ML14043A056

IR 05000275-13-005, 05000323-13-005; on 09/22/2013 - 12/31/2013; Diablo Canyon Power Plant; Follow-up of Events and Notices of Enforcement Discretion

ML14043A056
Person / Time
Site:	Diablo Canyon
Issue date:	02/11/2014
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Halpin E Pacific Gas & Electric Co
References
IR-13-005
Download: ML14043A056 (42)

See also: IR 05000275/2013005

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E. LAMAR BLVD.

ARLINGTON, TX 76011-4511

February 11, 2014

Mr. Edward D. Halpin

Senior Vice President and

Chief Nuclear Officer

Pacific Gas and Electric Company

Diablo Canyon Power Plant

P.O. Box 56, Mail Code 104/6

Avila Beach, CA 93424

SUBJECT:

DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION

REPORT 05000275/2013005 and 05000323/2013005

Dear Mr. Halpin:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Diablo Canyon Power Plant. On January 16 and February 7, 2014, the NRC

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

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

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

Two 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. The

NRC is treating this violation as a non-cited violation consistent with Section 2.3.2.a of the

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 Diablo Canyon Power Plant.

If you disagree with the cross-cutting aspects assignment or the finding not associated with a

regulatory requirement 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 Diablo Canyon 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 available electronically for public inspection in the NRCs Public

Document Room or from the Publicly Available Records (PARS) component of the NRC's

E. Halpin

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Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible

from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic

Reading Room).

Sincerely,

/RA/

Wayne C. Walker, Branch Chief

Project Branch A

Division of Reactor Projects

Docket Nos.: 05000275, 05000323

License Nos.: DPR-80, DPR-82

Enclosure:

NRC Inspection Report 05000275/2013005

and 05000323/2013005

w/ Attachment: Supplemental Information

cc w/ Enclosure: Electronic Distribution

ML14043A056

SUNSI Rev Compl.

Yes No

ADAMS

Yes No

Reviewer Initials

WCW

Publicly Avail.

Yes No

Sensitive

Yes No

Sens. Type Initials

WCW

SRI:DRP/A

RI:DRP/D

RI:DRP/F

SPE:DRP/A

C:DRS/EB1

C:DRS/EB2

TRHipschman BDParks

WCSmith

RDAlexander

TRFarnholtz

GBMiller

/RA/ via Email /RA/ via Email /RA/ via Email /RA/

/RA/

/RA/

2/10/14

2/6/14

2/6/14

2/7/14

1/29/14

2/7/14

C:DRS/OB

C:DRS/PSB1

C:DRS/PSB2

C:DRS/TSB

BC:DRP/A

VGaddy

MSHaire

HGepford

RKellar

WWalker

/RA/

/RA/

/RA/

/RA/

/RA/

2/10/14

2/10/14

2/10/14

2/10/14

2/11/14

- 1 -

Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket:

05000275; 05000323

License:

DPR-80; DPR-82

Report:

05000275/2013005; 05000323/2013005

Licensee:

Pacific Gas and Electric Company

Facility:

Diablo Canyon Power Plant, Units 1 and 2

Location:

7 1/2 miles NW of Avila Beach

Avila Beach, CA

Dates:

September 22 through December 31, 2013

Inspectors: T. Hipschman, Senior Resident Inspector

G. Guerra, Emergency Preparedness Inspector, Plant Support Branch 1

R. Kumana, Resident Inspector, Projects Branch A

J. Laughlin, Emergency Preparedness Inspector, NSIR

B. Parks, Resident Inspector

C. Smith, Resident Inspector

Approved

By:

Wayne Walker

Chief, Project Branch A

Division of Reactor Projects

- 2 -

SUMMARY

IR 05000275/2013005, 05000323/2013005; 09/22/2013 - 12/31/2013; Diablo Canyon Power

Plant; Follow-up of Events and Notices of Enforcement Discretion

The inspection activities described in this report were performed between September 22, 2013,

and December 31, 2013, by the resident inspectors at Diablo Canyon Power Plant along with

two inspectors from the NRCs Region IV office and inspectors from other NRC offices. Three

findings of very low safety significance (Green) are documented in this report. Two 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, Components Within the Cross-Cutting

Areas. Violations of NRC requirements are dispositioned in accordance with the NRCs

Enforcement Policy. The NRC's program for overseeing the safe operation of commercial

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

Cornerstone: Initiating Events

Green. The inspectors reviewed a Green self-revealing non-cited violation of

10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at

Nuclear Power Plants, for failure to implement adequate oversight controls and risk

assessment while performing 500kV transmission line insulator maintenance on Unit 2. This

caused an initiating event due to a flashover on the main transformer lightning arrester that

resulted in a reactor trip.

The failure to effectively perform a risk assessment and properly control maintenance

activities that resulted in a reactor trip was a performance deficiency. The performance

deficiency was more than minor because it was associated with the human performance

attribute of the Initiating Events cornerstone and adversely affected the cornerstone

objective to limit the likelihood of events that upset plant stability and challenged critical

safety functions during power operations, and is therefore a finding. Using Inspection

Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A,

Exhibit 1, Initiating Events Screening Questions, this finding was determined to be of very

low safety significance (Green) because, although it resulted in a reactor trip, it did not result

in the loss of mitigating equipment relied upon to transition the plant from the onset of the

trip to a stable shutdown condition. Additionally, using Inspection Manual Chapter 0612,

Appendix K, Maintenance Risk Assessment and Risk Management Significance

Determination Process, this finding was determined to be of very low safety significance

(Green). The licensee entered the condition into the corrective action program as

Notification 50572800.

This finding had a cross-cutting aspect in the area of human performance, associated with

the decision-making component, because the licensee did not demonstrate that nuclear

safety was an overriding priority during this maintenance activity. Specifically, the licensee

did not initially use conservative decision making in not properly categorizing the activity as

a reactor trip risk (despite internal and external operating experience to the contrary), and

again when the licensee did not terminate the hot washing activities when environmental

conditions degraded resulting in excessive water dispersion H.1(b). (Section 4OA3.1)

- 3 -

Green. The inspectors reviewed a Green self-revealing finding due to an inadequate

procedure for calibrating non-vital bus relays. This caused an initiating event due to a main

feed pump trip and unplanned downpower transient to 50 percent power on Unit 1.

The licensees failure to maintain an adequate maintenance procedure for calibrating non-

vital bus relays is a performance deficiency. Specifically, the procedure was inadequate in

that it contained an optional step to position a cut-out switch so that the relay would not de-

energize the bus if actuated during maintenance activities. The performance deficiency was

more than minor because, if left uncorrected, the performance deficiency had the potential

to lead to a more significant safety concern. In particular, when the bus de-energized and

tripped the running control oil pump, and the accumulator was unable to maintain system

pressure while the back-up control oil pump reached operating pressure, the main feed

pump tripped which resulted in a reactor power transient greater than 20 percent. Using

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

Appendix A, Exhibit 1, Initiating Events Screening Questions, this finding was determined

to be of very low safety significance (Green) because, although it resulted in a reactor

transient, it did not result in the loss of mitigating equipment relied upon to transition the

plant from the onset of the trip to a stable shutdown condition. This finding was entered into

the corrective action program as Notification 50588799.

This finding had a cross-cutting aspect in the area of human performance, associated with

the work control component, because the licensee did not adequately plan and coordinate

maintenance activities. Specifically, the licensee did not appropriately assess the job site

conditions that could impact human performance and human-system interface by failing to

incorporate operating experience into procedural guidance H.3(a). (Section 4OA3.2)

Cornerstone: Barrier Integrity

Green. The inspectors reviewed a Green self-revealing non-cited violation of

10 CFR Part 50, Appendix B, Criterion III, Design Control, after the licensee performed

a design change to the control room ventilation system (CRVS) that resulted in none of the

four CRVS pressurization fans being able to continuously operate if they started in response

to a Phase A containment isolation or control room radiation atmosphere intake actuation

signal. This resulted in declaring the Units 1 and 2 CRVS actuation instrumentation and

CRVS inoperable and unplanned entry into Technical Specifications (TS) 3.3.7, "Control

Room Ventilation System Actuation Instrumentation," and TS 3.7.10, "Control Room

Ventilation System," respectively.

