ML120440688

IR 05000397-11-005; 09/25/2011 - 12/31/2011; Columbia Generating Station, Integrated Resident and Regional Report; Maintenance Effectiveness; Operability Evaluations; Surveillance Testing; Event Follow-up

ML120440688
Person / Time
Site:	Columbia
Issue date:	02/13/2012
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Reddemann M Energy Northwest
References
IR-11-005
Download: ML120440688 (48)

See also: IR 05000397/2011005

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION I V

1600 EAST LAMAR BLVD

ARLINGTON, TEXAS 76011-4511

February 13, 2012

Mr. M.E. Reddemann

Chief Executive Officer

Energy Northwest

P.O. Box 968, Mail Drop 1023

Richland, WA 99352-0968

Subject: COLUMBIA GENERATING STATION - NRC INTEGRATED INSPECTION REPORT

NUMBER 05000397/20011005

Dear Mr. Reddemann:

On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Columbia Generating Station. The enclosed inspection report documents the

inspection results which were discussed on January 4, 2012, with Mr. B. Sawatzke, Vice

President Nuclear Generation/Chief Nuclear Officer, and other members of your staff.

The inspections examined activities conducted under your license as they relate to safety and

compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed

personnel.

Two NRC-identified and two self-revealing findings of very low safety significance (Green) were

identified during this inspection. Three of these findings were determined to involve violations of

NRC requirements. Further, a licensee-identified violation which was determined to be of very

low safety significance is listed in this report. The NRC is treating these violations as non-cited

violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these non-cited violations, you should provide a response within 30 days of the

date of this inspection report, with the basis for your denial, to the Nuclear Regulatory

Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the

Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear

Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at

Columbia Generating Station.

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

Columbia Generating Station.

Chief Executive Officer

Mr. M.E. Reddemann -2-

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure, and your response (if any) will be available electronically for public inspection in the

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

NRC's Agencywide Document 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 Walker, Chief

Project Branch A

Division of Reactor Projects

Docket No: 05000397

License No: NPF-21

Enclosure:

NRC Inspection Report 05000397/2011005

w/Attachment: Supplemental Information

cc w/Enclosure: Electronic Distribution

Chief Executive Officer

Mr. M.E. Reddemann -3-

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

Deputy Regional Administrator (Art.Howell@nrc.gov)

DRP Director (Kriss.Kennedy@nrc.gov)

DRP Deputy Director (Troy.Pruett@nrc.gov)

DRS Director (Anton.Vegel@nrc.gov)

DRS Deputy Director (Tom.Blount@nrc.gov)

Senior Resident Inspector (Jeremy.Groom@nrc.gov)

Resident Inspector (Mahdi.Hayes@nrc.gov)

Branch Chief, DRP/A (Wayne.Walker@nrc.gov)

Senior Project Engineer, DRP/A (David.Proulx@nrc.gov)

Project Engineer, DRP/A (Jason.Dykert@nrc.gov)

Site Administrative Assistant (Crystal.Myers@nrc.gov)

Public Affairs Officer (Victor.Dricks@nrc.gov)

Public Affairs Officer (Lara.Uselding@nrc.gov)

Project Manager (Mohan.Thadani@nrc.gov)

Acting Branch Chief, DRS/TSB (Ryan.Alexander@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Congressional Affairs Officer (Jenny.Weil@nrc.gov)

OEMail Resource

ROPreports

RIV/ETA: OEDO (Lydia.Chang@nrc.gov)

DRS/TSB STA (Dale.Powers@nrc.gov)

File located: R:\_Reactors\_CGS\2011\CGS2011005-rp-JRG.docx

SUNSI Rev Compl. Yes No ADAMS Yes No Reviewer Initials WW

Publicly Avail Yes No Sensitive Yes No Sens. Type Initials WW

SRI:DRP/A RI:DRP/A SPE:DRP/A C:DRS/EB1 C:DRS/EB2

JGroom MHayes DProulx TRFarnholtz GMiller

WWalker-E WWalker-E /RA/ /RA/ /RA/

2/8/12 2/7/12 1/27/12 1/31/12 1/30/12

C:DRS/OB C:DRS/PSB1 C:DRS/PSB2 AC:DRS/TSB BC:DRP/A

MSHaire MHay GEWerner RAlexander WWalker

/RA/ /RA/ /RA/ DProulx for /RA/

1/31/12 1/31/12 1/30/12 1/31/12 2/13/12

OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000397

License: NPF-21

Report: 05000397/2011005

Licensee: Energy Northwest

Facility: Columbia Generating Station

Location: Richland, WA

Dates: September 25, 2011 through December 31, 2011

Inspectors: J. Groom, Senior Resident Inspector

M. Hayes, Resident Inspector

P. Elkmann, Senior Emergency Preparedness Inspector

Approved By: W. Walker, Chief, Project Branch A

Division of Reactor Projects

-1- Enclosure

SUMMARY OF FINDINGS

IR 05000397/2011005; 09/25/2011 - 12/31/2011; Columbia Generating Station, Integrated

Resident and Regional Report; Maintenance Effectiveness; Operability Evaluations;

Surveillance Testing; Event Follow-up;

The report covered a 3-month period of inspection by resident inspectors and announced

baseline inspections by region-based inspectors. Three Green non-cited violations, one Green

Finding, and one Severity Level IV non-cited violation were identified. The significance of most

findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual

Chapter 0609, Significance Determination Process. The cross-cutting aspect is determined

using Inspection Manual Chapter 0310, Components Within the Cross Cutting Areas. Findings

for which the significance determination process does not apply may be Green or be assigned a

severity level after NRC management review. The NRC's program for overseeing the safe

operation of commercial nuclear power reactors is described in NUREG-1649, Reactor

Oversight Process, Revision 4, dated December 2006.

A. NRC-Identified Findings and Self-Revealing Findings

Cornerstone: Initiating Events

• Green. The inspectors reviewed a self-revealing finding for the licensee's failure

to follow work instructions. Specifically, mechanics failed to properly implement

Work Order 01188696, Task 7, when fabricating the gagging device used to

maintain main condenser hotwell surge volume bypass valve closed during

planned maintenance. As a result, on November 2, 2011, a rapid, unexpected

rise in hotwell level and conductivity and a rapid drop in condensate storage tank

level occurred. Subsequent review revealed that the gagging device installed on

the main condenser hotwell surge volume bypass valve failed, which allowed a

vacuum drag flow path of condensate storage tank water to the main condenser

hotwell. Following identification, the licensee re-fabricated a gagging device in

accordance with engineerings specifications. This issue was entered into the

licensee's corrective action program as Action Request AR 00251720.

The finding was more than minor because it affected the design control attribute

of the Initiating Events Cornerstone objective to limit the likelihood of those

events that upset plant stability and challenge critical safety functions during

shutdown as well as power operations. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the

inspectors determined this finding to be of very low safety significance (Green)

because the finding did not contribute to both the likelihood of a reactor trip and

the likelihood that mitigation equipment or functions will not be available. The

inspectors determined that this finding had a cross-cutting aspect in the area of

human performance associated with the decision making component because

the licensee failed to implement roles and authorities as designed when

fabricating the gagging device for COND-V-170 H.1(a) (Section 1R12).

-2- Enclosure

Cornerstone: Mitigating Systems

• Green. The inspectors identified a non-cited violation of Technical Specification 5.4.1.a, for the licensees failure to include appropriate steps in a surveillance

test procedure. Specifically, Procedure OSP-ELEC-W101, Offsite Station Power

Alignment Check, Revision 20, only verified that voltage was within a specified

band and proper onsite breaker alignment, without verifying that the site was

aligned to a credited power source. The inspectors determined that the licensee

could complete the surveillance procedure as written and declare the

surveillance requirement met even with the startup transformer being powered

from the un-credited 115kV distribution system. The inspectors identified this

issue in followup of an October 5, 2011 issue where the licensee experienced a

loss of the licensing bases power supply to the startup transformer without

operator knowledge. Following identification of this issue, the licensee revised

Procedure OSP-ELEC-W101 to have operators verify the startup transformer is

powered from the licensing basis power source. This issue was entered into the

licensees corrective action program as Action Request AR 249931249931

The finding was more than minor because it affected the procedure quality

attribute of the Mitigating Systems Cornerstone objective to ensure the

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

to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the

inspectors determined this finding to be of very low safety significance (Green)

because it did not result in the loss of a system safety function, did not represent

the loss of safety function of a single train for greater than its allowed outage

time, did not result in the loss of safety function of any non-technical specification

equipment, and did not screen as potentially risk significant due to seismic,

flooding, or severe weather initiating events. The inspectors determined a cross-

cutting aspect was not applicable since the cause of the procedure inadequacy

originated from its original implementation with missed opportunities in 2007 and

therefore was not reflective of current plant performance (Section 1R15).

