Text

NRC Integrated Inspection Report 05000266/2015004; 05000301/2015004, October 1, 2015 Through December 31, 2015
	ML16027A268
Person / Time
Site:	Point Beach
Issue date:	01/27/2016
From:	Jamnes Cameron; Reactor Projects Region 3 Branch 4
To:	Mccartney E; Point Beach
References
	IR 2015004
	Download: ML16027A268 (62)
	v • d • e

UNITED STATES ary 27, 2016

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000266/2015004; 05000301/2015004

Dear Mr. McCartney:

On December 31, 2015, 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 January 5, 2016, with Mr. D. DeBoer and other members of your staff.

Based on the results of this inspection, two NRC-identified findings of very low safety significance were identified. These findings involved violations of NRC requirements.

Additionally, one licensee-identified violation is listed in Section 4OA7. 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 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to: (1) the Regional Administrator, Region III; (2) the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and (3) the NRC Resident Inspector 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. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records System (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

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

Enclosure:

IR 05000266/2015004; 05000301/2015004

REGION III==

Docket Nos: 05000266; 05000301 License Nos: DPR-24; DPR-27 Report No: 05000266/2015004; 05000301/2015004 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: October 1, 2015 through December 31, 2015 Inspectors: D. Oliver, Senior Resident Inspector K. Barclay, Resident Inspector E. Coffman, Resident Inspector, V.C. Summer J. Mancuso, Reactor Engineer B. Bartlett, Project Engineer M. Garza, Emergency Preparedness Inspector M. Holmberg, Senior Reactor Inspector V. Myers, Senior Health Physicist Approved by: J. Cameron, Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report 05000266/2015004, 05000301/2015004; 10/01/2015-12/31/2015;

Point Beach Nuclear Plant, Units 1 & 2; Fire Protection and Inservice Inspection (ISI) Activities.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified by the inspectors. The findings involved NCVs of the U.S. Nuclear Regulatory Commission requirements. The significance of inspection findings is 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 April 29, 2015. Cross-cutting aspects are determined using IMC 0310, "Aspects Within the Cross-Cutting Areas," dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," dated February 2014.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and associated Non-Cited Violation of license condition 4.F for the licensees failure to have procedures or instructions to prevent firefighting booster hoses from being kinked and/or twisted on hose reels. Specifically, booster hoses were installed on hose reels in both units containments and in the turbine building (TB), which were twisted and kinked. The licensees corrective actions included rewinding hoses in the Unit 2 containment, four hoses in the TB, and creating compensatory measures for hose reels for the Unit 1 containment.

The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Protection Against External Events (Fire)and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. Specifically, the licensee failed to ensure that activities such as inspection, testing, and maintenance of fire protection systems were prescribed and accomplished in accordance with documented instructions, procedures, and drawings. In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings,

Table 2, the inspectors determined the finding affected the Mitigating Systems cornerstone. The finding degraded fire protection defense-in-depth strategies, and the inspectors determined, using Table 3, that it could be evaluated using Appendix F,

Fire Protection Significance Determination Process. The inspectors screened the issue to Green under the Phase 1 Screening Question 1.3.1-A, because the inspectors determined that the impact of a fire would be limited to one train/division of equipment for the affected fire areas and at least one credited safe shutdown path would be unaffected. This finding has a cross-cutting aspect of Training (H.9), in the area of human performance, because the licensee did not provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce, and instill nuclear safety values. Specifically, the inspectors determined that operations personnel were not adequately trained to recognize deficiencies associated with firefighting equipment standards, such as kinked and twisted hoses on hose reels, and subsequently failed to initiate actions to remedy such conditions. (Section 1R05.1)

Green.

The inspectors identified a finding of very low safety significance and associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to maintain a Unit 2 auxiliary feedwater system (AFW) pipe segment containing linear defects in accordance with the design and material specifications. As a corrective action, the licensee performed light filing to remove the defects from this pipe segment. The licensee entered the failure to maintain the AFW pipe segment in accordance with the design into the corrective action program (CAP) as action request (AR) 02084077, and was evaluating additional corrective actions.

This finding was determined to be more than minor in accordance with IMC 0612,

Appendix B, because if left uncorrected the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the licensees failure to maintain the Unit 2 AFW pipe segment containing linear defects in accordance with the design and material specifications could result in an increase in the possibility of pipe leakage or failure. In addition, the failure to maintain the AFW pipe segment containing linear defects in accordance with the design and material specification adversely affected the Mitigating System Cornerstone attribute of Equipment Performance because it could result in failure of AFW piping which would reduce the availability and reliability of the this mitigating system. The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors answered Yes to screening question A.1 of Exhibit 2. Although this finding adversely affected the design or qualification of the AFW pipe segments, the finding screened as very low safety significance (Green),

because it did not result in the loss of operability or functionality of the affected pipe segment. This finding has a cross-cutting aspect in the Teamwork (H.4) component of the human performance cross-cutting area. Specifically, the licensees Projects Team responsible for the AFW modifications did not effectively communicate and coordinate with the licensees Programs Engineering Group for resolution of the AFW pipe nonconforming conditions to ensure nuclear safety was maintained. (Section 1R08.1)

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

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit operated at or near full power until November 28, 2015, when the unit automatically tripped due to a failure of the main generator voltage regulator circuitry. The unit was restarted December 2, 2015, and reached full power the following day where it remained for the remainder of the inspection period.

