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IR 05000454-09-003, 05000455-09-003; on April 01, 2009 - June 30, 2009; Byron Station, Units 1 & 2; Operability Evaluations
	ML092190925
Person / Time
Site:	Byron
Issue date:	08/07/2009
From:	Richard Skokowski; Region 3 Branch 3
To:	Pardee C; Exelon Generation Co
References
	FOIA/PA-2010-0209 IR-09-003
	Download: ML092190925 (43)
	v • d • e

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION III

2443 WARRENVILLE ROAD, SUITE 210

LISLE, IL 60532-4352

August 7, 2009

Mr. Charles G. Pardee

Senior Vice President, Exelon Generation Company, LLC

President and Chief Nuclear Officer (CNO), Exelon Nuclear

4300 Winfield Road

Warrenville IL 60555

SUBJECT:

BYRON STATION, UNITS 1 AND 2 INTEGRATED INSPECTION

REPORT 05000454/2009003; 05000455/2009003

Dear Mr. Pardee:

On June 30, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated

inspection at your Byron Station, Units 1 and 2. The enclosed inspection report documents the

inspection findings which were discussed on July 8, 2009, with D. Enright and other members of

your staff.

The inspection 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.

Based on the results of this inspection, one NRC-identified finding of very low safety

significance was identified. The finding involved a violation of NRC requirement. Additionally,

licensee identified violations which were determined to be of very low safety significance are

listed in Section 4OA7 of this report. However, because of their very low safety significance,

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

the issues as non-cited violations (NCVs) in accordance with Section VI.A.1 of the NRC

Enforcement Policy.

If you contest the subject or severity of a Non-Cited 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,

DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory

Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,

Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001;

and the Resident Inspector Office at the Byron Station. 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 III, and the NRC Resident Inspector at Byron Station. The information

you provide will be considered in accordance with Inspection Manual Chapter 0305.

C. Pardee

-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 (PARS) component of NRC's document system

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

Public Electronic Reading Room).

Sincerely,

/RA/

Richard A. Skokowski, Chief

Branch 3

Division of Reactor Projects

Docket Nos. 50-454; 50-455

License Nos. NPF-37; NPF-66

Enclosure: Inspection Report No. 05000454/2009-003

and 05000455/2009-003

w/Attachment: Supplemental Information

cc w/encl:

Site Vice President - Byron Station

Plant Manager - Byron Station

Manager Regulatory Assurance - Byron Station

Senior Vice President - Midwest Operations

Senior Vice President - Operations Support

Vice President - Licensing and Regulatory Affairs

Director - Licensing and Regulatory Affairs

Manager Licensing - Braidwood, Byron, and LaSalle

Associate General Counsel

Document Control Desk - Licensing

Assistant Attorney General

Illinois Emergency Management Agency

J. Klinger, State Liaison Officer,

Illinois Emergency Management Agency

P. Schmidt, State Liaison Officer, State of Wisconsin

Chairman, Illinois Commerce Commission

B. Quigley, Byron Station

C. Pardee

-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 (PARS) component of NRC's document system

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

Public Electronic Reading Room).

Sincerely,

/RA/

Richard A. Skokowski, Chief

Branch 3

Division of Reactor Projects

Docket Nos. 50-454; 50-455

License Nos. NPF-37; NPF-66

Enclosure: Inspection Report No. 05000454/2009-003

and 05000455/2009-003

w/Attachment: Supplemental Information

cc w/encl:

Site Vice President - Byron Station

Plant Manager - Byron Station

Manager Regulatory Assurance - Byron Station

Senior Vice President - Midwest Operations

Senior Vice President - Operations Support

Vice President - Licensing and Regulatory Affairs

Director - Licensing and Regulatory Affairs

Manager Licensing - Braidwood, Byron, and LaSalle

Associate General Counsel

Document Control Desk - Licensing

Assistant Attorney General

Illinois Emergency Management Agency

J. Klinger, State Liaison Officer,

Illinois Emergency Management Agency

P. Schmidt, State Liaison Officer, State of Wisconsin

Chairman, Illinois Commerce Commission

B. Quigley, Byron Station

DISTRIBUTION:

See next page

DOCUMENT NAME: G:\\BYRO\\Byron 2009 003.doc

G Publicly Available

G Non-Publicly Available

G Sensitive

G Non-Sensitive

To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy

OFFICE

RIII

NAME

RNg:dtp

RSkokowski

DATE

08/07/09

OFFICIAL RECORD COPY

Letter to C. Pardee from Richard Skokowski dated August 7, 2009

SUBJECT:

BYRON STATION, UNITS 1 AND 2 INTEGRATED INSPECTION REPORT

05000454/2009-003; 05000455/2009-003

DISTRIBUTION:

Susan Bagley

RidsNrrDorlLpl3-2 Resource

RidsNrrPMByron Resource

RidsNrrDirsIrib Resource

Cynthia Pederson

Kenneth OBrien

Jared Heck

Allan Barker

Jeannie Choe

Linda Linn

DRPIII

DRSIII

Patricia Buckley

Tammy Tomczak

ROPreports Resource

Enclosure

U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos:

50-454; 50-455

License Nos:

NPF-37; NPF-66

Report Nos:

05000454/2009003 and 05000455/2009003

Licensee:

Exelon Generation Company, LLC

Facility:

Byron Station, Units 1 and 2

Location:

Byron, IL

Dates:

April 1, 2009, through June 30, 2009

Inspectors:

B. Bartlett, Senior Resident Inspector

J. Robbins, Resident Inspector

J. Cassidy, Senior Health Physicist

A. Garmoe, Braidwood Resident Inspector

R. Ng, Project Engineer

M. Phalen, Health Physicist

C. Thompson, Resident Inspector, Illinois Department of

Emergency Management

Observer:

J. Dalzell

Approved by:

R. Skokowski, Chief

Branch 3

Division of Reactor Projects

Enclosure

TABLE OF CONTENTS

SUMMARY OF FINDINGS ......................................................................................................... 1

REPORT DETAILS ..................................................................................................................... 2

Summary of Plant Status......................................................................................................... 2

1.

REACTOR SAFETY .................................................................................. 2

1R01

Adverse Weather Protection (71111.01) .................................................... 2

1R04

Equipment Alignment (71111.04) ............................................................... 4

1R05

Fire Protection (71111.05) ......................................................................... 4

1R06

Flooding (71111.06) ................................................................................... 5

1R11

Licensed Operator Requalification Program (71111.11) ............................. 6

1R12

Maintenance Effectiveness (71111.12) ...................................................... 6

1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13).. 7

1R15

Operability Evaluations (71111.15) ............................................................ 8

1R18

Plant Modifications (71111.18) ................................................................. 11

1R19

Post-Maintenance Testing (71111.19) ..................................................... 11

1R22

Surveillance Testing (71111.22) .............................................................. 12

1EP6

Drill Evaluation (71114.06) ....................................................................... 14

2.

RADIATION SAFETY .............................................................................. 14

2OS3

Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

................................................................................................................ 14

2PS1

Radioactive Gaseous And Liquid Effluent Treatment And Monitoring

Systems (71122.01) ................................................................................. 18

4.

OTHER ACTIVITIES ................................................................................ 21

4OA1

Performance Indicator Verification (71151) .............................................. 21

4OA2

Identification and Resolution of Problems (71152) ................................... 22

4OA5

Other Activities......................................................................................... 25

4OA6

Management Meetings ............................................................................ 27

4OA7

Licensee-Identified Violations .................................................................. 27

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

Key Points of Contact .............................................................................................................. 1

List of Items Opened, Closed and Discussed .......................................................................... 2

List of Documents Reviewed ................................................................................................... 3

List of Acronyms Used ............................................................................................................ 9

1

Enclosure

SUMMARY OF FINDINGS

IR 05000454/2009-003, 05000455/2009-003; April 01, 2009 - June 30, 2009; Byron Station,

Units 1 & 2; Operability Evaluations.

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

baseline inspections by regional inspectors. One Green finding was identified by the inspectors.

The finding was considered a Non-Cited Violation of NRC regulations. The significance of most

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

(IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not

apply may be Green or be assigned a severity level after NRC management review. The NRCs

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 and Self-Revealed Findings

Cornerstone: Initiating Event

Green. A finding of very low safety significance and associated Non-Cited Violation of

Technical Specification 3.4.13.B was identified by the NRC inspectors on June 24, 2009,

when reactor coolant pressure boundary leakage was identified on a Unit 2 process

sampling line and the licensee continued to operate the unit but did not repair or isolate

the leak within the Technical Specification Limiting Condition for Operation requirement

of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The licensee entered this issue into the corrective action program and

replaced the leaking section of pipe.

The inspectors concluded that the finding was greater than minor in accordance with

Appendix E, Example 2a, of IMC 0612, regarding situations when Technical

Specification limits were exceeded. The finding was determined to be of very low safety

significance after an SDP Phase 2 evaluation. The issue had been entered into the

licensees corrective action program as Issue Report (IR) 934800. The primary cause

for this finding was related to the cross-cutting area of Human Performance and its

associated component for Decision Making (H.1(b)) because licensee management

personnel concluded that this leak did not represent reactor coolant pressure boundary

leakage due to the closure of an isolation valve. (Section 1R15)

B.

Licensee-Identified Violations

Violations of very low safety significance that were identified by the licensee have been

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

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

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

2

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power throughout the inspection period with one exception. On

June 4, 2009, power was reduced to 89.7 percent for maintenance activities on the position

indicator for turbine governor valve Number 4. Power was restored to 100 percent the following

day.

Unit 2 operated at or near full power throughout the inspection period with two exceptions. On

April 25, 2009, power was reduced by 200 MWe in response to an urgent request from the grid

operator. Power was restored to 100 percent the next day. On June 18, 2009, power was

reduced to 90 percent and then to 80 percent on June 19, 2009, in response to requests from

the grid operator. Power was restored to 100 percent the following day.

