ML17223A116

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NRC Integrated Inspection Report 05000445/2017002 and 05000446/2017002
ML17223A116
Person / Time
Site: Comanche Peak  Luminant icon.png
Issue date: 08/10/2017
From: Mark Haire
NRC/RGN-IV/DRP/RPB-A
To: Peters K
Vistra Operations Company
Mark Haire
References
IR 2017002
Download: ML17223A116 (58)
v • d • e


See also: IR 05000445/2017002

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E. LAMAR BLVD

ARLINGTON, TX 76011-4511

August 10, 2017

Ken J. Peters, Senior Vice President

and Chief Nuclear Officer

Vistra Operations Company LLC

P.O. Box 1002

Glen Rose, TX 76043

SUBJECT: COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED

INSPECTION REPORT 05000445/2017002 and 05000446/2017002

Dear Mr. Peters:

On June 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at

your Comanche Peak Nuclear Power Plant, Units 1 and 2. On July 11, 2017, the NRC

inspectors discussed the results of this inspection with you and other members of your staff.

Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented five findings of very low safety significance (Green) in this report.

All of these findings involved violations of NRC requirements. Further, inspectors documented a

licensee-identified violation which was determined to be of very low safety significance in this

report. The NRC is treating these violations as non-cited violations (NCVs) consistent with

Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within

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

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

copies to the Regional Administrator, Region IV; the Director, Office of Enforcement,

U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident

inspector at the Comanche Peak Nuclear Power Plant.

If you disagree with a cross-cutting aspect assignment 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 IV; and the NRC resident inspector at the

Comanche Peak Nuclear Power Plant.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public

Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your

response (if any) will be made available electronically for public inspection in the NRCs Public

Document Room or the NRC's Agencywide Documents Access and Management System

(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html.

K. Peters 2

To the extent possible, your response, if any, should not include any personal privacy,

proprietary, or safeguards information so that it can be made available to the public without

redaction.

Sincerely,

/RA/

Mark S. Haire, Chief

Project Branch A

Division of Reactor Projects

Docket Nos. 5000445 and 5000446

License Nos. NPF-87 and NPF-89

Enclosure:

Inspection Report 05000445/2017002 and

050446/2017002

w/ Attachments:

1.) Supplemental Information

2.) Document Request

3.) Licensee Event Report

Detailed Risk Evaluation

K. Peters 3

COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT

05000445/2017002 and 05000446/2017002 - DATED AUGUST 10, 2017

DISTRIBUTION

KKennedy, RA

SMorris, DRA

TPruett, DRP

AVegel, DRS

JClark, DRS

RLantz, DRP

JJosey, DRP

RKumana, DRP

MHaire, DRP

RAlexander, DRP

MKirk, DRP

TSullivan, DRP

SJanicki, DRP

DLackey, DRP

JBowen, RIV/OEDO

KFuller, RC

VDricks, ORA

JWeil, OCA

MWatford, NRR

AMoreno, RIV/OCA

BMaier, RSLO

THipschman, IPAT

EUribe, IPAT

MHerrera, DRMA

RIV ACES

ROP Reports

Electronic Distribution for Comanche Peak Nuclear Power Plant

ADAMS ACCESSION NUMBER: ML17223A116

SUNSI Review ADAMS Non-Sensitive Publicly Available

By: MHaire/dll Yes No Sensitive Non-Publicly Available

OFFICE SRI:DRP/A RI:DRP/A SPE:DRP/A BC:EB1 BC:EB2 BC:OB

NAME JJosey RKumana RAlexander TFarnholtz GWerner VGaddy

SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/ /RA/

JMateychick

for

DATE 08/07/2017 08/04/2017 08/03/17 8/7/2017 08/08/2017 8/4/17

OFFICE BC:PSB2 TL-IPAT BC:DRP/A

NAME HGepford THipschman MHaire

SIGNATURE /RA/ /RA/ /RA/

DATE 08/04/2017 08/03/2017 8/9/17

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000445, 05000446

License: NPF-87, NPF-89

Report: 05000445/2017002 and 05000446/2017002

Licensee: Vistra Operations Company, LLC

Facility: Comanche Peak Nuclear Power Plant, Units 1 and 2

Location: 6322 N. FM-56, Glen Rose, Texas

Dates: April 1 through June 30, 2017

Inspectors: J. Josey, Senior Resident Inspector

R. Kumana, Resident Inspector

S. Janicki, Project Engineer

M. Chambers, Physical Security Inspector

L. Carson II, Sr. Health Physicist

J. ODonnell, CHP, Health Physicist

K. Clayton, Senior Operations Engineer

I. Anchondo, Reactor Inspector

Approved Mark S. Haire

By: Chief, Project Branch A

Division of Reactor Projects

Enclosure

SUMMARY

IR 05000445/2017002; 05000446/2017002; 04/01/2017 - 06/30/2017; Comanche Peak Nuclear

Power Plant; Fire Protection; Fire Protection; Inservice Inspection Activities; Maintenance

Effectiveness; Maintenance Risk Assessments and Emergent Work Control; Follow-up of

Events and Notices of Enforcement Discretion

The inspection activities described in this report were performed between April 1 and

June 30, 2017, by the resident inspectors on site and inspectors from the NRCs Region IV

office. Five findings of very low safety significance (Green) are documented in this report. All of

these findings involved violations of NRC requirements. The significance of inspection findings

is indicated by their color (Green, White, Yellow, or Red), which is determined using Inspection

Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are

determined using Inspection Manual Chapter 0310, Aspects within the Cross-Cutting Areas.

Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement

Policy. The NRCs program for overseeing the safe operation of commercial nuclear power

reactors is described in NUREG-1649, Reactor Oversight Process.

Cornerstone: Mitigating Systems

  • Green. The inspectors identified a non-cited violation of Operating Licenses NPF-87 and

NPF-89, License Condition 2.G, Fire Protection Program, for the failure to control transient

combustibles in accordance with the stations fire protection report. Specifically, Fire

Protection Report, Revision 29, Section 5.3.8, Fire Area EO - Control Room, includes

Deviation 3c-1, Control Room Missile Door, which requires, in part, that since the control

room missile door in the west wall is not a 3-hour rated fire door, the area of the turbine deck

within 100 feet of the door is to be void of combustibles. Contrary to this, the licensee

allowed storage of combustible materials in this area without required compensatory

measures. This issue does not represent an immediate safety concern because the

licensee removed the combustible materials upon identification. The licensee entered this

issue into corrective action program as Condition Report CR-2017-5564.

The failure to control transient combustible material in accordance with the approved fire

protection report is a performance deficiency. The performance deficiency was more than

minor and therefore a finding because it was associated with the protection against external

factors attribute of the Mitigating System Cornerstone and adversely affected the

cornerstone objective to ensure the availability, reliability, and capability of systems that

respond to initiating events to prevent undesirable consequences. Specifically, the

introduction of transient combustible materials decreased the external event mitigation for

fire prevention. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial

Characterization of Findings, June 19, 2012, the inspectors determined that the finding

pertained to a failure to adequately implement fire prevention and administrative controls for

transient combustible materials. As a result, the inspectors were directed to Inspection

Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process,

September 20, 2013. The inspectors evaluated the finding through Appendix F,

Attachment 1, Fire Protection Significance Determination Process Worksheet,

September 20, 2013, and determined that the finding was of very low safety consequence

(Green) because the Fire Prevention and Administrative Controls finding would not prevent

the reactor from reaching and maintaining a safe shutdown condition. The finding has a

problem identification and resolution cross-cutting aspect associated with resolution, in that,

the licensee failed to take effective corrective actions to address issues in a timely manner.

2

Specifically, the licensee had previously identified this issue in Condition Report

CR-2014010224 but had failed to take corrective actions to address it [P.3]. (Section 1R05)

Criterion V, Instructions, Procedures, and Drawings, that occurred when the licensee failed

on two occasions to perform an adequate operability determination associated with multiple

safety-related pipe supports. Specifically, the operability determination of multiple carbon

steel pipe support clamps exposed to boric acid and a bent sway strut pipe restraint lacked

the engineering rigor necessary to provide a high degree of confidence to support the

operability of the components. Subsequently, the inspectors concluded that the licensee

established reasonable expectation for operability once engineering provided the control

room with further analysis on the degraded conditions, and the new information was

reviewed and accepted. This issue was entered into the licensees corrective action

program as Condition Report CR-2017-05418.

The licensee's failure to perform adequate operability determinations per plant procedures

was a performance deficiency. The performance deficiency was more than minor, and

therefore a finding, because it was associated with the equipment performance attribute of

the Mitigating System cornerstone and adversely affected the cornerstone objective of

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

to prevent undesirable consequences. Specifically, the licensee: (1) failed to perform the

required corrosion evaluation for a comparison of material wastage against design

dimensions of the pipe support clamps; (2) failed to perform a visual inspection of the

material condition of the pipe support clamps as required by the work order; (3) used

non-seismic design tolerances for the qualification of a seismically qualified strut in the

immediate operability determination; and (4) failed to consider that the bent condition of the

strut occurred after the previously accepted visual examinations on the same pipe support.

All these issues could have resulted in safety-related components failing to perform their

specified safety function during accident conditions. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated October 7, 2016, and

Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for

Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors

determined the finding was of very low safety significance (Green) because the finding: (1) it

was not a design deficiency; (2) did not represent a loss of system and/or function; (3) did

not represent an actual loss of function of at least a single train for longer than its technical

specification allowed outage time; (4) and did not result in the loss of a high safety-

significant non-technical specification train. This finding had a cross-cutting aspect in the

area of problem identification and resolution associated with resolution because the licensee

failed to adequately assess the degraded condition of the pipe supports in a complete and

accurate manner to support a reasonable expectation of operability [P.1]. (Section 1R08)

Criterion III, Design Control, associated with the licensees failure to assure that design

changes were subject to design control measures commensurate with those applied to the

original design. Specifically, the licensee changed internal components for safety-related,

steam generator atmospheric relief valve booster relays but failed to verify that these new

components could withstand the environment created during a high energy line break. This

issue does not represent an immediate safety concern because the licensee performed an

operability determination which established a reasonable expectation for operability, and

implemented corrective actions to replace the relays with qualified relays. The licensee

3

entered this issue into the corrective action program for resolution as Condition Report CR-

2017-006236.

The failure to ensure that changes to the facility were subject to design control measures

commensurate with those applied to the original design was a performance deficiency. The

performance deficiency was more than minor, and therefore a finding, because it was

associated with the equipment performance attribute of the Mitigating Systems Cornerstone

and affected the associated objective to ensure availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences. Using

Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated

October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance

Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening

Questions, the inspectors determined the finding was of very low safety significance

(Green) because the finding: (1) was not a deficiency affecting the design and qualification

of a mitigating structure, system, or component, and did not result in a loss of operability or

functionality, (2) did not represent a loss of system and/or function, (3) did not represent an

actual loss of function of at least a single train for longer than its allowed outage time, or two

separate safety systems out-of-service for longer than their technical specification allowed

outage time, and (4) does not represent an actual loss of function of one or more non-

technical specification trains of equipment designated as high safety-significant for greater

than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in accordance with the licensees maintenance rule program. The inspectors

did not assign a cross-cutting aspect because the performance deficiency was not reflective

of present performance. (Section 1R12)

Criterion III, Design Control, associated with the licensees failure to assure that applicable

regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified

in the license application, for those structure, systems and components to which this

appendix applies, were correctly translated into specifications, drawings, procedures, and

instructions. Specifically, from initial construction through March 2017, the licensee failed to

fully incorporate applicable moderate energy line break design requirements for fire

protection piping located in the vicinity of the station service water pumps, the latter which

are needed to ensure the capability to shut down the reactor and maintain it in a safe

shutdown condition following a moderate energy line break. This issue does not represent

an immediate safety concern because when the lines were identified the licensee took

prompt action to isolate and depressurize them, and the licensee has implemented plant

modifications. The licensee entered this issue into the corrective action program as

Condition Report CR-2016-008147.

The failure to incorporate applicable design requirements into specifications for moderate

energy line break protection was a performance deficiency. The performance deficiency

was more than minor, and therefore a finding, because it was associated with the design

control attribute of the Mitigating Systems cornerstone and affected the cornerstone

objective to ensure the availability, reliability, and capability of systems that respond to

initiating events to prevent undesirable consequences. Specifically, from initial construction

through March 2017, the licensee failed to fully incorporate applicable design requirements

for components needed to ensure the capability to shut down the reactor and maintain it in a

safe shutdown condition following a moderate energy line break. Using Inspection Manual

Chapter 0609, Attachment 04, Initial Characterization of Findings, dated July 1, 2012, and

Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for

Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated

4

October 7, 2016, the inspectors determined the finding required a detailed risk evaluation

because the finding involved a deficiency affecting the design and qualification of a

mitigating structure, system, or component, and resulted in a loss of operability, and

represented an actual loss of function of at least a single train for longer than its allowed

outage time. A senior reactor analysts from Region IV performed a detailed risk evaluation

and determined that the bounding increase in core damage frequency for this issue was

5.1E-8/year for Unit 1 and 2.9E-10/year for Unit 2, and was therefore of very low safety

significance (Green). The inspectors did not assign a cross-cutting aspect because the

performance deficiency was not reflective of present performance. (Section 4OA3)

Cornerstone: Barrier Integrity

  • Green. The inspectors identified a non-cited violation of 10 CFR 50.65(a)(4), Requirements

for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees

failure to adequately assess risk and implement required risk management actions for a

planned maintenance activity. Specifically, the licensee failed to evaluate the risk and

implement required risk management actions associated with disabling a hazard barrier and

breeching the control room envelope when blocking open door E-40A. This issue did not

represent an immediate safety concern because, at the time of identification, the licensee

stopped the activity and secured the door. The licensee entered this issue into the corrective

action program for resolution as Condition Report CR-2017-006019.