Cornerstone: Barrier Integrity

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

Specification 5.4.1.a, for the licensees failure to follow procedures. Specifically,

on November 2, 2011, operators failed to follow Procedure

SOP-HVAC/RB-START, Reactor Building Ventilation Start, Revision 2, by

skipping a required step for restoration of reactor building ventilation to the

normal alignment following testing of secondary containment isolation valves. As

a result, when the reactor building ventilation fans were started, secondary

containment pressure increased rapidly to a peak positive pressure of

approximately 0.29 inch of water, while secondary containment is normally

maintained at 0.6 inch of water vacuum to meet its design basis function. When

operators completed of the surveillance test of the secondary containment

isolation valves, operators entered Procedure SOP-HVAC/RB-START at

-3- Enclosure

Step 5.1.5 which started the fans. The operators should have entered the

procedure at Step 5.1.1 which would have placed pressure controller

REA-DPIC-1B in manual. This step was necessary since the response time of

the controller was not rapid enough to compensate for the rapid changes in air

flows associated with a fan start. An event investigation concluded that the

missed procedural step was caused by poor planning and preparation and less

than adequate self and peer checks. This issue was entered into the licensees

corrective action program as Action Request AR 00251613.

The finding was more than minor because it affected the human performance

attribute of the Barrier Integrity Cornerstone objective to provide reasonable

assurance that physical design barriers (fuel cladding, reactor coolant system,

and containment) protect the public from radionuclide releases caused by

accidents or events. Using Inspection Manual Chapter 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, the inspectors determined

this finding to be of very low safety significance (Green) because it only

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

standby gas treatment system. The inspectors determined that this finding had a

cross-cutting aspect in the area of human performance associated with the work

practices component because the licensee failed to use human error prevention

techniques such as self and peer checking H.4(a) (Section 1R22).

Cornerstone: Emergency Preparedness

• Green. The inspectors identified a non-cited violation of Technical Specification 5.4.1.a for the licensee's failure to follow the abnormal procedure for

earthquakes. Specifically, the licensee failed to follow Procedure

ABN-Earthquake, Revision 6, by not recalibrating seismic instruments within 30

days of two earthquakes near the site that occurred on September 3, and

October 14, 2011. Consequently, several seismic instruments were not all

functional following the September 3, 2011 earthquake, and the same seismic

monitoring devices were not functional during the October 14, 2011 earthquake,

which complicated post-earthquake evaluation. Following identification of this

issue, the licensee performed calibrations of all seismic instruments on

November 2, 2011. This issue was entered into the licensee's corrective action

program as Action Request AR 00251987.

The finding was more than minor because it affected the human performance

attribute of the Emergency Preparedness Cornerstone objective to ensure the

licensee is capable of implementing adequate measures to protect the health and

safety of the public in the event of a radiological emergency. Specifically,

seismic instrumentation is required following a seismic event to evaluate the

necessity of an emergency declaration and to determine the impact of strong

motion on structures, systems and components or the need for a reactor

shutdown. Using Inspection Manual Chapter 0609, Appendix B, Emergency

Preparedness Significance Determination Process the inspectors determined

this finding to be of very low safety significance (Green) because while some

-4- Enclosure

seismic instruments were non-functional and that did complicate the operators

response to the October 14, 2011 earthquake, the non-functional instruments did

not result in a loss of planning standard or risk-significant planning standard

function. The inspectors determined that this finding had a cross-cutting aspect

in the area of human performance associated with the work control component

because the licensee failed to appropriately plan work activities by incorporating

the need for planned contingencies such as those needed to recalibrate seismic

instruments following an earthquake H.3(a) (Section 4OA3).

B. Licensee-Identified Violations

Violations of very low safety significance, which were identified by the licensee, have

been reviewed by the inspectors. Corrective actions taken or planned by the licensee

have been entered into the licensees corrective action program. These violations and

corrective action tracking numbers (condition report numbers) are listed in

Section 4OA7.

-5- Enclosure

REPORT DETAILS

Summary of Plant Status

The inspection period began with Columbia Generating Station in Mode 2, Startup," with

reactor power at approximately two percent rated thermal power. On September 27, 2011, the

main generator was synchronized with the grid. Full power was achieved on October 2, 2011.

On October 3, 2011, Columbia Generating Station reduced power to 65 percent for a control rod

pattern adjustment and returned to 100 percent power on October 4, 2011. On October 8, 2011,

Columbia Generating Station reduced power to approximately 85 percent due to problems with

cooling tower 1C. The unit returned to full power on October 9, 2011. On November 17, 2011,

Columbia Generating Station reduced power to 20 percent to support balancing of the main

turbine. Following balancing, the main generator was synchronized to the grid on November 19,

2011, and returned to 100 percent power on November 21, 2011. Columbia Generating Station

reduced power to 65 percent on December 10, 2011 to support a rod pattern adjustment and

returned to full power on December 11, 2011. The unit remained at or near full power for the

remainder of the inspection period.

1. REACTOR SAFETY

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

Emergency Preparedness

1R01 Adverse Weather Protection (71111.01)

.1 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

Since freezing conditions were forecast in the vicinity of the facility for October 25, 2011,

the inspectors reviewed overall preparations/protection for the expected weather

conditions. On October 25-27, 2011, the inspectors performed walkdowns of the reactor

protection system and emergency diesel generators because their safety-related

functions could be affected or required as a result of the extreme cold conditions

forecast for the facility. The inspectors observed insulation, heat trace circuits, space

heater operation, and weatherized enclosures to ensure operability of affected systems.

The inspectors reviewed licensee procedures and discussed potential compensatory

measures with control room personnel. The inspectors focused on plant managements

actions for implementing the stations procedures for ensuring adequate personnel for

safe plant operation and emergency response would be available. Specific documents

reviewed during this inspection are listed in the attachment.

Additionally, since high winds were forecast in the vicinity of the facility for November 22,

2011, the inspectors reviewed the plant personnels overall preparations for the expected

weather conditions. On November 22-23, 2011, the inspectors walked down the

transformer yard and emergency diesel generator 3 because components in these

systems could be affected as a result of high winds or tornado-generated missiles. The

inspectors evaluated the plant staffs preparations against the sites procedures and

-6- Enclosure

determined that the staffs actions were adequate. During the inspection, the inspectors

focused on plant-specific design features and the licensees procedures used to respond

to specified adverse weather conditions. The inspectors also toured the plant grounds to

look for any loose debris that could become missiles during high winds. Additionally, the

inspectors reviewed the FSAR and performance requirements for the systems selected

for inspection, and verified that operator actions were appropriate as specified by plant-

specific procedures. The inspectors also reviewed a sample of corrective action

program items to verify that the licensee identified adverse weather issues at an

appropriate threshold and dispositioned them through the corrective action program in

accordance with station procedures. Specific documents reviewed during this inspection

are listed in the attachment.

These activities constitute completion of two readiness for impending adverse weather

condition samples as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignments (71111.04)

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant

systems:

• October 7, 2011, high pressure core spray system following keep fill pump

maintenance

• October 19, 2011, seismic instrumentation

• November 21, 2011, Division 3 emergency diesel generator

• December 29, 2011, residual heat removal train C

The inspectors selected these systems based on their risk significance relative to the

reactor safety cornerstones at the time they were inspected. The inspectors attempted

to identify any discrepancies that could affect the function of the system, and, therefore,

potentially increase risk. The inspectors reviewed applicable operating procedures,

system diagrams, FSAR, technical specification requirements, administrative technical

specifications, outstanding work orders, condition reports, and the impact of ongoing

work activities on redundant trains of equipment in order to identify conditions that could

have rendered the systems incapable of performing their intended functions. The

inspectors also inspected accessible portions of the systems to verify system

components and support equipment were aligned correctly and operable. The

inspectors examined the material condition of the components and observed operating

-7- Enclosure

parameters of equipment to verify that there were no obvious deficiencies. The

inspectors also verified that the licensee had properly identified and resolved equipment

alignment problems that could cause initiating events or impact the capability of

mitigating systems or barriers and entered them into the corrective action program with

the appropriate significance characterization. Specific documents reviewed during this

inspection are listed in the attachment.

These activities constitute completion of four partial system walkdown samples as

defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

On November 23, 2011, the inspectors performed a complete system alignment

inspection of the standby liquid control system to verify the functional capability of the

system. The inspectors selected this system because it was considered both safety

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

inspectors inspected the system to review mechanical and electrical equipment line ups,

electrical power availability, system pressure and temperature indications, as

appropriate, component labeling, component lubrication, component and equipment

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

ancillary equipment or debris did not interfere with equipment operation. The inspectors

reviewed a sample of past and outstanding work orders to determine whether any

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

reviewed the corrective action program database to ensure that system equipment-

alignment problems were being identified and appropriately resolved. Specific

documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one complete system walkdown sample as

defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

-8- Enclosure

1R05 Fire Protection (71111.05)

.1 Quarterly Fire Inspection Tours

a. Inspection Scope

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

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

plant areas:

• October 12, 2011, Fire area R-1, reactor building 548 elevation

• November 9, 2011, Fire areas M-9, R-1 and R-4, reactor building 471 elevation

• November 15, 2011, Fire area RC-13, radwaste building 525 elevation

• December 2, 2011, Fire areas RC-1 and RC-2 radwaste building 487 elevation

• December 30, 2011, Fire areas R-1 and R-15, reactor building 422 elevation

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

protection program that adequately controlled combustibles and ignition sources within

the plant; effectively maintained fire detection and suppression capability; maintained

passive fire protection features in good material condition; and had implemented

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

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

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

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

additional insights, their potential to affect equipment that could initiate or mitigate a

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

the documents listed in the attachment, the inspectors verified that fire hoses and

extinguishers were in their designated locations and available for immediate use; that

fire detectors and sprinklers were unobstructed; that transient material loading was

within the analyzed limits; and fire doors, dampers, and penetration seals appeared to

be in satisfactory condition. The inspectors also verified that minor issues identified

during the inspection were entered into the licensees corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five quarterly fire-protection inspection samples

as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope

The inspectors reviewed the FSAR, the flooding analysis, and plant procedures to

assess susceptibilities involving internal flooding; reviewed the corrective action program

to determine if licensee personnel identified and corrected flooding problems; inspected

-9- Enclosure

underground bunkers/manholes to verify the adequacy of sump pumps, level alarm

circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and

verified that operator actions for coping with flooding can reasonably achieve the desired

outcomes. The inspectors also inspected the areas listed below to verify the adequacy

of equipment seals located below the flood line, floor and wall penetration seals,

watertight door seals, common drain lines and sumps, sump pumps, level alarms, and

control circuits, and temporary or removable flood barriers. Specific documents

reviewed during this inspection are listed in the attachment.

