Text

IR 05000382-09-004; on July 8, 2009 Through October 7, 2009; Waterford Steam Electric Station, Unit 3; Operability Evaluations
	ML093230675
Person / Time
Site:	Waterford
Issue date:	11/18/2009
From:	Clark J; NRC/RGN-IV/DRP/RPB-E
To:	Kowalewski J; Entergy Operations
References
	IR-09-004
	Download: ML093230675 (35)
	v • d • e

UNITED STATES

NUCLEAR REGULATORY COMMISSION

R E GI ON I V

612 EAST LAMAR BLVD, SUITE 400

ARLINGTON, TEXAS 76011-4125

November 18, 2009

Joseph Kowalewski, Vice President, Operations

Entergy Operations, Inc.

Waterford Steam Electric Station, Unit 3

17265 River Road

Killona, LA 70057-3093

Subject:

WATERFORD STEAM ELECTRIC STATION, UNIT 3 - NRC INTEGRATED

INSPECTION REPORT 05000382/2009-004

Dear Mr. Kowalewski:

On October 7, 2009, the U.S. Nuclear Regulatory Commission completed an inspection at your

Waterford Steam Electric Station, Unit 3. The enclosed integrated inspection report documents

the inspection findings, which were discussed on October 1, 2009, with you and other members

of your staff.

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

compliance with the Commissions rules and regulations and with the conditions of your license.

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

personnel.

This report documents one NRC identified finding of very low safety significance (Green). This

finding was determined to involve a violation of NRC requirements. However, because of the

very low safety significance and because it was entered into your corrective action program, the

NRC is treating this finding as a noncited violation, consistent with Section VI.A.1 of the NRC

Enforcement Policy. If you contest the violation or the significance of the noncited violation, you

should provide a response within 30 days of the date of this inspection report, with the basis for

your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,

Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear

Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas,

76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,

Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Waterford Steam Electric

Station, Unit 3 facility. In addition, if you disagree with the characterization of any finding in this

report, you should provide a response within 30 days of the date of this inspection report, with

the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC

Resident Inspector at Waterford Steam Electric Station, Unit 3. The information you provide will

be considered in accordance with Inspection Manual chapter 0305.

Entergy Operations, Inc.

- 2 -

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

enclosure, will be available electronically for public inspection in the NRC Public Document

Room or from the Publicly Available Records component of NRCs document system (ADAMS).

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

Public Electronic Reading Room).

Sincerely,

/RA/

Jeffrey A. Clark, P.E.

Chief, Project Branch E

Division of Reactor Projects

Docket: 50-382

License: NPF-38

Enclosure:

NRC Inspection Report 05000382/2009004

w/Attachment: Supplemental Information

cc w/Enclosure:

Senior Vice President

Entergy Nuclear Operations

P.O. Box 31995

Jackson, MS 39286-1995

Senior Vice President and

Chief Operating Officer

Entergy Operations, Inc.

P.O. Box 31995

Jackson, MS 39286-1995

Vice President, Operations Support

Entergy Services, Inc.

P.O. Box 31995

Jackson, MS 39286-1995

Senior Manager, Nuclear Safety

and Licensing

Entergy Services, Inc.

P.O. Box 31995

Jackson, MS 39286-1995

Site Vice President

Waterford Steam Electric Station, Unit 3

Entergy Operations, Inc.

17265 River Road

Killona, LA 70057-0751

Entergy Operations, Inc.

- 3 -

Director

Nuclear Safety Assurance

Entergy Operations, Inc.

17265 River Road

Killona, LA 70057-0751

General Manager, Plant Operations

Waterford 3 SES

Entergy Operations, Inc.

17265 River Road

Killona, LA 70057-0751

Manager, Licensing

Entergy Operations, Inc.

17265 River Road

Killona, LA 70057-3093

Chairman

Louisiana Public Service Commission

P.O. Box 91154

Baton Rouge, LA 70821-9154

Parish President Council

St. Charles Parish

P.O. Box 302

Hahnville, LA 70057

Director, Nuclear Safety & Licensing

Entergy, Operations, Inc.

440 Hamilton Avenue

White Plains, NY 10601

Louisiana Department of Environmental

Quality, Radiological Emergency Planning

and Response Division

P.O. Box 4312

Baton Rouge, LA 70821-4312

Chief, Technological Hazards Branch

FEMA Region VI

800 North Loop 288

Federal Regional Center

Denton, TX 76209

Entergy Operations, Inc.