The failure to adequately assess the risk and implement required risk management actions

for proposed maintenance activities was a performance deficiency. This performance

deficiency was more than minor, and therefore a finding, because it was associated with the

configuration control attribute of the Barrier Integrity Cornerstone and affected the

associated objective to ensure physical design barriers protect the public from radionuclide

releases caused by accidents or events. Using Inspection Manual Chapter 0609,

Appendix K, Maintenance Risk Assessment and Risk Management Significance

Determination Process, dated May 19, 2005, Flowchart 2, Assessment of Risk

Management Actions, the inspectors determined the need to calculate the risk deficit to

determine the significance of this issue. A senior reactor analyst determined the finding to

have very low safety significance (Green) based on combining the effects of the degradation

of the radiological barrier and tornado missile barrier functions. The analyst performed a

qualitative review of the screening criteria in Manual Chapter 0609, Appendix A, The

Significance Determination Process for Findings At-Power, for the degradation of the

radiological barrier function for the control room and considered the short exposure time

(2.9E-5 years) and the Comanche Peak specific high winds frequency (3.0E-4/year) for the

tornado missile barrier function of the control room to determine that the incremental core

damage probability deficit and the incremental large early release probability deficit were

less than 1E-6 and 1E-7, respectively. The finding has a human performance cross-cutting

aspect associated with procedure adherence, in that operations personnel failed to follow

procedures when allowing door E-40A to be opened. (Section 1R13)

5

PLANT STATUS

Unit 1 began the inspection period at approximately 100 percent power. On May 20, 2017,

unit 1 reduced power to 68 percent for main turbine testing and returned to full power the same

day. Unit 1 operated at full power for the rest of the inspection period.

Unit 2 began the inspection period at approximately 98 percent power. On April 2, 2017, Unit 2

was shut down for a planned refueling outage. Unit 2 returned to full power on May 10, 2017.

On June 2, 2017, unit 2 lowered power to 73 percent due to high turbine generator

temperatures. On June 5, unit 2 was shut down to repair the turbine generator and remained

shut down for the rest of the inspection period.

REPORT DETAILS

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

.1 Summer Readiness for Offsite and Alternate AC Power Systems

a. Inspection Scope

On June 26, 2017, the inspectors completed an inspection of the stations off-site and

alternate-ac power systems. The inspectors inspected the material condition of these

systems, including transformers and other switchyard equipment to verify that plant

features and procedures were appropriate for operation and continued availability of off-

site and alternate-ac power systems. The inspectors reviewed outstanding work orders

and open condition reports for these systems. The inspectors walked down the

switchyard to observe the material condition of equipment providing off-site power

sources.

These activities constituted one sample of summer readiness of off-site and alternate-ac

power systems, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment (71111.04)

.1 Partial Walk-Down

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant

systems:

  • April 25, 2017, Unit 2, component cooling water heat exchanger 2-01

6

The inspectors reviewed the licensees procedures and system design information to

determine the correct lineup for the systems. They visually verified that critical portions

of the systems or trains were correctly aligned for the existing plant configuration.

These activities constituted three partial system walk-down samples as defined in

Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection (71111.05)

.1 Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status

and material condition. The inspectors focused their inspection on five plant areas

important to safety:

train A

  • April 24, 2017, Fire area EO65, Unit 1 and 2, control room
  • April 25, 2017, Fire area TB105g, Unit 1, turbine deck
  • April 25, 2017, Fire area TB205g, Unit 2, turbine deck
  • May 1, 2017, Fire areas AA26, AA27, AE32, AF33, Unit 1 and 2, component

cooling water pump rooms

For each area, the inspectors evaluated the fire plan against defined hazards and

defense-in-depth features in the licensees fire protection program. The inspectors

evaluated control of transient combustibles and ignition sources, fire detection and

suppression systems, manual firefighting equipment and capability, passive fire

protection features, and compensatory measures for degraded conditions.

These activities constituted five quarterly inspection samples, as defined in Inspection

Procedure 71111.05.

b. Findings

Introduction. The inspectors identified a Green, non-cited violation of Operating

Licenses NPF-87 and NPF-89, License Condition 2.G, Fire Protection Program, for the

failure to control transient combustibles in accordance with the stations fire protection

report.

7

Description. On April 24, 2017, while touring the turbine deck, the inspectors noted a

large amount of combustible material stored within the 100 foot combustible material

exclusion area of door E-40A, control room to turbine deck. The inspectors determined

that the licensee had performed and evaluation of this condition under

EV-TR-2017-003925-1 and determined it to be acceptable. Inspectors questioned this

evaluation because the stations Fire Protection Report, Revision 29, Section 5.3.8, Fire

Area EO - Control Room, contains Deviation 3c-1, Control Room Missile Door, which

requires, in part, that since the control room missile door in the west wall is not a 3-hour

rated fire door, the area of the turbine deck within 100 feet of the door is to be void of

combustibles.

The inspectors reviewed EV-TR-2017-003925-1 and noted that this evaluation

documented that the combustible material exclusion area was created because a fire

rating for door E-40A could not be found (Condition Report CR-2014-010224) and

referenced Calculation 0210-063-0043, Maximum Permissible Fire Loading/Non-Rated

Features Analysis, Revision 14, as a basis for a 3-hour fire rating for the door.

Inspectors reviewed Condition Report CR-2014-010224 and noted that it had been

generated because combustible materials had been stored within 100 feet of door E-40A

without proper controls. Furthermore, this condition report identified that Deviation 3c-1

requires the area of the turbine deck within 100 feet of the door is to be void of

combustible material since door E-40A is not a 3-hour rated fire door. Inspectors also

reviewed Calculation 0210-063-0043 and determined that this calculation was not a

design analyses and used judgement as a basis for a 3-hour fire rating on door E-40A,

which was non-conservative.

Inspectors determined that the licensee had failed to implement the requirements of the

stations approved Fire Protection Report when storing combustible materials within the

combustible material exclusion zone without proper controls. Inspectors informed the

licensee of their concern and the licensee initiated Condition Report CR-2017-005564 to

capture this issue in the stations corrective action program. The licensee also removed

all combustible material from the exclusion area.

During subsequent reviews inspectors noted that the licensee had also initiated

Condition Report CR-2016-004166 because Nuclear Oversight had determined that the

corrective actions for Condition Report CR-2014-010224 were not fully effective.

Condition Report CR-2016-004166 was subsequently closed with no actions taken.

Analyses. The failure to control transient combustible material in accordance with the

approved fire protection report is a performance deficiency. The performance deficiency

was more than minor and therefore a finding because it was associated with the

protection against external factors attribute of the Mitigating System Cornerstone and

adversely affected the cornerstone objective to ensure the availability, reliability, and

capability of systems that respond to initiating events to prevent undesirable

consequences. Specifically, the introduction of transient combustible materials

decreased the external event mitigation for fire prevention. Using NRC Inspection

Manual Chapter 0609, Attachment 4, Initial Characterization of Findings,

June 19, 2012, the inspectors determined that the finding pertained to a failure to

adequately implement fire prevention and administrative controls for transient

combustible materials. As a result, the inspectors were directed to Inspection Manual

Chapter 0609, Appendix F, Fire Protection Significance Determination Process,

September 20, 2013. The inspectors evaluated the finding through Appendix F,

8

Attachment 1, Fire Protection Significance Determination Process Worksheet,

September 20, 2013, and determined that the finding was of very low safety

consequence (Green) because the Fire Prevention and Administrative Controls finding

would not prevent the reactor from reaching and maintaining a safe shutdown condition.

The finding has a problem identification and resolution cross-cutting aspect associated

with resolution, in that, the licensee failed to take effective corrective actions to address

issues in a timely manner. Specifically, the licensee had previously identified this issue

in Condition Report CR-2014-010224 but had failed to take corrective actions to address

it [P.3].

Enforcement. Comanche Peak Unit 1, Operating License NPF-87, Condition 2.G,

Fire Protection, requires, in part, that the licensee implement and maintain in effect all

provisions of the approved fire protection program as described in the Final Safety

Analysis Report through Amendment 78 and as approved in the Safety Evaluation

Report and its supplements through Supplement 24.

Comanche Peak Unit 2, Operating License NPF-89, Condition 2.G, Fire Protection,

requires, in part, that the licensee implement and maintain in effect all provisions of the

approved fire protection program as described in the Final Safety Analysis Report

through Amendment 87 and as approved in the Safety Evaluation Report and its

supplements through Supplement 27.

The stations approved fire protection program includes Fire Protection Report,

Revision 29, Section 5.3.8, Fire Area EO - Control Room, which contains

Deviation 3c-1, Control Room Missile Door, which requires, in part, that since the

control room missile door in the west wall is not a 3-hour rated fire door, the area of the

turbine deck within 100 feet of the door is to be void of combustibles. Contrary to the

above, on April 24, 2017, the licensee failed to maintain the area around the control

room missile door void of combustibles. Specifically, the licensee allowed storage of

combustible materials within 100 feet of the control room missile door in the west wall

without required compensatory measures for the deviation from the Fire Protection

Report. This issue does not represent an immediate safety concern because upon

identification, the licensee removed the combustible materials from the 100 foot

exclusion area. Since this violation was of very low safety significance (Green) and has

been entered into the corrective action program as Condition Report CR-2017-005564,

this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of

the NRC Enforcement Policy. (NCV 05000445/2017002-01; 05000446/2017002-01,

Failure to Control Transient Combustible Material in Accordance with a Fire Protection

Procedure)

1R08 Inservice Inspection Activities (71111.08)

The activities described in subsections 1 through 4 below constitute completion of one

inservice inspection sample, as defined in Inspection Procedure 71111.08.

.1 Non-destructive Examination Activities and Welding Activities

a. Inspection Scope

The inspector directly observed the following nondestructive examinations:

9

EXAMINATION

SYSTEM COMPONENT IDENTIFICATION

TYPE

Reactor Coolant Pressurizer Upper Heat-to-Shell Ultrasonic

(TCX-1-2100-5)

Reactor Coolant Pressurizer Spay Nozzle to Vessel Ultrasonic

(TCX-1-2100-12)

Reactor Coolant Pressurizer Safety Nozzle to Vessel Ultrasonic

(TCX-1-2100-13)

Reactor Vessel Control Rod Drive Mechanism Ultrasonic

Head Penetrations 75, 76, 77, 78

The inspector reviewed records for the following nondestructive examinations:

EXAMINATION

SYSTEM COMPONENT IDENTIFICATION

TYPE

Reactor Coolant Pressurizer Longitude Weld Ultrasonic

(TCX-1-2100-9)

Reactor Coolant Pressurizer Safety Nozzle to Vessel Ultrasonic

(TCX-1-2100-14, TCX-1-2100-15,

TCX-1-2100-16)

Service Water SW-1-132-046-A43R (Strut) Visual (VT-3)

(SW-1-AB-001-H1 during refueling outage

RF5, RF12, and RF14)

During the review and observation of each examination, the inspector observed whether

activities were performed in accordance with the ASME Code requirements and

applicable procedures. The inspector reviewed one indication that was previously

examined, and observed that the licensee evaluated and accepted the indication in

accordance with the ASME Code and/or an NRC approved alternative. The inspector

also reviewed the qualifications of all nondestructive examination technicians performing

the inspections to determine whether they were current.

b. Findings

No findings were identified.

.2 Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

The inspector reviewed the results of the licensees volumetric inspection of the reactor

vessel head to determine whether the inspection met ASME Code Case N-729-1. The

inspector also reviewed whether the required inspection coverage was achieved and

whether limitations were properly recorded. The inspector reviewed whether the

personnel performing the inspection were certified examiners to their respective

nondestructive examination method.

10

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control Inspection Activities

a. Inspection Scope

The inspector reviewed implementation of the boric acid corrosion control program for

monitoring degradation of those systems that could be adversely affected by boric acid

corrosion. The inspector reviewed the documentation associated with boric acid

corrosion control walk downs, as specified in Procedure STA-737, Boric Acid Corrosion

Detection and Evaluation, Revision 8. The inspector reviewed whether the visual

inspections emphasized locations where boric acid leaks could cause degradation of

safety-significant components, whether engineering evaluations used corrosion rates

applicable to the affected components and whether engineering properly assessed the

effects of corrosion induced wastage on structural or pressure boundary integrity. The

inspector observed whether corrective actions taken were consistent with the ASME

Code, 10 CFR 50, and Appendix B requirements.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The inspector reviewed the steam generator tube eddy current examination scope and

expansion criteria to determine whether these criteria met technical specification

requirements, EPRI guidelines, and commitments made to the NRC. The inspector also

reviewed whether the eddy current examination inspection scope included areas of

degradations that were known to represent potential eddy current test challenges such

as the top of tube sheet, tube support plates, and U-bends. The inspector confirmed

that no repairs were required at the time of the inspection.