The failure to use proper design control during the CRVS modification was a performance

deficiency. The performance deficiency was more than minor because it was associated

with the human performance attribute of the Barrier Integrity cornerstone, and it adversely

affected the cornerstone objective to provide reasonable assurance that physical design

barriers protect the public from radiological releases caused by accidents or events, and is

therefore a finding. Using Inspection Manual Chapter 0609, Attachment 04, Initial

Characterization of Findings, and Appendix A, Exhibit 3, Barrier Integrity Screening

Questions, this finding was determined to be of very low safety significance (Green)

because only the radiological barrier function of the control room was affected. The licensee

entered the condition into the corrective action program as Notification 50525605.

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The finding had a cross-cutting aspect in the area of human performance resources

component because licensee staff did not maintain complete, accurate, and up-to-date

design documentation - specifically, because the functions of the pressure switches and

CRVS interlocks had never been adequately described in design control documents H.2(c).

(Section 4OA3.3)

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been reviewed

by the inspectors. Corrective actions taken or planned by the licensee have been entered into

the licensees corrective action program. This violation and associated corrective action

tracking numbers are listed in Section 4OA7 of this report.

- 5 -

PLANT STATUS

Unit 1 began the inspection period at essentially full power. On October 14, 2013, power was

reduced to 50 percent due to an unplanned loss of a main feedwater pump. Following

corrective maintenance, the unit returned to full power on October 17, 2013. On October 28,

Unit 1 commenced a controlled power reduction to 50 percent for planned circulating water

tunnel cleaning. Unit 1 returned to full power on November 3, 2013, and remained there for the

duration of the inspection period.

Unit 2 essentially remained at full power the entire inspection period.

REPORT DETAILS

1.

REACTOR SAFETY

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

Emergency Preparedness

1R01 Adverse Weather Protection (71111.01)

.1

Readiness for Seasonal Extreme Weather Conditions

a.

Inspection Scope

On December 12 and December 20, 2013, the inspectors completed an inspection of the

stations readiness for seasonal extreme weather conditions. The inspectors reviewed

the licensees adverse weather procedures for high winds and evaluated the licensees

implementation of these procedures. The inspectors verified that prior to high winds, the

licensee had corrected weather-related equipment deficiencies identified during the

previous winter.

The inspectors selected two risk-significant systems that were required to be protected

from high winds:

500kV offsite power

Unit 2 start-up transformer

The inspectors reviewed the licensees procedures and design information to ensure the

systems and components would remain functional when challenged by adverse weather.

The inspectors verified that operator actions described in the licensees procedures were

adequate to maintain readiness of these systems.

These activities constituted one sample of readiness for seasonal adverse weather, as

defined in Inspection Procedure 71111.01.

b.

Findings

No findings were identified.

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.2

Readiness for Impending Adverse Weather Conditions

a.

Inspection Scope

On October 8, 2013, the inspectors completed an inspection of the stations readiness

for impending adverse weather conditions. The inspectors reviewed plant design

features, the licensees procedures and planned actions to respond to the seasons first

rain, and the licensees planned implementation of these procedures. The inspectors

evaluated operator staffing and accessibility of controls and indications for those

systems required to control the plant.

These activities constituted one sample of readiness for impending adverse weather

conditions, as defined in Inspection Procedure 71111.01.

b.

Findings

No findings were identified.

.3

Readiness to Cope with External Flooding

a.

Inspection Scope

On November 3, 2013, the inspectors completed an inspection of the stations readiness

to cope with external flooding. After reviewing the licensees flooding analysis, the

inspectors chose two plant areas that were susceptible to flooding:

Unit 1 auxiliary salt water rooms

Unit 2 auxiliary salt water rooms

The inspectors reviewed plant design features and licensee procedures for coping with

flooding. The inspectors walked down the selected areas to inspect the design features,

including the material condition of seals, drains, and flood barriers. The inspectors

evaluated whether credited operator actions could be successfully accomplished.

These activities constituted one sample of readiness to cope with external flooding, as

defined in Inspection Procedure 71111.01.

b.

Findings

No findings were identified.

1R04 Equipment Alignment (71111.04)

.1

Partial Walkdown

a.

Inspection Scope

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

systems:

September 24, 2013, Unit 2, emergency diesel generator 2-2

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November 3, 2013, Unit 1, auxiliary salt water system

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 were correctly aligned for the existing plant configuration.

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

Inspection Procedure 71111.04.

b.

Findings

No findings were identified.

.2

Complete Walkdown

a.

Inspection Scope

On November 22, 2013, the inspectors performed a complete system walk-down

inspection of the auxiliary feedwater pump 1-1. The inspectors reviewed the licensees

procedures and system design information to determine the correct auxiliary feedwater

lineup for the existing plant configuration. The inspectors also reviewed outstanding

work orders, open condition reports, in-process design changes, temporary

modifications, and other open items tracked by the licensees operations and

engineering departments. The inspectors then visually verified that the system was

correctly aligned for the existing plant configuration.

These activities constituted one complete system walk-down sample, 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 four plant areas

important to safety:

October 1, 2013, Unit 1 and 2, fire areas 6-A-1, 6-A-2, 6-A-3, 6-B-1, 6-B-2, 6-B-3

October 7, 2013, Unit 1, emergency diesel generator rooms 1-1, 1-2, and 1-3

October 8, 2013, Unit 2, emergency diesel generator rooms 2-1, 2-2, and 2-3

October 29, 2013, Units 1 and 2 intake structure

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

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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 four quarterly inspection samples, as defined in Inspection

Procedure 71111.05.

b.

Findings

No findings were identified.

1R06 Flood Protection Measures (71111.06)

a.

Inspection Scope

The inspectors completed an inspection of the stations ability to mitigate flooding due to

internal causes. After reviewing the licensees flooding analysis, the inspectors chose

two plant areas containing risk-significant structures, systems, and components that

were susceptible to flooding:

November 4, 2013, Units 1 and 2, auxiliary salt water pump vaults

November 6, 2013, Unit 1, component cooling water heat exchanger room 1-1

The inspectors reviewed plant design features and licensee procedures for coping with

internal flooding. The inspectors walked down the selected areas to inspect the design

features, including the material condition of seals, drains, and flood barriers. The

inspectors evaluated whether operator actions credited for flood mitigation could be

successfully accomplished.

These activities constitute completion of two flood protection measures samples as

defined in Inspection Procedure 71111.06.

b.

Findings

No findings were identified.

1R07 Heat Sink Performance (71111.07)

a.

Inspection Scope

On December 20, 2013, the inspectors completed an inspection of the readiness and

availability of risk-significant heat exchangers. The inspectors reviewed the data from a

performance test for the Unit 2 containment fan cooler units.

These activities constitute completion of one heat sink performance annual review

sample, as defined in Inspection Procedure 71111.07.

b.

Findings

No findings were identified.

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1R11 Licensed Operator Requalification Program and Licensed Operator Performance

(71111.11)

.1

Review of Licensed Operator Requalification

a.

Inspection Scope

On October 18, 2013, the inspectors observed a crew of licensed operators in the plants

simulator during requalification testing. The inspectors assessed the following areas:

Licensed operator performance

The ability of the licensee to administer the evaluations

The quality of post-scenario critiques

These activities constitute 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 October 14, 2013, and October 28, 2013, the inspectors observed the performance

of on-shift licensed operators in the plants main control room. At the time of the

observations, the plant was in a period of heightened activity due to reductions in plant

power. The inspectors observed the operators performance of the following activities:

Unit 1 post transient runback to 50 percent following the trip of main feed

pump 1-1

Unit 1 curtailment to 50 percent power for circulating water tunnel and condenser

cleaning

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

including conduct of operations procedures and other operations department policies.

These activities constitute completion of two quarterly licensed operator performance

samples, as defined in Inspection Procedure 71111.11.

b.

Findings

No findings were identified.

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1R12 Maintenance Effectiveness (71111.12)

a.

Inspection Scope

The inspectors reviewed one instance of degraded performance or condition of

safety-related structures, systems, and components (SSCs):

December 23, 2013, Units 1 and 2, plant radiation monitors

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.

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

a.

Inspection Scope

On October 10, 2013, the inspectors reviewed a risk assessment performed by the

licensee prior to a planned change in plant configuration and the risk management

actions planned by the licensee in response to elevated risk due to tracking on 230kV

transformers and the need for insulator cleaning.

