ML090420213
| ML090420213 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 02/10/2009 |
| From: | Richard Skokowski Region 3 Branch 3 |
| To: | Pardee C Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-08-005 | |
| Download: ML090420213 (49) | |
See also: IR 05000454/2008005
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
February 10, 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 05000454/2008-005 05000455/2008-005
Dear Mr. Pardee:
On December 31, 2008, 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 January 15, 2009, with
Mr. D. Hoots 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, two NRC-identified findings of very low safety
significance were identified. The findings involved violations of NRC requirements. 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 in accordance
with Section VI.A.1 of the NRC Enforcement Policy. Furthermore, four licensee identified
violations are listed in Section 4OA7 of this report.
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.
C. Pardee
-2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter,
its enclosure and your response (if any) will be available electronically for public inspection
in the NRC Public Document Room or from the Publicly Available Records (PARS)
component of NRC's 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. 05000454/2008-005 and 05000455/2008-005
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,
its enclosure and your response (if any) will be available electronically for public inspection
in the NRC Public Document Room or from the Publicly Available Records (PARS)
component of NRC's document system (ADAMS), accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
Richard A. Skokowski, Chief
Branch 3
Division of Reactor Projects
Docket Nos. 50-454; 50-455
Enclosure:
Inspection Report No. 05000454/2008-005 and 05000455/2008-005
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
DOCUMENT NAME: G:\\1-SECY\\1-WORK IN PROGRESS\\BYRO 2008 005.DOC
G Publicly Available
G Non-Publicly Available
G Sensitive
G Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy
OFFICE
RIII
NAME
RSkokowski:dtp
DATE
02/10/09
OFFICIAL RECORD COPY
Letter to C. Pardee from R. Skokowski dated February 10, 2009
SUBJECT:
BYRON STATION, UNITS 1 AND 2 INTEGRATED INSPECTION REPORT
05000454/2008-005 05000455/2008-005
DISTRIBUTION:
RidsNrrDorlLpl3-2
RidsNrrPMByron Resource
RidsNrrDirsIrib Resource
Mark Satorius
Kenneth OBrien
Cynthia Pederson
DRPIII
DRSIII
Patricia Buckley
ROPreports@nrc.gov
Enclosure
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-454; 50-455
License Nos:
Report Nos:
05000454/2008-005 and 05000455/2008-005
Licensee:
Exelon Generation Company, LLC
Facility:
Byron Station, Units 1 and 2
Location:
Byron, IL
Dates:
October 1, 2008, through December 31, 2008
Inspectors:
B. Bartlett, Senior Resident Inspector
R. Ng, Resident Inspector
J. Cassidy, Senior Health Physicist
A. Dunlop, Reactor Inspector
B. Jones, Reactor Inspector
D. Jones, Reactor Inspector
R. Langstaff, Reactor Inspector
D. McNeil, Reactor Inspector
R. Winter, Reactor Inspector
C. Thompson, Resident Inspector
Illinois Department of Emergency Management
Observer:
J. Gilliam, Reactor Engineer
Approved by:
R. Skokowski, Chief
Branch 3
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS
1
REPORT DETAILS
.3
Summary of Plant Status
.3
1.
REACTOR SAFETY .....3
1R01
Adverse Weather Protection (71111.01) .....................................................3
1R04
Equipment Alignment (71111.04)................................................................4
1R05
Fire Protection (71111.05)...........................................................................4
1R06
Flooding (71111.06) .....6
1R07
Annual Heat Sink Performance (71111.07).................................................6
1R11
Licensed Operator Requalification Program (71111.11) .............................7
1R12
Maintenance Effectiveness (71111.12) .......................................................8
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)..9
1R15
Operability Evaluations (71111.15) ...........................................................10
1R18
Plant Modifications (71111.18)..................................................................11
1R19
Post-Maintenance Testing (71111.19) ......................................................12
1R20
Outage Activities (71111.20) .....................................................................13
1R22
Surveillance Testing (71111.22)................................................................15
1EP6
Drill Evaluation (71114.06) ........................................................................18
2.
Radiation SAFETY ........19
2OS1
Access Control to Radiologically Significant Areas (71121.01).................19
2OS2
As-Low-As-Reasonably-Achievable Planning and Controls (71121.02) ...22
4OA1
Performance Indicator Verification (71151)...............................................23
4OA2
Identification and Resolution of Problems (71152)....................................28
4OA5
Other Activities 30
4OA6
Management Meetings ..32
4OA7
Licensee-Identified Violations....................................................................33
SUPPLEMENTAL INFORMATION
..1
Key Points of Contact
..1
List of Items Opened, Closed and Discussed............................................................................1
List of Documents Reviewed
..2
Enclosure
1
SUMMARY OF FINDINGS
IR 05000454/2008-005, 05000454/2008-005; October 1 - December 31, 2008; Byron Station,
Units 1 & 2; Refueling and Other Outage Activities, and Access Control to Radiologically
Significant Areas.
This report covers a 3-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. Two Green findings were identified by the
inspectors. The findings were considered to be Non-Cited Violations 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: Mitigating Systems
Green. The inspectors identified a finding of very low safety significance and associated
Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, for the licensees failure to follow procedure BAP 1450-1,
Access to Containment. Specifically, the inspectors determined that the licensee failed
to remove loose debris items from Unit 2 containment prior to Mode 4 or to perform an
engineering evaluation per procedure. The licensee entered this issue into the
corrective action program (CAP) as Issue Report (IR) 867171, removed the loose debris,
and completed an evaluation to verify that the containment sump was not adversely
affected.
The finding is more than minor because, if left uncorrected, the issue could have
become a more significant safety concern. The inspectors evaluated the finding using
IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial
Screening and Characterization of Finding, dated January 10, 2008, for the Mitigating
Systems Cornerstone. Since this finding was not a design or qualification deficiency, did
not result in loss of system or train safety function, and was not safety significant due to
external events, this issue is screened as very low safety significance. This finding is
related to the Work Control component of the Human Performance cross-cutting area for
the licensees failure to coordinate work activities and the need for work groups to
coordinate with each other. (H.3(b)) The personnel who left the material in containment
assumed it was acceptable as they had documented the material in a surveillance data
sheet, and the personnel who reviewed the completed data sheet assumed the material
had been or would be removed from containment, and none questioned the potential
impact upon the recirculation sump screens or coordinated with each other to ensure
resolution of the material prior to a mode change. (Section 1R20.b)
Cornerstone: Occupational Radiation Safety
Green. The inspectors identified a finding of very low safety significance and associated
NCV of Technical Specification 5.4.1 for failure to implement procedures required to
evaluate radiological hazards for airborne radioactivity. Specifically, the inspectors
Enclosure
2
identified that the licensee failed to re-start an air sampler on the refuel floor which
provided the only air monitoring system while workers were performing activities in the
area. The corrective actions taken by the licensee included starting the required air
sampler. The issue was entered in the licensees corrective action program as
IR 828767.
The finding is more than minor because it impacted the program and process attribute of
the Occupational Radiation Safety Cornerstone and affected the cornerstone objective of
ensuring adequate protection of worker health and safety from exposure to radiation, in
that the failure to fully evaluate the radiological hazards present in work areas could
result in unplanned exposure to workers. The finding was determined to be of very low
safety significance because it was not an As-Low-As-Is-Reasonably-Achievable
(ALARA) planning issue, there was no overexposure nor potential for overexposure, and
the licensees ability to assess dose was not compromised. This finding was caused by
inadequate self-checking and peer checking. Consequently, the cause of this deficiency
had a cross-cutting aspect in the area of Human Performance. (H.4(a)) Specifically, the
licensee failed to utilize human error prevention techniques commensurate with the risk
of the task. (Section 2OS1.1)
B.
Licensee-Identified Violations
Four 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 CAP. These violations and corrective action tracking
numbers are listed in Section 4OA7 of this report.