Unit 2 The unit began the period at 89 percent power, in coastdown, in preparation for the planned refueling outage (RFO) U2R34. The unit was shut down on October 3, 2015, for U2R34 and was subsequently started up on October 29, 2015, following refueling. The unit achieved and remained at full power on November 3, 2015, until the end of the inspection period.

1.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

Main article: IP 71111.01

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the 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. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

feedwater isolation valves; and

refueling water storage tank.

This inspection constituted one winter seasonal readiness preparations sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

2P-53 (Unit 2 motor-driven auxiliary feedwater {MDAFW} pump) with Unit 2 turbine-driven auxiliary feedwater (TDAFW) pump out-of-service (OOS);

G-02 emergency diesel generator (EDG) with G-04 OOS; and

G-04 EDG after monthly surveillance.

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, 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 to this report.

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

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

Main article: IP 71111.04S

a. Inspection Scope

On October 1, 2015, the inspectors performed a complete system alignment inspection of the Unit 1 and Unit 2 safety injection (SI) system 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 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:

Fire Zone 151: SI pump area;

Fire Zone 304: auxiliary feedwater rooms;

Fire Zone 608: Unit 2 containment 8 elevation; and

Fire Zone 611: Unit 2 containment 21 elevation.

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 OOS, degraded, or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the 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 four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

Failure to Follow Fire Protection Program Requirements for Care, Use and Maintenance of Fire Hose

Introduction:

A finding of very low safety significance and associated NCV of license condition 4.F was identified by the inspectors for the licensees failure to have procedures or instructions to prevent firefighting booster hoses from being kinked and/or twisted on hose reels. Specifically, booster hoses were installed on hose reels in both units containments and in the TB which were twisted and kinked.

Description:

On October 28, 2015, while touring the Unit 2 containment during the U2R34 RFO, the inspectors noted that fire hose reel HR-54 had rigid booster hose which was wound in a manner that caused the hose to twist and kink at the reel attachment fitting. The inspectors were concerned that this condition could prevent the proper flow of firefighting water upon pressurizing the hose on the reel as designed. Additionally the inspectors were concerned that storing the hose with a sharp bend or kink for a long period of time could lead to in-service failure of the hose, which could frustrate firefighting efforts and invalidate fire hazards analysis assumptions. In response to this and other related concerns surrounding the licensees booster hoses, the licensee rewound HR-54 and declared the hose reels in Unit 1 containment non-functional. As a compensatory measure, the licensee staged hoses near the entrance of the Unit 1 containment for use in the event of a fire.

On December 1, 2015, the Unit 1 containment was opened during the unplanned outage discussed in Section 1R20.2 of this report. During the closeout inspection of the Unit 1 containment, inspectors identified hose reels with kinked and twisted booster hoses, similar to the conditions described for HR-54 for the Unit 2 containment. The licensee took no further action since the Unit 1 containment hose reels had already been deemed non-functional based on the discovery of the condition in the Unit 2 containment.

On December 15, 2015, inspectors discovered three booster hoses in the TB that were twisted and kinked at the reel attachment fitting similar to the conditions noted in the Unit 1 and 2 containments. The inspectors were concerned with these hose reels because they were credited for the response to fires in the main control room and vital switchgear areas and could potentially delay firefighting efforts in these areas.

In response to the inspectors concerns, the licensee discovered an additional hose that was kinked on its reel, and rewound each of the TB hoses.

The inspectors review of these issues found that sections 2.3.1.4 and 4.1 of the licensees Fire Protection Evaluation Report (FPER) incorporated National Fire Protection Association (NFPA) standard 1962 (1979 version) by reference. Chapter 3 of NFPA 1962 specified that booster hose shall not be stored kinked, and care shall be taken to avoid twisting when rolling the hose onto a reel. The inspectors reviewed numerous licensee procedures for fire hose installation, service tests, monthly inspections, and storage following use. The inspectors concluded that specific attributes listed in NFPA 1962, such as those mentioned above were required to be, but were not incorporated into these procedures.

Analysis:

The inspectors determined that failure to have procedures or instructions to prevent booster hose from becoming kinked and/or twisted on hose reels was contrary to the licensees FPER and was a performance deficiency. The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Protection Against External Events (Fire) and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. Specifically, the licensee failed to ensure that activities such as inspection, testing, and maintenance of fire protection systems were prescribed and accomplished in accordance with documented instructions, procedures and drawings.

In accordance with IMC 0609, Significance Determination Process, 0609.04, Initial Characterization of Findings, Table 2, the inspectors determined the finding affected the Mitigating Systems cornerstone. The finding degraded fire protection defense-in-depth strategies, and the inspectors determined, using Table 3, that it could be evaluated using Appendix F, Fire Protection Significance Determination Process. The inspectors screened the issue to Green under the Phase 1 Screening Question 1.3.1-A, because the inspectors determined that the impact of a fire would be limited to one train/division of equipment for the affected fire areas and at least one credited safe shutdown path would be unaffected.