Steam Generator Inspection

flaws/degradation identified were consistent with the licensees previous outage

operational assessment predictions.

  • The inspector verified that steam generator eddy current examination scope and

expansion criteria met technical specification requirements.

  • The inspector verified that eddy current probes and equipment configurations

used to acquire data from the steam generator tubes were qualified to detect the

known/expected types of steam generator tube degradation in accordance with

Appendix H, Performance Demonstration for Eddy Current Examination of

EPRI Document 1013706.

11

The inspector reviewed the licensees identification of the following tube degradation

mechanisms:

expansion locations with the hot leg (HL) tubesheet

  • circumferential PWSCC at the HL tubesheet expansion transition
  • tube wear at anti-vibration bars, preheater baffle plates, and quatrefoil tube

support plates

  • tube wear due to loose parts

The inspector verified that the licensees eddy current examination scope included the

new degradation mechanism, fully enveloped the problem, and has taken appropriate

corrective actions before plant start up. The licensee will now include circumferential

primary water stress corrosion cracking as a new degradation mechanism at the multiple

locations specified above.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspector reviewed 14 condition reports concerning inservice inspection activities to

evaluate whether the licensee implemented appropriate corrective actions for inservice

inspection issues. From this review the inspector concluded that the licensee has an

appropriate threshold for entering inservice inspection issues into the corrective action

program and has procedures that direct a root cause evaluation when necessary. The

licensee also has an effective program for applying industry inservice inspection

operating experience. Specific documents reviewed during this inspection are listed in

the attachment.

b. Findings

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

Criterion V, Instructions, Procedures, and Drawings, that occurred when the licensee

failed on two occasions to perform an adequate operability determination associated

with safety-related pipe supports. Specifically, the operability determination of multiple

carbon steel pipe support clamps exposed to boric acid and a bent sway strut pipe

restraint, lacked the engineering rigor to provide a high degree of confidence to support

the components operability.

Description. Procedure STI-422.01, Operability Determination and Functionality

Assessment Program, institutes a definition for reasonable expectation of operability in

Section 4.18. In particular, this definition establishes that the supporting basis for the

reasonable expectation of Technical Specification System, Structure, and Component

(SSC) operability should provide a high degree of confidence that the SSC remains

12

operable. This requirement is applicable during both immediate and prompt operability

determinations per procedure Section 6.2.1, and 6.2.2, respectively.

On April 27, 2016, the licensee performed a visual inspection on an ASME Code,

Class 3, sway strut pipe restraint in the service water system. The examination

documented a slight bend along the strut resulting in a failed visual examination. The

immediate operability determination in Condition Report CR-2016-03811, documented

that a slightly bent or bowed strut was acceptable per Site Specification CPES-P-1079,

Specification Field Fabrication and Erection of Pipe Supports. An evaluation under the

prompt operability determination documented that the bent condition was within the

design calculation tolerances and that the strut restraint remained operable. Further

discussions at the time of the inspection established that the licensee believed that the

bent strut was part of the original construction of the pipe support.

The immediate operability determination referenced Step 4.1.2.9 of Site

Specification CPES-P-1079, and established that a slight bend on the strut restraint was

an acceptable condition for operation without further evaluation. Step 4.1.2.9 states:

Seismic Category None supports shall be installed within +/- 5 degrees from the

angle indicated on the Design Drawing. Support rods shall be installed such that

they do not exhibit slack. Slightly bent or bowed rods are acceptable provided

they support the dead load of the pipe.

The inspector determined that Seismic Category None is a designation for

nonsafety-related components that are not seismically qualified and are not required

to have a quality assurance inspection. These requirements are specified in

Table 5.1.1.1, Pipe Support Design Document Classification Matrix, of Site

Specification CPES-P-1079. However, the inspector verified that the strut was classified

as safety-related and was seismically qualified per design documents. Furthermore, the

inspector determined that the prior two visual examinations on the same strut that were

performed as part of the ASME Section XI program had not identified an unacceptable

condition such as a slight bend on the component. Therefore, the inspector determined

that the bent condition did not exist prior to the failed visual examination and that the

licensee had failed to consider these facts in their operability determination.

Consequently, the licensee failed to establish a reasonable expectation of operability.

On May 4, 2016, the licensee identified rust particles under the insulation of the

discharge line to the reactor coolant system in the Chemical and Volume Control

System. Upon removal of the insulation, the affected components exhibited excessive

discoloration in the form of corrosion products and dry boric acid. These components

included three ASME Code, Class 3, carbon steel pipe support clamps. The licensee

proceeded to clean the affected components under Work Order 5268838. A step

included in the work order directed the licensee to perform a material condition

inspection to look for obvious degradation such as pitting or corrosion. As a conclusion,

the licensee determined that the pipe support clamps remained operable because the

cross-sectional properties of the clamps with respect to membrane or bending strength

remain unaffected.

The inspector questioned the level of technical details and assumptions provided in the

operability determination evaluations. Specifically, the inspector noted that statements

such as, the inspected surfaces exhibited minor boric acid staining and material loss,

13

and with minimal material lost given the amount of corrosion product, the corrosion was

of an intermittent nature, were provided without quantifying the condition of the clamps.

The inspector determined that the boric acid evaluation performed per the boric acid

corrosion control program had failed to take into account corrosion rates as required by

Procedure STA-737.01, Boric Acid Corrosion Detection and Evaluation, Rev 0.

Furthermore, the inspector concluded that the visual inspection per Work Order 5268838

had not been performed, but rather signed off by engineering per teleconference

referencing the evaluation provided as part of the operability evaluation. The inspector

concluded that the licensee had not provided the technical rigor required to demonstrate

a reasonable expectation of operability as required by Section 6.2.1 and 6.2.2 of

Procedure STI-422.01.

Analysis. The licensee's failure to perform adequate operability determinations per plant

procedures was a performance deficiency. The performance deficiency was more than

minor, and therefore a finding, because it was associated with the equipment

performance attribute of the Mitigating System cornerstone and adversely affected the

cornerstone objective of ensuring the availability, reliability, and capability of systems that

respond to initiating events to prevent undesirable consequences. Specifically, the

licensee: (1) failed to perform the required corrosion evaluation for a comparison of

material wastage against design dimensions of the pipe support clamps; (2) failed to

perform a visual inspection of the material condition of the pipe support clamps as

required by the work order; (3) used non-seismic design tolerances for the qualification

of a seismically qualified strut in the immediate operability determination; and (4) failed

to consider that the bent condition of the strut occurred after the previously accepted

visual examinations on the same pipe support. All these issues could have resulted in

safety-related components failing to perform their specified safety function during

accident conditions. Using Inspection Manual Chapter 0609, Attachment 04, Initial

Characterization of Findings, dated October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power, Exhibit

2, Mitigating Systems Screening Questions, the inspectors determined the finding was

of very low safety significance (Green) because the finding: (1) it was not a design

deficiency; (2) did not represent a loss of system and/or function; (3) did not represent

an actual loss of function of at least a single train for longer than its technical

specification allowed outage time; and (4) did not result in the loss of a high safety-

significant non-technical specification train. This finding had a cross-cutting aspect in

the area of problem identification and resolution associated with resolution because the

licensee failed to adequately assess the degraded condition of both pipe supports in a

complete and accurate manner to support a reasonable expectation of operability [P.1].

Enforcement. Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and

Drawings, requires, in part, that activities affecting quality shall be accomplished in

accordance with these instructions, procedures, or drawings. Procedure STI-422.01,

Operability Determination and Functionality Assessment Program, Section 4.18

institutes a definition for reasonable expectation of operability. In particular, this

definition establishes that, the supporting basis for the reasonable expectation of

Technical Specification System, Structure, and Component (SSC) operability should

provide a high degree of confidence that the SSC remains operable. Contrary to the

above, on April 27 and May 4, 2017, the licensee failed to accomplish activities affecting

quality in accordance with the applicable procedure. Specifically, the licensee

discovered multiple degraded conditions of safety-related pipe supports but failed to

14

implement adequate actions that provided a reasonable expectation of operability as

required by Procedure STI-422.01. Since the affected components were located in the

operating Unit, the inspector concluded that the licensee had established reasonable

expectation for operability once engineering had provided the control room with further

analysis on the degraded conditions and the new information was reviewed and

accepted. Because the violation was of very low safety significance and it was entered

into the corrective action program as Condition Report CR-2017-005418, this violation is

being treated as a non-cited violation consistent with Section 2.3.2 of the NRC

Enforcement Policy. (NCV 05000446/2017002-02, Inadequate Operability Evaluation for

Safety Related Pipe Supports)

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

(71111.11)

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On May 31, 2017, the inspectors observed an evaluated simulator scenario performed

by an operating crew. The inspectors assessed the performance of the operators and

the evaluators critique of their performance.

These activities constituted completion of one quarterly licensed operator requalification

program sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

On April 2, 2017, the inspectors observed the performance of on-shift licensed operators

in the Unit 2 main control room. At the time of the observations, the unit was in a period

of heightened activity due to performing a planned shutdown for refueling. The

inspectors observed the operators performance of the unit shutdown, and transition to

shutdown cooling.

In addition, the inspectors assessed the operators adherence to plant procedures,

including the conduct of operations procedure and other operations department policies.

These activities constituted completion of one quarterly licensed operator performance

sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.3 Biennial Review

The licensed operator requalification program involves two training cycles that are

15

conducted over a 2-year period. In the first cycle, the annual cycle, the operators are

administered an operating test consisting of job performance measures and simulator

scenarios. In the second part of the training cycle, the biennial cycle, operators are

administered an operating test and a comprehensive written examination. For this cycle,

the licensee is completing the second, or biennial cycle, which ends March 31, 2017.

The licensee completed the operating tests in December 2016 and the inspectors

documented the results of the operating test performance and content reviews in

inspection report(s) 05000445/2016004 and 05000446/2016004.

On April 17, 2017, the licensee informed the inspectors of the completed biennial cycle

results for Units 1 and 2 for both the written examinations and the operating tests:

  • 11 of 13 crews passed the simulator portion of the operating test
  • The 2 crews that were evaluated as unsatisfactory consisted of twelve operators

and one individual failed the simulator scenarios as an individual (not tied to crew

performance)

operating test

  • Out of 74 operators, 2 retired from the company in December 2016, and 71 of the

remaining 72 licensed operators passed the written examination

The final failure count on any portion of the biennial exams was 14 operators. Using

74 operators as the total number of operators that took any portion of the exam, this

resulted in an 18.9 percent failure rate. This is below the threshold for a finding

(greater than 20 percent failure is a green finding) as described in Inspection Manual

Chapter 0609, "Significance Determination Process," Appendix I, "Licensed Operator

Requalification Significance Determination Process."

The inspectors also reviewed the written examinations for content quality, overlap, and

remediation packages. The individuals that failed any portions of their operating tests

and/or written examinations were remediated, retested, and passed their retake

operating tests and/or written examinations prior to returning to shift.

The inspectors completed one inspection sample of the biennial licensed operator

requalification program.

a. Inspection Scope

b. Findings

No findings were identified.

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1R12 Maintenance Effectiveness (71111.12)

.1 Routine Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed one instance of degraded performance or condition of safety-

significant structures, systems, and components (SSCs):

  • June 8, 2017, Unit 2 component cooling water system

The inspectors reviewed the extent of condition of possible common cause SSC failures

and evaluated the adequacy of the licensees corrective actions. The inspectors

reviewed the licensees work practices to evaluate whether these may have played a

role in the degradation of the SSCs. The inspectors assessed the licensees

characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance

Rule), and verified that the licensee was appropriately tracking degraded performance

and conditions in accordance with the Maintenance Rule.

These activities constituted completion of one maintenance effectiveness sample, as

defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

.2 Quality Control

a. Inspection Scope

On April 25, 2017, the inspectors reviewed the licensees quality control activities

through a review of parts installed in the steam generator atmospheric relief valves that

were purchased as commercial-grade parts but were dedicated prior to installation in a

quality-grade application.

These activities constituted completion of one quality control sample, as defined in

Inspection Procedure 71111.12.

b. Findings

Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix

B, Criterion III, Design Control, associated with the licensees failure to assure that

design changes were subject to design control measures commensurate with those

applied to the original design. Specifically, the licensee changed internal components for

safety-related booster relays but failed to verify that these new components could

withstand the environment created during a high energy line break.

Description. While reviewing a commercial grade dedication package for steam

generator atmospheric relief valve booster relays inspectors noted that Condition Report

CR-2017-004594 was written because of identified discrepancies with the currently

installed relay. Specifically, the licensee had determined that in 2005 a design change

had been performed which allowed new relay models to be installed in the plant, and

17

these new model contained elastomers that were not qualified for the environmental

conditions the relays could be exposed to under accident conditions. Inspectors

determined that these changes to the facility were design changes that should have

been subject to design control measures commensurate with those applied to the

original design, but were not.