Enclosure
3
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at or near full power throughout the inspection period with minor exceptions.
Unit 2 operated at or near full power throughout the inspection period with one exception. Unit 2
was in a refueling outage from October 6 through October 24, 2009.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1
Winter Seasonal Readiness Preparations
a.
Inspection Scope
The inspectors conducted a review of the licensees preparations for winter conditions to
verify that the plants design features and implementation of procedures were sufficient
to protect mitigating systems from the effects of adverse weather. Documentation for
selected risk-significant systems was reviewed to ensure that these systems would
remain functional when challenged by inclement weather. 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. Cold weather protection, such as
heat tracing and area heaters, was verified to be in operation where applicable. 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.
Specific documents reviewed during this inspection are listed in the Attachment. The
inspectors reviews focused specifically on the following plant systems due to their risk
significance or susceptibility to cold weather issues:
Diesel Generator Ventilation; and
Essential Service Water Cooling Towers.
This inspection constituted one winter seasonal readiness preparations sample as
defined in IP 71111.01-05.
b.
Findings
No findings of significance were identified.
Enclosure
4
1R04 Equipment Alignment (71111.04)
.1
Quarterly Partial System Walkdowns
a.
Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
Unit 2 Train B Auxiliary Feedwater System following Refueling Outage
Maintenance;
Unit 2 Essential Service Water System Following Refueling Outage; and
Unit 1 Train A Diesel Generator While Unit 1 Train B Diesel Generator was Out
of Service.
The inspectors selected these systems based on their risk significance relative to the
reactor safety cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could 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 three partial system walkdown samples as defined in
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 that were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
Division 12 Switchgear Room (Zone 5.1-1);
Division 21 Switchgear Room (Zone 5.6-2);
Enclosure
5
Auxiliary Building Elevation 451 (Zone 5.6-1);
Auxiliary Building Elevation 426 (Zone 5.1-1);
Auxiliary Building Elevation 426 (Zone 5.2-1); and
Auxiliary Building Elevation 383 (Zone 11.4-0).
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.
These activities constituted six quarterly fire protection inspection samples as defined in
b.
Findings
No findings of significance were identified.
.2
Annual Fire Protection Drill Observation (71111.05A)
a.
Inspection Scope
On September 14 and 21, 2008, the inspectors observed a fire brigade activation for a
Security Diesel Charger Fire. Based on this observation, the inspectors evaluated the
readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee
staff identified deficiencies; openly discussed them in a self-critical manner at the drill
debrief, and took appropriate corrective actions. Specific attributes evaluated were:
(1) proper wearing of turnout gear and self-contained breathing apparatus; (2) proper
use and layout of fire hoses; (3) employment of appropriate fire fighting techniques;
(4) sufficient firefighting equipment brought to the scene; (5) effectiveness of fire brigade
leader communications, command, and control; (6) search for victims and propagation of
the fire into other plant areas; (7) smoke removal operations; (8) utilization of pre
planned strategies; (9) adherence to the pre-planned drill scenario; and (10) drill
objectives. In addition, the inspectors evaluated the fire brigades training qualification
and the licensees self-contained breathing apparatus inspection and maintenance
program. Documents reviewed are listed in the Attachment to this report.
These activities constituted one annual fire protection inspection sample as defined by
Enclosure
6
b.
Findings
No findings of significance were identified.
1R06 Flooding (71111.06)
.1
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 area(s) 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:
Turbine Building Internal Flooding.
This inspection constituted one internal flooding sample as defined in IP 71111.06-05.
b.
Findings
No findings of significance were identified.
1R07 Annual Heat Sink Performance (71111.07)
.1
Heat Sink Performance
a.
Inspection Scope
The inspectors reviewed the licensees testing of Unit 2 Train B Diesel Generator Jacket
Water Heat Exchanger and Unit 2 Train C Reactor Containment Fan Cooler (RCFC)
Heat Exchanger to verify that potential deficiencies did not mask the licensees ability to
detect degraded performance, to identify any common cause issues that had the
potential to increase risk, and to ensure that the licensee was adequately addressing
problems that could result in initiating events that would cause an increase in risk. The
inspectors reviewed the licensees observations as compared against acceptance
criteria, the correlation of scheduled testing and the frequency of testing, and the impact
of instrument inaccuracies on test results. Inspectors also verified that test acceptance
criteria considered differences between test conditions, design conditions, and testing
conditions. Documents reviewed are listed in the Attachment to this report.
Enclosure
7
This annual heat sink performance inspection constituted two samples as defined in
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 November 4, 2008, 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.
.2
Licensed Operator Requalification Program (LORT)
a.
Inspection Scope
The inspectors performed an inspection of the licensees LORT test/examination
program for compliance with the stations Systems Approach to Training (SAT) program
which would satisfy the requirements of 10 CFR 55.59(c)(4). The reviewed operating
examination material consisted of six operating tests, each containing two or three
dynamic simulator scenarios per operating test and 36 job performance measures
(JPMs). The written examinations reviewed consisted of six written examinations, each
including a Part A, Plant and Control Systems, and Part B, Administrative
Enclosure
8
Controls/Procedure Limits. The examinations contained approximately 35 questions.
The inspectors reviewed the annual requalification operating test and biennial written
examination material to evaluate general quality, construction, and difficulty level. The
inspectors assessed the level of examination material duplication from week-to-week
during the current year operating test. The examiners assessed the amount of written
examination material duplication from week-to-week for the written examination
administered in 2006. The inspectors reviewed the methodology for developing the
examinations, including the LORT program 2-year sample plan, probabilistic risk
assessment insights, previously identified operator performance deficiencies, and plant
modifications. The documents reviewed during this inspection are listed in the
Attachment.
b.
Findings
No findings of significance were identified.
.3
Annual Operating Test Results
a.
Inspection Scope
The inspectors reviewed the overall pass/fail results of the biennial written examination,
the individual JPM operating tests, and the simulator operating tests, which were
required to be given per 10 CFR 55.59(a)(2)) administered by the licensee from
September 22, 2008, through December 15, 2008, as part of the licensees operator
licensing requalification cycle. These results were compared to the thresholds
established in IMC 0609, Appendix I, Licensed Operator Requalification Significance
Determination Process (SDP)." The evaluations were also performed to determine if the
licensee effectively implemented operator requalification guidelines established in
NUREG-1021, Operator Licensing Examination Standards for Power Reactors, and
Inspection Procedure 71111.11, Licensed Operator Requalification Program. The
documents reviewed during this inspection are listed in the Attachment.
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:
Auxiliary Building Ventilation System;
Unit 1 Train A Diesel Generator Ventilation Failure; and
Unit 2 Train A Diesel Generator Failure to Start During Manual Start Surveillance.
Enclosure
9
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 three 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)
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:
Unit 0 Component Cooling Heat Exchanger Out of Service while Unit 2 Train B
Diesel Generator was Out Of Service (OOS) and Bus Tie Breaker 12-13 was
open;
Shutdown Safety during Core Reload with Essential Service Water System
Return X-Tie Valve & Unit 0 Component Cooling Heat Exchanger OOS
Unit 2 Train A Residual Heat Removal System Work Window while Unit 2
Component Cooling Heat Exchanger was OOS; and
Unit 2 Train A Diesel Generator Failure to Start During Manual Start Surveillance.
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
Enclosure
10
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
four samples as defined in IP 71111.13-05.
b.
Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors reviewed the following issues:
Unit 2 Train B Auxiliary Feedwater Pump Jacket Water System Overflow;
Unit 1 Loose Part Monitoring System Noise;
Unit 2 Train B Containment Sump Isolation Valve Motor Degradation; and
Unit 1 Train B Diesel Generator Cylinder and Head Indications.
The inspectors selected these potential operability issues based on the risk-significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that 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 four samples as defined in IP 71111.15-05
b.
Findings
No findings of significance were identified.
Enclosure
11
1R18 Plant Modifications (71111.18)
.1
Temporary Plant Modifications
a.
