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IR 05000315/2014005, 05000316/2014005; on 10/01/2014 - 12/31/2014; Donald C. Cook Nuclear Power Plant, Units 1 and 2; Operability Determinations and Functional Assessments; Plant Modifications; Post Maintenance Testing; Radiological Hazard
	ML15042A380
Person / Time
Site:	Cook
Issue date:	02/10/2015
From:	Kenneth Riemer; NRC/RGN-III/DRP/B2
To:	Weber L; Indiana Michigan Power Co, Nuclear Generation Group
References
	IR 2014005
	Download: ML15042A380 (69)
	v • d • e

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION III

2443 WARRENVILLE RD. SUITE 210

LISLE, IL 60532-4352

February 10, 2015

Mr. Larry Weber

Senior VP and Chief Nuclear Officer

Indiana Michigan Power Company

Nuclear Generation Group

One Cook Place

Bridgman, MI 49106

SUBJECT: DONALD C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2

NRC INTEGRATED INSPECTION REPORT 05000315/2014005;

05000316/2014005

Dear Mr. Weber:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Donald C. Cook Nuclear Power Plant, Units 1 and 2. The enclosed report

documents the results of this inspection, which were discussed on January 20, 2015, with

yourself and members of your staff.

Based on the results of this inspection, three NRC-identified and two self-revealed findings of

very low safety significance were identified. The findings involved violations of NRC

requirements. However, because of their very low safety significance, and because the issues

were entered into your corrective action program, the NRC is treating the issues as

non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy

If you contest the subject or severity of these NCVs, you should provide a response within

30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a

copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III,

2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement,

U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector

Office at the Donald C. Cook Nuclear Power 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 Donald C. Cook

Nuclear Power Plant.

L. Weber

-2-

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/

Kenneth Riemer, Chief

Branch 2

Division of Reactor Projects

Docket Nos. 50-315; 50-316

License Nos. DPR-58; DPR-74

Enclosure:

IR 05000315/2014005; 05000316/2014005

w/Attachment: Supplemental Information

cc w/encl: Distribution via LISTSERV

Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos:

05000315; 05000316

License Nos:

DPR-58; DPR-74

Report No:

05000315/2014005; 05000316/2014005

Licensee:

Indiana Michigan Power Company

Facility:

Donald C. Cook Nuclear Power Plant, Units 1 and 2

Location:

Bridgman, MI

Dates:

October 1 through December 31, 2014

Inspectors:

J. Ellegood, Senior Resident Inspector

T. Taylor, Resident Inspector

J. Cassidy, Senior Health Physicist

M. Garza, Emergency Response Specialist

T. Go, Health Physicist

J. Lennartz, Project Engineer

M. Mitchell, Health Physicist

M. Phalen, Senior Health Physicist

E. Sanchez Santiago, Reactor Inspector

Approved by:

Kenneth Riemer, Chief

Branch 2

Division of Reactor Projects

TABLE OF CONTENTS

SUMMARY OF FINDINGS ........................................................................................................... 2

REPORT DETAILS ....................................................................................................................... 6

Summary of Plant Status ........................................................................................................... 6

1.

REACTOR SAFETY ................................................................................................. 6

1R01

Adverse Weather Protection (71111.01) ............................................................ 6

1R04

Equipment Alignment (71111.04) ....................................................................... 7

1R05

Fire Protection (71111.05) .................................................................................. 8

1R06

Flooding (71111.06) ........................................................................................... 9

1R07

Annual Heat Sink Performance (71111.07) ...................................................... 10

1R08

Inservice Inspection Activities (71111.08P) ...................................................... 10

1R11

Licensed Operator Requalification Program (71111.11) .................................. 13

1R12

Maintenance Effectiveness (71111.12) ............................................................ 15

1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13) ....... 15

1R15

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

1R18

Plant Modifications (71111.18) ......................................................................... 21

1R19

Post-Maintenance Testing (71111.19) ............................................................. 24

1R20

Outage Activities (71111.20) ............................................................................ 27

1R22

Surveillance Testing (71111.22) ....................................................................... 28

1EP4

Emergency Action Level and Emergency Plan Changes (71114.04) ............... 29

2.

RADIATION SAFETY ............................................................................................. 31

2RS1

Radiological Hazard Assessment and Exposure Controls (71124.01) ............. 31

2RS2

Occupational As-Low-As-Reasonably-Achievable Planning and Controls

(71124.02) ........................................................................................................ 37

2RS7

Radiological Environmental Monitoring Program (71124.07) ........................... 38

4.

OTHER ACTIVITIES .............................................................................................. 40

4OA1

Performance Indicator Verification (71151) ...................................................... 40

4OA2

Identification and Resolution of Problems (71152) ........................................... 45

4OA3

Followup of Events and Notices of Enforcement Discretion (71153) ............... 49

4OA6

Management Meetings ..................................................................................... 50

SUPPLEMENTAL INFORMATION ............................................................................................... 1

KEY POINTS OF CONTACT..................................................................................................... 1

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED ......................................................... 2

LIST OF DOCUMENTS REVIEWED ......................................................................................... 3

LIST OF ACRONYMS USED .................................................................................................. 13

2

SUMMARY OF FINDINGS

Inspection Report 05000315/2014005, 05000316/2014005; 10/01/2014 - 12/31/2014;

Donald C. Cook Nuclear Power Plant, Units 1 and 2; Operability Determinations and Functional

Assessments; Plant Modifications; Post-Maintenance Testing; Radiological Hazard Assessment

and Exposure Controls.

This report covers a 3-month period of inspection by resident inspectors and announced

baseline inspections by regional inspectors. Three Green findings were identified by the

inspectors. Additionally, there were two Green self-revealed findings. The findings were

considered non-cited violations (NCVs) of NRC regulations. The significance of inspection

findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and

determined using 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 NRCs Enforcement Policy dated July 9, 2013. The NRC's

program for overseeing the safe operation of commercial nuclear power reactors is described in

NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.

Cornerstone: Mitigating Systems

Green. A finding of very low safety significance, with an associated non-cited violation of

10 CFR Part 50, Appendix B, Criterion 16, Corrective Actions, was identified by the

inspectors for the licensees failure to promptly identify and correct a condition adverse

to quality (CAQ) associated with Unit 1 Turbine-Driven Auxiliary Feedwater (TDAFW)

pump turbine bearing oil. Specifically, the licensee failed to identify that water was

entering the oil system after leakage had been identified directly above one of the

TDAFW pump turbine bearings. On April 7, 2014, a cooling water leak was identified

above the outboard turbine bearing. The leak was classified as about 1 drop-per-minute

(dpm). On April 11, 2014, the licensee discovered the turbine bearing oil level was

above the maximum mark on an attached sight glass. Several possible reasons were

postulated for the high level (which had been steady in-band for over a year), such as

rising turbine building temperatures and the fact that it was not uncommon for personnel

to do unnecessary oil adds to the machine. Oil was drained out until level returned to

the maximum mark. On May 22, 2014, the licensee again noted oil level to be above the

maximum mark. Oil was drained again, and similar reasons provided for the level

increase. Further, a statement was made that oil level had been steady for the past

month, neglecting the previous high level condition. In parallel, NRC inspectors had

questioned why level was being maintained at the maximum mark when the operator

logs and a sign stated level should be kept at the minimum mark. On May 23, the

licensee decided to drain the oil system; 620 ml of water was found. New oil was added,

and a temporary modification was installed which directed leakage away from the

bearing. The issue was entered into the Corrective Action Program (CAP), and an

apparent cause evaluation later determined the leakage to be the primary intrusion

pathway for the water.

The issue was more-than-minor because it adversely affected the Configuration Control

attribute of the Mitigating Systems Cornerstone, whose objective is to ensure the

availability, reliability, and capability of systems that respond to initiating events to

prevent undesirable consequences. Additionally, if left uncorrected, the issue could lead

to a more significant safety concern. The inspectors assessed the finding for

3

significance using IMC 0609, Significance Determination Process. Per Appendix A, the

finding screened as Green, or very low safety significance, in Exhibit 2. Specifically, all

questions were answered no under Section A for findings related to Mitigating

Structures, Systems and Components (SSCs) and Functionality. The inspectors

reviewed the licensees past operability evaluation and concluded that given the

projected amount of water that could be entrained in the oil during operation, along with

the duration of operation assumed in the safety analyses, that operability of the pump

would be maintained. The finding had an associated cross-cutting aspect in the Human

Performance area, specifically, H.11, Challenge the Unknown. Regarding the TDAFW

oil system, the licensee rationalized why the level was increasing without sufficient

investigation given the significance of the system, and did not seek further information

that was readily available regarding appropriate oil levels. (Section 1R15)

Green. A finding of very low safety significance, with an associated non-cited violation

of Technical Specification (TS) 5.4, Procedures, was self-revealed when a vacuum was

inadvertently drawn on the AB Fuel Oil Storage Tank (FOST) during preparations for

surveillance activities. The vacuum caused an indication of lowering level in the tank,

alarms, and an unplanned TS Limiting Condition for Operation (LCO) action statement

entry. The licensee was performing work activities in preparation for a leak test of the

FOST. The general sequence of activities should have been a loosening of the vent

filter for the tank, a transfer of fuel from the FOST to the Emergency Diesel Generator

(EDG) day tanks, removal of the FOST from service, and finally removal of the vent filter

so test equipment could be connected to the tank. Due to ambiguous work instruction

steps and activities not being adequately controlled to ensure the proper sequence

occurred, workers first removed the vent filter completely and placed a Foreign Material

Exclusion (FME) bag over the vent. When operators later transferred fuel, a vacuum

was drawn in the tank and level appeared to be going down. Utilizing a manual method

of level measurement (which had also been affected by the vacuum), operators

determined fuel was actually being lost from the tank to the environment. Shortly

thereafter, the bag was found and removed, and level restored to normal (there was no

actual loss of fuel). Technical Specification 5.4, Procedures, states, in part, that written

procedures shall be established, implemented, and maintained covering the applicable

procedures recommended in Regulatory Guide 1.33. Regulatory Guide 1.33 states, in

part, that maintenance that can affect the performance of safety-related equipment

should be properly preplanned and performed in accordance with written procedures,

documented instructions, or drawings appropriate to the circumstances. Contrary to

these requirements, the FOST surveillance was performed with inadequate instructions

and was not coordinated appropriately. The licensee entered the issue into the CAP and

performed a root cause analysis.

The performance deficiency was more than minor because it adversely impacted the

Configuration Control attribute of the Mitigating Systems cornerstone, whose objective is

ensuring the availability, reliability, and capability of systems that respond to initiating

events to prevent undesirable consequences. The finding screened as Green, or very

low safety significance, utilizing IMC 0609, Appendix A, The Significance Determination

Process for Findings at Power. Specifically, all questions were answered no under

Section A of Exhibit 2 for Mitigating Systems, since that was the affected cornerstone.