The inspectors reviewed the licensees evaluation documented in Condition Report

CR-2017-004594. While this evaluation identified that the relays were not qualified for

the environment it focused only on procuring replacement relays. Based on this

inspectors determined that the licensees evaluation was inadequate. Specifically, the

inspectors noted that (1) the operability evaluation performed by the licensee failed to

establish a reasonable expectation of operability for all of the relays, and the licensee

had not initiated a past operability to address the inoperable relay, (2) the licensee had

no actions to correct the identified condition adverse to quality of a design change

implemented without appropriate controls, and (3) the licensee had no actions in place to

ensure that the inadequate relays were controlled as blocked stock to ensure they were

not subsequently re-installed in the facility.

The inspectors informed the licensee of their concerns, and the licensee subsequently

added actions to Condition Report CR-2017-004594 to address these issues. The

additional actions included a revised operability evaluation completed by the licensee

which adequately established a reasonable expectation for operability while the licensee

procured and installed replacement booster relays which fully met the required

environmental qualifications.

Analysis. The failure to ensure that changes to the facility were subject to design control

measures commensurate with those applied to the original design was a performance

deficiency. The performance deficiency was more than minor, and therefore a finding,

because it was associated with the equipment performance attribute of the Mitigating

Systems Cornerstone and affected the associated objective to ensure availability,

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

undesirable consequences. Using Inspection Manual Chapter 0609, Attachment 04,

Initial Characterization of Findings, dated October 7, 2016, and Inspection Manual

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

Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the

finding was of very low safety significance (Green) because the finding: (1) was not a

deficiency affecting the design and qualification of a mitigating structure, system, or

component, and did not result in a loss of operability or functionality, (2) did not

represent a loss of system and/or function, (3) did not represent an actual loss of

function of at least a single train for longer than its allowed outage time, or two separate

safety systems out-of-service for longer than their technical specification allowed outage

time, and (4) does not represent an actual loss of function of one or more non-technical

specification trains of equipment designated as high safety-significant for greater than 24

hours in accordance with the licensees maintenance rule program. The inspectors did

not assign a cross-cutting aspect because the performance deficiency was not reflective

of present performance (i.e., the design change was completed in 2005).

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in

part, that, design changes, including field changes, shall be subject to design control

measures commensurate with those applied to the original design. Contrary to the

above, the volume booster relays in the Unit 1 and Unit 2 atmospheric relief valves,

18

items that are safety-related and to which Appendix B requirements apply, did not have

design changes subject to the same design control measures commensurate with those

applied to the original design. Specifically, between August 2005 and April 25, 2017, the

licensee implemented changes to the relays and failed to control critical materials inside

of the relays. This issue does not represent an immediate safety concern because the

licensee performed an operability determination which established a reasonable

expectation for operability, and implemented corrective actions to replace the relays with

qualified relays. Because this finding is of very low safety significance, and has been

documented in the corrective action program as CR-2017-006236, this violation is being

treated as an NCV consistent with Section 2.3.2.a of the NRC Enforcement Policy.

(05000445/2017002-03; 05000446/2017002-03, Relays not Environmentally Qualified)

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

a. Inspection Scope

The inspectors reviewed five risk assessments performed by the licensee prior to

changes in plant configuration and the risk management actions taken by the licensee in

response to elevated risk:

  • March 27, 2017, Unit 2, refueling outage 2RF16 defense in depth plan
  • April 17, 2017, Unit 2, equipment train A controls during orange risk window due

to train B outage

  • May 4, 2017, Unit 1 and Unit 2, controls in place when opening hazard barrier

door E-40A

  • May 31, 2017, Unit 2, sequencer maintenance during main turbine automatic

voltage regulator testing

maintenance window

The inspectors verified that these risk assessments were performed timely and in

accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant

procedures. The inspectors reviewed the accuracy and completeness of the licensees

risk assessments and verified that the licensee implemented appropriate risk

management actions based on the result of the assessments.

The inspectors also observed portions of the unit 2 polar crane troubleshooting during a

reactor vessel head lift on April 8 and 9, 2017, an emergent work activity that had the

potential to cause an initiating event.

The inspectors verified that the licensee appropriately developed and followed a work

plan for this activity. The inspectors verified that the licensee took precautions to

minimize the impact of the work activity on SSCs.

These activities constituted completion of six maintenance risk assessments and

emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

19

b. Findings

Introduction. The inspectors identified a non-cited violation of 10 CFR 50.65(a)(4),

Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power

Plants, for the licensees failure to adequately assess risk and implement required risk

management actions for a planned maintenance activity. Specifically, the licensee failed

to evaluate the risk and implement required risk management actions associated with

disabling a hazard barrier and breeching the control room envelope when blocking open

door E-40A.

Description. While touring the turbine deck on May 4, 2017, inspectors noted that door

E-40A was blocked open by a pallet jack with no workers in the immediate area of the

door. Inspectors questioned this because this door is a tornado missile boundary and

part of the control room pressure boundary. Inspectors noted that site procedure

ODA-308, LCO Tracking Program, Revision 16, section 13.7.39, Tornado Missile

Shields, contains a preplanned risk assessment and required risk management actions

associated with disabling this barrier. Specifically, for routine entry and exit, the person

opening/closing the door is in administrative control of the door and for all other activities

a dedicated individual stationed at the door in continuous communication with the control

room who could rapidly shut the door is required.

Inspectors went to the control room and engaged the shift manager with their concerns

about the current configuration of door E-40A. During their discussion they determined

that the shift manager had authorized the opening of the door, but had not reviewed and

implemented the required risk management actions specified in the risk assessment

documented in procedure ODA-308. The shift manager subsequently directed that the

activity be stopped, and door E-40A be shut. Condition Report CR-2017-006019 was

generated to capture this issue in the stations corrective action program.

Analysis. The failure to adequately assess the risk and implement required risk

management actions for proposed maintenance activities was a performance deficiency.

This performance deficiency was more than minor, and therefore a finding, because it

was associated with the configuration control attribute of the Barrier Integrity

Cornerstone and affected the associated objective to ensure physical design barriers

protect the public from radionuclide releases caused by accidents or events. Using

Inspection Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk

Management Significance Determination Process, dated May 19, 2005, Flowchart 2,

Assessment of Risk Management Actions, the inspectors determined the need to

calculate the risk deficit to determine the significance of this issue. A senior reactor

analyst determined the finding to have very low safety significance (Green) based on

combining the effects of the degradation of the radiological barrier and tornado missile

barrier functions. The analyst performed a qualitative review of the screening criteria in

Manual Chapter 0609, Appendix A, The Significance Determination Process for

Findings At-Power, for the degradation of the radiological barrier function for the control

room and considered the short exposure time (2.9E-5 years) and the Comanche Peak

specific high winds frequency (3.0E-4/year) for the tornado missile barrier function of the

control room to determine that the incremental core damage probability deficit and the

incremental large early release probability deficit were less than 1E-6 and 1E-7,

respectively. The finding has a human performance cross-cutting aspect associated

with procedure adherence, in that operations personnel failed to follow procedures when

allowing door E-40A to be opened [H.8].

20

Enforcement. Title 10 CFR 50.65(a)(4) states, in part, Before performing maintenance

activities (including, but not limited to surveillance, post-maintenance testing, and

corrective and preventive maintenance), the licensee shall assess and manage the

increase in risk that may result from proposed maintenance activities. Contrary to the

above, prior to performing maintenance activities, the licensee failed to manage the

associated increase in risk from the proposed maintenance activity. Specifically, on

May 4, 2017, the licensee failed to implement required risk management actions

associated with disabling a hazard barrier and breeching the control room envelope

when blocking open door E-40A. This issue did not represent an immediate safety

concern because, at the time of identification, the licensee stopped the activity and

secured the door. Since this violation was of very low safety significance (Green) and

has been entered into the corrective action program as Condition Report CR-2017-

006019, this violation is being treated as a non-cited violation consistent with Section

2.3.2.a of the NRC Enforcement Policy. (NCV 05000445/2017002-04;

05000446/2017002-04, Failure to Adequately Assess Risk and Implement Risk

Management Actions for Proposed Maintenance.)

1R15 Operability Determinations and Functionality Assessments (71111.15)

a. Inspection Scope

The inspectors reviewed seven operability determinations that the licensee performed

for degraded or nonconforming SSCs:

  • April 7, 2017, Unit 2, CR-2017-004391 negative pressure boundary door

degraded window

  • April 13, 2017, Unit 2, CR-2017-004737 2-02 reactor coolant pump bolting issue
  • April 20, 2017, Unit 1 and Unit 2, CR-2017-004594 steam generator atmospheric

relief valve booster relays contain unqualified material for environmental

qualification

comprehensive operability test flow oscillations

design minimum

exceeded response time acceptance criteria in surveillance procedure

  • May 18, 2017, Unit 2, IR-2017-006454 oil leak on chiller X-05

The inspectors reviewed the timeliness and technical adequacy of the licensees

evaluations. Where the licensee determined the degraded SSC to be operable or

functional, the inspectors verified that the licensees compensatory measures were

appropriate to provide reasonable assurance of operability or functionality. The

inspectors verified that the licensee had considered the effect of other degraded

conditions on the operability or functionality of the degraded SSC.

21

These activities constituted completion of seven operability and functionality review

samples as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed five post-maintenance testing activities that affected risk-

significant SSCs:

  • May 8, 2017, Unit 2, train A main steam line isolation and response time testing

following valve actuator adjustment

  • May 9, 2017, Unit 2, train A slave relay testing

maintenance

  • May 19, 2017, Unit 2, diesel generator 2-01 post maintenance re-torques

replacement of sentinel valve

The inspectors reviewed licensing- and design-basis documents for the SSCs and the

maintenance and post-maintenance test procedures. The inspectors observed the

performance of the post-maintenance tests to verify that the licensee performed the tests

in accordance with approved procedures, satisfied the established acceptance criteria,

and restored the operability of the affected SSCs.

These activities constituted completion of five post-maintenance testing inspection

samples, as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities (71111.20)

a. Inspection Scope

During the stations refueling outage that concluded on May 8, 2017, the inspectors

evaluated the licensees outage activities. The inspectors verified that the licensee

considered risk in developing and implementing the outage plan, appropriately managed

personnel fatigue, and developed mitigation strategies for losses of key safety functions.

This verification included the following:

22

  • Review of the licensees outage plan prior to the outage
  • Review and verification of the licensees fatigue management activities
  • Monitoring of shut-down and cool-down activities
  • Verification that the licensee maintained defense-in-depth during outage activities
  • Observation and review of reduced-inventory and mid-loop activities
  • Observation and review of fuel handling activities
  • Monitoring of heat-up and startup activities

These activities constituted completion of one refueling outage sample, as defined in

Inspection Procedure 71111.20.

b. Findings

No findings were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors observed seven risk-significant surveillance tests and reviewed test

results to verify that these tests adequately demonstrated that the SSCs were capable of

performing their safety functions:

In-service tests:

Containment isolation valve surveillance tests:

  • May 8, 2017, Unit 2, train A main steam line isolation and response time testing

Other surveillance tests:

  • April 12, 2017, Unit 2, train B integrated test sequence testing

The inspectors verified that these tests met technical specification requirements, that the

licensee performed the tests in accordance with their procedures, and that the results of

the test satisfied appropriate acceptance criteria. The inspectors verified that the

licensee restored the operability of the affected SSCs following testing.

23

These activities constituted completion of seven surveillance testing inspection samples,

as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

2. RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)

a. Inspection Scope

The inspectors evaluated the licensees performance in assessing the radiological

hazards in the workplace associated with licensed activities. The inspectors assessed

the licensees implementation of appropriate radiation monitoring and exposure control

measures for both individual and collective exposures. During the inspection, the

inspectors interviewed licensee personnel, walked down various areas in the plant,

performed independent radiation dose rate measurements, and observed postings and

physical controls. The inspectors reviewed licensee performance in the following areas:

  • Radiological hazard assessment, including a review of the plants radiological

source terms and associated radiological hazards. The inspectors also reviewed

the licensees radiological survey program to determine whether radiological

hazards were properly identified for routine and non-routine activities and

assessed for changes in plant operations.

  • Instructions to workers including radiation work permit requirements and

restrictions, actions for electronic dosimeter alarms, changing radiological

conditions, and radioactive material container labeling.

  • Contamination and radioactive material control, including release of potentially

contaminated material from the radiologically controlled area, radiological survey

performance, radiation instrument sensitivities, material control and release

criteria, and control and accountability of sealed radioactive sources.

  • Radiological hazards control and work coverage. During walk-downs of the

facility and job performance observations, the inspectors evaluated ambient

radiological conditions, radiological postings, adequacy of radiological controls,

radiation protection job coverage, and contamination controls. The inspectors

also evaluated dosimetry selection and placement as well as the use of

dosimetry in areas with significant dose rate gradients. The inspectors examined

the licensees controls for items stored in the spent fuel pool and evaluated

airborne radioactivity controls and monitoring.

downs, the inspectors verified the adequacy of posting and physical controls,

including areas of the plant with the potential to become risk-significant high

radiation areas.

