IR 05000266/2015003

IR 05000266/2015003, 05000301/2015003; on 07/01/2015 - 09/30/2015; Point Beach Nuclear Plant, Units 1 & 2; Operability Determinations and Functionality Assessments and Follow-Up of Events and Notices of Enforcement Discretion

ML15302A428
Person / Time
Site:	Point Beach
Issue date:	10/29/2015
From:	Cameron J L Reactor Projects Region 3 Branch 4
To:	McCartney E Point Beach
References
IR 2015003
Download: ML15302A428 (67)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION III 2443 WARRENVILLE RD. SUIT E 210 LISLE, IL 60532

-4352 October 29, 2015 Mr. Eric McCartney Site Vice President NextEra Energy Point Beach, LLC 6610 Nuclear Road

Two Rivers, WI 54241

SUBJECT: POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2

- NRC INTEGRATED INSPECTION REPORT 05000 266/20 15003; 05000 301/20 15003

Dear Mr. McCartney:

On September 30, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed a n inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on October 14, 2015, with you and other members of your staff.

Based on the results of this inspection, three NRC-identified findings of very low safety significance were identified. Two of the findings involved violation s 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 n on-cited violation s (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of these NCV s, 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 the Regional Administrator, U.S. Nuclear Regulatory Commission , Region III; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and 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 NRC's Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading

-rm/adams.htm l (the Public Electronic Reading Room).

Sincerely,

/RA John Rutkowski Acting for/

Jamnes Cameron, Chief Branch 4 Division of Reactor Projects

Docket Nos. 50

-266; 50-301 License Nos. DPR-24; DPR-27 Enclosure:

IR 05000 266/20 15003; 05000301/20 15003 w/Attachment: Supplemental Information cc w/encl: Distribution via LISTSERV

Enclosure U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos:

05000 266; 050003 01 License Nos:

DPR-24; DPR-27 Report No:

05000 266/20 15003; 050003 01/20 15003 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: July 1, 2015 through September 30, 2015 Inspectors:

D. Oliver, Senior Resident Inspector K. Barclay, Resident Inspector E. Coffman, Acting Senior Resident Inspector J. Mancuso, Acting Resident Inspector R. Baker, Operations Engineer B. Bartlett, Project Engineer V. Myers, Senior Health Physicist B. Palagi, Senior Operations Engineer J. Rutkowski, Project Engineer Approved by:

J. Cameron, Chief Branch 4 Division of Reactor Projects

SUMMARY OF FINDINGS

................................

................................................................

......... 4

REPORT DETAILS

................................

................................................................

...............

7 Summary of Plant Status

................................

................................................................

REACTOR SAFETY

................................

................................................................

.. 7

1R01 Adverse Weather Protection

................................

...........................

1R04 Equipment Alignment

................................

...................................... 8

1R05 Fire Protection

................................

................................................

1R06 Flooding

................................

........................................................

10 1R07 Annual Heat Sink Performance (71111.07)

................................

......................

1R11 Licensed Operator Requalification Program

................................

..11

1R12 Maintenance Effectiveness

............................................................

1R13 Maintenance Risk Assessments and Emergent Work Control

.......16 1R15 Operability Determinations and Functional Assessments (71111.15)

..............

1R19 Post-Maintenance Testing

................................

.............................

1R22 Surveillance Testing

................................

......................................19 1EP6 Drill Evaluation (71114.0 6) ................................

..............................................

RADIATION SAFETY

................................

...............................................................

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and Transportation

................................

..........................

OTHER ACTIVITIES

................................

................................................................

===.25

=

................................

......................

4OA2 Identification and Resolution of Problems

................................

...........

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

..............

4OA5 Other Activities

................................

................................................................

.......42

4OA6 Management Meetings

................................

....................................................

4OA7 Licensee-Identified Violations

................................

..........................................

43

SUPPLEMENTAL INFORMATION

................................

.............................................................

Key Points of Contact

................................

................................................................

.............

List of Items Opened, Closed, and Discussed

........................................................................ 2 List of Documents Reviewed

................................

................................................................

.. 3 List of Acronyms Used

................................

................................................................

...........

SUMMARY OF FINDINGS

Inspection Report

(IR) 05000266/2015003, 05000301/2015003; 07/01/2015-09/30/2015; Point Beach Nuclear Plant, Units 1 & 2;

Operability Determinations and Functionality Assessments

and Follow

-Up of Events and Notices of Enforcement Discretion.

This report covers a 3

-month period of inspection

by resident inspectors and announced baseline inspections by regional inspectors. Three Green finding s were identified by the inspectors.

Two of the finding

s were considered NCVs of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC)

0609, "Significance Determination Process" dated

June 2, 2011. Cross-cutting aspects are determined using IMC 0310, "Aspects Within the Cross

-Cutting Areas" effective date December

4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy dated February

4, 2 015. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG

-1649, "Reactor Oversight Process" Revision 5, dated February

2014. Cornerstone: Mitigating Systems

Green. The inspectors identified a finding of very low safety significance for the licensee's failure to follow procedure EN

-AA-203-1001, "Operability Determinations/Functionality Assessments," Revision 19. Specifically, when the licensee identified that internal flood sources in the

diesel generator building (DGB) were larger than the

drain capacity, they failed to identify all affected structures, systems, and components (SSCs). The DGB contains predominately

Train B emergency power systems; however, the

fuel oil transfer pumps for the

Trai n A emergency diesel generators are located in the southeast corner of the

building. The licensee failed to assess the effects of flooding on the

Train A fuel oil transfer pumps. The

licensee's corrective actions included the creation of an adverse condition monitoring plan, which implemented an hourly flood watch in the

DGB when the fire pump was manually started.

T he inspectors determined that the

finding was more than minor

, because if left uncorrected

, it would potentially result in a more safety significant issue. Specifically, the failure to evaluate the effects of flooding on all SSCs resulted in inadequate compensatory measures

. The inspectors determined the finding could be evaluated using the significance determination process (SDP) in accordance with IMC

0609, "Significance Determination Process," Attachment

0609.04, "Initial Characterization of Findings," dated

June 19, 2012, and Appendix

A, "The Significance Determination Process for Findings At

-Power," Exhibit

2, "Mitigating Systems Screening Questions," dated June 19, 2012. For the time period in question, Ma

y 17 , 2015 to September 17, 2015, the inspectors reviewed the security door card reader reports and starting sump levels for the DGB and found that during times when the fire pumps were running, station personnel had toured the DGB at a frequency that would have identified

flooding conditions before a loss of system function. The

inspectors concluded that the finding was of very low safety significance (Green), because the

inspectors answered "No" to the Mitigating Systems screening questions. This finding has a cross

-cutting aspect of Evaluation (P.2), in the area of Problem Identification and Resolution

(PI&R), for failing to thoroughly evaluate issues to ensure that resolutions address causes and

extent of conditions commensurate with their safety significance.

(Section 1R 15.1)

Green. 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

licensee's failure to ensure that a non

-Category I (seismic) component failure, that results in flooding, would not adversely affect safety

-related equipment needed to get the plant to safe shutdown (SSD) or to limit the consequences of an accident. Specifically, the design of Point Beach did not ensure that the Residual Heat Removal (RHR) pumps would be protected from all credible non

-Category I (seismic) system failures. The licensee's corrective actions included an extensive internal flooding design review, which will result in an updated Final Safety Analysis Report (FSAR)

with a more detailed description of the station

's flooding licensing basis; modifications to multiple flood barriers to bring

them into compliance with the

licensee's flooding licensing basis; installation of additional flood level alarms where necessary, and evaluation or modification of service water

(SW) piping to properly qualify it

as seismic.

The inspectors determined that

the finding was more than minor because it was associated with the Design Control attribute of the Mitigating System cornerstone and

affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate design resulted in an unanalyzed condition and loss of

safety function of the RHR system while the plants were in Modes

4, 5, and 6, when relying on the RHR system for decay heat removal. The

inspectors determined the finding could be evaluated using the SDP in accordance with IMC

0609, "Significance Determination Process," Attachment

0609.04, "Initial Characterization of Findings," dated June 19, 2012, and Appendix

A, "The Significance Determination Process for Findings At

-Power," Exhibit

2, "Mitigating Systems Screening Questions," dated June 19, 2012. The

inspectors answered "yes" to question 2 of the screening questions because the finding represented a loss of safety function. Thus the

inspectors consulted the Region III Senior Risk Analysts (SRAs) who performed a detailed risk evaluation and determined that the

finding was of very low safety significance (Green). The inspectors determined that the associated finding did not have a cross

-cutting aspect because the finding was not reflective of current performance.

(Section 4OA3.1) Green/SLIV. The inspectors identified

a Severity Level IV

NCV of 10 CFR 50.59(d)(1), "Changes, Tests, and Experiments," and an associated finding of very low safety significance for the

licensee's failure to perform a safety evaluation to demonstrate that the removal of statements from the FSAR did not require a license amendment. Specifically, the

licensee failed to perform a safety evaluation to determine whether removing an FSAR statement, which defined the RHR pump cubicle design flood height as seven feet, could be performed without a license amendment. The licensee entered the deficiency in their CAP as Action Request

(AR) 02069425 by which the licensee intends on re

-evaluating the 1996 FSAR chan

g e. The inspectors determined that the finding was more than minor because the finding, if left uncorrected, would become a more significant safety concern. Specifically,

inappropriately removing the information from the FSAR allowed the

licensee to decrease the design basis flood protection height of the RHR compartments and significantly reduced the available time to isolate the leaking RHR pump seal. Violations of 10 CFR 50.59 are dispositioned using the traditional enforcement process instead of the SDP because they are considered to be violations that potentially impede or impact the regulatory process. In addition, the associated violation was determined to

be more than minor because the inspectors could not reasonably determine that the changes

would not have ultimately required NRC prior approval. The

inspectors determined the finding could be evaluated using the SDP in accordance with IMC

0609, "Significance Determination Process," Attachment

0609.04, "Initial Characterization of Findings," dated June 19, 2012, and Appendix

A, "The Significance Determination Process for Findings At

-Power," Exhibit

2, "Mitigating Systems Screening Questions,"

dated June 19, 2012. The inspectors concluded that the finding was of very low safety significance (Green), because the inspectors answered "No" to the Mitigating Systems screening questions. The

inspectors determined that the associated finding did not have a cross-cutting aspect because the

finding was not reflective of current performance.

(Section 4OA3.1) Licensee-Identified Violations

Cornerstone: Barrier Integrity

A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's CAP. This violation and associated CAP tracking number are listed in Section

4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit operated at or

near full power for the inspection period, except for brief power reductions to conduct planned maintenance and surveillance activities.

Unit 2 The unit operated at or near full power for the inspection period, except for brief power reductions to conduct

planned maintenance and surveillance activities

with two exceptions

. On September 8, 2015, reactor power was reduced to 97

percent in response to a momentary closure of a governor valve. The unit was subsequently restored to full power on the same day.

On September 1 6 , 2015 the unit entered coastdown in preparation for the upcoming scheduled refueling outage

(RFO), U2R34. Unit 2 remained in coastdown through the end of the inspection period, finishing the period at

9 percent power.

1. REACTOR SAFETY

Cornerstone s: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

(71111.01)

.1 External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the design basis wave run-up flooding event. The evaluation included a review to verify that systems required to be protected from the wave run

-up event, which included the SW pumps, Train A emergency diesel generators, 1A

-05 and 2A-05 4160 volt safety-related distribution buses, and turbine driven auxiliary feed water pumps, were protected from the adverse effects of the wave event. As part of this evaluation, the inspectors reviewed the licensee's abnormal operating procedure (AOP) and other implementing procedures for mitigating the design basis wave run-up event to ensure that they could be implemented as written.

The inspectors inspected portions of the pre-staged flood barrier inventory to confirm that the temporary flood barriers were stored in the correct location, contained the correct number of barriers, and that the

barriers were in good material condition. The inspectors also confirmed that cabinet seal serial numbers on multiple sand bag storage cabinets matched the last recorded serial numbers from the previous inventory. The inspectors walked down portions of the

protected area between the

SW pump house and the turbine building to confirm that no structural gaps or leakage paths existed that could have bypassed flood barriers. Documents reviewed are listed in the

to this report.

This inspection constituted one external flooding sample as defined in Inspection Procedure (IP)

71111.01-05.

b. Findin gs No findings were identified.

.2 Readiness For Impending Adverse Weather Condition

-Heavy Rainfall/External Flooding Conditions

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the expected flooding conditions based on predicted rainfall. As part of this evaluation, the inspectors

observed the licensee as they implemented their AOP attachment for potential flooding concerns. The observation included walking down the turbine building, primary auxiliary building, and circulating water pump house to confirm that no flooding conditions affecting safety

-related equipment were in progress. Additionally, the inspectors

checked for obstructions that could prevent draining, verified that the submersible pumps and associated hoses were properly staged, and confirmed that

cabinet seal serial numbers on multiple sand bag storage cabinets matched the last recorded serial numbers from the previous inventory. The

inspectors also walk ed down portions of the protected area and confirmed that no obstructions or gaps existed which would inhibit site drainage during the predicted flood conditions or allow water ingress past a barrier. Documents reviewed are listed in the

to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in IP

71111.01-05. b. Findings No findings were identified.

1R04 Equipment Alignment

(71111.04)

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk

-significant systems: 1P-35B diesel driven fire pump after testing; 2P-29 turbine

-driven auxiliary feedwater pump after testing; and

G-03 emergency diesel generator (EDG) following enduranc e run. 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. Doc

uments reviewed are listed in the Attachment to this report.

These activities constituted three partial system walkdown sample

s as defined in

IP 71111.04-05. b. Findings No findings were identified.

1R05 Fire Protection

(71111.05)

.1 Routine Resident Inspector Tours (71111.05Q)

a. Inspection Scope

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

Fire Z one 187: central tank area;

Fire Z one s 552 and 553: SW and circulating water (CW) pump room s; Fire Zone s 770 and 773: G-03 diesel and switchgear rooms

Fire Zone 771

'A' EDG fuel oil pump room;

and Fire Zone s 775 and 777

G-04 diesel and switchgear rooms

. The inspectors reviewed areas to assess if the

licensee had implemented a

FP program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive FP features in good material condition, and implemented adequate compensatory measures for

out-of-service (OOS), degraded or inoperable

FP equipment, systems, or features in accordance with

the licensee's fire plan. The

inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's 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 plant's ability to respond to a security event. Usi

ng the documents listed in the

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

licensee's CAP. Documents

reviewed are listed in the

to this report.

These activities constituted five quarterly fire protection inspection samples as defined in

IP 71111.05-05.

b. Findings No findings were

identified.

.2 Annual Fire Protection Drill Observation

(71111.05A)

a. Inspection Scope

On September 22, 2015, the inspectors observed a fire brigade activation

for a simulated fire in the T

-32A and B fuel oil storage tanks. Based on this observation , the inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the

licensee staff identified deficiencies

, openly discussed them in a self

-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

proper wearing of turnout gear and self

-contained breathing apparatus;

proper use and layout of fire hoses;

employment of appropriate firefighting techniques;

sufficient firefighting equipment brought to the scene

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

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

utilization of pre

-planned strategies;

adherence to the pre-planned drill scenario; and

drill objectives.

Documents reviewed are listed in the

to this report.

These activities constituted one

annual fire protection inspection sample as defined in

IP 71111.05-05. b. Findings No findings were identified.

1R06 Flooding (71111.06)

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety

-related equipment from internal flooding events. The

inspectors reviewed flood analyses and design

documents, including the FSAR, engineering calculations, and abnormal

operating procedures to identify licensee commitments. The specific documents reviewed are listed in

th e Attachment to this report. In addition, the

inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the

failure or misalignment of nearby sources of water, such

as the fire suppression or the CW systems. The

inspectors also reviewed the

licensee's corrective action documents with respect to past flood

-related items identified in the CAP to verify the adequacy of the corrective actions. The

inspectors performed a walkdown of the following plant area(s) to assess the adequacy of watertight doors and verify drains and

sumps were clear of debris and were operable, and that the

licensee complied with its commitments:

CW pump house; and

G-03/G-04 EDG building. Documents reviewed during this inspection are listed in the

to this report.

This inspection constituted two internal flooding sample

s as defined in IP

71111.06-05. b. Findings No findings were identified.

1R07 Annual Heat Sink Performance

(71111.07)

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensee's

testing of

the HX-13A; Train A s pent f uel pool (SFP) heat exchanger to verify that potential deficiencies did not mask the licensee's ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the

licensee was

adequately addressing problems that could result in initiating events that would cause an increase in risk. The

inspectors reviewed the

licensee's observations

as compared against acceptance

criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test

results. Inspectors also verified that test acceptance

criteria considered differences between test conditions, design conditions, and testing conditions. Documents reviewed for th

is inspection are listed in the

to this document.

This annual heat sink performance inspection constituted one

sample as defined in

IP 71111.07-05. b. Findings No findings were identified.