The FME bag was installed, which rendered the AB FOST inoperable, for approximately

16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months . This was less than the TS allowed outage time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The finding had

an associated cross-cutting aspect in the human performance area, specifically, H.5,

Work Management. Work activities should be planned, controlled, and executed with

4

nuclear safety as the overriding priority. Contrary to the tenets of the cross-cutting

aspect, the work was planned and executed with inadequate work instructions. Further,

there was a lack of coordination between a number of work groups and activities

associated with the test. (Section 1R15)

Green. A finding of very low safety significance, with an associated non- violation

of TS 5.4, Procedures, was self-revealed on November 1, 2014, when the Unit 1

TDAFW pump tripped during an emergent dual-unit shutdown. Both units were taken

offline by operators due to debris intrusion from Lake Michigan into the cooling water

screenhouse. The TDAFW pump started as expected but shutdown after a few minutes

of operation. Investigation by the licensee revealed that a cover for the trip solenoid had

been installed incorrectly. The cover was relatively loose and had been placed near

components involved with the proper latching of the Trip and Throttle valve (TTV) (the

valve which opens to let steam in to turn the pump on). After refuting several possible

causes and running the pump several times for testing, the licensee determined the

likely cause of the trip was the misplaced enclosure, which could have interfered with the

proper latching of the TTV. Technical Specification 5.4, Procedures, states, in part,

that written procedures shall be established, implemented, and maintained covering the

applicable procedures recommended in Regulatory Guide 1.33. Regulatory Guide 1.33

states, in part, that maintenance that can affect the performance of safety-related

equipment should be properly preplanned and performed in accordance with written

procedures, documented instructions, or drawings appropriate to the circumstances.

Contrary to these requirements, the cause of the misplaced enclosure was due to a lack

of detailed instructions regarding the installation and removal of the enclosure. The

enclosure was most recently affected by maintenance performed during the fall 2014

refueling outage. The licensee worked with the vendor and reinstalled the enclosure

correctly. The Unit 2 TDAFW pump trip solenoid enclosure was also found out of

position and corrected. The licensee entered the issue into the CAP.

The performance deficiency was more than minor because it adversely impacted the

Configuration Control attribute of the Mitigating Systems cornerstone, whose objective is

ensuring the availability, reliability, and capability of systems that respond to initiating

events to prevent undesirable consequences. The inspectors utilized IMC 0609

Appendix A, The Significance Determination Process for Findings at Power, to assess

the significance of the finding. Per Exhibit 2, the finding represented a loss of function

for one train of Auxiliary Feedwater (AFW) for greater than the TS allowed outage time.

Therefore, the inspectors consulted the regional Senior Reactor Analyst for a detailed

risk evaluation. The inspectors considered the Unit 1 TDAFW pump inoperable since

the last successful surveillance on October 23, 2014. Given the evidence available, this

was the likely opportunity for the conditions to be established to set-up the improper

engagement between the TTV and the trip hook. In the detailed analysis, the finding

screened as Green, or very low safety significance. The finding had an associated

cross-cutting aspect in the area of human performance, specifically, H.8, Procedure

Adherence. During maintenance, work proceeded on the trip enclosure despite a lack of

detailed instructions on the removal/installation of the enclosure. (Section 1R19)

Cornerstone: Barrier Integrity

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

Criterion 3 Design Control, for the licensees inadequate radiological review of

permanently removing the Auxiliary Missile Blocks (AMBs) from the Unit 1 and Unit 2

5

containment accident shields. The finding was determined to be more than minor

because it was associated with the Barrier Integrity Cornerstone attribute of design

control; and adversely affected the cornerstone objective of maintaining radiological

barrier functionality of the safety-related accident shield. Specifically, the failure to

control plant design and adequately evaluate the radiological effects of permanently

removing the AMBs from the Unit 1 and Unit 2 containment accident shields did not

ensure that the accident shield will provide its design function to ensure safe radiation

levels outside the containment building following a maximum design basis accident.

The inspectors evaluated the finding 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. Because the finding

impacted the Barrier Integrity Cornerstone, the inspectors screened the finding through

IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,

dated June 19, 2012, using Exhibit 3, Barrier Integrity Screening Questions. The

finding screened as very-low safety significance (Green) because the finding only

represented a degradation of the radiological barrier function provided for the Auxiliary

Building. The inspectors determined the cause of this finding did not represent current

licensee performance and, thus, no cross-cutting aspect was assigned. (Section 1R18)

Cornerstone: Occupational Radiation Safety

Green. The inspectors identified a finding of very-low safety significance for inadequate

procedures used to verify Locked High Radiation Controls in the Unit 2 Containment with

an associated non- violation of TS 5.4, Procedures. As a result, weekly, from

November 1, 2013, to March 2014, multiple Radiation Protection Technicians verified the

Unit 2 Upper Containment Cavity Gate was locked; however it did not secure the area

against unauthorized access.

The inspectors determined that the performance deficiency was more than minor

because if left uncorrected the performance deficiency could lead to a more significant

safety concern. Specifically, the failure to identify deficient Locked High Radiation Area

(LHRA) controls could result in unintentional exposure to high levels of radiation. The

finding was determined to be of very-low safety significance because the problem was

not an as-low-as-is-reasonably-achievable (ALARA) planning issue, there was no

overexposure, nor substantial potential for an overexposure, and the licensees ability to

assess dose was not compromised. The inspectors did not identify a corresponding

cross-cutting aspect for this performance deficiency. The licensee entered the

deficiency in their Corrective Action Program as Action Request (AR) 2014-9001

immediately upon discovery and presentation by the inspectors. (Section 2RS1.1)

6

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period in a refueling outage. On October 29, 2014, the plant was

restored to 100 percent power. On November 1, rough lake conditions generated substantial

amounts of debris that clogged trash racks and travelling screens. The licensee manually

tripped the reactor and maintained the plant in hot standby (Mode 3). On November 8, the

licensee restored the plant to 100 percent power.

Unit 2 began the inspection period at 100 percent power. On November 1, 2014, rough lake

conditions generated substantial amounts of debris that clogged trash racks and travelling

screens. The licensee reduced power to 50 percent to reduce circulating water flow.

Conditions continued to degrade; therefore the licensee manually tripped the reactor. The

licensee cooled down and entered Mode 5 to repair an intermediate range nuclear instrument.

On November 13, the plant was restored to 100 percent power.

1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

.1

Winter Seasonal Readiness Preparations

a.

Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to

verify that the plants design features and implementation of procedures were sufficient

to protect mitigating systems from the effects of adverse weather. Documentation for

selected risk-significant systems was reviewed to ensure that these systems would

remain functional when challenged by inclement weather. During the inspection, the

inspectors focused on plant specific design features and the licensees procedures used

to mitigate or respond to adverse weather conditions. Additionally, the inspectors

reviewed the Updated Final Safety Analysis Report (UFSAR) and performance

requirements for systems selected for inspection, and verified that operator actions were

appropriate as specified by plant specific procedures. Cold weather protection, such as

heat tracing and area heaters, was verified to be in operation where applicable. The

inspectors also reviewed CAP items to verify that the licensee was identifying adverse

weather issues at an appropriate threshold and entering them into their CAP in

accordance with station corrective action procedures. Documents reviewed are listed in

the Attachment to this report. The inspectors reviews focused specifically on the

following plant systems due to their risk significance or susceptibility to cold weather

issues:

This inspection constituted one winter seasonal readiness preparations sample as

defined in Inspection Procedure (IP) 71111.01-05.

b.

Findings

No findings were identified.

7

.2

Readiness for Impending Adverse Weather ConditionHigh Wind Conditions

a.

Inspection Scope

On November 6, 2014, the National Weather Service predicted high winds and rough

lake conditions in the vicinity of the plant. Since debris intrusion during similar conditions

the previous week had resulted in damage to equipment and a dual unit plant trip, the

inspectors validated the sites readiness for the adverse weather. The inspectors

reviewed the licensees overall preparations/protection for the expected weather

conditions. The inspectors walked down the service water screen house to assess the

licensee progress on repairing trash racks and traveling water screens. The inspectors

evaluated the licensee staffs preparations against the sites procedures and determined

that the staffs actions were adequate. During the inspection, the inspectors focused on

actions taken to minimize debris intrusion and operators preparations to address

degradation of raw water systems. The inspectors also reviewed a sample of CAP items

to verify that the licensee identified adverse weather issues at an appropriate threshold

and disposed them through the CAP in accordance with station corrective action

procedures. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition

sample as defined in IP 71111.01-05.

b.

Findings

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:

Unit 2 Residual Heat Removal system after maintenance;

Unit 2 Steam Generator (SG) power-operated relief valves during maintenance

on other power-operated relief valves; and

Unit 2 AFW during maintenance on a single train.

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, UFSAR, 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

8

identified and resolved equipment alignment problems that could cause initiating events

or impact the capability of mitigating systems or barriers and entered them into the CAP

with the appropriate significance characterization. Documents reviewed are listed in the

Attachment to this report.

These activities constituted three partial system walkdown samples as defined in

IP 71111.04-05.

b.

Findings

No findings were identified.

.2

Semiannual Complete System Walkdown

a.

Inspection Scope

On December 30, 2014, the inspectors completed a complete system alignment

inspection of the Unit 1 Containment Spray system to verify the functional capability of

the system. This system was selected because it was considered both safety significant

and risk significant in the licensees probabilistic risk assessment. The inspectors

walked down the system to review mechanical and electrical equipment lineups;

electrical power availability; system pressure and temperature indications, as

appropriate; component labeling; component lubrication; component and equipment

cooling; hangers and supports; operability of support systems; and to ensure that

ancillary equipment or debris did not interfere with equipment operation. A review of a

sample of past and outstanding WOs was performed to determine whether any

deficiencies significantly affected the system function. In addition, the inspectors

reviewed the CAP database to ensure that system equipment alignment problems were

being identified and appropriately resolved. Documents reviewed are listed in the

Attachment to this report.

These activities constituted one complete system walkdown sample as defined in

IP 71111.04-05.

b.

Findings

No findings were identified.

1R05 Fire Protection (71111.05)

.1

Routine Resident Inspector Tours (71111.05Q)

a.

Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability,

accessibility, and the condition of firefighting equipment in the following risk-significant

plant areas:

Unit 2 AB EDG;

Unit 2 CD EDG;

Unit 2 Quadrant cable tunnels; and

Unit 1 Essential Service Water Motor Control Center Room.

9

The inspectors reviewed areas to assess if the licensee had implemented a fire

protection program that adequately controlled combustibles and ignition sources

within the plant, effectively maintained fire detection and suppression capability,

maintained passive fire protection features in good material condition, and implemented

adequate compensatory measures for out-of-service, degraded or inoperable fire

protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk

as documented in the plants Individual Plant Examination of External Events with later

additional insights, their potential to impact equipment which could initiate or mitigate a

plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that

fire hoses and extinguishers were in their designated locations and available for

immediate use; that fire detectors and sprinklers were unobstructed; that transient

material loading was within the analyzed limits; and fire doors, dampers, and penetration

seals appeared to be in satisfactory condition. The inspectors also verified that minor

issues identified during the inspection were entered into the licensees CAP.

Documents reviewed are listed in the Attachment to this report.

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

IP 71111.05-05.

b.

Findings

No findings were identified.

1R06 Flooding (71111.06)

.1

Underground Vaults

a.

Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that

contained cables whose failure could disable risk-significant equipment. The inspectors

determined that the cables were not submerged, that splices were intact, and that

appropriate cable support structures were in place. In those areas where dewatering

devices were used, such as a sump pump, the device was operable and level alarm

circuits were set appropriately to ensure that the cables would not be submerged. In

those areas without dewatering devices, the inspectors verified that drainage of the area

was available, or that the cables were qualified for submergence conditions. The

inspectors also reviewed the licensees corrective action documents with respect to past

submerged cable issues identified in the corrective action program to verify the

adequacy of the corrective actions. The inspectors performed a walkdown of the

following underground bunkers/manholes subject to flooding:

Bunkers/manholes containing security cabling; and

Bunkers/manholes with safety-related cabling supporting technical specification

offsite power sources

Specific documents reviewed during this inspection are listed in the Attachment to this

report. This inspection constituted one underground vaults sample as defined in

IP 71111.06-05.

10

b.

Findings

No findings were identified.

1R07 Annual Heat Sink Performance (71111.07)

a.