24

  • Radiation worker performance and radiation protection technician proficiency

with respect to radiation protection work requirements. The inspectors

determined if workers were aware of significant radiological conditions in their

workplace, radiation work permit controls/limits in place, and electronic dosimeter

dose and dose rate set points. The inspectors observed radiation protection

technician job performance, including the performance of radiation surveys.

  • Problem identification and resolution for radiological hazard assessment and

exposure controls. The inspectors reviewed audits, self-assessments, and

corrective action program documents to verify problems were being identified

and properly addressed for resolution.

These activities constituted completion of the seven required samples of radiological

hazard assessment and exposure control program, as defined in Inspection

Procedure 71124.01.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation (71124.03)

a. Inspection Scope

The inspectors evaluated whether the licensee controlled in-plant airborne radioactivity

concentrations consistent with as low as reasonably achievable principles and that the

use of respiratory protection devices did not pose an undue risk to the wearer. During

the inspection, the inspectors interviewed licensee personnel, walked down various

areas in the plant, and reviewed licensee performance in the following areas:

  • Engineering controls, including the use of permanent and temporary ventilation

systems to control airborne radioactivity. The inspectors evaluated installed

ventilation systems, including review of procedural guidance, verification of

systems used during high-risk activities, and verification of airflow capacity, flow

path, and filter/charcoal unit efficiencies. The inspectors also reviewed the use of

temporary ventilation systems used to support work in contaminated areas, such

as high-efficiency particulate air/charcoal negative pressure units. Additionally,

the inspectors evaluated the licensees airborne monitoring protocols, including

verification that alarms and set points were appropriate.

  • Use of respiratory protection devices, including an evaluation of the licensees

respiratory protection program for use, storage, maintenance, and quality

assurance of National Institute for Occupational Safety and Health-certified

equipment, air quality and quantity for supplied-air devices and self-contained

breathing apparatus (SCBA) bottles, qualification and training of personnel, and

user performance.

  • Self-contained breathing apparatus for emergency use, including the licensees

capability for refilling and transporting SCBA bottles to and from the control room

and operations support center during emergency conditions, hydrostatic testing

25

of SCBA bottles, status of SCBA staged and ready for use in the plant including

vision correction, mask sizes, etc., SCBA surveillance and maintenance records,

and personnel qualification, training, and readiness.

  • Problem identification and resolution for airborne radioactivity control and

mitigation. The inspectors reviewed audits, self-assessments, and corrective

action documents to verify problems were being identified and properly

addressed for resolution.

These activities constituted completion of the four required samples of in-plant

airborne radioactivity control and mitigation program, as defined in Inspection

Procedure 71124.03.

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

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

Preparedness, Public Radiation Safety, Occupational Radiation Safety, and

Security

4OA1 Performance Indicator Verification (71151)

.1 Safety System Functional Failures (MS05)

a. Inspection Scope

For the period of April 1, 2016, through March 31, 2017, the inspectors reviewed

licensee event reports (LERs), maintenance rule evaluations, and other records that

could indicate whether safety system functional failures had occurred. The inspectors

used definitions and guidance contained in Nuclear Energy Institute Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-

1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to determine

the accuracy of the data reported.

These activities constituted verification of the safety system functional failures

performance indicator for units 1 and 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors reviewed the licensees reactor coolant system chemistry sample

analyses for the period of April 1, 2016, through March 31, 2017, to verify the accuracy

and completeness of the reported data. The inspectors used definitions and guidance

contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment

26

Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported

data.

These activities constituted verification of the reactor coolant system specific activity

performance indicator for units 1 and 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Reactor Coolant System Total Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system total leakage

for the period of April 1, 2016, through March 31, 2017, to verify the accuracy and

completeness of the reported data. The inspectors used definitions and guidance

contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported

data.

These activities constituted verification of the reactor coolant system leakage

performance indicator for units 1 and 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.4 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors verified that there were no unplanned exposures or losses of radiological

control over locked high radiation areas and very high radiation areas during the period

of June 1, 2016, to March 31, 2017. The inspectors reviewed a sample of radiologically

controlled area exit transactions showing exposures greater than 100 mrem. The

inspectors used definitions and guidance contained in Nuclear Energy Institute

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7,

to determine the accuracy of the reported data.

These activities constituted verification of the occupational exposure control

effectiveness performance indicator as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

27

.5 Radiological Effluent Technical Specifications (RETS)/Offsite Dose Calculation Manual

(ODCM) Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed corrective action program records for liquid or gaseous effluent

releases that occurred between June 1, 2016, and March 31, 2017, and were reported to

the NRC to verify the performance indicator data. The inspectors used definitions and

guidance contained in Nuclear Energy Institute Document 99-02, Regulatory

Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of

the reported data.

These activities constituted verification of the RETS/ODCM radiological effluent

occurrences performance indicator as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution (71152)

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items

entered into the licensees corrective action program and periodically attended the

licensees condition report screening meetings. The inspectors verified that licensee

personnel were identifying problems at an appropriate threshold and entering these

problems into the corrective action program for resolution. The inspectors verified that

the licensee developed and implemented corrective actions commensurate with the

significance of the problems identified. The inspectors also reviewed the licensees

problem identification and resolution activities during the performance of the other

inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected one issue for an in-depth follow-up:

  • The inspectors reviewed the licensees corrective action program and associated

documents to identify trends that could indicate the existence of a more

significant safety issue. The inspectors focused on an issue associated with

ambient air temperature limits for starting the stations risk significant alternate

power diesel generators documented in Condition Reports CR-2016-001817 and

CR-2017-002072. The inspectors assessed the licensees problem identification

28

threshold, cause analyses, extent of condition reviews and compensatory

actions. The inspectors verified that the licensee appropriately prioritized the

planned corrective actions and that these actions were adequate to correct the

condition.

These activities constituted completion of one annual follow-up sample as defined in

Inspection Procedure 71152.

b. Findings

No findings were identified.

4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)

.1 (Closed) Licensee Event Report 05000445/2016-001-01, Unanalyzed Condition

Involving Potential Moderate Energy Line Break

a. Inspection Scope

On September 13, 2016, based on initial observations by NRC inspectors, the licensee

determined that pressurized fire protection piping in the service water intake structure

was not properly shielded for moderate energy line break protection of service water

components which resulted in inoperability of one train of service water for both Unit 1

and Unit 2.

During extent of condition walk downs conducted on October 6, 2016, October 10, 2016,

November 17, 2016, December 5, 2016, and December 22, 2016, additional piping in

the Unit 1 and Unit 2 safeguards and auxiliary buildings was found to not be shielded

correctly as well, resulting in inoperability of one train of various safety related equipment

for both units. The licensee determined the most likely cause of this event was that the

methodology used to conduct the initial moderate energy line break walk downs was

flawed and allowed some threats to be missed. The licensees corrective actions include

shielding the affected piping, performing a 100 percent walk down of rooms containing

moderate energy line break piping identified for shielding, and revising the systems

interaction program maintenance procedure.

These activities constituted completion of one event follow-up sample, as defined in

Inspection Procedure 71153.

b. Findings

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

Appendix B, Criterion III, Design Control, associated with the licensees failure to

assure that applicable regulatory requirements and the design bases, as defined in 10

CFR 50.2 and as specified in the license application, for those structure, systems and

components to which this appendix applies, were correctly translated into specifications,

drawings, procedures, and instructions. Specifically, from initial construction through

March 2017, the licensee failed to fully incorporate applicable design requirements for

components needed to ensure the capability to shut down the reactor and maintain it in

a safe shutdown condition following a moderate energy line break.

29

Description. On September 13, 2016, inspectors performed walkdowns in the service

water intake structure and identified a vertical run of unshielded, pressurized fire

protection piping that appeared to pose a moderate energy line break threat to the

service water pumps. Inspectors determined that in the event of a moderate energy line

break crack along any portion of the unshielded piping, the resultant spray had the

potential to impact the function of any one of the four service water pumps. However,

only one train would have been affected during the event due to the physical

configuration/separation relative to the source line and target pumps and/or associated

motor control centers that support pump operation. Inspectors informed the licensee of

their concern.

Engineering personnel performed a subsequent walkdown of the intake structure and

determined that the identified piping was not correctly shielded and operability of the

service water pumps was in question. The licensee took immediate action to isolate and

depressurize the fire protection line in question which addressed the operability concern.

The licensee entered this issue into the station corrective action program as Condition

Report CR-2016-008147 for resolution.

Part of the licensees actions was to perform extent of condition walkdowns for

unshielded moderate energy piping in the safeguards building for Unit 1 and 2. During

the extent of condition walk downs conducted on October 6, 2016, October 10, 2016,

November 17, 2016, December 5, 2016, and December 22, 2016, additional piping in

the Unit 1 and Unit 2 safeguards and auxiliary buildings was found to not be

appropriately shielded against a moderate energy line break, resulting in the inoperability

of various safety related equipment for both units.

  • Unit 2 Train B 480 VAC motor control center 2EB2-1 (Unit 2 Train B emergency

core cooling, battery charger, containment spray, and containment isolation valve

equipment)

  • Unit 1 Train B 480V MCC 1EB4-2, and Unit 1 Train B Distribution Panel 1ED2-2

(Unit 1 Train B safety-related pumps, panels, sequencer, and transformers)

  • Unit 1 Train B 480V MCC 1 EB4-1 (Unit 1 Train B safety-related pumps, valves,

fans, battery chargers, and transformers)

  • Unit 2 Train B 480V MCC 2E134-1 (Unit 2 Train B safety-related pumps, valves,

fans, battery chargers, and transformer)

  • Unit 1, Train B 480V MCC 1E84-1 (Unit 1 Train B safety-related pumps, valves,

fans, battery chargers, and transformers)

In each of these instances the licensee took prompt action to isolate and depressurize

the identified moderate energy piping pending modification. The licensee subsequently

determined that the most probable cause of the issue was the use of a flawed

methodology during the initial moderate energy piping walkdowns conducted in 1989.

The licensee reported this issue to NRC in Event Report 52239, and Licensee Event

Report 16-002-00.

30

Analyses. The failure to incorporate applicable design requirements into specifications

for moderate energy line break protection was a performance deficiency. The

performance deficiency was more than minor, and therefore a finding, because it was

associated with the design control attribute of the Mitigating Systems cornerstone and

affected the cornerstone objective to ensure the availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences.

Specifically, from initial construction through March 2017, the licensee failed to fully

incorporate applicable design requirements for components needed to ensure the

capability to shut down the reactor and maintain it in a safe shutdown condition following

a moderate energy line break. Using Inspection Manual Chapter 0609, Attachment 04,

Initial Characterization of Findings, dated July 1, 2012, and Inspection Manual

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

Exhibit 2, Mitigating Systems Screening Questions, dated October 7, 2016, the

inspectors determined the finding required a detailed risk evaluation because the finding

involved a deficiency affecting the design and qualification of a mitigating structure,

system, or component, and resulted in a loss of operability, and represented an actual

loss of function of at least a single train for longer than its allowed outage time. A senior

reactor analysts from Region IV performed a detailed risk evaluation and determined

that the bounding increase in core damage frequency for this issue was 5.1E-8/year for

Unit 1 and 2.9E-10/year for Unit 2, and was therefore of very low safety significance

(Green). Additional information is included in the detailed risk evaluation in

Attachment 3 of this report. The inspectors did not assign a cross-cutting aspect

because the performance deficiency was not reflective of present performance.

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in

part, that, measures shall be established to assure that applicable regulatory

requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the

license application, for those structures, systems, and components to which this

appendix applies, are correctly translated into specifications, drawings, procedures, and

instructions. Contrary to the above, measures established by the licensee did not

assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those structures, systems, and

components to which this appendix applies, were correctly translated into specifications,

drawings, procedures, and instructions. Specifically, from initial construction through

March 2017, the licensee failed to fully incorporate applicable design requirements for

components needed to ensure the capability to shut down the reactor and maintain it in

a safe shutdown condition following a moderate energy line break. This issue does not

represent an immediate safety concern because when the lines were identified the

licensee took prompt action to isolate and depressurize them, and the licensee has

implemented plant modifications. Since this violation was of very low safety significance

(Green) and has been entered into the corrective action program as Condition Report

CR-2016-008147, this violation is being treated as a non-cited violation consistent with

Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000445/2017002-05;

05000446/2017002-05, Failure to Translate Design Requirements Into the As Built

Facility)

31

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 14, 2017, the inspectors presented the radiation safety inspection results to

Mr. T. McCool, Site Vice President, and other members of the licensee staff. The licensee

acknowledged the issues presented. The licensee confirmed that any proprietary information

reviewed by the inspectors had been returned or destroyed.

On April 21, 2017, the inspector presented the inservice inspection activities inspection results

to Mr. S. Sewell, Director of Engineering and Regulatory Affairs, and other members of the

licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that

any proprietary information reviewed by the inspector had been returned or destroyed.

On May 4, 2017, the inspectors presented the licensed operator requalification program

inspection results to Mr. J. Ruby, Exam Lead, Licensed Operator Requalification Training, and

other members of the licensee staff. The licensee representatives acknowledged the findings

presented. The inspectors asked the licensee whether any materials examined during the

inspection should be considered proprietary. No proprietary information was identified.