• October 6, 2011, electrical manholes 43 and 44

• December 15, 2011, flooding safe shutdown analysis for a postulated pipe break

in the condensate storage tank 24 inch supply line and potential impact to

components HPCS-PS-3A and 3B

These activities constitute completion of one flood protection measures inspection

sample and an annual review of cables located in manholes/bunkers consisting of a

review of two individual manholes as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry

standards, and reviewed critical operating parameters and maintenance records for the

Division 2 diesel cooling water heat exchangers. The inspectors verified that

performance tests were satisfactorily conducted for heat exchangers/heat sinks and

reviewed for problems or errors; the licensee utilized the periodic maintenance method

outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines;

the licensee properly utilized biofouling controls; the licensees heat exchanger

inspections adequately assessed the state of cleanliness of their tubes; and the heat

exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring

the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents

reviewed during this inspection are listed in the attachment.

These activities constitute completion of one heat sink inspection sample as defined in

Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

- 10 - Enclosure

1R11 Licensed Operator Requalification Program (71111.11)

a. Inspection Scope

On November 15, 2011, the inspectors observed a crew of licensed operators in the

plants simulator to verify that operator performance was adequate, evaluators were

identifying and documenting crew performance problems and training was being

conducted in accordance with licensee procedures. The inspectors evaluated the

following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification

actions and emergency plan actions and notifications

The inspectors compared the crews performance in these areas to preestablished

operator action expectations and successful critical task completion requirements.

Specific documents reviewed during this inspection are listed in the attachment.

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.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk

significant systems:

• November 7, 2011, Action Request 249959, failure of control room handswitch

for valve RHR-V-24B

- 11 - Enclosure

• December 19, 2011, Action Request 251720, Maintenance associated with main

condenser hotwell makeup valve COND-V-0170 results in hotwell level transient

The inspectors reviewed events such as where ineffective equipment maintenance has

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

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

problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

• Scoping of systems in accordance with 10 CFR 50.65(b)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

• Verifying appropriate performance criteria for structures, systems, and

components classified as having an adequate demonstration of performance

through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as

requiring the establishment of appropriate and adequate goals and corrective

actions for systems classified as not having adequate performance, as described

in 10 CFR 50.65(a)(1)

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

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

effectiveness issues were entered into the corrective action program with the appropriate

significance characterization. Specific documents reviewed during this inspection are

listed in the attachment.

These activities constitute completion of two quarterly maintenance effectiveness

samples as defined in Inspection Procedure 71111.12-05.

b. Findings

Introduction. The inspectors reviewed a self-revealing Green finding for the licensee's

failure to follow work instructions when fabricating the gagging device used to maintain

main condenser hotwell surge volume bypass valve closed during planned maintenance.

Description. On November 2, 2011, the main control room received unexpected

annunciator Main Condenser Hotwell Level High. Indications in the control room

included a rapid, unexpected rise in hotwell level, increases in hotwell conductivity and a

- 12 - Enclosure

rapid drop in condensate storage tank level. Operators entered the alarm response

procedure and determined that an undesired flow path from the condensate storage

tanks to the main condenser hotwell was the cause of the level transient. Operators

closed isolation valve COND-V-17 to stop the water transfer. In total, approximately

91,500 gallons of water was transferred from the condensate storage tanks to the main

condenser hotwell. The licensee discovered that a gagging device installed on main

condenser hotwell surge volume bypass valve COND-V-170 under Work Order 01188696, Task 5, did not hold resulting in the valve opening slightly. This open valve

allowed a vacuum drag flow path of condensate storage tank water to the main

condenser hotwell.

The design of the gagging device had been established under Action Request

AR-EVAL 219734 and specified that it was machined out of A36 steel bar stock and had

the same thread pitch as the stem for valve COND-V-170. This design allowed for the

gagging device to be clamped around the valve stem threads and rested against the

valve yoke to keep the valve closed so that the operator could be removed. Fabrication

of the gagging device was performed under Work Order 01188696, Task 7. The

inspectors interviewed the machinist responsible for fabricating the gag and discovered

that the design was changed during the fabrication process. Specifically, the machinist

elected to use a pre-existing gagging device made of brass rather than to fabricate a

new gag. When installed, the brass gagging device did not properly engage the valve

stem threads so the machinist modified the design to a smooth bore which would only

clamp around the exterior of the valve stem and relied on friction to maintain the valve

closed. When installed in this configuration, the forces associated with re-installing the

operator were of sufficient magnitude to overcome the friction imparted by the gagging

device. Consequently, the valve opened and transferred water from the condensate

storage tanks to the main condenser hotwell. The modifications to the gagging device

were implemented by the machinist without consultation of the engineer responsible for

the design.

Analysis. The failure of licensee personnel to follow work instructions when fabricating a

gagging device for main condenser hotwell surge volume bypass valve COND-V-170

was a performance deficiency. The finding was more than minor because it affected the

design control attribute of the Initiating Events Cornerstone objective to limit the

likelihood of those events that upset plant stability and challenge critical safety functions

during shutdown as well as power operations. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors

determined this finding to be of very low safety significance (Green) because the finding

did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation

equipment or functions will not be available. The inspectors determined that this finding

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

decision making component because the licensee failed to act with proper authority

when fabricating the gagging device for COND-V-170 H.1(a).

Enforcement. Enforcement action does not apply because the performance deficiency

did not involve a violation of regulatory requirements. The finding is of very low safety

significance and the issue was entered into the licensee's corrective action program as

- 13 - Enclosure

AR 00251720: FIN 05000397/2011005-01, Failure to Follow Work Instructions when

Fabricating a Gagging Device for Main Condenser Hotwell Surge Bypass Valve."

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

a. Inspection Scope

The inspectors reviewed licensee personnel's evaluation and management of plant risk

for the maintenance and emergent work activities affecting risk-significant and safety-

related equipment listed below to verify that the appropriate risk assessments were

performed prior to removing equipment for work:

• October 19, 2011, Yellow risk during planned reactor core isolation cooling

maintenance window

• October 24, 2011, Yellow risk during planned maintenance on reactor core

isolation maintenance and control room emergency filtration fan A

• November 10, 2011, Yellow risk during planned surveillance testing of diesel

generator 2

• November 15, 2011, Yellow risk during planned work on the offsite power system,

standby gas treatment system B and standby liquid control system

• December 12-14, 2011, Yellow risk during planned maintenance of the standby

gas treatment system A and quarterly surveillance testing of the standby liquid

control system

The inspectors selected these activities based on potential risk significance relative to

the reactor safety cornerstones. As applicable for each activity, the inspectors verified

that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)

and that the assessments were accurate and complete. When licensee personnel

performed emergent work, the inspectors verified that the licensee personnel promptly

assessed and managed plant risk. The inspectors reviewed the scope of maintenance

work, discussed the results of the assessment with the licensee's probabilistic risk

analyst or shift technical advisor, and verified plant conditions were consistent with the

risk assessment. The inspectors also reviewed the technical specification requirements

and inspected portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met. Specific

documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five maintenance risk assessments and

emergent work control inspection samples as defined in Inspection

Procedure 71111.13-05.

- 14 - Enclosure

b. Findings

No findings were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors reviewed the following issues:

• October 6, 2011, Action Request AR 249795249795documenting loss of both credited

power sources to the startup transformer

• October 12, 2011, Action Requests AR 248876248876 249535 and 249891

documenting issues related to the fill material for cooling tower 1C

• October 18, 2011, Action Request AR 250306250306documenting unevaluated

shielding installed on residual heat removal system

• November 7, 2011, Action Requests AR 219624219624and 250150, documenting

operating experience related to Ametek static uninterruptible power supplies

• November 14, 2011, Action Request AR 251613251613documenting a failure of

ventilation damper WMA-AD-51A/1A

• December 9, 2011, Action Request AR 254047254047documenting a ten drop per

minute leak on Division 2 diesel cooling water heat exchanger DCW-HX-1B2

• December 29, 2011, Action Request AR 253985253985documenting that electrical

disconnect WMA-42-8F1E inadvertently opened

The inspectors selected these potential operability and functionality issues based on the

risk significance of the associated components and systems. The inspectors evaluated

the technical adequacy of the evaluations to ensure that technical specification

operability was properly justified and the subject component or system remained

available such that no unrecognized increase in risk occurred. The inspectors compared

the operability and design criteria in the appropriate sections of the technical

specifications and FSAR to the licensee personnels evaluations to determine whether

the components or systems were operable. Where compensatory measures were

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

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

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

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

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

associated with operability evaluations. Specific documents reviewed during this

inspection are listed in the attachment.