1R11 Licensed Operator Requalification Program

(71111.11)

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

(71111.11Q)

a. Inspection Scope

On September 9, 2015, the inspectors observed

the licensed operators annual operating examination for crew

A in the plant's simulator during licensed operator requalification training (LORT) to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems

, and training was being conducted in accordance with licensee

procedures. The

inspectors evaluated the following areas:

licensed operator performance;

crew's 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 crew's performance in these areas was compared to pre

-established operator action expectations and successful critical task completion requirements. Documents reviewed

are listed in the

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 July 17, 2015, the inspectors observed

TS-6 with FLUX measurements and pre-outage control rod drive

resistance checks

. This was an activity that required heightened awareness and had an associated increased risk. The

inspectors evaluated the following areas:

licensed operator

performance;

crew's 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

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.

.3 Biennial Written and

Annual Operating Test Results

(71111.11A)

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Test, as administered by the licensee from August

10, 2015 through September

18, 2015, and required by

CFR Part 55.59(a). The results were compared to the thresholds established in IMC 0609, Appendix

IProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609, Appendix</br></br>I" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., "Licensed Operator Requalification Significance Determination Process," to

assess the overall adequacy of the

licensee's LORT Program to meet the requirements of 10

CFR 55.59. This inspection constituted one annual licensed operator requalification inspection sample as defined in IP

71111.11A.

b. Findings No findings were identified.

.4 Biennial Review

(71111.11B)

a. Inspection Scope

The following inspection activities were conducted during the week of

August 31, 2015, to assess: (1) the effectiveness and adequacy of the facility licensee's implementation and maintenance of its Systems Approach to Training (SAT) based LORT Program implemented to satisfy the requirements of 10

CFR 55.59; (2) conformance with the requirements of 10

CFR 55.46 for use of a plant reference simulator to conduct operator licensing examinations and

for satisfying experience requirements; and (3) conformance with the operator license conditions specified in 10

CFR 55.53. Documents reviewed are listed in the Attachment

to this report

. Problem Identification and Resolution (10

CFR 55.59(c); SAT Element 5 as Defined in 10

CFR 55.4): The inspectors evaluated the

licensee's ability to assess the effectiveness of its LORT program and their ability to implement appropriate corrective actions to maintain its LORT Program up

-to-date. The inspectors reviewed

documents related to the plant's operating history and associated responses (e.g., Plant Issues Matrix and Plant Performance Review Reports; recent examination and

IRs; and Licensee Event Reports

(LERs). The inspectors reviewed the use of feedback from operators, instructors, and supervisors, as well as the use of feedback from plant events and industry experience information. The inspectors reviewed the

licensee's

quality assurance (QA) oversight activities, including licensee training department self-assessment reports.

Licensee Requalification Examinations (10

CFR 55.59(c); SAT Element 4 as Defined in 10

CFR 55.4): The inspectors reviewed the licensee's program for development and administration of the LORT biennial written examination and annual operating tests to assess the licensee's ability to develop and administer examinations that were acceptable for meeting the requirements of

CFR 55.59(a).

- The inspectors reviewed the methodology used to construct the examination

including content, level of

difficulty, and general quality of the examination/test materials. The inspectors also assessed the level of examination material duplication from week

-to-week for both the operating tests conducted during 2014 and the current year, as well as the writte

n

examinations administered in 2014. The inspectors reviewed a sample of

the written examinations and associated answer keys to check for consistency and accuracy.

- The inspectors observed the administration of the annual operating test to assess the licensee's effectiveness in conducting the examinations, including the conduct of pre

-examination briefings, evaluations of individual operator and crew performance, and post-examination analysis. The

inspectors evaluated the performance of one crew, Team 1 and Team 2, in parallel with the facility evaluators during four dynamic simulator scenarios, and evaluated various licensed crew members concurrently with facility evaluators during the administration of several job performance measures.

- The inspectors assessed the adequacy and effectiveness of the remedial training conducted since the last requalification examination and the training planned for the current examination cycle to ensure that the

licensee addressed weaknesses in licensed operator or crew performance identified during training and plant operations. The

inspectors reviewed remedial training procedures and individual remedial training plans.

Conformance with Examination Security Requirements (10

CFR 55.49): The inspectors conducted an assessment of the licensee's processes related

to examination physical security and integrity (e.g., predictability and bias) to verify compliance with 10

CFR 55.49, "Integrity of Examinations and Tests

." The inspectors reviewed the facility licensee's examination security

procedure, and observed the implementation of physical security controls (e.g., access restrictions and simulator input/output (I/O) controls) and integrity measures (e.g., security agreements, sampling criteria, bank use, and test item repetition) throughout the inspection period.

Conformance with Simulator Requirements (10

CFR 55.46): The inspectors assessed the adequacy of the licensee's simulation facility (simulator) for use

in operator licensing examinations and for satisfying experience requirements. The inspectors reviewed a sample of simulator performance test records

(e.g., transient tests, malfunction tests, scenario based tests, post

-event tests, steady state tests, and core performance tests), simulator discrepancies, and

the process for ensuring continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The inspectors reviewed and evaluated the discrepancy corrective action process to ensure that simulator fidelity was being maintained.

Open simulator discrepancies were reviewed for importance relative to the impact on 10

CFR 55.45 and 55.59 operator actions as well as on nuclear and thermal hydraulic operating characteristics.

Conformance with Operator License Conditions (10

C FR 55.53): The inspectors reviewed the facility licensee's program for maintaining active operator licenses to assess compliance with 10

CFR 55.53(e) and (f). The inspectors reviewed the

procedural guidance and the process for tracking on

-shift hours for

licensed operators, and which control room positions were granted watch

-standing credit for maintaining active operator licenses. Additionally, medical records for

licensed operators were reviewed for compliance with 10

CFR 55.53(I). This inspection constitutes one biennial licensed operator requalification inspection sample as defined in IP

71111.11B.

b. Findings No findings were identified.

1R12 Maintenance Effectiveness

(71111.12)

.1 Routine Quarterly Evaluations

a. Inspection Scope

Th e inspectors evaluated degraded performance

issues involving the following risk-significant system:

Reactor protection system

using a problem

-oriented approach

. 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

to this report. This inspection constituted

one quarterly maintenance effectiveness

sample as defined in IP 71111.12-05. b. Findings No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

(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:

July 6, 2015: K-2A instrument air compressor, W

-86 battery room fan, 2DY

-02 blue channel instrument bus inverter with bus B

-04 relay calibrations;

July 17, 2015: G-02 EDG endurance run

during P-35B; diesel

-driven fire pump (DDFP) replacement, TS

-6 bus 2A-01 relay calibration, with switchyard factor

and Unit 2 power range nuclear instrumentation calibrations

July 27, 2015

PBTP 258 acceptance testing of P

-35B; DDFP with 1CV-110A boric acid blender flow control valve

OOS, 18-month instrument and service air system calibrations , K-3A service air compressor OOS and 1A52

-52 bus 1A-04 to bus 2A-04 cross-tie breaker unavailable;

August 4, 2015: P-32A, P-32B, and P

-32C SW pumps OOS with 2P-2C charging pump OOS; and August 6, 2015: P-35B DDFP , G-04 EDG, and 2P

-2C charging pump OOS.

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 five sample s as defined in IP

71111.13-05. b. Findings No findings were identified.

1R15 Operability Determinations and Functional Assessments

(71111.15)

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

AR 02057684:

incomplete

surveillance

- SR 3.8.9.1 distribution

system [for 480VAC B03 and B04 cross

-tie breakers]

FA 02043804

SFP cooler degradation

worse & replacement

stalled; FA 02044783:

Reduced available operator response time for DGB

flood; FA 02063308:

NFPA 80 5 manual action feasibility

n on-compliance; and

POD 02052030:

POR request for W

-185A & B A-06 switchgear

room fans. 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 T

S and FSAR to the licensee's 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 an

d 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 Attachment to this report.

This operability inspection constituted five sample s as defined in IP

71111.15-05. b. Findings 1) Incomplete Functionality Assessment for Flooding in the Diesel Generator Building

Introduction: The inspectors identified a finding of very low safety significance (Green) for the licensee's failure to follow procedure

EN-AA-203-1001, "Operability Determinations/Functionality Assessments," Revision 19. Specifically, when

the licensee identified that internal flood sources in the

diesel generator building (DGB) were larger than the

drain capacity, they failed to identify all affected SSCs. The

DGB contains predominately Train B emergency power systems; however, the

fuel oil transfer pumps for the

Train A emergency diesel generators are located in the southeast corner of the building. The

licensee failed to assess the effects of flooding on the

Train A fuel oil transfer pumps.

Description: During the

inspectors' review of Prompt Operability Determination (POD) 02044783, "Reduced Available Operator Response Time For DGB Flood," Revision 1, they found that the

licensee had previously identified an error in POD 02044783, Revision

0, which had failed to identify all affected SSCs for a postulated 8

-inch fire water pipe leak. The

DGB contains predominately

Train B emergency power systems; however, the

fuel oil transfer pumps for the

Train A emergency diesel

generators are located in the southeast corner of the

building. The licensee had failed to assess the effects of flooding on the

Train A fuel oil transfer pumps, which was documented in AR

2055129, and corrected in the

revision to the PO

D. The inspectors' review of the revised POD identified that the updated compensatory measures did not address all circumstances. Specifically, the

licensee had measures in place to send personnel to the

DGB and check for flooding if a fire pump auto started; however, t

he licensee failed to address those times when a

fire pump

was already running for various plant support or testing activities. The

inspectors' review of station logs found that the

licensee had previously run a

fire pump to support system chlorination, to use the fire hoses to keep excess lake grass off the

traveling water screens, and also for annual underground fire main flow testing. The

licensee's initial identification of the issue would have qualified for licensee identified credit; however, the inspectors added value when they identified that the

licensee's corrective actions in the revision to the

POD were not comprehensive.

The licensee documented the

inspectors concerns in AR

2074593, and created an adverse condition monitoring plan, which implemented an hourly flood watch in the

DGB when a fire pump was manually started.

Analysis: The inspectors determined that the

licensee's failure to adequately evaluate the effects of flooding on all SSCs in the DGB was not in accordance with procedure

EN-A A-203-1001, Section 4.5.2, Step

2, and Functionality Assessment Form

EN-AA-203-1001-F02, which was a performance deficiency warranting further review.

EN-AA-203-1001-F02 required the

licensee to describe the affected SSCs, which should have included the fuel oil transfer pumps from the

Train A diesels. The

finding was determined to be more than minor because

, if left uncorrected

, would potentially result in a more safety significant issue. Specifically, the failure to evaluate the effects of flooding

on all SSCs resulted in inadequate compensatory measures

. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, "Significance Determination Process," Attachment

0609.04, "Initial Characterization of Findings," dat

ed June 19, 2012, and Appendix

A, "The Significance Determination Process for Findings At

-Power," Exhibit

2, "Mitigating Systems Screening Questions," dated

June 19, 2012. For the time period in question, May 17, 2015 to September 17, 2015, the inspectors

reviewed the security door card reader reports and starting sump levels for the DGB and found that during times when the fire pumps were running, station personnel had toured the DGB at a frequency that would have identified flooding conditions before a loss of system function. The

inspectors concluded that the finding was of very low safety significance (Green), because the

inspectors answered "No" to the Mitigating Systems screening questions.

This finding has a cross

-cutting aspect of Evaluation (P.2), in the area of PI&R for failing to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the

licensee failed to evaluate all SSCs affected by a

fire water pipe leak.

Enforcement: This finding does not involve enforcement action because no violation

of a regulatory requirement was identified. As corrective actions, the

licensee created an adverse condition monitoring plan, which implemented an hourly flood

watch in the DGB when the fire pump was manually started. The

licensee also created an action item to revise POD 02044783 and formally document the compensatory measures. Because this finding does not involve a violation and is of very low safety significance, it is identified as a finding

(FIN 05000266/2015003

-01; 05000301/2015003

-01, Incomplete

Functionality Assessment for Flooding in the Diesel Generator Building).

1R19 Post-Maintenance Testing

(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:

1P-11A component cooling water

(CCW) pump following oil change;

2DY-02 blue channel instrument bus inverter

following preventative maintenance

P-35B DDFP after complete replacement;

P-35B DDFP after modifications;

Red channel reactor coolant system (RCS) delta temperature instrument following repair;

Safety-related battery

D-106 cell 48 replacement; and

W-86 primary auxiliary building

(PAB) battery & inverter room vent fan.

These activities were selected based upon the SSC's ability to impact risk.

T he 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 i

n 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

to this report.

This inspection constituted seven post-maintenance

testing (PMT) sample s as defined in

IP 71111.19-05. b. Findings No findings were identified.

1R22 Surveillance Testing

(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:

1ICP 02.001WH:

white channel reactor protection and safeguards system logic testing (Routine);

2ICP 02.001YL:

yellow channel reactor protection and safeguards system logic testing, with rod insertion limit verification (Routine);

IT-03 Train B: low head safety injection (SI) pump and valve test (Routine);

TS-6: control rod exercise tes

t - Unit 2 (Routine); and

IT-06 Train A: containment spray pump and valve IST (In

-Service Test). 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 te

st 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 in

-service testing

activities, testing was performed in accordance with the applicable version of Section

XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;

where applicable, test results not meeting acceptance

criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

where applicable for safety

-related instrument control surveillance tests, reference setting data were accurately incorporated in the test

procedure;

where applicable, actual conditions encountering high resistance electrical

contacts were such that the intended safety function could still be accomplished;

prior procedure

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

test; equipment was returned to a position or status required to support the

performance of its safety functions; and

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

Documents reviewed are listed in the

to this report.

This inspection constituted four routine surveillance

testing sample s and one in-service test sample

as defined in IP

71111.22, Sections-02 and-05. b. Findings No findings were identified.

1EP6 Drill Evaluation

(71114.06)

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on August 4, 2015, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. Because the drill involved a simulated hostile action based event, t

he inspectors observed emergency response operations in

the control room simulator and the alternate emergency response facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CA

P. As part of the inspection, the

inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one

sample as defined in

IP 71114.06-06. b. Findings No findings were identified.

2. RADIATION SAFETY

Cornerstones:

Public Radiation Safety and Occupational Radiation Safety

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and Transportation

(71124.08)

This inspection constituted one complete sample as defined in

IP 71124.08-05. .1 Inspection Planning

(02.01) a. Inspection Scope

The inspectors reviewed the solid radioactive waste system description in the

FSAR, the process control program, and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed.

The inspectors reviewed the scope of

QA audits in this area since the last inspection to gain insights into the licensee's performance and inform the "smart sampling" inspecti

on planning.

b. Findings No findings were identified.

.2 Radioactive Material Storage

(02.02) a. Inspection Scope

The inspectors selected areas where containers of radioactive waste are stored, and evaluated whether the containers were labeled in accordance with

CFR 20.1904, "Labeling Containers," or controlled in accordance with 10

CFR 20.1905, "Exemptions to Labeling Requirements

." The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, "Standards fo

r Protection against Radiation

." For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against

unauthorized removal and controlled in accordance with 10

CFR 20.1801, "Security of Stored Material," and 10

CFR 20.1802, "Control of Material Not in Storage

." The inspectors evaluated whether the licensee established a process for monitoring

the impact of long term storage (e.g., buildup of any gases produced by

waste decomposition, chemical reactions, container deformation, loss of container integrity,

or re-release of free

-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or nonconformance with waste disposal requirements.

The inspectors selected containers of stored radioactive material, and assessed for signs of swelling, leakage, and deformation.

b. Findings No findings were identified.

.3 Radioactive Waste System Walkdown

(02.03) a. Inspection Scope

The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in the

FSAR, Offsite Dose Calculation Manual, and process control program. The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment which is not in service or abandoned in place would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure. The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, "Changes, Tests, and Experiments

." The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what is described in the

FSAR were reviewed and documented in

accordance with 10

CFR 50.59, as appropriate and to assess the impact on radiation doses to members of the public.

The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the process control program, and provided representative samples of the waste product for the purposes of waste classification as described in 10

CF R 61.55, "Waste Classification

." For those systems that provide tank recirculation, the inspectors evaluated whether the tank recirculation procedures provided sufficient mixing.

The inspectors assessed whether the licensee's process control program correctly described the current methods and procedures for dewatering and waste stabilization (e.g., removal of freestanding liquid).

b. Findings No findings were identified.

.4 Waste Characterization and Classification

(02.04) a. Inspection Scope

The inspectors selected

the following radioactive waste streams for review:

dry active waste; and

primary resin. For the waste streams listed above, the inspectors assessed whether the

licensee's radiochemical sample analysis results (i.e., "10

CFR Part 61" analysis) were sufficient to support radioactive waste characterization as required by 10

CFR Part 61, "Licensing Requirements for Land

Disposal of Radioactive Waste

." The inspectors evaluated whether the licensee's use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current

CFR Part 61 analysis for the selected radioactive waste streams.

