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{{#Wiki_filter: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
{{#Wiki_filter:UNITED STATES ber 29, 2015


Two Rivers, WI 54241 SUBJECT: POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2
==SUBJECT:==
- NRC INTEGRATED INSPECTION REPORT 05000 266/20 15003; 05000 301/20 15003
POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000266/2015003; 05000301/2015003


==Dear Mr. McCartney:==
==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.
On September 30, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on 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.
Based on the results of this inspection, three NRC-identified findings of very low safety significance were identified. Two of the findings involved violations of NRC requirements.


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.
Additionally, one licensee-identified violation is listed in Section 4OA7. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.


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
If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with 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.


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).
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)
component of the NRC's Agencywide Documents Access and Management System (ADAMS).
 
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).


Sincerely,
Sincerely,
/RA John Rutkowski Acting for/
/RA John Rutkowski Acting for/
Jamnes Cameron, Chief Branch 4 Division of Reactor Projects
Jamnes Cameron, Chief Branch 4 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27
 
Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27  


===Enclosure:===
===Enclosure:===
IR 05000 266/20 15003; 05000301/20 15003 w/Attachment: Supplemental Information
IR 05000266/2015003; 05000301/2015003 w/Attachment: Supplemental Information


REGION III==
REGION III==
Docket Nos:
Docket Nos: 05000266; 05000301 License Nos: DPR-24; DPR-27 Report No: 05000266/2015003; 05000301/2015003 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 Enclosure
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=
=SUMMARY OF FINDINGS=
................................
......................................................................................................... 4
 
................................................................
......... 4


=REPORT DETAILS=
=REPORT DETAILS=
 
  ............................................................................................................... 7 Summary of Plant Status ........................................................................................................ 7 1.
  ................................
................................................................
...............
7 Summary of Plant Status
................................
................................................................


==REACTOR SAFETY==
==REACTOR SAFETY==
................................
.................................................................................................. 7
................................................................
.. 7
{{a|1R01}}
{{a|1R01}}
==1R01 Adverse Weather Protection==
==1R01 Adverse Weather Protection==
{{IP sample|IP=IP 71111.01}}
{{IP sample|IP=IP 71111.01}}
................................
........................................................... 7
...........................
 
{{a|1R04}}
{{a|1R04}}
==1R04 Equipment Alignment==
==1R04 Equipment Alignment==
{{IP sample|IP=IP 71111.04}}
{{IP sample|IP=IP 71111.04}}
................................
...................................................................... 8
...................................... 8
{{a|1R05}}
{{a|1R05}}
==1R05 Fire Protection==
==1R05 Fire Protection==
{{IP sample|IP=IP 71111.05}}
{{IP sample|IP=IP 71111.05}}
................................
................................................................................ 9
................................................
 
{{a|1R06}}
{{a|1R06}}
==1R06 Flooding==
==1R06 Flooding==
{{IP sample|IP=IP 71111.06}}
{{IP sample|IP=IP 71111.06}}
................................
........................................................................................10
........................................................
{{a|1R07}}
10 1R07 Annual Heat Sink Performance (71111.07)
==1R07 Annual Heat Sink Performance==
................................
{{IP sample|IP=IP 71111.07}}
......................
......................................................11
 
{{a|1R11}}
{{a|1R11}}
==1R11 Licensed Operator Requalification Program==
==1R11 Licensed Operator Requalification Program==
{{IP sample|IP=IP 71111.11}}
{{IP sample|IP=IP 71111.11}}
................................
..................................11
..11
{{a|1R12}}
{{a|1R12}}
==1R12 Maintenance Effectiveness==
==1R12 Maintenance Effectiveness==
{{IP sample|IP=IP 71111.12}}
{{IP sample|IP=IP 71111.12}}
............................................................
............................................................15
 
{{a|1R13}}
{{a|1R13}}
==1R13 Maintenance Risk Assessments and Emergent Work Control==
==1R13 Maintenance Risk Assessments and Emergent Work Control==
{{IP sample|IP=IP 71111.13}}
{{IP sample|IP=IP 71111.13}}
.......16 1R15 Operability Determinations and Functional Assessments (71111.15)
.......16
..............
{{a|1R15}}
 
==1R15 Operability Determinations and Functional Assessments==
{{IP sample|IP=IP 71111.15}}
..............16
{{a|1R19}}
{{a|1R19}}
==1R19 Post-Maintenance Testing==
==1R19 Post-Maintenance Testing==
{{IP sample|IP=IP 71111.19}}
{{IP sample|IP=IP 71111.19}}
................................
.............................................................19
.............................
 