Inspection Scope

The inspectors reviewed the licensees inspection of Unit 1 CD EDG north air aftercooler

to verify that potential deficiencies did not mask the licensees 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 observed

licensee visual observations of the internals of the heat exchanger to verify cleanliness

of the heat exchanger. Additionally, the inspectors reviewed eddy current testing results

and interviewed heat exchanger program engineers. Documents reviewed for this

inspection are listed in the Attachment 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.

1R08 Inservice Inspection Activities (71111.08P)

From September 29, 2014, through October 10, 2014, the inspector conducted a review

of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring

degradation of the Unit 1 Reactor Coolant System (RCS), steam generator tubes,

Emergency Feedwater Systems, Risk Significant Piping and Components, and

Containment Systems.

The inspections described in Sections 1R08.1, 1R08.2, IR08.3, IR08.4, and 1R08.5

below constituted one inservice inspection sample as defined in IP 71111.08-05.

.1

Piping Systems Inservice Inspection

a.

Inspection Scope

The inspectors observed and reviewed records of the following non-destructive

examinations (NDE) mandated by the American Society of Mechanical Engineers

(ASME)Section XI Code to evaluate compliance with the ASME Code Section XI

and Section V requirements, and if any indications and defects were detected, to

determine whether these were dispositioned in accordance with the ASME Code or an

NRC-approved alternative requirement:

Ultrasonic (UT) examination of ASME Code Class 2, risk informed (R-A), pipe to

elbow weld, 1-FW-12-02S;

UT of ASME Code Class 1, Pressurizer Relief Nozzle inner Radius;

6-1-RC-7-IRS;

11

UT of ASME Code Class 1; Pressurizer Spray Nozzle Inner Radius;

4-1-RC-10-IRS; and

Magnetic Particle (MT) Examination of ASME Code Class 1, Pressurizer Vessel

Support; 1-PRZ-26.

There were no recordable indications identified during the previous refueling outage.

The inspectors reviewed NDE records associated with the following pressure boundary

welds completed for risk significant components during the current refueling outage to

determine whether the licensee applied the pre-service NDE and acceptance criteria

required by the Construction Code and ASME Code,Section XI. Additionally, the

inspectors reviewed the welding procedure specification and supporting weld procedure

qualification records to determine whether the weld procedure was qualified in

accordance with the requirements of Construction Code and the ASME Code Section IX:

Welds OW-1, OW-2 and OW-3 associated with replacement valve 1-CS-314

(Work Order 55440759-5); and

Welds OW-1 and OW-2 associated with replacement valve 1-NLI-112-V1 (Work

Order 55390312-01)

The inspectors also reviewed NDE records associated with the following pressure

boundary welds completed for risk significant systems since the beginning of the last

refueling:

Welds OW-1, 2, 3, 4, 5 and OW-6 associated with replacement of valve

1-NFP-222-V2 (Work Order 55421212-10/13); and

Welds OW-1 associated with the installation of pipe support 1-ARC-S4012

(WO Order 55404504-06).

b.

Findings

No findings were identified.

.2

Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a.

Inspection Scope

For the Unit 1 reactor vessel head, no examination was required pursuant to

10 CFR 50.55a(g)(6)(ii)(D) for the current refueling outage. Therefore, no NRC review

was completed for this inspection procedure attribute.

b.

Findings

No findings were identified.

.3

Boric Acid Corrosion Control (BACC)

a.

Inspection Scope

The inspectors observed the licensees BACC visual examinations for portions of the

RCS, connected systems, and verified whether these visual examinations emphasized

12

locations where boric acid leaks can cause degradation of safety significant

components.

The inspectors reviewed the following licensee evaluations of RCS components with

Boric Acid deposits to determine whether degraded components were documented in

the corrective action system. The inspectors also evaluated corrective actions for any

degraded RCS components to determine whether they met the component Construction

Code, ASME Section XI Code, and/or NRC approved alternative:

AR 2013-4317; 1-QRV-114, body to bonnet leak;

AR 2013-4625;1-CS-448-1 has a BA leak;

AR 2013-5096; No. 14 SG cold leg nozzle dam leakage;

AR 2013-6839; U1C25 Refueling Cavity Leakage; and

AR 2013-7061; 1-RH-147W has Boric Acid on Body to Bonnet.

The inspectors reviewed the following corrective actions related to evidence of

BA leakage to determine whether the corrective actions completed were consistent with

the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B,

Criterion XVI:

AR 2013-0534; 12-CS-185 has a body to bonnet leak;

AR 2014-9459; 12-CS-185 has a ruptured diaphragm;

AR 2013-7220; Reactor Head and Pressure Vent Piping Area;

AR 2013-7355; 1-NFP-240 has evidence of prior test fitting leakage; and

AR 2013-7067; 1-RH-107W leaks by at 0.095 ml/min.

b. Findings

No findings were identified.

.4

Steam Generator Tube Inspection Activities

a.

Inspection Scope

The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET data

analysts, and reviewed documentation related to the SG ISI Program to determine

whether:

the numbers and sizes of SG tube flaws/degradation identified was consistent

with the licensees previous outage Operational Assessment predictions;

the SG tube ET examination scope and expansion criteria were sufficient to meet

the Technical Specifications, and the Electric Power Research Institute (EPRI)

Document 1013706, Pressurized Water Reactor Steam Generator Examination

Guidelines;

the SG tube ET examination scope included potential areas of tube degradation

identified in prior outage SG tube inspections and/or as identified in NRC generic

industry operating experience applicable to these SG tubes;

the licensee-identified new tube degradation mechanisms and implemented

adequate extent of condition inspection scope and repairs for the new tube

degradation mechanism;

the licensee implemented qualified depth sizing methods to degraded tubes

accepted for continued service;

13

the ET probes and equipment configurations used to acquire data from the SG

tubes were qualified to detect the known/expected types of SG tube degradation

in accordance with Appendix H, Performance Demonstration for Eddy Current

Examination, of EPRI Document 1013706, Pressurized Water Reactor Steam

Generator Examination Guidelines;

the licensee performed secondary side SG inspections for location and removal

of foreign materials;

The licensee implemented repairs for SG tubes damaged by foreign material;

and

Foreign objects were left within the secondary side of the SGs, and if so, that the

licensee implemented evaluations, which included the effects of foreign object

migration and/or tube fretting damage.

b.

Findings

No findings were identified.

.5

Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems entered into the licensees

CAP and conducted interviews with licensee staff to determine whether:

the licensee had established an appropriate threshold for identifying ISI-related

problems;

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

corrective actions; and

the licensee had evaluated operating experience and industry generic issues

related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action

documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program (71111.11)

.1

Resident Inspector Quarterly Review of Licensed Operator Requalification (71111.11Q)

a.

Inspection Scope

On November 19, 2014, the inspectors observed a crew of licensed operators in the

plants simulator during licensed operator requalification training to verify that operator

performance was adequate, evaluators were identifying and documenting crew

performance problems and training was being conducted in accordance with licensee

procedures. The inspectors evaluated the following areas:

licensed operator performance;

14

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

The crews performance in these areas was compared to pre-established operator action

expectations and successful critical task completion requirements. Documents reviewed

are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program

simulator sample as defined in IP 71111.11

b.

Findings

No findings were identified.

.2

Resident Inspector Quarterly Observation of Heightened Activity or Risk (71111.11Q)

a.

Inspection Scope

On October 17-18, 2014, the inspectors observed the drain-down and vacuum fill of the

RCS during the Unit 1 refueling outage. This was a high-risk (Orange) activity planned

during the outage. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

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

correct use and implementation of procedures;

control board (or equipment) manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications (if applicable).

The performance in these areas was compared to pre-established operator action

expectations, procedural compliance and task completion requirements. Documents

reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk

sample as defined in IP 71111.11, and was done in conjunction with the requirements of

IP 71111.20.

15

1R12 Maintenance Effectiveness (71111.12)

a.

Inspection Scope

The inspectors evaluated degraded performance issues involving the following

risk-significant systems:

Nuclear Instrumentation;

Main Steam;

Anticipated Transient Without Scram Mitigating System Actuation Circuitry; and

Rod Position Indication

The inspectors reviewed events such as where ineffective equipment maintenance had

resulted in valid or invalid automatic actuations of engineered safeguards systems and

independently verified the licensee's actions to address system performance or condition

problems in terms of the following:

implementing appropriate work practices;

identifying and addressing common cause failures;

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

characterizing system reliability issues for performance;

charging unavailability for performance;

trending key parameters for condition monitoring;

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

verifying appropriate performance criteria for SSCs/functions classified as (a)(2),

or appropriate and adequate goals and corrective actions for systems classified

as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability,

and condition monitoring of the system. In addition, the inspectors verified maintenance

effectiveness issues were entered into the CAP with the appropriate significance

characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted four quarterly maintenance effectiveness samples as defined

in IP 71111.12-05.

b.

Findings

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

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:

Rough lake conditions during emergent trash rack work;

Essential service water flow verification work concurrent with EDG testing; and

Emergent repairs to the Unit 2 Motor-Driven Auxiliary Feedwater (MDAFW) pump

room ventilation unit

16

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

three samples as defined in IP 71111.13-05.

b.

Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments (71111.15)

a.

Inspection Scope

The inspectors reviewed the following issues:

Main Steam Safety Valves lift during dual-unit trip;

Water intrusion into the Unit 1 TDAFW turbine bearings;

Question regarding TDAFW pump mission time;

Inability to make new ice during the Unit 1 refueling outage;

Inadvertent placement of FME bag on AB Fuel Oil Storage Tank vent;

Failure of automatic load tapping of Unit 2 Reserve Auxiliary Transformer and

failure of automatic generator trip during dual-unit trip; and

Leakby on a Unit 2 AFW flow control valve.

The inspectors selected these potential operability issues based on the risk significance

of the associated components and systems. The inspectors evaluated the technical

adequacy of the evaluations to ensure that TS operability was properly justified and the

subject component or system remained available such that no unrecognized increase in

risk occurred. The inspectors compared the operability and design criteria in the

appropriate sections of the TS and UFSAR to the licensees evaluations to determine

whether the components or systems were operable. Where compensatory measures

were required to maintain operability, the inspectors determined whether the measures

in place would function as intended and were properly controlled. The inspectors

determined, where appropriate, compliance with bounding limitations associated with the

evaluations. Additionally, the inspectors reviewed a sampling of corrective action

documents to verify that the licensee was identifying and correcting any deficiencies

associated with operability evaluations. Documents reviewed are listed in the

Attachment to this report.

This operability inspection constituted seven samples as defined in IP 71111.15-05.

17

b.

Findings

(1) Failure to Identify Conditions Adverse to Quality Associated with the Unit 1 TDAFW

Pump Turbine Oil System

Introduction: A finding of very low safety significance (Green) with an associated NCV of

10 CFR Part 50, Appendix B, Criterion 16, Corrective Actions, was identified by the

inspectors for the licensees failure to promptly identify and correct a CAQ associated

with Unit 1 TDAFW pump turbine bearing oil. Specifically, the licensee failed to identify

that water was entering the Unit 1 TDAFW pump turbine bearing oil system after leakage

had been identified directly above one of the TDAFW pump turbine bearings.

Description: On April 7, 2014, the licensee identified a 1 dpm leak from the Unit 1

TDAFW pump governor cooling pipe located directly above the outboard turbine bearing.

An AR was written (AR 2014-4473) which determined that due to the leak rate and the

apparent lack of any equipment impacts, there were no operability concerns. On

April 11, 2014, the licensee discovered that the turbine bearing oil level was

approximately 0.5 inches above the MAXIMUM mark on the sight glass. Level had been

recorded in the logs as being within band for over a year without any prior evidence of

high level. Additionally, there were no evolutions that had been performed which would

explain the high level. The licensee generated AR 2014-4684 to document this

condition. The AR documented several possible reasons for the unexplained level rise.