- 4 -

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

Deputy Regional Administrator (Chuck.Casto@nrc.gov)

DRP Director (Dwight.Chamberlain@nrc.gov)

DRP Deputy Director (Anton.Vegel@nrc.gov)

DRS Director (Roy.Caniano@nrc.gov)

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

Senior Resident Inspector (Mark.Haire@nrc.gov)

Resident Inspector (Dean.Overland@nrc.gov)

Branch Chief, DRP/E (Jeff.Clark@nrc.gov)

Senior Project Engineer, DRP/E (Ray.Azua@nrc.gov)

WAT Site Secretary (Linda.Dufrene@nrc.gov)

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

Branch Chief, DRS/TSB (Michael.Hay@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

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

OEMail Resource

Regional State Liaison Officer (Bill.Maier@nrc.gov)

NSIR/DPR/EP (Steve.LaVie@nrc.gov)

DRS STA (Dale.Powers@nrc.gov)

OEDO RIV Coordinator (Leigh.Trocine@nrc.gov)

ROPreports

File located: R:\\_REACTORS\\_WAT\\2009\\WAT 2009004 RP-DHO.doc

SUNSI Rev Compl.

Yes No

ADAMS

Yes No

Reviewer Initials

Publicly Avail

Yes No

Sensitive

Yes : No

Sens. Type Initials

RIV:SRI:DRP/E

SPE/DRP/E

C:DRS/EB1

C:DRS/EB2

DHOverland

RAzua

TRFarnholtz

NFOKeefe

/RA/RAzua for

/RA/

11/17/09

11/12/09

C:DRS/OB

C:DRS/PSB1

C:DRS/PSB2

C:DRP/E

SGarchow

MPShannon

GEWerner

JAClark

/RA/

/RA/RAzua for

11/17/2009

11/13/09

E11/11/09

11/17/09

OFFICIAL RECORD COPY

T=Telephone E=E-mail

F=Fax

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket:

05000382

License:

NFP-38

Report:

05000382/2009004

Licensee:

Entergy Operations, Inc.

Facility:

Waterford Steam Electric Station, Unit 3

Location:

Hwy. 18

Killona, LA

Dates:

July 8, 2009 through October 7, 2009

Inspectors:

D. Overland, Senior Resident Inspector

R. Egli, Branch Chief, TTC

R. Hickok, Senior Reactor Technology Instructor, TTC

G. Replogle, Senior Project Engineer, RIV

M. Chambers, Resident Inspector, Cooper Nuclear Station

P. Jayroe, Project Engineer, RIV

T. Buchanan, Project Engineer, RIV

S. Anderson, General Engineer, HQ

L. Carson II, Senior Health Physicist

Approved By:

Jeff Clark, Chief, Project Branch E

Division of Reactor Projects

- 1 -

Enclosure

SUMMARY OF FINDINGS

IR 05000382/2009004; July 8, 2009 through October 7, 2009; Waterford Steam Electric Station,

Unit 3; Operability Evaluations.

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

baseline inspections by regional based inspectors. One Green noncited violation of significance

was identified. The significance of most findings is indicated by their color (Green, White,

Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process.

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: Mitigating Systems

Green. The inspectors identified a Green non-cited violation of technical specification 3.3.1, Reactor Protective Instrumentation. The technical specifications require all four

channels (A, B, C, and D) of local power density, departure from nucleate boiling ratio,

and reactor coolant flow instruments to be operable when in Mode 1. These Channel B

instruments require an input from the Channel B log power instrument, which was

previously declared inoperable. With the Channel B log power instrument inoperable,

the Channel B local power density, departure from nucleate boiling ratio, and reactor

coolant flow instruments should also have been declared inoperable. The licensee

entered this finding in their corrective action program as condition reports CR-WF3-

2009-4401 and CR-WF3-2009-4407.

The failure to either trip or bypass the inoperable channels within one hour was more

than minor because it affected the configuration control attribute of the mitigating

systems cornerstone. Specifically, deliberate operator action was required to ensure that

proper reactor protection system coincidence and reliability were maintained. Also, if left

uncorrected, the potential existed for Channel B reactor protective trips to be

inadvertently removed while at power. The failure to meet the technical specifications

was considered to be of very low safety significance (Green), since there was no actual

loss of safety function. This finding has a cross-cutting aspect in the decision-making

component of the human performance area because the licensee failed to verify the

validity of underlying assumptions and identify unintended consequences of failing to

comply with technical specification 3.3.1 by declaring the log power Channel B

inoperable and not placing local power density, departure from nucleate boiling ratio,

and reactor coolant flow instrument channels in either bypass or trip condition (H.1.b).