1.

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

.1

Readiness of Offsite and Alternate Alternating Current (AC) Power Systems

a.

Inspection Scope

The inspectors verified that plant features and procedures for operation and continued

availability of offsite and alternate AC power systems during adverse weather were

appropriate. The inspectors reviewed the licensees procedures affecting these areas

and the communications protocols between the transmission system operator (TSO) and

the plant to verify that the appropriate information was being exchanged when issues

arose that could impact the offsite power system. Examples of aspects considered in

the inspectors review included:

The coordination between the TSO and the plant during off-normal or emergency

events;

The explanations for the events;

The estimates of when the offsite power system would be returned to a normal

state; and

The notifications from the TSO to the plant when the offsite power system was

returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and

maintain availability and reliability of both the offsite AC power system and the onsite

alternate AC power system prior to or during adverse weather conditions. Specifically,

the inspectors verified that the procedures addressed the following:

3

Enclosure

The actions to be taken when notified by the TSO that the post-trip voltage of the

offsite power system at the plant would not be acceptable to assure the

continued operation of the safety-related loads without transferring to the onsite

power supply;

The compensatory actions identified to be performed if it would not be possible to

predict the post-trip voltage at the plant for the current grid conditions;

A re-assessment of plant risk based on maintenance activities that could affect

grid reliability, or the ability of the transmission system to provide offsite power;

and

The communications between the plant and the TSO when changes at the plant

could impact the transmission system, or when the capability of the transmission

system to provide adequate offsite power was challenged.

Specific documents reviewed during this inspection are listed in the Attachment. The

inspectors also reviewed Corrective Action Program (CAP) items to verify that the

licensee was identifying adverse weather issues at an appropriate threshold and

entering them into their CAP in accordance with station corrective action procedures.

This inspection constitutes one readiness of offsite and alternate AC power systems

sample as defined in Inspection Procedure (IP) 71111.01-05.

b.

Findings

No findings of significance were identified.

.2

Summer Seasonal Readiness Preparations

a.

Inspection Scope

The inspectors performed a review of the licensees preparations for summer weather

for selected systems, including conditions that could lead to an extended drought as a

result of high temperatures.

During the inspection, the inspectors focused on plant specific design features and the

licensees procedures used to mitigate or respond to adverse weather conditions.

Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)

and performance requirements for systems selected for inspection, and verified that

operator actions were appropriate as specified by plant specific procedures. Specific

documents reviewed during this inspection are listed in the Attachment. The inspectors

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

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

station corrective action procedures. The inspectors reviews focused specifically on the

following plant systems:

Switchyard; and

Non-Essential Service Water.

This inspection constitutes one seasonal adverse weather sample as defined in

IP 71111.01-05.

4

Enclosure

b.

Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

.1

Quarterly Partial System Walkdowns

a.

Inspection Scope

The inspectors performed a partial system walkdown of the following risk-significant

system:

Unit 1 Train B Diesel Fuel Oil while Unit 1 Train A Diesel Generator was

out-of-service.

The inspectors selected this system based on its risk significance relative to the reactor

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

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

potentially increase risk. The inspectors reviewed applicable operating procedures,

system diagrams, UFSAR, Technical Specification (TS) requirements, 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 CAP

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

Attachment.

These activities constituted one partial system walkdown sample as defined in

IP 71111.04-05.

b.

Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1

Routine Resident Inspector Tours (71111.05Q)

a.

Inspection Scope

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

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

plant areas:

5

Enclosure

Division 11 Misc. Electrical Equipment and Battery Room (Zone 5.6-1);

Unit 1 Electrical Penetration Area (Zone 11.5A-1);

Unit 2 Electrical Penetration Area (Zone 11.5A-2);

Unit 1 Train B Diesel Fuel Oil Storage Tank Room (Zone 10.1-1); and

Unit 1 Train B Diesel Generator and Day Tank Room (Zone 9.1-1).

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

protection program that adequately controlled combustibles and ignition sources within

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

passive fire protection features in good material condition, and 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 impact equipment which could initiate or mitigate a

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

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

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

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

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

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

during the inspection were entered into the licensees CAP. Documents reviewed are

listed in the Attachment to this report.

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

IP 71111.05-05.

b.

Findings

No findings of significance were identified.

1R06 Flooding (71111.06)

.1

Internal Flooding

a.

Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee

procedures intended to protect the plant and its safety-related equipment from internal

flooding events. The inspectors reviewed flood analyses and design documents,

including the UFSAR, engineering calculations, and abnormal operating procedures to

identify licensee commitments. The specific documents reviewed are listed in the

Attachment to this report. In addition, the inspectors reviewed licensee drawings to

identify areas and equipment that may be affected by internal flooding caused by the

failure or misalignment of nearby sources of water, such as the fire suppression or the

circulating water systems. The inspectors also reviewed the licensees corrective action

documents with respect to past flood-related items identified in the corrective action

program to verify the adequacy of the corrective actions. The inspectors performed a

walkdown of the following plant areas to assess the adequacy of watertight doors and

verify drains and sumps were clear of debris and were operable, and that the licensee

complied with its commitments:

6

Enclosure

AB - 346' Elevation - SX piping in the General Area; and

AB - 330' Elevation - SX Pump Rooms.

This inspection constituted two internal flooding samples as defined in IP 71111.06-05.

b.

Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

.1

Resident Inspector Quarterly Review (71111.11Q)

a.

Inspection Scope

On May 6, 2009, the inspectors observed a crew of licensed operators in the plants

simulator during licensed operator requalification examinations 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;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

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

expectations and successful critical task completion requirements. Documents reviewed

are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program

sample as defined in IP 71111.11.

b.

Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

.1

Routine Quarterly Evaluations (71111.12Q)

a.

Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk

significant systems:

7

Enclosure

Unit 2 Bus 211 Grounding Issues;

Unit 1 and Unit 2 Boric Acid System Degraded Boric Acid Tank Liners;

Unit 1 and Unit 2 Main Power System Classified as (a)(1) Under Maintenance

Rule; and

Unit 2 Train B Station Air System due to Multiple Trip Events.

The inspectors reviewed events such as where ineffective equipment maintenance had

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

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

problems in terms of the following:

implementing appropriate work practices;

identifying and addressing common cause failures;

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

characterizing system reliability issues for performance;

charging unavailability for performance;

trending key parameters for condition monitoring;

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

verifying appropriate performance criteria for structures, systems, and

components (SSCs)/functions classified as (a)(2) or appropriate and adequate

goals and corrective actions for systems classified as (a)(1).

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

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

effectiveness issues were entered into the CAP with the appropriate significance

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

This inspection constituted four quarterly maintenance effectiveness samples as defined

in IP 71111.12-05.

b.

Findings

No findings of significance were identified.

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

.1

Maintenance Risk Assessments and Emergent Work Control

a.

Inspection Scope

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

maintenance and emergent work activities affecting risk-significant and safety-related

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

prior to removing equipment for work:

0A Main Control Room Ventilation Train Loss of Control Room Differential

Pressure;

Unit 1 Train A Diesel Generator out of service while Unit 2 Station Auxiliary

Transformer 242-1 was out of service;

8

Enclosure

Unit 2 Auxiliary Feedwater Flow Control Valves Failed Open for Calibration while

Unit 1 Essential Service Water (SX) Return Header Isolation Valve and Unit 0

Component Cooling Heat Exchanger Isolation Valve were out-of-service (OOS);

Unit 1 Train B Diesel Generator out of service while Unit 1 Train A SX Suction

Isolation Valve was unable to close;

Unit Common 0SX10BA Piping, Possible Thru Wall Leak; and

Unit 1 Condenser Piping Leak that was not Isolable.

These activities were selected based on their potential risk significance relative to the

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

risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate

and complete. When emergent work was performed, the inspectors verified that the

plant risk was promptly reassessed and managed. The inspectors reviewed the scope

of maintenance work, discussed the results of the assessment with the licensee's

probabilistic risk analyst or shift technical advisor, and verified plant conditions were

consistent with the risk assessment. The inspectors also reviewed TS requirements and

walked down portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met. Documents

reviewed are listed in the Attachment to this report.

These maintenance risk assessments and emergent work control activities constituted

six samples as defined in IP 71111.13-05.

b.

Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

.1

Operability Evaluations

a.

Inspection Scope

The inspectors reviewed the following issues:

Unit 1 Train B Auxiliary Feedwater Gear Box and Right Angle Gear Drive High

Vibrations;

Unit 1 Nuclear Instrument Power Range Different than Computer Calorimetric;

Movement of a Heavy Load over the Dry Cask in the Cask Loading Pit;

Assessment of the Diesel Oil Storage Tank Vents being Non-Seismic and

Non-Tornado Proof;

Assessment of Bus 211 Operability due to Grounding Issues;

Unit 1 Circulating Water Piping Leak;

Unit 1 Reactor Coolant System Pressure Boundary Leakage;

Pressurizer Powered Operated Relief Valve Accumulator 2A Low Pressure

Alarm; and

Essential Service Water Make Up Pump 0A Discharge Check Valve Leakage.

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

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

9

Enclosure

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

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

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

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

whether the components or systems were operable. Where compensatory measures

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

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

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

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

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

associated with operability evaluations. Documents reviewed are listed in the

Attachment to this report.

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

b.