Inspection Scope
The inspectors reviewed the following temporary modification:
Temporary Line to Connect the Drain Lines of Unit 2 A and D Reactor Coolant
Pump Standpipes.
The inspectors compared the temporary configuration change 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 system. 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 verified that as applicable that 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, and engineering 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 one temporary modification sample as defined in
b.
Findings
No findings of significance were identified.
.2
Permanent Plant Modifications
a.
Inspection Scope
The following engineering design package was reviewed and selected aspects were
discussed with engineering personnel:
Unit 2 Residual Heat Removal System Vent Valve Addition.
This document and related documentation were reviewed for adequacy of the
associated 10 CFR 50.59 safety evaluation screening, consideration of design
parameters, implementation of the modification, post-modification testing, and relevant
procedures, design, and licensing documents were properly updated. The inspectors
observed ongoing and completed work activities to verify that installation was consistent
with the design control documents. The modification added vent locations to safety
related piping in order to allow the removal of air/voids as necessary such as following
maintenance. Documents reviewed are listed in the Attachment to this report.
Enclosure
12
This inspection constituted one permanent plant modification sample as defined in
b.
Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors reviewed the following post-maintenance (PM) activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
Unit 2 Safety Injection System Accumulator Injection Check Valve 2SI8818C
Repair;
Unit 2 Charging/Safety Injection System Flow Balance following Outage
Maintenance;
Unit 1 Train B Charging Pump Return to Service Following Maintenance;
Unit 2 Train B Auxiliary Feedwater Valve Emergency Actuation Signal
Verification Test;
Work Order (WO) 1171264, Operate Diesel Generator 2A in Local Following
Switch Repair;
WO 00999110, Unit 1 Train B RCFC Following Breaker Maintenance; and
Relay Actuation Surveillance 2BOSR 3.2.8-632A to Test Valve 2AF004A.
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 Part 50 requirements, licensee procedures, and various
NRC generic communications to ensure that the test results adequately ensured that the
equipment met the licensing basis and design requirements. In addition, the inspectors
reviewed corrective action documents associated with 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
b.
Findings
No findings of significance were identified.
Enclosure
13
1R20 Outage Activities (71111.20)
a.
Inspection Scope
The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the
Unit 2 refueling outage (RFO - B2R14), conducted October 6 through October 24, 2008,
that the licensee had appropriately considered risk, industry experience, and previous
site-specific problems in developing and implementing a plan that assured maintenance
of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown
and cooldown processes and monitored licensee controls over the outage activities
listed below. Documents reviewed during the inspection are listed in the Attachment to
this report.
Licensee configuration management, including maintenance of defense-in-depth
commensurate with the OSP for key safety functions and compliance with the
applicable TS when taking equipment out-of-service.
Implementation of clearance activities and confirmation that tags were properly
hung and equipment appropriately configured to safely support the work or
testing.
Installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indication, accounting for instrument error.
Controls over the status and configuration of electrical systems to ensure that
TS and OSP requirements were met, and controls over switchyard activities.
Monitoring of decay heat removal processes, systems, and components.
Controls to ensure that outage work was not impacting the ability of the operators
to operate the spent fuel pool cooling system.
Reactor water inventory controls including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss.
Controls over activities that could affect reactivity.
Refueling activities, including fuel handling.
Startup and ascension to full power operation, tracking of startup prerequisites,
walkdown of the containment to verify that debris had not been left which could
block emergency core cooling system suction strainers, and reactor physics
testing.
Licensee identification and resolution of problems related to RFO activities.
This inspection constituted one RFO sample as defined in IP 71111.20-05.
b.
Findings
Introduction: The inspectors identified a finding of very low safety significance and an
associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, for the licensees failure to follow Procedure BAP 1450-1, Access to
Containment.
Description: On October 22, 2008, the licensee was in the process of restarting Unit 2
from the refueling outage. The inspectors performed an assessment for loose debris
inside of containment following the licensees completion of their readiness for changing
from Mode 5 to Mode 4. During the assessment, the inspectors identified items that
required removal prior to the change in mode, most of which were of a minor nature.
Enclosure
14
Examples included pieces of duct tape, cable ties, several signs, and some trash.
However, items found on the polar crane and items that had been left to support control
rod drop timing testing were required by procedure either to be removed prior to Mode 4
or to have an engineering analysis to support their presence inside containment in
Mode 4 and above.
In Mode 4 and above, the licensee was required by TS to have the emergency sump
operable and thus containment cleanliness was required. At the time when the
inspectors performed their assessment of containment cleanliness, the licensee was in
Mode 5 but was within hours of making the change to Mode 4. Therefore, at the time of
identification by the inspectors, the items were not a challenge to the TS requirements
but should have been removed in preparation for the mode change. The items left for
the control rod drop testing were evaluated by engineering to be left and found to be
acceptable. However, due to an internal licensee miss-communication, the items on the
polar crane were left in place without an engineering evaluation performed. This
condition was not identified until after Mode 4 was achieved. In addition, the licensees
IR, which documented the items found by the inspectors, stated that items on the polar
crane were removed; when in fact, they were still on the crane.
The items that had been left through the mode change into Mode 4 were subsequently
evaluated by the licensee as being acceptable and not a significant challenge to blocking
the containment recirculation sump screens following a postulated accident. After the
final use of the polar crane, these items were removed. They consisted mainly of work
orders, copies of procedures, and fibrous rope.
Analysis: The inspectors determined that the failure to remove loose debris items from
containment prior to Mode 4 or to perform an engineering evaluation as required by
procedure was a performance deficiency warranting a significance determination. Using
IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated
September 20, 2007; the inspectors concluded that the finding was greater than minor
because, if left uncorrected, the issue could have become a more significant safety
concern. The inspectors evaluated the finding using IMC 0609, Significance
Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and
Characterization of Finding, dated January 10, 2008, for the Mitigating Systems
Cornerstone. Since this finding was not a design or qualification deficiency, did not
result in loss of system or train safety function and was not safety significant due to
external events, it was screened as very low safety significance (Green).
This finding is related to the Work Control component of the Human Performance
cross-cutting area for the licensees failure to coordinate work activities and the need for
work groups to coordinate with each other. The personnel who left the material in
containment assumed it was acceptable as they had documented the material in a
surveillance data sheet and the personnel who reviewed the completed data sheet
assumed the material had been or would be removed from containment and none
questioned the potential impact upon the recirculation sump screens or coordinated with
each other to ensure resolution of the material prior to a mode change. (H.3(b))
Enforcement: 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that activities affecting quality shall be prescribed by
procedures and accomplished in accordance to these procedure. Byron Administrative
Procedure BAP 1450-1, Revision 37, Access to Containment, was written in
Enclosure
15
accordance with Appendix B. Step 3.2.1 stated in part that, Tools and Equipment taken
into containment in Modes 1, 2, 3, or 4 will be removed when personnel exit
containment. Engineering evaluation and approval is required to leave materials, tools,
and equipment unattended in containment. Contrary to the above, on
October 22, 2008, the inspectors identified that licensee personnel left material inside of
containment in Mode 5 with the knowledge that the material would remain present in
Mode 4 and Mode 3 and an engineering evaluation had not been performed. Because
this violation was of very low safety significance and was captured in the licensees
corrective action program (IR 835427), it is being treated as a NCV consistent with
Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000455/2008005-01)
The inspectors determined that the licensees subsequent failure to promptly correct the
loose debris left inside of containment even though the items had been entered into the
corrective action system was a performance deficiency. Since this violation was
licensee-identified, the enforcement aspect and its safety significance are described in
Section 4OA7 of this report.
1R22 Surveillance Testing (71111.22)
.1
Routine 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:
Unit 2 Train B Diesel Generator 18-month Safety Injection Signal Override Test;
Unit 2 Train B Auxiliary Feedwater Valve Verification Test;
Unit 2 Train A Diesel Generator Operability Surveillance; and
Unit 2 Train B Auxiliary Feedwater Pump Monthly Surveillance.