This finding has a cross-cutting aspect of Training (H.9), in the area of human performance, because the licensee did not provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce, and instill nuclear safety values. Specifically, the inspectors determined that operations personnel were not adequately trained to recognize deficiencies associated with firefighting equipment standards, such as kinked and twisted hoses on hose reels, and subsequently failed to initiate actions to remedy such conditions.

Enforcement:

License condition 4.F for both Unit 1 and Unit 2 required the licensee to implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR and Safety Evaluation Report dated August 2, 1979, (and Supplements dated October 21, 1980, January 22, 1981, and July 27, 1988) and the Safety Evaluation Report issued January 8, 1997, for TS Amendment No. 170 and No. 174. Section 9.10 of the FSAR stated that the FPER was incorporated into the FSAR by reference. Section 4.2.b of the FPER stated, in part, that activities such as inspection, testing, and maintenance of fire protection systems are prescribed and accomplished in accordance with documented instructions, procedures, and drawings.

Sections 2.3.1.4 and 4.1 of the FPER incorporated NFPA 1962 (1979 version) by reference. Chapter 3 of NFPA 1962 stated that booster hose shall not be stored kinked, and care shall be taken to avoid twisting when rolling the hose onto a reel.

Contrary to the above, until December 15, 2015, the licensee failed to have procedures or instructions to prevent booster hose from being kinked and/or twisted on hose reels, a condition which was identified by inspectors on three separate occasions.

The licensees corrective actions included rewinding hoses in the Unit 2 containment, four hoses in the TB, and creating compensatory measures for hose reels for the Unit 1 containment. Because this violation was of very low safety significance and it was entered into the licensees CAP as AR 02099151, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000266/2015004-01; 05000301/2015004-01, Failure to Follow Fire Protection Program Requirements for Care, Use and Maintenance of Fire Hose).

1R06 Flooding

Main article: IP 71111.06

.1 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions.

The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to flooding:

manhole Z-065A (manhole #1); and

manhole Z-065B (manhole #2).

Specific documents reviewed during this inspection are listed in the Attachment to this report. This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08P

From October 13, 2015 through October 21, 2015, the inspectors conducted a review of the implementation of the licensees ISI Program for monitoring degradation of the reactor coolant system (RCS), steam generator (SG) tubes, emergency feedwater systems, risk-significant piping and components, and containment systems.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors observed the following Non-Destructive Examinations (NDEs) mandated by the American Society of Mechanical Engineers (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:

ultrasonic (UT) examination of reactor closure head studs 17-21; and

visual (VT-1) examination of reactor closure head nuts and washers 17 through 32.

The inspectors observed the following 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:

underwater VT-1 examination of circumferential core barrel weld No. 3 utilizing a remote camera and a fiberscope to meet industry standards MRP-228, Materials Reliability Program: Inspection Standard for Pressurized Water Reactor Internals, and MRP-227, Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines.

The inspectors reviewed the following examinations completed during the previous outages 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:

dye penetrant (PT) examination reports Nos. 451240, 451236, and AR 01950806 that recorded and dispositioned linear indications identified in a Unit 2 base metal pipe segment (P103/2a) near the cross-tie line for the TDAFW system pump; and

PT report No. PT-271 and AR 01384224 that recorded and dispositioned linear indications identified in a Unit 1 base metal pipe segment (F4) near the cross-tie line for the motor driven auxiliary feedwater pump (MDAFWP).

The inspectors reviewed records of the following pressure boundary welds completed for risk-significant systems since the beginning of the last RFO to determine if the licensee applied the preservice NDEs 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:

ASME Code Section XI Class 2 Repair Replacement Activity - Fabrication of AFW pipe welds 35, 38, and 39 to support installation of pipe (DB-3) that provided for a cross-tie connection between the AFW for each Unit.

b. Findings

Inadequate Evaluation of Non-Conforming Auxiliary Feedwater System Pipe Defects

Introduction:

The inspectors identified a finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to maintain a Unit 2 AFW pipe segment containing linear defects in accordance with the design and material specifications.

Description:

In 2010 and 2014, the licensee identified linear defects in the base metal for two AFW pipe segments and subsequently returned these non-conforming pipe segments to service without determination of the extent of the defects (e.g., depth and/or length). The inspectors were concerned that these non-conforming pipe segments posed an increased risk for in-service failure.

On March 22, 2014, during the preparation for welding on an existing Unit 2 AFW system pipe segment (P103/2a) near the cross-tie line for the turbine-driven auxiliary feedwater (TDAFW) pump, the licensee identified linear defects. Specifically, in PT examination report No. 451240, the licensee recorded three linear defects 0.75 inches long and a fourth linear defect 0.5 inch in length. The licensee initially assigned actions to grind on the pipe material to remove these defects or replace this pipe segment. Subsequently, the defects were not removed, nor was the pipe segment replaced. Instead, the licensee documented in AR 01950806 that radiography did not reveal defects in any view. The lines are consistent, but the depth seems to vary some as indicated by the amount of buffing required to make the indication clear completely. UT 0 degree revealed one spot in the buffed area where wall thickness was 0.264 inch. This is just above the 12.5 percent manufacturers tolerance of 0.2625 inch. This is still believed to be a defect caused during the manufacturing process and is original to construction.