On March 27, 2017, the inspectors presented the resident inspector quarterly inspection results

to Mr. K. Peters, Senior Vice President and Chief Nuclear Officer, and other members of the

licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that

any proprietary information reviewed by the inspectors had been returned or destroyed.

32

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Barnette, Consultant, Licensing Technologist

A. Birdett, Engineer, Steam Generator

S. Dixon, Consulting License Analyst, Regulatory Affairs

J. Goodrich, Supervisor, Radiation Protection.

J. Gumnick, Manager, Radiation Protection

R. Knapp, Supervisor, Radiation Protection

T. Hope, Manager, Regulatory Affairs

J. Howard, Engineering, Inservice Inspection

T. McCool, Site Vice President

E. McGurk, Supervisor, Radiation Protection

K. Peters, Senior Vice President and Chief Nuclear Officer

J. Ruby, Exam Lead, Licensed Operator Requalification Training

S. Sewell, Director, Engineering and Regulatory Affairs

J. Taylor, Director, Site Engineering

C. Tran, Manager, Engineering Programs

G. Woods, Supervisor, Radiation Protection

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000445/2017002-01 Failure to Control Transient Combustible Material in Accordance

NCV 05000446/2017002-01 with a Fire Protection Procedure (Section 1R05)

Inadequate Operability Evaluation for Safety-related Pipe

05000446/2017002-02 NCV

Supports (Section 1R08)05000445/2017002-03

NCV Relays not Environmentally Qualified (Section 1R12)05000446/2017002-03

05000445/2017002-04 Failure to Adequately Assess Risk and Implement Risk

NCV 05000446/2017002-04 Management Actions for Proposed Maintenance (Section 1R13)05000445/2017002-05 Failure to Translate Design Requirements Into the As Built Facility

NCV 05000446/2017002-05 (Section 4OA3)

Closed

05000445-2016-001- Unanalyzed Condition Involving Potential Moderate Energy Line

LER

01 Break (Section 4OA3)

Attachment 1

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

Procedures

Number Title Revision

STA-634 Extreme Temperature Equipment Protection Program 6

Section 1R04: Equipment Alignment

Miscellaneous Documents

Number Title

Guarded Equipment Management Sign Posting Log

Section 1R05: Fire Protection

Calculations

Number Title Revision

0210-063-0043 Maximum Permissible Fire Loading/Non-Rated Features 14

Analysis

Condition Reports

CR-2017-003925 CR-2014-010224 CR-2016-004166 CR-2016-004167

Procedures

Number Title Revision

FPI-403 Fire Preplan Instruction Manual 5

STA-729 Control of Transient Combustibles, Ignition Sources and Fire 11

Watches

Miscellaneous Documents

Number Title

DBD-ME-002

Section 1R08: Inservice Inspection Activities

Procedures

Number Title Revision/

Date

SG-SGMP-17-8 Comanche Peak 2RF16 (April 2017) Steam Generator 0

Degradation Assessment

A1-2

Procedures

Number Title Revision/

Date

STI-422.01 Operability Determination and Functionality Assessment 4

Program

SG-CDME-08-28 Steam Generator Condition Monitoring and Operational July 17,

Assessment for Comanche Peak Unit 2, April 2008 (2RF10) 2008

MRS-SSP-3393 Eddy Current Data Analysis Guidelines for Comanche Peak 0

Unit 2 D5 steam generators

STA-737 Boric Acid Corrosion Detection and Evaluation 8

MRS-TRC-2317 Use of Appendix H and I Qualified Techniques at Comanche 0

Peak 2RF16 Steam Generator Inspection

SG-SGMP-14-9 Steam Generator Condition Monitoring and Operational 0

Assessment for Comanche Peak Unit 2, April 2014 Outage

(2RF14)

WDI-PJF- Reactor Vessel Head Examination Final Report April 2017 0

1316984-FSR-

001

DBD-CS-018 Design Criteria for Pipe Stress and Pipe Supports 11

WDI-SSP-1326 Reactor Vessel Head Penetration Inspection Service 0

Procedure for Comanche Peak Unit 2

WDI-STD-1040 Procedure for Ultrasonic Examination of Reactor Vessel 14

Head Penetrations

TX-ISI-302 Ultrasonic Examination of Austenitic Piping Welds 5

TX-ISI-210 Ultrasonic Examination Procedure of Welds in Ferritic Steel 9

Vessel

TX-ISI-8 VT-1 and VT-3 Visual Examination Procedure 9

CPES-P-1079 Specification Field Fabrication and Erection of Pipe 11

Supports

Reactor Vessel Closure Head Visual Examination 5

Drawings

Number Title Revision

MS-2-001-402- Large Bore Piping Support CP-4

C72S

BRHL-SW-1-AB- Station Service Water CP-5

001

BRP-SW-1-AB- Station Service Water CP-1

001

A1-3

Condition Reports

CR-2017-005066 CR-2017-005109 CR-2017-005222 CR-2016-004050 CR-2016-003811

CR-2016-005566 CR-2016-005600 CR-2016-007429 CR-2015-008795 CR-2015-009112

CR-2015-009115 CR-2015-009180 CR-2015-009181 CR-2015-009272

Work Orders

5264718 5171029 5268838

Section 1R11: Licensed Operator Requalification Program and Licensed Operator

Performance

Miscellaneous Documents

Number/Type Title Date

Written Exams 2017 Exam -Weeks 1-6 April 2017

Sample Plans 2017 Exam -Weeks 1-6 April 2017

ES-601-1 NRC Exam Security Agreement Form March 2017

Condition Reports

IR-2017-003933 TR-2017-003859 TR-2017-002923 TR-2017-001656

TR-2017-000548 TR-2016-010799 TR-2016-000851 TR-2017-001568

Section 1R12: Maintenance Effectiveness

Miscellaneous Documents

Number Title Revision/

Date

Technical Evaluation 94-00367-00-00 March 17,

1994

CJ7239-1 Dedication Plan for Fisher Volume Booster Fischer (CW) 1

P/N CW2625-12-HT

Q1717.0 Nuclear Environmental Test Procedure for Fischer Volume 1

Booster

Condition Reports

CR-2017-004594 CR-2005-000085 CR-2005-003263

A1-4

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Condition Reports

CR-2017-006354 CR-2014-004903 CR-2011-010090 CR-2009-008296

Drawings

Number Title Revision

M2-0249 Flow Diagram Generator Primary Water 18

Miscellaneous Documents

Number Title

EV-IR-2017- Unit 2 ODMI for Primary Water Pump 5 line to vent line

006354-1 weld crack

EV-IR-2017- Evaluation to install temporary tieback support for Primary

006354-2 Water

EV-IR-2017- Maximum crack size before shutdown

006354-3

Work Orders

5444458

Section 1R15: Operability Determinations and Functionality Assessments

Drawings

Number

E2-0064 S2-0910-2-8010A

Procedures

Number Title Revision

OPT-214A Diesel Generator operability test 22

STI-422.01 Operability determinations and functionality assessment 2

program

STA-707 10CFR50.59 and 10CFR72.48 reviews 21

MSM-C0-3346 Emergency Diesel Engine Turbocharger Maintenance 6

INC-214 Installation of electrical conductor seal assemblies 0

A1-5

Miscellaneous Documents

Number Title Revision/

Date

59SC-2017- 50.59 Screening - EDG G90 Elliot Turbocharger - Thin Wall April 17,

000057-01-00 Turbine Casing 2017

VDRT-5427168 Diesel Generator Turbocharger Casing Minimal Wall April 19,

Thickness 2017

EVAL-2005- Evaluation of EDG 2-01 Turbocharger wall thinning April 7, 2005

001433-01-00

VL-04-000971 Vendor Letter - G90 Elliot Turbocharger Thin Wall Turbine April 6, 2004

Case

FDA-2017- U1/U2 Generic use-as-is disposition to address EDG 0

000057-01 Turbocharger wall thinning

Work Orders

5174039 5429766

Section 1R19: Post-Maintenance Testing

Calculations

Number Title Revision

ME-CA- Residual Heat Removal design performance limit for 0

00005476 Inservice Testing

Condition Reports

CR-2017-005384

Procedures

Number Title Revision

OPT-203B Residual Heat Removal System 14

OPT-206B AFW System 22

Miscellaneous Documents

Number Title Date

EV-CR-2017- RHR pump comprehensive pump test flow band evaluation April 21,

005384-1 2017

Work Orders

5171407

A1-6

Section 1R20: Refueling and Other Outage Activities

Condition Reports

CR-2017-004725 CR-2017-004789 CR-2017-004811

Procedures

Number Title Revision

OPT-203B Residual Heat Removal System 14

IPO-002B Plant Startup from Hot Standby 10

NUC-301 Low power physics testing 21

Work Orders

5174286

Section 1R22: Surveillance Testing

Procedures

Number Title Revision

STA-601 Authority for Equipment Operation 17

Section 2RS1: Radiological Hazard Assessment and Exposure Controls

Procedures

Number Title Revision

RPI-115 Alarm Response 9

RPI-212 Radioactive Source Control 13

RPI-213 Survey and Release of Material and Personnel 26

RPI-400 Decontamination Program 21

RPI-509 Personnel Dosimetry Program 16

RPI-602 Radiological Surveillance and Posting 58

RPI-606 Radiation Work and General Access Permits 37

RPI-623 Radiological Briefings 10

RPI-626 Alpha Monitoring Program 8

RPI-700 Sealed Source Leak Testing 13

RPI-802 Performance of Source Checks 23

STA-650 General Health Physics Plan 8

STA-655 Exposure Monitoring Program 22

A1-7

Procedures

Number Title Revision

STA-656 Radiation Work Control 22

STA-660 Control of High Radiation Areas 17

Audits and Self-Assessments

Number Title Date

CR-2016- CPNPP Strategic Self-Assessment Report October

005928 16, 2016

CR-2016- CPNPP Targeted Self-Assessment Report September

005929 15, 2016

Condition Reports

CR-2016-003921 CR-2016-004059 CR-2016-004387 CR-2016-004390 CR-2016-004806

CR-2016-004879 CR-2016-005048 CR-2016-006813 CR-2016-006813 CR-2017-000761

CR-2017-004224 CR-2017-004307 CR-2017-004787

Radiation Work Permits

Number Title Revision

20172100 2RF16 RP Support in Containment 0

20172214 2RF16 Reactor Vessel Annulus BMI, Seal Table Activities, 0

Eddy Current Testing and Containment Close-Out

20172300 2RF16 Secondary Side Steam Generator Activities 0

20172400 2RF16 Primary Side Steam Generator Activities 1

20172600 2RF16 Westinghouse (WEC) Refueling Activities 2

Radiation Surveys

Number Title Date

U-2 RB 825 S/G Platform #s 1, 2, & 3 April 13, 2017

U-2 RB 825 S/G Channel Head Survey Points (EPRI) April 13, 2017

Generator #s 1, 2, 3, & 4.

M-20161101-10 U-2 RB 808 All Rooms 2-154 November 1,

Quarterly Comprehensive 2016

M-20170125-11 U-2 RB 808 All Rooms 2-154 January 25,

Quarterly Comprehensive 2017

M-20170215-17 Aux 842 Valve & Pipe Gallery X-230 February 15,

Trending Routine 2017

M-20170225-1 Aux 832 Piping Area X-213 February 25,

Bi-Weekly 2017

A1-8

Procedures

Number Title Revision

M-20170329-13 Aux 832 Piping Area X-213 March 29, 2017

Post Resin Transfer Flush Survey

M-20170330-19 Aux 842 Valve & Pipe Gallery X-230 March 30, 2017

Post 24 Hour Resin Transfer

Air Sampling Results

Number Title Date

12-Apr-2017- U2 Equipment Hatch 832 April 12, 2017

0005

12-Apr-2017- Unit 2 LTDN HX A/S April 12, 2017

0037

13-Apr-2017- Platform 1 Iodine April 13, 2017

0006

13-Apr-2017- Platform 1 Particulate April 13, 2017

0007

Section 2RS3: In-plant Airborne Radioactivity Control and Mitigation

Procedures

Number Title Revision

ODA-102 Conduct of Operations 27

RPI-888 Calibration of Air Sampling Equipment 4

RPI-902 Issue and Control of Respiratory Protection 17

RPI-903 Cleaning, Decontamination, & Disinfecting of Respiratory 14

Protection Equipment

RPI-904 Accountability & Inspection of Respiratory Protection 13

Equipment (Maintenance & Repair)

SOP-817A Safeguards Ventilation Systems 10

SOP-816 Primary Plant Ventilation Systems 13

SOP-801A Containment Ventilation 14

SOP-802 Control Room Ventilation 13

STA-659 Respiratory Protection Program 17

STI-659.1 Use of Respiratory Protection 0

STI-704.1 Processing Respiratory Health Screens 1

STA-704 Respiratory Health Screen Program 17

A1-9

Procedures

Number Title Revision

TRA-103 Respiratory Protection Training 11

Audits and Self-Assessments

Number Title Date

CR-2016- CPNPP Strategic Self-Assessment Report October 16,

005928 2016

CR-2016- CPNPP Targeted Self-Assessment Report September 15,

005929 2016

AI-TR-2017- 1 CRE habitability targeted self-assessment January 27,

000435 2017

Condition Reports

CR-2016-007561 CR-2016-010369 CR-2016-008843 CR-2016-002439 CR-2017-001125

CR-2016-006015

Miscellaneous Documents

Title Date

SCBA Qualification Records March 31, 2017

SCBA Qualification Records Ops & Fire Brigade March 13, 2017

SCBA Inspection Records December 16,

2016

SCBA Inspection Records October 15, 2016

CPNPP Respirator Model Types March 13, 2017

Section 4OA2: Problem Identification and Resolution

Condition Reports

CR-2016-001817 CR-2017-002072

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

Condition Reports

CR-2016-008147

A1-10

The following items are requested for the

Occupational Radiation Safety Inspection

Comanche Peak Nuclear Power Plant

Inspection Dates April 10 - 17, 2017

Integrated Report 2017002

Inspection areas are listed in the attachments below.