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine 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 USAR, 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;
Enclosure
16
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, as defined in
IP 71111.22, Section -05.
b.
Findings
No findings of significance were identified.
.2
Inservice Testing (IST) Surveillance
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:
Unit 2 Charging/Safety Injection System Flow Balance; and
Unit 2 Reactor Coolant System Pressure Isolation Valve and Cold Leg Injection
Isolation Valve Leakage Surveillance.
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine whether: any preconditioning occurred; effects of the testing were
adequately addressed by control room personnel or engineers prior to the
commencement of the testing; acceptance criteria were clearly stated, demonstrated
Enclosure
17
operational readiness, and were 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 corrective action program.
Documents reviewed are listed in the Attachment.
This inspection constituted two inservice inspection samples as defined in Inspection
Procedure 71111.22.
b.
Findings
No findings of significance were identified.
.3
Containment Isolation Valve Testing
The inspectors reviewed the test results for the following activity to determine whether
the risk-significant system and equipment were capable of performing their intended
safety function and to verify testing was conducted in accordance with applicable
procedural and TS requirements:
Local Leak Rate Test for Containment Isolation Valve 1RY8028.
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine whether: any preconditioning occurred; effects of the testing were
adequately addressed by control room personnel or engineers prior to the
commencement of the testing; acceptance criteria were clearly stated, demonstrated
operational readiness, and were 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
Enclosure
18
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, test results not meeting acceptance criteria were addressed
with an adequate operability evaluation or the system or component was declared
inoperable; 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 were listed in the Attachment.
This inspection constituted one containment isolation valve inspection sample as defined
in IP 71111.22-05.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation (71114.06)
.1
Emergency Preparedness Drill Observation
a.
Inspection Scope
The inspectors evaluated the conduct of a licensee unannounced off-hour drive-in drill
on November 12, 2008, to identify any weaknesses and deficiencies in classification,
notification, and protective action recommendation development activities. The
inspectors observed emergency response operations in the Technical Support Center
and Operation Support Center to determine whether the event classification,
notifications, protective action recommendations and associated response activities
were performed in accordance with procedures. The inspectors also attended the
licensee drill critique to compare any inspector-observed weakness with those identified
by the licensee staff in order to evaluate the critique and to verify whether the licensee
staff was properly identifying weaknesses and entering them into the corrective action
program. As part of the inspection, the inspectors reviewed the drill package and other
documents listed in the Attachment to this report.
This emergency preparedness drill inspection constituted one sample as defined in
b.
Findings
No findings of significance were identified.
Enclosure
19
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1
Plant Walkdowns and Radiation Work Permit Reviews
a.
Inspection Scope
The inspectors reviewed licensee controls and surveys in the following radiologically
significant work areas within radiation areas, high radiation areas, and airborne
radioactivity areas in the plant to determine if radiological controls including surveys,
postings, and barricades were acceptable:
Unit 2 Containment Building; and
Auxiliary Building.
This inspection supplements the sample reported in Inspection
Report 05000454/2008002; 05000455/2008002.
The inspectors reviewed the radiation work permits (RWPs) and work packages used to
access these areas and other high radiation work areas. The inspectors assessed the
work control instructions and control barriers specified by the licensee. Electronic
dosimeter alarm set points for both integrated dose and dose rate were evaluated for
conformity with survey indications and plant policy. The inspectors interviewed workers
to verify that they were aware of the actions required if their electronic dosimeters
noticeably malfunctioned or alarmed.
This inspection supplements the sample reported in Inspection
Report 05000454/2008002; 05000455/2008002.
The inspectors also reviewed the licensees physical and programmatic controls for
highly activated and/or contaminated materials (non-fuel) stored within the spent fuel
pool or other storage pools. Documents reviewed were listed in the Attachment.
This inspection constitutes one sample as defined in IP 71121.01-5.
b.
Findings
Introduction: A Green NRC-identified finding of very low safety significance and
associated NCV of TS 5.4.1 was identified for failure to implement procedures required
to evaluate radiological hazards for airborne radioactivity.
Description: The inspectors identified that required air samples were not performed
while workers in the reactor cavity were performing reactor disassembly, during the
refueling outage in October 2008. Additionally, a continuous air sampler was not
operating on the 426 elevation of containment.
Airborne radioactivity surveys verify that the radiological conditions are similar to the
conditions predicted during as-low-as-is-reasonably-achievable (ALARA) Planning.
Enclosure
20
Air samples also validate that the controls specified in the ALARA Plan adequately
protect the workers from unnecessary radiation exposure. The evaluation of the
radiological conditions associated with reactor disassembly was documented in RWP
and ALARA Plan 10008916. The ALARA Plan required continuous air sampling in the
reactor cavity in accordance with licensee Procedure RP-AA-302.Continuous air
sampling involved an air sample system consists of a pump and a filter. The filter is
changed periodically and analyzed for radioactivity deposits. On October 8, 2008, the
filter was removed during the previous shift and not replaced with a new filter. The on-
coming shift assumed that a new air sample filter was replaced and that the air sampler
was returned to service. The on-coming shift allowed work crews to enter the reactor
cavity to perform reactor disassembly activities without validating this assumption.
The inspectors reviewed the corrective actions and ensured that a filter was installed
and the pump was operating before leaving containment. Additionally, the licensee
planned to evaluate the issue and to prescribe long-term actions to prevent recurrence.
Analysis: The inspectors determined that this finding was a performance deficiency
because licensees are required to comply with TS requirements and implement various
radiological control procedures. The inspectors also determined that the deficiency was
reasonably within the licensees ability to foresee and correct. The finding is more than
minor because it is associated with the Occupational Radiation Safety cornerstone
attribute of Program and Process and adversely affects the cornerstone objective of
protecting worker health and safety from exposure to radiation. Specifically, the failure
to perform required air sampling impacted the licensees ability to prevent an unplanned
personnel exposure. The finding was assessed using the Occupational Radiation Safety
SDP. The finding was determined to be of very low safety significance (Green), because
it was not an ALARA planning issue, there was no overexposure or potential for
overexposure, and the licensees ability to assess dose was not compromised.
As described above, this finding was caused by inadequate self-checking and peer
checking. Consequently, the cause of this finding had a cross-cutting aspect in the area
of Human Performance. Specifically, the licensee failed to utilize human error
prevention techniques commensurate with the risk of the task. (H.4(a))Enforcement:
Technical Specification 5.4.1.a. requires that the licensee establish, implement, and
maintain procedures specified in Regulatory Guide 1.33, Revision 2, Appendix A, which
specifies procedure for airborne radiation monitoring and for implementing the ALARA
program. Radiation Protection Procedure RP-AA-401, Operational ALARA Planning
and Controls, Revision 9, outlines the requirements for ALARA Plans and requires that
ALARA plans be developed and implemented. The ALARA Plan that evaluated reactor
disassembly and provided the methods and controls associated with reactor
disassembly activities was documented for RWP 10008916. One of the prescribed
controls included in this ALARA Plan required continuous air sampling in the cavity.
Because this finding is of very low safety significance and has been entered into the
licensees corrective action program as IR 828767, this violation is being treated as an
NCV, consistent with Section VI.A of the NRC Enforcement Policy.
(NCV 05000454/2008005-02; 05000455/2008005-02)
Enclosure
21
.2
Job-In-Progress Reviews
a.
Inspection Scope
The inspectors observed the following two jobs that were being performed in radiation
areas, airborne radioactivity areas, or high radiation areas for observation of work
activities that presented the greatest radiological risk to workers:
Cleaning and Eddy Current Testing of the Seal Table; and
Dye Penetrant Testing of Reactor Head Penetration 68.
The inspectors reviewed radiological job requirements for these activities, including
RWP requirements and work procedure requirements and attended ALARA job
briefings.