It is the opinion of the NDE Engineer that the pipe is satisfactory for continued use.

Therefore, the licensee returned the linear pipe defects to service after attributing the condition to manufacturing defects, and without investigation, to determine if these defects meet the acceptance criteria for the applicable manufacturing code or standard.

On March 8, 2010, during the preparation for welding on an existing Unit 1 AFW system pipe segment (F4) near the cross-tie line for the MDAFWP, the licensee identified linear defects. Specifically, in PT examination report No. 271, the licensee documented that three linear defects each two inches in length remained following buffing on this pipe segment and that these defects continued under the unremoved paint coating. Despite a lack of information on the actual length or depth of these defects, the licensee accepted this condition for service as documented in AR 01384224 which stated:

ISI has reviewed the pictures and determined that the linear indication is a minor surface defect due to hot rolling during the manufacturing process. The linear indication is nearly perfectly straight and of uniform depth. This indication is not a crack since cracks are jagged and follow a path perpendicular or parallel to the metal grain.

In addition, the AR stated:

linear indication is a manufacturing defect which is allowed by code. Per the notes in this AR, and conversation with ISI Program Owner, there is no issue with this indication, and work has already continued. Not a mode hold issue, and can be closed.

Therefore, the licensee returned the linear pipe defects to service after attributing the condition to manufacturing defects, and without investigation, to determine if these defects meet the acceptance criteria for the applicable manufacturing Code or standard.

The applicable design standard for the AFW piping was identified in DG-M03, Point Beach Nuclear Plant Design and Installation Guidelines, Attachment 1, Bechtel Piping Class Specification. This specification required the AFW pipe to meet American Society of Testing and Materials (ASTM) A-106B, Seamless Carbon Steel Pipe for High Temperature Service. ASTM A-106B, Section 20, Finish Step a, stated that, the finished pipe shall be reasonably straight and free from injurious defects, and Step b, Depth of Injurious Defects, stated, all defects shall be explored for depth. When the depth is in excess of 12.5 percent of the nominal wall thickness or encroaches the minimum wall thickness such defects shall be considered injurious. Additionally, ASTM A-106B Paragraph c(1) required machining or grinding defects not classified as injurious must be removed if greater than 5 percent of the pipe wall. For the Unit 1 and Unit 2 AFW pipe segments containing linear defects, the licensee had not explored the depth of the defects and for the Unit 1 pipe segment the length of the three defects was not determined. Therefore, the inspectors were concerned that these AFW pipe segments containing linear defects were non-conforming with respect to the ASTM A-106B specification.

In response to the inspectors concern for these non-conforming AFW pipe conditions, the licensee entered these issues into the CAP. For the Unit 2 AFW pipe segment, the licensee documented in AR 02082787 that the NRC questioned the acceptance criteria applied. Because Unit 2 was in an outage and in a shutdown condition (Mode 6),

the affected system was not required to be operable. On October 20, 2015, the licensee completed follow-up UT and magnetic particle (MT) examination of the affected Unit 2 pipe segment. During the MT examination, the licensee detected a three inch long linear defect in this pipe segment and the UT examination confirmed that the minimum pipe wall measured in the area of previous grinding/buffing near this defect was 0.265 inch thick. The UT examination also confirmed that the nominal pipe wall in this pipe segment was approximately 0.298 inch. Therefore, approximately 11 percent of the material had been removed by grinding prior to detecting the three inch long linear defect during the MT examination. Subsequently, the licensee performed light filing on this defect and completed a PT examination to confirm this defect was removed from this pipe segment. For the Unit 1 AFW pipe segment, the licensee documented in AR 02083211 that the NRC questioned the acceptance criteria applied. Because Unit 1 was in an operating condition (Mode 1), the affected system was required to be operable. The licensee initially determined the pipe segment was operable because the linear defects had been accepted by engineering. The inspectors questions as to the basis for this determination prompted the licensee to provide more information to support immediate operability. Specifically, the licensee completed review of the pipe stress analysis for the affected pipe segment to demonstrate that margins existed to code allowable stress limits and identified that the pipe had successfully passed hydrostatic pressure tests as a basis for immediate operability. On October 23, 2015, the licensee completed follow-up UT and MT examination of the affected Unit 1 pipe segment.

During the MT examination, the licensee detected a 2.75 inch long linear defect in this pipe segment and the UT examination confirmed that the pipe remained above the minimum pipe wall measured in the area of previous grinding/buffing near this defect (e.g. lowest reading was 0.269 inch thick). The licensee noted that the MT examination indication presented only a faint indication (e.g., very little MT powder retained) and elected to confirm if the indication represented a true surface defect by performing a PT examination. Subsequently, the licensee completed a PT examination which did not detect any defects. The licensee attributed the lack of the defects to undocumented grinding/buffing activities which occurred following the 2010 PT examination that originally identified the three linear indications and concluded that the Unit 1 AFW pipe segment was in conformance with the ASTM A-106B material specification.

