ML092190925
| 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) | |
See also: IR 05000454/2009003
Text
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
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
Enclosure: Inspection Report No. 05000454/2009-003
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
Enclosure: Inspection Report No. 05000454/2009-003
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 RIII
NAME RNg:dtp RSkokowski
DATE 08/07/09 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
Jeannie Choe
DRPIII
DRSIII
Patricia Buckley
ROPreports Resource
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-454; 50-455
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
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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. 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.
1 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:
2 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.
3 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:
4 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)
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:
5 Enclosure
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:
6 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;
7 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;
- 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
8 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
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
9 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
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
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 <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br /> and 26 minutes to repair the pipe
and to exit the TS. This was 49 hours5.671296e-4 days <br />0.0136 hours <br />8.101852e-5 weeks <br />1.86445e-5 months <br /> and 26 minutes over the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. 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 <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br /> 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)
10 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:
11 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);
12 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.
13 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
14 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.
15 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
16 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.
17 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
This inspection constitutes one sample as defined by Inspection Procedure 71122.01-5.
18 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.
19 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
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.
20 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.
21 Enclosure
4OA2 Identification and Resolution of Problems (71152)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
.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.
22 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.
23 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.
24 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
25 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
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
26 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.
27 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
28 Enclosure
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
1 Attachment
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
05000455/2009003-01 NCV Failure to Comply with TS 3.4.13.B Reactor Coolant
05000454/2009003-02 URI Diesel Oil Storage Tank Vent Regulatory Compliance Backfit
05000455/2009003-02 May be Required
Closed
05000455/2009003-01 NCV Failure to Comply with TS 3.4.13.B Reactor Coolant
2 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
3 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
4 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
5 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
6 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
7 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
8 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
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
TSO Transmission System Operator
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
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