- 15 - Enclosure

These activities constitute completion of seven operability evaluations inspection

samples as defined in Inspection Procedure 71111.15-05

b. Findings

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

Specification 5.4.1.a, Procedures, for the licensees failure to include appropriate

instructions in Surveillance Testing Procedure OSP-ELEC-W101, Offsite Station Power

Alignment Check, Revision 20, for verifying breaker alignment conformed with licensing

basis documents. Specifically, licensee personnel failed to include steps in the

procedure that verified the startup transformer was powered from the credited 230kV

power distribution system.

Description. On October 5, 2011, the inspectors reviewed Action Request AR 249795249795 which documented the loss of the licensing basis power supply to the startup

transformer. The startup transformer is powered through a substation that is either

powered from the 230kV distribution system or the 115kV distribution system. When the

startup transformer is powered from the 115kV distribution system the licensee is

required to enter Technical Specification 3.8.1, AC Sources Operating, Condition A due

to one offsite source being inoperable. One offsite source is considered inoperable in

this condition since the 115kV distribution is not a credited source of power to the startup

transformer in the Columbia Generating Station licensing basis. The inspectors

reviewed Surveillance Requirement 3.8.1.1 which required the licensee to verify correct

breaker alignment and indicated power availability for each offsite circuit. The

inspectors reviewed the technical specification bases and noted the following:

The breaker alignment verifies that each breaker is in its correct position to

ensure that distribution buses and loads are connected to their preferred power

source and that appropriate independence of offsite circuits is maintained.

The inspectors reviewed Procedure OSP-ELEC-W101, Offsite Station Power Alignment

Check, Revision 20, and found that the procedure only verified voltage was within a

specified band and that the onsite breaker alignment was aligned to the appropriate

electrical buses. The inspectors determined that the licensee could complete the

surveillance procedure as written and declare the surveillance requirement met even

though the startup transformer is being powered from the non-credited 115kV

distribution system since the licensee does not actively verify the startup transformer is

powered from the appropriate 230kV substation. The inspectors determined that

Procedure OSP-ELEC-W101 did not meet the intent of the surveillance requirement

since it did not verify the appropriate independence of the offsite power circuits.

The inspectors reviewed Action Request 54232, from July 2007, which documented the

differences between the credited and non-credited supplies to the startup transformer. A

corrective action from this action request added a precaution and limitation to Procedure

OSP-ELEC-W101 that alerted operators of the potential of being lined up to an un-

credited source and the need to review technical specifications if this occurred. The

inspectors interviewed control room operators to determine if the operators were

verifying which source was powering the startup transformer while performing the

- 16 - Enclosure

surveillance procedure. The inspectors determined the operators were not verifying the

plant was lined up to the credited source for the startup transformer unless a diesel

generator was concurrently out of service. The licensee documented the inspectors

concerns regarding the adequacy of Procedure OSP-ELEC-W101 in Action Request AR

249931. The licensee revised Procedure OSP-ELEC-W101 on November 29, 2011, to

have operators verify the startup transformer is powered from its licensing basis source.

Analysis: The licensee's failure to include steps to ensure the startup transformer is

powered from its credited offsite source in a surveillance procedure was a performance

deficiency. The finding was more than minor because it affected the procedure quality

attribute of the Mitigating Systems Cornerstone objective to ensure the availability,

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

undesirable consequences. Using Inspection Manual Chapter 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, the inspectors determined this finding

to be of very low safety significance (Green) because it did not result in the loss of a

system safety function, did not represent the loss of safety function of a single train for

greater than its allowed outage time, did not result in the loss of safety function of any

non-technical specification equipment, and did not screen as potentially risk significant

due to seismic, flooding, or severe weather initiating events. The inspectors determined

a cross-cutting aspect was not applicable since the cause of the procedure inadequacy

originated from its original implementation with missed opportunities in 2007 and

therefore was not reflective of current plant performance.

Enforcement: Technical Specification 5.4.1.a requires, in part, that written procedures

be established, implemented, and maintained as recommended in Regulatory Guide

1.33, Revision 2, Appendix A, dated February 1978. Paragraph 8.b, Section 2.q of

Regulatory Guide 1.33, Appendix A, requires specific procedures for surveillance tests

associated with emergency power tests. Contrary to the above, since

November 8, 2007, the licensee failed to maintain Surveillance Procedure

OSP-ELEC-W101, Offsite Station Power Alignment Check Revision 0-20 by not

including steps to have operators verify appropriate independence of offsite power

circuits was maintained regardless of plant configuration. This was identified on October

5, 2011 and the surveillance procedure was revised on November 29, 2011 to include

steps to verify the correct lineup to the startup transformer. Because this finding is of

very low safety significance and was entered into the licensees corrective action

program as Action Request AR 249931249931 the violation is being treated as a non-cited

violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000397/2011005-02, Failure to Include Appropriate Acceptance Criteria in Offsite

Power Alignment Procedure.

1R18 Plant Modifications (71111.18)

a. Inspection Scope

To verify that the safety functions of important safety systems were not degraded, the

inspectors reviewed the following plant modifications:

• Applicability Determination 11-0260, Revision of Standby Liquid Control Quarterly

Operability Procedure to Incorporate Engineering Calculation that Defines

- 17 - Enclosure

Maximum Water Level in Standby Liquid Control Test Tank to Ensure System

Operability

For temporary modifications, the inspectors reviewed the associated safety-evaluation

screening against the system design bases documentation, including the FSAR and the

technical specifications, and verified that the modification did not adversely affect the

system operability/availability. The inspectors also verified that the installation and

restoration were consistent with the modification documents and that configuration

control was adequate. Additionally, the inspectors verified that the temporary

modification was identified on control room drawings, appropriate tags were placed on

the affected equipment, and licensee personnel evaluated the combined effects on

mitigating systems and the integrity of radiological barriers.

For modifications that involved permanent changes to the plants configuration, the

inspectors reviewed key affected parameters associated with energy needs, materials,

replacement components, timing, heat removal, control signals, equipment protection

from hazards, operations, flow paths, pressure boundary, ventilation boundary,

structural, process medium properties, licensing basis, and failure modes.

The inspectors verified that modification preparation, staging, and implementation did

not impair emergency/abnormal operating procedure actions, key safety functions, or

operator response to loss of key safety functions; postmodification testing will maintain

the plant in a safe configuration during testing by verifying that unintended system

interactions will not occur; systems, structures and components performance

characteristics still meet the design basis; the modification design assumptions were

appropriate; the modification test acceptance criteria will be met; and licensee personnel

identified and implemented appropriate corrective actions associated with permanent

plant modifications. Specific documents reviewed during this inspection are listed in the

attachment.

These activities constitute completion of one sample for plant modifications as defined in

Inspection Procedure 71111.18-05.

b. Findings

No findings were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed the following postmaintenance activities to verify that

procedures and test activities were adequate to ensure system operability and functional

capability:

• September 28, 2011, postmaintenance testing of reactor feedwater pump 1A

following turbine overhaul

- 18 - Enclosure

• September 29, 2011, postmaintenance testing of weld repair to main steam valve

MS-V-707C

• October 24, 2011, postmaintenance testing of reactor core isolation cooling valve

RCIC-V-22 following stem nut replacement

• November 14, 2011, postmaintenance testing of technical support center

following work on ventilation system

• December 19, 2011, postmaintenance testing of residual heat removal system

relay E-RLY-RHRA/62/1

The inspectors selected these activities based upon the structure, system, or

component's ability to affect risk. The inspectors evaluated these activities for the

following:

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

adequate for the maintenance performed

• Acceptance criteria were clear and demonstrated operational readiness; test

instrumentation was appropriate

The inspectors evaluated the activities against the technical specifications, the FSAR, 10

CFR Part 50 requirements, licensee procedures, and various NRC generic

communications to ensure that the test results adequately ensured that the equipment

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

corrective action documents associated with postmaintenance tests to determine

whether the licensee was identifying problems and entering them in the corrective action

program and that the problems were being corrected commensurate with their

importance to safety. Specific documents reviewed during this inspection are listed in

the attachment.

These activities constitute completion of five postmaintenance testing inspection

samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities (71111.20)

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the refueling

outage that began on April 2, 2011 and concluded on September 27, 2011, to confirm

that licensee personnel had appropriately considered risk, industry experience, and

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

- 19 - Enclosure

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

portions of the reactor startup and monitored licensee controls over the outage activities

listed below.

• Configuration management, including maintenance of defense in depth, is

commensurate with the outage safety plan for key safety functions and

compliance with the applicable technical specifications when taking equipment

out of service.