The licensee entered the failure to maintain the AFW pipe segment in accordance with the design into the CAP as AR 02084077, and evaluated additional corrective actions.

Analysis:

The inspectors determined that the licensees failure to maintain a Unit 2 AFW pipe segment containing linear defects in accordance with the design and material specifications was contrary to 10 CFR Part 50, Appendix B, Criterion III, Design Control, and a performance deficiency.

The inspectors determined that the finding was more than minor in accordance with IMC 0612, Appendix B, because if left uncorrected the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the licensees failure to maintain the Unit 2 AFW pipe segment containing linear defects in accordance with the design and material specifications could result in an increase in the possibility of pipe leakage or failure. In addition, the failure to maintain the AFW pipe segment containing linear defects in accordance with the design and material specification adversely affected the Mitigating System Cornerstone attribute of Equipment Performance because it could result in failure of AFW piping, which would reduce the availability and reliability of this mitigating system.

The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. The inspectors answered Yes to screening question A.1 of Exhibit 2. Although this finding adversely affected the design or qualification of the AFW pipe segments, the finding screened as very low safety significance, because it did not result in the loss of operability or functionality of the affected pipe segment.

This finding has a cross-cutting aspect in the Teamwork (H.4) component of the human performance cross-cutting area. Specifically, the licensees Projects Team responsible for the AFW modifications did not effectively communicate and coordinate with the licensees Programs Engineering group for resolution of the AFW pipe non-conforming conditions to ensure nuclear safety was maintained.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in 10 CFR 50.2 and as specified in the license application, for those structures, systems, and components (SSCs) to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. These measures shall include provisions to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. Measures shall also be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the SSCs.

Procedure DG-M03, Point Beach Nuclear Plant Design and Installation Guidelines, 1, Bechtel Piping Class Specification, required AFW pipe to meet ASTM A-106B Seamless Carbon Steel Pipe for High Temperature Service.

Procedure ASTM A-106B, Section 20, Finish Step a, stated that, The finished pipe shall be reasonably straight and free from injurious defects, and Step b, Depth of Injurious Defects, stated, all defects shall be explored for depth. When the depth is in excess of 12.5 percent of the nominal wall thickness or encroaches the minimum wall thickness such defects shall be considered injurious.

Contrary to the above, on March 22, 2014, for Unit 2 AFW system pipe segment (P103/2a) four defects were identified during PT examination (report No. 451240), which were not explored for depth or removed to ensure that the finished pipe segment was free of injurious defects (AR 01950806). Because this violation was of very low safety significance and was entered into the licensees CAP (AR 02084077), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000301/2015004-02; Inadequate Evaluation of Non-Conforming Auxiliary Feedwater System Pipe Defects).

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

A bare metal VT and non-visual examination of the reactor head upper head penetrations were not required this outage to fulfill the requirements of 10 CFR 50.55a(g)(6)(ii)(D). Additionally, 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 these inspection procedure attributes.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

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

The inspectors reviewed the following licensee evaluations of RCS and connected/affected components with boric acid deposits to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded RCS components to determine if they met the ASME Section XI Code.

Boric Acid Evaluation Screening 14-091, 2RC-506C;

Boric Acid Evaluation Screening 14-152, 2RH-716C; and

Boric Acid Evaluation Screening 14-155, 2RH-706A.

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 01948376; Boric Acid Leak 2S-V-29 Vent Cap;

AR 01948460; Boric Acid Leak 2SI-V-12; and

AR 01949101; Boric Acid Leak 2RC-00506C.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

Examination of the SG tubes was not required this outage pursuant to the Point Beach, Unit 2, TSs. Therefore, no NRC review was completed for this IP 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 CAP 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.

The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, 1R08.4, and 1R08.5 above constituted one ISI sample as defined in IP 71111.08.

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 November 17, 2015, the inspectors observed crew B licensed operators in the plants simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that 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 71111.11-05.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On October 29 and 30, 2015, the inspectors observed reactor startup on Unit 2. This was an activity that required heightened awareness or was related to increased risk.

The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

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

correct use and implementation of procedures;

control board (or equipment) manipulations;

oversight and direction from supervisors; and

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

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 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

incorrect lube oil added to 2P-11A component cooling water (CCW) pump and 1P-28 main feed pump;

multiple failures of the K-2B service air compressor; and

service water pump P-32B failed to start.

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 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:

October 8, 2015: planned shutdown yellow risk for Unit 2 head lift;

October 9, 2015: planned shutdown yellow risk for fuel movement;

October 16, 2015: planned shutdown yellow risk for fuel movement; and

December 17-18, 2015: emergent risk after 2P-11B CCW motor failure.

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 during this inspection 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

No findings were identified.