(Section 1R15)

B.

Licensee-Identified Violations

None

- 2 -

Enclosure

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period on July 8, 2009, at 100 percent power and remained at

approximately 100 percent power for the rest 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 thunderstorms with potential tornados and high winds were forecast in the vicinity

of the facility for October 4, 2009, the inspectors reviewed the licensees overall

preparations/protection for the expected weather conditions. The inspectors evaluated

the licensee staffs documented preparations against the sites procedures and

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 inspector's evaluated operator staffing and

accessibility of controls and indications for those systems required to control the plant.

Additionally, the inspectors reviewed the Updated Final Safety Analysis Report and

verified that operator actions were appropriate as specified by plant-specific procedures.

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

These activities constitute completion of one readiness for impending adverse weather

condition sample as defined in Inspection Procedure 71111.01-05.

b.

Findings

No findings of significance 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:

July 22, 2009: Chemical volume control Train A

August 12, 2009: Emergency feedwater Train A

August 13, 2009: Low pressure safety injection Train B

August 18, 2009: Emergency feedwater Train AB

September 15, 2009: High pressure safety injection system Train A

- 3 -

Enclosure

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, Updated Final Safety Analysis Report, 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 walked down accessible

portions of the systems to verify system components and support equipment were

aligned correctly and operable. The inspectors examined the material condition of the

components and observed operating parameters of equipment to verify that there were

no obvious deficiencies. The inspectors also verified that the licensee had properly

identified and resolved equipment alignment problems that could cause initiating events

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

corrective action program with the appropriate significance characterization. Specific

documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five partial system walkdown samples as

defined in Inspection Procedure 71111.04-05.

b.

Findings

No findings of significance were identified.

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:

July 21, 2009: Reactor auxiliary building fire Zones 8B, 8C, 11, and 12

July 22, 2009: Reactor auxiliary building fire Zones 33, 35, 38, and 39

July 30, 2009: Reactor auxiliary building fire Zones 3, 5, and 6

August 3, 2009: Fire Zones Roof E and Roof W

August 11, 2009: Reactor auxiliary building fire Zone 16

August 18, 2009: Reactor auxiliary building fire Zones 33, 35, 36, 37, 38, and 39

August 19, 2009: Reactor auxiliary building fire Zone 32

August 20, 2009: Reactor auxiliary building fire Zones 2, Roof E, and Roof W

August 23, 2009: Reactor auxiliary building fire Zones 11, 12,13, 8B, and 8C

August 24, 2009: Reactor auxiliary building fire Zones 15, 16, 17, 18, 19, 20,

and 21

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

protection program that adequately controlled combustibles and ignition sources within

- 4 -

Enclosure

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 ten quarterly fire-protection inspection samples

as defined in Inspection Procedure 71111.05-05.

b.

Findings

No findings of significance were identified.

.2

Annual Fire Protection Drill Observation (71111.05A)

a.

Inspection Scope

On September 23, 2009, the inspectors observed a fire brigade activation as the result

of a simulated fire at feed heater drain Pump C. The observation evaluated the

readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee

staff identified deficiencies, openly discussed them in a self-critical manner at the drill

debrief, and took appropriate corrective actions. Specific attributes evaluated were:

(1) proper wearing of turnout gear and self-contained breathing apparatus; (2) proper

use and layout of fire hoses; (3) employment of appropriate fire fighting techniques;

(4) sufficient firefighting equipment brought to the scene; (5) effectiveness of fire brigade

leader communications, command, and control; (6) search for victims and propagation of

the fire into other plant areas; (7) smoke removal operations; (8) utilization of pre

planned strategies; (9) adherence to the preplanned drill scenario; and (10) drill

objectives.

These activities constitute completion of one annual fire-protection inspection sample as

defined in Inspection Procedure 71111.05-05.

b.

Findings

No findings of significance were identified.

- 5 -

Enclosure

1R11 Licensed Operator Requalification Program (71111.11)

a.

Inspection Scope

On August 4, 2009, 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 pre-established

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 of significance were identified.

1R12 Maintenance Effectiveness (71111.12Q)

a.

Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk

significant systems:

August 11, 2009: Seal leakage on chemical volume control charging pumps

September 3, 2009: Review of operating experience smart sample FY 2009-01,

Inspection of electrical connections for motor control center, circuit breakers and

interfaces

- 6 -

Enclosure

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

No findings of significance were identified.

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:

July 29, 2009: Scheduled elective maintenance outage for containment fan

coolers Train B to calibrate containment fan cooler Header B CCW return

temperature control valve solenoid Valve CC-835B

- 7 -

Enclosure

August 3, 2009: Scheduled surveillance of reactor protection system Channel A

September 9, 2009: Scheduled activity to remove high pressure safety injection

Pump AB from high pressure safety injection Train A alignment and align high

pressure safety injection Pump A to Train A

September 11, 2009: Emergent maintenance to replace station Battery AB,

Cell 31 with a spare cell due to degraded cell voltage

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 four maintenance risk assessments and

emergent work control inspection samples as defined in Inspection

Procedure 71111.13-05.

b.

Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a.

Inspection Scope

The inspectors reviewed the following issues:

July 14, 2009: Low individual cell voltage on vital 125 vdc station Battery AB

Cell 39

August 11, 2009: Unplanned load variations during emergency diesel generator

Train A surveillance

August 12, 2009: Emergency diesel generator Train A Relay EG EREL 2342(J)

found out of calibration during surveillance

August 20, 2009: Channel B local power density, departure from nucleate boiling

ratio, and reactor coolant flow instruments, when Channel B log power

instrument was inoperable

- 8 -

Enclosure

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

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

adequacy of the evaluations to ensure that 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 Updated

Safety Analysis Report to the licensees evaluations, to determine whether the

components or systems were operable. Where compensatory measures were required

to maintain operability, the inspectors determined whether the measures in place would

function as intended and were properly controlled. The inspectors determined, where

appropriate, compliance with bounding limitations associated with the evaluations.

Additionally, the inspectors 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.

These activities constitute completion of four 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 3.3.1, Reactor Protective Instrumentation. The technical specifications

require all four channels (A, B, C, and D) of local power density, departure from nucleate

boiling ratio, and reactor coolant flow instruments to be operable when in Mode 1.

These Channel B instruments require an input from the Channel B log power instrument,

which was previously declared inoperable. With the Channel B log power instrument

inoperable, the Channel B local power density, departure from nucleate boiling ratio, and

reactor coolant flow instruments should also have been declared inoperable.

Description: On Aug 20, 2009, the inspector observed the performance of procedure

MI-003-126, Revision 14, Core Protection Calculator Functional. During the

performance of the test procedure, the inspector noted that CPC Channel B high log

power trip was bypassed. The inspector asked why technical specification 3.3.1 had not

been entered due to the inoperable log power Channel B instrument. Technical

specification 3.3.1, Reactor Protective Instrumentation, requires that the reactor

protective instrumentation channels and bypasses contained in Table 3.3-1 be operable

in accordance with the requirements of the table. Table 3.3-1 requires all four channels

of local power density (LPD), departure from nucleate boiling ratio (DNBR), and reactor

coolant flow instruments to be operable in Mode 1.

Log power Channel B provides a high log power automatic bypass removal signal for

LPD, DNBR, and reactor coolant flow instrumentation channels. Technical specification 3.3.1, Table 3.3-1 requires the high log power bypass shall be automatically removed

when reactor power is greater than or equal to 10-4% of rated thermal power. When in

Mode 1, reactor power is greater than 10-4% of rated thermal power. The inspectors

determined that when a log power instrument is out of service, the automatic removal of

the high log power bypass function is inoperable and thus the associated protective

channels of LPD, DNBR, and reactor coolant flow are also inoperable.

- 9 -

Enclosure

The log power Channel B instrument was originally declared inoperable on Sept 1, 2008.

The operability determination concluded that since the plant was in Mode 4, only two log

power channels were required, therefore entry into technical specification 3.3.1 was not

required. On Sept 9, 2008, the plant entered Mode 2 with log power Channel B still

inoperable. The operability was not revised to reflect the change in plant conditions. In

accordance with technical specification 3.3.1, operators should have taken action to

place the associated LPD, DNBR, and reactor coolant flow protective channels to either

bypass or trip within one hour.

On Aug 22, 2009, after considering the inspectors question, the licensee declared LPD

Channel B and DNBR Channel B inoperable, and placed both instruments in bypass.

During a subsequent control room tour, the inspector verified that LPD and DNBR were

bypassed, however noticed that reactor coolant flow Channel B had not been bypassed.