The inspectors evaluated whether changes to plant operational parameters were taken into account to: (1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and (2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above. The inspectors evaluated

whether the licensee had established and maintain

ed an adequate QA

program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55 and 10

CFR 61.56, "Waste Characteristics

." b. Findings No findings were identified

.

.5 Shipment Preparation

(02.05) a. Inspection Scope

The inspectors reviewed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensee's

procedures for cask loading and closure procedures were consistent with the vendor's current approved procedures.

Due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during routine training. The inspectors assessed whether the licensee's training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

b. Findings No findings were identified.

.6 Shipping Records

(02.06) a. Inspection Scope

The inspectors evaluated whether the shipping documents indicated the proper shipper name; emergency response information and a 24

-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification,

transport index, and UN number for the following radioactive shipments:

14-024C: Unit 2 "A" steam generator

(SG); 14-024E: four SGs on canal barge;

14-024F: fou r SGs on train;

14-042: dry active waste;

14-052: fuel cleaning equipment; and

15-008: primary resin.

Additionally, the inspectors assessed whether the shipment placarding was consistent

with the information in the shipping documentation.

b. Findings No findings were identified.

.7 Identification and Resolution of Problems

(02.07) a. Inspection Scope

The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation, were being identified by the

licensee

at an appropriate threshold, were properly characterized, and were properly addressed for resolution in the

licensee's

CA

P. Additionally, the

inspectors evaluated whether the corrective actions were appropriate for a selected sample of problems documented by the licensee that involve radioactive waste processing, handling, storage, and transportation.

The inspectors reviewed results of selected audits performed since the last inspection of this program and evaluated the adequacy of the

licensee's corrective

actions for issues identified during those audits.

b. Findings No findings were identified.

4. OTHER ACTIVITIES

Cornerstones:

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

4OA1 Performance Indicator Verification

(71151) .1 Mitigating Systems Performance Index

-Emergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI)

- Emergency AC Power System performance indicator

(PI) for Units 1 and 2, for the period from the third

quarter 2014 through the

second quarter 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute

(NEI) Document

99-02, "Regulatory Assessment Performance

Indicator Guideline," Revision

7, dated August 31, 2013, were used. The

inspectors reviewed the licensee's operator narrative logs, MSPI derivation reports, issue

reports, event reports and NRC Integrated IRs to validate the accuracy of the submittals. The

inspectors reviewed the MSPI component risk coefficient to determine if

it had changed by more than 25

percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The

inspectors also reviewed the licensee's

issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and

none were identified. Documents reviewed are listed in th

e Attachment to this report.

This inspection constituted two MSPI emergency AC power system sample

s as defined in IP 71151-05. b. Findings No findings were identified.

.2 Mitigating Systems Performance Index

-High Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection Systems performance for Units 1 and 2, for the period from the third

quarter 2014 through the second quarter 2015. To determine the accuracy

of the PI data reported during those periods, PI definitions and guidance contained in the

NEI Document 99

-02, "Regulatory Assessment Performance

Indicator Guideline," Revision

7, dated August 31, 2013, were used. The

inspectors reviewed the licensee's

operator narrative logs, issue

reports, MSPI derivation reports, event reports and NRC Integrated IRs to validate the accuracy of the submittals. The

inspectors reviewed the MSPI component risk coefficient to determine if

it had changed by more than 25

percent in value since the previous inspection, and if so, that the change was in accordance wit

h applicable NEI

guidance. The

inspectors also reviewed the licensee's issue

report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI high pressure injection system sample

s as defined in IP 71151-05. b. Findings No findings were identified.

.3 Mitigating Systems Performance Index

-Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Heat Removal System

PI for Units 1 and 2, for the period from the third

quarter 2014 through the second quarter 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the

NEI Document 99

-02, "Regulatory Assessment Performance Indicator Guideline," Revision

7, dated August 31, 2013, were used. The inspectors reviewed the licensee's

operator narrative logs, issue

reports, event reports, MSPI derivation reports, and NRC Integrated IRs to validate the accuracy of the submittals. The

inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25

percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's issue

report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the

to this report. This inspection constituted two MSPI heat removal system sample

s as defined in

IP 71151-05. b. Findings No findings were identified.

4OA2 Identification and Resolution of Problems

(71152) .1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline

PIs 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 licensee's 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 licensee's CAP as a result of the

inspectors' observations are included in the

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

Section 1 of this report.

b. Findings No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance

issues for follow

-up, the inspectors performed a screening of items entered into the licensee's CAP. This review was accomplished through inspection of

the station's daily condition report packages

or equivalent.

These daily reviews were performed by procedure as part of the

inspectors' daily plant status monitoring activities and, as such, did not constitute any separate inspection

samples. b. Findings No findings were identified.

.3 Annual Follow

-up of Selected Issues: 2RC-431b bellows leak a. Inspection Scope

During a review of items entered in the licensee's CAP, the

inspectors recognized a corrective action item documenting

an increase

in activity levels in the

Unit 2 containment

sump

A. Specifically, the licensee noted an increasing trend in Iodine

-131,

133, and Xenon

-133. The inspectors checked Unit 2 RCS leakrate trends, containment

humidity , and radiation trends. Additionally, the inspectors entered the

Unit 2 containment at power with the licensee to walkdown areas to determine if there were signs of a physical leak in the

Unit 2 containment. During the containment entry, a significant accumulation of boric acid was observed by the

inspectors and the

licensee to have accumulated on the valve actuator of 2RC

-431B, Pressurizer Spray Line Pressure Control Valve.

The inspectors performed a review of the licensee's corrective actions specifically for 2RC-431B, the surrounding target equipment, and all other related

operational

impacts to unit operation with an active RCS to atmosphere leak. Specifically, the

inspectors verified the following attributes during their review of the licensee's corrective actions for the RCS leakage: 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

Although a full inspection of 2RC

-431B will not be possible until the unit's

next RFO , t he inspectors noted that the licensee's initial characterization of the leak in

AR 02059583, was that it was

a bellows leak and packing failure. The

licensee made this determination based upon photos taken during the aforementioned containment entry. This and other associated ARs related to the leak

did not make reference to the fact that there have been several previous occurrences for these valves on both unit

's pressurizers.

A brief summary of the history associated with these valves at Point Beach Nuclear Plant , Units 1 and 2 , are as follows:

February 18, 1974: modifications to

Unit 1 are implemented to install bellows seal conversion kits to spray valves because packing leakage required shutdowns of the unit. At this time, Unit 2 had already been using this type of arrangement with satisfactory results.

August 1987: 2RC-431B bellows

is replaced due to stem binding preventing the valve from shutting.

May 1991: 1RC-431A bellows replaced due to valve stem binding issues.

April 23, 1992: the bellows leak detection line for 1RC

-431A was broken off, presumed at the time due to fatigue failure. November 23, 2004: 2RC-431A shows indications of leakage from both the bellows and the bellows tell

-tale line. No determination for the bellows failure is given.

May 5, 2005 and July

7, 2005: small amounts of boric acid observed on the bellows tell-tale line for 2RC

-431A, and bellows is determined to have failed.

April 23, 2008: during the replacement of a connected pressure

indicator, the bellows tell

-tale line for 2RC

-431B is discovered to be cracked. Forensic evaluation of the piping attributed the failure to chloride induced transgranular stress corrosion cracking. 2RC

-431A is then removed for similar analysis, and revealed cracking on the interior surfaces. Chloride contamination was detected on the interior surfaces of the piping for both valves, with no conclusive determination as to the source of the chlorides.

December 29, 2008: swabs and follow

-up penetrant

testing reveals chloride contamination on both 1RC

-431A and B

valve bellows tell

-tale piping. Photographs for 1RC

-431A show that failure of the piping was inevitable.

May 22, 2011: 1RC-431B bellows and packing failed

. The inspectors reviewed the results of previous causal products and external operating experience, and determined that this history demonstrates an equipment reliability

issue that appears to be unique to Point

Beach specifically related to the tell

-tale line failures. The above history illustrates a number of previous occurrences that do not specifically describe a deficiency of NRC requirements at this time.

During the upcoming refueling outage the licensee will perform corrective valve maintenance and also perform a causal

analysis in accordance with their CAP. The licensee plans on incorporating the inspectors' observations during their assessment. This review constituted one in

-depth PI&R sample as defined in IP

71152-05. b. Findings No findings were identified.

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

(71153) .1 (Closed) Licensee Event Report 05000266/2015

-001-00: Inadequately Sealed Pipe Penetration Results in an Unanalyzed Condition for Internal Flooding

On November

19, 2014, NRC inspectors, as part of their annual internal flooding inspection, identified potential gaps in sealant material for a pipe penetration through the Unit 2 RHR valve gallery wall that separated both trains of RHR. The

licensee subsequently inspected both the Unit

and 2 valve gallery walls on November

21, 2014, and found that sealant was never applied to the Unit

penetration, which openly communicated between both trains of the Unit

RHR pump cubicles approximately three feet above the floor. The penetration gaps, when combined with previously identified flooding design deficiencies, such as new flood sources and unqualified barriers, resulted in the loss of safety function for the RHR system during the previous three year timeframe.

Documents reviewed are listed in the Attachment to this report. This LER is closed.

b. Findings 1) Potential Failure of Multiple Safety

-Related Trains During Flooding Events

Introduction: The inspectors identified a finding of very low safety significance

and an associated NCV of 10 CFR Part 50, Appendix

B, Criterion

III, "Design Control," for the

licensee's failure to ensure that a non

-Category I (seismic) component failure, that results in flooding, would not adversely affect safety

-related equipment needed to get the plant to SSD or to limit the consequences of an accident. Specifically, the design of Point Beach did not ensure that the RHR pumps would be protected from all credible non-Category I (seismic) system failures.

Discussion

On November 19, 2014, NRC inspectors, as part of their annual internal flooding inspection, identified potential gaps in sealant material for a pipe penetration through the

Unit 2 RHR valve gallery wall that separated both trains of RHR. The licensee subsequently inspected both the Unit

and 2 valve gallery walls on November 21, 2014, and found that sealant was never applied to the Unit

penetration, which openly communicated between both trains

of the Unit

RHR pump cubicles approximately three feet above the floor. The licensee had previously identified additional flood barrier weakness, pipes that were not seismically qualified, and additional flooding sources, in response to NRC inspector questions, as well as, independent licensee efforts to validate that their

internal flooding design was adequate to protect

SSD equipment from design basis internal flooding sources. The previous deficiencies were evaluated in operability evaluations, which had concluded that the licensee had not deviated from their overall internal flood design basis of ensuring that a single internal flooding event did not cause the loss of a system needed to safely shutdown the plant. The previous operability conclusions had relied on the accumulation of flood waters to a height of seven feet in a single RHR compartment on each unit, which reduced the amount of flood water that cascaded into the remaining RHR compartments and maintained

the operability of the opposite train and overall RHR system function for each unit. The existence of the unsealed or partially sealed penetrations between the RHR pump valve gallery walls invalidated the

licensee's unstated assumption in previous operability evaluations that flood waters could not migrate from one RHR compartment to another below the seven foot level. Significant flooding issues identified included:

The licensee, while walking down the RHR heat exchanger rooms to answer NRC flood-related inspection questions, identified that unsealed and non

-seismic penetrations existed between the #2 and #3 pipeways and the RHR heat exchanger rooms. These unsealed penetrations represented a new conveyance

flood path to the RHR pumps. The licensee had previously assessed that flood sources would be directed to the central area outside of the RHR pump cubicles

on the lowest level of the PA

B. This central area could hold approximately 28,000 gallons of water before spilling over a seven

-foot wall into the individual RHR pump cubicles. The newly identified

conveyance path allowed water to bypass the central area and accumulate in the RHR valve gallery cubicles, which

directly communicate with the RHR pump cubicles through four

-inch openings in the walls.

The licensee identified that the Refueling Water Storage Tank pipe penetration between the façade building and the PAB on each unit was not seismically

qualified. Previous analyses by the licensee had credited the large volume of the facade floor and its ability to flood up to the PAB door thresholds before entering the PA

B. The pipe penetration, which was below the height of the PAB door thresholds, would need to have met the requirements of a penetration flood

barrier, which would include being seismically qualified. Those requirements

were prescribed in a letter form the AEC to the licensee, titled "Supplemental Request for Flooding Analysis of Non

-Category I System Sources," dated December 10, 1974. The licensee's corrective actions included an extensive internal flooding design review, which will result in an updated FSAR with a more detailed description of the station

's flooding licensing basis; modifications to multiple flood barriers to bring them into compliance with the licensee's flooding licensing basis; installation of additional flood level alarms where necessary, and evaluation or modification of

SW piping to properly qualify it

as seismic.

Analysis: The inspectors determined that the licensee's failure to ensure that the RHR pumps would be protected from all credible non

-Category I (seismic) system failures was a performance deficiency. The inspectors determined that the finding was more than minor because it was associated with the Design Control attribute of the Mitigating System cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent

undesirable consequences. Specifically, the inadequate design resulted in an unanalyzed condition and loss of safety function of the RHR system while the plants

were in Modes

4, 5, and 6, when relying on the RHR system for decay heat removal. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, "Significance Determination Process," Attachment

0609.04, "Initial Characterization of Findings," dated

June 19, 2012, and Appendix

A, "The Significance Determination Process for Findings At

-Power," Exhibit

2, "Mitigating Systems Screening Questions," dated

June 19, 2012. The inspectors answered "yes" to question 2 of the screening questions because the finding represented a loss of safety function. Thus the inspectors consulted the regional SRA.

Detailed Risk Evaluation

The detailed risk evaluation was performed by Region III SRAs. The increase in core building flooding events. The exposure time (ET) assumed was

one year which is the maximum allowed by the SD

P. For the evaluation of the risk significance, the SRAs considered the following flooding events: - Case 1: Random RHR or CCW leak into the RHR pump cubicles/RHR pipe and valve galleries - Case 2: Seismic Event

- with unit above RHR shutdown cooling (e.g., while in Mode

at power) - Case 3: Seismic Event

- with unit on RHR shutdown cooling

- Case 4: RHR pump seal leak

- Case 5: External leakage from outside plant into the Plant Auxiliary Building (PAB)

- Case 6: Random SW or FP system leak in the PAB

1) Case 1: Random RHR or Component Cooling Water (CCW) Leak in the RHR Pump Cubicles/RHR Pipe and Valve Galleries

To evaluate the delta risk due to a random RHR or CCW system pipe break in the RHR pump cubicles/RHR pipe and valve galleries (i.e., RHR cubicles), the SRAs first obtained information from the licensee on the lengths of various size piping in these RHR areas. The following information was obtained in Table 1 below:

(Note: The two units are reasonably symmetric as far as piping lengths are concerned)

Table 1 Nominal Pipe Diameter (inches) Approximate Aggregate Length (feet)

RHR A RHR B Total RHR A + B

CCW 36 137 173 0 70 70 >10 0 0 0 RHR 36 146 182 59 148 207 >10 0 0 0 The SRAs then determined the frequency of a pipe break using Electric Power Research Institute (EPRI)

Report 302000079, "Pipe Rupture Frequencies for Internal Flooding Probabilistic Risk Assessments," Revision

3. The pipe breaks of interest were determined to be those between approximately 100

gpm and 2000

gpm (i.e., in the "Flood" mode range in the EPRI report). A leakage rate of less 100

gpm would allow extensive time to mitigate the flood and thus would not

be risk significant, while a leakage rate of greater than 2000

gpm would not allow enough time for action to mitigate the leakage with or without the performance deficiency and thus would not represent a

delta risk.

From Table ES

-2 of the EPRI report, the

following failure rates were obtained in Table 2 below for the CCW and RHR piping in the "Flood" mode" range of leakage:

Table 2 Nominal Pipe Diameter

(inches) Failure Rate

(per year/ft)

CCW 3.57E-8 5.30E-9 RHR 8.09E-9 2.44E-9 The risk significant time period associated with random pipe leakage in the RHR cubicles is when the

unit is on RHR shutdown cooling and with both 1) the

SGs unavailable for decay heat removal, and 2) with the reactor cavity not flooded. To obtain a representative ET for when the

unit is on RHR shutdown cooling and with both 1) the SGs unavailable for decay heat removal, and 2) with the reactor cavity not flooded, the associated time periods during the last RFOs on each unit were obtained. A time period of approximately seven days was obtained for

Unit 1 and a time period of approximately

8.3 days was obtained for

Unit 2. In this analysis, a probability of 3.0E

-2 (approximately

days) was conservatively used that the

unit was on RHR shutdown cooling with the SGs unavailable and with the reactor cavity not flooded during the one year ET.