• Clearance activities, including confirmation that tags were properly hung and

equipment appropriately configured to safely support the work or testing.

• Controls over activities that could affect reactivity.

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

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

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

reactor physics testing.

• Licensee identification and resolution of problems related to refueling outage

activities.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one refueling outage and other outage

inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed the FSAR, procedure requirements, and technical

specifications to ensure that the surveillance activities listed below demonstrated that the

systems, structures, and/or components tested were capable of performing their

intended safety functions. The inspectors either witnessed or reviewed test data to

verify that the significant surveillance test attributes were adequate to address the

following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

- 20 - Enclosure

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems,

structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints

The inspectors also verified that licensee personnel identified and implemented any

needed corrective actions associated with the surveillance testing.

• November 2, 2011, Work Order 02007123, reactor building ventilation (secondary

containment) isolation valve operability test

• November 3, 2011, Work Order 02007056, diesel generator 3 semi-annual

operability test

• November 8, 2011, reactor coolant system leakage detection calculation used to

satisfy Technical Specification Surveillance Requirement SR 3.4.5.1

• December 19, 2011, Work Order 02010460, residual heat removal system A

quarterly inservice/operability surveillance testing

• December 28, 2011, Work Order 02010572, containment isolation valve

operability test

Specific documents reviewed during this inspection are listed in the attachment.

- 21 - Enclosure

These activities constitute completion of five surveillance testing inspection samples as

defined in Inspection Procedure 71111.22-05.

b. Findings

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

Technical Specification 5.4.1.a, Procedures for the failure of the licensee to follow

procedures associated with surveillance testing of secondary containment isolation

valves.

Description. On November 2, 2011, operations personnel performed testing of

secondary containment isolation valves in accordance with

Procedure OSP-CONT/IST-Q702, Reactor Building Ventilation Isolation Valve

Operability, Revision 8. Following completion of the surveillance test, OSP-

CONT/IST-Q702, Step 7.1.13, directed operators to restore reactor building ventilation to

a normal alignment in accordance with Procedure SOP-HVAC/RB-START, Reactor

Building Ventilation Start, Revision 2. The operators mistakenly believed that all of the

prerequisite steps required to start the reactor building outside air fan ROA-FN-1A and

reactor building exhaust air fan REA-FN-1B had been met so the operators entered

Procedure SOP-HVAC/RB-START at Step 5.1.5 which started the fans. The operators

should have entered the procedure at Step 5.1.1 which would have placed pressure

controller REA-DPIC-1B in manual. This step is necessary since the response time of

REA-DPIC-1B in automatic was not rapid enough to compensate for the rapid changes

in air flows associated with a fan start. Consequently, when the reactor building outside

air and exhaust fans were started, secondary containment pressure increased rapidly to

a peak of approximately 0.29 inch of water.

Procedure OSP-CONT/IST-Q702 is written such that the licensee enters Technical

Specification 3.6.4.1, Secondary Containment in anticipation of exceeding the

minimum required pressure of 0.25 inch of vacuum water gauge. However, the

procedure is also designed to preserve the analytical assumptions associated with the

post-loss of coolant accident performance of the standby gas treatment system specified

in the Columbia Generating Station Final Safety Analysis Report Table 6.2-28,

Analytical Sequence of Events in Secondary Containment which assumed reactor

building (secondary containment) starting pressure of 0.0 inch of water gauge. The error

that occurred on November 2, 2011 resulted in secondary containment pressure briefly

exceeding the analytical starting assumption of 0.0 inch of water gage specified in the

Columbia Generating Station Final Safety Analysis Report. Upon exceeding 0.0 inch of

water, the control room operators received an annunciator for high reactor building

differential pressure and entered Emergency Operating Procedure 5.3.1, Secondary

Containment Control, Revision 18. In response to the high pressure in secondary

containment, the operators placed REA-DPIC-1B in manual and restored secondary

containment vacuum to greater than the technical specification minimum of 0.25 inch of

vacuum water gauge.

An event investigation conducted by the licensee concluded that the missed procedural

step was caused by poor planning and preparation and less than adequate self and peer

checks.

- 22 - Enclosure

Analysis. The failure of licensee personnel to follow surveillance procedures associated

with reactor building ventilation isolation valve testing was a performance deficiency.

The finding was more than minor because it affected the human performance attribute of

the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical

design barriers (fuel cladding, reactor coolant system, and containment) protect the

public from radionuclide releases caused by accidents or events. Using Inspection

Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings,

the inspectors determined this finding to be of very low safety significance (Green)

because it only represented a degradation of the radiological barrier function provided

for by the standby gas treatment system. The inspectors determined that this finding

had a cross-cutting aspect the area of human performance associated with the work

practices component because the licensee failed to use human error prevention

techniques such as self and peer checking H.4(a).

Enforcement. Technical Specification 5.4.1.a, requires, in part, that written procedures

be established, implemented, and maintained as recommended in Regulatory Guide

1.33, Revision 2, Appendix A, dated February 1978. Paragraph 8.b, Section 2.b of

Regulatory Guide 1.33, Appendix A, requires specific procedures for surveillance tests

associated with containment isolation tests. Procedure OSP-CONT/IST-Q702, Reactor

Building Ventilation Isolation Valve Operability, Revision 8, is the licensee procedure

used to test secondary containment isolation valves. Step 7.1.13 of

Procedure OSP-CONT/IST-Q702 directed operators to restore reactor building

ventilation to a normal alignment in accordance with Procedure OSP-CONT/IST-Q702,

Reactor Building Ventilation Start, Revision 2. Contrary to this requirement, on

November 2, 2011, the licensee failed to complete SOP-HVAC/RB-START Step 7.1.13

as required. Specifically, operators started reactor building outside air fan ROA-FN-1A

and reactor building exhaust air fan REA-FN-1B at Step 5.1.5 of Procedure SOP-

HVAC/RB-START without first performing Steps 5.1.1 through 5.1.4. Because this

finding is of very low safety significance and was entered into the licensees corrective

action program as Action Request AR 00251613, the violation is being treated as a non-

cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000397/2011005-03, Missed Procedural Step Results in Secondary Containment

Pressure Excursion.

Cornerstone: Emergency Preparedness

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

.1 Review of Columbia Generating Station Emergency Plan, Revisions 51 through 54,

Procedure 13.1.1, Classifying the Emergency, Revision 39, and Procedure 13.1.1A,

Classifying the Emergency, Technical Bases, Revisions21-001 through 23.

a. Inspection Scope

The inspector performed in-office reviews of Columbia Generating Station Emergency

Plan, Revisions 51 through 54, Procedure 13.1.1, Classifying the Emergency,

- 23 - Enclosure

Revision 39, and Procedure 13.1.1A, Classifying the Emergency, Technical Bases,

Revisions21-001 through 23. These revisions:

• Added the Federal Emergency Management Agency to the list of agencies

responding to radiological emergencies under the National Response

Framework;

• Removed the requirement for Energy Northwest to inform the Fast Flux Test

Facility Control Room when site evacuation is initiated;

• Clarified that transient populations in the emergency planning zone are warned of

an emergency by outdoor sirens;

• Clarified that equipment for three environmental monitoring teams is stored

onsite, with one additional set of equipment stored at the Energy Northwest

Office Complex in Richland;

• Added coordination between the Columbia Generating Station Emergency Plan

and the emergency plan for remediation activities at the Department of Energy

618-11 Burial Ground;

• Clarified that radioactive or chemical releases from activities at the Department of

Energy 618-11 Burial Ground are classifiable when conditions onsite meet

applicable emergency action level thresholds;

• Added a requirement for the licensee to notify personnel at the Department of

Energy 618-11 Burial Ground when a site evacuation is initiated;

• Clarified that the Department of Energy 618-11 Burial Ground Project is

responsible for notifying the Columbia Generating Station Control Room of

radioactive, flammable, or toxic releases from the burial ground site;

• Added emergency action levels 9.3.U.4, Release of radioactive materials from

an event at 618-11 Burial Ground deemed detrimental to safe operation of the

plant, and 9.3.A.4, Release of radioactive materials from an event at 618-11

Burial Ground that has entered a CGS plant structure that jeopardizes operation

of systems required to maintain safe operations or to establish and maintain safe

shutdown;

• Added emergency plan section 5.5.1, 618-11 Burial Ground Protective Actions;

• Added Procedure 13.5.8, 618-11 Waste Burial Ground Remediation Project

Responsibilities, to Appendix 2, Emergency Plan Implementing Procedures;

• Changed the emergency action level Table 3 General Emergency value for

monitor PRM-RE-1C, Reactor Building Exhaust High, from 9.35E4

counts/second to 9.35E6 counts/second;

- 24 - Enclosure

• Changed thermoluminescent dosimeter (TLD) to dosimeter of legal record

(DDR);

• Changed the licensees dosimetry vendor from the Fermi-2 Dosimetry Laboratory

to Landauer, Inc.;

• Procedure 13.1.1, Classifying the Emergency, Revision 39, step 4.1.1, changed

when indications of abnormal occurrences are received by the Control Room

staff the Shift Manager shall to the Shift Manager should;

• Procedure 13.1.1A, Classifying the Emergency, Technical Bases, Revision 21-

001 changed the main steam line tunnel temperature referenced in the basis for

emergency action level 3.4.A.1 from 156 degrees to 164 degrees;

• Procedure 13.1.1A, Classifying the Emergency, Technical Bases, Revision 22,

changed notes in emergency action levels 2.2.S.1, Failure of RPS

instrumentation to complete or initiate an automatic reactor scram once a RPS

setpoint has been exceeded and manual scram was not successful, and 2.2.G.1,

Failure of the RPS to complete an automatic scram and manual scram was not

successful and there is indication of an extreme challenge to the ability to cool

the core, from declaration shall be based to declaration should be based;

• Procedure 13.1.1A, Classifying the Emergency, Technical Bases, Revision 22,

changed the note in emergency action level 8.1.U.1, Unexpected increase in

ISFSI radiation, from the average surface dose rates of each overpack shall not

exceed, to of each overpack should not exceed; and

• Procedure 13.1.1A, Classifying the Emergency, Technical Bases, Revision 23,

clarified that emergency action level 9.3.U.3, Release of toxic or flammable

gases affecting the Protected Area boundary deemed detrimental to safe

operation of the plant, is intended for uncontrolled processes, precluding small

or incidental releases or those not impacting structures needed for plant

operation.