Please provide the requested information on or before April 3, 2017.

Please submit this information using the same lettering system as below. For example, all

contacts and phone numbers for Inspection Procedure 71124.01 should be in a file/folder titled

1- A, applicable organization charts in file/folder 1- B, etc.

If information is placed on ims.certrec.com, please ensure the inspection exit date entered is at

least 30 days later than the onsite inspection dates, so the inspectors will have access to the

information while writing the report.

In addition to the corrective action document lists provided for each inspection procedure listed

below, please provide updated lists of corrective action documents at the entrance meeting.

The dates for these lists should range from the end dates of the original lists to the day of the

entrance meeting.

If more than one inspection procedure is to be conducted and the information requests appear

to be redundant, there is no need to provide duplicate copies. Enter a note explaining in which

file the information can be found.

If you have any questions or comments, please contact Louis C. Carson II at (817) 200-1221

or Louis.Carson@nrc.gov.

PAPERWORK REDUCTION ACT STATEMENT

This letter does not contain new or amended information collection requirements subject

to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). Existing information

collection requirements were approved by the Office of Management and Budget,

control number 3150-0011.

Attachment 2

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

Performance Indicator Verification (71151)

Date of Last Inspection: May 13, 2016

A. List of contacts and telephone numbers for the Radiation Protection Organization Staff

and Technicians

B. Applicable organization charts

C. ALL radiation protection related licensee assessments and audits, all independent or

third party radiation protection related assessments and audits, all radiation protection

related self-assessments, and all radiation safety related LERs, including but not limited

to radiation monitoring instrumentation and radioactive effluents, releases and / or spills,

written since May 2016.

D. Procedure indexes for the radiation protection procedures

E. Please provide specific procedures related to the following areas noted below.

Additional Specific Procedures may be requested by number after the inspector reviews

the procedure indexes.

1. Radiation Protection Program Description

2. Radiation Protection Conduct of Operations

3. Personnel Dosimetry Program

4. Posting of Radiological Areas

5. High Radiation Area Controls

6. RCA Access Controls and Radiation Worker Instructions

7. Conduct of Radiological Surveys

8. Radioactive Source Inventory and Control

9. Declared Pregnant Worker Program

F. List of corrective action documents (including corporate and sub-tiered systems) since

May 2016.

a. Initiated by the radiation protection organization

b. Assigned to the radiation protection organization

NOTE: The lists should indicate the significance level of each issue and the search

criteria used. Please provide in document formats which are searchable so that

the inspector can perform word searches.

If not covered above, a summary of corrective action documents since May 2016

involving unmonitored releases, unplanned releases, or releases in which any dose limit

or administrative dose limit was exceeded (for Public Radiation Safety Performance

Indicator verification in accordance with IP 71151)

Additionally, a copy of ALL radiation protection AND chemistry department root cause

evaluations, apparent cause evaluation, and condition evaluations performed since May

2016.

G. List of radiologically significant work activities scheduled to be conducted during the

inspection period (If the inspection is scheduled during an outage, please also include a

list of work activities greater than 1 rem, scheduled during the outage with the dose

estimate for the work activity.)

H. List of active radiation work permits

A2-2

I. Radioactive source inventory list

a. All radioactive sources that are required to be leak tested

b. All radioactive sources that meet the 10 CFR Part 20, Appendix E, Category 2

and above threshold. Please indicate the radioisotope, initial and current activity

(w/assay date), and storage location for each applicable source.

J. The last two leak test results for the radioactive sources inventoried and required to be

leak tested. If applicable, specifically provide a list of all radioactive source(s) that have

failed its leak test within the last two years

K. A current listing of any non-fuel items stored within your pools, and if available, their

appropriate dose rates (Contact / @ 30cm)

L. Computer printout of radiological controlled area entries greater than 100 millirem since

the previous inspection to the current inspection entrance date. The printout should

include the date of entry, some form of worker identification, the radiation work permit

used by the worker, dose accrued by the worker, and the electronic dosimeter dose

alarm set-point used during the entry (for Occupational Radiation Safety Performance

Indicator verification in accordance with IP 71151).

3. In-Plant Airborne Radioactivity Control and Mitigation (71124.03)

Date of Last Inspection: October 2015

A. List of contacts and telephone numbers for the following areas:

1. Respiratory Protection Program

2. Self-contained breathing apparatus

B. Applicable organization charts

C. Copies of audits, self-assessments, vendor or NUPIC audits for contractor support

(SCBA), and LERs, written since date of last inspection related to:

1. Installed air filtration systems

2. Self-contained breathing apparatuses

D. Procedure index for:

1. Use and operation of continuous air monitors

2. Use and operation of temporary air filtration units

3. Respiratory protection

E. Please provide specific procedures related to the following areas noted below.

Additional Specific Procedures may be requested by number after the inspector reviews

the procedure indexes.

1. Respiratory protection program

2. Use of self-contained breathing apparatuses

3. Air quality testing for SCBAs

4. Use of installed plant systems, such as containment purge, spent fuel pool

ventilation, and auxiliary building ventilation

F. A summary list of corrective action documents (including corporate and sub-tiered

systems) written since date of last inspection, related to the Airborne Monitoring program

including since October 2015

A2-3

1. Continuous air monitors

2. Self-contained breathing apparatuses

3. Respiratory protection program

NOTE: The lists should indicate the significance level of each issue and the search

criteria used. Please provide in document formats which are searchable so that

the inspector can perform word searches.

G. List of SCBA qualified personnel - reactor operators and emergency response personnel

H. Inspection records for self-contained breathing apparatuses (SCBAs) staged in the plant

for use since date of last inspection: October 2015

I. SCBA training and qualification records for control room operators, shift supervisors,

STAs, and OSC personnel for the last year.

A selection of personnel may be asked to demonstrate proficiency in donning, doffing,

and performance of functionality check for respiratory devices

J. List of respirators (available for use) by type (APR, SCBA, PAPR, etc.), manufacturer,

and model.

A2-4

PAPERWORK REDUCTION ACT STATEMENT

This letter does not contain new or amended information collection requirements subject to

the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). Existing information

collection requirements were approved by the Office of Management and Budget, Control

Number 31500011. The NRC may not conduct or sponsor, and a person is not required to

respond to, a request for information or an information collection requirement unless the

requesting document displays a currently valid Office of Management and Budget control

number.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter

and its enclosure will be available electronically for public inspection in the NRC Public

Document Room or from the Publicly Available Records (PARS) component of NRCs

document system (ADAMS). ADAMS is accessible from the NRC web site at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Information Request

February 24, 2017

Notification of Inspection and Request for Information

Comanche Peak Unit 2

NRC Inspection Report 05000446/2017002

INSERVICE INSPECTION DOCUMENT REQUEST

Inspection Dates: April 10 - 21, 2017

Inspection Procedures: IP 71111.08 Inservice Inspection (ISI) Activities

Inspector: Isaac Anchondo

A. Information Requested for the In-Office Preparation Week

The following information should be sent to the Region IV office in hard copy or electronic

format (ims.certrec.com preferred), in care of Isaac Anchondo, by March 17, 2017, to facilitate

the selection of specific items that will be reviewed during the onsite inspection week. The

inspector will select specific items from the information requested below and then request from

your staff additional documents needed during the onsite inspection week (Section B of this

enclosure). We ask that the specific items selected from the lists be available and ready for

review on the first day of inspection. Please provide requested documentation electronically if

possible. If requested documents are large and only hard copy formats are available, please

inform the inspector(s), and provide subject documentation during the first day of the onsite

inspection.

If you have any questions regarding this information request, please call the inspector as soon

as possible.

Based on the current schedule, on April 10, 2017, reactor inspector from the Nuclear Regulatory

Commissions (NRC) Region IV office will perform the baseline inservice inspection at

Comanche Peak, Unit 2, using NRC Inspection Procedure 71111.08, Inservice Inspection

A2-5

Activities. Experience has shown that this inspection is a resource intensive inspection both for

the NRC inspector and your staff. The date of this inspection may change dependent on the

outage schedule you provide. In order to minimize the impact to your onsite resources and to

ensure a productive inspection, we have enclosed a request for documents needed for this

inspection. These documents have been divided into two groups. The first group (Section A of

the enclosure) identified information to be provided prior to the inspection to ensure that the

inspector are adequately prepared. The second group (Section B of the enclosure) identifies

the information the inspector will need upon arrival at the site. It is important that all of these

documents are up to date and complete in order to minimize the number of additional

documents requested during the preparation and/or the onsite portions of the inspection.

We have discussed the schedule for these inspection activities with your staff and understand

that our regulatory contact for this inspection will be Mr. James Barnette of your licensing

organization. The tentative inspection schedule is as follows:

Preparation week: April 3, 2017

Onsite weeks: April 10 - 21, 2017

Our inspection dates are subject to change based on your updated schedule of outage

activities. If there are any questions about this inspection or the material requested, please

contact the lead inspector Isaac Anchondo at (817) 200-1152 (isaac.anchondo@nrc.gov).

A.1 ISI/Welding Programs and Schedule Information

a) A detailed schedule (including preliminary dates) of:

i. Nondestructive examinations planned for ASME Code Class Components

performed as part of your ASME Section XI, risk informed (if applicable),

and augmented inservice inspection programs during the upcoming outage.

ii. Examinations planned for Alloy 82/182/600 components that are not

included in the Section XI scope (If applicable)

iii. Examinations planned as part of your boric acid corrosion control program

(Mode 3 walkdowns, bolted connection walkdowns, etc.)

iv. Welding activities that are scheduled to be completed during the upcoming

outage (ASME Class 1, 2, or 3 structures, systems, or components)

b) A copy of ASME Section XI Code Relief Requests and associated NRC safety

evaluations applicable to the examinations identified above.

i. A list of ASME Code Cases currently being used to include the system

and/or component the Code Case is being applied to.

c) A list of nondestructive examination reports which have identified recordable or

rejectable indications on any ASME Code Class components since the beginning of

the last refueling outage. This should include the previousSection XI pressure test(s)

conducted during start up and any evaluations associated with the results of the

pressure tests.

A2-6

d) A list including a brief description (e.g., system, code class, weld category,

nondestructive examination performed) associated with the repair/replacement

activities of any ASME Code Class component since the beginning of the last outage

and/or planned this refueling outage.

e) If reactor vessel weld examinations required by the ASME Code are scheduled to

occur during the upcoming outage, provide a detailed description of the welds to be

examined and the extent of the planned examination. Please also provide reference

numbers for applicable procedures that will be used to conduct these examinations.

f) Copy of any 10 CFR Part 21 reports applicable to structures, systems, or components

within the scope of Section XI of the ASME Code that have been identified since the

beginning of the last refueling outage.

g) A list of any temporary noncode repairs in service (e.g., pinhole leaks).

h) Please provide copies of the most recent self-assessments for the inservice

inspection, welding, and Alloy 600 programs

A.2 Reactor Pressure Vessel Head

Provide a detailed scope of the planned bare metal visual examinations (e.g., volume

coverage, limitations, etc.) of the vessel upper head penetrations and/or any nonvisual

nondestructive examination of the reactor vessel head including the examination

procedures to be used.

i. Provide the records recording the extent of inspection for each penetration

nozzle including documents which resolved interference or masking issues

that confirm that the extent of examination meets 10 CFR

50.55a(g)(6)(ii)(D).

ii. Provide records that demonstrate that a volumetric or surface leakage path

examination assessment was performed.

Copy of current calculations for EDY, and RIY as defined in Code Case N-729-1 that establish

the volumetric and visual inspection frequency for the reactor vessel head and J-groove welds.

A.3 Boric Acid Corrosion Control Program

a) Copy of the procedures that govern the scope, equipment and implementation of the

inspections required to identify boric acid leakage and the procedures for boric acid

leakage/corrosion evaluation.

b) Please provide a list of leaks (including code class of the components) that have been

identified since the last refueling outage and associated corrective action

documentation. If during the last cycle, the unit was shut down, please provide

documentation of containment walkdown inspections performed as part of the boric

acid corrosion control program.