Combining the above two tables and the probability of being on RHR shutdown cooling with the SGs unavailable and with the reactor cavity not flooded, the following information is obtained in Table

below: Table 3 Nominal Pipe Diameter (inches) Failure Rate (per year/ft) Total RHR Cubicle

Piping Length (feet) Probability on RHR cooling (with no SGs/reactor cavity not flooded) Failure Rate/Year

(while on RHR cooling (with no SGs/reactor cavity not flooded)

CCW 3.57E-8 173 3.0E-2 1.85E-7 >6 and 5.30E-9 70 3.0E-2 1.11E-8 RHR 8.09E-9 182 3.0E-2 4.42E-8 >6 and 2.44E-9 207 3.0E-2 1.52E-8 Total = 2.56E-7 The following information was obtained from the licensee regarding flood volumes in the RHR cubicle areas:

RHR Cubicle Volumes

Water Level

- Significance

Water Level in RHR Cubicle

Gallons RHR Pump - Unavailable Due to Flooding 22 inches 3261 Degraded Case

- Height of Opening Between A and B RHR Cubicles

feet 5336 Base Case

- Height of Wall Between A and B RHR Cubicles

feet 12451 For discussion purposes, assume a 300

gpm leak (i.e., approximately a one

-inch pipe break in either CCW or RHR water) due to a random pipe break in an RHR cubicle.

Base Case: The 7 foot wall is intact between the RHR A and B Pipe and Valve Galleries.

For this case, it would take approximately 15,712

gallons of water (i.e., 12451 + 3261 = 15712 gallons) to enter the RHR cubicles before both RHR pumps would be unavailable.

The time available to isolate a 300

gpm leak is:

Time Available Base Case = 15712 gallons/300

gpm = 52.4 minutes

Degraded Case

The 7 foot wall has an opening at the 3 foot level between the RHR A and B Pipe and Valve Galleries.

For this case, it

would take approximately 8,597

gallons of water (i.e., 5336 + 3261 = 8597 gallons) to enter the RHR cubicles before both RHR pumps would be unavailable.

The time available to isolate a 300

gpm leak is:

Time Available Degraded Case = 8597 gallons/300

gpm = 28.7 minutes

In the above, conservatively assume that for the Degraded Case

the Time Available to isolate an RHR or CCW leak in the RHR cubicle is insufficient before both RHR pumps are rendered unavailable due to room flooding [i.e., the Human Error Probability (HEP) is 1.0]. In the Base Case, conservatively assume that the HEP is 0 (i.e., the leak would always be isolated before both RHR pumps are rendered unavailable due to flooding). flooding in the RHR cubicles is given by the Failure Rate/Year in Table 3 above. That is, the value in Table 3 for the Failure Rate/Year represents the frequency of the event occurring and leading directly to core damage.

Thus, the = 2.56E-7/yr. 2) Case 2: Seismic Event

- with Unit above RHR Shutdown Cooling (e.g., while in Mode 1 at Power)

To evaluate the delta risk due to a seismic event with the

unit above RHR shutdown cooling (e.g., while in Mode

at power), the following assumptions were made:

- If non-seismic piping failed that could result in flooding in the RHR cubicles and a loss-of-coolant-accident (LOCA) occurred, then core damage was assumed (i.e., the conditional core damage probability (CCDP) was 1.0). - The ET was assumed to be one

year which is the maximum allowed by the

SDP. - In Section

3.1.3.3 of the Point Beach Individual Plant

Examination of External Events, it states that plant piping (e.g., including SW , FP, and CW piping) can be screened at a High Confidence of Low Probability of Failure (HCLPF) of 0.3g. The HCLPF value corresponds to a 95

percent probability with a 95

percent confidence level that a seismic event at the HCLPF capacity will not result in damage to

the associated component. The SRAs reduced the HCLPF capacity from 0.3g to 0.2g to provide additional margin during a seismic event for the failure of non

-seismic piping.

The reactor makeup water tank was also assumed, conservatively, to have a HCLPF of

0.2g. Using guidance from NRC's Risk Assessment Standardization Project (RASP) handbook, only the "Bin 2" "Bin 2" is defined in the RASP handbook as seismic events with intensities greater than 0.3g but less than 0.5g. Earthquakes of lesser severity are unlikely to result in large pipe failures and earthquakes of a larger magnitude could result in major structural damage throughout the plant which would not be representative

of a risk due to the performance deficiency. The

initiating

event frequency (IEF) of an earthquake in "Bin 2" was estimated to be 1.29E

-5/yr for Point Beach using Table

4A-1 of Section

of the RASP handbook. Using a HCLPF capacity of 0.2g, a probability of 1.90E

-1 was obtained for the failure of non-seismic piping/tanks in "Bin 2" that could result in

flooding in the RHR cubicles. - The conditional probability of a small loss of coolant accident (SLOCA) and a medium LOCA (MLOCA) for a seismic event in Bin 2 was obtained from Figure 4.5 of the RASP handbook (large LOCAs are not considered credible in Bin 2). These conditional probabilities were given as 4.5E

-2 and 4E-3; respectively. The total probability of a LOCA for a seismic event in Bin 2 is thus 4.

9E-2. factors:

Non-seismic pipe failure/tank failure] x [ProbLOCA] x [CCDP] x [ET]

= [1.29E-5/yr] x [1.90E

-1] x [4.9E

-2] x [1.0] x [1.0]

= 1.20E-7/yr 3) Case 3: Seismic Event

- with Unit on RHR Shutdown Cooling

The risk significant time period with the

unit on RHR shutdown cooling is when both 1) the SGs are unavailable for decay heat removal, and 2) when the reactor cavity is no

t flooded. As described in Case 1 above, in this analysis, a probability of 3.0E

-2 (approximately 11

days) was conservatively used that the

unit was on RHR shutdown cooling with the SGs unavailable and with the reactor cavity not flooded.

The following assumptions were made as far as the failure of non

-seismic piping that could result in flooding in the RHR cubicles:

- If non-seismic piping failed that could result in flooding in the RHR cubicles, then core damage was assumed (i.e., the CCDP

was 1.0). - The ET was assumed to be o

ne year which is the maximum allowed by the

SD

P. - Similar to Case 2, the seismic capacity of non

-seismic piping was assumed to have a HCLPF capacity of 0.2g. The IEF of an earthquake in "Bin 2" was estimated to be 1.29E-5/yr for Point Beach using Table

4A-1 of Section

of the RASP handbook. Using a HCLPF capacity of 0.2g, a probability of 1.90E

-1 was obtained for the failure of

non-seismic piping in "Bin 2" that could result in

flooding in the RHR cubicles.

A bounding value for thfactors: Non-seismic pipe failure/tank failure] x [ProbRHR Cooling

-No SGs-Rx Cavity Not Flooded

] x [CCDP] x [ET]

= [1.29E-5/yr] x [1.90E

-1] x [3.0E

-2] x [1.0] x [1.

0] = 7.35E-8/yr 4) Case 4: RHR Pump Seal Leak

The leakage due to an RHR pump seal failure was assumed to be 50

gpm (as described in DBD -T-41, "Hazards

- Internal and External Flooding (Module A)

." The following information was considered:

- A level switch in each RHR pump cubicle would alarm in the Main Control Room (MCR) to detect water in the cubicle from an RHR pump seal leak.

- Each RHR cubicle has a normally closed, remotely

-operated drain isolation valve that can be controlled from the MC

R. - Per the licensee's evaluation, the drainage capacity of the drain line from each RHR cubicle is approximately 150

gpm at a level of 22 inches in the RHR cubicle (which corresponds to the level at which an RHR pump would be unavailable due to room flooding).

- The drain line from each RHR cubicle drains to a sump on the

-19 foot elevation in the PAB. The sump on the

-19 foot elevation in the PAB has two sump pumps with a rated capacity of 75

gpm each (total of 150

gpm). - Alarm Response Procedure

1C 20 A 4-4 for "Unit

or 2 RHR Pump Rooms Level High" provides directions to determine which RHR cubicle(s) are flooding and to cycle the RHR cubicle drain valve(s) while maintaining the high level MCR alarm for the PAB

-19 foot sump clear.

The MCR alarm, RHR cubicle drain lines, and Alarm Response Procedure for high water level in an RHR cubicle should allow an excessive time to mitigate a 50

gpm RHR pump seal leak. Even without any operator action to drain a 50

gpm seal leak into an RHR cubicle to the

-19 foot PAB sump using the RHR cubicle drain valve, it would take

approximately 172 minutes (almost three

hours) to render both RHR pumps unavailable (i.e., 8597

gallons/50

gpm = 172 minutes). The time available of approximately three hours allows plenty of time to isolate a leaking RHR pump seal before both RHR pumps would be rendered unavailable. The delta risk significance associated with the

performance deficiency due to a 50

gpm RHR pump seal leak is considered to be negligible.

5) Case 5: External Leakage from Outside Plant into the Plant Auxiliary Building

The SRAs reviewed the following documents:

- Functionality Assessment (FA)

2004858-03 - Calculation FPLC

-076-CALC-019, "Precipitation Effects Sensitivity Analysis," Revision

- Calculation FPLC-076-CALC-014, "PBNP Precipitation and Snow Intensity Determination and Roof Drainage Evaluation," Revision

Based on a review of the above documents, the SRAs determined that the delta risk associated with the performance deficiency due to external leakage from outside the plant into Plant Auxiliary Building was negligible.

6) Case 6: Random Service Water or Fire Protection System Leak in the PAB

The SRAs evaluated the delta risk due to a random SW or FP water leak due to a pipe break in the PAB that could funnel water into the RHR cubicles. As described in Functionality Assessment 2004858-03, Attachment

1, there are essentially three conveyance paths to each RHR cubicle:

- When the volume in the PAB central area on the

-19 foot level exceeds 27,901

gallons, flow enters the RHR cubicles through the personnel access (at a 7 foot level above the floor on the

-19 foot level of the PAB), - When flow accumulates on the 8 foot elevation of the PAB, flow occurs through the RHR heat exchanger rooms down to the RHR cubicles, and

- When flow accumulates on the 8 foot level of the PAB, flow occurs through Pipeway

1. 3 into the Unit

RHR pipe and valve gallery. This pathway is currently blocked by sandbags, but no credit is taken for the sandbags.

This delta risk evaluation will also consider the case before seals between Pipeway

1. 2 and the Unit

RHR pipe and valve gallery on the 8 foot elevation of the PAB were successfully installed, which now prevents flood waters from the sub

-floor pipe trench on the 8 foot level

of the PAB from entering the Unit

RHR pipe and valve gallery.

Per Functionality Assessment

2004858-03, Attachment

1, following a pipe break in the upper levels of the PAB, by analysis there is a flow split of the leakage from a pipe break into the following areas in the listed proportions.

- -19 foot PAB central area

84.6 percent - 1A RHR cubicle

0.0 percent - 1B RHR cubicle

2.2 percent - 2A RHR cubicle

0.1 percent - 2B RHR cubicle

13.1 percent For simplicity assume a 1000

gpm SW or FP leak into the upper levels of the PA

B.

a) For the Base CaseProperty "Contact" (as page type) with input value "B.</br></br>a) For the Base Case" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., assume that all the water from a SW or FP leak into the PAB would go to the

-19 foot level central area of the PAB (i.e., the basement level of the PAB). The water from the leak would then accumulate on

-19 foot central area of the PAB, and overflow into all four RHR

pump cubicles (i.e., both Unit

and 2 A and B RHR

cubicles) when 27,901

gallons had accumulated on the floor. The overflow into the

RHR pump cubicles would be equally split between all four RHR pumps or at a flow of 250

gpm each. Since a level of 22 inches in the RHR cubicles (3261

gallons) would render an RHR pump unavailable, the time after the pipe break

at which both RHR

pumps would become unavailable is:

Time Base Case

= (27901 gallons/1000

gpm) + (3261

gallons/250

gpm) = 27.9 minutes + 13.0 minutes

= 40.9 minutes

b) For the Degraded Case, assume the water flow from the SW or FP leak is split in the proportions as stated above, except assume that 1B RHR cubicle has 10

percent additional input due to flow through Pipeway #2 into th

e Unit 1 RHR pipe and valve gallery (i.e., before this leakage path was sealed).

The proportion of leakage onto the -19 foot PAB central area would then decrease to 74.6

percent. The flow split of the leakage from

a pipe break is then given into the following areas in the listed proportions.

- -19 foot PAB central ar

ea 74.6 percent - 1A RHR cubicle

0.0 percent - 1B RHR cubicle

2.2 percent - 2A RHR cubicle

0.1 percent - 2B RHR cubicle

13.1 percent Since an inspection of the walls separating the 2A and 2B RHR pipe and valve galleries found the penetrations at the 3 foot elevation separating the 2A and 2B RHR cubicles

relatively tight, the evaluation below will discuss the

case for leakage into the Unit

R HR cubicles (in which there was relatively large open spaces between the 1A and 1B RHR cubicles at the 3 foot elevation). With a leakage rate of 746

gpm into the

-19 foot PAB central area, it would

take 37.4 minutes (i.e., 27901

gallons/746

gpm = 3 7.4 minutes) to overflow into the RHR cubicles. During these 3

7.4 minutes, 4

563 gallons [i.e., (3 7.4 minutes)(122

gpm) = 4 563 gallons] would have accumulated in the Unit

RHR cubicles. After 3

7.4 minutes, the leakage rate into the Unit

RHR cubicles would come from two sources:

1) overflow into the RHR pump cubicles from the

-19 foot PA

B central area at a rate of 373

gpm per unit, and 2) leakage of 122

gpm via the flow distribution provided above. The total inleakage into the Unit

RHR cubicles would then

be 495 gpm (i.e., 373 + 122 = 495 gpm). With a degraded wall with an opening between the 1A and 1B RHR pipe and valve galleries at the 3 foot level, as described in Case 1, it

would take approximately 8,597

gallons of water (i.e., 5 336 + 3261 = 8597

gallons) to enter the RHR cubicles before both RHR pumps would become unavailable.

The time after the pipe break at which both Unit

RHR pumps would become unavailable is then:

Time Degraded Case

= (27901 gallons/746

gpm) + (8597 gallons - 4563 gallons)/(495

gpm) = 37.4 minutes + 9.2 minutes = 46.6 minutes Since the Time Degraded Case is greater than the Time Base Case , the delta risk significance for this case is negligible.

Cases 1 through 6 above.

Total Case 1 Case 2 Case 3 Case 4 Case 6 = 2.56E-7 + 1.20E-7 + 7.35E-8 + 0 + 0 + 0 = 4.50E-7/y r Large Early Release Frequency (LERF) Risk Contribution

Since the total estimated change in was greater than 1.0 E-7/yr, IMC 0609 Appendix H, "Containment Integrity Significance Determination Process" was used to determine the potential risk contribution due to large early release frequency (LERF). Point Beach is a 2

-LOOP Westinghouse Pressurized Water Reactor with a large dry containment. Sequences important to LERF include

SG tube rupture events and inter-system LOCA events. These were not the dominant core damage sequences for this finding. Conclusion

Based on the detailed risk evaluation, the SRAs determined that

the finding was of very low safety

significance (Green).

The inspectors determined that the associated finding did not have a

cross-cutting aspect because the finding was not reflective of current performance.

Enforcement

Title 10 CFR Part 50, Appendix

B, Criterion

III, "Design Control," requires, in part, that measures be established to assure that the design basis for safety

-related functions of SSCs are correctly translated into specifications, drawings, procedures, and

instructions.

Contrary to the above, from February

17, 1975 until December

2014, the licensee failed to

assure that the design basis for safety

-related functions of SSCs

were correctly translated into specifications, drawings, procedures, and instructions.

Specifically, the licensee failed

to implement design control measures to ensure that the failure of a non

-Category I component, which result

ed in flooding, would not adversely affect safety

-related equipment needed to place the plant in a

SSD condition or to limit the consequences of an accident. Because this violation was of very low safety significance and it was entered into the licensee's CAP as AR 02008551, this violation is being treated as an NCV, consistent with Section

2.3.2 of the NRC Enforcement Policy. The licensee's corrective actions included an extensive internal flooding design review, which will result in an

updated FSAR with a

more detailed description of the stations flooding licensing basis; modifications to multiple flood barriers to bring them into compliance with the licensee's

flooding licensing basis; installation of additional flood level alarms where necessary, and evaluation or modification

of SW piping to properly qualify it

as seismic

(NCV 05000266/2015003

-0 2; 05000301/2015003

-0 2; Potential Failure of Multiple Safety-Related Trains During Flooding Events).

2) Failure to Perform a Written Safety Evaluation for FSAR Chang

es Introduction

The inspectors identified a Severity Level IV, NCV of 10

CFR 50.59(d)(1), "Changes, Tests, and Experiments," and an associated finding of very low safety significance (Green) for the licensee's failure to perform a safety evaluation to demonstrate that the removal of statements from the FSAR did not require a license amendment. Specifically, the licensee failed to perform a safety evaluation to determine whether removing an FSAR statement, which defined the RHR pump cubicle design flood height as seven feet, could be performed without a license amendment.