The inspectors verified that this risk assessment was 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 assessment and verified that the licensee implemented appropriate risk

management actions based on the result of the assessment.

On October 11, 2013, the inspectors observed portions of emergent work activities that

had the potential to affect the functional capability of mitigating systems due to a failed

stroke time test on auxiliary feedwater valve LCV-110.

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

plan for these activities. The inspectors verified that the licensee took precautions to

minimize the impact of the work activities on unaffected structures, systems, and

components (SSCs).

These activities constitute completion of two maintenance risk assessments and

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

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b.

Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments (71111.15)

a.

Inspection Scope

The inspectors reviewed six operability determinations that the licensee performed for

degraded or nonconforming structures, systems, or components (SSCs):

October 15, 2013, operability determination of Unit 1, auxiliary feedwater

pump 1-2 after failed stroke test of LCV-110

October 17, 2013, operability determination of Unit 1 anticipated transient without

scram mitigation system actuation circuitry following testing

October 23, 2013, operability determination of Unit 1 control room Indications

after failure of a control panel transformer

October 25, 2013, operability determination of Unit 1 and Unit 2 emergency

diesel generators tornado capability

November 4, 2013, operability determination of Unit 1 condensate storage tank

piping upon the identification of corrosion

November 6, 2013 assessment of emergency diesel generator fuel oil

transformer pump 0-2

The inspectors reviewed the timeliness and technical adequacy of the licensees

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

inspectors verified that the licensees compensatory measures were appropriate to

provide reasonable assurance of operability. The inspectors verified that the licensee

had considered the effect of other degraded conditions on the operability of the

degraded SSC.

These activities constitute completion of six operability and functionality review samples,

as defined in Inspection Procedure 71111.15.

b.

Findings

No findings were identified.

1R18 Plant Modifications (71111.18)

a.

Inspection Scope

On December 5, the inspectors reviewed a permanent plant modification to the Unit 2

plant computer system.

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The inspectors reviewed the design and implementation of the modification. The

inspectors verified that work activities involved in implementing the modification did not

adversely impact operator actions that may be required in response to an emergency or

other unplanned event. The inspectors verified that post-modification testing was

adequate to establish the functionality of the structures, systems, or components as

modified.

These activities constitute completion of one sample of permanent modifications, as

defined in Inspection Procedure 71111.18.

b.

Findings

No findings were identified.

1R19 Post-Maintenance Testing (71111.19)

a.

Inspection Scope

The inspectors reviewed four post-maintenance testing activities that affected

risk-significant structures, systems, or components (SSCs):

October 2, 2013, Unit 2, emergency diesel generator 2-1

November 19, 2013 Unit 1, emergency diesel generator 1-3

December 3, 2013, Unit 2, auxiliary feedwater pump 2-2

December 23, 2013, Unit 1, emergency diesel generator 1-3

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 constitute completion of four post-maintenance testing inspection

samples, as defined in Inspection Procedure 71111.19.

b.

Findings

No findings were identified.

1R22 Surveillance Testing (71111.22)

a.

Inspection Scope

The inspectors observed four risk-significant surveillance tests and reviewed test results

to verify that these tests adequately demonstrated that the structures, systems, and

components (SSCs) were capable of performing their safety functions:

- 13 -

Inservice tests:

October 15, 2013, Stroke Test of Unit 1, auxiliary feedwater pump 1-2

valve LCV-110

November 5, 2013, surveillance test of motor driven auxiliary feedwater

pump 1-2

Other surveillance tests:

October 17, 2013, Functional Test of Unit 1 anticipated transient without scram

mitigation system actuation circuitry

December 23, 2013, Unit 1, surveillance test of emergency diesel generator 1-3

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.

These activities constitute completion of four surveillance testing inspection samples, as

defined in Inspection Procedure 71111.22.

b.

Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Testing (71114.02)

a.

Inspection Scope

The inspectors discussed with licensee staff the operability of offsite siren emergency

warning systems and backup alerting methods to determine the adequacy of licensee

methods for testing the alert and notification system in accordance with 10 CFR Part 50,

Appendix E. The licensees alert and notification system testing program was compared

with criteria in NUREG-0654, Criteria for Preparation and Evaluation of Radiological

Emergency Response Plans and Preparedness in Support of Nuclear Power Plants,

Revision 1; FEMA Report REP-10, Guide for the Evaluation of Alert and Notification

Systems for Nuclear Power Plants, and the licensees current FEMA-approved alert

and notification system design report, Alert and Notification Design Report, Revision 1.

The specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection

Procedure 71114.02.

b.

Findings

No findings were identified.

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1EP3 Emergency Response Organization Staffing and Augmentation System (71114.03)

a.

Inspection Scope

The inspectors discussed with licensee staff the operability of primary and back-up

systems for augmenting the on-shift emergency response staff to determine the

adequacy of licensee methods for staffing emergency response facilities in accordance

with the requirements of 10 CFR Part 50, Appendix E. The inspectors reviewed licensee

methods for staffing alternate emergency response facilities. The inspectors also

reviewed periodic surveillances of the augmentation system to determine the licensees

ability to staff emergency response facilities within the response times described in the

site emergency plan. The specific documents reviewed during this inspection are listed

in the attachment.

These activities constitute completion of one sample as defined in Inspection

Procedure 71114.03.

b.

Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)

a.

Inspection Scope

The Office of Nuclear Security and Incident Response (NSIR) headquarters staff

performed an in-office review of the latest revisions of various Emergency Plan

Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS

accession numbers ML13269A256 and ML13277A112 as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in

the revisions resulted in no reduction in the effectiveness of the Plan, and that the

revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to

10 CFR Part 50. The NRC review was not documented in a safety evaluation report and

did not constitute approval of licensee-generated changes; therefore, this revision is

subject to future inspection. The specific documents reviewed during this inspection are

listed in the Attachment.

These activities constitute completion of three samples as defined in Inspection

Procedure 71114.04 05.

b.

Findings

No findings were identified.

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1EP5 Maintenance of Emergency Preparedness (71114.05)

a.

Inspection Scope

The inspectors reviewed licensee records associated with maintaining the emergency

preparedness program between August 2011 and November 2013, including:

Licensee procedures

After-action reports

Quality Assurance audit and surveillance reports

Program assessments

Drill and exercise evaluation reports

Assessments of the impact of changes to the emergency plan and emergency

plan implementing procedures

Maintenance records for equipment important to emergency preparedness

The inspectors reviewed summaries of 725 corrective action program entries assigned

to the emergency preparedness department and emergency response organization and

selected 32 for detailed review against the program requirements. The inspectors

evaluated the response to the corrective action requests to determine the licensees

ability to identify, evaluate, and correct problems in accordance with the licensee

program requirements, planning standard 10 CFR 50.47(b)(14), and 10 CFR Part 50,

Appendix E.

The inspectors reviewed summaries of 103 assessments of the impact of changes to the

emergency plan and emergency plan implementing procedures and selected 5 for

detailed review against program requirements. The inspectors also visited the licensees

alternate emergency response facilities and reviewed their procedures for use when

access to the site is restricted. The specific documents reviewed during this inspection

are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection

Procedure 71114.05.

b.

Findings

Unresolved Item - Procedures for Recommending Protective Actions for Members of the

Public on the Pacific Ocean

Introduction. The inspectors identified an unresolved item associated with the

implementation of the licensees process to make protective action recommendations

within the ten mile emergency planning zone (EPZ). This item remains unresolved

- 16 -

pending further NRC staff review to determine if this issue constitutes a violation of NRC

requirements.

Description. The inspectors determined that the licensee does not make protective

action recommendations for members of the public on the ocean within ten miles of the

plant. The licensee also does not notify the United States Coast Guard (USCG) of

emergency events. A requirement to make direct notifications was removed from the

licensees emergency plan implementing procedures (EPIP) in 2003. The licensee relies

on the San Luis Obispo County government to notify the USCG to take any actions

necessary to protect members of the public. The county has procedures which include a

default action to recommend the USCG evacuate waterborne vessels within five nautical

miles if the licensee notifies the county of a general emergency. The USCG has

additional guidance recommending a two nautical mile safety zone for an alert or site

area emergency. The licensee had initiated a condition report on November 12, 2013,

identifying that other sites make protective action recommendations for water areas.