This inspection supplements the sample reported in Inspection
Report 05000454/2008002; 05000455/2008002.
Job performance was observed with respect to the radiological control requirements to
assess whether radiological conditions in the work area were adequately communicated
to workers through pre-job briefings and postings. The inspectors evaluated the
adequacy of radiological controls, including required radiation, contamination, and
airborne surveys for system breaches; radiation protection job coverage, including any
applicable audio and visual surveillance for remote job coverage; and contamination
controls. Documents reviewed were listed in the Attachment.
This inspection supplements the sample reported in Inspection
Report 05000454/2008002; 05000455/2008002.
b.
Findings
No findings of significance were identified.
.3
High Risk Significant, High Dose Rate, High Radiation Area, and Very High Radiation
Area Controls
a.
Inspection Scope
The inspectors held discussions with the Radiation Protection Manager concerning high
dose rate, high radiation area and very high radiation area controls and procedures,
including procedural changes that had occurred since the last inspection, in order to
assess whether any procedure modifications substantially reduced the effectiveness and
level of worker protection.
The inspectors discussed with radiation protection supervisors the controls that were in
place for special areas of the plant that had the potential to become very high radiation
areas during certain plant operations. The inspectors assessed if plant operations
required communication beforehand with the radiation protection group, so as to allow
corresponding timely actions to properly post and control the radiation hazards.
Documents reviewed were listed in the Attachment.
Enclosure
22
This inspection constitutes one sample as defined in IP 71121.01-5.
b.
Findings
No findings of significance were identified.
.4
Radiation Worker Performance
a.
Inspection Scope
The inspectors reviewed radiological problem reports for which the cause of the event
was due to radiation worker errors to determine if there was an observable pattern
traceable to a similar cause and to determine if this perspective matched the corrective
action approach taken by the licensee to resolve the reported problems. Problems or
issues with planned or completed corrective actions were discussed with the Radiation
Protection Manager. Documents reviewed were listed in the Attachment.
This inspection constitutes one sample as defined in IP 71121.01-5.
b. Findings
No findings of significance were identified.
.5
Radiation Protection Technician Proficiency
a.
Inspection Scope
The inspectors reviewed radiological problem reports for which the cause of the event
was radiation protection technician error to determine if there was an observable pattern
traceable to a similar cause and to determine if this perspective matched the corrective
action approach taken by the licensee to resolve the reported problems. Documents
reviewed were listed in the Attachment.
This inspection constitutes one sample as defined in IP 71121.01-5.
b.
Findings
No findings of significance were identified.
2OS2 As-Low-As-Reasonably-Achievable Planning and Controls (71121.02)
.1
Radiological Work Planning
a.
Inspection Scope
The inspectors evaluated the licensees list of work activities ranked by estimated
exposure that were in progress and reviewed the following two work activities of highest
exposure significance:
Cleaning and Eddy Current Testing of the Seal Table; and
Dye Penetrant Testing of Reactor Head Penetration 68.
Enclosure
23
This inspection supplements the sample reported in Inspection
Report 05000454/2008002; 05000455/2008002.
For these two activities, the inspectors reviewed the ALARA work activity evaluations,
exposure estimates, and exposure mitigation requirements in order to verify that the
licensee had established procedures and engineering and work controls that were based
on sound radiation protection principles in order to achieve occupational exposures that
were ALARA. The inspectors also determined if the licensee had reasonably grouped
the radiological work into work activities, based on historical precedence, industry
norms, and/or special circumstances.
This inspection supplements the sample reported in Inspection
Report 05000454/2008002; 05000455/2008002.
Documents reviewed were listed in the Attachment.
b. Findings
No findings of significance were identified.
.2
Radiation Worker Performance
a.
Inspection Scope
Radiation worker and radiation protection technician performance was observed during
work activities being performed in radiation areas, airborne radioactivity areas, and high
radiation areas that presented the greatest radiological risk to workers. The inspectors
evaluated whether workers demonstrated the ALARA philosophy by being familiar with
the scope of the work activity and tools to be used, by utilizing ALARA low dose waiting
areas, and by complying with work activity controls. Also, radiation worker training and
skill levels were reviewed to determine if they were sufficient relative to the radiological
hazards and the work involved. Documents reviewed were listed in the Attachment.
This inspection supplements the sample reported in Inspection
Report 05000454/2008002; 05000455/2008002.
b.
Findings
No findings of significance were identified.
4OA1 Performance Indicator Verification (71151)
.1
Mitigating Systems Performance Index - Emergency AC Power System
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index (MSPI) - Unit 1 and Unit 2 Emergency AC Power System performance indicator
for Byron Unit 1 and Unit 2 for the period from the fourth quarter 2007 through the third
quarter 2008. To determine the accuracy of the Performance Indicators (PI) data
reported during those periods, PI definitions and guidance contained in the Nuclear
Enclosure
24
Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator
Guideline, Revision 5, were used. The inspectors reviewed the licensees operator
narrative logs, MSPI derivation reports, issue reports, event reports, and NRC Integrated
Inspection Reports for the period of October 2007 through September 2008 to validate
the accuracy of the submittals. The inspectors reviewed the MSPI component risk
coefficient to determine if it had changed by more than 25 percent in value since the
previous inspection, and if so, that the change was in accordance with applicable
NEI guidance. The inspectors also reviewed the licensees issue report database to
determine if any problems had been identified with the 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 MSPI emergency AC power system samples as defined
in IP 71151-05.
b.
Findings
No findings of significance were identified.
.2
Mitigating Systems Performance Index - High Pressure Injection Systems
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - Unit 1 and Unit 2 High Pressure Injection Systems performance indicator for
Byron Unit 1 and Unit 2 for the period from the fourth quarter 2007 through the third
quarter 2008. To determine the accuracy of the PI data reported during those periods,
PI definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports,
event reports, and NRC Integrated Inspection Reports for the period of October 2007 to
September 2008 to validate the accuracy of the submittals. The inspectors reviewed the
MSPI component risk coefficient to determine if it had changed by more than 25 percent
in value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the 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 MSPI high pressure injection system samples as defined
in IP 71151-05.
b.
Findings
No findings of significance were identified.
Enclosure
25
.3
Mitigating Systems Performance Index - Heat Removal System
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - Unit 1 and Unit 2 Heat Removal System performance indicator for Byron Unit 1
and Unit 2 for the period from the fourth quarter 2007 through the third quarter 2008.
To determine the accuracy of the PI data reported during those periods, PI definitions
and guidance contained in the NEI Document 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the
licensees operator narrative logs, issue reports, event reports, MSPI derivation reports,
and NRC Integrated Inspection Reports for the period of October 2007 through
September 2008 to validate the accuracy of the submittals. The inspectors reviewed the
MSPI component risk coefficient to determine if it had changed by more than 25 percent
in value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the 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 MSPI heat removal system samples as defined in
b.
Findings
No findings of significance were identified.
.4
Mitigating Systems Performance Index - Residual Heat Removal System
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - Unit 1 and Unit 2 Residual Heat Removal System performance indicator for
Byron Unit 1 and Unit 2 for the period from the fourth quarter 2007 through the third
quarter 2008. To determine the accuracy of the PI data reported during those periods,
PI definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports,
event reports, and NRC Integrated Inspection Reports for the period of October 2007
through September 2008 to validate the accuracy of the submittals. The inspectors
reviewed the MSPI component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable NEI guidance. The inspectors also reviewed the licensees
issue report database to determine if any problems had been identified with the 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 MSPI residual heat removal system samples as defined
in IP 71151-05.
Enclosure
26
b.
Findings
No findings of significance were identified.
.5
Mitigating Systems Performance Index - Cooling Water Systems
a.