{{a|1R22}}
{{a|1R22}}
==1R22 Surveillance Testing==
==1R22 Surveillance Testing==
{{IP sample|IP=IP 71111.22}}
{{IP sample|IP=IP 71111.22}}
................................
......................................................................19
......................................19 1EP6 Drill Evaluation (71114.0 6) ................................
{{a|1EP6}}
..............................................
==1EP6 Drill Evaluation==
{{IP sample|IP=IP 71114.06}}
..............................................................................21 2.


==RADIATION SAFETY==
==RADIATION SAFETY==
................................
...............................................................................................21
...............................................................


{{a|2RS8}}
{{a|2RS8}}
==2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and Transportation==
==2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling,==
{{IP sample|IP=IP 71124.08}}
 
................................
Storage, and Transportation (71124.08) ..........................................................21 4.
..........................


==OTHER ACTIVITIES==
==OTHER ACTIVITIES==
................................
.................................................................................................25
................................................................
 
===.25
{{a|4OA1}}
{{a|4OA1}}
==4OA1 Performance Indicator Verification==
==4OA1 Performance Indicator Verification==
===
{{IP sample|IP=IP 71151}}
{{IP sample|IP=IP 71151}}
................................
......................................................25
......................
 
{{a|4OA2}}
{{a|4OA2}}
==4OA2 Identification and Resolution of Problems==
==4OA2 Identification and Resolution of Problems==
{{IP sample|IP=IP 71152}}
{{IP sample|IP=IP 71152}}
................................
...........................................27
...........
 
{{a|4OA3}}
{{a|4OA3}}
==4OA3 Follow-Up of Events and Notices of Enforcement Discretion==
==4OA3 Follow-Up of Events and Notices of Enforcement Discretion==
{{IP sample|IP=IP 71153}}
{{IP sample|IP=IP 71153}}
..............
..............29


{{a|4OA5}}
{{a|4OA5}}
==4OA5 Other Activities==
==4OA5 Other Activities.......................................................................................................42==


................................
................................................................
.......42
{{a|4OA6}}
{{a|4OA6}}
==4OA6 Management Meetings==
==4OA6 Management Meetings ....................................................................................42==
 
................................
....................................................


{{a|4OA7}}
{{a|4OA7}}
==4OA7 Licensee-Identified Violations==
==4OA7 Licensee-Identified Violations ..........................................................................43==
 