Title 10 of the Code of Federal Regulations Part 50.54(q)(2) requires the licensee

to maintain an emergency plan that meets the planning standards outlined in

10 CFR 50.47(b). The planning standard outlined in 10 CFR 50.47(b)(10) requires

the licensee to provide a range of protective actions for emergency workers and

members of the public in the plume exposure pathway EPZ. NUREG-0654 generally

defines the plume exposure EPZ as ten miles radius from the plant. The EPZ may

be defined with alternate boundaries by the licensee if an adequate basis exists.

Title 10 of the Code of Federal Regulations Part 50.54(q)(3) requires the licensee to

obtain NRC approval for changes to the emergency plan, or perform an analysis

demonstrating the changes do not reduce the effectiveness of the plan. The licensee

did not obtain prior NRC approval for the 2003 revision to the EPIPs removing the direct

notification to the USCG of emergency declarations.

This issue remains unresolved pending further NRC review of additional information to

address the concerns described above, in order to determine the adequacy of the

licensees emergency plan and implementing procedures, whether the licensees

protective actions recommendations procedure is consistent with their licensing basis,

and whether or not the issue represents a violation of 10 CFR 50.54(q)(2). In addition,

more information is required to determine if the revision to the implementing procedures

removing the requirement to make a direct notification to the USCG constitutes a

violation of 10 CFR 50.54(q)(3).

This issue is being tracked as URI 05000275/2013005-01; 05000323/2013005-01;

Unresolved Item - Procedures for Recommending Protective Actions for Members of

the Public on the Pacific Ocean.

1EP6 Drill Evaluation (71114.06)

Emergency Preparedness Drill Observation

a.

Inspection Scope

The inspectors observed an emergency preparedness drill on October 30, 2013, to verify

the adequacy and capability of the licensees assessment of drill performance. The

inspectors reviewed the drill scenario, observed the drill from the Technical Support

- 17 -

Center, and reviewed the post-drill critique. The inspectors verified that the licensees

emergency classifications, off-site notifications, and protective action recommendations

were appropriate and timely. The inspectors verified that any emergency preparedness

weaknesses were appropriately identified by the licensee in the post-drill critique and

entered into the corrective action program for resolution.

These activities constitute completion of one emergency preparedness drill observation

sample, as defined in Inspection Procedure 71114.06-05.

b.

Findings

No findings were identified.

4.

OTHER ACTIVITIES

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

Preparedness, Public Radiation Safety, Occupational Radiation Safety, and

Security

4OA1 Performance Indicator Verification (71151)

.1

Data Submission Issue

a.

Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the

third quarter 2013 performance indicators for any obvious inconsistencies prior to its

public release in accordance with Inspection Manual Chapter 0608, Performance

Indicator Program.

This review was performed as part of the inspectors normal plant status activities and,

as such, did not constitute a separate inspection sample.

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 September 2012 through September 2013 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 specific activity

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

- 18 -

b.

Findings

No findings were identified.

.3

Reactor Coolant System Identified Leakage (BI02)

a.

Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system (RCS)

identified leakage for the period of September 2012 through September 2013 to verify

the accuracy and completeness of the reported data. The inspectors reviewed the

performance of RCS leakage surveillance procedure on October 7, 2013. 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 specific activity

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

b.

Findings

No findings were identified.

.4

Drill/Exercise Performance (EP01)

a.

Inspection Scope

The inspectors sampled licensee submittals for the Drill and Exercise Performance,

performance indicator for the period October 2012 through September 2013 to

determine the accuracy of the licensees reported performance indicator data. The

inspectors reviewed the licensees records associated with the performance indicator to

verify that the licensee accurately reported the indicator in accordance with relevant

procedures and Nuclear Energy Institute Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 7. Specifically, the inspectors reviewed

licensee records and processes including procedural guidance on assessing

opportunities for the performance indicator; assessments of performance indicator

opportunities during pre-designated control room simulator training sessions,

performance during the 2012 biennial exercise, and performance during other drills. The

specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the drill/exercise performance sample as

defined in Inspection Procedure 71151.

b.

Findings

No findings were identified.

- 19 -

.5

Emergency Response Organization Drill Participation (EP02)

a.

Inspection Scope

The inspectors sampled licensee submittals for the Emergency Response Organization

Drill Participation performance indicator for the period October 2012 through

September 2013 to determine the accuracy of the licensees reported performance

indicator data. The inspectors reviewed the licensees records associated with the

performance indicator to verify that the licensee accurately reported the indicator in

accordance with relevant procedures and Nuclear Energy Institute Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 7. Specifically, the

inspectors reviewed licensee records and processes including procedural guidance on

assessing opportunities for the performance indicator, rosters of personnel assigned to

key emergency response organization positions, and exercise participation records. The

specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the emergency response organization drill

participation sample as defined in Inspection Procedure 71151.

b.

Findings

No findings were identified.

.6

Alert and Notification System Reliability (EP03)

a.

Inspection Scope

The inspectors sampled licensee submittals for the Alert and Notification System

performance indicator for the period October 2012 through September 2013 to

determine the accuracy of the licensees reported performance indicator data. The

inspectors reviewed the licensees records associated with the performance indicator to

verify that the licensee accurately reported the indicator in accordance with relevant

procedures and Nuclear Energy Institute Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 7. Specifically, the inspectors reviewed

licensee records and processes including procedural guidance on assessing

opportunities for the performance indicator and the results of periodic alert notification

system operability tests. The specific documents reviewed are described in the

attachment to this report.

These activities constitute completion of the alert and notification system sample as

defined in Inspection Procedure 71151.

b.

Findings

No findings were identified.

- 20 -

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. 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

Semiannual Trend Review

a.

Inspection Scope

The inspectors performed a review of the licensees corrective action program and

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

significant safety issue. In particular, the inspectors focused their review on notifications

and several root cause reports completed in the last year which involved human

performance issues, including:

Three instances of loss of start-up power (May 2011)

Low temperature overpressure protection inoperable to technician error (June 2012)

Reactor trip due to a high voltage insulator flashover (October 2012)

Control room ventilation system fans inadequate design modification

(November 2012)

Inadvertent de-energizing of 4kV bus G (February 2013)

Containment isolation valve S-2-200 mispositioned during a mode change

(March 2013)

Three emergency diesel generators inoperable concurrently (June 2013)

500kV insulator hot washing results in a reactor trip (July 2013)

Unit 2 spent fuel handling error (July 2013)

Locked high radiation area found unlocked (October 2013)

Main feed pump trip and reactor power transient due to inadvertent relay actuation

(October 2013)

Auxiliary salt water cross tie valve found closed (November 2013)

Emergency diesel generator inoperable due to a fuel oil leak (December 2013)

Radiation monitors RM11 and 12 inoperable as a result of a maintenance activity

(December 2013)

- 21 -

The inspectors reviewed documents and interviewed personnel to determine if the

licensee completely and accurately identified problems in a timely manner

commensurate with its significance, evaluated and dispositioned operability issues,

considered the extent of conditions and causes, prioritized the problem commensurate

with its safety significance, identified appropriate corrective actions, and completed

corrective actions in a timely manner commensurate with the safety significance of the

issue.

These activities constitute completion of one semi-annual trend review inspection

sample as defined in Inspection Procedure 71152.

b.

Findings

No findings were identified. However, the inspectors identified that while the licensee

appropriately identified and entered these individual issues into the corrective action

program, the root and apparent causes and associated corrective actions were limited in

station-wide application. Specifically, the inspectors identified a common theme in the

licensees cause evaluations which focused on maintenance leadership not consistently

reinforcing human performance standards and error reduction tools. The licensee

agreed with the inspectors observations and entered the issue into the corrective action

program as Notification 50601631, requiring a root cause evaluation to assess and take

corrective actions relative to the adverse human performance trend more broadly than

was completed for the individual station events.

.3

Annual Follow-up of Selected Issues

a.

Inspection Scope

The inspectors selected three issues for an in-depth follow-up:

On October 22, 2013, the inspectors reviewed corrective actions associated with

a Green non-cited violation issued in the first quarter of 2010 for failure to follow

the requirements of the Seismically Induced System Interaction Program (SISIP)

with respect to the stowage and anchoring of potential seismic hazards. The

inspectors evaluated the licensees current compliance with the program, to

include a walkdown of locations in the plant and a review of a sample of required

seismic hazard evaluations. The inspectors assessed the licensees problem

identification threshold, cause analyses, extent of condition reviews and

compensatory actions for the violation. The inspectors verified that the licensee

appropriately prioritized the planned corrective actions and that these actions

were adequate to correct the condition.