Inspection Scope
The inspectors sampled licensee submittals for the Unit 1 and Unit 2 Mitigating Systems
Performance Index - Unit 1 and Unit 2 Cooling Water Systems performance indicator for
Byron Unit 1 and Unit 2 for the period from the fourth quarter 2007 through the third
quarter 2008. To determine the accuracy of the PI data reported during those periods,
PI definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports,
event reports, and NRC Integrated Inspection Reports for the period of October 2007
through September 2008 to validate the accuracy of the submittals. The inspectors
reviewed the MSPI component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable NEI guidance. The inspectors also reviewed the licensees
issue report database to determine if any problems had been identified with the 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 MSPI cooling water system samples as defined in
b.
Findings
No findings of significance were identified.
.6
Reactor Coolant System Specific Activity
a.
Inspection Scope
The inspectors sampled licensee submittals for the Reactor Coolant System (RCS)
Specific Activity performance indicator for the period of June 2007 through August 2008
to determine the accuracy of the PI data reported during those periods, PI definitions
and guidance contained in the NEI Document 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the
licensees RCS chemistry samples, TS requirements, issue reports, event reports and
NRC Integrated Inspection Reports for the period of June 2007 through August 2008 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. In addition to record
reviews, the inspectors observed a chemistry technician obtain and analyze a reactor
coolant system sample. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two reactor coolant system specific activity samples as
defined in IP 71151-05.
Enclosure
27
b. Findings
No findings of significance were identified.
.7
Reactor Coolant System Leakage
a.
Inspection Scope
The inspectors sampled licensee submittals for the RCS Leakage performance indicator
Unit 1 Reactor Coolant System Identified Leakage and Unit 2 Reactor Coolant System
Identified Leakage. To determine the accuracy of the PI data reported during those
periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors
reviewed the licensees operator logs, RCS leakage tracking data, issue reports, event
reports, and NRC Integrated Inspection Reports for the period of March 2007 to
November 2008 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 reactor coolant system leakage samples as defined in
b.
Findings
No findings of significance were identified.
.8
Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent
Occurrences
a.
Inspection Scope
The inspectors sampled licensee submittals for the Radiological Effluent TS
(RETS)/Offsite Dose Calculation Manual (ODCM) Radiological Effluent Occurrences
performance indicator for the period of June 2007 through August 2008. The inspectors
used PI definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 5 to determine the accuracy of
the PI data reported during those periods. The inspectors reviewed the licensees issue
report database and selected individual reports generated since this indicator was last
reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or
improperly calculated effluent releases that may have impacted offsite dose. The
inspectors reviewed gaseous effluent summary data and the results of associated offsite
dose calculations for selected dates between June 2007 and August 2008 to determine
if indicator results were accurately reported. The inspectors also reviewed the licensees
methods for quantifying gaseous and liquid effluents and determining effluent dose.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one RETS/ODCM radiological effluent occurrences sample
as defined in IP 71151-05.
Enclosure
28
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
.1
Routine Review of items Entered Into the Corrective Action Program
a.
Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensees 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.
Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees 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.
Enclosure
29
b.
Findings
No findings of significance were identified.
.3
Semi-Annual Trend Review
a.
Inspection 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 July 01 through December 31, 2008,
although some examples expanded beyond those dates when 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.
This review constituted a single semi-annual trend inspection sample as defined in
b.
Findings
No findings of significance were identified.
.4
Selected Issue Follow-Up Inspection: Byron Review of Potential Preconditioning Issue
a.
Inspection Scope
During a review of items entered in the licensees CAP, the inspectors observed that the
licensee was following up on potential preconditioning issues identified at Braidwood for
applicability to Byron Station. The inspectors selected this issue for a follow-up
inspection on problem identification and resolution. Documents reviewed are listed in
the Attachment to this report.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b.
Findings and Observations
In October 2007, the licensee at Braidwood identified a number of potential
preconditioning issues of motor-operated and air-operated valves. Specifically,
preventive maintenance tasks were being performed on the valves prior to the inservice
test such that testing was not being conducted in the as-found condition. Although the
Enclosure
30
ASME Code does not specifically require as-found testing, the NRC had issued several
generic communications on the subject to ensure licensees evaluated the potential
affects of the maintenance on the test results. An action request was initiated to review
this issue for applicability to Byron.
In December 2007, the licensees corporate support group, the licensee and its sister
sites discussed this issue and developed draft guidance on preconditioning. One area
that was considered to be potentially preconditioning was performing stem lubrications
on a valve on the same frequency as the inservice test.
In February 2008, in advance of refueling outage B1R15, the licensee conducted a
review of valves that were tested on a cold shutdown or refueling outage frequency. The
review was performed to determine whether any preventive maintenance was going to
be performed prior to the inservice test on the valve, which could be presumed to be
preconditioning. This review did not identify any instances of preconditioning. The
inspectors, however, questioned six valves that had stem lubrication frequency of once a
refueling cycle and appeared to be performed on the valves prior to the test. This did
not appear to meet the licensees guidance in Procedure ER-AA-302-1006, Generic
Letter 96-05 Program Motor-Operated Valve Maintenance and Testing Guidelines, or
the newly developed draft guidance for what could be potentially considered
preconditioning. The guidance stated that stem lubrication would not be considered
preconditioning unless it was routinely scheduled immediately before and at the same
frequency as the valve test. These six valves appeared to meet the guidance for being
potentially preconditioning issues.
Although the inspectors determined that these valves should have been flagged in the
action request as having potential preconditioning concerns, further review by the
licensee indicated that with the exception of one valve, all the stem lubrications were
performed after the inservice test during the outage. The one exception also had
several other maintenance activities performed during the outage and it was not
conclusive if the testing was performed prior to or after the maintenance. The licensee
indicated that there was not any guidance with respect to the schedule as to whether
testing or maintenance should be performed first. The issue of preconditioning of motor-
operated valves prior to their diagnostic test to meet Generic Letter 96-05, Periodic
Verification of Design-Basis Capability of Safety-Related Power-Operated Valves, may
also be an issue as it may not be possible to verify the valve would have been capable
to operate under design basis conditions for the time frame since the last maintenance
or test without the as-found testing. Although no specific preconditioning issues were
identified, additional scheduling guidance or training may be warranted to highlight the
potential for preconditioning by not testing valves in their as-found condition.
No findings of significance were identified.
.5
4OA5 Other Activities Implementation of Temporary Instruction (TI) 2515/176,
Emergency Diesel Generator Technical Specification Surveillance Requirements
Regarding Endurance and Margin Testing
a.
Inspection Scope
The objective of TI 2515/176 was to gather information to assess the adequacy of
nuclear power plant emergency diesel generator endurance and margin testing as
prescribed in plant-specific TS. The inspectors reviewed the licensee's TS, procedures,
Enclosure
31
and calculations, and interviewed licensee personnel to complete the TI. The
information gathered for this TI was forwarded to the Office of Nuclear Reactor
Regulation for further review and evaluation on December 17, 2008. This TI is complete
at Byron Station; however, this TI 2515/176 will not expire until August 31, 2009.
Additional information may be required after review by the Office of Nuclear Reactor
Regulation.
b.
Findings
No findings of significance were identified.
.6
Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review
a.
Inspection Scope
The inspectors reviewed the final report for the INPO plant assessment conducted in
June 2008 and dated December 2008. The inspectors reviewed the report to ensure
that issues identified were consistent with the NRC perspectives of licensee
performance and to verify if any significant safety issues were identified that required
further NRC follow-up.
b.
Findings
No findings of significance were identified.
.7
Quarterly Resident Inspector Observations of Security Personnel and Activities
a.
Inspection Scope
During the inspection period, the inspectors conducted observations of security force
personnel and activities to ensure that the activities were consistent with licensee
security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during both normal and off-normal plant working hours.
Multiple tours of operations within the Central and Secondary Security Alarm
Stations;
Owner Controlled Area and Protected Area access control posts;
Other security officer posts including the ready room and compensatory posts;
and Security equipment log review.