1R15 Operability Determinations and Functional Assessments

Main article: IP 71111.15

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

AR 02088465: Nitrogen Pressure Reads Zero - NRC Identified (2Q-3 containment penetration);

FA 02004858: Primary Auxiliary Building Flooding Deficiencies;

FA 02093466: Slow Through Wall Leak on U2 CVCS Piping;

FA 02076105: P-35B Fails to Start on Battery 2; and

POD 02095722: Unit 1 - Abandoned 3/8 SS Line Abrading Charging Piping.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and 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 five samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

Main article: IP 71111.18

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

EC 283475; Qualification of Duromar SAR-UW Epoxy Phenolic as a Service Level 3 Repair Coating for Internal Use in the CST [Condensate Storage Tank].

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the FSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with engineering personnel to ensure that the plant modification would not adversely impact overall plant performance. Documents reviewed are listed in the to this report.

This inspection constituted one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

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

2CV-313A; seal water return isolation valve stroke test post-rebuild;

2SI-830B; SI accumulator relief valve leak check following replacement;

2SI-854B; RHR suction from RWST valve stroke test following leak repair;

leak-rate test of 2CC-755B; 2P-1B RCP CC header check valve following maintenance;

Unit 2 TDAFWP air accumulator relief valve leak check following valve replacement; and

Unit 2 TDAFWP pump test following outboard bearing replacement.

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 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 six 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 RFO, conducted October 3 through 30, 2015, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth.

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

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

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

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

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

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

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

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

controls over activities that could affect reactivity;

maintenance of secondary containment as required by TS;

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

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

startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (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.

.2 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for an unscheduled outage that began on November 28, 2015, and continued through December 2, 2015. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The unscheduled outage was required following the automatic reactor trip described in Section

4OA3 of this report. The licensee determined during initial steps of the

subsequent Unit 1 reactor startup, that the N-31 source range nuclear instrument detector failed to exhibit proper response and required replacement. Detector replacement required the licensee to maintain the reactor shutdown and enter the Unit 1 containment. The inspectors observed the reactor shutdown, outage equipment configuration and risk management, control and monitoring of decay heat removal, control of containment activities, personnel fatigue management, startup and heatup activities, and identification and resolution of problems associated with the outage.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

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

ORT 3A: Safety Injection Actuation with Loss of Engineered Safeguards AC (Train A) Unit 2 (Routine);

TS 40 Train A: 2MS-2018 Main Steam Isolation Valve Operability Trip Test Unit 2 (IST); and

Unit 2 Containment Spray Train A Leakage Test (CIV).

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

did preconditioning occur;

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

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

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

as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the 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, ASMEs 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 one routine surveillance testing sample, one in-service test sample, and one containment isolation valve (CIV) sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

Main article: IP 71114.04

.1 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the Emergency Plan, Emergency Action Levels (EALs), and EAL Bases document to determine if these changes decreased the effectiveness of the Emergency Plan.

The inspectors also performed a review of the licensees 10 CFR 50.54(q) change process as well as the Emergency Plan change documentation to ensure proper implementation for maintaining Emergency Plan integrity.

The U.S. Nuclear Regulatory Commission 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. The specific documents reviewed during this inspection are listed in the Attachment to this report.

This EAL and Emergency Plan Change inspection constituted one sample as defined in IP 71114.04-06.

b. Findings

No findings were identified.

2.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

Main article: IP 71124.01

.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 the 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 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 were appropriate for the given radiological hazard.

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

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

RWP 15-2016: removal/reinstall reactor vessel (RV) head;

RWP 15-2018: seal table activities;

RWP 15-2020: keyway entries; and

RWP 15-2033: primary auxiliary building (PAB) valve maintenance activities.

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

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

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

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee 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 VT 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 a NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

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

RWP 15-2016: remove/reinstall RV head;

RWP 15-2018: seal table activities; and

RWP 15-2033: PAB valve maintenance.

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 (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)

.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.

This inspection constituted one complete sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

4.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Mitigating Systems Performance IndexResidual Heat Removal System

.6 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent Technical Specification (RETS)/Offsite Dose Calculation Manual (ODCM) radiological effluent occurrences PI for the period from the third quarter 2014 through the second quarter 2015. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates to determine if indicator results were accurately reported.

The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

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 IPs 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

The licensee identified a finding and an associated NCV which is documented in Section

4OA7 of this report.

.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 or equivalent.

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 Follow-up of Selected Issues: Containment Electrical Penetration 2Q-3 Does

Not Hold Nitrogen Pressure

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting a depressurized containment electrical penetration for the Unit 2 containment. Specifically, the licensee responded to observations made by inspectors noting that the containment electrical penetration, 2Q-03, nitrogen pressure gauge indicated that the penetration was completely depressurized only two days after maintenance was performed to check and re-pressurize this assembly.