On November 27, 2013, the inspectors reviewed the diesel fuel oil storage and

supply system components, particularly for the fuel oil flow transmitter FIT-168.

The inspectors identified that this flow transmitter was found out of tolerance on

several occasions, and that there were no preventative maintenance activities

scheduled between surveillance tests of the fuel oil transfer system. The

inspectors interviewed the system engineer and reviewed the Maintenance

Rule (a).1 plan for planned corrective actions. In addition, the inspectors

independently verified that the inaccurate fuel flow readings from the FIT-168 fuel

- 22 -

flow transmitter could not affect the surveillance test results, because separate

fuel oil level indicators are used to verify the fuel system is transferring the proper

amount of fuel oil.

The inspectors conducted a cumulative review of operator workarounds during

the period December 2-6, 2012, for Units 1 and 2, and assessed the

effectiveness of the operator workaround program to verify that the licensee was:

(1) identifying operator workaround problems at an appropriate threshold;

(2) entering them into the corrective action program; and (3) identifying and

implementing appropriate corrective actions. The review included walkdowns of

the control room panels, interviews with licensed operators and reviews of the

control room discrepancies list, the lit annunciators list, the operator burden list,

and the operator workaround list.

The inspectors assessed the licensees problem identification 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.

These activities constitute completion of three annual follow-up samples, which included

one operator work-around sample.

b.

Findings

No findings were identified.

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

.1

(Closed) 05000323/2013-005-01: Unit 2 Reactor Trip due to Lightning Arrester

Flashover

Introduction. The inspectors reviewed a Green self-revealing non-cited violation of

10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at

Nuclear Power Plants for failure to implement adequate oversight controls and risk

assessment while performing 500kV transmission line insulator maintenance on Unit 2.

This caused an initiating event due to a flashover on the main transformer lightning

arrester that resulted in a reactor trip.

Description. On July 10, 2013, with Diablo Canyon Power Plant Unit 2 at 100 percent

power, PG&E personnel were performing periodic hot washing of 500kV transmission

line insulators. The purpose of hot washing the insulators is to remove contaminants

that can degrade the mechanical and insulating properties which could result in a

flashover. A flashover is a high voltage short-circuit to ground event. During the hot

washing of the Unit 2 500kV Phase A dead-end insulators, an overspray of wash water

drifted onto the 500kV main transformer Phase A lightning arrester, resulting in a

flashover to ground. This actuated the 500kV differential protection relay, which opened

the Unit 2 main generator output breakers as designed. This resulted in a Unit 2 main

turbine trip, and a reactor protection reactor trip, also as designed. The reactor

protection system and engineered safeguards features performed as expected, and

operators placed Unit 2 in a hot shutdown condition. There were no complications other

- 23 -

than damage to the A Phase lightning arrester. Following repairs, Unit 2 was returned to

service on July 14, 2013.

The inspectors reviewed the licensees root-cause evaluation, as well as conducted an

independent review. The inspectors determined the licensee appropriately identified that

the root cause of the flashover event was a result of inadequate controls that lead to

wash water drifting on the A Phase lightning arrester. The water stream overspray

containing dissolved dirt and sea salts was driven by wind onto the lightning arrester,

overloading its ability to provide adequate resistance to ground, which resulted in a

flashover. PG&E personnel did not take appropriate controls to stop the hot washing

activity during a period when wind conditions resulted in excessive water dispersion,

fogging, or overspray, contrary to PG&E transmission line washing requirements and

techniques.

Additionally, the licensee failed to adequately assess the maintenance risk by

categorizing the activity as a non-trip risk. Conflicting guidance and a change to

procedure AD7.DC6, On-line Maintenance Risk Management, resulted in licensee staff

inappropriately categorizing the hot wash activity as a non-trip risk, when it should have

been classified as a low trip risk. The basis for the hot washing preventative

maintenance was not properly documented in the licensee preventive maintenance

procedure, MA1.DC51. Because of this, the risk assessment changed over time from

being characterized as a trip risk, to a non-trip risk. The trip risk was screened out per

Procedure AD7.DC6, On-line Maintenance Risk Management, as an activity which

could not directly cause a reactor trip. Guidance in Section 3.15 of Procedure AD7.DC6

defined a risk activity as something that can significantly increase the probability of a

reactor or turbine trip. Additionally, PG&E Grid Control Center operations routinely listed

hot washing as a trip risk. Further, the licensee did not identify several industry and

internal PG&E Electric Operations operating experience events that identified the

potential for a flashover due to hot washing activities.

The inspectors reviewed the licensees corrective actions which included suspending hot

washing activities. Diablo Canyon personnel began hot washing the 500kV insulators at

a six-week frequency in 1996 in response to a failed insulator at a PG&E substation.

Prior to 1996, the 500kV dead-end insulators were washed during refueling outages.

As a result of this event, Diablo Canyon staff analyzed the periodicity of performing the

500kV insulators hot washes. The licensee determined that based on operating

experience and existing design, the insulators have sufficient margin to defer the

maintenance activity until the next refueling outage.

Analysis. The failure to effectively perform a risk assessment and properly control

maintenance activities that resulted in a reactor trip on July 10, 2013, was a performance

deficiency. The performance deficiency was more than minor because it was associated

with the human performance attribute of the Initiating Events cornerstone and adversely

affected the cornerstone objective to limit the likelihood of events that upset plant

stability and challenged critical safety functions during power operations, and is therefore

a finding. Using Inspection Manual Chapter 0609, Attachment 04, Initial

Characterization of Findings, and Appendix A, Exhibit 1, Initiating Events Screening

Questions, this finding was determined to be of very low safety significance (Green)

because, although it resulted in a reactor trip, it did not result in the loss of mitigating

equipment relied upon to transition the plant from the onset of the trip to a stable

- 24 -

shutdown condition. Additionally, using Inspection Manual Chapter 0612, Appendix K,

Maintenance Risk Assessment and Risk Management Significance Determination

Process, this finding was determined to be of very low safety significance (Green).

This finding had a cross-cutting aspect in the area of human performance, associated

with the decision-making component, because the licensee did not demonstrate that

nuclear safety was an overriding priority during this maintenance activity. Specifically, the

licensee did not initially use conservative decision making in not properly categorizing

the activity as a reactor trip risk (despite internal and external operating experience to

the contrary), and again when the licensee did not terminate the hot washing activities

when environmental conditions degraded resulting in excessive water dispersion.

H.1(b)

Enforcement. This finding is also a violation of 10 CFR 50.65(a)(4), which requires that

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 the proposed maintenance

activities. The scope of the assessment includes non-safety-related structures, systems

and components whose failure could cause a reactor scram or actuation of a safety-

related system. Contrary to this requirement, the licensee failed to assess the

maintenance activity as a reactor trip initiating event by classifying the activity as a

non-trip risk. Because this finding was of very low safety significance and was entered

into the corrective action program as Notification 50579100, this violation is being

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

Policy: NCV 05000323/20130055-02, Reactor Trip due to a Lightning Arrester

Flashover.

.2

(Closed) LER 05000275/2013-007-00: Auxiliary Feedwater Actuation Due to a Main

Feedwater Pump Trip

Introduction. The inspectors reviewed a Green self-revealing finding due to an

inadequate procedure for calibrating non-vital bus relays. This caused an initiating event

due to a main feed pump trip and unplanned downpower transient to 50 percent power

on Unit 1.

Description. On October 14, 2013, with Unit 1 at 100 percent power, main feedwater

pump 1-1 tripped. This event began when maintenance technicians inadvertently

contacted a 480V bus overcurrent relay. When the relay tripped, the non-vital 480V bus

15D de-energized. As a result, the inservice control oil pump tripped, and the backup

control oil pump started as designed; however, a degraded control oil system

accumulator was not able to maintain control oil system pressure long enough for the

back-up control oil pump to develop pressure before the main feed pump 1-1 protective

logic tripped the pump. In response, plant operators rapidly reduced power from

100 percent to 50 percent power and manually started the auxiliary feedwater pumps per

plant procedures and conditions. Feedwater and turbine control systems operated as

designed, mitigating the loss of a single feed pump from full power.