Findings

(1) Failure to Comply with Technical Specifications Regarding Reactor Coolant Pressure

Boundary (RCPB) Leakage

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

TS 3.4.13.B was identified by the NRC inspectors on June 26, 2009, when RCPB

leakage was identified but not repaired or isolated within the TS Limiting Condition for

Operation requirement of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

Description: On June 24, 2009, during a routine containment entry at power, licensee

personnel identified a pinhole leak (one drop every 5 minutes) on a welded connection

inside the Unit 2 containment (IR 934800). The welded connection is on line 2PS01BB

and the line is 3/8 inch in diameter. This line is a pressurizer liquid sample line and is a

non-safety related non-American Society of Mechanical Engineer (ASME) code, class

D pipe. The licensee verified that valve 2PS9350B upstream of the leak was closed and

that both containment isolation valves downstream of the leak were closed. Based on

the upstream valve being closed and in the Shift Managers opinion being isolated, and

with the remaining leakage being not significant, the leak was not considered by licensee

personnel to be RCPB leakage.

10 CFR 50.2, defines RCPB as all those pressure-containing components of boiling

and pressurized water-cooled nuclear power reactors, such as pressure vessels, piping,

which are connected to the reactor coolant system, up to and including any and all

of the following The outermost containment isolation valve in system piping which

penetrated primary reactor containment. TS 1.1 define pressure boundary leakage

as LEAKAGE (except primary to secondary LEAKAGE) through a nonisolable fault in an

RCS component body, pipe wall, or vessel wall.

The portion of the line with the through wall leak is a part of the RCPB as the line is

connected to the pressurizer, which is a part of the reactor coolant system (RCS) and

was located before the innermost containment isolation valve. Though isolation valve

2PS9350B was closed, the leakage out of the pipe continued which demonstrated that

the isolation valve was leaking by and the leak was not fully isolated. As such, there

was a fault through a RCS component pipe wall which was not isolable. Technical

10

Enclosure

Specification 3.4.13.B had an allowable value of No pressure boundary LEAKAGE with

a requirement that if pressure boundary leakage existed to be in Mode 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The NRC inspectors consulted regional management and headquarters personnel

related to this issue. On June 26, 2009 at 4:30 p.m., the licensee was informed that in

NRCs opinion, the leak was RCPB leakage and that TS 3.4.13.B should have been

entered. The licensee acknowledged the NRC opinion and immediately entered

TS 3.4.13.B.

The licensee had begun repair efforts earlier in the day on June 26, 2009. The repair

was completed; post maintenance testing was performed and the licensee exited the

TS at 8:07 p.m. on June 26.

The inspectors determined by a review of the records that licensee personnel exited

Unit 1 containment on June 24, 2009, at 1:41 p.m. Using that time as the start time, the

inspectors calculated that it took the licensee 55 hours6.365741e-4 days 0.0153 hours 9.093915e-5 weeks 2.09275e-5 months and 26 minutes to repair the pipe

and to exit the TS. This was 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months and 26 minutes over the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months TS requirement.

Analysis: The inspectors determined that the licensees failure to comply with

TS 3.4.13.B was a performance deficiency warranting a significance evaluation.

The inspectors concluded that the issue was more than minor in accordance with

Appendix E, Example 2a, of Inspection Manual Chapter (IMC) 0612 regarding situations

when Technical Specification limits were exceeded.

The inspectors performed a significance determination process (SDP) of this issue using

IMC 0609, Attachment IMC 0609.04. The inspectors determined the finding fell under

the Initiating Events Cornerstone as a primary system loss of coolant accident initiator.

However, it did not represent a transient initiator contributor, did not represent a fire

initiator contributor, and was not an internal/external flooding initiator contributor. The

inspectors determined that, assuming the worst case degradation, the finding could

result in exceeding the TS limit for RCS leakage. This is because the TS limit for RCPB

leakage is zero and the actual leakage was one drop every 5 minutes. The inspectors

then performed a Phase 2 SDP using the risk informed inspection notebook. The

Phase 2 result was green.

The primary cause of this finding was related to the cross-cutting area of Human

Performance for Decision Making (H.1(b)) because licensee management personnel

concluded that this leak did not represent RCPB leakage as the isolation valve was

closed, even though it was known to have slight leak-by and determined that

TS 3.4.13.B was not required to be entered.

Enforcement: Technical Specification 3.4.13.B requires that there be no RCPB leakage.

If RCPB leakage exists, the licensee is required to repair the leak or to shutdown and be

in Mode 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Contrary to this requirement, starting on June 24, 2009, Unit 2

had through pipe wall RCPB leakage and the licensee did not repair or shut down the

leak for 55 hours6.365741e-4 days 0.0153 hours 9.093915e-5 weeks 2.09275e-5 months and 26 minutes. Because of the very low safety significance of the

issue and because the issue has been entered into the licensees CAP (IR 934800); the

issue is being treated as an NCV, consistent with Section VI.A.1, of the NRC

Enforcement Policy. (NCV 05000455/2009003-01)

11

Enclosure

(2) Diesel Oil Storage Tank Vents Being Non-Seismic and Non-Tornado Proof

No findings of significance were identified regarding this issue, however, a related

unresolved item is described in Section 40A5.1 of this report.

1R18 Plant Modifications (71111.18)

.1

Temporary Plant Modifications

a.

Inspection Scope

The inspectors reviewed the following temporary modifications:

Unit 2 Engineering Change 375313 Plugging of Gland Steam Leak on High

Pressure Turbine; and

Unit 1 Train B Auxiliary Feedwater Gear Box and Right Angle Gear Drive High

Vibrations.

The inspectors compared the temporary configuration changes and associated

10 CFR 50.59 screening and evaluation information against the design basis, the

UFSAR, and the TS, as applicable, to verify that the modification did not affect the

operability or availability of the affected systems. The inspectors also compared the

licensees information to operating experience information to ensure that lessons learned

from other utilities had been incorporated into the licensees decision to implement the

temporary modification. The inspectors, as applicable, performed field verifications to

ensure that the modifications were installed as directed; the modifications operated as

expected; modification testing adequately demonstrated continued system operability,

availability, and reliability; and that operation of the modifications did not impact the

operability of any interfacing systems. Lastly, the inspectors discussed the temporary

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

individuals were aware of how extended operation with the temporary modification in

place could impact overall plant performance. Documents reviewed are listed in the

Attachment to this report.

This inspection constituted two temporary modification samples as defined in

IP 71111.18-05.

b.

Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

.1

Post-Maintenance Testing

a.

Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that

procedures and test activities were adequate to ensure system operability and

functional capability:

12

Enclosure

Unit 2 Train B Diesel Driven Auxiliary Feedwater Pump Start Sequence Test

following Maintenance;

Pressurizer Liquid Space Sample Line Through Wall Leak Repair Leak Test;

Unit 2 Train B Solid State Protection System Surveillance following Corrective

Maintenance;

Unit 1 Essential Service Water Return Isolation Valve (1SX010) Test following

Breaker Work;

Unit 1 Containment Spray System Test following Repair of 1SX091A;

Unit 1 Train A Diesel Generator Test following Turning Gear Maintenance; and

SX Makeup Pump Test following Level Switch Replacement.

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

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

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

for the maintenance performed; acceptance criteria were clear and demonstrated

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

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

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

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

documentation was properly evaluated. The inspectors evaluated the activities against

TS, the UFSAR, 10 CFR 50 requirements, licensee procedures, and various

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

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

reviewed corrective action documents associated with post-maintenance tests to

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

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

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

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

IP 71111.19-05.

b.

Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

.1

Surveillance Testing

a.

Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether

risk-significant systems and equipment were capable of performing their intended safety

function and to verify testing was conducted in accordance with applicable procedural

and TS requirements:

Calibration of Reactor Coolant Pump Seal Water Injection Flow Loop (Routine);

Unit 1 Train B Diesel Generator Operability Semi-Annual Surveillance (Routine);

Unit 1 Auxiliary Feedwater Isolation Valve Stroke Time Testing (IST);

Unit 1Train B Auxiliary Feedwater Pump, Monthly Surveillance (Routine);

13

Enclosure

Unit 2 Diesel Driven Auxiliary Feedwater Pump Monthly Surveillance,

2BOSR 7.5.4-2, Revision 16 (Routine); and

Unit 2 Steam Generator Blowdown Containment Isolation Valve Stroke Time

Testing (IST).

The inspectors observed in plant activities and reviewed procedures and associated

records to determine some of the following:

did preconditioning occur;

were the effects of the testing adequately addressed by control room personnel

or engineers prior to the commencement of the testing;

were acceptance criteria clearly stated, demonstrated operational readiness, and

consistent with the system design basis;

plant equipment calibration was correct, accurate, and properly documented;

as-left setpoints were within required ranges; and the calibration frequency were

in accordance with TSs, the UFSAR, procedures, and applicable commitments;

measuring and test equipment calibration was current;

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

prerequisites described in the test procedures were satisfied;

test frequencies met TS requirements to demonstrate operability and reliability;

tests were performed in accordance with the test procedures and other

applicable procedures; jumpers and lifted leads were controlled and restored

where used;

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

test equipment was removed after testing;

where applicable for inservice testing activities, testing was performed in

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

Mechanical Engineers code, and reference values were consistent with the

system design basis;

where applicable, test results not meeting acceptance criteria were addressed

with an adequate operability evaluation or the system or component was

declared inoperable;

where applicable for safety-related instrument control surveillance tests,

reference setting data were accurately incorporated in the test procedure;

where applicable, actual conditions encountering high resistance electrical

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

prior procedure changes had not provided an opportunity to identify problems

encountered during the performance of the surveillance or calibration test;

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

performance of its safety functions; and

all problems identified during the testing were appropriately documented and

dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted four routine surveillance testing samples, and two inservice

testing samples, as defined in IP 71111.22, Sections -02 and -05.

14

Enclosure

b.

Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06)

.1

Training Observation

a.

Inspection Scope

The inspector observed a simulator training evolution for licensed operators on

June 18, 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 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 to this report.

This training inspection constituted one sample as defined in IP 71114.06-05.

b.

Findings

No findings of significance were identified.