The inspectors performed a detailed review of the licensees corrective actions for 2Q-03 and other similar containment electrical penetrations, as well as a review of the licensees containment leak rate testing program. Specifically, the inspectors verified the following attributes during their review of the licensees corrective actions for the containment penetration:

Complete, accurate and timely documentation of the identified problem in the CAP;

consideration of the extent of condition, generic implications, common cause, and previous occurrences;

classification and prioritization of the resolution of the problem, commensurate with safety significance;

action taken in the correction of the identified problem;

identification of negative or worsening short-term trends associated with equipment performance either directly or indirectly caused by actively leaking component; and

operating experience was adequately evaluated for applicably, and lessons learned were and are intended to be communicated to the appropriate organizations for implementation.

Observations: The inspectors conducted a historical review of the condition and included penetrations of both Unit 1 and 2 containments to evaluate the licensees corrective actions respective to the attributes listed above. Inspectors determined that the condition had existed for this single penetration since the late-1990s. Several ARs were written for this condition since it was first identified, and inspectors determined that the licensee has had several opportunities to replace the assembly during previous Unit 2 RFOs but has opted to scope the work out of each outage in favor of other priorities during latter stages of outage planning. The inspectors also determined that the licensee included this penetration in their 10 CFR Part 50, Appendix J containment leak testing program and was performing leak-rate testing on this assembly at regular intervals. This penetration had at one time been evaluated as operable but non-conforming and was being monitored as a maintenance rule a(1) status component, but was deemed fully operable and was removed from maintenance rule a(1) by this inclusion in the containment leak rate testing program. The inspectors concluded that ultimately this penetration and the overall containment leakage is being monitored and trended in accordance with the requirements of NEI 94-01; Industry Guidance for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J; July 26, 1995, which has been endorsed by the NRC.

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

b. Findings

No findings were identified.

.4 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue.

The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 1, 2015 through December 31, 2015, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in 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 one semi-annual trend inspection sample as defined in IP 71152-05.

Observations: During the course of the review period for this inspection sample, the inspectors noted several examples where the licensee's handling and control of lubricating oil had led to the wrong oil being added to components. Although these errors did not result in any immediate adverse consequences, a potential trend in this area is apparent and suggests that additional licensee attention to effect corrective actions may be appropriate. Specific examples associated with this trend included, but were not limited to:

July 16, 2015: the licensee identified two barrels of waste oil in the TB that were not labeled and were not being controlled in accordance with the licensees chemical control program requirements.

August 11, 2015: abnormal color was noted from oil changed from the Unit 2 CCW pump outboard bearing. A detailed analysis of the oil and operability determination was made, which concluded that the wrong oil had been added to the bearing oiler during maintenance as a result of a human performance error.

The wrong oil was identified by analysis and was determined to be the same base oil, but with additives which served to provide additional protection from corrosion and wear. The licensee determined that no detrimental effect resulted from this condition.

September 16, 2015: the licensee determined that the wrong oil was added to the Unit 1 B SG feed pump (non-safety related). Analysis of the oil indicated elevated levels of phosphorous and calcium, and a higher viscosity. Based on the properties of the oil contamination, the licensee determined that feed and bleed of the oil was required to prevent damage to the pump bearings. The licensee later determined that cross-contamination had likely occurred via a rig used for filling EH system fluid.

September 17, 2015: the licensee discovered the door for the lube oil storage room unlocked. The unlocked door was meant to be used to control access to quality-controlled lubricants. Upon inspection of the room, the licensee discovered several deficiencies, including industrial safety problems and containers which appeared to have been used to store and transfer several different oil types.

October 6, 2015: the licensee identified that the barrels identified in Julys AR were now labeled; however, they lacked the detail required by the chemical control program procedures.

October 16, 2015: the licensee identified improperly labeled oil in a storage cabinet.

October 27, 2015: licensee maintenance personnel removed a barrel of oil from the lube oil storage room labeled as new. This oil was intended to be added to both of the Unit 2 SG feed pumps; however, maintenance personnel noted that the oil looked dark and dirty. Engineering personnel were contacted and determined that the barrel actually contained waste oil and was not properly labelled.

December 4, 2015: the licensee received the results of oil sample analysis from the Unit 2 TDAFWP which had elevated levels of phosphorous, which was abnormal for this pump. The licensee determined that the cause was likely due to contamination during oil change maintenance. The licensee concluded that the AFW pump remained operable based on factors of contamination levels, viscosity, and the required mission time for the safety-related pump.

Each of the observations above represented failures of the licensees implementation of their programs for the storage, use, and handling of chemical as well as control of quality materials and were entered into their CAP. Many of the oils stored in the lube oil storage room may be interchangeably used for safety and non-safety applications. At the time, no adverse impacts have resulted from the licensees demonstrated weaknesses in this area for safety-related equipment that could be determined as more-than-minor.

b. Findings

No findings were identified.

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

Main article: IP 71153

.1 Unit 1 Main Generator Lock-out and Automatic Reactor Trip

a. Inspection Scope

On November 28, 2015, at 7:12 p.m., operators received several alarms associated with the Unit 1 main generator voltage regulator followed by a Generator Lockout alarm and a subsequent automatic reactor trip from full power. All equipment functioned as designed, including the AFW system that automatically started on low SG water level.