................................
..........................................
43  


=SUPPLEMENTAL INFORMATION=
=SUPPLEMENTAL INFORMATION=


................................
==KEY POINTS OF CONTACT==
.............................................................
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
I, "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
: [[contact::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
: [[contact::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
: [[contact::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
: [[contact::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
: [[contact::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
: [[contact::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
: [[contact::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
: [[contact::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
: [[contact::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:
Licensee
- 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
#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
#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
: [[contact::B.
a) For the Base Case]], 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.
: [[contact::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.
: [[contact::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.
: [[contact::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.
: [[contact::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.
: [[contact::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  
: [[contact::E. McCartney]], Site Vice President
: [[contact::E. McCartney]], Site Vice President
: [[contact::D. DeBoer]], Plant
: [[contact::D. DeBoer]], Plant General Manager
General Manager  
: [[contact::S. Aerts]], Performance Improvement Manager
: [[contact::S. Aerts]], Performance
: [[contact::R. Amundson]], Training Operations Supervisor
Improvement
: [[contact::R. Baird]], Training Fleet Manager
Manager  
: [[contact::R. Amundson]], Training
Operations
Supervisor  
: [[contact::R. Baird]], Training
Fleet Manager  
: [[contact::L. Christensen]], Project Manager
: [[contact::L. Christensen]], Project Manager
: [[contact::A. Cookle]], Senior Security Analyst
: [[contact::A. Cookle]], Senior Security Analyst
: [[contact::C. Ford]], Maintenance
: [[contact::C. Ford]], Maintenance Support Department Head
Support Department
Head  
: [[contact::D. Forter]], Project Site Manager
: [[contact::D. Forter]], Project Site Manager
: [[contact::A. Gustafson]], Training
: [[contact::A. Gustafson]], Training Ops General Supervisor
Ops General Supervisor
: [[contact::R. Harrsch]], Engineering Site Director
: [[contact::R. Harrsch]], Engineering
Site Director
: [[contact::M. Millen]], Senior Project Manager
: [[contact::M. Millen]], Senior Project Manager
: [[contact::T. Ouret]], Training
: [[contact::T. Ouret]], Training Fleet Manager
Fleet Manager  
: [[contact::R. Parker]], Chemistry Manager
: [[contact::R. Parker]], Chemistry
: [[contact::T. Schneider]], Senior Engineer
Manager  
: [[contact::E. Schultz]], Operations Assistant Manager Line
: [[contact::T. Schneider]], Senior
: [[contact::G. Strharsky]], Site Quality Manager
Engineer  
: [[contact::M. Vana]], Senior Training Ops Instructor
: [[contact::E. Schultz]], Operations
: [[contact::R. Webber]], Operations Site Director
Assistant Manager Line  
: [[contact::R. Welty]], Radiation Protection Manager
: [[contact::G. Strharsky]], Site Quality Manager  
: [[contact::M. Wilcox]], On Line Manager
: [[contact::M. Vana]], Senior
Training Ops Instructor  
: [[contact::R. Webber]], Operations
Site Director  
: [[contact::R. Welty]], Radiation
Protection
Manager  
: [[contact::M. Wilcox]], On
Line Manager  
: [[contact::P. Wild]], Design Engineering Manager
: [[contact::P. Wild]], Design Engineering Manager
: [[contact::B. Woyak]], Licensing
: [[contact::B. Woyak]], Licensing Manager
Manager  Nuclear Regulatory Commission
Nuclear Regulatory Commission
: [[contact::J. Cameron]], Chief, Reactor Projects Branch 4
: [[contact::J. Cameron]], Chief, Reactor Projects Branch 4


LIST OF ITEMS OPENED, CLOSED , AND DISCUSSED
==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
#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
===Opened===
- AR 02002825; Legacy Flooding Modification Concerns
: 05000266/2015003-01  FIN    Incomplete Functionality Assessment for Flooding in the
- AR 02004858; Question Screening of AR 2002825 for Functionality
: 05000301/2015003-01          Diesel Generator Building (Section 1R15.1)
- AR 02006362; PAB Flooding Alarm Feature Questioned
: 05000266/2015003-02  NCV    Potential Failure of Multiple Safety-Related Trains During
- AR 02006807; Rad Waste Storage Vaults/Flood Conveyance Path
: 05000301/2015003-02          Flooding Events (Section 4OA3.1)
- AR 02008004; Pipe Penetration Grout/Seal Degraded
: 05000266/2015003-03  SLIV  Failure to Perform a Written Safety Evaluation for FSAR
- AR 02008551; Seal Penetrations in Half Wall In
: 05000301/2015003-03  NCV    Changes (Section 4OA3.1)
- 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,
: [[contact::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
: [[contact::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
===Closed===
D ACE Apparent Cause Evaluation
: 05000266/2015003-01  FIN    Incomplete Functionality Assessment for Flooding in the
ADAMS Agencywide Document Access Management System
: 05000301/2015003-01          Diesel Generator Building (Section 1R15.1)
AOP Abnormal Operating Procedure
: 05000266/2015001-00  LER    Inadequately Sealed Pipe Penetration Results in an
AR Action Request
Unanalyzed Condition for Internal Flooding
CAP Corrective Action Program
                              (Section 4OA3.1)
CDF Core Damage Frequency
: 05000266/2015003-00  LER    D-107 Battery Charger Failure to Limit Current Results in
CCDP Conditional Core Damage Probability
Operation or Condition Prohibited by Technical
CCW Component Cooling Water
Specifications (Section 4OA3.2)
CFR Code of Federal Regulations
: 05000266/2015003-01  LER    D-107 Battery Charger Failure to Limit Current Results in
CW Circulating Water
Operation or Condition Prohibited by Technical
DDFP Diesel-Driven Fire Pump
Specifications (Section 4OA3.2)
DGB Diesel Generator Building
: 05000266/2015004-00  LER   Out-of-Service A-06 Switchgear Room Fans Result in
EDG Emergency Diesel Generator
Operation Prohibited by Technical Specifications
EP Emergency Preparedness
                              (Section 4OA3.3)
EPRI Electric Power Research Institute
: 05000266/2015003-02  NCV    Potential Failure of Multiple Safety-Related Trains During
ET Exposure Time
: 05000301/2015003-02          Flooding Events (Section 4OA3.1)
FA Functional Assessment
: 05000266/2015003-03  SLIV  Failure to Perform a Written Safety Evaluation for FSAR
FP Fire Protection
: 05000301/2015003-03  NCV    Changes (Section 4OA3.1)
FSAR Final Safety Analysis Report
2515/190              TI    Inspection of the Proposed Interim Actions Associated
GPM Gallons Per Minute
with Near-Term Task Force Recommendation 2.1
HEP Human Error Probability
Flooding Hazard Evaluations (Section 4OA5.1)
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
==LIST OF DOCUMENTS REVIEWED==
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
}}
}}