These revisions also corrected and revised titles, made minor editorial corrections, and

corrected typographical errors.

These revisions were compared to their previous revisions, to the criteria of NUREG-

0654, Criteria for Preparation and Evaluation of Radiological Emergency Response

Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to Nuclear

Energy Institute Report 99-01, Emergency Action Level Methodology, Revision 4, and

to the standards in 10 CFR 50.47(b) to determine if the revisions adequately

implemented the requirements of 10 CFR 50.54(q). These reviews were not

documented in a safety evaluation report and did not constitute an approval of licensee-

generated changes; therefore, the revisions are subject to future inspection.

- 25 - Enclosure

These activities constitute completion of eight samples as defined in Inspection

Procedure 71114.04-05.

b. Findings

No findings were identified.

.2 Review of Columbia Generating Station Emergency Plan, Revision 55.

a. Inspection Scope

The inspector performed an on-site and in-office review of Columbia Generating Station

Emergency Plan, Revision 55. This revision:

• Deleted the Operations Support Center Information Coordinator emergency

response organization position;

• Deleted the Technical Support Center to Operations Support Center

Communicator emergency response organization position;

• Removed the stand-alone Operations Support Center located in the Yakima

Building and moved Operations Support Center functions to areas within the

existing Technical Support Center; and

• Deleted telecommunications links to the previous Operations Support Center in

the Yakima Building.

This revision was compared to its previous revision, to the criteria of NUREG-0654,

Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and

Preparedness in Support of Nuclear Power Plants, Revision 1, and to the standards in

10 CFR 50.47(b) to determine if the revisions adequately implemented the requirements

of 10 CFR 50.54(q). The inspector toured the areas designated for the Operations

Support Center during an onsite inspection August 8 - 12, 2011. This review was not

documented in a safety evaluation report and did not constitute an approval of licensee-

generated changes; therefore, the revision is subject to future inspection.

These activities constitute completion of one sample as defined in Inspection

Procedure 71114.04-05.

b. Findings

No findings were identified.

- 26 - Enclosure

1EP6 Drill Evaluation (71114.06)

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on November

1, 2011, to identify any weaknesses and deficiencies in classification, notification, and

protective action recommendation development activities. The inspectors observed

emergency response operations in the technical support center and the emergency

operations facility to determine whether the event classification, notifications, and

protective action recommendations were performed in accordance with procedures. The

inspectors also attended the licensee drill critique to compare any inspector-observed

weakness with those identified by the licensee staff in order to evaluate the critique and

to verify whether the licensee staff was properly identifying weaknesses and entering

them into the corrective action program. As part of the inspection, the inspectors

reviewed the drill package and other documents listed in the attachment.

These activities constitute completion of one sample as defined in Inspection

Procedure 71114.06-05.

b. Findings

No findings were identified.

.2 Training Observations

a. Inspection Scope

The inspectors observed a simulator training evolution for licensed operators on

December 13, 2011, which required emergency plan implementation by a licensee

operations crew. This evolution was planned to be evaluated and included in

performance indicator data regarding drill and exercise performance. The inspectors

observed event classification and notification activities performed by the crew. The

inspectors also attended the post-evolution critique for the scenario. The focus of the

inspectors activities was to note any weaknesses and deficiencies in the crews

performance and ensure that the licensee evaluators noted the same issues and entered

them into the corrective action program. As part of the inspection, the inspectors

reviewed the scenario package and other documents listed in the attachment.

These activities constitute completion of one sample as defined in Inspection

Procedure 71114.06-05.

b. Findings

No findings were identified.

- 27 - Enclosure

4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the

licensee for the third Quarter 2011 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 Mitigating Systems Performance Index - Heat Removal System (MS08)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance

index - heat removal system performance indicator for the period from the fourth quarter

2010 through the third quarter 2011. To determine the accuracy of the performance

indicator data reported during those periods, the inspectors used definitions and

guidance contained in NEI Document 99-02, Regulatory Assessment Performance

Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator

narrative logs, issue reports, event reports, mitigating systems performance index

derivation reports, and NRC integrated inspection reports for the period of October 2010

through September 2011, to validate the accuracy of the submittals. The inspectors

reviewed the mitigating systems performance index component risk coefficient to

determine if it had changed by more than 25 percent in value since the previous

inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any

problems had been identified with the performance indicator data collected or

transmitted for this indicator and none were identified. Specific documents reviewed are

described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index -

heat removal system sample as defined in Inspection Procedure 71151-05.

- 28 - Enclosure

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance

index - cooling water systems performance indicator for the period from the fourth

quarter 2010 through the third quarter 2011. To determine the accuracy of the

performance indicator data reported during those periods, the inspectors used definitions

and guidance contained in NEI Document 99-02, Regulatory Assessment Performance

Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator

narrative logs, issue reports, mitigating systems performance index derivation reports,

event reports, and NRC integrated inspection reports for the period of October 2010

through September 2011, to validate the accuracy of the submittals. The inspectors

reviewed the mitigating systems performance index component risk coefficient to

determine if it had changed by more than 25 percent in value since the previous

inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any

problems had been identified with the performance indicator data collected or

transmitted for this indicator and none were identified. Specific documents reviewed are

described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index -

cooling water system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems (71152)

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

Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical

Protection

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of

this report, the inspectors routinely reviewed issues during baseline inspection activities

and plant status reviews to verify that they were being entered into the licensees

corrective action program at an appropriate threshold, that adequate attention was being

given to timely corrective actions, and that adverse trends were identified and

addressed. The inspectors reviewed attributes that included the complete and accurate

- 29 - Enclosure

identification of the problem; the timely correction, commensurate with the safety

significance; the evaluation and disposition of performance issues, generic implications,

common causes, contributing factors, root causes, extent of condition reviews, and

previous occurrences reviews; and the classification, prioritization, focus, and timeliness

of corrective actions. Minor issues entered into the licensees corrective action program

because of the inspectors observations are included in the attached list of documents

reviewed.

These routine reviews for the identification and resolution of problems did not constitute

any additional inspection samples. Instead, by procedure, they were considered an

integral part of the inspections performed during the quarter and documented in

Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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

human performance issues for follow-up, the inspectors performed a daily screening of

items entered into the licensees corrective action program. The inspectors

accomplished this through review of the stations daily corrective action documents.

The inspectors performed these daily reviews as part of their daily plant status

monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Semi-Annual 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. The inspectors focused their review on repetitive equipment

issues, but also considered the results of daily corrective action item screening

discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human

performance results. The inspectors nominally considered the 6-month period of July

2011 through December 2011 although some examples expanded beyond those dates

where the scope of the trend warranted.

The inspectors also included issues documented outside the normal corrective action

program in major equipment problem lists, repetitive and/or rework maintenance lists,

- 30 - Enclosure

departmental problem/challenges lists, system health reports, quality assurance

audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the

licensees corrective action program trending reports. Corrective actions associated with

a sample of the issues identified in the licensees trending reports were reviewed for

adequacy.

These activities constitute completion of one semi-annual trend inspection sample as

defined in Inspection Procedure 71152-05.

b. Findings and Observations

The inspectors noted a continuing trend involving inadequate storage of equipment near

safety related equipment. Specifically, the following action requests were generated

documenting continuing weakness in complying with plant procedures PPM 10.2.53,

Scaffolding, Revision 38 and PPM 10.2.222, Seismic Storage Requirements for

Transient Equipment, Revision 1.

• Action Request 244730, Transient Equipment in Diesel Generator Number 1

area not placed in accordance with PPM 10.2.53.

• Action Request 247524, 55 gallon drums staged too close to safety related

equipment.

• Action Request 252323, Gang box located too close to safety related

equipment.

The inspectors verified that this adverse trend is being evaluated in the licensees

corrective action program as Action Request AR 245159245159.4 Selected Issue Follow-up Inspection

a. Inspection Scope

The inspectors reviewed several corrective action documents associated with secondary

containment to determine if the licensee correctly evaluated the reportability of each

item. Included in the review was a search of the licensees corrective action program for

the previous three years for keywords secondary containment inoperable.