One was that turbine building temperature had gone up. Another was that it was not

uncommon for personnel to unnecessarily add oil to the machine from time to time. No

other information was provided to validate either potential cause. Additionally, there was

no mention of the leak identified above one of the turbine bearings four days prior. No

formal monitoring plan was established. An action was created to sample the oil for

water, but as of six weeks later, a work order had not been finalized and scheduled.

The only other action was a lessons-learned that was created for Mechanical

Maintenance department regarding unnecessary oil adds. The response to the action

from the group was that they dont typically do oil adds, but that they discussed the topic

anyway. The inspectors reviewed reference information with respect to oil levels and

their importance to machine operability. According to the vendor manual, EPRI

guidance on Terry turbines, and an AR the licensee evaluated in 2012, oil level is

extremely critical in the turbine bearing pedestals. The references all concluded that oil

level above the MAXIMUM mark could lead to oil frothing, which could affect stable

operation of the turbine and loss of oil from the system. Further, the references, along

with the plant logs, stated that oil level should be kept at or slightly above the MINIMUM

mark. Action Request 2014-4684 concluded that in April 2013, the reservoir was

over-filled to the MAXIMUM mark. No further information was provided on why this

occurred or why it was acceptable to stay at the MAXIMUM mark. One quart of oil was

drained from the turbine bearing pedestals, bringing the level back to near the

MAXIMUM mark. Approximately five weeks later, an NRC inspector touring the plant

questioned why level was near the MAXIMUM mark given a placard near the sight glass

said to keep level at the MINIMUM mark (which aligned with the references above).

The licensee generated an AR (2014-6315) about one week later on May 22 when the

inspector asked about the condition again. In the AR, they documented the NRC

observation and also the fact that an operator had noted level to be above the

MAXIMUM mark by approximately 0.25 inches. Oil was again drained from the

machine, this time to right above the MINIMUM mark. The operability assessment

(which was not documented until the following day), stated that at time of discovery, the

18

machine was operable because of oil level not affecting operability of the turbine and a

history of overfilling that sometimes required draining of the oil. Further, a statement

was made that there had been a consistent oil level trend for the past month. Again,

the leakage above the bearing was not discussed. There was no discussion of the

previous high-level condition from April 11. On May 23, the licensee decided to

completely drain the oil and sample it for water; 620 ml of water was found in the 2.5

gallon system. New oil was added, and an apparent cause evaluation was performed.

The evaluation concluded that leakage above the bearing housing (documented

originally in AR 2014-4473), combined with a small casing steam leak that condensed

above the housing while the machine was in operation, caused the water intrusion in the

bearing oil. Later evaluation determined the leak rate from the pipe had increased to

8 dpm in standby, and while running the leak rate was 20 dpm. The leakage sources

were diverted away from the bearing housing with a temporary modification pending

repairs (which were completed in the September-October 2014 refueling outage).

Based on the above, the inspectors concluded the licensee had sufficient information to

promptly identify and correct water intrusion into the TDAFW turbine bearing oil system

on April 11 and May 22, 2014. Additionally, the licensee failed to identify the potential

operability impacts (as described in the multiple references above) on April 11 and

May 22 when oil level was above the MAXIMUM mark. Water intrusion into safety-

related oil systems is a CAQ.

Analysis: The failure to promptly identify and correct a CAQ, as required by

10 CFR Part 50, Appendix B, Criterion 16, associated with water intrusion into the

TDAFW turbine oil system was an issue warranting further review in the SDP. Per

IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the issue was

more-than-minor because it adversely affected the Configuration Control attribute of the

Mitigating Systems Cornerstone, whose objective is to ensure the availability, reliability,

and capability of systems that respond to initiating events to prevent undesirable

consequences. Additionally, if left uncorrected, the issue could lead to a more significant

safety concern. Specifically, not recognizing water intrusion into safety-related oil

systems can impact operability and affect how safety equipment operates.

The inspectors assessed the finding for significance using IMC 0609, Significance

Determination Process, issued June 2, 2012. Per Appendix A, The Significance

Determination Process (SDP) for Findings-at-Power, issued June 19, 2012, the finding

screened as Green, or very low safety significance, in Exhibit 2. Specifically, all

questions were answered no under Section A for findings related to Mitigating SSCs

and Functionality. The inspectors reviewed the licensees past operability evaluation

and concluded that given the projected amount of water that could be entrained in the oil

during operation, along with the duration of operation assumed in the safety analyses,

that operability of the pump would be maintained.

The inspectors determined the finding had an associated cross-cutting aspect in the

Human Performance area, specifically, H.11, Challenge the Unknown. Some of the

tenets of H.11, as described in NUREG-2165, Safety Culture Common Language

Initiative, Section QA.2, Questioning Attitude, are that individuals avoid complacency

and continuously challenge existing conditions in order to identify discrepancies that

might result in error or inappropriate action. Further, it states that individuals challenge

unanticipated results rather than rationalize them, and that abnormal indications are not

attributed to indication problems. Regarding the TDAFW oil system, the licensee

rationalized why the level was increasing without sufficient investigation given the

19

significance of the system, and did not seek further information that was readily available

regarding appropriate oil levels.

Enforcement: 10 CFR Part 50, Appendix B, Criterion 16, Corrective Action, requires, in

part, that conditions adverse to quality, such as deficiencies, defective material and

equipment, and nonconformances are promptly identified and corrected.

Contrary to the above, between April 11 and May 23, 2014, the licensee failed to

promptly identify and correct a CAQ. Specifically, the licensee failed to promptly identify

and correct water intrusion into the safety-related Unit 1 TDAFW pump oil system

despite multiple opportunities to do so. On April 7, the licensee became aware of a

water leak directly above the TDAFW pump turbine outboard bearing. On April 11, and

May 22, the licensee learned that the oil level had exceeded the MAXIMUM mark. The

actions taken (draining the oil level) did not correct the condition adverse to quality in

that water continued to leak into the oil. On May 23, the licensee drained the oil system

and discovered approximately 620 ml of water.

For immediate corrective actions, the licensee added new oil to the system and installed

a temporary modification to prevent further water intrusion. Further corrective actions

included an apparent cause evaluation and past operability evaluation. Permanent

repairs to the cooling water leak above the bearing were completed during the Fall 2014

refueling outage. The licensee initiated AR-2014-6315 to document the condition and

track corrective actions.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the

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

the licensees CAP. (NCV 05000315/2014005-01; Failure to Identify Conditions

Adverse to Quality associated with the Unit 1 TDAFW Pump Turbine Oil System)

(2) Unplanned Inoperability of the AB Fuel Oil Storage Tank During Maintenance

Introduction: A finding of very low safety significance (Green) with an associated NCV of

TS 5.4, Procedures, was self-revealed when a vacuum was inadvertently drawn on the

AB FOST during preparations for surveillance activities. The vacuum caused an

indication of lowering level in the tank, alarms, and an unplanned TS LCO action

statement entry.

Description: On August 20, 2014, the licensee was performing work activities in

preparation for an upcoming, routine leak-test of the AB FOST. The AB FOST is one of

two underground tanks on site that supply fuel to the EDGs via the smaller day tanks

(which are provided for each EDG and offer a more limited, immediate fuel supply). The

test consists of establishing a vacuum in the tank and monitoring it for a period of time.

Several support activities are required to be performed prior to the test, some of which

include transfer of fuel from the FOST to the day tanks, removal of a vent cover for the

FOST, and connection of vendor-supplied vacuum and test equipment to the vent. Per

the overarching surveillance procedure, the basic order of activities should have been to

loosen the vent cover, transfer an amount of fuel to the day tanks, remove the FOST

from service, remove the vent cover, hook up the test equipment, and perform the test.

During the day shift on August 20, workers went out to work on the vent cover. The

associated work instruction did not provide adequate guidance on what exactly was to

be done. While the intent was just to loosen the cover at that point, the Subject of the

20

WO was Remove manway cover and vent cover. The instructions in the WO were

written as loosen/remove vent cover, and under the Precautions section the statement

Per tank procedure, as a minimum, we only have to loosen vent filter. The workers

ended up removing the cover instead of loosening it, and placed an FME bag over the

vent to prevent foreign material from entering the tank. Later on night shift, operations

staff commenced the transfer of fuel to the day tanks. With the FME bag installed, a

vacuum was drawn on the tank. Based on the configuration of the level instruments and

tank vent, the instruments indicated a lowering tank level and generated low level alarms

because of the vacuum. Operators performed a back-up measurement of tank level

using a dip stick, however, again, based on the tank construction, this method also

showed what appeared to be a lowering tank level. With this information, operators

believed an actual loss of fuel from the tank had occurred. Absent any indications in the

plant of fuel leaving the system, they concluded a release to the environment may have

occurred. Appropriate reports were made to state, federal, and local agencies.

Additionally, the operators entered TS LCO 3.8.3 Condition A based on the observed

level indications. During investigation soon after the abnormal level indications, the FME

bag was found on the vent. Once removed, level in the tank returned to normal. There

was no actual loss of fuel from the tank.

Analysis: The failure to have adequate instructions for performing work on safety-related

equipment, as required by TS 5.4, Procedures, was a performance deficiency

warranting further review utilizing IMC 0612, Appendix B, Issue Screening, issued

September 7, 2012. The performance deficiency was more than minor because it

adversely impacted the Configuration Control attribute of the Mitigating Systems

cornerstone, whose objective is ensuring the availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences.

The finding screened as Green, or very low safety significance, utilizing IMC 0609

Appendix A, The Significance Determination Process for Findings at Power, issued

June 19, 2012. Specifically, all questions were answered no under Section A of

Exhibit 2 for Mitigating Systems, since that was the affected cornerstone. The FME bag

was installed, which rendered the AB FOST inoperable, for approximately 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months .

This was less than the TS allowed outage time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

The finding had an associated cross-cutting aspect in the human performance area,

specifically, H.5, Work Management. Work activities should be planned, controlled, and

executed with nuclear safety as the overriding priority. Contrary to the tenets of the

cross-cutting aspect, the work was planned and executed with inadequate work

instructions. Further, there was a lack of coordination between a number of work groups

and activities associated with the test.

Enforcement: Technical Specification 5.4, Procedures, states, in part, that written

procedures shall be established, implemented, and maintained covering the applicable

procedures recommended in Regulatory Guide 1.33. Regulatory Guide 1.33 states, in

part, that maintenance that can affect the performance of safety-related equipment

should be properly preplanned and performed in accordance with written procedures,

documented instructions, or drawings appropriate to the circumstances.

Contrary to those requirements, on August 20, 2014, the AB FOST leak test was

performed with inadequate procedures and with tasks done outside the proper

21

sequence. As a result, the AB FOST was rendered inoperable for approximately

16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months .

Immediate corrective actions involved the removal of an FME bag which had been

placed over the AB FOST vent. The licensee also generated AR-2014-9877, which

included a root cause analysis. This violation is being treated as an NCV, consistent

with Section 2.3.2 of the Enforcement Policy because it was of very low safety

significance and was entered into the licensees CAP. (NCV 05000315/2014005-02; 05000316/2014005-02; Unplanned Inoperability of the AB Fuel Oil Storage Tank

During Maintenance)

1R18 Plant Modifications (71111.18)

a.