The licensees investigation revealed that a transducer failed within the main generator voltage regulator circuitry. The licensee repaired the voltage regulator, and commenced a reactor startup on November 30, 2015. Prior to reaching criticality, the licensee re-inserted all control rods due to operators observing a lack of proper response from the N-31 source range nuclear instrument. The licensee then entered a forced outage to replace the N-31 source range nuclear instrument detector as documented in Section 1R20.2 of this report.

The inspectors responded to the site immediately following the reactor trip and verified that the trip was uncomplicated by any significant equipment or human performance issues. Several minor equipment issues were reviewed by the inspectors to verify that plant operators were appropriately compensating for the issues in accordance with plant procedures.

This event was reported by the licensee (event number 51570) in accordance with 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A), for the automatic actuation of a reactor trip and the automatic system actuation of the AFW system.

A reactor startup was commenced on December 2, 2015, and the main generator was synchronized to the grid later that day. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

a. Inspection Scope

The inspectors reviewed the final report for the INPO plant evaluation conducted in August 2015. The inspectors reviewed the report to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC follow-up.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 5, 2016, the inspectors presented the inspection results to Mr. D. DeBoer, Plant General Manager, and other members of the licensee staff. The licensee acknowledged the issues presented.

.2 Interim Exit Meetings

Interim exits were conducted for:

The inspection results for the areas of radiological hazard assessment and exposure controls; and RCS specific activity, occupational exposure control effectiveness, and RETS/ODCM radiological effluent occurrences performance indicator verification were discussed with Mr. E. McCartney, Site Vice President, on October 16, 2015.

The inspection results for ISI were discussed with Mr. E. McCartney, Site Vice President, on October 21, 2015.

The annual review of EAL and Emergency Plan changes were discussed with Mr. R. Seizert, Emergency Preparedness Manager, on November 13, 2015.

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 violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements; it meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

The licensee identified a finding of very low safety significance (Green) and an NCV of TS 5.4.1, Procedures for the failure to maintain the emergency operating procedures (EOPs).

The licensees TS 5.4.1 required, in part, that written procedures shall be maintained including the EOPs required to implement the requirements of NUREG-0737 and to NUREG-0737, Supplement 1, as stated in Generic Letter 82-33. During design reviews, the licensee discovered that following a 2012 calculation update, the licensee inconsistently applied pre and post-modification uncertainties that had resulted from a 2010 modification associated with the sensitivity and calibration of both units Subcooling Margin Monitors. Ultimately the calculative errors resulted in 19 EOP Subcooling setpoints being incorrectly calculated. These Subcooling setpoints are used throughout the licensees EOPs network to provide operators with discrete indications for key EOP decision making.

Contrary to the above, from April 12, 2012 through November 5, 2015, the licensees EOP network of procedures for both Unit 1 and 2, contained the incorrect setpoints for decision points with respect to subcooling. The licensee entered this issue into the CAP as AR 02089011 and AR 02099152.

The inspectors consulted the Region III Senior Reactor Analysts and determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated July 1, 2012 and IMC 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, dated July 1, 2012. The inspectors determined that the issue was a design or qualification deficiency confirmed not to result in a loss of operability; therefore, answered yes to question A.1 in Exhibit 2, Section A, Mitigating SSCs and Functionality. This resulted in the finding screening as Green.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. McCartney, Site Vice President

D. DeBoer, Plant General Manager

S. Aerts, Performance Improvement Manager

S. Forsha, Principal Engineer

D. Forter, Project Site Manager

B. Gerbers, Engineering Supervisor

R. Harrsch, Engineering Site Director

L. Hawki, Engineering Site Manager-ERRT

W. Jensen, Principal Engineering Analyst

B. Kopetsky, Security Site Manager

T. Lesniak, Mechanical Department Head

S. Manthei, Senior Engineer

S. Merriner, Maintenance Section Supervisor

M. Millen, Senior Project Manager

C. Neuser, Engineering Site Manager-Systems

R. Parker, Chemistry Manager

E. Schmidt, Engineering Site Manager-Programs

T. Schneider, Senior Engineer

E. Schultz, Operations Assistant Manager-Line

R. Seizert, Emergency Preparedness Manager

G. Strharsky, Site Quality Manager

R. Webber, Operations Site Director

R. Welty, Radiation Protection Manager

P. Wild, Design Engineering Manager

B. Woyak, Licensing Manager

Nuclear Regulatory Commission

J. Cameron, Chief, Reactor Projects Branch 4

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000266/2015004-01 NCV Failure to Follow Fire Protection Program Requirements

05000301/2015004-01 for Care, Use and Maintenance of Fire Hose

(Section 1R05.1)

05000301/2015004-02 NCV Inadequate Evaluation of Non-Conforming Auxiliary

Feedwater System Pipe Defects (Section 1R08.1)

Closed

05000266/2015004-01 NCV Failure to Follow Fire Protection Program Requirements

05000301/2015004-01 for Care, Use and Maintenance of Fire Hose

(Section 1R05.1)

05000301/2015004-02 NCV Inadequate Evaluation of Non-Conforming Auxiliary

Feedwater System Pipe Defects (Section 1R08.1)

LIST OF DOCUMENTS REVIEWED