These activities constitute completion of one in-depth problem identification and

resolution samples as defined in Inspection Procedure 71152-05.

c. Findings

No findings were identified.

- 31 - Enclosure

.5 In-depth Review of Operator Workarounds

a. Inspection Scope

On October 5, 2011, the inspectors reviewed the operations department burden list,

control room deficiencies, and operator work around list to determine if any operator

work arounds, either individually or collectively, could unnecessarily challenge mitigating

system performance or operators during event response. The inspectors verified that

Energy Northwest was identifying and documenting operator work around problems at

an appropriate threshold. Documents reviewed are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure

71152-05.

b. Findings

No findings were identified.

4OA3 Event Follow-up (71153)

.1 NRC Event Follow-up to the October 14, 2011, Magnitude 3.4 Earthquake Located near

Richland, Washington

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

Specification 5.4.1.a, Procedures for the failure of the licensee to follow the abnormal

procedure for earthquakes. Specifically, the licensee failed to take procedurally required

steps to re-calibrate seismic instruments within 30 days after entry into the abnormal

procedure.

Description. On September 3, 2011, while the plant was in a refueling outage, a

Magnitude 3.7 earthquake occurred, centered about four miles south of the plant.

Procedure ABN-Earthquake, Revision 6, was implemented immediately following the

earthquake. Operators walked down key safe-shutdown equipment and concluded there

was no system or structural damage due to the earthquake. The licensee determined in

Step 4.7 of ABN-Earthquake, that no emergency declaration was necessary since the

control room did not receive an alarm for minimum seismic earthquake exceeded or

operating basis earthquake exceeded. The minimum seismic detected annunciator

has a set point of .01g. In contrast, the operating basis earthquake and safe shutdown

earthquakes for Columbia Generating Station are .125g and .25g respectively.

On October 14, 2011, a Magnitude 3.4 earthquake, centered about four miles south of

the plant, was felt in the main control room and by other plant personnel. Operators

again entered abnormal procedure ABN-Earthquake which required walk downs of key

safe shutdown equipment. Following those walkdowns, the licensee concluded there

was no system or structural damage due to the earthquake. Similar to the September 3,

2011, earthquake, no emergency declaration was necessary since the control room did

- 32 - Enclosure

not receive an alarm for minimum seismic earthquake exceeded or operating basis

earthquake exceeded.

The inspectors reviewed the licensees response to the September 3 and October 14,

2011 earthquakes. The inspectors noted that not all available seismic monitoring

devices were functional during the September 3 and October 14, 2011, earthquakes

which complicated post earthquake evaluation. Specifically, since June 28, 2011, the

tri-axial accelerograph tape recorder SEIS-TR-3 had been inoperable due to a

non-functioning trigger switch and one of three tri-axial response spectrum recorders

had been inoperable due to a damaged recording reed. Additionally, since September

7, 2011, the seismic trigger for the tri-axial accelerographs was not functioning to start

the required tape recorders. The inspectors went on to identify that following the

September 3, 2011 earthquake the licensee failed to perform Step 4.21 of ABN-

Earthquake which required the licensee re-calibrate all seismic instruments within 30

days. Consequently, the failure to perform Step 4.21 resulted in the same instruments

being non-functional during the October 14, 2011, earthquake.

Following identification of this issue, the licensee performed calibrations of all seismic

instruments restoring the equipment to a function status on November 2, 2011.

Analysis. The failure to follow abnormal procedures associated with earthquake

response was a performance deficiency. The finding was more than minor because it

affected the human performance attribute of the Emergency Preparedness Cornerstone

objective to ensure the licensee is capable of implementing adequate measures to

protect the health and safety of the public in the event of a radiological emergency.

Specifically, seismic instrumentation is required following a seismic event to evaluate the

necessity of an emergency declaration and to determine the impact of strong motion on

structures, systems and components or the need for a reactor shutdown. Using

Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance

Determination Process the inspectors determined this finding to be of very low safety

significance (Green) because while some seismic instruments were non-functional and

that did complicate the operators response to the October 14, 2011 earthquake, the

non-functional instruments did not result in a loss of planning standard or risk-significant

planning standard function. The inspectors determined that this finding had a

cross-cutting aspect in the area of human performance associated with the work control

component because the licensee failed to appropriately plan work activities by

incorporating the need for planned contingencies such as those needed to recalibrate

seismic instruments following an earthquake H.3(a).

Enforcement. Technical Specification 5.4.1.a requires, in part, that written procedures

be established, implemented, and maintained as recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Paragraph 6.w. of Regulatory

Guide 1.33, Appendix A, requires specific procedures for acts of Nature (e.g., tornado,

flood, dam failure, earthquakes). On September 3, 2011, licensee Procedure

ABN-Earthquake, Revision 6, was implemented in response to a seismic event. Step

4.21 required that seismic instruments be re-calibrated within 30 days following entry

into the procedure. Contrary to this requirement, on October 3, 2011, the licensee failed

to re-calibrate all seismic instruments following the September 3, 2011 earthquake.

- 33 - Enclosure

Consequently, several required seismic instruments were non-functional during a similar

earthquake that occurred on October 14, 2011. Because this finding is of very low safety

significance and was entered into the licensees corrective action program as Action

Request AR 00251987, the violation is being treated as a non-cited violation consistent

with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000397/2011005-04, Failure

to Follow Earthquake Abnormal Procedure.

4OA6 Meetings

Exit Meeting Summary

On November 9, 2011, the inspector presented the results of in-office inspection of eight

changes to the licensee emergency plan and emergency plan implementing procedures to Mr.

D. Gregoire, Manager, Regulatory Affairs, and other members of the licensees 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 December 13, 2011, the inspector presented the results of in-office inspection of a change to

the licensee emergency plan to Mr. D. Gregoire, Manager, Regulatory Affairs, and other

members of the licensees 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 January 4, 2012, the inspectors presented the inspection results to Mr. B. Sawatzke, Vice

President Nuclear Generation/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 met the criteria of Section 2.3.2 of the NRC

Enforcement Policy for being dispositioned as a non-cited violation:

Title 10 of the Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control,

requires, in part, that measures be established to assure that applicable regulatory requirements

and the design basis, for structures, systems, and components are correctly translated into

specifications, drawings, procedures, and instructions. Contrary to the above, on September 18,

1996, the licensee failed to adequately translate the design and licensing basis seismic

requirements for the residual heat removal system when installing shielding on valves RHR-V-

144A, RHR-V-144B and RHR-V-145B under RFTS-96-10-003. Specifically, the licensee failed

to account for the additional weight of the shielding that would add mechanical stress to the

systems piping during a safe shutdown earthquake. Following discovery by the licensee, the

shielding on valves RHR-V-144A, RHR-V-144B and RHR-V-145B was removed. Subsequent

evaluation by the licensee revealed that the additional shielding would add substantial stresses

to the system piping but the stresses would still be below design specifications. This finding was

- 34 - Enclosure

entered in the licensees corrective action program as Action Requests AR 00250306. This

finding is greater than minor because it was associated with the design control attribute of the

Mitigating Systems 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. This finding is of very low safety significance because it was a

design or qualification deficiency confirmed not to result in a loss of operability or functionality.

.

- 35 - Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

B. Adami, Manager, Technical Services

J. Bekhazi, Manager, Maintenance

D. Brown, Manager, Operations

K. Christianson, Regulatory Affairs, Licensing Engineer

M. Davis, Manager, Radiological Services

Z. Dunham, Supervisor, Licensing

C. England, Manager, Chemistry

A. Fahnestock, Manager, Emergency Preparedness

R. Garcia, Licensing Engineer

C. Golightly, Root Cause Analyst

D. Gregoire, Manager, Regulatory Affairs

C. King, Assistant Plant General Manager

B. MacKissock, Plant General Manager

D. Mand, Manager, Design Engineering

C. Moon, Manager, Training

B. Sawatzke, Vice President Nuclear Generation/Chief Nuclear Officer

B. Sherman, BPA, Nuclear Engineer

S. Wood, Manager, Organizational Effectiveness

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None.

Opened and Closed

Failure to Follow Work Instructions when Fabricating a Gagging Device

05000397-2011005-01 FIN

for Main Condenser Hotwell Surge Bypass Valve (Section 1R12)

Failure to Include Appropriate Acceptance Criteria in Offsite Power

05000397-2011005-02 NCV

Alignment Procedure (Section 1R15)

Missed Procedural Step Results in Secondary Containment Pressure

05000397-2011005-03 NCV

Excursion (Section 1R22)05000397-2011005-04 NCV Failure to Follow Earthquake Abnormal Procedure (Section 4OA3)

A-1 Attachment

Closed

None.

Discussed

None.