Inspection Scope

The inspectors reviewed the following modification(s):

Permanent removal of shield/missile blocks

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety

evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to

verify that the modification did not affect the operability or availability of the affected

system(s). The inspectors, as applicable, observed ongoing and completed work

activities to ensure that the modifications were installed as directed and consistent with

the design control documents; the modifications operated as expected; post-modification

testing adequately demonstrated continued system operability, availability, and reliability;

and that operation of the modifications did not impact the operability of any interfacing

systems. As applicable, the inspectors verified that relevant procedure, design, and

licensing documents were properly updated. Lastly, the inspectors discussed the plant

modification with operations, engineering, and training personnel to ensure that the

individuals were aware of how the operation with the plant modification in place could

impact overall plant performance. Documents reviewed are listed in the Attachment to

this report.

This inspection constituted one permanent plant modification sample as defined in

IP 71111.18-05.

b.

Findings

Lack of Adequate Design Review of Effects of Removing the Auxiliary Missile Blocks

from the Containment Accident Shield

Introduction: A finding of very-low safety significance (Green) and associated NCV of

Title 10 CFR Part 50, Appendix B, Criterion 3, Design Control, was identified by the

NRC inspectors for the licensees inadequate radiological review of permanently

removing the AMBs from the Unit 1 and Unit 2 containment accident shields.

Description: In March 2014, the NRC reviewed a licensee modification

(EC-0000049191) to the Unit 1 and 2 safety-related containment accident shields. The

modification consisted of permanently removing the AMBs, located in front of the primary

containment equipment hatches on the 650 elevation of the Auxiliary Building. The

AMBs are portable and removable shield blocks and are a part of the safety-related

22

containment accident shield. The AMBs are in place during power operations for

shielding purposes. The AMBs are removed during plant outages to permit containment

access for equipment.

The main purpose of the accident shield, as a part of original plant design and currently

described in the UFSAR, Section 11.2.1.1.4, is to ensure safe radiation levels outside

the containment building following a maximum design-basis accident; specifically, a

large break loss-of-coolant accident (LBLOCA). The plant containment and the accident

shield function (USFAR Section 11.2.1) ensure that operating personnel at the plant and

the general public are protected by adequate containment shielding, post LBLOCA. This

was in accordance with plant specific design Criteria 1 of 10 CFR Part 50 General

Design Criteria 1 Quality Standards and Records of Appendix A General Design

Criteria for Nuclear Power Plants, 10 CFR Part 20 Standards for Protection Against

Radiation, and 10 CFR Part 100 Reactor Site Criteria. The inspectors reviewed the

original and current plant design configuration and determined that, prior to plant

modification (EC-0000049191), the plant design met General Design Criteria 1 for

radiation safety. Specifically, RG 1.69 Concrete Radiation Shields for Nuclear Power

Plants was explicit in stating that General Design Criteria 1 for containment ensures

reasonable assurance for compliance to 10 CFR Part 20 Standards for Protection

Against Radiation under post-accident conditions. Additionally, initial plant design for

the containment accident shield was consistent with RG 1.69 Concrete Radiation

Shields for Nuclear Power Plants.

Using the licensees design basis source term, licensee calculation number RS-C-0046

Doses and Dose Rates from Post LOCA Airborne Sources determined that with the

AMBs in place, the Post LBLOCA dose rates were:

A nominal 31 Rem/hr at 1 second after LBLOCA at 1 inch from the AMBs; and

A nominal 3.9 Rem/hr at 1 second after LBLOCA at 50 feet from the AMBs.

These dose rates provide for safe radiation levels outside the containment building

following a maximum design-basis accident consistent with the UFSAR design

statements and in accordance with the requirements of 10 CFR Part 20, Standards for

Protection Against Radiation.

The licensee provided no comparable post-modification dose rate calculations to the

inspectors specific to AB 650 elevation once the AMBs were removed. However, the

licensee provided information (Calculation Number RS-C-0232, Equipment Hatch Dose

Rates - Gap Release; Revision 01) that showed calculated Post LBLOCA dose rates

of 196.2 Rem/hr at 45 feet from the equipment hatch. Additionally, the licensee had

analogous Post-LBLOCA dose rate calculations for the containment personnel hatch.

These dose rates provide a frame of reference, in that, the calculations provide for no

AMB shielding. However, the calculations did include shielding benefit from the inside

containment crane wall (Calculation Number RS-C-0046, Doses and Dose Rates from

Post LOCA Airborne Sources). Specific calculated dose rates were:

A nominal 36,300 Rem/hr at 1 second after LBLOCA at 1 inch from the personnel

hatch; and

A nominal 397 Rem/hr at 1 second after LBLOCA at 50 feet from the personnel

hatch.

23

The inspectors determined that post-modification dose rates on the AB 650 elevation

could result in lethal doses, as defined in NUREG/CR 6545 Probabilistic Accident

Consequence Uncertainty Analysis: Early Health Effects Uncertainty Assessment, to

individuals in a very short period of time (from fractions of a second to minutes,

depending on the location of personnel relative to the radiation source). By permanently

removing the AMBs, the licensee failed to provide for safe radiation levels outside the

containment building following a maximum design-basis accident, contrary to the design

bases and inconsistent with the requirements of 10 CFR Part 20.

Additionally, 10 CFR 20.1101(b) and RG 1.69 state, in part, that the licensee shall use,

to the extent practical, engineering controls based upon sound radiation principles to

achieve occupational doses and doses to members of the public that are

as-low-as-reasonably-achievable (ALARA). Original plant design and the plants 40-year

operational history demonstrate that plant operation with the AMBs in place was both

practical and ALARA.

The licensee documented this issue in the CAP as AR 2014-13016. Corrective actions

included licensee determination to achieve radiation attenuation analogous to original

plant design of the AMBs in place.

Analysis: The inspectors determined that the licensees inadequate radiological review

of permanently removing the AMBs from the Unit 1 and Unit 2 containment accident

shields was a performance deficiency. The performance deficiency was determined to

be more than minor (Green) because it was associated with the Barrier Integrity

Cornerstone attribute of design control; and adversely affected the cornerstone objective

of maintaining radiological barrier functionality of the safety-related containment accident

shield. Specifically, the failure to control plant design and adequately evaluate the

radiological effects of permanently removing the AMBs from the Unit 1 and Unit 2

containment accident shields did not ensure that the accident shield will provide its

design function to ensure safe radiation levels outside the containment building following

a maximum design basis accident.

The inspectors evaluated the finding using the SDP in accordance with IMC 0609,

Significance Determination Process, Attachment 0609.04, Initial Characterization of

Findings, dated June 19, 2012. Because the finding impacted the Barrier Integrity

Cornerstone, the inspectors screened the finding through IMC 0609, Appendix A, The

Significance Determination Process for Findings At-Power, dated June 19, 2012, using

Exhibit 3, Barrier Integrity Screening Questions. The finding screened as of very-low

safety significance (Green) because the finding only represented a degradation of the

radiological barrier function provided for the Auxiliary Building.

The inspectors determined the cause of this finding did not represent current licensee

performance and, thus, no cross-cutting aspect was assigned.

Enforcement: Title 10 CFR Part 50, Appendix B, Criterion 3, Design Control, requires,

in part, that design changes be subject to design control measures commensurate with

those applied to the original design.

Contrary to the above, on February 6, 2009, the licensee performed a design change

and failed to subject it to design control measures commensurate with those applied to

the original design. Specifically, the licensee modified the original plant design by

24

removing the auxiliary missile blocks from the safety-related accident shield. However,

the design control measures applied to the modification failed to ensure safe radiation

levels outside the containment accident shield following a design basis loss-of-coolant

accident.

Because this violation was of very-low safety significance and was entered into the

licensees CAP (AR 2014-13016), this violation is being treated as an NCV, consistent

with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000315/2014005-03; 05000316/2014005-03; Radiological Impact of the Removal of the Auxiliary Shield

Blocks on the Containment Accident Shield Post LBLOCA)

1R19 Post-Maintenance Testing (71111.19)

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:

Unit 1 AB EDG following governor replacement;

Unit 1 CRID III and IV maintenance;

Unit 2 UAT breakers following failure to close;

Unit 1 CD EDG governor replacement and aftercooler maintenance;

Unit 1 TDAFW governor overhaul;

Repair of Unit 2 AFW flow control valve flow retention issue;

Repair of circuitry associated with failure of fast transfer and generator trip during

dual-unit trip; and

Unit 1 TDAFW repairs following inadvertent trip.

These activities were selected based upon the structure, system, or component's ability

to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate

for the maintenance performed; acceptance criteria were clear and demonstrated

operational readiness; test instrumentation was appropriate; tests were performed as

written in accordance with properly reviewed and approved procedures; equipment was

returned to its operational status following testing (temporary modifications or jumpers

required for test performance were properly removed after test completion); and test

documentation was properly evaluated. The inspectors evaluated the activities against

TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various

NRC generic communications to ensure that the test results adequately ensured that the

equipment met the licensing basis and design requirements. In addition, the inspectors

reviewed corrective action documents associated with post-maintenance tests to

determine whether the licensee was identifying problems and entering them in the CAP

and that the problems were being corrected commensurate with their importance to

safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted eight post-maintenance testing samples as defined in

IP 71111.19-05.

25

b.

Findings

Introduction: A finding of very low safety significance (Green) with an associated NCV of

TS 5.4, Procedures, was self-revealed on November 1, 2014, when the Unit 1 TDAFW

pump tripped during an emergent dual-unit shutdown. Both units were taken offline by

operators due to debris intrusion from Lake Michigan into the cooling water

screenhouse. The TDAFW pump started as expected but shutdown after a few minutes

of operation.

Description: On November 1, 2014, operators removed both units from service in

response to excessive debris intrusion into the cooling water screenhouse. Following

the trip of both reactors, AFW pumps started as expected. However, the Unit 1 TDAFW

unexpectedly turned off after a few minutes of operation while operators were adjusting

flow to the steam generators. Adequate flow continued to be provided by the two other

AFW pumps. During the ensuing forced outage to address the debris intrusion issue,

the licensee performed an investigation into why the pump tripped off. The licensee

explored and ruled out causes such as a pump overspeed, failed overspeed trip circuitry,

and governor control problems. The investigation included several test runs of the pump

while rapidly changing demand in an effort to stress the pump and replicate the trip

event. During continued troubleshooting, the licensee later discovered a protective

enclosure around an electronic component (the trip solenoid) had been installed

incorrectly. The enclosure was relatively loose, and the licensee found by moving it

slightly, it could be placed in a position where a threaded rod on the enclosure could

interfere with the proper latching of the TTV for the pump. When the pump turns on, the

TTV opens to admit steam to the turbine. As the valve stem moves up, an attachment

engages a trip hook. The trip hook basically acts to hold the valve open. On a trip

condition, such as a pump overspeed, the hook would move out of the way, allowing the

valve to shut and the pump to turn off. Precise engagement between the TTV and the

trip hook is required for the pump to operate correctly. In this case, the licensees

apparent cause evaluation determined the most likely cause was inadequate trip hook

engagement as a result of the interference from the trip solenoid enclosure. As part of

the extent-of-condition, the licensee discovered the same potential issue on the Unit 2

TDAFW pump. Further investigation revealed that the enclosure was not captured in

design diagrams, and that work instructions regarding its installation/removal were not

detailed. Most recently, the Unit 1 TDAFW pump trip solenoid enclosure had been

removed and reinstalled during the Fall 2014 refueling outage as part of planned

maintenance. Working with the pump vendor, the licensee identified the correct

configuration of the enclosure and reinstalled them correctly on both pumps. The

licensee tested the pump several times afterwards, and restored the Unit 1 TDAFW

pump to operable status at the conclusion of the forced outage.

Analysis: The failure to have adequate instructions for performing work on safety-related

equipment, as required by TS 5.4, Procedures, was a performance deficiency

warranting further review utilizing IMC 0612, Appendix B, Issue Screening, issued

September 7, 2012. The performance deficiency was more than minor because it

adversely impacted the Configuration Control attribute of the Mitigating Systems

cornerstone, whose objective is ensuring the availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences.