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

.1

Inspection Planning and Identification of Instrumentation

a. Inspection Scope

The inspectors reviewed the licensees UFSAR to identify applicable radiation monitors

associated with measuring transient high and very high radiation areas, including those

intended for remote emergency assessment. The inspectors identified the types of

portable radiation detection instrumentation that were used for job coverage of high

radiation area work, including instruments for underwater surveys, portable and fixed

area radiation monitors that were used to provide radiological information in various

plant areas, and continuous air monitors that were used to assess airborne radiological

conditions and work areas with the potential for workers to receive a 50 millirem or

greater committed effective dose equivalent (CEDE). Whole body counters that were

used to monitor for internal exposure and those radiation detection instruments that were

used to conduct surveys for the release of personnel and equipment from the

15

Enclosure

radiologically controlled area (RCA), including contamination monitors and portal

monitors, were also identified.

This inspection constituted two samples as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

.2

Calibration and Testing of Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors reviewed radiological instrumentation to determine if it had been

calibrated as required by the licensees procedures, consistent with industry and

regulatory standards. The inspectors also reviewed alarm setpoints for selected

instruments to determine whether they were established consistent with the UFSAR or

TS, as applicable, and with industry practices and regulatory guidance. Specifically, the

inspectors reviewed calibration procedures and the most recent calibration records for

the following radiation monitoring instrumentation and calibration equipment:

Personnel Contamination Monitors;

Shepard Calibrator;

Telepoles;

Ion Chambers; and

Air Samplers.

The inspectors determined what actions were taken when, during calibration or source

checks, an instrument was found significantly out of calibration or exceeded as-found

acceptance criteria. Should that occur, the inspectors determined whether the licensees

actions would include a determination of the instruments previous uses and the possible

consequences of that use since the prior successful calibration. The inspectors also

reviewed the results of the licensees most recent 10 CFR 61 source term (radionuclide

mix) evaluations to determine if the radiation sources that were used for instrument

calibration and for instrument checks were representative of the plant source term.

The inspectors observed the licensees use of the portable survey instrument calibration

units, discussed calibrator output validation methods, and compared calibrator exposed

readings with calculated/expected values. The inspectors evaluated compliance with

licensee procedures while radiation protection (RP) personnel demonstrated the

methods for performing source checks of portable survey instruments and source

checks of personnel contamination and portal monitors.

This inspection constituted one sample as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

16

Enclosure

.3

Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed licensee corrective action program documents and any

Licensee Event Reports or special reports that involved personnel contamination monitor

alarms due to personnel internal exposures to determine whether identified problems

were entered into the corrective action program for resolution.

While no internal exposure with a CEDE greater than 50 millirem occurred since the last

inspection in this area, the inspectors reviewed the licensees methods for internal dose

assessment to determine if affected personnel would be properly monitored using

calibrated equipment and if the data would be analyzed and exposures properly

assessed.

This inspection constituted one sample as defined in IP 71121.03-5.

The inspectors reviewed corrective action program reports related to exposure

significant radiological incidents that involved radiation monitoring instrument

deficiencies since the last inspection in this area, as applicable. Members of the

RP staff were interviewed and corrective action documents were reviewed to determine

whether follow-up activities were being conducted in an effective and timely manner

commensurate with their importance to safety and risk based on the following:

Initial problem identification, characterization, and tracking;

Disposition of operability/reportability issues;

Evaluation of safety significance/risk and priority for resolution;

Identification of repetitive problems;

Identification of contributing causes;

Resolution of NCVs tracked in the corrective action system; and

Identification and implementation of effective corrective actions.

This inspection constituted one sample as defined in IP 71121.03-5.

The inspectors determined if the licensees self-assessment and audit activities

completed for the approximate 2-year period that preceded the inspection were

identifying and addressing repetitive deficiencies or significant individual deficiencies

in problem identification and resolution, as applicable.

This inspection constituted one sample as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

.4

Radiation Protection Technician Instrument Use

a. Inspection Scope

The inspectors verified that calibrations for those survey instruments used to perform job

coverage surveys and for those currently designated for use had not lapsed. The

17

Enclosure

inspectors determined if response checks of portable survey instruments and checks of

instruments used for unconditional release of materials and workers from the RCA were

completed prior to instrument use, as required by the licensees procedure. The

inspectors also discussed instrument calibration methods and source response check

practices with RP staff and observed staff demonstrate instrument source checks.

This inspection constituted one sample as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

.5

Self-Contained Breathing Apparatus Maintenance/Inspection and Emergency Response

Staff Qualifications

a. Inspection Scope

The inspectors reviewed the status and surveillance records of self-contained breathing

apparatus (SCBAs) that were staged in the plant and ready-for-use and evaluated the

licensees capabilities for refilling and transporting SCBA air bottles to-and-from the

control room and operations support center during emergency conditions. The

inspectors determined if control room staff and other emergency response and RP

personnel were trained, respirator fit tested, and medically certified to use SCBAs,

including personal bottle change-out. Additionally, the inspectors reviewed SCBA

qualification records for numerous members of the licensees radiological emergency

teams to determine if a sufficient number of staff were qualified to fulfill emergency

response positions, consistent with the licensees emergency plan and the requirements

of 10 CFR 50.47.

This inspection constituted one sample as defined in IP 71121.03-5.

The inspectors reviewed the qualification documentation for at least 50 percent of the

onsite, or as applicable, offsite contract personnel that performed maintenance on

manufacturer designated vital SCBA components. The inspectors also reviewed

vital component maintenance records for several SCBA units that were designated as

ready-for-use. The inspectors also evaluated, through record review and observations, if

the required air cylinder hydrostatic testing was documented and current and if the

Department of Transportation required retest air cylinder markings were in place for

several randomly selected SCBA units and spare air bottles. The inspectors reviewed

the onsite maintenance procedures governing vital component work, as applicable,

including those for the low-pressure alarm and pressure-demand air regulator. The

inspectors reviewed the licensees maintenance procedures and the SCBA

manufacturers recommended practices to determine if there were any inconsistencies

between them.

This inspection constituted one sample as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

18

Enclosure

Cornerstone: Public Radiation Safety

2PS1 Radioactive Gaseous And Liquid Effluent Treatment And Monitoring Systems (71122.01)

.1

Inspection Planning

a. Inspection Scope

The inspectors reviewed the configuration of the licensees gaseous and liquid effluent

processing systems to confirm that radiological discharges were properly mitigated,

monitored, and evaluated with respect to public exposure. The inspectors reviewed the

performance requirements contained in General Design Criteria 60 and 64 of

Appendix A to 10 CFR Part 50 and in the licensees Radiological Effluent Technical

Specifications (RETS) and Offsite Dose Calculation Manual (ODCM). The inspectors

also reviewed any abnormal radioactive gaseous or liquid discharges and any conditions

since the last inspection when effluent radiation monitors were out-of-service to verify

that the required compensatory measures were implemented. Additionally, the

inspectors reviewed the licensee=s quality control program to verify that the radioactive

effluent sampling and analysis requirements were satisfied and that discharges of

radioactive materials were adequately quantified and evaluated.

The inspectors reviewed each of the radiological effluent controls program requirements

to verify that the requirements were implemented as described in the licensees RETS.

For selected system modification since the last inspection, the inspectors reviewed

changes to the liquid or gaseous radioactive waste system design, procedures, or

operation, as described in the UFSAR and plant procedures.

The inspectors reviewed changes to the ODCM made by the licensee since the

last inspection to ensure consistency was maintained with respect to guidance in

NUREG-1301, 1302 and 0133 and Regulatory Guides 1.109, 1.21 and 4.1. If

differences were identified, the inspectors reviewed the licensees technical basis or

evaluations to verify that the changes were technically justified and documented.

The inspectors reviewed the radiological effluent release report(s) for 2007 and 2008 in

order to determine if anomalous or unexpected results were identified by the licensee,

entered in the CAP, and adequately resolved.

The inspectors reviewed any significant changes in reported dose values from the

previous radiological effluent release report, and the inspectors evaluated the

factors which may have resulted in the change. If the change was not explained as

being influenced by an operational issue (e.g., fuel integrity, extended outage, or major

decontamination efforts), the inspectors independently assessed the licensee=s offsite

dose calculations to verify that the licensees calculations were adequately performed

and were consistent with regulatory requirements.

The inspectors reviewed the licensees correlation between the effluent release reports

and the environmental monitoring results, as provided in Section IV.B.2 of Appendix I to

10 CFR Part 50.

This inspection constitutes one sample as defined by Inspection Procedure 71122.01-5.

19

Enclosure

b. Findings

No findings of significance were identified.

.2

Onsite Inspection

a. Inspection Scope

The inspectors performed a walkdown of selected components of the gaseous and liquid

discharge systems (e.g., gas compressors, demineralizers and filters (in use or in

standby), tanks, and vessels) and reviewed current system configuration with respect to

the description in the UFSAR. The inspectors evaluated temporary waste processing

activities, system modifications, and the equipment material condition. For equipment or

areas that were not readily accessible, the inspectors reviewed the licensee's material

condition surveillance records, as applicable. The inspectors reviewed any changes that

were made to the liquid or gaseous waste systems to verify that the licensee adequately

evaluated the changes and maintained effluent releases as low as reasonably

achievable.

During system walkdowns, the inspectors assessed the operability of selected point of

discharge effluent radiation monitoring instruments and flow measurement devices. The

effluent radiation monitor alarm set point values were reviewed to verify that the set

points were consistent with RETS/ODCM requirements.

For effluent monitoring instrumentation, the inspectors reviewed documentation to verify

the adequacy of methods and monitoring of effluents, including any changes to effluent

radiation monitor set-points. The inspectors evaluated the calculation methodology and

the basis for the changes to verify the adequacy of the licensees justification.

The inspectors observed the licensees sampling of liquid and gaseous radioactive

waste (e.g., sampling of waste steams) and observed selected portions of the routine

processing and discharge of radioactive effluents during the onsite inspection.