Description: During the review of corrective actions associated with LER

266/2015-001, the inspectors found that the licensee intended to keep the pipe penetration between the Unit 1 RHR valve gallery cubicles unsealed and planned to clarify in their FSAR that the seven foot walls separating the RHR cubicles were never intended to be credited as

flood barriers to the full seven feet. The inspectors' review of the FSAR did not identify any statements that defined the credited flood protection height for the RHR cubicle walls. The inspectors' review of the licensee's design basis document for RHR identified a discussion related to separating and protecting the RHR pumps from an RHR pump seal leak or a flange leak, the discussion also referenced a Westinghouse letter from June 26, 1967. The inspectors' review of the referenced Westinghouse letter and other associated correspondence found that the licensee had credited the seven foot walls

as flood barriers. Specifically, in response to Atomic Energy Commission questions, the licensee stated in their PSAR, supplement 1, dated

January 11, 1968, that leakage in the RHR pump cubicles could backup to a depth of seven feet without affecting the

operation of the second pump. The inspectors found that this statement was also included in the licensee's FSAR and

remained there until September

1996, when the licensee changed their FSAR to clarify RHR pump cubicle drain positions. The inspectors' review of the licensee's safety evaluation that was credited for making the FSAR change was related to adding elapsed time indicators to auxiliary building

sump pumps, and did not evaluate removing the seven foot design requirement. The licensee entered the

deficiency in their CAP as AR 02069428. Analysis: The inspectors determined that the failure to provide a written safety evaluation to demonstrate that the removal of statements from the FSAR did not require a license amendment was contrary to the requirements of 10

CFR 50.59(d)(1) and was a performance deficiency. The inspectors determined that the finding was more than

minor because the finding, if left uncorrected, would become a more significant safety concern. Specifically, inappropriately removing

the information from the FSAR allowed the licensee to decrease the design basis flood protection height of the RHR compartments and significantly reduced the available time to isolate the leaking RHR pump seal. The

inspectors concluded this finding was associated with the Mitigating Systems Cornerstone.

In addition, the associated violation was determined to

be more than minor because the inspectors could not reasonably determine that the changes would not have ultimately required prior

NRC approval. Violations of 10

CFR 50.59 are dispositioned using the traditional enforcement process instead of the SDP because they are considered to be violations that potentially impede or impact the regulatory process. This violation is associated with a finding that has been evaluated by the SDP and communicated with an SDP color reflective of the safety impact of the deficient licensee performance. The SDP, however, does not specifically consider the regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety

significance of the associated finding.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, "Significance Determination Process," Attachment

0609.04, "Initial Characterization of Findings," dated

June 19, 2012, and Appendix

A, "The Significance Determination Process for Findings A

t-Power," Exhibit

2, "Mitigating Systems Screening

Questions," dated

June 19, 2012. The inspectors concluded that the finding was of very low safety significance (Green), because the inspectors answered "No" to the Mitigating

Systems screening questions.

The inspectors concluded that the performance deficiency associated with the unsealed barriers was assessed in the design control

violation discussed above and the risk associated with this finding would be related to the potential for inadequate corrective actions if the FSAR remained incorrect.

In accordance with Section

6.1.d of the NRC Enforcement Policy

, this violation is categorized as Severity Level IV because the resulting changes were evaluated by the SDP as having very low safety significance (i.e., Green finding). Th

e inspectors determined that the associated finding did not have a cross

-cutting aspect because the finding was not reflective of current performance.

Enforcement: Title 10

CFR 50.59 Section

(d)(1) requires, in part, that the

licens ee maintain records of changes in the facility, of changes in procedures, and of tests and experiments. These records must include a written evaluation which provides the bases for the determination that the change, test, or experiment does not require a license amendment pursuant to Paragraph (c)(2).

Contrary to the above, on September

30, 1996, the licensee failed to perform a written safety evaluation to demonstrate that the deletion of the RHR pump cubicle design flood height from the FSAR did not require a license amendment. The violation is being treated as an NCV, consistent with Section

2.3.2 of the Enforcement Policy because it was of very low safety significance and was entered into the

licensee's

CAP (AR 0 206942 5) (SLIV NCV 05000266/2015003

-0 3; 05000301/2015003

-0 3; Failure to Perform a Written Safety Evaluation for FSAR Changes).

.2 (Closed) Licensee Event Reports

05000266/2015

-003-00; 05000266/2015

-003-01: D-107 Battery Charger Failure to Limit Current Results in Operation or Condition Prohibited by Technical Specifications

On March 9, 2015, the licensee discovered that the current limit feature on Battery Charger D-107 would not function as expected. The licensee's troubleshooting efforts identified a defective crimp on a wire, which caused an intermittent open circuit that disabled the current limit function. The disabled current limiter could have prevented the

charger from performing its design basis function. On May

8, 2015, this event was reported by the

licensee in accordance with 10

CFR 50.73(a)(2)(i)(B) for an operation or condition prohibited by TSs. The licensee repaired the

loose crimp and performed an apparent cause evaluation

to determine any needed long

-term corrective actions. The inspectors reviewed the licensee's assessment and

corrective actions associated with the failed battery charger and identified one Green finding, which was documented in Secti on 1R12 of NRC IR

05000266/2015001; 05000301/2015001. Additionally, the licensee identified one Green finding and violation of NR

C requirements, which was documented in Section

4OA7 of NRC

IR 05000266/2015001; 05000301/2015001.

The inspectors also observed that information contained in the original revision of

the LER was inaccurate.

Specifically, under the Safety

Significance section of the

LER, the licensee stated that plant procedures provided appropriate guidance to manually lower the oncoming charger voltage to match running bus voltage, thus preventing a high current condition. The

inspectors found that the guidance in the associated AOP was not appropriate, and it could not have been accomplished as written. The inspectors assessed the inaccurate information to be a minor performance deficiency. The licensee entered the issue into their CAP and revised the

LER. Documents reviewed are listed in the Attachment to this report. Both the original and revised LER are closed.

.3 (Closed) Licensee Event Report 05000266/2015

-004-00: Out-of-Service A-06 Switchgear Room Fans Result in Operation Prohibited by Technical Specifications

On June 4 , 201 5 , while preparing for planned preventative maintenance on the

G-03/G-04 EDG switchgear room exhaust fans, the licensee discovered that removal of an exhaust fan may result in the inoperability of the associated supported safety

-related switchgear. The licensee performed a

past operability review (POR) which concluded that numerous occasions existed over the past three years where the safety

-related 4.16kV switchgear associated with 'B' Train EDGs w as inoperable, and resulted in a reportable condition d

ue to exceeding allowed outage times required by

TS s. On August 3, 2015, this condition was reported by the

licensee in accordance with

CFR 50.73(a)(2)(i)(B) for the operation or condition prohibited by TSs and

10 CFR 50.73(a)(2)(vii) for the common cause inoperability of independent trains of safety-related electrical power sources and their associated switchgear

. The inspectors reviewed the

LER to determine if the licensee's evaluation and associated corrective actions were appropriate. The inspectors also assessed the accuracy of the

LER, the timeliness of corrective actions, whether additional violations

of requirements occurred, and if potential generic

issues existed. Based on this review the inspectors determined that a licensee

identified NCV

of NRC requirements existed , and is documented in

Section 4OA7 of this report. Documents reviewed are listed in the Attachment to this report. This

LER is closed.

These event follow

-up review s constituted four sample s as defined in IP

71153-05. 4OA5 Other Activities

.1 (Closed) Temporary Instruction (TI) 2515/190, Inspection of the Proposed Interim Actions Associated with Near

-Term Task Force Recommendation 2.1 Flooding Hazard Evaluations

a. Inspection Scope

The inspectors independently verified that the Point Beach staff's proposed interim actions would perform their intended function for flooding mitigation by performing the following:

visual inspection of the flood protection feature if the flood protection feature was relevant; external visual inspection for indications of degradation that would prevent the

flood protection features credited function from being performed was performed;

reasonable simulation, if applicable, to the site; and

flood protection feature functionality was determined using either visual observation or by review of other documents.

The inspectors verified that issues identified were entered into the licensee's CAP. b. Findings No findings were identified. This

TI is closed.

4OA6 Management Meetings

.1 Exit Meeting Summary

On October 14, 2015 , the inspectors presented the inspection results

to Mr.

E. McCartney, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The

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

.2 Interim Exit Meetings

Interim exits were conducted for:

On July 16, 2015, the results of the T

I 2515/190, Inspection of the Proposed Interim Actions Associated with Near

-Term Task Force Recommendation

2.1 Flooding Hazard Evaluations were presented to Mr.

E. McCartney, Site Vice President, and other members of the licensee's staff

On August 21, 2015, the inspection results for the areas of radiation monitoring instrumentation and radioactive gaseous and liquid effluent treatment were discussed with Mr.

E. McCartney, Site Vice President , and other members of the licensee's staff

On September

4, 2015, the results of the biennial licensed operator requalification program area assessment i

nspection were presented to Mr.

D. DeBoer, Plant

General Manager , and other members of the

licensee's staff; and On September

23, 2015, the results of the 2015

licensed operator annual

test were discussed

with Mr.

R. Amundson, Operations Training Supervisor, via telephone.

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

The licensee identified a finding of very low safety significance (Green) and an NCV of

TS 3.8.9; Distribution Systems

-Operating, Condition A

, which required the licensee to immediately declare associated supported features inoperable for the 4.16 kV safeguards busses. Failure

to implement this action subsequently required the licensee to place both units in mode

within 36

hours. Contrary to the above, the licensee discovered that numerous occasions existed over the past three

years where safety

-related 4.16kV switchgear associated with 'B' Train EDGs was inoperable due to the inoperability of the W

-185A and W

-185B, 1A-06 and 2A-06 Switchgear room fans, which were required support systems for the EDGs and associated switchgear.

The inspectors evaluated the

finding in accordance with IMC

0609, Significance Determination Process, and determined that the finding required a detailed risk evaluation which was performed by Region III SRAs. The SRAs gathered data from licensee GOTHIC model calculations, licensee engineering evaluations associated with the POR of the condition and the NRC's Standard Plant Analysis Risk model. Based on the SSCs being available for their respective 24

-hour mission time(s), the SRAs determined that the increase in sk is of very low safety significance (i.e., Green).

The licensee

reported this condition in LER

15-004-00, which was closed in Section 4OA3 of this report. The licensee's corrective actions included improving administrative and procedural controls for removing these fans from service and used lessons learned from this condition to implement corrective actions to improve

procedural guidance for similar activities where ventilation systems may cause support

system inoperabilities.

ATTACHMENT: SUPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION KEY POINTS OF CONTAC

T Licensee

E. McCartney, Site Vice President

D. DeBoer, Plant

General Manager

S. Aerts, Performance

Improvement

Manager

R. Amundson, Training

Operations

Supervisor

R. Baird, Training

Fleet Manager

L. Christensen, Project Manager

A. Cookle, Senior Security Analyst

C. Ford, Maintenance

Support Department

Head

D. Forter, Project Site Manager

A. Gustafson, Training

Ops General Supervisor

R. Harrsch, Engineering

Site Director

M. Millen, Senior Project Manager

T. Ouret, Training

Fleet Manager

R. Parker, Chemistry

Manager

T. Schneider, Senior

Engineer

E. Schultz, Operations

Assistant Manager Line

G. Strharsky, Site Quality Manager

M. Vana, Senior

Training Ops Instructor

R. Webber, Operations

Site Director

R. Welty, Radiation

Protection

Manager

M. Wilcox, On

Line 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 05000266/2015003

-0 1 05000301/2015003

-0 1 FIN Incomplete Functionality Assessment for Flooding in the Diesel Generator Building (Section

1R 15.1) 05000266/2015003

-02 05000301/2015003

-0 2 NCV Potential Failure of Multiple Safety

-Related Trains During Flooding Events

(Section 4OA3.1) 05000266/2015003

-03 05000301/2015003

-0 3 SLIV NCV Failure to Perform a Written Safety Evaluation for FSAR Changes (Section

4OA3.1) Closed 05000266/2015003

-01 05000301/2015003

-01 FIN Incomplete Functionality Assessment for Flooding in the Diesel Generator Building (Section

1R 15.1) 05000266/2015001

-00 LER Inadequately Sealed Pipe Penetration Results in an Unanalyzed Condition for Internal Flooding

(Section 4OA3.1) 05000266/2015003

-00 LER D-107 Battery Charger Failure to Limit Current Results in Operation or Condition Prohibited by Technical

Specifications (Section 4OA3.2) 05000266/2015003

-01 LER D-107 Battery Charger Failure to Limit Current Results in Operation or Condition Prohibited by Technical Specifications (Section 4OA3.2) 05000266/2015004

-00 LER Out-of-Service A-06 Switchgear Room Fans Result in Operation Prohibited by Technical Specifications (Section 4OA3.3) 05000266/2015003

-02 05000301/2015003

-02 NCV Potential Failure of Multiple Safety

-Related Trains During Flooding Events (Section

4OA3.1) 05000266/2015003

-03 05000301/2015003

-03 SLIV NCV Failure to Perform a Written Safety Evaluation for FSAR Changes (Section 4OA3.1) 2515/190 TI Inspection of the Proposed Interim Actions Associated with Near-Term Task Force Recommendation

2.1 Flooding Hazard Evaluations

(Section 4OA5.1)

LIST OF DOCUMENTS REVIEWED The following is a partial list of documents reviewed during the inspection. Inclusion on this list does not imply that the NRC inspector reviewed the documents in their entirety, but rather that selected sections or portions of the documents were evaluated as part of the overall inspection effort. Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.

1R01 Adverse Weather Protection

(71111.01)

- 2015 Summer Readiness Audit; May

14, 2015 - AOP-13C; Severe Weather Conditions; Revision

- AR 01896156; Flooding White Finding and Notice of Violations

- AR 01937424; PBSA

-ENG-15-01 External Events Program Quick Hit Assessment

- AR 02019484; PBSA

-ENG-15-04 Flooding Issues Quick Hit Assessment

- Assessment #:

PBSA-ENG-15-04; Engineering Quick Hit Self

-Assessment Related to Flooding Issues; January

28, 2015 - Condition Report Search for Façade Flood from September

1, 2012 - September 12, 2015 - Condition Report Search for Weather from September

2, 2014 - September 12, 2015 - Entry into Abnormal

Operating Procedure (AOP) Audit; June

11, 2015 - Flooding Strategy Tabletop Audit; January

21, 2015 - NP 8.4.17; PBNP Flooding Program; Revision

- OM 3.30; Operations Snow Emergency Staffing; Revision

- PC 6 Part 9; Flood Mitigation Inventory Checks; Revision

- Prompt Operability Compensatory Action Review Audit; December

23, 2014 - RMP 9422; Circulating Water Pumphouse and Turbine Hall Barrier Placement; Revision

- Table Top Review Session for Required Flooding Barrier Placement Procedural Revisions Audit; August

27, 2014 - Winter 2014 Readiness Review Audit; November

4, 2014 - WM-01.29 PMs Within 7

Days of End of Grace Interval Report; September

2, 2015 - WO 40376098-01; PC-6.9 Operations Flood Equipment Inventory; August

17, 2015 1R04 Equipment Alignment

(71111.04)

- 0-PT-FP-002; Weekly Diesel Engine

-Driven Fire Pump Functional

Test; Revision

- AR 02020656; Inadvertent Operation of Breaker While Hanging Danger

Tag - AR 02033371; Momentary Condenser Hotwell Level Alarm

- AR 02066668; FIT

-4459A Flow Transmitter Was Found Aligned

- AR 02069472; 2SW

-447 Found Open, CL

-10C Position is Shut

- AR 02070664; Valve CD

-119 Mispositioned During Chlorination Event

- AR 02070707; 2X

-06, 2B-40 Diesel Generator Bldg MCC Transformer

- AR 02071554; Emergent Plant Status

Control Meeting Regarding MISPO

Events - CL 10D; Fuel Oil Systems; Revision

- CL 11A G-03; G-03 Diesel Generator Checklist; Revision

- CL 13E Part 1; Auxiliary Feedwater Valve Lineup Turbine

-Driven Unit

2; Revision

- CL 13E Part 2; Auxiliary Feedwater Valve Lineup Motor Driven; Revision

- CL 19; Fire Protection System Valves; Revision

- Control Room Log Entries for August

27, 2015 - Corrective Action Program Misposition Keyword Search from

January 21, 2015 - September 21, 2015 - Drawing M-207; Sheet

1; Service Water; Revision

- Drawing M-208; Sheet

1; Fire Water; Revision

- Drawing M-217; Sheet

1; Auxiliary Feedwater System; Revision

103 - Drawing M-217; Sheet

2; Auxiliary Feedwater System; Revision

- Drawing M-2207; Sheet

1; Service Water; Revision

- Drawing P-159; Aux. F.W. From Heating Boiler CNDS. Return & Pump Recirc. To CNDS Stg. Tank 6" & 3" JG

-4; Revision

- Drawing P-359; Sheet

1; Unit 1 - Turbine Bldg.; Revision

- Drawing P-359; Sheet

2; Unit 1 - Turb. Bldg.; Revision

- FSAR Section 10.2; Auxiliary Feedwater System (AF); UFSAR

2014 - IT 09A; Cold Start of Turbine

-Driven Auxiliary Feed Pump and Valve

Test (Quarterly) Unit

2; Revision 65 1R05 Fire Protection

(71111.05)