Diablo Canyon personnel determined that the cause of the relay trip was failure to

incorporate operating experience in the relay maintenance procedure. Operating

experience documented that it was possible for the relay covers reset arm to come into

contact with the relay during replacement of the cover following the calibration. The

- 25 -

calibration procedure contained an optional step to position a cut-out switch so that the

relay would not de-energize the bus if actuated. Although technicians discussed

whether they should reposition the switch, they determined it was not necessary. The

technicians were unaware that the cover lever could come in contact with the relay and

actuate the trip circuit. Inadequate procedural guidance and not incorporating operating

experience were identified as causes for the unintended bus de-energization.

Normally, a single bus de-energization should not result in a plant power transient

because plant systems have backup or redundant equipment to provide for reliability.

Although the main feed pump 1-1 back-up oil pump started as designed upon the loss of

the running control oil pump, the control oil accumulator did not maintain system

pressure as designed, resulting in the protective action to trip the main feed pump.

PG&E missed an opportunity to identify and correct the degraded accumulator prior to

this event. On June 29, 2013, while preparing to exit a forced outage, main feed

pump 1-1 was placed into service. Operators noticed an abnormal low nitrogen

pressure on the accumulator and initiated a notification to resolve the problem. In the

evaluation, engineering personnel did not fully identify the problem with the accumulator

not maintaining pressure and did not provide an adequate corrective action before

returning it to service. This created a hidden system vulnerability when the bus 15D

de-energization tripped the running control oil pump and the accumulator was unable to

maintain system pressure while the back-up control oil pump reached operating

pressure. Following this event, maintenance personnel replaced the accumulator

bladder.

Analysis. The licensees failure to maintain an adequate maintenance procedure for

calibrating non-vital bus relays is a performance deficiency. Specifically, the procedure

was inadequate in that it contained an optional step to position a cut-out switch so that

the relay would not de-energize the bus if actuated during maintenance activities. The

performance deficiency was more than minor because, if left uncorrected, the

performance deficiency had the potential to lead to a more significant safety concern. In

particular, when the bus de-energized and tripped the running control oil pump, and the

accumulator was unable to maintain system pressure while the back-up control oil pump

reached operating pressure, the main feed pump tripped which resulted in a reactor

power transient greater than 20 percent. Using Inspection Manual Chapter 0609,

Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 1, Initiating

Events Screening Questions, this finding was determined to be of very low safety

significance (Green) because, although it resulted in a reactor transient, it did not result

in the loss of mitigating equipment relied upon to transition the plant from the onset of

the trip to a stable shutdown condition.

This finding had a cross-cutting aspect in the area of human performance, associated

with the work control component, because the licensee did not adequately plan and

coordinate maintenance activities. Specifically, the licensee did not appropriately assess

the job site conditions that could impact human performance and human-system

interface by failing to incorporate operating experience into procedural guidance. H.3(a)

Enforcement. This finding does not involve enforcement action because no regulatory

requirement was identified. This finding was placed in the licensees corrective action

program as Notifications 50598753, 50588110, and 50588799. Because this finding

does not involve a violation and is of very low safety significance (Green), it is identified

- 26 -

as a finding: FIN 05000275/2013005-03, Auxiliary Feedwater Actuation Due to a Main

Feedwater Pump Trip.

.3

(Closed) LER 05000275; 05000323/2012-008-00: Loss of Control Room Ventilation

System Due to Inadequate Design Control

Introduction. The inspectors reviewed a Green self-revealing non-cited violation of

10 CFR Part 50, Appendix B, Criterion III, Design Control, after the licensee performed

a design change to the control room ventilation system (CRVS) that resulted in none of

the four CRVS pressurization fans being able to continuously operate if they started in

response to a Phase A containment isolation or control room radiation atmosphere

intake actuation signal. This resulted in declaring the Units 1 and 2 CRVS actuation

instrumentation and CRVS inoperable, and an unplanned entry into Technical

Specification (TS) 3.3.7, "Control Room Ventilation System Actuation Instrumentation,"

and TS 3.7.10, "Control Room Ventilation System," respectively.

Description. In October 2012, Diablo Canyon personnel completed modifications and

testing of the Units 1 and 2 CRVS by adding a back-draft damper in each unit's CRVS

recirculation line. These dampers were designed to minimize the amount of unfiltered

air entering the control room when one train is not in operation.

On November 27, 2012, while performing a functional test of the CRVS pressurization

system, operators identified that none of the four CRVS pressurization fans would

continuously operate if they started in response to a safety injection or control room

atmosphere intake radiation actuation signal. Operators declared the Units 1 and 2

CRVS actuation instrumentation inoperable and entered TS 3.3.7, "Control Room

Ventilation System Actuation Instrumentation," as directed by TS 3.3.7, Condition B,

operators also declared one train of CRVS inoperable and entered TS 3.7.10,

Condition A.

Licensee troubleshooting efforts determined that the recent installation of back-draft

dampers and post-modification CRVS flow balancing resulted in a higher static head in

CRVS common ducting during recirculation operation. This caused pressurization fan

cycling due to actuation of the system pressure switches. The original pressurization

system design utilized pressure switches to provide interlocks which precluded running

two fans simultaneously by causing the non-associated fan to shut off. This feature was

originally designed to protect against over pressurization of the system ducting. Soon

after initial system construction, the pressurization fans were modified such that over-

pressurization was no longer possible, but the pressure interlocks remained in the

actuation circuitry. Per design basis document Design Criteria Memorandum

(DCM) S-23F, "Control Room HVAC System," the pressure switches were only identified

as providing a low pressure permissive to start a redundant fan. Therefore, engineers

involved in the damper modification and flow rebalancing did not recognize that the

same pressure switches also provided an over-pressurization interlock. Following these

modifications, the pressurization fan that was selected to run increased static pressure in

ducting downstream of the pressurization fans enough to exceed the setpoint of all the

pressure switches that indicate their associated fan is running. Thus, this condition

caused the operating fan to shut down, which lowered the common-header static

pressure below the setpoint of the pressure switch. This reduction of static pressure in

the common header resulted in the restart of the pressurization fan. Thus, with the on-

- 27 -

and-off cycling of the pressurization fan, the control room ventilation recirculation mode

would not be sustained upon a Phase A containment isolation or radiation monitor

actuation. However, Mode 4 CRVS operation could be sustained by control room

operator manual action taken as directed by DCPP Emergency Operating

Procedure E-0, "Reactor Trip or Safety Injection," Appendix E, "ESP Auto Actions,

Secondary and Auxiliaries Status."

Analysis. The failure to use proper design control during the CRVS modification was a

performance deficiency. The performance deficiency was more than minor because it

was associated with the human performance attribute of the Barrier Integrity

cornerstone, and it adversely affected the cornerstone objective to provide reasonable

assurance that physical design barriers protect the public from radiological releases

caused by accidents or events, and is therefore a finding. Using Inspection Manual

Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A,

Exhibit 3, Barrier Integrity Screening Questions, this finding was determined to be of

very low safety significance (Green) because only the radiological barrier function of the

control room was affected. The finding had a cross-cutting aspect in the area of human

performance resources component because licensee staff did not maintain complete,

accurate, and up-to-date design documentation. Specifically, because the functions of

the pressure switches and CRVS interlocks had never been adequately described in

design control documents. H.2(c)

Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,

Criterion III, Design Control, requires, in part, that measures shall be established to

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

§ 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. Measures shall also be established for the

selection and review for suitability of application of materials, parts, equipment, and

processes that are essential to the safety-related functions of the structures, systems

and components. Contrary to the above, in October 2012, the licensee completed a

design change to the control room ventilation system that resulted in none of the four

CRVS pressurization fans being able to continuously operate if they started in response

to a Phase A containment isolation or control room radiation atmosphere intake actuation

signal. This resulted in declaring the Units 1 and 2 CRVS actuation instrumentation and

CRVS inoperable and an unplanned entry into Technical Specifications (TS) 3.3.7,

"Control Room Ventilation System Actuation Instrumentation," and TS 3.7.10, "Control

Room Ventilation System," respectively. Because this finding was of very low safety

significance and was entered into the corrective action program as Notification

50525605, this violation is being treated as a non-cited violation consistent with

Section 2.3.2 of the NRC Enforcement Policy: NCV 05000275;05000323/2012008-04,

Loss of Control Room Ventilation System Due to Inadequate Design Control.