Additionally, the inspectors reviewed several radioactive effluent discharge permits and

assessed whether the appropriate treatment equipment was used and whether the

radioactive effluent was processed and discharged in accordance with RETS/ODCM

requirements, including the projected doses to members of the public.

The inspectors interviewed staff concerning effluent discharges made with inoperable

(declared out-of-service) effluent radiation monitors to determine if appropriate

compensatory sampling and radiological analyses were conducted at the frequency

specified in the RETS/ODCM. For compensatory sampling methods, the inspectors

reviewed the licensees practices to determine if representative samples were obtained

and if the licensee routinely relied on the use of compensatory sampling in lieu of

adequate system maintenance or calibration of effluent monitors.

The inspectors reviewed surveillance test results for non-safety-related ventilation and

gaseous discharge systems (high efficiency particulate air (HEPA) and charcoal

filtration) to verify that the systems were operating within the specified acceptance

criteria. In addition, the inspectors assessed the methodology the licensee used to

determine the stack/vent flow rates to verify that the flow rates were consistent with the

RETS/ODCM.

20

Enclosure

The inspectors reviewed the licensees program for identifying any normally

non-radioactive systems that may have become radioactively contaminated to determine

if evaluations (e.g. 10 CFR 50.59 evaluations) were performed per IE Bulletin 80-10.

The inspectors did not identify any unknown contaminated systems that may have been

unmonitored discharge pathways to the environment.

The inspectors reviewed instrument maintenance and calibration records

(i.e., both installed and counting room equipment) associated with effluent

monitoring and reviewed quality control records for the radiation measurement

instruments. The inspectors performed this review to identify any degraded

equipment performance and to assess corrective actions, as applicable.

The inspectors reviewed the radionuclides that were included by the licensee in its

effluent source term to determine if all applicable radionuclides were included (within

detectability standards) in the licensees evaluation of effluents. The inspectors

reviewed waste stream analyses (10 CFR Part 61 analyses) to determine if

hard-to-detect radionuclides were also included in the source term analysis.

The inspectors reviewed a selection of monthly, quarterly, and annual dose calculations

to ensure that the licensee had properly demonstrated compliance with 10 CFR 50,

Appendix I, and RETS dose criteria.

The inspectors reviewed licensee records to identify any abnormal gaseous or liquid

tank discharges (e.g., discharges resulting from misaligned valves, valve leak-by, etc) to

determine if the licensee had implemented the required actions. The inspectors

determined if abnormal discharges were assessed and reported as part of the Annual

Radioactive Effluent Release Report consistent with Regulatory Guide 1.21. There were

no abnormal releases reported in the 2007 and 2008 annual effluent release reports.

The inspectors reviewed the licensees effluent sampling records (sampling locations,

sample analyses results, flow rates, and source term) for radioactive liquid and gaseous

effluents to verify that the licensees information satisfied the requirements of

10 CFR 20.1501.

This inspection constitutes one sample as defined by IP 71122.01-5.

b. Findings

No findings of significance were identified.

.3

Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, Licensee Event

Reports, and Special Reports related to the radioactive effluent treatment and monitoring

program since the last inspection to determine if identified problems were entered into

the CAP for resolution. The inspectors also assessed whether the licensee's

self-assessment program was capable of identifying repetitive deficiencies or significant

individual deficiencies in problem identification and resolution.

21

Enclosure

The inspectors reviewed corrective action reports from the radioactive effluent treatment

and monitoring program since the previous inspection, interviewed staff, and reviewed

documents to determine if the following activities were conducted in an effective and

timely manner commensurate with their importance to safety and risk:

initial problem identification, characterization, and tracking;

disposition of operability/reportability issues;

evaluation of safety significance/risk and priority for resolution;

identification of repetitive problems;

identification of contributing causes;

identification and implementation of effective corrective actions;

resolution of NCVs tracked in the corrective action system;

implementation/consideration of risk significant operational experience feedback;

and

ensuring problems were identified, characterized, prioritized, entered into a

corrective action, and resolved.

This inspection constitutes one sample as defined by IP 71122.01-5.

b. Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

.1

Unplanned Transients per 7000 Critical Hours

a.

Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per

7000 Critical Hours Performance Indicator (PI) for Units 1 and 2 for the period

beginning on the first quarter of 2008 through the end of the first quarter 2009.

To determine the accuracy of the PI data reported during those periods, PI definitions

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

Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors

reviewed the licensees operator narrative logs, issue reports, maintenance rule records,

event reports and NRC Integrated Inspection Reports for the period of January 2008

through March 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 PI data collected or transmitted for this indicator and none were

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

This inspection constituted two unplanned transients per 7000 critical hours samples as

defined in IP 71151-05.

b.

Findings

No findings of significance were identified.

22

Enclosure

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 Resolution of Items Entered Into the Corrective Action Program

a.

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 CAP at

an appropriate threshold, that adequate attention was being given to timely corrective

actions, and that adverse trends were identified and addressed. Attributes reviewed

included: the complete and accurate identification of the problem; that timeliness was

commensurate with the safety significance; that evaluation and disposition of

performance issues, generic implications, common causes, contributing factors, root

causes, extent of condition reviews, and previous occurrences reviews were proper and

adequate; and that the classification, prioritization, focus, and timeliness of corrective

actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result 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 of significance were identified.

.2

Daily Corrective Action Program Reviews

a.

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 CAP. This review was accomplished through

inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant

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

samples.

b.

Findings

No findings of significance were identified.

23

Enclosure

.3

Semi-Annual Trend Review

a.

Scope

The inspectors performed a review of the licensees CAP and associated documents to

identify trends that could indicate the existence of a more significant safety issue. The

inspectors review was focused on repetitive equipment issues, but also considered the

results of daily inspector CAP item screening discussed in Section 4OA2.2 above,

licensee trending efforts, and licensee human performance results. The inspectors

review nominally considered the 6 month period of January 1 through June 30, 2009

although some examples expanded beyond those dates where the scope of the trend

warranted.

The review also included issues documented outside the normal CAP in major

equipment problem lists, repetitive and/or rework maintenance lists, 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

CAP trending reports. Corrective actions associated with a sample of the issues

identified in the licensees trending reports were reviewed for adequacy.

The inspectors also specifically assessed the licensees trend in human performance

related to decision making as it was discussed in the Annual Assessment Letter to the

licensee dated March 4, 2009.

This review constituted a single semi-annual trend inspection sample as defined in

IP 71152-05.

b. Findings and Observations

Although some human performance issues continued in the area of decision making, the

inspectors noted that the licensee had instituted substantial corrective actions and

observed positive changes at the facility. Specifically, two NRC identified findings had

been identified with cross-cutting aspects of decision making within the previous three

quarters and a third item was identified in this inspection period. While actions to

improve decision making were instituted across the facility, continued management

oversight is warranted to sustain well-based decision making across the site. Findings

No findings of significance were identified.

.4

Selected Issue Follow-Up Inspection: Technical Support Center Chiller Issues

a.

Scope

During a review of items entered in the licensees CAP, the inspectors observed that the

licensee was having numerous issues related to the Technical Support Center (TSC)

chiller units. The inspectors selected this issue for a follow-up inspection of problem

identification and resolution. Documents reviewed are listed in the Attachment to this

report.

24

Enclosure

This review constituted one in-depth problem identification and resolution sample as

defined in IP 71152-05.

b.

Findings and Observations

The TSC is one of the licensees onsite emergency response facilities. It is designed to

be habitable to the same degree as the control room for postulated accident conditions,

except that the equipment is not Seismic Category I qualified, redundant or instrumented

as in the control room. The TSC envelope also houses a computer room that contains

the stations local area network (LAN) computers and gateway, the Emergency

Response Data System (ERDS), the Illinois Emergency Management Agencys General

Emergency Management System and other communication equipment. The TSC

computer room has its own cooling system.

Using TSC as a keyword in a CAP search, the inspectors identified 24 IRs generated

since June 2007, 15 of which were generated in 2008 and 7 of those were generated in

2009. All of the IRs were related to deficiencies in the TSC or TSC computer room

cooling systems. The functions of these cooling systems are to provide an adequate

environment for the responders during an event, and to protect the communication and

emergency response-related equipment such as ERDS and the LAN that are housed in

the TSC.

At the start of this inspection, the TSC cooling unit has a Freon leak and all three TSC

computer room cooling units have various equipment issues and two of the three units

were non-operational for the second half of 2008. When the third TSC room cooling unit

failed in December 2008, a portable circulating fan had to be used with the computer

room door propped open to keep the temperature down. The TSC temperature had

occasionally gone up to 100°F because of the unavailability of the cooling unit. Although

a TSC temperature of 100°F is not prohibited by the licensees procedures, continued

high temperatures in the TSC could reduce the life of the communication and emergency

response-related equipment housed in the TSC.

The licensee has established a Chiller High Impact Team to address the number of

issues on the TSC cooling systems. At the conclusion of this inspection period, the TSC

chiller units were operational.

The elevated temperature in TSC only affected the comfort of the emergency

responders and potentially the operating life of the communication equipment.

Therefore, the licensee had met all the requirements for radiological protection for the

TSC with the High Efficiency Particulate HEPA and charcoal filtration being operable,

and no issues of significance were identified.

Although several deficiencies were associated with the TSC cooling systems noted over

the last 3 years, the timeliness of the licensee corrective actions were commensurate

with the safe function of the equipment.

25

Enclosure

4OA5 Other Activities

.1

(Open) URI (05000454/2009003-02; 05000455/2009003-02); Diesel Oil Storage Tank

Vent Lines Regulatory Compliance

The inspectors noted that the diesel oil storage tank (DOST) vent piping was non-safety

related and was located in a non-safety related structure. Subsequent inspector

questions focused on the DOSTs ability to vent if the vent lines were crimped during a

seismic or tornado generated missile event.