LIST OF DOCUMENTS REVIEWED

Section 1RO1: Adverse Weather Protection

PROCEDURES

NUMBER TITLE REVISION

ABN-WIND Tornado/High Winds 22

SOP- Cold Weather Operations 19

COLDWEATHER-

OPS

ACTIONS REQUESTS

00249800 00250815 00252469

Section 1RO4: Equipment Alignment

DRAWINGS

NUMBER TITLE REVISION

M520 Flow Diagram HPCS and LPCS Systems Reactor Building 98

M522 Flow Diagram Standby Liquid Control System Reactor 37

Building

M521-3 Flow Diagram Residual Heat Removal Loop C 8

PROCEDURES

NUMBER TITLE REVISION

ISP-SEIS-S401 Triaxial Time History Accelrograph Functional Check 1

ISP-SEIS-X301 Triaxial Time History Accelrograph Channel Calibration 5

ISP-SEIS-X302 Peak Acceleration Recorder Par 400 - CC 0

OSP-SW-M103 HPCS Service Water Valve Position Verification 17

A-2 Attachment

PROCEDURES

NUMBER TITLE REVISION

SOP-DG3-STBY High Pressure Core Spray Diesel Generator Standby Lineup 12

SOP-HPCS- Placing HPCS in Standby Status 2

STBY

SOP-RHR-LU RHR System Valve and Breaker Lineup 2

SOP-SLC-LU SLC System Valve and Breaker Lineup 0

ACTION REQUESTS

00201671 00207848 02005222 00245254 00247873

00243476 00243593 00244059 00248593 00249214

00244468 00245216 00245253 00251207 00251351

00248005 00248056 00248440 00249694 00249806

00251206

WORK ORDER 29078547

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION /

DATE

Design Specification for Division 15 Section 15A.3 General 5

Piping and Mechanical Installation

ANSI/ANS-2.2- Earthquake instrumentation Criteria for Nuclear Power Plants September 5,

1978 1978

QID 144025 Flexible Couplings and Hoses 2

Section 1RO5: Fire Protection

PROCEDURES

NUMBER TITLE REVISION

15.3.17 Fire Door Operability - Semiannual, Annual and Biennial 6

A-3 Attachment

ACTION REQUEST

00247367

WORK ORDER 02000988

Section 1RO6: Flood Protection Measures

ACTION REQUESTS

00237290 249867 249729 249178

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

Calc 5.51.58 Flooding Safe Shutdown Analysis 4

CCER No. 03- Component CER Summary Sheet HPCS-PS-3A, HPCS-PS- 0

002 3B

EC 2074 HPCS-LS-3A and HPCS-LS-3B Replacement 0

ME-02-02-02 Table of Pump Room/Stairwell Flooding Scenarios 1

Section 1RO7: Heat Sink Performance

PROCEDURES

NUMBER TITLE REVISION

PPM 8.4.62 Thermal Performance Monitoring of DCW-HX-1B1 and DCW- 8

HX-1B2

DRAWINGS

NUMBER TITLE REVISION

M512-3 Flow Diagram Diesel Oil and Miscellaneous Systems Diesel 36

Generator Building

SW-283-1.5 To Loop B Return from DG-ENG-1B 8

22029 Washington Public Power Supply System Engine Jacket E

Water Heat Exchanger Tandem 20-645-E4 4650KW

Generator Set

A-4 Attachment

ACTION REQUEST

00254538

WORK ORDERS

01107072 01183223 01198321

Section 1R11: Licensed Operator Requalification

PROCEDURES

NUMBER TITLE REVISION

TDI-08 Licensed Operator Requalification program 8

PPM 5.1.1 RPV Control 19

PPM 13.1.1 Classifying the Emergency 37

PPM 5.1.2 RPV Controls - ATWS 20

PPM 5.2.1 Primary Containment Control 19

PPM 5.3.1 Secondary Containment Control 18

OI-15 EOP and EAL Clarifications 21

PPM 5.5.1 Overriding ECCS Valve Logic to Allow Throttling RPV 6

Injection

Section 1R12: Maintenance Effectiveness

ACTION REQUESTS

00216276 00219734 00249959 00251720 00252156

00253693

PROCEDURES

NUMBER TITLE REVISION

4.840.A3 840.A3 Annunciator Panel Alarms 17

DRAWINGS

NUMBER TITLE REVISION /

DATE

A-12802-M-2A Cast Steel Bolted Bonnet Globe Valve w/ Duplex Gear December 5,

Operator 1973

Temporary Gag for COND-V-170- Information Only N/A

A-5 Attachment

WORK ORDER 01188696

Section 1R13: Maintenance Risk Assessment and Emergent Work Controls

PROCEDURES

NUMBER TITLE REVISION

1.3.76 Integrated Risk Management 29

1.3.83 Protected Equipment Program 8

1.5.14 Risk Assessment and Management for 22

Maintenance/Surveillance Activities

Section 1R15: Operability Evaluations

PROCEDURES

NUMBER TITLE REVISION

DES-2-9 Technical Evaluations 18

PPM 1.3.66 Operability and Functionality Evaluation 20

PPM 1.3.67 Operational Decision Making Process 10

SWP-CAP-01 Corrective Action Program 24

ACTION REQUESTS

00219624 00248876 00248877 00249891 00249535

00250009 00250150 00250306 00250415 00250490

00252299 00254047 00254858

WORK ORDER 01107071

Section 1R18: Plant Modifications

NUMBER TITLE REVISION /

DATE

OSP-SLC/IST- Standby Liquid Control Pumps Operability Test 22

Q701

A-6 Attachment

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

Calculation CE Standby Liquid Control Test Tank Structural Evaluation 0

02-10-14

AD-11-0260 Applicability Determination for Licensing Basis Changes 0

Section 1R19: Postmaintenance Testing

PROCEDURES

NUMBER TITLE REVISION

10.18.3 Reactor Feedwater Pump Overhaul 12

10.25.169 Maintenance and Repair of Limitorque Valve Operators - 11

Model SMB and SB 0 Through 4

ESP- LPCI Pump A Start - LOCA Time Delay Relay, E-RLY- 8

RLYRHRA621- RHRA/62/1 - CC

B301

SWP-TST-01 Post Maintenance Testing Program 14

ACTION REQUESTS

00248704 00248809 00252176

WORK ORDERS

01177825 01179637 001196711 01190703 02001104

02003493 02002110 02013230 02013055

MISCELLANEOUS DOCUMENT

NUMBER TITLE REVISION /

DATE

ASME Section XI Work Plan Number 2-2419 N/A

A-7 Attachment

Section 1R20: Refueling and Other Outage Activities

PROCEDURES

NUMBER TITLE REVISION /

DATE

3.1.1 Master Startup Checklist 50

3.1.2 Reactor Plant Startup 74

ACTION REQUEST

00249102

Section 1R22: Surveillance Testing

PROCEDRUES

NUMBER TITLE REVISION

OSP-CONT/IST- CSP and CEP Containment Isolation Valve Operability 11

Q701

OSP-CONT/IST- Reactor Building Ventilation Isolation Valve Operability 8

Q702

OSP-ELEC-S703 HPCS Diesel Generator Semi-Annual Operability Test 48

OSP-INST-H101 Shift and Daily Instrument Checks (Modes 1, 2, 3) 73

PPM 5.3.1

SOP-HVAC/RB- Reactor Building Ventilation Start 2

START

OSP-RHR/IST- RHR Loop A Operability Test 31

Q702

OI-17 System Availability Tracking 0

1.5.14 Risk Assessment and Management for 22

Maintenance/Surveillance Activities

ACTION REQUEST

00251613

WORK ORDERS

02007056 02007123 02010572

A-8 Attachment

Section 1EP6: Drill Evaluation

PROCEDURES

NUMBER TITLE REVISION

ABN-Flooding Flooding 12

5.1.1 RPV Control 19

5.1.2 RPV Control - ATWS 20

5.1.3 Emergency RPV Depressurization 18

5.1.4 RPV Flooding 9

5.4.1 Radioactive Release Control 14

10.25.156 Emergency Light Inspection - Annual 7

13.1.1 Classifying the Emergency 39

SAG-1 RPV and Primary Containment Flooding 2

SAG-2 Containment and Radioactive Release Control 3

ACTION REQUESTS

00251608 00251652 00251658 00251695 00252031

Section 4OA1: Performance Indicator Verification

PROCEDURES

NUMBER TITLE REVISION

SOP-SW-START Standby Service Water System Start 4

SOP-SW-LU Standby Service Water System Valve and Breaker Lineup 3

ACTION REQUESTS

00234051 00234141 00239952 00248836 00249423

MISCELLANEOUS DOCUMENTS

NUMBER TITLE REVISION

MSPI-01-BD- Mitigating System Performance Index (MSPI) Basis 11

0001 Document

A-9 Attachment

Section 4OA2: Identification and Resolution of Problems

PROCEDURES

NUMBER TITLE REVISION

1.3.81 Maintaining Plant Component Status Control 4

10.20.18 Division 3 Diesel Generator Engine 2/4/6/12 Year 0

Preventative Maintenance

OI-9 Operations Standards and Expectation 49

SWP-CAP-01 Corrective Action Program 24

ACTION REQUESTS

00035504 00231240 00213502 00242217 00244452

00244730 00244905 00245139 00245159 00245996

00247524 00247710 00249287 00252282 00252323

Section 4OA3: Event Follow-up

PROCEDURES

NUMBER TITLE REVISION

ABN-Earthquake Earthquake 6

ACTION REQUEST

00219734

Section 4OA7: Licensee-Identified Violations

ACTION REQUEST

00250306

A-10 Attachment