.4

(Closed) Licensee Event Report (LER) 05000275/1-2013-004-00: All Three Unit 1

Emergency Diesel Generators Momentarily Inoperable

On June 23, 2103, following a loss of 230kV offsite power, Unit 1 control room operators

did not enter LCO 3.0.3 when they simultaneously made all three emergency diesel

generators inoperable by simultaneously placing them all in manual. When 230kV

startup power to the site was lost due to an electrical fault on the grid, all diesel

- 28 -

generators started automatically, as designed. The response procedure directs the

operators to shut down the unloaded EDGs and place them in standby. The operators

chose to first place all three EDGs in manual, which makes them inoperable, and then

shut them down and restored to auto one by one. This resulted in all three EDGs

being inoperable for approximately two minutes. The licensee identified this condition

the following day during a routine supervisory review, and subsequently followed up with

the required 8-hour non-emergency report to the NRC for an unanalyzed condition.

The inspectors dispositioned the failure to comply with technical specifications as a

licensee identified violation in Section 4OA7 of this report.

No additional deficiencies were identified during the review of these Licensee Event

Reports supplemental revisions. This Licensee Event Report is closed.

These activities constitute completion of four event follow-up samples, as defined in Inspection

Procedure 71153.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On November 21, 2013, the inspectors presented the results of the onsite inspection of the

licensees emergency preparedness program to Mr. T. Baldwin, Manager, Regulatory Services,

and other members of the licensees staff. The licensee acknowledged the issues presented.

The inspectors asked the licensee whether any materials examined during the inspection should

be considered proprietary. No proprietary information was identified.

On January 16, 2014, the inspectors presented the inspection results to Mr. E. Halpin, Senior

Vice President and Chief Nuclear Officer, and other members of the licensee staff. The licensee

acknowledged the issues presented. The inspector asked the licensee whether any materials

examined during the inspection should be considered proprietary. No proprietary information

was identified.

On February 7, 2014, the inspectors presented additional information regarding the inspection

results to Mr. E. Halpin, Senior Vice President and Chief Nuclear Officer, and other members of

the licensee staff. The licensee acknowledged the issues presented. The inspector asked the

licensee whether any materials examined during the inspection should be considered

proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and

is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for

being dispositioned as a non-cited violation.

Technical Specification 3.8.1, Condition I, states, when two or more Emergency Diesel

Generators (EDGs) and one or more required offsite circuits are inoperable, the required

action is to enter Limiting Condition for Operation (LCO) 3.0.3, which requires a unit

shutdown initiated within one hour. Contrary to this, on June 23, 2013, following a loss

of 230kV offsite power, Unit 1 control room operators did not enter LCO 3.0.3 when they

simultaneously made all three EDGs inoperable by placing them all in manual. When

- 29 -

230kV startup power to the site was lost due to an electrical fault on the grid, all diesel

generators started automatically, as designed. The response procedure directs the

operators to shut down the unloaded EDGs and place them in standby. The operators

chose to first place all three EDGs in manual, which makes them inoperable, and then

shut them down and restored to auto one by one. This resulted in all three EDGs

being inoperable for approximately two minutes. The licensee identified this condition

the following day during a routine supervisory review and subsequently followed up with

the required 8-hour non-emergency report to the NRC for an unanalyzed condition. The

performance deficiency was more than minor because it was associated with operating

equipment lineup area of the configuration 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 (i.e., core damage). In accordance with IMC 0609 Appendix A, Exhibit 2,

Mitigating Systems Screening Questions, this violation did not require a detailed risk

evaluation because it did not represent an actual loss of diesel generator function for

greater than the Technical Specification allowed outage time, and the risk-significant

function was not lost, even though the design basis start would not have occurred.

Therefore, this violation was of very low safety significance (Green). The licensee

entered the issue into the corrective action program as Notification 50570582.

Corrective actions included implementing more stringent requirements for supervisory

oversight of plant manipulations and modifying the response procedure to specify

sequential steps for placing EDGs in manual one at a time when securing.

A-1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

B. Allen, Site Vice President

J. Arhar, Supervisor, Engineering

S. Baker, Manager, Engineering

T. Baldwin, Manager, Regulatory Services

A. Bates, Director, Engineering Services

K. Bych, Manager, Engineering

S. Dunlap, Supervisor, Engineering

J. Fledderman, Director, Strategic Projects

P. Gerfen, Senior Manager

P. Gerfas, Assistant Director, Station Director

M. Gibbons, Acting Director, Work Control

M. Ginn, Manager, Emergency Planning

D. Gouveia, Manager, Operations

E. Halpin, Chief Nuclear Officer

D. Hardesty, Senior Engineer

J. Hinds, Director, Quality Verification

T. Irving, Manager, Radiation Protection

J. Kang, Engineer, Mechanical Systems Engineering

T. King, Director, Nuclear Work Management

A. Lin, Engineering

J. MacIntyre, Director, Maintenance Services

M. McCoy, NRC Interface, Regulatory Services

J. Nimick, Director, Operations Services

G. Porter, Senior Engineer

J. Salazar, System Engineer

L. Sewell, Supervisor, Radiation Protection

D. Shippey, ALARA Supervisor, Radiation Protection

R. Simmons, Manager, Electrical Maintenance

D. Stermer, Manager, Operation

M. Stevens, Associate, Quality Verification

S. Stoffel, Supervisor, Dosimetry

J. Summy, Senior Director, Engineering and Projects

L. Walter, Station Support

J. Welsch, Station Director R. West, Manager, ICE Systems

E. Wessel, Chemical Engineer, Chemistry

M. Wright, Manager, Mechanical Systems Engineering

A-2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened 05000275/2013005-01

05000323/2013005-01

URI

Procedures for Recommending Protective Actions for Members

of the Public on the Pacific Ocean (Section 1EP5)

Opened and Closed 05000323/2013005-02

NCV Reactor Trip due to a Lightning Arrester Flashover

(Section 4OA3.1)05000275/2013005-03

FIN

Auxiliary Feedwater Actuation Due to a Main Feedwater Pump

Trip (Section 4OA3.2)05000275/2012008-04

05000323/2012008-04

NCV Loss of Control Room Ventilation System due to Inadequate

Design Control (Section 4OA3.3)

Closed

05000323/2-2013-005-

01

LER Unit 2 Reactor Trip due to Lightning Arrester Flashover

(Section 4OA3.1)

05000275/1-2013-007-

00

LER Auxiliary Feedwater Actuation Due to a Main Feedwater Pump

Trip (Section 4OA3.2)

05000275; 05000323/

1-2012-008-00

LER Loss of Control Room Ventilation System due to Inadequate

Design Control (Section 4OA3.3)

05000275/1-2013-004-

00

LER All Three Unit 1 Emergency Diesel Generators Momentarily

Inoperable (Section 4OA3.4)