The inspectors also reviewed a report of the results of a survey of the site security
organization relative to its safety conscious work environment. The inspectors
considered whether the surveys were conducted in a manner that encouraged candid
and honest feedback. The results were reviewed to determine whether an adequate
number of staff responded to the survey. The inspectors also reviewed Exelons
self-assessment of the survey results and verified that any issues or areas for
improvement were entered into the corrective action program for resolution.
These quarterly resident inspector observations of security force personnel and activities
did not constitute any additional inspection samples. Rather, they were considered an
integral part of the inspectors' normal plant status review and inspection activities.
Enclosure
32
b.
Findings
No findings of significance were identified.
.8
(Closed) Unresolved Items (URI) 05000454/455/2008003-06: Auxiliary Feedwater
Tunnel Hatch Margin to Safety
The licensee had identified that the design analysis for evaluation of the Auxiliary
Feedwater (AFW) tunnel flood seal covers did not include the effects of a high energy
line break in the main steam isolation valve tunnels at another facility. The NRC
inspectors at that facility questioned why a dynamic load factor as a result of the impulse
pressure following a high energy line break had not been considered in an analytic
calculation performed to support the operability evaluation.
Following a review of the licensees evaluation, the inspectors questioned the licensees
conclusion that the operability of the AFW hatches continued to be supported despite
analytical results showing a factor of safety for the concrete expansion anchors
supporting the hatches of less than 2.0, which is contrary to the guidance provided in
NRC Bulletin 79-02, Pipe Support Base Plate Designs Using Concrete Expansion
Anchors. Additionally, the inspectors noted that the licensees evaluation did not
address Section C.13 of NRC Technical Guidance 9900, Operability Determinations &
Functionality Assessment for Resolution of Degraded or Nonconforming Conditions
Adverse to Quality or Safety. Specifically, Section C.13 stated that if a structure was
degraded, the licensee should assess the structures capability of performing its
specified function. As long as the identified degradation did not result in exceeding
acceptance limits specified in applicable design codes and standards referenced in the
design basis documents, the affected structure was either operable or functional. The
licensee also identified additional errors that reduced the margin of safety for the
structural integrity of a high energy line break barrier.
At the close of the inspection period that opened this URI, temporary modifications were
implemented at both facilities that restored the margin of safety to greater than 2.0.
Pending additional follow-up by the inspectors for the past operability and timeliness of
corrective actions, extent of condition, and corrective actions, a URI was opened.
During this inspection period, the issue was assessed by regional inspectors at the other
facility. The inspectors conclusions were reviewed by the inspectors at Byron and
confirmed to be applicable to Byron. The inspectors documented their review in
Section 4OA7 as two licensee-identified violations. This URI is closed.
4OA6 Management Meetings
.1
Exit Meeting Summary
On January 15, 2009, the inspectors presented the inspection results to Mr. D. Hoots
and other members of the licensee staff. The licensee acknowledged the issues
presented. The inspectors confirmed that none of the material examined during the
inspection was proprietary.
.2
Interim Exit Meetings
Enclosure
33
Interim exits were conducted for:
Occupational Radiation Safety Program for Access to Radiologically Significant
Areas and Performance Indicator Verification with Mr. D. Hoots, and other
members of the licensees staff on October 10, 2008.
Inservice Inspection 71111.08 with Mr. D. Hoots on October 16, 2008. The
inspectors returned proprietary information reviewed during the inspection prior
to leaving the site.
TI 2515/176 via telephone with Mr. B. Grundmann and other licensee staff on
November 25, 2008.
The licensed operator requalification training written examination and operating
test construction and the biennial written examination and annual operating test
results with Mr. G. Wolfe via telephone on December 15, 2008.
The inspectors confirmed that none of the potential report input discussed was
considered proprietary.
4OA7 Licensee-Identified Violations
The following violation of very low significance (Green) was identified by the licensee
and is a violation of NRC requirements which meet the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.
NRC Order EA-03-009, for Byron Unit 2, requires that the licensee perform
ultrasonic testing of each RPV head penetration nozzle every refueling outage
because of its high susceptibility ranking. Contrary to this, the licensee
discovered during the current B2R14 outage that penetration 41 was not
ultrasonically tested during the prior Unit 2 outage in April 2007 (B2R13). No
observable boric acid deposits were noted as a result of the bare metal visual
examination of the penetration nozzles performed during outages B2R13 and
B2R14; and there were no reportable indications found as a result of the B2R14
ultrasonic test of penetration 41. Based upon this, the violation was of very low
safety significance. The licensee entered this issue into the corrective action
program as IR 829647.
10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part,
that measures shall be established to assure that conditions adverse to quality,
such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and non-conformances are promptly identified and corrected.
Licensee Procedure LS-AA-125, Revision 12, Corrective Action Program (CAP)
Procedure, was written in accordance with Criterion XVI. Step 2.12 of
LS-AA-125 requires, in part, a Corrective Action is any action that meets any
of the following. Is necessary to restore a Significance Level 1, 2, or 3
Condition. Contrary to the above, on October 22, 2008, licensee personnel
failed to correct a condition adverse to quality as stated in IR 834410.
Specifically, loose debris that had been left on the polar crane had not been
removed prior to Unit 2 changing from Mode 5 to Mode 4. IR 834410 had been
designated by the licensee as a Significance level 3 condition. This issue is of
very low safety significance because this finding was not a design or qualification
deficiency, did not result in loss of system or train safety function and was not
safety significant due to external events.
Enclosure
34
10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part,
that measures shall be established to assure that conditions adverse to quality,
such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and non-conformances are promptly identified and corrected.
Contrary to the above, since April 18, 2007, the licensee failed to promptly
identify and correct conditions adverse to quality regarding design of AFW tunnel
hatch covers. Specifically, upon finding a design deficiency in the hatch
structural calculation, the licensee failed to promptly identify all the related design
issues through more detailed reviews and field inspections, and to complete
corrective actions to address the design deficiencies and to restore the design
margins. This finding was of very low safety significance because the finding did
not represent an actual open pathway in the physical integrity of reactor
containment. The issue was identified in the licensees CAP as IR 857487. The
licensee had completed a temporary modification to increase the safety margin of
the hatches and is in the process of designing a permanent modification to
restore full design margin.