The inspectors utilized IMC 0609 Appendix A, The Significance Determination Process

for Findings at Power, issued June 19, 2012, to assess the significance of the finding.

26

Per Exhibit 2, the finding represented a loss of function for one train of AFW for greater

than the TS allowed outage time. Therefore, the inspectors consulted the regional

Senior Reactor Analyst (SRA) for a detailed risk evaluation. The inspectors considered

the Unit 1 TDAFW pump inoperable since the last successful surveillance on

October 23. Given the evidence available, this was the likely opportunity for the

conditions to be established to set-up the improper engagement between the TTV and

the trip hook.

The Region III SRA used the NRC standardized plant analysis risk model for D.C. Cook

to perform a detailed risk evaluation. The model has internal and external event

initiators. The SRA assumed an exposure period for the condition of 9 days. The delta

core damage frequency (CDF) calculated was 4.5E-7/yr, which is a finding of very low

safety significance (Green). The dominant risk sequence was a fire in the turbine

building, followed by a failure of main feedwater, auxiliary feedwater and feed and bleed.

Since the calculated delta CDF was greater than 1E-7/yr, the SRA also considered the

potential impact of the finding on large early release frequency using IMC 0609

Appendix H, Containment Integrity Significance Determination Process. The plant has

an ice condenser containment and sequences important to large early release frequency

are steam generator tube rupture, inter-system loss-of-coolant accident, and station

blackout. Some of the sequences that contributed to the change in CDF included station

blackout sequences but their contribution was less than 1E-7/yr. The SRA concluded

that the risk of this finding should be characterized by the overall change in CDF.

The finding had an associated cross-cutting aspect in the area of human performance,

specifically, H.8, Procedure Adherence. Safety Culture Common Language Initiative

NUREG-2165 provides an example of the aspect as individuals review procedures

before work to validate they are appropriate for scope of work, and ensure required

changes are completed before implementation. Contrary to this description, work

proceeded on the trip enclosure despite a lack of detailed instructions on the

removal/installation of the enclosure.

Enforcement: Technical Specification 5.4, Procedures, states, in part, that written

procedures shall be established, implemented, and maintained covering the applicable

procedures recommended in Regulatory Guide 1.33. Regulatory Guide 1.33 states, in

part, that maintenance that can affect the performance of safety-related equipment

should be properly preplanned and performed in accordance with written procedures,

documented instructions, or drawings appropriate to the circumstances.

Contrary to those requirements, work was performed on the Unit 1 TDAFW pump trip

solenoid enclosure with inadequate work instructions. As a result, an apparent cause

evaluation determined the misplaced enclosure was the likely cause of the pump

failure during an actual demand following a dual-unit trip. The violation existed from

October 23, 2014, until troubleshooting and post-maintenance testing activities were

completed on November 3, 2014, following the dual-unit trip.

For immediate corrective actions, the licensee initiated AR-2014-13668 and began

troubleshooting activities. The licensee investigation revealed the misplaced trip

solenoid enclosure to be the likely cause of the pump trip. Subsequently, the enclosures

were installed in the correct position. This violation is being treated as an NCV,

consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety

27

significance and was entered into the licensees CAP. (NCV 05000315/2014005-04;

Inadvertent Trip of the Unit 1 TDAFW Pump)

1R20 Outage Activities (71111.20)

.1

Refueling Outage Activities

a.

Inspection Scope

The inspectors reviewed the Outage Safety Plan and contingency plans for the Unit 1

refueling outage, conducted September 24 - October 24, 2014, to confirm that the

licensee had appropriately considered risk, industry experience, and previous

site-specific problems in developing and implementing a plan that assured maintenance

of defense-in-depth. During the refueling outage, the inspectors observed portions of

the shutdown and cooldown processes and monitored licensee controls over the outage

activities listed below:

licensee configuration management, including maintenance of defense-in-depth

commensurate with the Outage Safety Plan for key safety functions and

compliance with the applicable TS when taking equipment out of service;

implementation of clearance activities and confirmation that tags were properly

hung and equipment appropriately configured to safely support the work or

testing;

installation and configuration of reactor coolant pressure, level, and temperature

instruments to provide accurate indication, accounting for instrument error;

controls over the status and configuration of electrical systems to ensure that

TS and Outage Safety Plan requirements were met, and controls over switchyard

activities;

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

controls to ensure that outage work was not impacting the ability of the operators

to operate the spent fuel pool cooling system;

reactor water inventory controls including flow paths, configurations, and

alternative means for inventory addition, and controls to prevent inventory loss;

controls over activities that could affect reactivity;

maintenance of secondary containment as required by TS;

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

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

leakage;

startup and ascension to full power operation, tracking of startup prerequisites,

walkdown of the drywell (primary containment) to verify that debris had not been

left which could block emergency core cooling system suction strainers, and

reactor physics testing; and

licensee identification and resolution of problems related to refueling outage

activities.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one Refueling Outage sample as defined in IP 71111.20-05.

28

b.

Findings

No findings were identified.

.2

Unit 1 and Unit 2 Forced Outages Commencing November 1, 2014

a.

Inspection Scope

On November 1, rough lake conditions generated substantial amounts of debris that

clogged trash racks and travelling screens. The licensee manually tripped the Unit 1

reactor and initially reduced power to 50 percent on the Unit 2 reactor to reduce

circulating water flow. Conditions continued to degrade; therefore the licensee

subsequently tripped the Unit 2 reactor. Unit 1 remained in Mode 3 and returned to

100 percent power on November 8. Unit 2 was cooled down to Mode 5 to repair an

intermediate range nuclear instrument. Unit 2 was returned to 100 percent power on

November 13. The inspectors toured portions of containment, observed shutdown and

startup activities, assessed plant risk, and observed maintenance activities.

This inspection constituted one Forced Outage sample as defined in IP 71111.20-05.

b.

Findings

No findings were identified.

1R22 Surveillance Testing (71111.22)

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:

1-OHP-4030-108-008R, Unit 1 ECCS Check Valve Test, (IST);

1-EHP-4030-134-203, Unit 1 LLRT (Containment Isolation Valve);

12-MHP-4030-010-004, Ice Condenser Intermediate Deck Door Surveillance,

(Ice Condenser Surveillance);

Unit 1 Control Room Emergency Ventilation Surveillance, 1-EHP-4030-128-229

(Routine); and

Loss of Offsite Power/Loss-of-Coolant Accident Circuit Testing (Routine).

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 USAR, procedures, and applicable commitments;

29

measuring and test equipment calibration was current;

test equipment was used within the required range and accuracy; applicable

prerequisites described in the test procedures were satisfied;

test frequencies met TS requirements to demonstrate operability and reliability;

tests were performed in accordance with the test procedures and other

applicable procedures; jumpers and lifted leads were controlled and restored

where used;

test data and results were accurate, complete, within limits, and valid;

test equipment was removed after testing;

where applicable for inservice testing activities, testing was performed in

accordance with the applicable version of Section XI, American Society of

Mechanical Engineers code, and reference values were consistent with the

system design basis;

where applicable, test results not meeting acceptance criteria were addressed

with an adequate operability evaluation or the system or component was

declared inoperable;

where applicable for safety-related instrument control surveillance tests,

reference setting data were accurately incorporated in the test procedure;

where applicable, actual conditions encountering high resistance electrical

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

prior procedure changes had not provided an opportunity to identify problems

encountered during the performance of the surveillance or calibration test;

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

performance of its safety functions; and

all problems identified during the testing were appropriately documented and

dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two routine surveillance testing samples, one inservice

testing sample, one ice condenser surveillance, and one containment isolation valve

sample as defined in IP 71111.22, Sections-02 and-05.

b.

Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)

a.

Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the

Emergency Plan and Emergency Plan Implementing Procedures as listed in the

Attachment to this report.

The licensee transmitted the Emergency Plan and Emergency Action Level revisions to

the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V,

Implementing Procedures. The NRC review was not documented in a safety

evaluation report and did not constitute approval of licensee-generated changes;

therefore, this revision is subject to future inspection. The specific documents reviewed

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

30

This Emergency Action Level and Emergency Plan Change inspection constituted one

sample as defined in IP 71114.04-06.

b.

Findings

Introduction: An Unresolved Item (URI) was identified because additional information is

required to determine whether a performance deficiency that is more than minor exists

and if a violation of 10 CFR 50.54(q)(3) occurred. The inspectors identified an issue of

concern for a change to the Donald C. Cook Emergency Plan, Table 1, that reduced the

number of Radiation Protection Technicians (RPTs) required to augment the on-shift

emergency response organization in 60 minutes of a declared emergency and replaced

them with a Radiological Assessment Coordinator (RAC) and an Environmental

Assessment Coordinator (EAC).

Description. During the review, the inspectors identified a change made in Table 1 of

Revision 35 to the Emergency-Plan (E-Plan), dated June 3, 2014. The change reduced

the number of 60-minute response RPTs tasked with conducting offsite surveys from

three RPTs to two RPTs and one EAC. The second change reduced the number of

60-minute response RPTs tasked with conducting in-plant surveys from two RPTs to one

RPT and one RAC. According the licensees 10 CFR 2014 50.54(q) screening

evaluation, this change was to align the wording in Table 1 with Sections B.5.a.4 and

B.5.c.4 of the E-Plan. The inspectors identified that the wording in Section B.5.a.4 and

B.5.c.4 of the E-Plan had been changed to include the EAC and the RAC as 60-minute

responders in Revision 19 of the plan in March of 2004. Inspectors review of the

10 CFR 50.54(q) screening for the changes in Revision 19, identified no evaluations had

been done for this change. The inspectors reviewed Revision 18 of the E-Plan and the

associated March 21, 2003 licensee request for prior approval for changes to the E-plan

that was conducted, approved by the NRC, and implemented in this revision. The NRC

approved change request included specific numbers of RPTs for 60-minute response

tasks of three RPTs for offsite surveys and 2 RPTs for onsite surveys.

The licensee indicated that the EAC and RAC were not currently qualified RPTs. This

suggests a performance deficiency, due to the appearance of a reduction in

effectiveness to the licensees E-plan, without prior NRC approval. However, in order to

determine if this is a performance deficiency of more than minor significance, additional

information is required to understand if the RAC and EAC positions had equivalent

capabilities as the qualified RPTs. The licensee has entered this issue in their

Corrective Action Program as AR 2014-15685, Potential EP Finding. Compensatory

actions were taken while their staff gathers additional information, which included

requiring two additional qualified RPTs to respond to the Operations Support Center

within 60 minutes prior to activating the facility in the event of a declared emergency.

The licensee stated that it will provide the inspectors with additional information within

30 days of the exit meeting.

Therefore, a URI was identified pending additional information. Specifically,

documentation demonstrating the knowledge, skills, and abilities of the EAC and RAC

are equivalent to the RPTs is necessary for the inspectors to determine whether the

performance deficiency is more than minor and if a violation of 10 CFR 50.54(q)

occurred. (URI 05000315/2014005-05; Changes to Minimum 60-Minute Emergency

Responder Staffing Without Prior Approval)

31

2.

RADIATION SAFETY

2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)

The inspection activities supplement those documented in NRC Inspection Report

05000315-05000316/2014002 and constitute one complete sample as defined in

Inspection Procedure 71124.01-05.

.1

Radiological Hazard Assessment (02.02)

a.

Inspection Scope

The inspectors determined whether there have been changes to plant operations since

the last inspection that may result in a significant new radiological hazard for onsite

workers or members of the public. The inspectors evaluated whether the licensee

assessed the potential impact of these changes and has implemented periodic

monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from selected plant areas and

evaluated whether the thoroughness and frequency of the surveys where appropriate for

the given radiological hazard.