- AR 01817087; Temp Power / Housekeeping Concerns Found

- AR 02072938; Transient Combustible Documentation not Complete

- AR 02072943; ANSUL Cart in Circ Water Pump House was not Secured

- Drawing PBC-218 Sheet 3; Fire Protection for Turbine Building Aux. Building & Containment Elev. 26'-0"; Revision

- Drawing PBC

-218 Sheet 19; Fire Protection for Diesel Generator Building; Revision 5

- Drawing PBC-219 Sheet 23; Fire Emergency Procedure 4.10 Aux. Building & Containment Elev. 26'-0"; Revision

- Drawing PBC-219 Sheet 41; Fire Emergency Procedure 4.19 Circulating Water Pumphouse; Revision 5 - FEP 4.8; PAB-26' Unit 1 & 2 VCT Area, Central Tank Area; Revision

- FEP 4.19; Circulating Water Pumphouse; Revision

- FEP 4.20; Site; Revision

- FEP 4.27; Emergency Diesel Generator Building(G

-03/G-04); Revision

- FHAR; Appendix

A Fire Area Analysis Summary Report for Fire Area

A58; Revision

- FHAR; Appendix

A Fire Area Analysis Summary Report for Fire Area

A61; Revision

- FHAR; Appendix

A Fire Area Analysis Summary Report for Fire Area

A71; Revision

- FOP 1.2; Potential Fire Affected Safe Shutdown Components; Revision

- FPEE 1999-003; Diesel Generators G03 & G04 Building Boundaries; Revision

- FPER; Fire Protection Evaluation Report; Revision

- NP 1.9.9; Transient Combustible Control; Revision

- NP 8.4.17; PBNP Flooding Program; Revision

- PBF-2058c; Fire

Round Performance Sheet

-Miscellaneous Areas; September

21, 2015 - PC 74; Conducting and Evaluating Fire Drills; Revision

- Reader Transaction History from September

21, 2015 - September 22, 2015 1R06 Flooding (71111.06)

- AR 01288369; Internal Flooding Concern in the Circulating Water Pump House

- ARP C01 B 1-1; Diesel Fire Pump Running; Revision

- ARP C01 B 1-2; Electric Fire Pump Running; Revision

- Calculation

2009-0008; Circulating Water Pump House Internal/External Flooding; October 2, 2014 - Calculation

201 4-0002; Effects on Safety Equipment of Bypassing the Installed Wave Run

-up Barriers Through the Storm and Subsoil Drain Systems; August

11, 2014 - Calculation

2014-0007; Allowable Flood Levels; October

31, 2014

- Calculation

2014-04473; Internal Flooding Assessment of Emergency Diesel Generator Building; October

16, 2014 - FSAR Section 2.5; Hydrology; UFSAR

2014 - FSAR Appendix A.7; Internal Flooding; UFSAR

2012 - Letter; US Atomic Energy Commission to Wisconsin Electric Power Company and Wisconsin Michigan Power Company; September 26, 1972

- Letter; US Atomic Energy Commission to Wisconsin Electric Power Company and Wisconsin Michigan Power Company; December 10, 1974

- Letter; US Atomic Energy Commission to Wisconsin Electric Power Company and Wisconsin

Michigan Power Company; September 29, 1975

- Letter; US Atomic Energy Commission to Wisconsin Electric Power Company and Wisconsin Michigan Power Company; November 20, 1975

- Letter; Wisconsin Electric Power Company to US Atomic Energy Commission;

February 20, 1973 - Letter; Wisconsin Electric Power Company to US Atomic Energy Commission; February 14, 1975 - Letter; Wisconsin Electric Power Company to US Atomic Energy Commission; February 17, 1975 - Letter; Wisconsin Electric Power Company to US Atomic Energy Commission; April

28, 1975 - Letter; Wisconsin Electric Power Company to US Atomic Energy Commission; October 24, 1975 - Letter; Wisconsin Electric Power Company to US Nuclear Regulatory Commission; May 26, 1976 - OM 4.3.8; Control of Time Critical Operator Actions; Revision

- SCR 2007-0150-01; MOD EC 11174 CWPH Flood Relief Modification; October

29, 2009 - SCR 2009-0057; USAR 01141895 Changes to FSAR

A.7, Plant Internal Flooding; May 5, 2009 - WO 40345512-01; Electric Motor

-Driven Fire Pump Functional

Test; August

13, 2015 1R07 Annual Heat Sink Performance

(71111.07)

- AR 01837285; HX

-13A Spent Fuel Pool Heat Exchanger has Leak

- AR 01837905; Additional Investigation Shows Through Wall Hole on HX

-13A - AR 01911809; SW

-2911-BS Packing Blown Out/UE Declared

- AR 02043804; SFP Cooler Degradation Worse & Replacement Stalled

- AR 02061757; Low Wall Thickness on HX

-13A SFP HX

- AR 02062041; Datum Point Unable to be Verified

- ASME XI R/R/M Pressure

Test Data Sheet for HX

-013A; January

10, 2013 - Drawing E-121202; Diesel Generator Building Concrete Plan @

EL 28'-0"; Revision

- Drawing E-121208; Diesel Generator Building Concrete Sections and Details; Sheet

4; Revision 5 - Drawing E-121210; Diesel Generator Building Concrete Sections and Details; Sheet

6; Revision 6 - ER-AA-201-2001-10000; Attachment

6; Focused Bridging Strategy for Spent Fuel Pool Cooling & Filtration; February

10, 2014 - FA 02043804; Spent Fuel Pool Heat Exchangers HX

-013A & HX-013B and the Attached Service Water (SW) System"; May

8, 2015 - HX-13A Phased Array Scan Results; May

24, 2015 - PBF-1554; Repair/Replacement Form for HX

-013B - WO 40204644-07; GL 89-13 UT Shell Thickness; August

2, 2013

1R11 Licensed Operator Requalification Program

(71111.11)

- 10 CFR 50.59/72.48 Screening No.

2012-0175-01; Update EOPs to Current ERG [Emergency

Response Guidelines]; Revision

- 2014 Week 4 LORT Comprehensive Written RO Exam

- 2014 Week 4 LORT Comprehensive Written SRO Exam

- 2015 Week 3 Scenario PBN LOC 000 016E; Revision

- 2015 Week 3 Scenario PBN LOC 000 017E; Revision

- 2015 Week 4 Scenario PBN LOC 000 026E; Revision 4 - 2015 Week 4 Scenario PBN LOC 000 043E; Revision

- Academic Review Board Meeting; December

2, 2015 - Apparent Cause Evaluation for AR

0183223; Revision

- AR 01836045; EOP

-0 Background Document Potentially Incorrect

- AR 01836383; OI 39 PAB Vent Note for LCO 3.7.14 Incorrect

- AR 01859099; Broken Simulator Recorder 6019 Relocated From U1 to U2

- AR 01904359; Inaccurate DEP PI Implementation During Evaluated LOC Scenario

- AR 01971700; Evaluate Recommended Enhancements to OM

4.3.8 - AR 01980471; SWR Validation

- SG Pressures Out

-of-Tolerance - AR 02035238; Training Observation UNSAT

- AR 02043755; LOC Simulator Training Exceeds 10 Students (Approved)

- AR 02054168; PFAT Process Is Being Used Improperly In Some Instances

- AR 02059064; Recent Change Has Disabled Simulator Standalone Hard drives

- AR 02062314; STA Biennial Written Exam Requirements Need A Decision

- AR 02063994; Assessment AFI

- Alt Path JPMs Require Additional Review

- AR 02065595; Simulator Procedures Not Replaced During Segment 15D

- AR 02069079; Conformance With Licensed Operator Medical Vulnerability

- AR 02071664; Steam Generator Tube Rupture Time Critical Action Control

- AR 02075939; Annual Operating Examination EP Errors

- Crew Simulator Evaluation Form; Crew E, Team 1

- Crew Simulator Evaluation Form; Crew E, Team 2

- Five JPMs from 2015 Week 4 of the Requalification Exams

- Focused Self

-Assessment No. PBSA

-TRN-15-02; OPS 71111.11 Pre Inspection Assessment; SAR No. 02028438; Focused Area Self

-Assessment; June

- 5, 2015 - Four JPMs from 2015 Week 3 of the Requalification Exams - Individual Simulator Evaluation Forms; Crew

A; Segment

15E - LOC Long Range Training Program 2013

- 2018 - OM 1.1; Conduct of Plant Operations, PBNP Specific; Revision

- OM 4.3.8; Control of Time Critical Operator Actions; Revision

- One JPM from 2015 Week 2 of the Requalification Exams

- OP-AA-100-1001; License Maintenance and Activation; Revision

- PBN LOC 027E; NRC Annual Operating Exam; Revision

- PBNP LOCT Segment

15E Schedules; Licensed Operator Continuing Training; August 10, 2015 through September 2 5, 2015 - PBSA-TRN-15-02; Focused Self

-Assessment

- Point Beach Operations Self

-Evaluation and Trending Analysis Report for 1

st Quarter 2015; May 1, 2015 - Point Beach Operations Self

-Evaluation and Trending Analysis Report for 2

nd Quarter 2015; July 27, 2015 - SEG PBN LOC 000 043E; Scenario Based Testing; Revision

- SEG PBN LOC 000 E; Scenario Based Testing; Revision

- Simulator Comprehensive Assessment Finding for AR

01854671; March

1, 2013

- Simulator Evaluation Form; Crew

A; Segment

15E - Simulator Review Committee

Minutes 2 nd Quarter 2015; June

3, 2015 - Simulator Test SCT6.1.4; 100% Power Steady State Drift Test; August

25, 2014 - Simulator Test SCT6.2.3; 28% Power Steady State Performance Test; December

15, 2013 - Simulator Test SCT6.3.1; 100% Heat Balance; August

26, 2014 - TR-AA-104; NextEra Energy Fleet Licensed Operator Continuing Training Program; Revision 6 - TR-AA-220-1002; NRC Licensed Operator Exam Security; Revision

- TR-AA-220-1004; Licensed Operator Continuing Training Annual Operating and Biennial Written Exams; Revision

- TR-AA-230-1004; SAT [Systematic Approach to Training] Implementation; Revision

- TR-AA-230-1007; Conduct of Simulator Training and Evaluation; Revision

- TR-AA-230-1009; Training Examination Security; Revision

1R12 Maintenance Effectiveness

(71111.12)

- 1ICP 02.001BL; Reactor Protection and Engineered Safety Features Blue Channel Analog

Day Surveillance

Test; Revision

- AR 01854297; CN

-CPS-07-13 Discrepancy

with TS 3.3.2-1 4.E., STPT

2.2 - AR 01913395; ER Improvement Plan

- RPS Channels

- AR 01936887; ITC

-00408L / Refurbishment Needed

- AR 01962494; 1FC

-474A/B Recent Bistable OOT's

- AR 01967175; TS 3.3.1 NOTE

/ TS 3.3.2 NOTE

Not Consistently Followed

- AR 01998340; Found Instruments Out of Tolerance During ICP

04.0001C - AR 01998974; Instruments Found Out of Tolerance During ICP

04.001D - AR 02018291; As Found OOT 1TC

-403D - AR 02026362; LREV of CE Identifies Missed Opportunity

- AR 02049677; IT

-406A White of Delta Setpoint

Channel Failed Low

- AR 02054210; 1

-FC-474B Found Out of Spec 1ICP

2.001BL - AR 02058625; 1FC

-474A/B Still Drifting After Refurbishment

- AR 02059958; EC 279296 Changes Incorrectly Implemented

- AR 02060246; 1FC

-00474A/B Setpoint Adjust

- EC 279296 - AR 02060265; 1FC

-00475A/B Setpoint Adjust

- EC 279296 - AR 02060271; 2FC

-00464A/B Setpoint Adjust - EC 279296 - AR 02060273; 2FC

-00465A/B Setpoint Adjust

- EC 279296 - AR 02060276; 2FC

-00474A/B Setpoint Adjust

- EC 279296 - AR 02060277; 2FC

-00475A/B Setpoint Adjust

- EC 279296 - AR 02067197; Foxboro Refurbishment WO's

- CE 01962494; 1

-FC-474A/B Recent Bistable OOT's - CE 01967175; TS 3.1.1 NOTE

/ TS 3.3.2 NOTE

Not Consistently Followed

- CE 02018291; As Found OOT 1TC

-403D - CE 02054210; 1FC

-474B Found Out of Spec During WO 40332063 1ICP 02.001BL - Function Lists for All Maintenance Rule Systems for RP; March 12, 2013 - Maintenance Rule Functional Failure Evaluation, ITM

-00402B for AR

2049677 - Maintenance Rule Functional Failure Evaluation, LT

-00426 for CR

01944790 - Maintenance Rule Performance Criteria for RP System; June

23, 2004 - NP 7.7.5; Maintenance Rule

Monitoring; Revision

- NP 8.3.8; Maintenance Calibrations Response and Review; Revision

- Scope Change Request Form for AR

01962494; LOOP

B Steam Flow High/High

-High Bistable

- Unit 1 4.16kV System Health Report from April

1, 2015 - June 30, 2015 - Unit 1 Radiation Protection System Health Report from April

1, 2015 - June 30, 2015

- WO 40182511; 1TM

-00402B / Refurbish Setpoint 1 Dynamic Compensator

- WO 40240493; 2

-PC-486C Refurbishment Bistable

- WO 40253464; 1FC

-474A/B Refurbish Bistable

- WO 40292087; 1TC

-00408L / Refurbishment Needed

- WO 40305107; 2LC

-472C, Repair and Refurbish Low Level Bistable

- WO 40315939; 1FC

-475A/B: Refurbish Bistable 1R35 or Before

- WO 40315940; 1FC

-464A/B: Refurbish Bistable 1R35 or Before

- WO 40356854; ITC

-403A/D Refurbishment Bistable

- WO 40363201; 2PC

-486C / Reinstall 2

-PC-00486C Back into Plant

- WO 40399690; 1FC

-474A/B - Still Drifting After Refurbishment

1R13 Maintenance Risk Assessments and Emergent Work Control

(71111.13)

- AR 02051282; NP8.4.16, HELB Barriers, Doesn't Include All Barriers to EDG - AR 02057542; Safety Monitor Look Ahead Scheduling on 5/19/2015

- AR 02065159; Fire MR(A)(4) In

-Scope SSC OOS for More Than 30

Days - AR 02073919; On

-Line Safety Assessment of Scheduled Work

- Condition Report Search for Emergent Work from March

28, 2015 - September 28, 2015 - Condition Report Search for Safety Monitor from March

28, 2015 - September 28, 2015 - Control Room Log Entries for August

3, 2015 - August 7, 2015 - Control Room Log Entries for August

4, 2015 - August 6, 2015 - Control Room Log Entries for

August 6, 2015 - August 7, 2015 - Control Room Log Entries for July

6, 2015 - Control Room Log Entries for July

17, 2015 - Control Room Log Entries for July

27, 2015 - ICP 06.008-1 Instrument and Service Air System 18

Month Calibration; Revision

- NP 10.3.7; On

-Line Safety Assessment; Revision

- NP 10.3.7; On

-line Safety Assessment; Revision

- PBF-1658; Safety Monitor Change Notice for PBTP

258 FW to SW

Test; July

17, 2015 - Point Beach Station Daily Status Report; Unit

1; August 4, 2015 - Unit 1 Safety Monitor for

July 6, 2015 - Unit 1 Safety Monitor for July

17, 2015 - Unit 1 Safety Monitor for July

27, 2015 - Unit 1 Safety Monitor for August

4, 2015 - Unit 1 Safety Monitor for August

5, 2015 - Unit 1 Safety Monitor for October

2, 2015 - Unit 2 Safety Monitor for July

6, 2015 - Unit 2 Safety Monitor for July

17, 2015 - Unit 2 Safety Monitor for July

27, 2015 - Unit 2 Safety Monitor for August

4, 2015 - Unit 2 Safety Monitor for August

2, 2015 - Unit 2 Safety Monitor for October

2, 2015 - Unit 2 Safety Monitor for October

9, 2015 - Unit 2 Safety Monitor for October

24, 2015 1R15 Operability Determinations and Functional Assessments

(71111.15)

- 0-TS-EP-001; Weekly Power Availability Verification; Revision

- AR 01837285; HX

-13A Spent Fuel Pool Heat Exchanger has Leak

- AR 01837905; Additional Investigation Shows Through Wall Hole on HX

-13A - AR 02011512; Unable to Complete Scheduled Activities

- AR 02039244; Significant Change to OD/FA Process Not Trained

- AR 02043804; SFP Cooler Degradation Worse & Replacement Stalled

- AR 02044783; Reduced Available

Operator Response Time for DGB Flood

- AR 02052030; POR Request for W

-185A & B A-06 Switchgear Room Fans

- AR 02055129; Non

-Consequential Omission in FA02044783

- AR 02057684; Incomplete Surveillance

- SR 3.8.9.1 Distribution System

- AR 02057722; (P)