During the course of the inspection, the inspectors ascertained that in the associated

amendments and Supplemental Safety Evaluation Reports of the early 1980s, the NRC

reviewers position was that the vents needed to be seismic and missile protected.

Subsequent to that time, communications between the licensee and the NRC resulted in

the NRC reviewers accepting the licensees design where the vent lines were routed

through the Category II turbine building. However, the reviewers basis was that the

licensee had committed to make the vent lines seismically supported, that the licensee

had stated that the vent lines would break before crimping, that there were alternate vent

paths and that the lines were designed in accordance with ANSI B31.1 piping

standards.

The NRC inspectors determined that the lines were not modified to be seismically

supported and that there were no calculations supporting the break before crimp

position. Piping experts consulted by the licensee also indicated that the lines

would crimp before breaking. Although alternate vent paths do exist, there was no

instrumentation that would alert the plant operators to a need for the alternate vent

paths prior to diesel generator operability impact. There were also no procedures,

training, or tools needed by the operators to establish the alternate vent paths. A more

detailed review of the docket by the inspectors and the licensee determined that there

was no actual submittal by the licensee stating they would upgrade the vent paths to

seismic grade and the source of the NRC reviewers comment could not be located.

The licensee initiated IR 877430 and performed a prompt operability determination. The

licensee concluded that the diesel oil storage tanks and the diesel generators remained

operable, but degraded in the installed configuration specifically that the NRC reviewers

basis for accepting this changes from the design requirements was not valid.

The inspectors reviewed the operability determination with no issues identified regarding

operability. However, this issue will remain unresolved pending further review of the

installed configuration and assessment of 10 CFR 50.109(a)(4) to determine if a

modification is necessary to bring the facility into compliance with the rules or orders of

the Commission (URI 05000454/2009003-02; 05000455/2009003-02).

.2

(Closed) NRC Temporary Instruction 2515/173 Review of the Industry Ground Water

Protection Voluntary Initiative

a. Inspection Scope

An NRC assessment was performed of the licensees implementation at Byron Station of

the Nuclear Energy Institute - Ground Water Protection Initiative (NEI-GPI) (dated

August 2007 (ML072610036)). The inspectors assessed whether the licensee evaluated

26

Enclosure

work practices that could lead to leaks or spills and performed an evaluation of systems,

structures, and components that contain licensed radioactive material to determine

potential leak or spill mechanisms.

The inspectors verified that the licensee completed a site characterization of geology

and hydrology to determine the predominant ground water gradients and potential

pathways for ground water migration from onsite locations to off-site locations. The

inspectors also verified that an onsite ground water monitoring program had been

implemented to monitor for potential licensed radioactive leakage into groundwater and

that the licensee had provisions for the reporting of its ground water monitoring results.

(See http://www.nrc.gov/reactors/operating/ops-experience/tritium/plant-info.html)

The inspectors reviewed the licensees procedures for the decision making process for

potential remediation of leaks and spills, including consideration of the long term

decommissioning impacts. The inspectors also verified that records of leaks and

spills were being recorded in the licensees decommissioning files in accordance with

10 CFR 50.75(g).

The inspectors reviewed the licensees notification protocols to determine whether they

were consistent with the Groundwater Protection Initiative. The inspectors assessed

whether the licensee identified the appropriate local and state officials and conducted

briefings on the licensees ground water protection initiative. The inspectors also verified

that protocols were established for notification of the applicable local and state officials

regarding detection of leaks and spills.

b. Findings

No findings of significance were identified; however, as specified in 2515/173-05, the

inspectors identified the following deviations from Nuclear Energy Institute - Ground

Water Protection Initiative (NEI-GPI) protocols or areas within the NEI-GPI that were

not fully addressed within the licensees program.

(1)

GPI Objective 1.4 - Remediation Process.

a. Establish written procedures outlining the decision making process for

remediation of leaks and spills or other instances of inadvertent releases.

This process is site specific and shall consider migration pathways.

The licensee had not established written procedure(s) outlining the decision making

process for remediation of leaks and spills or other instances of inadvertent releases that

are site specific and consider migration pathways.

b. Evaluate the potential for detectible levels of licensed material resulting from

planned releases of liquids and/or airborne materials.

The licensee had not performed/completed an evaluation of the potential for detectible

levels of licensed material from planned releases of liquids and/or airborne materials

(e.g., rain-out and condensation). The licensee determined that an additional evaluation

was not required because the licensee had analyzed the Construction Run-Off Pond for

licensed material. However, the inspectors questioned whether some uncertainties in

the sample location (i.e., the potential for significant dilution) and the annual frequency

27

Enclosure

ensured the samples collected were representative of material from planned releases of

liquids and/or airborne materials (e.g., rain-out and condensation).

(2)

GPI Objective 2.1 - Stakeholder Briefing.

b. Licensees should consider including additional information or updates on

ground water protection in periodic discussions with State/Local officials.

The licensee had not included additional information or updates on ground water

protection in periodic discussions with State/Local officials.

4OA6 Management Meetings

.1

Exit Meeting Summary

On July 8, 2009, the inspectors presented the inspection results to D. Enright, and other

members of the licensee staff. The licensee acknowledged the issues presented. The

inspectors confirmed that none of the potential report input discussed was considered

proprietary.

.2

Interim Exit Meetings

Interim exits were conducted for:

Occupational radiation safety program for Instrumentation and Public Radiation

Safety cornerstone programs for Effluent and Groundwater Protective Initiative

with Mr. D. Enright and other members of the licensees staff on May 15, 2009.

The inspectors confirmed that none of the potential report input discussed was

considered proprietary.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee

and are violations of NRC requirements which meet the criteria of Section VI of the

NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

10 CFR 50, Appendix B, Criterion III, Design Control, states, in part, that

measures shall be established for the selection and review for suitability of

application of materials, parts, equipment, and processes that are essential to the

safety-related functions of the structures, systems and components. Contrary to

this, in March 2008 for Unit 1, and March 2007 for Unit 2, the licensee

implemented a modification to the Emergency Core Cooling System throttle valve

design using a material (gas nitrided stainless steel) that was prohibited by

design specifications and contributed to flow rates in the pump runout region of

the high head and intermediate head safety injection pumps. This violation was

of very low safety significance because the design deficiency did not result in a

loss of operability or functionality of the emergency core cooling systems. The

licensee entered into the CAP as IR 908529.

28

Enclosure

10 CFR 70.51(b)(1), as issued on January 1, 1986, requires each licensee to

keep records showing receipt, inventory (including location), disposal,

acquisition, and transfer of all special nuclear material in his possession

regardless of its origin or method of acquisition. Contrary to this requirement, in

1986, a source containing 1 micro-curie of special nuclear material was ordered,

received, used, and disposed as part of a project performed by a member of the

licensees health physics staff. However, the special nuclear material coordinator

was not aware of the purchase, and therefore, the source was not entered in to

the appropriate tracking logs. The licensee disposed of the empty vial that was

used to deliver the special nuclear material in 1990. This incident was identified

in the licensees corrective action program as IR 864861 and IR 886232. This

was determined to be a Severity IV violation because it involved an isolated

failure to secure, or maintain surveillance over licensed material in a quantity

greater than 10 times but not greater than 1000 times the quantity specified in

Appendix C to Part 20. Additionally, the material was labeled as radioactive,

located in an area posted as containing radioactive materials; and the failure

occurred despite a functional program to detect and deter security violations that

included training, staff awareness, detection, and corrective action.

ATTACHMENT: SUPPLEMENTAL INFORMATION

1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

D. Enright, Site Vice President

B. Adams, Plant Manager

B. Askren, Security Director

C. Gayheart, Operations Director

D. Gudger, Regulatory Assurance Manager

L. Bogue, Training Manager

M. Dahms, Maintenance Support Manager

B. Jacobs, Sr. Design Engineering Manager

P. Johnson, NOS Manager

S. Kerr, Chemistry Manager

V. Naschansky, Electrical Design Manager

B. Riedl, Acting Project Management Manager

D. Thompson, Radiation Protection Manager

Nuclear Regulatory Commission

R. Skolowski, Branch Chief

B. Bartlett, Senior Resident Inspector

J. Robbins, Resident Inspector

2

Attachment

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened 05000455/2009003-01

NCV

Failure to Comply with TS 3.4.13.B Reactor Coolant

Pressure Boundary Leakage 05000454/2009003-02

05000455/2009003-02

URI

Diesel Oil Storage Tank Vent Regulatory Compliance Backfit

May be Required

Closed 05000455/2009003-01

NCV

Failure to Comply with TS 3.4.13.B Reactor Coolant

Pressure Boundary Leakage

3

Attachment

LIST OF DOCUMENTS REVIEWED

The following is a list of documents reviewed during the inspection. Inclusion on this list does

not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that

selected sections of portions of the documents were evaluated as part of the overall inspection

effort. Inclusion of a document on this list does not imply NRC acceptance of the document or

any part of it, unless this is stated in the body of the inspection report.