The inspectors selected the following radiologically risk significant work activities that

involved exposure to radiation:

Refuel Cavity Decontamination Activities;

Steam Generator Platform Activities;

Valve Maintenance / Repair;

Perform Radiography in Auxiliary and Turbine Buildings and Plant Restricted

Areas; and

Reactor Pit Very High Radiation Area (VHRA) Downpost Survey.

For these work activities, the inspectors assessed whether the pre-work surveys

performed were appropriate to identify and quantify the radiological hazard and to

establish adequate protective measures. The inspectors evaluated the radiological

survey program to determine if hazards were properly identified, including the following:

identification of hot particles;

the presence of alpha emitters;

the potential for airborne radioactive materials, including the potential presence

of transuranics and/or other hard-to-detect radioactive materials (This evaluation

may include licensee planned entry into non-routinely entered areas subject to

previous contamination from failed fuel.);

the hazards associated with work activities that could suddenly and severely

increase radiological conditions and that the licensee has established a means to

inform workers of changes that could significantly impact their occupational dose;

and

severe radiation field dose gradients that can result in non-uniform exposures of

the body.

32

The inspectors observed work in potential airborne areas and evaluated whether the air

samples were representative of the breathing air zone. The inspectors evaluated

whether continuous air monitors were located in areas with low background to minimize

false alarms and were representative of actual work areas. The inspectors evaluated

the licensees program for monitoring levels of loose surface contamination in areas of

the plant with the potential for the contamination to become airborne.

b.

Findings

No findings were identified.

.2

Instructions to Workers (02.03)

a.

Inspection Scope

The inspectors reviewed the following radiation work permits used to access high

radiation areas and evaluated the specified work control instructions or control barriers:

RWP 141100; U1C26 - Refuel Cavity Decontamination Activities;

RWP 141148; U1C26 - Steam Generator Platform Activities;

RWP 141145; U1C26 - Valve Maintenance / Repair;

RWP 1 41130; U1C26 - Perform Radiography in Auxiliary & Turbine Buildings &

Plant Restricted Areas; and

RWP 141172; U1C26 - Reactor Pit VHRA Downpost Survey.

For these radiation work permits, the inspectors assessed whether allowable stay times

or permissible dose (including from the intake of radioactive material) for radiologically

significant work under each radiation work permit were clearly identified. The inspectors

evaluated whether electronic personal dosimeter alarm set-points were in conformance

with survey indications and plant policy.

For work activities that could suddenly and severely increase radiological conditions, the

inspectors assessed the licensees means to inform workers of changes that could

significantly impact their occupational dose.

b.

Findings

No findings were identified.

.3

Contamination and Radioactive Material Control (02.04)

a.

Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated

material leaving the radiological control area and inspected the methods used for

control, survey, and release from these areas. The inspectors observed the

performance of personnel surveying and releasing material for unrestricted use and

evaluated whether the work was performed in accordance with plant procedures and

whether the procedures were sufficient to control the spread of contamination and

prevent unintended release of radioactive materials from the site. The inspectors

assessed whether the radiation monitoring instrumentation had appropriate sensitivity for

the type(s) of radiation present.

33

The inspectors reviewed the licensees criteria for the survey and release of potentially

contaminated material. The inspectors evaluated whether there was guidance on how to

respond to an alarm that indicates the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to verify that the

radiation detection instrumentation was used at its typical sensitivity level based on

appropriate counting parameters. The inspectors assessed whether or not the licensee

has established a de facto release limit by altering the instruments typical sensitivity

through such methods as raising the energy discriminator level or locating the instrument

in a high-radiation background area.

The inspectors selected several sealed sources from the licensees inventory records

and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving

nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b.

Findings

No findings were identified.

.4

Radiological Hazards Control and Work Coverage (02.05)

a.

Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or

potential radiation levels) during tours of the facility. The inspectors assessed whether

the conditions were consistent with applicable posted surveys, radiation work permits,

and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required

surveys, radiation protection job coverage (including audio and visual surveillance for

remote job coverage), and contamination controls. The inspectors evaluated the

licensees use of electronic personal dosimeters in high noise areas as high radiation

area monitoring devices.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to

personnel in high-radiation work areas with significant dose rate gradients.

The inspectors reviewed the following radiation work permits for work within airborne

radioactivity areas with the potential for individual worker internal exposures:

RWP 141100; U1C26 - Refuel Cavity Decontamination Activities;

RWP 141148; U1C26 - Steam Generator Platform Activities; and

RWP 141145; U1C26 - Valve Maintenance / Repair.

For these radiation work permits, the inspectors evaluated airborne radioactive controls

and monitoring, including potential for significant airborne levels (e.g., grinding, grit

blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The

inspectors assessed barrier (e.g., tent or glove box) integrity and temporary

high-efficiency particulate air ventilation system operation.

34

The inspectors examined the licensees physical and programmatic controls for highly

activated or contaminated materials (i.e., nonfuel) stored within spent fuel and other

storage pools. The inspectors assessed whether appropriate controls (i.e.,

administrative and physical controls) were in place to preclude inadvertent removal of

these materials from the pool.

The inspectors examined the posting and physical controls for selected high radiation

areas and very-high radiation areas to verify conformance with the occupational

performance indicator.

b.

Findings

Failure to Identify Deficient Locked High Radiation Area Controls Due to Procedure

Inadequacy

Introduction: An NRC identified Green NCV of TS 5.4.1, Procedures, was identified for

inadequate procedures used to verify Locked High Radiation Controls in the Unit 2

Containment.

Description: On July 24, 2014, the inspector walked down the Unit 2 containment cavity

access ladder. At the time of the walkdown, the access to the cavity was posted LHRA

and had a ladder cage that functioned as a ladder lock device, in addition to a four-foot

high locked gate for access to the permanently installed cavity ladder. Discussions with

Radiation Protection staff had identified that the ladder lock device was not in place in

March 2014. Additionally, it was established that the locking cage was not placed back

on the ladder following the refueling outage in October 2013 when the area was

conservatively posted as a LHRA as the dose rates in the containment cavity were not in

excess of 1000 millirem per hour at 30 centimeters. The inspector reviewed Survey

Number CNP-1311-0001, dated November 1, 2013, which was a survey of the Final

Containment Cavity Survey following the last refueling outage. This survey confirmed

that the highest dose in the accessible areas of the cavity were nominally 2400 millirem

per hour on contact, and 500 millirem per hour at 30 centimeters from the source with

the highest readings in the cavity lift system pit area following the cavity

decontamination. These dose rates would not constitute a LHRA (greater than

1000 millirem per hour at 30 centimeters.) The survey showed that the gate to the cavity

ladder was posted as a LHRA.

Licensee Procedure PMP-6010-RPP-003, High, Locked High, and VHRA Access,

Section 3.3.5, directs weekly LHRA and VHRA verifications. Additional procedure

guidance is provided in THG-026, Locked High Radiation Area, and Very-High Radiation

Weekly Verification Process, Data Sheet 1, LHRA/VHRA Status Sheet, with additional

management expectations and a tracking tool for door/gate verifications while used as a

field guide for verifying LHRA/VHRA controls (i.e., doors/gates). The inspector identified

a substantial procedural weakness in this guidance in that the Data Sheet apparently did

not provide enough detail to direct Radiation Protection Technicians (RPTs) to verify that

the locked cage/ladder lock to the reactor cavity was in place and locked; a condition

which is necessary to provide reasonable assurance that the area is secured against

unauthorized access and cannot be easily circumvented. A review of the data verified

that RP staff did not identify the missing cage/ladder lock to the Unit 2 Reactor Cavity

ladder during weekly LHRA verification from November 2013 through March 2014. The

NRC inspectors also reviewed the LHRA and VHRA verification documentation in the

35

RP station daily logs from November 2013 to March 2014 and the inspectors did not

identify any discrepancies noted in the logs associated with in LHRA controls during their

weekly walkdowns of LHRA and VHRA verification. A review of the Corrective Action

Program documents did not identify a record of the missing ladder lock device or

identification of an unlocked LHRA. Therefore the licensee was not aware of the

deficient LHRA controls at the Unit 2 cavity ladder until it was discussed with the

inspectors. The failure to identify deficient LHRA controls could have the potential failure

to identify and report a Performance Indicator (PI) occurrence.

Analysis: The inspectors determined that there was an inadequacy in the licensees

procedure for identifying a deficient Locked High Radiation Area for the barrier in their

weekly locked cage/ladder barrier to the cavity of Unit 2 containment. The inspectors

determined that the procedure did not provide clear directions to assure the Radiation

Protection Technician would verify the required controls for LHRA is a performance

deficiency. The inspectors determined that the cause of the performance deficiency was

reasonably within the licensees ability to foresee and correct and should have been

prevented.

The finding was not subject to traditional enforcement since the incident did not have a

significant safety consequence, did not impact the NRCs ability to perform its regulatory

function, and was not willful.

The inspectors determined that the performance deficiency was more than minor in

accordance with IMC 0612, Appendix B, Issue Screening, because if left uncorrected,

the performance deficiency could lead to a more significant safety concern. Specifically,

the failure to identify deficient LHRA controls could result in unintentional exposure to

high levels of radiation.

The finding was assessed using the Occupational Radiation Safety SDP and was

determined to be of very-low safety significance because the problem was not an

ALARA planning issue, there were no overexposures nor substantial potential for

overexposures given the highest dose rates present in the room, the scope of work, and

the licensees ability to assess dose was not compromised.

The inspectors did not identify a corresponding cross-cutting aspect for this performance

deficiency.

Enforcement: Technical Specification 5.4.1, Procedures, requires that written

procedures shall be established, implemented and maintained covering the activities

referenced in Appendix A of Regulatory Guide 1.33, Revision 2. Control of Radioactivity

procedures, including limiting personnel exposure, are specified in Appendix A.

Contrary to the above, Procedure PMP-6010-RPP-003, High, Locked High, and

Very-High Radiation Area Access, Section 3.3.5, LHRA and VHRA Door/Gate

verification in conjunction with Procedural Guidance THG-026, Locked High Radiation

Area, and Very-High Radiation Weekly Verification Process did not provide sufficient

details to direct RPTs to verify that the locked cage/ladder lock to the reactor cavity was

in place and locked; a condition which is necessary to provide reasonable assurance

that the area is secured against unauthorized access and cannot be easily

circumvented. Consequently, weekly, from November 1, 2013, to March 2014 multiple

36

RPTs verified the Unit 2 Upper Containment Cavity gate was locked, but did not secure

the area against unauthorized access.

Corrective actions included review and revision of Procedure PMP-6010-RPP-003, High,

Locked High, and Very-High Radiation Area Access, and the associated Procedural

Guidance THG-026, Locked High Radiation Area and Very-High Radiation Weekly

Verification. Because this violation is of very-low safety significance and it was entered

into the licensees CAP as AR 2014-9001, this violation is being treated as an NCV

consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000315/2014005-06; 05000316/2014005-06; Failure to Identify Deficient

Locked High Radiation Area Controls Due to Procedure Inadequacy)

.5

Risk Significant High Radiation Area and Very-High Radiation Area Controls (02.06)

a.

Inspection Scope

The inspectors discussed with the radiation protection manager the controls and

procedures for high-risk, high radiation areas and very-high radiation areas. The

inspectors discussed methods employed by the licensee to provide stricter control of

very-high radiation area access as specified in 10 CFR 20.1602, Control of Access to

Very-High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and

Very-High Radiation Areas of Nuclear Plants. The inspectors assessed whether any

changes to licensee procedures substantially reduce the effectiveness and level of

worker protection.