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

Procedures

Number

Title

Revision

OP J-2

Off-site Power Sources

9

Drawings

Number

Title

Revision

502110

500/230/25/12/4kV Systems

19

A-3

Section 1R04: Equipment Alignment

Procedures

Number

Title

Revision

OP J-6B:II-A

Diesel Generator 2-2 Alignment Checklist

0

OP J-6B:II-A

Diesel Generator 2-2 Alignment Checklist

0

OM6.ID13

Safety at Heights: Fall Protection, Ladder Safety, Working

Under Suspended Loads

18

OP D-1:II

Auxiliary Feedwater System - Alignment Checklist

0

Drawings

Number

Title

102014

Piping Schematic-Somponent Cooling Water System

Section 1R05: Fire Protection

Procedures

Number

Title

Revision

STP M-70C

Inspection of ECG Doors

24

STP M-39A1

U1 & 2, Routine Surveillance Test of Diesel Generator 1-1

(2-1) Room Carbon Dioxide Fire System Operation

16

DCM S-18

Fire Protection System

13B

OM8.ID4

Control of Flammable and Combustible Materials

20

OM8.ID1

Fire Loss Prevention

24

ECG 18.7

Fire Rated Assemblies

10

Drawings

Number

Title

Revision

111906

Units 1 and 2 Fire Drawings, Sheets 1-32

6

Section 1R06: Flood Protection Measures

Work Orders

64079046

64065780

A-4

Section 1R07: Heat Sink Performance

Procedures

Number

Title

Revision

STP M-51

Routine Surveillance Test of Containment Fan Cooler

Units

January 20, 2013

STP M-51

Routine Surveillance Test of Containment Fan Cooler

Units

March 10, 2013

STP M-93A

Refueling Interval Surveillance - Containment Fan

Cooler

March 13, 2013

Notifications

50592355

Section 1R11: Licensed Operator Requalification Program and Licensed Operator

Performance

Procedures

Number

Title

Revision

OP.1DC10

Conduct of Operations

39

Lesson R133S1

Fire in 480V Bus with Loss of Component Cooling

Water Flow to Reactor Coolant Pumps

1a

CP M-6

Fire

34

OP AP-11

Malfunction of Component Cooling Water System

30

EOP E-0

Reactor Trip or Safety Injection

43

Section 1R12: Maintenance Effectiveness

Miscellaneous

Title

Revision

Radiation Monitoring System Reliability and Availability October 29, 2013

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

Number

Title

Revision

MA1.DC11

230kV Bare Hand Removal and Installation Drops

October 10, 2013

A-5

Notifications

50578562

Section 1R15: Operability Determinations and Functionality Assessments

Procedures

Number

Title

Revision

OM7.ID12

Operability Determination

27

OM7.ID13

Technical Evaluations

3

EOP E-2

Faulted Steam Generator Isolation

21

STP V-3P6A

Exercising Valves LCV-110 and LCV-111 Auxiliary

Feedwater Pump Discharge

24

STP P-AFW-12

Routine Surveillance Test of Motor-Driven Auxiliary

Feedwater Pump

18

STP I-92A

AMSAC Functional Test

7

STP I-92A

AMSAC Functional Test

8

STP M-21-A1

Emergency Diesel Generator Functional Test

95

STP M-9B

Diesel Engine Generator Routine Surveillance Test

94

Notifications

50314416

50587512

50507137

50587869

50314416

A0662030

A0692213

A0735701

A0671415

A0479517

50577766

50577917

50572400

50573100

50572174

50595324

50591862

50594028

50594186

50595251

50596161

50596125

50590178

5058999

Section 1R19: Post-Maintenance Testing

Procedures

Number

Title

Revision

STP M-9A

Diesel Engine Generator Routine Surveillance Test

94

STP M-9B

Diesel Engine Generator Routine Surveillance Test

94

STP P-AFW-22

Routine Surveillance Test of Motor-Driven Auxiliary

Feedwater Pump 2-2

17

A-6

Work Orders

64103356

60052907

60053052

60053529

64045245

64085882

60056781

64050757

64052107

64080841

64089790

64089802

64091605

64103362

64057674

50439378

Section 1R22: Surveillance Testing

Procedures

Number

Title

Revision

STP V-3P6A

Exercising Valves LCV-110 and LCV-111 Auxiliary

Feedwater Pump Discharge

24

STP P-AFW-12

Routine Surveillance Test of Motor-Driven Auxiliary

Feedwater Pump

18

STP I-92A

AMSAC Functional Test

7

STP I-92A

AMSAC Functional Test

8

Notifications

50587512

50507137

50587869

50314416

Section 1EP2: Alert and Notification System Testing

Procedures

Number

Title

Revision

EP MT-43

Early Warning System And Maintenance

11

Miscellaneous

Number

Title

Revision

Alert and Notification Design Report

0

Alert and Notification Design Report

1

P000129

Testing the MK 831DT Battery with the SOC 140

Battery Tester

A

A-7

Section 1EP3: Emergency Response Organization Staffing and Augmentation System

Procedure

Number

Title

Revision

EP EF-1

Activation And Operation Of The Technical Support

Center

44

EP EF-2

Activation And Operation Of The Operational Support

Center

33

EP EF-3

Activation And Operation Of The Emergency

Operations Facility

37

Section 1EP4: Emergency Action Level and Emergency Plan Changes

Procedure

Number

Title

Revision

EP, Appendix F

ERO On-Shift Staffing Analysis Report

4.00A

EP, Appendix D,

Category S

System Malfunction

4.01A

EP, Section 7

Emergency Facilities and Equipment

4.18

Section 1EP5: Maintenance of Emergency Preparedness

Procedure

Number

Title

Revision

AWP EP-007

Updating Letters of Agreement

0

EP EF-11

Operation of Alternate Emergency Response

Facilities

0

EP EF-9

Backup Emergency Response Facilities

11

EP G-1

Emergency Classification and Emergency Plan

Activation

43

EP G-3

Notification of Off-Site Organizations

0

EP G-3

Notification of Offsite Organizations

2

EP G-3

Notification of Off-Site Agencies and Emergency

Response Organization Personnel

39

EP G-3

Notification of Off-Site Agencies

40

EP G-3

Emergency Notification of Off-Site Agencies

54B

EP G-4

Assembly and Accountability

26

A-8

Procedure

Number

Title

Revision

EP G-5

Evacuation of Non-Essential Site Personnel

14

EP MT-27

Technical Support Center and Alternate Facility

Location

13

EP MT-28

Operational Support Center and Alternate Facility

Location

11

EP MT-29

Emergency Operations Facility (EOF)

10

EP RB-10

Protective Action Recommendations

10

EP RB-10

Protective Action Recommendations

16

EP RB-3

Stable Iodine Thyroid Blocking

7

OM10

Emergency Preparedness

2

OM10.DC1

Emergency Preparedness Drills and Exercises

6

OM10.DC2

Emergency Response Organization On-Call

6

OM10.DC3

Emergency Response Facilities, Equipment, and

Resources

6

OM10.ID2

Emergency Plan Revision and Review

11

OM10.ID4

Emergency Response Organization Management

12

OM7.ID1

Problem Identification and Resolution

43

OP1.DC17

Control of Equip Required by Technical

Specifications or Designated Programs

27

OP1.DC37

Plant Logs

49

XI1.ID2

Regulatory Reporting Requirements and Reporting

Process

38

Miscellaneous

Number

Title

Revision

Cal OES - Emergency Planning Zones for Serious

Nuclear Power Plant Accidents

Emergency Plan

4

PSS25

USCG - DCPP Emergency Response

November 2007

SOP III.01

San Luis Obispo County - Emergency Services

Director

October 2012

SOP III.25

San Luis Obispo County - United States Coast Guard

June 2013

A-9

Number

Title

Revision

SOP III.44

San Luis Obispo County - Port San Luis Harbor

District

September 2012

DCL-03-024

Emergency Plan Implementing Procedure Update

March 5, 2003

FN120390032

Emergency Preparedness Program Audit

May 3, 2012

FN123390018

Emergency Preparedness Program Audit

February 13, 2013

SAPN50527030

2013 DCPP Baseline Inspection Readiness

Assessment Report

October 18, 2013

Condition Reports

50390230

50392157

50420772

50422636

50422848

50426267

50426528

50427067

50429569

50439297

50439409

50441513

50454155

50457490

50459012

50463112

50468358

50480569

50507869

50508628

50510467

50511677

50522732

50523461

50531921

50531922

50532391

50536699

50542191

50557886

50560263

50562023

50569770

50572410

50573151

50583556

50584094

50593750

50595533

Section 4OA1: Performance Indicator Verification

Procedure

Number

Title

Revision

AWP EP-001

Emergency Preparedness Performance Indicators

16

XI1.DC1

Collection and Submittal of NRC Performance

Indicators

12

STP R-10C

Reactor Coolant System Water Inventory Balance

44

A-10

Section 4OA2: Problem Identification and Resolution

Procedures

Number

Title

Revision

AD4.ID3

SISIP Housekeeping Activities

12

Seismically Induced Systems Interaction Manual

10

AD7.ID2

Daily Notification Review Team and Standard Plant

Priority Assignment Scheme

20

AD7.ID12

Work Management Process

3

Notifications

50494799

50463051

50299740

50499634

50572174

50587627

50572355

50577917

50572400

50573100

50588799

50587467

50592711

50595324

50600007

50591862

50592561

50560387

50592561

50560826

50583459

50583562

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

Notifications

50572400

50573100

50572800

Section 4OA7: Licensee-Identified Violations

Notifications

50570582