operability issue based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and 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 and two partial samples as defined in IP 71111.15-05. The two partial samples will be completed in the second quarter of 2014.

b. Findings

(1) Failure to Perform Flood Reviews of Material That Could Affect Flood Relief Paths

Introduction:

A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure follow procedures. Specifically, the licensee failed to perform a flood review, as required by NP 8.4.17, PBNP Flooding Barrier / Relief Path Program, Revision 15, when work activities in the G-02 EDG room left a lightweight wet floor safety sign that could have been transported during a license basis internal flood event and affected the flow capacity of the flood relief slots.

Description:

On March 5, 2014, the inspectors observed a lightweight wet floor safety sign in the G-02 EDG room. The inspectors knew that the room had slotted openings to allow internal flood waters to be relieved through the slots to protect the EDG. The inspectors were concerned that the sign would be transported in flood waters and could restrict the flow through the flood protection slots. The inspectors discussed the concern with the licensee, who immediately removed the sign from the room and documented the concern in the CAP. The licensees evaluation concluded that the water would have been deep enough to cause transport and the flow out of the slots would have likely drawn the sign to either of the two flood relief slots and reduced the flow capacity. The inspectors reviewed NP 8.4.17 and found that steps 2.6 through 2.6.3, required, in part, that work affecting a flood mitigation feature would require a flood review to be performed. The inspector inquired if a flood review had been performed for the material left in the G-02 EDG room and the licensee determined that one had not been performed. The inspectors reviewed NP 8.4.7 and found that the flood review considerations included:

determining any potential flood hazards or challenge to a flood mitigation feature;

identifying precautionary actions to be taken before, during and after the work;

identifying any operability challenges for equipment affected, or in the vicinity;

identifying any required actions supporting the basis for proceeding with the work and its compliance with regulatory commitments; and

identifying whether any other compensatory measures, temporary modifications, or permanent modifications are required.

In addition to the material the inspector observed, the inspectors identified examples in the licensees CAP of material improperly stored in rooms that rely on flood relief paths to protect equipment during internal flooding events. The licensee determined that station personnel did not understand the need to protect flood relief paths from material that could be transported and reduce flood relief flow. The licensee concluded, and the inspectors agreed, that the training of the station personnel related to the types of materials that could affect flood relief features was insufficient.

Analysis:

The inspectors determined that the licensees failure to perform a flood review was contrary to the requirements of procedure NP 8.4.17, Revision 15, Steps 2.6 through 2.6.3, and was a performance deficiency. The inspectors determined that the finding was more than minor, because, if left uncorrected, could become a more significant safety concern. Specifically, if the licensee was not performing flood reviews for material left unattended during or after work activities, susceptible unattended material could be transported to credited flood relief dampers and impeded the design flow rate required for the dampers to protect safety related equipment. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 4, External Events Screening Questions, dated June 19, 2012. The inspectors answered yes to question 1 of External Events screening questions since the finding could potentially degrade one train of the emergency power system (a risk significant system). Thus the inspectors consulted the regional SRA.

The SRA performed a detailed risk evaluation using the Point Beach Standardized Plant Analysis Risk Model Version 8.22. For there to be a risk increase due to this deficiency there would have to be a LOOP coincident with a flood event that renders the GO2 EDG unavailable. The SRA performed a bounding analysis assuming that the flood event occurred coincident with a LOOP. The exposure time for the deficient condition was not more than 15-days. Assuming a 15-day exposure time, the delta CDF was 9.3E-08/yr.

The dominant sequence involved a transient initiating event with a consequential LOOP and station blackout. Based on the result of the detailed risk evaluation, the issue is of very low risk significance (Green).

This finding has a cross-cutting aspect of Training (H.9) in the area of human performance, for failing to provide training and ensure knowledge transfer to maintain a knowledgeable workforce. Specifically, the licensee did not ensure that personnel were knowledgeable of need to control material that could transport during an internal flooding event, restrict flood relief paths, and affect flood mitigation features.

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 NP 8.4.17, PBNP Flooding Barrier / Relief Path Program, Revision 15, steps 2.6 through 2.6.3 require, in part, that work affecting a flood mitigation feature requires a flood review to be performed.

Contrary to the above, between February 20 and March 5, 2014, the licensee failed to perform a flood review for work that affected flood mitigation features. Specifically, work activities in the G-02 diesel generator room left material behind that could affect flood mitigation features, for which no flood review was completed. Because this violation was of very low safety significance and the licensee entered it into the CAP as AR 01960472, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000266/2014002-003; 05000301/2014002-003; Failure to Perform Flood Reviews of Material That Could Affect Flood Relief Paths) The licensees short-term corrective actions included removing the material from the G-02 EDG room and communicating to station personnel the importance of not leaving susceptible material unattended. At the conclusion of the inspection period, the licensee was still determining their long-term corrective actions.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

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

post-maintenance testing (PMT) of P-35B, Diesel Fire Pump (Unit 1/2);

PMT of service water valve SW-32C (Unit 1/2);

PMT of the 1P-29 turbine driven AFW pump recirculation line valve controller (Unit 1); and

PMT of 1LT-426, Pressurizer Level Transmitter (Unit 1).

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the 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 post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R20 Outage Activities

Main article: IP 71111.20

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 2 refueling outage (RFO), that began on March 17, 2014, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below:

licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TSs when taking equipment out of service;

installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication;

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

monitoring of decay heat removal processes, systems, and components;

controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system;

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

controls over activities that could affect reactivity;

maintenance of secondary containment as required by TSs;

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

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

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one partial refueling outage sample as defined in IP 71111.20-05. This partial sample will be completed in the second quarter of 2014.