The inspector asked the shift manager if technical specification 3.3.1, Table 3.3-1

notation (C) affected any other trips. Upon further assessment, operations personnel

determined that reactor coolant low flow was also affected and declared steam

generator flow Channel B to be inoperable, as well.

Analysis: The failure to either trip or bypass the inoperable channels within one hour

was more than minor because it affected the configuration control attribute of the

mitigating systems cornerstone. Specifically, deliberate operator action was required to

ensure that proper reactor protection system coincidence and reliability were maintained.

Also, if left uncorrected, the potential existed for Channel B reactor protective trips to be

inadvertently removed while at power. The failure to meet the technical specifications

was considered to be of very low safety significance (Green), since there was no actual

loss of safety function. This finding has a cross-cutting aspect in the decision-making

component of the human performance area because the licensee failed to verify the

validity of underlying assumptions and identify unintended consequences of failing to

comply with technical specification 3.3.1 by declaring the log power Channel B

inoperable and not placing DNBR, LPD, and reactor coolant flow channels in either

bypass or trip condition (H.1.b).

Enforcement: Technical specification 3.3.1, Reactor Protective Instrumentation,

requires all four channels of LPD, DNBR, and reactor coolant flow to be operable and

able to have the high log power bypass automatically removed when reactor power is

greater than or equal to 10-4% percent of rated thermal power. Contrary to this, on

September 9, 2008, the licensee did not comply with the limiting condition for operation

action statement for technical specification 3.3.1 which states, the inoperable channel is

placed in either the bypassed or tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The plant remained in

this condition until August 22, 2009. This violation has been determined to be of very

low safety significance and was entered into their corrective action program in condition

reports CR-WF3-2009-4401 and CR-WF3-2009-4407. Therefore, this violation is being

treated as a non-cited violation (NCV), consistent with Section VI.A.1 of the NRC

Enforcement Policy.

- 10 -

Enclosure

1R18 Plant Modifications (71111.18)

a.

Inspection Scope

The inspectors reviewed the following temporary/permanent modifications to verify that

the safety functions of important safety systems were not degraded:

August 26, 2009: Permanent modification of containment vacuum relief valves

such that once the valves are automatically opened, they remain open until

manually closed.

August 7, 2009: Temporary modification to revise the setpoint for the reactor

coolant Pump 2A upper thrust bearing high temperature alarm to reduce

nuisance alarms in the control room.

September 14, 2009: Temporary modification to replace station Battery AB, Cell

31 with a new cell. The old Cell 31 was left in place and jumpered around, while

the new Cell 31 was installed at the end of the battery rack.

The inspectors reviewed the temporary modification and the associated safety

evaluation screening against the system design bases documentation, including the

Updated Final Safety Analysis Report 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.

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 for

the modification listed below. 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

appropriateness of modification design assumptions, and 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 three samples for temporary and permanent

plant modifications as defined in Inspection Procedure 71111.18-05

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Enclosure

b.

Findings

No findings of significance 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:

June 23, 2009: Replacement of high pressure safety injection Pump B Tyco time

delay relay following the failure of the relay to start the pump during a routine

surveillance test

July 23, 2009: Replacement of seal package on chemical volume control

charging Pump B to reduce reactor coolant system unidentified leakage

July 29, 2009: Scheduled elective maintenance calibration of containment fan

cooler Header B CCW return temperature control valve solenoid Valve CC-835B

August 4, 2009: Corrective maintenance to repair the actuator for steam

generator SG1 main steam atmospheric dump Valve MS-116A

August 11, 2009: Scheduled preventative maintenance to clean, inspect, and

test emergency diesel generator Train A Relay EG EREL 2342(J)

September 9, 2009: Scheduled preventative maintenance to replace the

pulsation dampener and perform motor maintenance on chemical volume control

charging Pump AB

September 14, 2009: Emergent maintenance to replace station Battery AB,

Cell 31 with a spare cell, due to degraded voltage on the cell

September 29, 2009: Scheduled preventative maintenance to check the

overcurrent trip on the breaker for non-nuclear safety return header isolation

Valve CC-562.

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 (as applicable):

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

adequate for the maintenance performed

Acceptance criteria were clear and demonstrated operational readiness; test

instrumentation was appropriate

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Enclosure

The inspectors evaluated the activities against the technical specifications, the Updated

Final Safety Analysis Report, 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 eight postmaintenance testing inspection

sample(s) as defined in Inspection Procedure 71111.19-05.

b.

Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a.

Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, procedure

requirements, and technical specifications to ensure that the six 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

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

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Enclosure

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.

August 6, 2009: Safety related electrical Bus 3A undervoltage relay calibration

August 10, 2009: Emergency diesel generator Train A surveillance

August 20, 2009: Core protection calculator Train B surveillance

August 22, 2009: Plant protection system Channel B surveillance

August 24, 2009: Emergency diesel generator and subgroup relays Train B

September 14, 2009: High pressure safety injection Train AB

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

These activities constitute completion of six surveillance testing inspection samples as

defined in Inspection Procedure 71111.22-05.

b.

Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06)

.1

Training Observations

a.

Inspection Scope

The inspectors observed a training evolution for licensed operators on September 17,

2009, 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

postevolution 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.

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Enclosure

b.

Findings

No findings of significance were identified.

2.

RADIATION SAFETY

Cornerstone: Occupational and Public Radiation Safety

2OS2 ALARA Planning and Controls (71121.02)

a.

Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual and

collective radiation exposures ALARA. The inspector used the requirements in 10 CFR

Part 20 and the licensees procedures required by technical specifications as criteria for

determining compliance. The inspector interviewed licensee personnel and reviewed:

Current 3-year rolling average collective exposure

Five outage work activities scheduled during the inspection period and

associated work activity exposure estimates which were likely to result in the

highest personnel collective exposures

Site-specific trends in collective exposures, plant historical data, and source-term

measurements

Five work activities of highest exposure significance completed during the last

outage

ALARA work activity evaluations, exposure estimates, and exposure mitigation

requirements

Intended versus actual work activity doses and the reasons for any

inconsistencies

Person-hour estimates provided by maintenance planning and other groups to

the radiation protection group with the actual work activity time requirements

Post-job (work activity) reviews

Assumptions and basis for the current annual collective exposure estimate, the

methodology for estimating work activity exposures, the intended dose outcome,

and the accuracy of dose rate and man-hour estimates

Method for adjusting exposure estimates, or re-planning work, when unexpected

changes in scope or emergent work were encountered

Exposure tracking system

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Enclosure

Exposures of individuals from selected work groups

Records detailing the historical trends and current status of tracked plant source

terms and contingency plans for expected changes in the source term due to

changes in plant fuel performance issues or changes in plant primary chemistry

Declared pregnant workers during the current assessment period, monitoring

controls, and the exposure results

Self-assessments, audits, and special reports related to the ALARA program

since the last inspection

Resolution through the corrective action process of problems identified through

post-job reviews and post-outage ALARA report critiques

The inspector completed 11 of the required 15 samples and 5 of the optional samples as

defined in IP 71121.02-05.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

.1

Data Submission Issue

a.

Inspection Scope

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

quarter of 2009 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 of significance were identified.

.2

Safety System Functional Failures

a.

Inspection Scope

The inspectors sampled licensee submittals for the Safety System Functional Failures

performance indicator for the period from the second quarter of 2008 through the second

quarter of 2009. To determine the accuracy of the performance indicator data reported

during those periods, performance indicator definitions and guidance contained in NEI

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5,

and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73" definitions

and guidance were used. The inspectors reviewed the licensees operator narrative

logs, operability assessments, maintenance rule records, maintenance work orders,

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Enclosure

issue reports, event reports and NRC Integrated Inspection reports for the period

beginning the second quarter of 2008 through the second quarter of 2009 to validate the

accuracy of the submittals. 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 safety system functional failures sample as

defined in Inspection Procedure 71151-05.

b.

Findings

No findings of significance were identified.

.3

Mitigating Systems Performance Index - Emergency ac Power System

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index (MSPI) - Emergency ac Power System performance for the period from the

second quarter of 2008 through the second quarter of 2009. To determine the accuracy

of the performance indicator data reported during those periods, performance indicator

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

Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the

licensees operator narrative logs, mitigating systems performance index derivation

reports, issue reports, event reports and NRC integrated inspection reports for the period

beginning the second quarter of 2008 through the second quarter of 2009 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

emergency ac power system sample as defined in Inspection Procedure 71151-05.

b.

Findings

No findings of significance were identified.

.4

Mitigating Systems Performance Index - Cooling Water Systems

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index - Cooling Water Systems performance for the period from the second quarter of

2008 through the second quarter of 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

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

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Enclosure

Performance Indicator Guideline, Revision 5, was used. 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