Section 1R01: Adverse Weather Protection

OP-AA-108-107-1001; Station Response to Grid Capacity Conditions, Revision 2

OP-AA-108-107-1002; Interface Agreement Between Exelon Energy Delivery and Exelon

Generation for Switchyard Operations, Revision 4

OP-AA-108-107; Switchyard Control, Revision 2

WC-AA-8000; Interface Procedure Between Exelon Energy Delivery (Comed/Peco) and Exelon

Generation (Nuclear/Power) for Construction and Maintenance Activities, Revision 2

WC-AA-8003; Interface Procedure Between Exelon Generation (Nuclear/Power) for Design

Engineering and Transmission Planning Activities, Revision 1

IR 932840; One Broken Strand of Fence Wire South End of Switchyard, June 18, 2009

IR 932857; Gravel Starting to Wash Out Along Bottom of Switchyard Fence, June 18, 2009

IR 929613; 1WS143 Failed Open, June 10, 2009

Diagram of Non-Essential Service Water System M-43 Sheet 2A, Rev AF

Corrective Action Documents as a Result of NRC Inspection

IR 927025; Piping Downstream of 0VQ003 Corroded, June 02, 2009

IR 927294; NRC Outside Site Walkdown, June 02, 2009

Section 1R04: Equipment Alignment (Quarterly

BOP DG-M1B; Train B Diesel Generator System Valve Lineup, Revision 11

BOP DG-M1; Diesel Generator System Valve Lineup, Revision 18

BOP DG-E1B; Unit 1Train B Diesel Generator Electrical Lineup, Revision 2

BOP DG-E1; Unit 1 Diesel Generator Electrical Lineup, Revision 6

Drawings; M-50, Diagram of Diesel Fuel Oil; Sheet 1A - Revision AR, Sheet 1B - Revision AN,

Sheet 1C - Revision AN, Sheet 1D - Revision AN, Sheet 5 - Revision H

Section 1R05: Fire Protection (Quarterly)

Byron Station Pre-Fire Plans, Zone 5.6-1; Division 11 Miscellaneous Electrical Equipment and

Battery Room, Revision 5

Byron Station Pre-Fire Plans, Zone 11.5A-1, Unit 1 Electrical Penetration Area, Revision 5

Byron Station Pre-Fire Plans, Zone 11.5A-2; Unit 2 Electrical Penetration Area, Revision 5

Byron Station Pre-Fire Plans, Zone 10.1-1; 1B Diesel Fuel Oil Storage Tank Room, Revision 6

Byron Station Pre-Fire Plans, Zone 9.1-1; 1B Diesel Generator and Day Tank Room, Revision 5

4

Attachment

Section 1R06: Flood Protection Measures

Unit 2 SX Pump Room

0BMSR DD-1; Water-Tight Barrier Inspection (CM-6.1.1.), Revision 5

Drawing 1SD1; Watertight Bulkhead Doors # SD1, SD2, SD3, and SD4 General Arrangement

Section 1R11: Licensed Operator Requalification Program

Cycle 09-3, Out of the Box Evaluation Scenario, Revision 1

Section 1R12: Maintenance Effectiveness

IR 752949; Need Work Order to Reconcile Boric Acid Pump Issues, March 21, 2008

IR 785140; Failed Post Maintenance Test - 2B SAC Change Inlet Filter Alarm Still Lit,

June 10, 2008

IR 785280; Work Request Needed to Troubleshoot Frequency Cycling of the 2SA390B,

June 11, 2008

IR 785780; 1 Year PM for the SAC Require Changes, June 12, 2008

IR 788763; Disk Out Indication, May 30, 2008

IR 789245; 2W MPT Breakers 8-4 and 8-9 Tripped, June 23, 2008

IR 792959; 2B SAC Package Discharge Temperature HI, July 02, 2008

IR 792964; 2B SAC Inlet Vacuum Low, July 02, 2008

IR 804572; Received Unexpected Generator Volt Reg Trouble Alarm, August 06, 2008

IR 805773; Abnormal Water Flow from SA Receiver Blowdown, August 11, 2008

IR 806949; Unit 1 Generator has Low Insulation Reading, August 14, 2008

IR 812790; 2B SAC Trip Causes Reduction in SA/IA Header Pressure, August 31, 2008

IR 815475; Loss of 1A & 2B SAC, September 09, 2008

IR 815792; 2SA10CB; Perform Troubleshooting, September 09, 2008

IR 821914; DC BUS 211 Ground, September 24, 2008

IR 829302; Deficiencies Found During Main Generator Crawl Through, October 09, 2008

IR 829391; Deficiencies Found During Phase and Neutral Bushing Box Inspection,

October 10, 2008

IR 833862; Crackling Noise Coming from Cooling Group No.2 Transformer, October 21, 2008

IR 858464; Group 1 Bank 4 Breaker Tripped Open, December 19, 2008

IR 860396; Unexpected alarm 125VDC BUS 211 Ground, December 27, 2008

IR 860783; DC BUS 211 Ground Annunciator Comes In, December 29, 2008

IR 861426; 2E MPT Cooling Bank 4 Water in Electrical Connector for Fans, December 30, 2008

IR 866827; Byron Not in Compliance with Power Transformer PCM Template, January 14, 2009

IR 890145; DC BUS 211 Has +95VDC Ground, March 09, 2009

IR 897167; Level II Ground on BUS 211, March 25, 2009

IR 897637; DC BUS 211 Ground Troubleshooting, March 25, 2009

IR 899326; Unexpected Annunciator, March 29, 2009

IR 904254; NERC Compliance FASA Identified Unit 1 Exciter/PSS Modeling, April 07, 2009

IR 907806; Unit 1 Boric Acid Storage Tank Liner Degraded, April 15, 2009

IR 909320; 211 DC High Grounds, April 20, 2009

IR 913515; 2AB03P Pump Bearing Housing Temps High, April 29, 2009

IR 918383; Low Resistance Reading on Turbine Generator, May 11, 2009

IR 920486; DC Bus 211 Ground, April 26, 2009

IR 919481; 2B SAC Package Discharge Temperature High, May 3, 2009

IR 920878; 2SA10CB Work Window Issues, May 18, 2009

IR 922994; Lessons Learned from 2B SAC Cooler Cleaning (FNM WR 304289), May 22, 2009

5

Attachment

IR 923206; 1B/2B SACs Cycling Different than Setpoints, May 22, 2009

IR 923864; Main Power Transformer Single Point Vulnerability Review RES, May 26, 2009

IR 927061; Summer Readiness of 1E MPT Degraded, June 02, 2009

BOP SA-12; Operations of Sierra Station Air Compressor, Revision 25

MA-AA-716-004; Troubleshooting Plan, April 20, 2009, Revision 7

Drawing 6E-2-3374; Byron Unit 2 Electrical Installation Auxiliary Building Partial Plan

Elevation 463-0, Revision BN

Drawing 6E-0-3502; Electrical Installation Essential Service Cooling Tower 0A Plan -

Switchgear Room Elevation 874-0, Revision AX

Drawing 6E-0-3680; Duct Run Routing Outdoor - West of Station, Revision AF

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Unit 1 Risk Configurations; Week of 05/25/09, Revision 1

Unit 2 Risk Configurations; Week of 05/25/09, Revision 1

Protected Equipment Log for Unit 2 Auxiliary Feedwater Flow Calibration; dated 05/27/09

Protected Equipment Log for 0SX147 & 1SX010 Unavailable; dated 05/28/09

Protected Equipment Log for 2SX034 Unable to Open & Unable to Close; dated 05/28/09

Protected Equipment Log for Unit 1 Train B Diesel Generator Vent Fan; dated 05/29/09

IR 932515; Check Valve 0SX28A Leaking By, June 18, 2009

Section 1R15: Operability Evaluations

EC 375875; Initial Leak Seal Clamp on 1CW20AB-6 Pipe to Stop/Contain Through Wall Leak

and Evaluate for Wall Thinning

Cases of ASME Boiler and Pressure Vessel Code N-523-2, October 02, 2000

Cases of ASME Boiler and Pressure Vessel Code N-597-2, November 18, 2003

Issue 932448; Unit 2 Pressurizer PORV Accumulator 2A Low Pressure Alarm, June 17, 2009

EC 375875 Rev. 0; Install Leak Seal Clamp on 1CW20AB-6 Pipe to Stop/Contain Through Wall

Leak and Evaluate for Wall Thinning

EC 375987 00; Operations Evaluation 09-003, OA SX Makeup Pump Discharge Check Valve

Leaking By, June 23, 2009

IR 940534; Probable Dispute of Potential NRC Violation, June 24, 2009

Section 1R18: Plant Modifications

EC 375313; Plugging of Gland Steam Leak at Unit 2 HP Turbine, May 05, 2009

EC 374690; Add Temporary Weight on 1B AF Pump Gearbox to Improve Vibrations,

March 19, 2009

Section 1R19: Surveillance Testing

WO 1018533 01; Replacement of the Fuel Shutoff Solenoid, August 24, 2007

WO 1060464 02; Replace OLS-SX096 Level Probe and Switch Assembly, May 22, 2009

WO 1062976 12; 1SX019A Leaks By, June 23, 2009

WO 1083921-01; Perform Thermal Overload Testing (1SX010), dated 05/29/09

WO 1083921-02; OPS PMT - 1SX010 Stroke

WO 1199056-01; Hi DP Alarm Came In Early

WO 1199056-02; OPS PMT Task Hi DP Alarm Came In Early

WO 1215696 01; 2BOSR 3.1.5-2, Train B SSPS Bi-Monthly Surveillance, June 30, 2009

6

Attachment

WO 1223817 01; 1CS01PA Comprehensive IST Requirements for Containment Spray Pump,

June 23, 2009

WO 1236031 01; 0A SX Makeup Pump Operability Surveillance, June 16, 2009

Clearance Order 73701; 1PDS-VD071 - Replace Transmitter

IR 919415; MMD Loosened Wrong Bolts on 1DG01KA Turning Gear, May 13, 2009

Issue 920190; All Issues on Turning Gear Wrong Bolts Loosened Not Addressed, May 13, 2009

BMP 3108-9; Engaging and Disengaging of Diesel Generator Turning Gear, Revision 7

BMP 3208-1; Emergency Stand-By DG Engine 6-Year/20-Year Surveillance, Revision 20