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

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

0-PT-EDG-031; G-03 Emergency Diesel Generator Endurance and Margin Testing (routine);

2RMP 9071-2; A-06 4160/480 Degraded and Loss of Voltage Monthly Surveillance (routine);

IT-04; Unit 2 Low Head Safety Injection Pumps and Valves Train A (inservice testing);

TS 6; Unit 2 Rod Exercise Test (routine);

1ICP 02.003A; Reactor Protection System Logic Train A 31 Day Surveillance Test (routine); and

1ICP 02.005A; Engineered Safety Features System Logic Train A 31 Day Staggered Actuation Logic Test (routine).

The inspectors selected from the following attributes to consider during their inspection of licensee surveillance testing activities:

did preconditioning occur;

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

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

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

as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the 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 Section XI, American Society of Mechanical Engineers (ASME) code, and reference values were consistent with the system design basis;

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

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

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

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

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

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

Documents reviewed are listed in the Attachment to this report.

This inspection constituted five routine surveillance testing sample and, one inservice testing sample, as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

Main article: IP 71124.01

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

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

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

PAB Valve Maintenance Activities;

S/G Handhole Cover Remove/Install;

Cavity Activities; and

Fuel Transfer System Maintenance Activities.

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 used to access high radiation areas and evaluated the specified work control instructions or control barriers:

RWP 14-2015; Cavity Activities;

RWP 14-2020; Keyway Entries;

RWP 14-2031; S/G Handhole Cover Remove/Install;

RWP 14-2034; PAB Valve Maintenance Activities; and

RWP 14-2039; Fuel Transfer System Maintenance Activities.

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

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

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

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee 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, radiation work permits, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of 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 radiation work permits for work within airborne radioactivity areas with the potential for individual worker internal exposures:

RWP 14-2015; Cavity Activities;

RWP 14-2034; PAB Valve Maintenance Activities; and

RWP 14-2039; Fuel Transfer System Maintenance Activities.

For these radiation work permits, 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 (i.e., nonfuel) stored within spent fuel and other storage pools. The inspectors assessed whether appropriate controls (i.e., administrative and physical controls) were in place to preclude inadvertent removal of these materials from the pool.

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

b. Findings

No findings were identified.

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

4OA2 Identification and Resolution of Problems

Main article: IP 71152

.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 Corrective Action Program Reviews

a. Inspection Scope

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

These 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 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 was identifying 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 operator workarounds.

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

b. Findings

No findings were identified.

4OA5 Other Activities

.1 The table below provides a cross-reference from the third and fourth quarter 2013

findings and one carry over item from the first quarter of 2013 and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014, will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting Aspect New Cross-Cutting Aspect 05000266/2013002-10 P.1(c) P.2 05000301/2013002-10 05000266/2013004-01 H.1(b) H.14 05000301/2013004-01 05000266/2013005-01 H.3(a) H.5 05000266/2013005-02 H.1(c) H.10 05000301/2013005-02

4OA6 Meetings Including Exit

.1 Exit Meeting Summary

On April 9 and April 23, 2014, the inspectors presented the inspection results to Mr. E. McCartney, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

the inspection results of the inservice inspection with Mr. R. Harrsch on March 26, 2014; and

the inspection results for the areas of radiological hazard assessment and exposure controls and occupational ALARA planning and controls with Mr. E. McCarthy, Site Vice President, on March 28, 2014.

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

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. McCartney, Site Vice President

R. Webber, Operations Site Director

R. Harrsch, Engineering Site Director

C. Trezise, Director Special Projects

D. Lauterbur, Training Site Manager

F. Hennessy, Performance Improvement Manager

J. Keltner, Chemistry Manager

J. Pruitt, Site Quality Manager

M. Millen, Licensing Manager

R. Clark, Licensing

R. Seizert, Licensing Supervisor

R. Welty, Radiation Protection Manager

S. Forsha, Program Engineering

T. Schneider, Licensing Engineer

W. Jensen, NDE Level III

Nuclear Regulatory Commission

J. Cameron, Chief, Reactor Projects Branch 4

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened

05000266/2014002-01 NCV A Failure to Provide Sufficient Field Overlap to Ensure 100

05000301/2014002-01 Percent Coverage (Section 1R08.1.b(1))

05000266/2014002-02 NCV A Failure to Measure Interpass Temperature

05000301/2014002-02 (Section 1R08.1.b(2))

05000266/2014002-03 NCV Failure to Perform Flood Reviews of Material That Could

05000301/2014002-03 Affect Flood Relief Paths (Section 1R15.b(1))

Closed

05000266/2014002-01 NCV A Failure to Provide Sufficient Field Overlap to Ensure 100

05000301/2014002-01 Percent Coverage (Section 1R08.1.b(1))

05000266/2014002-02 NCV A Failure to Measure Interpass Temperature

05000301/2014002-02 (Section 1R08.1.b(2))

05000266/2014002-03 NCV Failure to Perform Flood Reviews of Material That Could

05000301/2014002-03 Affect Flood Relief Paths (Section 1R15.b(1))

05000266/2013002-01 URI Flooding Impact of Loose Items Found on Roof Tops

05000301/2013002-01 (Section 1R01.1)

LIST OF DOCUMENTS REVIEWED