0-TS-EP-001 - Weekly Power Availability Verification

- AR 02058356; Using Admin Controls for SR 3.8.9.1 - AR 02058356; Using Administrative Controls for SR 3.8.9.1 - AR 02058744; TS B 3.8.9 (LAR 273 & CR

2058356) - AR 02061757; Low Wall Thickness on HX

-13A SFP HX

- AR 02062041; Datum Point Unable to be Verified

- AR 02062318; TS B 3.8.9 - Distribution Systems

-Operating - AR 02066328; Compensatory Measures Not Created for Functionality Issues

- AR 02073745; Functionality Action Assignment Issues

- AR 02074593; Compensatory Measures for

FA 2044783 Questioned

- ASME XI R/R/M Pressure

Test Data Sheet for HX

-013A; January

10, 2013 - Calculation

2014-04473; Internal Flooding Assessment of Emergency Diesel Generator Building; Revision

- Condition Report Search for Functionality Assessments from

March 28, 2015 - September 28, 2015 - Condition Report Search for Operability Determination from

March 28, 2015 - September 28, 2015 - Control Room Log Entries for Fire Pump

- Control Room Log Entries for March

20, 2013 - Control Room Log Entries for March 31, 2013 - Control Room Log Entries for April

1, 2013 - Control Room Log Entries for October

11, 2014 - Control Room Log Entries for October

24, 2014 - Control Room Log Entries for P

-35 - Drawing E-222209; Diesel Generator Building Piping Arrangement Sections;

Revision 5 - EC 284095; Heatup Evaluation of G03/G04 Switchgear Room; July

20, 2015 - EC 284298; Electrical Support for POR

2052030-01; July 16, 2015 - EN-AA-203-1001; Operability Determinations/Functionality Assessments; Revision

- EN-AA-203-1001; Operability

Determinations/Functionality Assessments; Revision

- ER-AA-201-2001-10000; Attachment

6; Focused Bridging Strategy for Spent

Fuel Pool Cooling & Filtration; February

10, 2014 - FA 02043804; Spent Fuel Pool Heat Exchangers HX

-013A & HX-013B and the Attached

Service Water (SW) System"; May

8, 2015 - FA 02044783; Reduced Available Operator Response Time for DGB Flood

- Rev 1; July 30, 2015 - FA 02044783; Reduced Available Operator Response Time for DGB Flood; May

21, 2015 - FA 02044783; Reduced Available Operator Re

sponse Time for DGB Flood

- Revision 1; July 30, 2015 - HX-13A Phased Array Scan Results; May

24, 2015 - LER 266/2015-001-00; Inadequately Sealed Pipe Penetrations Result in an Unanalyzed Condition for Internal Flooding; ; January

19, 2015 - PBF-1554; Repair/Replacement Form for HX

-013B - PI-AA-104-1000; Corrective Action; Revision

- POR 02052030; POR Request for W

-185A & B A-06 Switchgear Room Fans; July

20, 2015 - Reader Transaction History from July

30, 2015

- Reader Transaction History from August

16, 2015 - Reader Transaction History from August

17, 2015 - Reader Transaction History from September

3, 2015 - SER 2001-0007; Safety Evaluation for Conversion to Improved Tech Specs

- VPNPD-90-222; Electrical Inspection Exit Meeting Point Beach Nuclear Plant; May

10, 1990 - WO 402 04644-07; GL 89-13 UT Shell Thickness; August

2, 2013 1R19 Post-Maintenance Testing

(71111.19)

- 0-PT-FP-002; Weekly Diesel Engine

-Driven Fire Pump; Revision

- 0-PT-FP-002; Weekly Diesel Engine

-Driven Fire Pump; Revision

- 0-SOP-DC-003; 125 VDC System, Bus D-03 & Components; Revision

- 1RMP 9045-5; 1DY-04 Yellow Channel Instrument Bus Static Inverter Maintenance Procedure; Revision

- 1-SOP-CC-001; Component Cooling System; Revision

- 2RMP 9036-6; 2DY-02 Blue Channel Instrument Bus Static Inverter Maintenance Procedure; Revision 28 - AR 01728040; W

-86 Failed PMT

- Low Flow Alarm in While Running in Slow

- AR 01889770; Unexpected Alarm for W

-86 Low Flow

- AR 02063818; NRC Identified HELB Bar

rier Questions

- AR 02064783; New Valve SW

-573, SW X-Connect From FP Shut - AR 02069101; D

-106/Low Individual Cell Voltage on Cell

1. 48 - AR 02069303; NFPA 805 LAR Supplement Complete with Open FP Owner Comments

- AR 02072448; MTN Proc Doesn't Implement Reqs of HELB & Penetrating Barrie

- AR 02076105; P

-35B Fails to Start on Battery

- Calculation

N-93-059; D106 Sizing, Voltage Drop and Short Circuit Calculation; Revision

- Control Room Log Entries for July

6, 2015 - Control Room Log Entries for August

7, 2015 - CR 97-1419; Prompt Operability Determination (PODs) That Could Not be Located

in the RES Files; April

30, 1997 - DBD-02; Component Cooling Water System; Revision

- DBD-17; Vital 120 VAC System Design Basis Document; Revision

- DBD-29; Auxiliary Building and Control Building HVAC; Revision

- EC 259770; NRC Order Fukushima FLEX Diesel

Fire Pump Replacement / SW X

-Tie NRC 2013-0024 Letter, NRC Order EA

-12-0-49; Revision

- EC 281936; FS

-4909/4910, Flow Switch Replacement; August

29, 2014 - Fire Protection Evaluation Report; Revision

- FSAR Section 8.6; 120 VAC Vital Instrument Power (Y);

UFSAR 2013 - FSAR Section 8.7; 120 VDC Electrical Distribution System; UFSAR

2013 - FSAR Section 9.1; Component Cooling Water (CC); UFSAR

2014 - NP 8.4.16; PBNP High Energy Line Break Barriers/Vent Paths; Revision

- NPC-36820; Safety Evaluation Modification to

Instrumentation Power Supply; April

21, 1980 - OI 35 (480V); 480V Electrical Equipment Operation; Revision

- PBTP 258; P-35B Diesel Driven Fire Pump and Service Water Cross Tie Modification Acceptance

Test; Multiple

Revisions - PBTP 258; P-35B Diesel Driven Fire Pump and Service Water Cross Tie Modification Acceptance Test; Revision

- PCR 02064890; P

-35B Diesel Driven Fire Pump and Service Water Cross Tie Modification Acceptance Test

- Station Log for September

4, 2015 - VNBI Air Flow Measurements; January

26, 20 12

- WO 347173-78; P-035B/Ops PMT Testing

- EC 259770 - WO 40092908; W

-86 PAB/BATT INVERT RM VENT Fan Air Filter; January

28, 2012 - WO 40143606; W

-86 Failed PMT

- Low Flow Alarm in While Running in Slow; April

18, 2012 - WO 40331279; 2DY

-02 - Maintain and Inspect

Inverter; July

8, 2015 - WO 40331279-01; 2DY, Perform De

-Energized Portion of 2RMP 9036

-6 - WO 40339105-01; 1P-011A/Install Support Bracket on IB/OB Oiler/Sight Glass

- WO 40342576; Diesel Engine

-Driven Fire Pump Functional

Test; August

7, 2015 - WO 40347176-01; 1P-011A-M, MCE Analyze Motor (1B52

-10A/1B-03) w/RIC - WO 40364552; W

-086 Lubricate Fan Bearings; July

6, 2015 - WO 40364569-01; 1P-011A Change Oil, Flush Bearings and Clean Intake Grills

- WO 40364569-02; 1P-011A Operations PMT/RTS

- WO 40408516; D

-106/Perform Battery Load Test After Cell Replacement; August

29, 2015 - WO 40410103; CH1(RED) Delta T to ind E/I conv; September

20, 2015 1R22 Surveillance Testing

(71111.22)

- 1ICP 02.001WH; Reactor Protection and Engineered Safety Features White Channel Analog

Day Surveillance Test; Revision

- 2ICP 02.001YL; Reactor Protection and Engineered Safety Features Yellow Channel Analog

Day Surveillance

Test; Revision

- 2ICP 04.029

-4; Rod Insertion Limit Control and T Comp Signal Input Outage Calibration; Revision 10 - ACE 02045383; Missed IST Surveillance Requirement; May

27, 2015 - AR 02045383; Missed 48

Month Testing Freq 1

st Requirement

- AR 02065907; Vacuum Breaker 1CC

-779A Missed IST Testing Frequency

- AR 02065938; Replace, Test Vacuum Relief 1CC

-779A - AR 02065940; Replace, Test 2CC-779A CC Surge Tank Vacuum Breaker

- IT 06 Train A; Train A Containment Spray Pump and Valves Unit

2; September

16, 2015 - IT 03 Train B; Low Head Safety Injection Pumps and Valves Train

B Unit 1; Revision

- OP-AA-100-1000-F01; Adverse Condition Monitoring and Contingency Plan for DGB Fire System Integrity; May

26, 2015 - POD 02065907; Vacuum Breaker 1CC

-779A Missed IST Testing Frequency; August

13, 2015 - STPT 6.1; Setpoints: Rod Insertion Limit Alarms; Revision

- TS 6; Rod Exercise Test Unit

2; Revision

- WO 40342559; 2ICP 2.1YL

- RP/SG Analog

- Yellow; July

29, 2015 - WO 40353190; IT

-06 Train A, 2P-14A Cont Spray Pump; September

16, 2015 - WO 40355595-01; IT-03 Train B, 1P-10B Low Head SI Pumps/Vlvs; September

28, 2015 1EP6 Drill Evaluation

(71114.06)

- AOP 29; Security Threat; Revision

- AR 02066514; 2015

-PreEx Sensitivity to Hostile Action Response

- AR 02066516; 2015

-PreEx Coordination Between Facilities

- AR 02066517; 2015

-PreEx Reentry Team Command and Control

- AR 02066518; 2015

-PreEx Depth of Critique on Crew Performance

- AR 02066519; 2015

-PreEx TRFD Facility Command and Control

- AR 02066520; 2015

-PreEx Equipment

Issues - AR 02066521; 2015

-PreEx TRFD RP Reentry Team Briefings

- AR 02066523; 2015

-PreEx EOF Access for Incident Commander

- AR 02066525; 2015

-PreEx County Dispatch Initial Reporting Template Confusion

- AR 02066526; 2015

-PreEx Offisite Agencies Improvement Areas

- AR 02066527; 2015

-PreEx On-Site Accountability During HAB Scenario

- AR 02066528; 2015

-PreEx Security Processes at JPIC

- AR 02066531; 2015

-PreEx Error in News Release from JPIC

- EPIP 1.1; Course of Actions; Revision

- EPIP 1.2; Emergency Classification; Revision

- EPIP 1.3; Dose Assessment and Protective Actions Recommendations; Revision

- EPIP 10.1; Emergency Reentry; Revision

- NARS Form for Drill; August 4, 2015 07:57 a.m. - NARS Form for Drill; August

4, 2015 09:37 a.m. - Point Beach Emergency Preparedness Drill Scenario; August

4, 2015 2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and Transportation

(71124.08)

- 2015 DAW Data Analysis per 10 CFR 61; August

13, 2015 - AR 01865299; Radioactive Shipment Vehicle in Accident

- AR 02060793; Issue with RDW

14.4 and Used Radioactive Oil Storage

- AR 02060871; Rad Material Storage Areas May Need Review for FSAR Update

- AR 02061452; Minor Discrepancy in Shipping Documents for SGLA

- RDW 14.3; Steam Generator Storage Facility Low

-Level Radioactive Waste Storage Requirements; Revision

- RDW 14.4; Requirements for the Storage of Containers in Outside Areas Including Warehouse 7; Revision

- RDW 18.1; Determining Activity and Radionuclide Content of Radwaste and Radioactive Material Packages; Revision

- RDW 18.1.1; 10 CFR 61 Sampling Program; Revision

- RDW 18.2; Radwaste Classification, Shipment Type and Waste Stability Determination; Revisi on 2 - RP-AA-107; Radioactive Material Control Program; Revision

- RP-AA-108-1002; Shipment of Radioactive Material; Revision

- RP-AA-108-1003; Radioactive Materials Surveys for Shipment; Revision

- RP-AA-108-1004; Packaging Radioactive Materials for Shipment; Revision

- Transportation Package 14

-024C; Unit

"A" Steam Generator

- Transportation Package 14

-024E; Four Steam Generators on Canal Barge

- Transportation Package 14

-024F; Four Steam Generators on Train

- Transportation Package 14

-042; Dry Active Waste

- Transportation Package 14

-052; Fuel Cleaning Equipment

- Transportation Package 15

-008; Primary Resin

4OA1 Performance Indicator Verification

(71151) - AR 01899071; 2A52

-89 50G Relay Control Power

- AR 01994937; MSPI Data Error for G

-01 May 2014 - AR 01995233; Corrections to MSPI Data for EAC May

2014 - AR 02017498; MOB 182 Power Inadvertently Interrupted/CI Indication Lost

- AR 02017951; Trend Only Alert on 2P

-15A SI Pump Vibes

- AR 02030649; Control Power Light Out for 50G/2A52

-88 Ground Relay

- Control Room log Entries; Various Dates

- Maintenance Rule System Unavailability Report; May

26, 2015 - MSPI Derivation Report; MSPI Emergency AC Power System; Unavailability Index, Unit

1; December 2014

- MSPI Derivation Report; MSPI Emergency AC Power System; Unreliability Index, Unit 1; December 2014 - MSPI Derivation Report; MSPI Heat Removal System; Unavailability Index, Unit

1; December 2014 - MSPI Derivation Report; MSPI Heat Removal System; Unavailability Index, Unit

1; March 2015 - MSPI Derivation Report; MSPI Heat Removal System; Unavailability Index, Unit

2; September 2014 - MSPI Derivation Report; MSPI Heat Removal System; Unavailability Index, Unit

2; March 2015 - MSPI Derivation Report; MSPI Heat Removal System; Unreliability Index, Unit

1; December 2014 - MSPI Derivation Report; MSPI Heat Removal System; Unreliability Index, Unit

1; March 2015 - MSPI Derivation Report; MSPI Heat Removal System; Unreliability Index, Unit

2; September 2014 - MSPI Derivation Report; MSPI Heat Removal System; Unreliability Index, Unit

2; March 2015 - MSPI Derivation Report; MSPI High Pressure Injection System; Unavailability Index, Unit

1; June 2015 - MSPI Derivation Report; MSPI High Pressure Injection System; Unavailability Index, Unit

1; December 2014 - MSPI Derivation Report; MSPI High Pressure Injection System; Unavailability Index, Unit

2; September 2014 - MSPI Derivation Report; MSPI High Pressure Injection System; Unavailability Index, Unit

2; December 2014 - MSPI Derivation Report; MSPI High Pressure Injection System; Unreliability Index, Unit

1; June 2015 - MSPI Derivation Report; MSPI High Pressure Injection System; Unreliability Index, Unit

1; December 2014 - MSPI Derivation Report; MSPI High Pressure Injection System; Unreliability Index, Unit

2; September 2014 - MSPI Derivation Report; MSPI High Pressure Injection System; Unreliability Index, Unit

2; December 2014 - MSPI Document for Point Beach; Revision

- MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Unit

1; September

2014 - MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Uni

t 1; December

2014 - MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Unit

1; March 2015 - MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Unit

1; June 2015 - MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Unit

2; September 2014 - MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Unit

2; December

2014 - MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Unit

2; March 2015 - MSPI Indicator Margin Remaining in Green for EAC, HPI and HRS, Unit

2; June 2 015 - MSPI Monthly Unavailability and Verification for Auxiliary Feedwater System for April

2015; May 4, 2015 - MSPI Monthly Unavailability and Verification for Auxiliary Feedwater System for December 2014; January

8, 2015 - MSPI Monthly Unavailability and Verification for Auxiliary Feedwater System for March

2015; April 2, 2015 - MSPI Monthly Unavailability and Verification for EAC system for August

2014; September 8, 2014 - MSPI Monthly Unavailability and Verification for EAC system for April

2015; May 5, 2015

- MSPI Monthly Unavailability and Verification for EAC system for December

2014; January 5, 2015 - MSPI Monthly Unavailability and Verification for EAC system for February

2015; March 3, 2015 - MSPI Monthly Unavailability and Verification for EAC system for July

2014; August 4, 2014 - MSPI Monthly Unavailability and Verification for EAC system for September

2014; October 1, 2014 - MSPI Monthly Unavailability and Verification for SI system for February

2015; March

3, 2015 - MSPI Monthly Unavailability and Verification for SI system for July

2014; August

1, 2014 - MSPI Monthly Unavailability and Verification for SI system for May

2015; June

1, 2015 - MSPI Monthly Unavailability and Verification for SI system for November