BOP AF-7; Diesel Drive Auxiliary Feedwater Pump B Startup on Recirc, Revision 34

Section 1R22: Surveillance Testing

BIP 2500-161; Calibration of RCP Seal Water Injection Flow Loop, Revision 2

IR 781472; Repeated SD Leak Issues, May 31, 2008

IR 805496; 2C SG Lower SD Flow Isolation Valve, August 08, 2008

IR 806396; Both Units SD Systems Degraded for >5 years, August 12, 2008

IR 818280; 2SD02PA Failed PMT, September 16, 2008

IR 822784; 2SD005C Air Regulator Requires EQ Requirement, September 26, 2008

IR 860294; 2SD005C Stroke Time Near Admin Limit, December 26, 2008

IR 875858; Flow Indicator Shows Flow When Isolated, February 03, 2009

IR 933440; 2SD007 Tripped Shut for No Apparent Reason, June 20, 2009

WO 1182264 01; 1B Diesel Generator Operability Semi-Annual Surveillance, April 24, 2009

WO 1207861 01; STT for 1AF013E-H, May 01, 2009

WO 1226372 01; 1B AF Pump Surveillance, May 01, 2009

WO 1222389 01; STT for 2SD002A-H and 2SD005A-D (week B), June 22, 2009

Section 1EP6: Drill Evaluation

EP Pre-Exercise Drill Scenario - June 12, 2009

Section 2OS3: Radiation Monitoring Instrumentation and Protective Equipment

BRP-5800-1; Use of Air Ionization Chambers and Geiger-Mueller Instruments for Measuring

Personnel Exposures; Revision 14

BRP-5800-3; Area Radiation Monitoring System Alert/High Alarm Setpoints; Revision 25

BRP-5800-9; 1(2)RE-AR011(12) Fuel Handling Incident Monitor Setpoint Change; Revision 09

BRP-5820-14; Process Radiation Monitoring System Alert/High Alarm Setpoints; Revision 37

BRP-5821-4; Operation of the Eberline AMS-3 Beta Air Monitor; Revision 07

BRP 5822-10; Calibration, Source Check, and Maintenance of the Eberline PM-7 Portal

Monitors; Revision 21

BRP 5822-11; Calibration of Nuclear Enterprises Small Articles Monitor (SAM); Revision 14

BRP-5823-26; Calibration and Operation of the Eberline Model RO-7; Revision 11

BRP-5823-38; Operation and Calibration of the Ram Gam 1; Revision 07

BRP-5823-40; Operation of the Merlin-Gerin Telepole; Revision 07

BRP-5825-3; Operation and Use of the J.L. Shepherd Model 89 Gamma Calibration;

Revision 11

BRP-5825-7; J.L. Shepherd Model 89 Gamma Calibration Unit Certification to Establish NIST

Tracebility; Revision 08

RP-BY-700; Controls for Radiation Protection Instrumentation; Revision 02

RP-BY-700-1001; Instrument Calibration and Source Check Settings; Revision 24

7

Attachment

RP-BY-825-1000; Maintenance Care and Inspection of the Viking Self-Contained Breathing

Apparatus; Revision 11

Calibration Records of the High Range Containment Radiation Monitors

(1/2AR-020 and 1/2AR-021); 2007 and 2008

Calibration Records of Electronic Dosimeter from Zion Station; March 2007 and March 2008

Calibration Records of the IPM-8M; various 2008

Calibration Records of the PM-7 Portal Monitor; May 2009

Condition Reports associated with PowerLab portable radiation survey and monitoring

instruments, station radiation survey and monitoring instruments, and containment high range

radiation monitors; various dates 2007 and 2008

Exelon PowerLabs Audit - 2008-10; Exelon PowerLabs Coatsville, Pa; September 2008

Formal Benchmark Report (AR No. 670099); PowerLabs Coatsville, PA; Undated

Position Papers Assessing Isotopic Mix and Percent Abundance Data (Part 61) on Radiation

Survey and Monitoring Equipment Performance; various dates 2007 and 2008

Quality Assurance Program Implementation, Internal Audit Report; May 2008

Respiratory Protection Lesson Plan; 06GRS2; Revision 00

Respirator Qualification, Maintenance and Training Records; various dates 2008

Self-Assessment - 699118; Radiation Protection Instrumentation and Protective Equipment;

June 2008

Self-Assessment - 842820; Radiation Protection Instrument Check-in; February 2009

SCBA Bottle Hydro Tests and Maintenance Records; various dates 2008

Section 2PS1: Radioactive Gaseous and Liquid Effluent Treatment and Monitoring

Systems

Annual Radioactive Effluent Release Report; 2007

Annual Radioactive Effluent Release Report; 2008

Functional Area Self Assessment (FASA) 831375; Radioactive Gaseous and Liquid Effluents;

March 31, 2009

CY-AA-110-200; Sampling; Revision 8

CY-AA-130-200; Quality Control; Revision7

CY-BY-110-600; Chemistry Sample Points; Revision 27

Technical Requirements Manual (TRM); Section 3.11; Radiological Effluents; December 2008

CY-BY-170-301; Offsite Dose Calculation Manual; Revision 6

CY-AA-170-210; Potentially Contaminated System Controls; Program; Revision 0

CY-AA-170-215; Release of Bulk Fluids From Potentially Contaminated Plant Systems;

Revision 0

CY-AA-170-2150; PCSC Program Implementation Guidelines; Revision 0

IR 00783135; Removal of ODCM Special Reporting Requirements; June 5, 2008

IR 00909590; Communication Failures for 1PR02J LCO Entry; April 20, 2009

IR 00904109; Actual Vent Stack Flow Rates vs. UFSAR; April 7, 2009

IR 00877744; Spike on 2PR01J Results in Containment Release Termination; February 7, 2009

IR 00805788; 1PR028J Tritium Sample; August 11, 2008

WO 00902761; Perform Calibration of 01PR01J; August 17, 2007

WO 00934411; Calibration of Rad Monitor 2PR28J; August 24, 2007

WO 00935870; Calibration of Rad Monitor 1PR28J; October 08, 2007

WO 00979053; Calibration of 0PR05J; March 06, 2008

Section 4OA1: Performance Indicator Verification

Power History Curves for Unit 1 and Unit 2 from May 2008 - April 2009

8

Attachment

Section 4OA2: Identification and Resolution of Problems

Drawing M-94, Diagram of Technical Support Center Ventilation System, Sheet 2, Revision P

Drawing M-94, Diagram of Technical Support Center Ventilation System, Sheet 3, Revision H

WO 1038609; TSC Ventilation HEPA Filter Performance Test, December 8, 2008

WO 1038610; TSC Ventilation System Charcoal Absorber Bank Operability,

December 10, 2008

TSC Ventilation Work Order Backlog, dated 05/26/09

IR 929246; Visiting NRC Inspector Access Hindered at PAF, June 08, 2009

Corrective Action Documents as a Result of NRC Inspection

IR 907593; Discrepancy in Operations Log Entry, April 14, 2009

IR 908794; Walkdown Results, April 16, 2009

IR 909409; Pre-Fire Plan Discrepancy, April 20, 2009

IR 909634; Missing Screws in Electrical Cabinet Doors, April 20, 2009

IR 909808; Missing Screws in Electrical Cabinet Doors, April 20, 2009

IR 909817; Bowed-Out Door on Electrical Cabinet, April 20, 2009

IR 910064; NRC Comments on Fire Protection Issues, April 21, 2009

IR 909222; Metal Strip That Holds the Weather Stripping on is Broken, April 19, 2009

IR 909229; Weather Stripping is Ragged, April 19, 2009

IR 909251; Box with Switchplate Hanging Down By MCC 133X4 D1, April 19, 2009

IR 909216; Fire Protection Valve Packing Leak, Previous IR Closed Packing Still Leaking,

December 31, 1960

IR 909119; Nitrogen Test Isolation Valve 1NT041D Has a Bent Operator, April 16, 2009

IR 937811; NRC Walkdown at CW Pump House, June 29, 2009

Section 4OA5: Other Activities

Functional Area Self Assessment (FASA); AR 838638-02; Radioactive Groundwater Protection

Program (RGPP) Assessment as required per NEI 0707; December 16, 2008

CY-AA-170-400; Radiological Groundwater Protection Program; Revision 4

CY-AA-170-4000; Radiological Groundwater Protection Program Implementation; Revision 4

LS-AA-1120; Reportable Event RAD 1.1 Reportability Manual; Revision 10

EN-AA-407; Response to Unplanned Discharges of Licensed Radionuclides to Groundwater,

Surface Water, or Soil; Revision 1

CY-BY-170-4160; Radioactive Groundwater Protection Program Scheduling and Notification;

Revision 4

Hydrogeologic Investigation Work Plan; Fleetwide Tritium Assessment; Byron Generating

Station; May 2006

9

Attachment

LIST OF ACRONYMS USED

AC

Alternating Current

ADAMS

Agencywide Document Access Management System

ASME

American Society of Mechanical Engineers

CAP

Corrective Action Program

CEDE

Committed Effective Dose Equivalent

CFR

Code of Federal Regulations

DOST

Diesel Oil Storage Tank

ECCS

Emergency Core Cooling System

ERDS

Emergency Response Data System

HEPA

High Efficiency Particulate

IMC

Inspection Manual Chapter

IP

Inspection Procedure

IR

Inspection Report

IR

Issue Report

IST

Inservice Testing

LAN

Local Area Network

NCV

Non-Cited Violation

NEI-GPI

Nuclear Energy Institute - Groundwater Protection Initiatives

NRC

U.S. Nuclear Regulatory Commission

ODCM

Occupational Dose Calculation Manual

PARS

Publicly Available Records

PI

Performance Indicator

RCPB

Reactor Coolant Pressure Boundary

RCA

Radiological Control Area

RCS

Reactor Coolant System

RETS

Radiological Effluent Technical Specifications

RP

Radiation Protection

SCBA

Self-Contained Breathing Apparatus

SDP

Significance Determination Process

SSC

Structures, Systems, and Components

SX

Essential Service Water System

TS

Technical Specification

TSC

Technical Support Center

TSO

Transmission System Operator

UFSAR

Updated Final Safety Analysis Report

URI

Unresolved Item

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