The inspectors discussed the controls in place for special areas that have the potential

to become very-high radiation areas during certain plant operations with first-line health

physics supervisors (or equivalent positions having backshift health physics oversight

authority). The inspectors assessed whether these plant operations require

communication beforehand with the health physics group, so as to allow corresponding

timely actions to properly post, control, and monitor the radiation hazards including

re-access authorization.

The inspectors evaluated licensee controls for very-high radiation areas and areas with

the potential to become a very-high radiation areas to ensure that an individual was not

able to gain unauthorized access to the very-high radiation areas.

b.

Findings

No findings were identified.

.6

Radiation Worker Performance (02.07)

a.

Inspection Scope

The inspectors observed radiation worker performance with respect to stated radiation

protection work requirements. The inspectors assessed whether workers were aware of

the radiological conditions in their workplace and the radiation work permit controls/limits

in place, and whether their performance reflected the level of radiological hazards

present.

37

b.

Findings

No findings were identified.

.7

Radiation Protection Technician Proficiency (02.08)

a.

Inspection Scope

The inspectors observed the performance of the radiation protection technicians with

respect to all radiation protection work requirements. The inspectors evaluated whether

technicians were aware of the radiological conditions in their workplace and the radiation

work permit controls/limits, and whether their performance was consistent with their

training and qualifications with respect to the radiological hazards and work activities.

b.

Findings

No findings were identified.

.8

Problem Identification and Resolution (02.09)

a.

Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring and

exposure control were being identified by the licensee at an appropriate threshold and

were properly addressed for resolution in the licensees Corrective Action Program. The

inspectors assessed the appropriateness of the corrective actions for a selected sample

of problems documented by the licensee that involve radiation monitoring and exposure

controls. The inspectors assessed the licensees process for applying operating

experience to their plant.

b.

Findings

No findings were identified.

2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls (71124.02)

The inspection activities supplement those documented in NRC Inspection Report

05000315-05000316/2014002 and constitute a partial sample as defined in Inspection

Procedure 71124.02-05.

.1

Radiation Worker Performance (02.05)

a.

Inspection Scope

The inspectors observed radiation worker and radiation protection technician

performance during work activities being performed in radiation areas, airborne

radioactivity areas, or high radiation areas. The inspectors evaluated whether workers

demonstrated the ALARA philosophy in practice (e.g., workers are familiar with the work

activity scope and tools to be used, workers used ALARA low-dose waiting areas) and

whether there were any procedure compliance issues (e.g., workers are not complying

with work activity controls). The inspectors observed radiation worker performance to

assess whether the training and skill level was sufficient with respect to the radiological

hazards and the work involved.

38

b.

Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program (71124.07)

This inspection constituted one complete sample as defined in Inspection Procedure

71124.07-05.

.1

Inspection Planning (02.01)

a.

Inspection Scope

The inspectors reviewed the annual radiological environmental operating reports and the

results of any licensee assessments since the last inspection to assess whether the

Radiological Environmental Monitoring Program was implemented in accordance with

the Technical Specifications and Offsite Dose Calculation Manual. This review included

reported changes to the Offsite Dose Calculation Manual with respect to environmental

monitoring, commitments in terms of sampling locations, monitoring and measurement

frequencies, land use census, Inter-Laboratory Comparison Program, and analysis of

data.

The inspectors reviewed the Offsite Dose Calculation Manual to identify locations of

environmental monitoring stations.

The inspectors reviewed the Final Safety Analysis Report for information regarding the

environmental monitoring program and meteorological monitoring instrumentation.

The inspectors reviewed quality assurance audit results of the program to assist in

choosing inspection smart samples. The inspectors also reviewed audits and technical

evaluations performed on the vendor laboratory if used.

The inspectors reviewed the annual effluent release report and the 10 CFR Part 61,

Licensing Requirements for Land Disposal of Radioactive Waste, report, to determine if

the licensee was sampling, as appropriate, for the predominant and dose-causing

radionuclides likely to be released in effluents.

b.

Findings

No findings were identified.

.2

Site Inspection (02.02)

a.

Inspection Scope

The inspectors walked down select air sampling stations and dosimeter monitoring

stations to determine whether they were located as described in the Offsite Dose

Calculation Manual and to determine the equipment material condition. Consistent with

smart sampling, the air sampling stations were selected based on the locations with the

highest X/Q, D/Q wind sectors, and dosimeters were selected based on the most risk

significant locations (e.g., those that have the highest potential for public dose impact).

39

For the air samplers and dosimeters selected, the inspectors reviewed the calibration

and maintenance records to evaluate whether they demonstrated adequate operability of

these components. Additionally, the review included the calibration and maintenance

records of select composite water samplers.

The inspectors assessed whether the licensee had initiated sampling of other

appropriate media upon loss of a required sampling station.

The inspectors observed the collection and preparation of environmental samples from

different environmental media (e.g., ground and surface water, milk, vegetation,

sediment, and soil) as available to determine whether environmental sampling was

representative of the release pathways as specified in the Offsite Dose Calculation

Manual and if sampling techniques were in accordance with procedures.

Based on direct observation and review of records, the inspectors assessed whether

the meteorological instruments were operable, calibrated, and maintained in

accordance with guidance contained in the Final Safety Analysis Report, NRC

Regulatory Guide 1.23, Meteorological Monitoring Programs for Nuclear Power Plants,

and licensee procedures. The inspectors assessed whether the meteorological data

readout and recording instruments in the control room and, if applicable, at the tower

were operable.

The inspectors evaluated whether missed and/or anomalous environmental samples

were identified and reported in the annual environmental monitoring report. The

inspectors selected events that involved a missed sample, inoperable sampler, lost

dosimeter, or anomalous measurement to determine if the licensee had identified the

cause and had implemented corrective actions. The inspectors reviewed the licensees

assessment of any positive sample results (i.e., licensed radioactive material detected

above the lower limits of detection) and reviewed the associated radioactive effluent

release data that was the source of the released material.

The inspectors selected structures, systems, or components that involve or could

reasonably involve licensed material for which there is a credible mechanism for

licensed material to reach ground water, and assessed whether the licensee had

implemented a sampling and monitoring program sufficient to detect leakage of these

structures, systems, or components to ground water.

The inspectors evaluated whether records, as required by 10 CFR 50.75(g), of leaks,

spills, and remediation since the previous inspection were retained in a retrievable

manner.

The inspectors reviewed any significant changes made by the licensee to the Offsite

Dose Calculation Manual as the result of changes to the land census, long-term

meteorological conditions (3-year average), or modifications to the sampler stations

since the last inspection. They reviewed technical justifications for any changed

sampling locations to evaluate whether the licensee performed the reviews required to

ensure that the changes did not affect its ability to monitor the impacts of radioactive

effluent releases on the environment.

The inspectors assessed whether the appropriate detection sensitivities with respect to

Technical Specifications/Offsite Dose Calculation Manual where used for counting

40

samples (i.e., the samples meet the technical specifications/Offsite Dose Calculation

Manual required lower limits of detection). The inspectors reviewed quality control

charts for maintaining radiation measurement instrument status and actions taken for

degrading detector performance. The licensee uses a vendor laboratory to analyze the

radiological environmental monitoring program samples so the inspectors reviewed the

results of the vendors quality control program, including the inter-laboratory comparison,

to assess the adequacy of the vendors program.

The inspectors reviewed the results of the licensees Inter-Laboratory Comparison

Program to evaluate the adequacy of environmental sample analyses performed by the

licensee. The inspectors assessed whether the inter-laboratory comparison test

included the media/nuclide mix appropriate for the facility. If applicable, the inspectors

reviewed the licensees determination of any bias to the data and the overall effect on

the radiological environmental monitoring program.

b.

Findings

No findings were identified.

.3

Identification and Resolution of Problems (02.03)

a.

Inspection Scope

The inspectors assessed whether problems associated with the radiological

environmental monitoring program were being identified by the licensee at an

appropriate threshold and were properly addressed for resolution in the licensees

Corrective Action Program. Additionally, they assessed the appropriateness of the

corrective actions for a selected sample of problems documented by the licensee that

involved the radiological environmental monitoring program.

b.

Findings

No findings were identified.

4.

OTHER ACTIVITIES

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

Preparedness, and Occupational and Public Radiation Safety

4OA1 Performance Indicator Verification (71151)

.1

Mitigating Systems Performance Index - Emergency AC Power System

a.

Inspection Scope

In the third quarter of 2014, the inspectors sampled licensee submittals for the Mitigating

Systems Performance Index (MSPI) - Emergency AC Power System performance

indicator for Donald C. Cook Unit 1 and Unit 2 for the period from the third quarter 2013

through the second quarter 2014. 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

41

licensees operator narrative logs, MSPI derivation reports, issue reports, event reports

and NRC Integrated Inspection Reports for the period of July 2013 through June 2014 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 licensees issue report database to

determine if any problems had been identified with the PI data collected or transmitted

for this indicator and none were identified. Documents reviewed are listed in the

Attachment to this report. Portions of this inspection activity were credited in NRC

Inspection Report 05000315-05000316/2014004.

This inspection constituted one MSPI emergency AC power system sample as defined in

IP 71151-05.

b.

Findings

No findings were identified.

.2

Mitigating Systems Performance Index - High Pressure Injection Systems

a.

Inspection Scope

In the third quarter of 2014, the inspectors sampled licensee submittals for the Mitigating

Systems Performance Index - High Pressure Injection Systems performance indicator

for Donald C. Cook Unit 1 and Unit 2 for the period from the third quarter of 2013 thru

the third quarter of 2014. 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 licensees operator narrative logs, issue

reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports

for the period of the third quarter of 2013 thru the 2nd quarter of 2014 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 licensees issue report database to

determine if any problems had been identified with the PI data collected or transmitted

for this indicator and none were identified. Documents reviewed are listed in the

Attachment to this report. Portions of this inspection activity were credited in NRC

Inspection Report 05000315-05000316/2014004.

This inspection constituted one MSPI high pressure injection system sample as defined

in IP 71151-05.

b.

Findings

No findings were identified.

42

.3

Mitigating Systems Performance Index - Heat Removal System

a.

Inspection Scope

In the third quarter of 2014, the inspectors sampled licensee submittals for the Mitigating

Systems Performance Index - Heat Removal System performance indicator for

Donald C. Cook Unit 1 and Unit 2 for the period from the third quarter 2013 through the

second quarter 2014. 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 licensees operator narrative logs, issue reports,

event reports, MSPI derivation reports, and NRC Integrated Inspection Reports for the

period of July 2013 through June 2014 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 licensees issue report database to determine if any problems had been identified

with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report. Portions of this

inspection activity were credited in NRC Inspection Report

05000315-05000316/2014004.

This inspection constituted one MSPI heat removal system sample as defined in

IP 71151-05.

b.

Findings

No findings were identified.

.4

Mitigating Systems Performance Index - Residual Heat Removal System

a.

Inspection Scope

In the third quarter of 2014, the inspectors sampled licensee submittals for the Mitigating

Systems Performance Index - Residual Heat Removal System performance indicator for

Donald C. Cook Unit 1 and Unit 2 for the period from the third quarter 2013 through the

second quarter 2014. 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 licensees operator narrative logs, issue reports,

MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the

period of July 2013 through June 2014 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 licensees issue report database to determine if any problems had been identified

with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report. Portions of this

inspection activity were credited in NRC Inspection Report

05000315-05000316/2014004.

43

This inspection constituted one MSPI residual heat removal system sample as defined in

IP 71151-05.

b.

Findings

No findings were identified.

.5

Mitigating Systems Performance Index - Cooling Water Systems

a.

Inspection Scope

In the third quarter of 2014, the inspectors sampled licensee submittals for the Mitigating

Systems Performance Index - Cooling Water Systems performance indicator for