Revision as of 05:09, 31 October 2019

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  NextEra Energy icon.png
Issue date: 10/29/2015
From: Jamnes Cameron
Reactor Projects Region 3 Branch 4
To: Mccartney E
Point Beach
References
IR 2015003
Download: ML15302A428 (67)
v • d • e


Text

UNITED STATES ber 29, 2015

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000266/2015003; 05000301/2015003

Dear Mr. McCartney:

On September 30, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on 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 violations of NRC requirements.

Additionally, one licensee-identified violation is listed in Section 4OA7. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with 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 NRCs Public Document Room or from the Publicly Available Records (PARS)

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

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

Sincerely,

/RA 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; 05000301/2015003 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000266; 05000301 License Nos: DPR-24; DPR-27 Report No: 05000266/2015003; 05000301/2015003 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 Enclosure

SUMMARY OF FINDINGS

......................................................................................................... 4

REPORT DETAILS

............................................................................................................... 7 Summary of Plant Status ........................................................................................................ 7 1.

REACTOR SAFETY

.................................................................................................. 7

1R01 Adverse Weather Protection

Main article: IP 71111.01

........................................................... 7

1R04 Equipment Alignment

Main article: IP 71111.04

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

1R05 Fire Protection

Main article: IP 71111.05

................................................................................ 9

1R06 Flooding

Main article: IP 71111.06

........................................................................................10

1R07 Annual Heat Sink Performance

Main article: IP 71111.07

......................................................11

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

..................................11

1R12 Maintenance Effectiveness

Main article: IP 71111.12

............................................................15

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

.......16

1R15 Operability Determinations and Functional Assessments

Main article: IP 71111.15

..............16

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.............................................................19

1R22 Surveillance Testing

Main article: IP 71111.22

......................................................................19

1EP6 Drill Evaluation

Main article: IP 71114.06

..............................................................................21 2.

RADIATION SAFETY

...............................................................................................21

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling,

Storage, and Transportation (71124.08) ..........................................................21 4.

OTHER ACTIVITIES

.................................................................................................25

4OA1 Performance Indicator Verification

Main article: IP 71151

......................................................25

4OA2 Identification and Resolution of Problems

Main article: IP 71152

...........................................27

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

Main article: IP 71153

..............29

4OA5 Other Activities.......................................................................................................42

4OA6 Management Meetings ....................................................................................42

4OA7 Licensee-Identified Violations ..........................................................................43

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

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

05000266/2015003-01 FIN Incomplete Functionality Assessment for Flooding in the
05000301/2015003-01 Diesel Generator Building (Section 1R15.1)
05000266/2015003-02 NCV Potential Failure of Multiple Safety-Related Trains During
05000301/2015003-02 Flooding Events (Section 4OA3.1)
05000266/2015003-03 SLIV Failure to Perform a Written Safety Evaluation for FSAR
05000301/2015003-03 NCV Changes (Section 4OA3.1)

Closed

05000266/2015003-01 FIN Incomplete Functionality Assessment for Flooding in the
05000301/2015003-01 Diesel Generator Building (Section 1R15.1)
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 NCV Potential Failure of Multiple Safety-Related Trains During
05000301/2015003-02 Flooding Events (Section 4OA3.1)
05000266/2015003-03 SLIV Failure to Perform a Written Safety Evaluation for FSAR
05000301/2015003-03 NCV 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

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