2014; December 1, 2014 - MSPI Monthly Unavailability and Verification for SI system for October

2014; November 1, 2014 - NEI 99-02; Regulatory Assessment Performance Indicator Guideline; Revision

4OA2 Identification and Resolution of Problems

(71152) - 10 CFR 50.59 Report

91-083-02; Installation of Static Transfer Capability for the Safety-Related Instrument Busses; September

10, 1992 - 12Q0114-R-001; Seismic Walkdown Report in Response to the 50.54(f) Information Request Regarding Fukushima Near

-Term Task Force Recommendation

2.3: Seismic; November 24, 2012 - AOP-1B Unit 1; Reactor Coolant Pump Malfunction; Revision

- Apparent Cause Evaluation for AR

01654178; Packing Leak of 1RC

-431B PZR Spray Valve

- Apparent Cause Evaluation Report for AR

01127323; MRE for 2RC

-431B Cracked Bellow Tell-Tale - Failure Analysis

- AR 0112 7323-011, 012, 013 Evaluation; May

4, 2009 - AR 01127323-14; MRE for 2RC

-431B Cracked Bellow Tell

-Tale - Failure Analysis; July 23, 2008 - AR 01342136; 2RC

-431B Intermediate Leakoff Line Cracked

- AR 01342963; 2RC

-431B Cracked Bellows Tell

-Tale - Failure Analysi

s - AR 01654178; Packing Leak of 1RC

-431B PZR Spray Valve

- AR 01854297; CN

-CPS-07-13 Discrepancy With TS 3.3.2-1 4.E., STPT

2.2 - AR 02057684; Incomplete Surveillance

- SR 3.8.9.1 Distribution System

- AR 02058307; D

-107 A1 Firing Card Replacement Decision Making

Process - AR 02058355; State Disagreement With PAR Strategy for Hostile Action GE

- AR 02058356; Using Administrative Controls for SR 3.8.9.1 - AR 02058410; XE

-133/I-131 in U2 Containment Sump

"A" - AR 02058701; FS

-3207 Failed to Actuate During TS

-87 - AR 02059583; 2RC-431B Has A Bellows Leak and Packing Failure

- AR 02059958; EC 279296 Changes Incorrectly Implemented

- AR 02059975; Possible Gap Identified in Control Room

- AR 02060048; Grout of Shield Wall Not Installed Per MFG Instructions

- AR 02060236; REG Guide

1.21 Section 2.2 Conditions Are Not Being Met

- AR 02060246; 1FC

-00474A/B Setpoint Adjust

- EC 279296 - AR 02060328; High Vibration on Fan Axial Point

- AR 02060329; 2P

-11A CCW Pump Discharge Piping Missing 2

Seismic Bolts

- AR 02061183; Pipe Thinning Found in DDFP

P-035B Discharge Piping

- AR 02061247; Embedded Conduit Found Partially Filled With Water

- AR 02061257; U2 Containment Increase in Activity Levels

- RCS

- AR 02061757; Low Wall Thickness on HX

-13A SFP HX - AR 02071120; 2DY

-04 Swapped Over to Backup "Dirty" Power

- AR 02071174; Potential Trend of PZR Spray Valve Bellows

- BALCM Appendix

C; Boric Acid Indication Evaluation; Revision

- Control Room Log Entries for September

2, 2015 - DBD-17; Vital 120VAC System; Revision

- Documentation of Maintenance Performance

Criteria for RC system; January

11, 2002 - Drawing E-100 Sheet 2; Electrical Plot Plan; Revision

- Drawing PBC-270; Operations Office; Revision

- ER-AP-116; Boric Acid Corrosion Control; Revision

- FPL-02311; Failure Evaluation on a Section of 1/2"

- Schedule 80, Stainless Steel Piping off the Pressurizer Spray Control Valve Removed from the 2RC

-431A Train, Purchase Order No. 22780 Amendment

1, FPL Point Beach, LLC; September

4, 2008 - FPL-96492; Failure Evaluation on a Section of 3/4"

- Schedule 80, Type 304 or 316 Stainless Steel Piping off the Pressurizer Spray Control Valve Identified as 2RC431B, Purchase Order No. 22780 FPL Energy, Point Beach, LLC; May 5, 2008 - MRC Screening Report; July

14, 2015 - NRC 2012-0101; Next

Era Energy Point Beach, LLC Response to 10 CFR 50.54(f) Request for Information Regarding Near

-Term Task Force Recommendation

2.3: Seismic; November 26, 2012 - PBF-9221; Valve Packing Data Sheet; Revision

- RMP 9106; Pressurizer Spray Line Control Valve Maintenance; Revision

- Unit 2 SI Containment Sump

A Sample Results from April

4, 2015 to July 18, 2015 - WO 40151331; 2RC

-00431B Overhaul Valve and Replace Bellows as Required; February 17, 2015 - WO 893802; Bellows Leak Off P.I. Has Tubing CRA; September

15, 1989 - WR 94121710; 2RC

-00431B/Has a Bellows Leak and Packing Failure; July

13, 2015 - X-Y Graph of Leakage Trends Past 400

Days; July

14, 2014 - July 15, 2015 - X-Y Graph of Leakage Trends Past 60

Days; May 11, 2015 - July 10, 2015 4OA3 Follow-Up of Events and Notices of Enforcement Discretion

(71153) - 10 CFR Applicability Determination; Update FSAR Sections

6.2 Safety Injection System

(SI) Section and 9.2.3 (RHR) System Evaluation of the FSAR; May

11, 2015 - ACE 02031054; D

-107 Charger Did Not Current Limit During As

-Found Checks

- Rev. 01; June 25, 2015 - ACE 02052030; W

-185 Fans Removed from Service Without Addressing Impact on Supported Safety-Related Equipment; September

11, 2015 - AOP-0.0; Vital DC System Malfunction; Revision

- AOP-0.0; Vital DC System Malfunction; Revision

- AR 01785426; Unit

Façade Flooding - AR 01785471; 1Z

-30 U1 Façade Elevator Flood

- AR 01785729; Long Standing Equipment Issue

- Façade Flooding

- AR 01806858; Potential Ponding on Northwest Corner of the Protected Area

- AR 01948109; Internal Flooding Hazards in PAB not Fully Evaluated

- AR 01982413; Need Flood Protection at U2 Façade Doors

231 and 232 - AR 01984256; Alber Load Bank Anomaly - AR 01987856; Current Configuration Not Previously Evaluated for Flooding

- AR 01989614; Vulnerability to External Flooding

- AR 01992690; 8" SW Supply, Return Pipe for BDE in PAB May Not be Seismic

- AR 02001639; License Basis Requirements for TB Roof Drains Questioned

- AR 02002165; Flooding Conveyance Path to Facades Not Analyzed

- AR 02002825; Legacy Flooding Modification Concerns

- AR 02004858; Question Screening of AR 2002825 for Functionality

- AR 02006362; PAB Flooding Alarm Feature Questioned

- AR 02006807; Rad Waste Storage Vaults/Flood Conveyance Path

- AR 02008004; Pipe Penetration Grout/Seal Degraded

- AR 02008551; Seal Penetrations in Half Wall In

- 19 El. Unit

RHR Chase - AR 02010158; Lack of Redundancy for Internal Flood Detection

- AR 02011512; Unable to Complete Scheduled Activities

- AR 02012950; Potential New Non

-Seismic PAB Flood Sources

- AR 02013411; AOP

-28 - (P) - AR 02031282; D

-107 Charger Current Limit Not Working Properly

- AR 02046480; Troubleshooting Documentation

- AR 02052030; POR Request for W

-185A & B A-06 Switchgear Room Fans

- AR 02067912; W

-13A1 CSR Fan Failed to Start on Low Flow

- AR 02069425; RHR Pump Cubicle Flood Barriers

- AR 02080343; Flooding Model Did Not Properly Incorporate Relief Paths

- ARP 1C20 A 2-4; Auxiliary Building North Sump Level High; Revision

- ARP 1C20 A 3-4; Auxiliary Building South Sump Level High; Revision

- Calculation PBNP

-994-21-13; HELB Reconstitution Program Task

- Building Recovery; December 15, 2010 - Calculation

2014-0009; In-leakage from Maximum Precipitation Flood; October

5, 2014 - Calculation

2014-0014; Develop Inputs Needed to Establish License Basis Piping Failure Flow Rates; December

19, 2014 - CE 01806858 & 01806867; Potential Ponding on Northwest Corner of Protected Area; October 9, 2012 - CE 02008004; Penetration Through the 7'

Divider Wall in RHR Valve Galleries Not Sealed Well - Change Request Form for AR

2008551; Seal Penetrations in Half Wall In

- 19 EL. Unit

RHR Cha se - Condition Report Search for Flood from November

10, 2015 - November 20, 2015 - Construction Drawing for Temporary Low Level Radwaste Storage Vaults; October

25, 1980 - DBD-10; Residual Heat Removal System; Revision

- DBD-T-41; Hazards

- Internal and External Flooding (Module

A); Revision

- Drawing M-154; Auxiliary Building Drainage Area 8

- Plan at El. 8'

-0"; Revision

- Drawing M-223; Sheet

3; Drainage & Sanitary Waste Systems; Revision

- Drawing PB

31S08003000100; Concrete Vaults; June

2, 1979 - Drawing P BC-346; Plant Area Stormwater Plan; Revision

- EC 0280162; Interior Flood Barriers Doors 12, 14, & 20

- EC 0281314; Seal Penetrations Between PAB Trench and Pipeways 2

& 3 - EC 0282029; Reinforce Masonry Wall Between Façade and PAB

- EC 0282379; Maximum Precipitation - EC 0282395; 8" SW Header

- EC 0282899; Install Level Switches

- EC 0283217; Flood Barrier at Entrance to Pipeway

- FA 01806858; Potential Ponding on Northwest Corner of the Protected Area; October

1, 2012 - FA 02004858; Question Screening of AR

2002825 for Functionality: Inadequate Basis on CLB Change of Façade Flood (95002

-4) - Final Response to Task Interface Agreement 2005

-10 Relating to Impact of Flooding on Residual Heat Removal (RHR) Pumps at Kewaunee Power Station (Task Interface Agreement (TIA) 20 05-10)(TAC No. MC8937); May

5, 2006

- FSAR Section 9.2; Residual Heat Removal (RHR); UFSAR

2014 - FSAR Appendix A.2; High Energy Pipe Failure Outside Containment; UFSAR

2013 - FSAR Appendix A.7; Plant

Flooding; UFSAR

2014 - LER 266/2015-001-00; Inadequately Sealed

Pipe Penetrations Result in an Unanalyzed Condition for Internal Flooding; January

19, 2015 - LER 266/201 5-004-00; Out-of-Service A-06 Switchgear Room Fans Result in Operation Prohibited by Technical Specifications

- Letter from Advisory Committee on Reactor Safeguards to Chairman,

U.S. Atomic Energy Commission; Report on Point Beach Nuclear Plant, Unit

No. 1; May 16, 1967 - Letter from Atomic Energy Commission to Wisconsin Electric Power Company;

October 31, 1967 - Letter from Next

E ra Energy Point Beach to

U.S. Nuclear Regulatory Commission; NextEra Energy Point Beach, LLC Response to 10 CFR 50.54(f) Request for Information Regarding Near

-Term Task Force Recommendation

2.3, Flooding; November

20, 2012 - Letter from Westinghouse Electric Corporation to Bechtel Corporation; Residual Heat Pump Compartment; May

2, 1967 - Letter from Westinghouse Electric Corporation to Bechtel Corporation; ACRS Requirements on the Residual Heat Pump Compartment; June

26, 1967 - Letter from Westinghouse Electric Corporation to Wisconsin Michigan Power Company; Unit No. 2 FSAR Suppl. No.

1; December

29, 1967 - List of Open Operability/Functionality

Issues for August

31, 2015 - List of Open Operability/Functionality

Issues for September

4, 2015 - NEPB-87-250; Evaluation of SOER 85-5 Internal Flooding

of Power Plant Buildings; April 16, 1987 - OM 3.7; AOP and EOP Procedure Usage for Response to Plant Transients; Revision

- PB041853-02; Refined FSAR Change Documents for the September

1996 FSAR Chapter 9; October 15, 1997 - POD AR 01948109; Internal Flooding Hazards in PAB Not Fully Evaluated; September 24, 2014 - POR 02008551; Seal Penetrations in Half Wall in

-19 El. Unit

RHR Chase; January

15, 2015 - POR 02052030; POR Request for W

-185A & B A-06 Switchgear Room Fans; July

20, 2015 - Preliminary Facility Description and Safety Analysis Report Supplement

1; Dated January 11, 1968 - RMP 9359-6A; D-105 Station Battery, D

-107 Battery Charger Maintenance and Surveillances; Revision 8 - WO 40302870-14; D-107 Current Limit Out of Range; August

14, 2014 - WO 40302870-15; D-107, Troubleshoot and Repair Battery Charger; August

13, 2014 - WO 40351967-01; WL/Perform Flow Verification of PAB Floor Drain Lines

- WO 40353503-01; PAB/Investigate Material in Half Wall

- 19 El. sU1 RHR Chase

4OA5 Other Activities

- EC-0000284296; (Evaluation 2015

-0016, Revision

0) Locally Intense Precipitation Flooding Coping Strategies (Flood Levels); Revision

- FPL-076-FHRPR; Point Beach Flood Hazard Revaluation Report; Revision

- Supplemental Information Related To Request for Information Pursuant to Title 10 of the Code of Federal Regulations

50.54(f) Regarding Flooding Hazard Reevaluations for Recommendation

2.1 of the Near

-Term Task Force Review of Insights from the Fukushima Dai

-Ichi Accident; ML13044A561

LIST OF ACRONYMS USE

D ACE Apparent Cause Evaluation

ADAMS Agencywide Document Access Management System

AOP Abnormal Operating Procedure

AR Action Request

CAP Corrective Action Program

CDF Core Damage Frequency

CCDP Conditional Core Damage Probability

CCW Component Cooling Water

CFR Code of Federal Regulations

CW Circulating Water

DDFP Diesel-Driven Fire Pump

DGB Diesel Generator Building

EDG Emergency Diesel Generator

EP Emergency Preparedness

EPRI Electric Power Research Institute

ET Exposure Time

FA Functional Assessment

FP Fire Protection

FSAR Final Safety Analysis Report

GPM Gallons Per Minute

HEP Human Error Probability

IEF Initiating Event Frequency

IMC Inspection Manual Chapter

IP Inspection Procedure

IR Inspection Report

JPM Job Performance Measure

KV Kilovolt LER Licensee Event Report

LERF Large Early Release Frequency

LLC Limited Liability Corporation

LOCA Loss-of-Coolant-Accident LOOP Loss of Offsite Power

LORT Licensed Operator Requalification Training

MSPI Mitigating Systems Performance Index

MCR Main Control Room

NCV Non-Cited Violation NEI Nuclear Energy Institute

NFPA National Fire Protection Association

NRC U.S. Nuclear Regulatory Commission

OOS Out-of-Service PAB Primary Auxiliary Building

PARS Publicly Available Records

System PI Performance Indicator

PI&R Problem Identification and Resolution

PMT Post-Maintenance

Testing POD Prompt Operability Determination

POR Past Operability Review

PWR Pressurized Water Reactor

QA Quality Assurance

RASP Risk Assessment Standardization Project

RCS Reactor Coolant System

RFO Refueling Outage

RHR Residual Heat Removal

RP Radiation Protection

SAT Systems Approach to Training

SDP Significance Determination Process

SFP Spent Fuel Pool

SG Steam Generator

SI Safety Injection

SRA Senior Risk Analyst

SSC Structures, Systems, and Components

SSD Safe Shutdown SW Service Water

TS Technical Specification

VAC Volts Alternating Current

VDC Volts Direct Current

WO Work Order

WR Work Request

E. McCartney

-2- inspection

in the NRC's Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading

-rm/adams.html

(the Public Electronic Reading Room).

Sincerely, /RA John Rutkowski Acting for/

Jamnes Cameron, Chief

Branch 4

Division of Reactor Projects

Docket Nos. 50

-266; 50-301 License Nos. DPR

-24; DPR-27 Enclosure: IR 05000266/2015003; 05000301/201500

w/Attachment: Supplemental Information

cc w/encl: Distribution via LISTSERV

DISTRIBUTION

w/encl: Janelle Jessie

RidsNrrDorlLpl3

-1 Resource

RidsNrrPMPointBeach

RidsNrrDirsIrib Resource

Cynthia Pederson

Darrell Roberts

Richard Skokowski

Allan Barker

Carole Ariano

Linda Linn

DRPIII DRSIII Jim Clay Carmen Olteanu

ROPreports.Resource@nrc.gov

ADAMS Accession Number ML15302A428

Publicly Available

Non-Publicly Available

Sensitive Non-Sensitive To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy

OFFICE RIII RIII RIII RIII NAME JRutkowski:cs

JRutkowski for

JCameron DATE 10/29/15 10/29/15 OFFICIAL RECORD COPY