A2-7

A.4 Steam Generator Tube Inspections

a) A detailed schedule of:

i. Steam generator tube inspection, data analyses, and repair activities for

the upcoming outage (if occurring).

ii. Steam generator secondary side inspection activities for the upcoming

outage (if occurring).

b) Copy of SG history documentation given to vendors performing eddy current (ET)

testing of the SGs during the upcoming outage.

c) Copy of procedure containing screening criteria used for selecting tubes for in-situ

pressure testing and the procedure to be used for in-situ pressure testing.

d) Copy of previous outage SG tube operational assessment. Also include a copy of the

following documents as they become available:

i. Degradation assessment

ii. Condition monitoring assessment

e) Copy of the document defining the planned SG ET scope (e.g., 100 percent of

unrepaired tubes with bobbin probe and 20 percent sample of hot leg expansion

transition regions with rotating probe) and identify the scope expansion criteria, which

will be applied. Also identify and describe any deviations in this scope or expansion

criteria from the EPRI Guidelines.

f) Copy of the document describing the ET acquisition equipment to be applied including

ET probe types. Also identify the extent of planned tube examination coverage with

each probe type (e.g. rotating probe -0.080 inches, 0.115 inches pancake coils and

mid-range +point coil applied at the top-of-tube-sheet plus 3 inches to minus 12

inches).

g) Identify and quantify any SG tube leakage experienced during the previous operating

cycle. Also provide documentation identifying which SG was leaking and corrective

actions completed and planned for this condition.

h) Copy of steam generator eddy current data analyst guidelines and site validated eddy

current technique specification sheets. Additionally, please provide a copy of EPRI

Appendix H, Examination Technique Specification Sheets, qualification records.

i) Provide past history of the condition and issues pertaining to the secondary side of the

steam generators (including items such as loose parts, fouling, top of tube sheet

condition, crud removal amounts, etc.).

Indicate where the primary, secondary, and resolution analyses are scheduled to take place.

A.5 Additional Information Related to all Inservice Inspection Activities

A2-8

a) A list with a brief description of inservice inspection, and boric acid corrosion control

program related issues (e.g., Condition Reports) entered into your corrective action

program since the beginning of the last refueling outage. For example, a list based

upon data base searches using key words related to piping such as: inservice

inspection, ASME Code,Section XI, NDE, cracks, wear, thinning, leakage, rust,

corrosion, boric acid, or errors in piping examinations.

b) Provide training (e.g. Scaffolding, Fall Protection, FME, Confined Space) if they are

required for the activities described in A.1 through A.4.

c) Please provide names and phone numbers for the following program leads:

Inservice inspection (examination, planning)

Containment exams

Reactor pressure vessel head exams

Snubbers and supports

Repair and replacement program

Licensing

Site welding engineer

Boric acid corrosion control program

Steam generator inspection activities (site lead and vendor contact)

B. Information to be Provided Onsite to the Inspector(s) at the Entrance Meeting (April 6,

2017):

B.1 Inservice Inspection / Welding Programs and Schedule Information

a) Updated schedules for inservice inspection/nondestructive examination activities,

including planned welding activities, and schedule showing contingency repair plans, if

available.

b) For ASME Code Class welds selected by the inspector from the lists provided from

Section A of this enclosure, please provide copies of the following documentation for

each subject weld:

Weld data sheet (traveler).

Weld configuration and system location.

Applicable Code Edition and Addenda for weldment.

Applicable Code Edition and Addenda for welding procedures.

Applicable welding procedures used to fabricate the welds.

Copies of procedure qualification records (PQRs) supporting the weld

procedures from B.1.b.v.

Copies of welders performance qualification records (WPQ).

A2-9

Copies of the nonconformance reports for the selected welds (If

applicable).

Radiographs of the selected welds and access to equipment to allow

viewing radiographs (if radiographic testing was performed).

Copies of the preservice examination records for the selected welds.

Readily accessible copies of nondestructive examination personnel

qualifications records for reviewing.

c) For the inservice inspection related corrective action issues selected by the inspector

from Section A of this enclosure, provide a copy of the corrective actions and

supporting documentation.

d) For the nondestructive examination reports with relevant conditions on ASME Code

Class components selected by the inspector from Section A above, provide a copy of

the examination records, examiner qualification records, and associated corrective

action documents.

e) A copy of (or ready access to) most current revision of the inservice inspection

program manual and plan for the current interval.

f) For the nondestructive examinations selected by the inspector from Section A of this

enclosure, provide a copy of the nondestructive examination procedures used to

perform the examinations (including calibration and flaw characterization/sizing

procedures). For ultrasonic examination procedures qualified in accordance with

ASME Code,Section XI, Appendix VIII, provide documentation supporting the

procedure qualification (e.g. the EPRI performance demonstration qualification

summary sheets). Also, include qualification documentation of the specific equipment

to be used (e.g., ultrasonic unit, cables, and transducers including serial numbers) and

nondestructive examination personnel qualification records.

B.2 Reactor Pressure Vessel Head (RPVH)

a) Provide drawings showing the following (if performing any RPVH inspection activities):

i. RPVH and control rod drive mechanism nozzle configurations.

ii. RPVH insulation configuration.

Note: The drawings listed above should include fabrication drawings for the nozzle

attachment welds as applicable.

b) Copy of the documents which demonstrate that the procedures to be used for

volumetric examination of the reactor vessel head penetration J-groove welds were

qualified by a blind demonstration test in accordance with 10 CFR 50.55a(g)(6)(ii)(D).

c) Copy of volumetric, surface and visual examination records for the prior inspection of

the reactor vessel head and head penetration J-groove welds.

A2-10

B.3 Boric Acid Corrosion Control Program

a) Please provide boric acid walk down inspection results, an updated list of boric acid

leaks identified so far this outage, associated corrective action documentation, and

overall status of planned boric acid inspections.

b) Please provide any engineering evaluations completed for boric acid leaks identified

since the end of the last refueling outage. Please include a status of corrective actions

to repair and/or clean these boric acid leaks. Please identify specifically which known

leaks, if any, have remained in service or will remain in service as active leaks.

B.4 Steam Generator Tube Inspections

a) Copies of the Examination Technique Specification Sheets and associated justification

for any revisions.

b) Please provide a copy of the eddy current testing procedures used to perform the

steam generator tube inspections (specifically calibration and flaw

characterization/sizing procedures, etc.).

c) Copy of the guidance to be followed if a loose part or foreign material is identified in

the steam generators.

d) Identify the types of SG tube repair processes which will be implemented for defective

SG tubes (including any NRC reviews/evaluations/approvals of this repair process).

Provide the flaw depth sizing criteria to be applied for ET indications identified in the

SG tubes.

e) Copy of documents describing actions to be taken if a new SG tube degradation

mechanism is identified.

f) Provide procedures with guidance/instructions for identifying (e.g. physically locating

the tubes that require plugging) and plugging SG tubes.

g) List of corrective action documents generated by the vendor and/or site with respect to

steam generator inspection activities.

B.5 Codes and Standards

a) Ready access to (i.e., copies provided to the inspector(s) for use during the inspection

at the onsite inspection location, or room number and location where available):

i. Applicable Editions of the ASME Code (Sections V, IX, and XI) for the

inservice inspection program and the repair/replacement program.

b) Copy of the performance demonstration initiative (PDI) generic procedures with the

latest applicable revisions that support site qualified ultrasonic examinations of piping

welds and components (e.g., PDI-UT-1, PDI-UT-2, PDI-UT-3, PDI-UT-10, etc.).

Boric Acid Corrosion Guidebook Revision 1 - EPRI Technical Report 1000975.

A2-11

Comanche Peak Medium Energy Line Break Licensee Event Report

Detailed Risk Evaluation

Comanche Peak Nuclear Power Plant Licensee Event Report 16-002-01, Unanalyzed

Condition Involving Potential Moderate Energy Line Break, described six vulnerabilities in the

licensees equipment configurations for medium energy line breaks (MELB). Each of these

conditions is contained in the tables in this evaluation.

The length of piping which could cause the loss of the affected components by having a MELB

was estimated and the values are contained in the tables.

All MELBs were assumed to fail the affected components every time the piping would leak or

break. The pipe leak and/or break frequency was estimated by the use of system piping data

from the 2010 Component Reliability update for data from NUREG/CR-6928, Industry-Average

Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants.

The analyst assumed non-service water system piping and added the 2.53E-10 per hour per

foot for small leakage and 2.53E-11 per hour per foot for large leakage to estimate the MELB

hazard.

The MELB deficiencies were assumed to have existed since initial plant power operations

began. Exposure time was limited to one year per Section 2.0, Exposure Time Modeling, in the

Risk Assessment of Operational Events (RASP) Handbook.

The analyst assumed for condition number 1 in the tables below that each unit was vulnerable

to having a service water pump affected and therefore considered a loss of service water pump

for each unit in the estimate of increase in core damage frequency for each unit. The

Comanche Peak Plant Risk Information e-Book was used to determine that service water pump

1-1 was the most risk significant service pump for Unit 1; and service water pump 2-1 was the

most significant service water pump for Unit 2.

The analyst assumed for condition number 3 in the tables below that only one component could

be affected, therefore in the tables, only the most risk significant service water pump was

considered in the final estimated increase in core damage frequency.

The analyst first estimated the increase in core damage frequency due to the additional failure

probability of the components from a MELB event. The results are contained in the following

table:

Condition Number and Feet of Piping failure Nominal failure Revised Increase in core damage

Affected Component(s) piping probability probability failure frequency

probability Unit 1 Unit 2

1 Service Water Pump 1- 50 3.34E-7 1.57E-4 1.58E-4 2.44E-10 N/A

1

Service Water Pump 2- 50 3.34E-7 1.57E-4 1.58E-4 N/A 2.44E-10

1

2 Motor Control Center 5 3.34E-8 3.33E-5 3.34E-5 N/A Negligible

2EB2-1

3 Switchgear 1EA2 20 1.34E-7 3.33E-5 3.34E-5 1.32E-10 N/A

Motor Control Center 20 1.34E-7 3.33E-5 3.34E-5 Negligible N/A

1EB4-2

Distribution Panel 20 1.34E-7 6.50E-5 6.51E-5 Negligible N/A

1ED2-2

A3-1 Attachment 3

Condition Number and Feet of Piping failure Nominal failure Revised Increase in core damage

Affected Component(s) piping probability probability failure frequency

probability Unit 1 Unit 2

4 Motor Control Center 5 3.34E-8 3.33E-5 3.333E-5 1.0E-11 N/A

1EB4-1

5 Motor Control Center 5 3.34E-8 3.33E-5 3.34E-5 N/A 1.0E-11

2EB4-1

6 Motor Control Center 10 6.68E-8 3.33E-5 3.34E-5 1.0E-11 N/A

1EB4-1

Total Increase In Core Damage Frequency (per year) for each Unit 3.96E-10 2.54E-10

The analyst then estimated the increase in core damage frequency from each of the MELB

events by increasing the initiating event frequency for cases where there was a clear initiator

(e.g., loss of bus initiator, loss of service water initiator). If no initiator was modelled, the analyst

assumed the MELB caused a transient and applied the frequency of the MELB event to the

conditional core damage probability (CCDP) for a transient. The following table contains the

results:

Condition Number and Feet of Piping failure Nominal Revised Transient Increase in core damage

Affected Component(s) piping frequency initiating initiating CCDP frequency

(per year) event event Unit 1 Unit 2

frequency frequency

1 Service Water Pump 50 1.22E-4 5.74E-2 5.76E-2 N/A Negligible N/A

1-1

Service Water Pump 50 1.22E-4 5.74E-2 5.76E-2 N/A N/A Negligible

2-1

2 Motor Control 5 1.22E-5 6.90E-1 6.90E-1 9.33E-6 N/A 1.2E-10

Center 2EB2-1

3 Switchgear 1EA2* 20 4.88E-5 False 4.88E-5 N/A 4.55E-8 N/A

Motor Control 20 4.88E-5 6.90E-1 6.90E-1 5.35E-6 2.61E-10 N/A

Center 1EB4-2 (not used)

Distribution Panel 20 4.88E-5 7.37E-4 7.86E-4 N/A 3.52E-8 N/A

1ED2-2** (not used)

4 Motor Control 5 1.22E-5 6.90E-1 6.90E-1 2.22E-4 2.7E-9 N/A

Center 1EB4-1

5 Motor Control 5 1.22E-5 6.90E-1 6.90E-1 2.22E-4 N/A 2.7E-9

Center 2EB4-1

6 Motor Control 10 2.44E-5 6.90E-1 6.90E-1 2.22E-4 2.7E-9 N/A

Center 1EB4-1

Total Increase In Core Damage Frequency (per year) for each Unit 5.1E-8 2.8E-9

  • The analyst assumed that an initiator for failure of bus 1EA2 could be modeled by increasing the failure probability of bus 1EA1 to

obtain representative results because the SPAR model did not contain an initiator of loss of bus 1EA2.

    • A MELB affecting distribution panel 1ED2-2 was assumed to initiate a complete loss of DC bus 1ED2.

Adding the results of the two effects resulted in an estimated increase in core damage

frequency of 5.1E-8/year for Unit 1 and 2.9E-10/year for Unit 2. Based on these increases, the

finding was determined to be of very low safety significance (Green). The estimates were

obtained by use of Version 8.28 of the Comanche Peak SPAR model ran on SAPHIRE, Version

8.1.5. The dominant core damage sequences were losses of switchgear and losses of service

water. Offsite power and feed and bleed availability remained to mitigate the significance of

dominant initiators.

A3-2

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