10 CFR Part 50, Appendix B, Criterion III, Design Control, required, in part, that
design control measures shall provide for verifying or checking the adequacy of
design, such as by the performance of design reviews, by the use of alternate or
simplified calculation methods, or by the performance of a suitable testing
program. Contrary to this, on December 4, 1987, the licensee failed to ensure
design measures were in place for verifying or checking the adequacy of AFW
hatch cover plate design. Specifically, in Calculation 5.6.3.9, the licensee failed
to ensure that a safety factor in accordance with the station design criteria was
applied in the design of expansion anchors. The issue was identified in the
licensees corrective action as IR 654270. This finding was of very low safety
significance because it did not represent an actual open pathway in the physical
integrity of reactor containment.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment
1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
D. Hoots, Site Vice President
W. Grundmann, Regulatory Assurance Manager
Z. Cox, Chemist
G. Contrady, Programs Manager
H. Do, Corporate ISI Engineer
S. Greenlee, Engineering Director
D. Thompson, Radiation Protection Manager
Nuclear Regulatory Commission
R. Skokowski, Branch Chief
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened 05000454/2008005-01
Failure to Remove or Evaluate Loose Debris Inside of
Containment Prior to Applicable Mode 05000454/2008005-02
Failure to Evaluate Radiological Hazards for Airborne
Radioactivity
Closed 05000454/2008005-01
Failure to Remove or Evaluate Loose Debris Inside of
Containment Prior to Applicable Mode 05000454/2008005-02
Failure to Evaluate Radiological Hazards for Airborne
Radioactivity
05000454;
455/2008-003-06
Unit 1 and Unit 2 Auxiliary Feedwater Tunnel Hatch Margin
to Safety
Attachment
2
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
WO 1020141 01; 89-13 Heat Exchanger Inspection for 2B Diesel Driven AF Pump Closed Cycle
Cooler, October 16, 2008
Issue 846625; Procedure Enhancement, November 18, 2008
BOP SX-T2; SX Tower Operations Guidelines, Revision 12
Section 1R04: Equipment Alignment (Quarterly)
2BOSR 7.8.1-1; Unit 2 Essential Service Water System Valve Position Monthly Surveillance,
Revision 16
BOP DG-1; Diesel Generator Alignment to Standby Condition, Revision 11
BOP VD-5; DG Room Ventilation System Operation, Revision 6
BwOP VD-5; DG Room Ventilation System operation, Revision 12
BwOS VD-1a; Diesel Ventilation Systems; Revision 4
10 CFR 50.59 Screening, BOP Vd-5 DG Room Ventilation System Operation; January 06, 1986
Corrective Action Documents as a Result of NRC Inspection
IR 852537; Compensatory Actions Not Procedurally Directed, December 4, 2008
Section 1R05: Fire Protection (Quarterly)
Corrective Action Documents as a Result of NRC Inspection
IR 842026; Fire Zone Walkdown Issues, November 07, 2008
IR 850920; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
IR 850922; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
IR 850925; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
IR 850926; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
IR 850929; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
IR 850931; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
IR 850932; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
IR 842026; Fire Zone Walkdown Issues, November 07, 2008
IR 847572; Interim NRC Inspector Fire Zone Walkdown Findings, November 20, 2008
Section 1R05: Fire Protection (Annual)
BAP 1100-10; Response Procedure for Fire, Revision 7
BAP 1100-10T1; 401 Fire Brigade Equipment Inventory, Revision 7
Byron Emergency Self-Contained Breathing Apparatus Storage Locations Monthly Inventory,
September 2008
OP-AA-201-003; Fire Drill Performance, Revision 7
Attachment
3
OP-AA-201-005; Fire Brigade Qualification, Revision 6
OP-AA-201-008; Pre-Fire Plans, Revision 1
RP-BY-1000; Maintenance Care and Inspection of the ISI Viking Self-Contained Breathing
Apparatus (SCBA), Revision 9
Self-Contained Breathing Apparatus Monthly Inspection, September 2008
Byron Station Fire Drill Critique Form, August 24, 2008
Summary Report for Each Shift Reflecting Fire Brigade and HazMat Qualification Status,
October 12, 2008
IR 823253; Safe-Guards Information Slows Fire Response, September 27, 2008
Section 1R07: Heat Sink Performance
WO 1036955; Perform As-Found/As-Left Inspections of 2C RCFC
Issue 830146; Replace RCFC Channel Heads with stainless Steel in B2R15, October 13, 2008
IR 830370; Restricted Tubes in 2C RCFC, Need to Plug, October 13, 2008
IR 829315; 2C RCFC Channel Head Degradation, Divider Plates, October 10, 2008
Section 1R08: Inservice Inspection Activities
IR 829647; Penetration 41 Not Examined During B2R13; October 11, 2008
IR 831084; Foreign Objects Found In 2C SG Secondary Side - B2R14; October 15, 2008
IR 829610; Acceptance Criteria Used On SX Pipe Was Not Appropriate; October 11, 2008
IR 843635, Steam Generator Tube Sheet Inspection Results - B2R14, November 11, 2008
IR 832181; Foreign Objects Found In 2A SG Secondary - B2R14; dated October 17, 2008
IR 830452; B2R14 - Weld Defects Revealed During Radiography Of Repair; October 14, 2008
IT00717275-02; Buildup of Deposits in Steam Generators, NRC IN 2007-37
ER-AP-335-1012; Bare Metal Visual Examination of PWR Vessel Penetration and Nozzle Safe-
Ends; Revision 3
ER-AP-335-040; Evaluation of Eddy Current Data for Steam Generator Tubing; Revision 4
EXE-ISI-11; Liquid Penetrant Examination, Revision 4
EXE-UT-350; Procedure for Acquiring Material Thickness and Weld Contours; Revision 2
EXE-PDI-UT-2; Ultrasonic Examination of Austenitic Piping Welds in Accordance with PDI-UT-
2; Revision 5
EXAE-ISI-8; VT-1 Direct; Revision 1
ER-AP-335-039; Multi-Frequency Eddy Current Data Acquisition of Steam Generator Tubing;
Revision 5
ER-MW-335-1009; Site Specific Performance; Revision 4
ER-AP-331; Boric Acid Corrosion Control (BACC) Program; Revision 3
ER-AP-331-1001; Boric Acid Corrosion control (BACC) Inspection Locations, Implementation
and Inspection Guidelines; Revision 3
ER-AP-331-1002; Boric Acid Corrosion control Program Identification, Screening, and
Evaluation; Revision 4
ER-AP-331-1004; Boric Acid Corrosion Control (BACC) Training and Qualification, Revision 2
ER-AP-420-002; Byron/Braidwood Unit 2: Steam Generator Eddy Current Activities; Revision 8
Section 1R11: Licensed Operator Requalification Program
Six Reactor Operator Biennial Written Examinations for CY 2008; no dates
Thirty Senior Reactor Operator Examination Questions for CY 2008 Exams; no dates
Twelve Dynamic Simulator Scenarios; no dates
Attachment
4
48 Job Performance Measures; no dates
Licensed Operator Written Examination and Operating Test Results, CY 2008; no date
Section 1R12: Maintenance Effectiveness
IR 417274; Hydramotor Indication Shows Open but Damper Blades are Closed, March 11, 2002
IR 460411; VA Supply/Exhaust Fan Vibration Alarm Setpoint Basis Concern
IR 717005; VA-Tolerance for Equipment Degradation, January 1, 2008
IR 726481; High Vibrations on 0C VA Fan (Supply Fan), January 24, 2008
IR 727128; VA Issues, January 26, 2008
IR 735812; VA Concerns, February 13, 2001
IR 748406; Need (A)(1) Determination: VA Unacceptable Performance Trend, March 12, 2008
IR 850742; Control Damper Problems for 1A DG Ventilation, December 01, 2008
IR 869580; MM Expanded Scope Replace Linear Converter, January 23, 2007
IR 999934; Replace Linear Converter, November 07, 2008
WO 99270872; 1A DG Vent Outside Damp Not Fully Closed, September 13, 2008
VA Degradation/Status Presentations to the Plant Health Committee, December 10, 2007,
February 4, 2008, and May 5, 2008
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Unit 1 Risk Configurations; Week of October 13, 2008, Revision 3
Unit 2 Risk Configurations; Week of November 17, 2008
Protected Equipment Log for 2B DG Outage, October 11, 2008
Protected Equipment Log for Line 0622/Bus 12 Outage, October 12, 2008
Protected Equipment Log for Unit 0 Component Cooling Water Heat Exchanger,
October 11, 2008
Protected Equipment Log for Unit 2 CC Heat Exchanger, November 16, 2008
Protected Equipment Log for 2RA RH Pump Suction OOS, November 17, 2008
B2R14 Shutdown Risk Evaluation; October 15, 2008
B2R14 Outage Status, October 16, 2008
Byron Operations Log; October 15, 2008, to October 16, 2008
OU-AP-104; Shutdown Safety Management Program Byron/Braidwood Annex, Revision 11
IR 832167; NOS Identified OPS Lacks Sensitivity to OLR/SDR, October 17, 2008
Unit 0/1/2 Standing Order; Operator Ownership During IMD Surveillances, October 17, 2008
IR 829481; NOS ID Shutdown Risk Vulnerability, October 10, 2008
Section 1R15: Operability Evaluations
IR 810117; Unit 1 LM Indicates Potential Source of Noise as Near 1RC8002D, August 22, 2008
IR 810867; Expansion Tank Overflow When Started and Running, August 26, 2008
IR 814019; Low JW Level in the 1B AF Pump, September 04, 2008
IR 846398; Need Work Order Created to Replace Grease, November 18, 2008
IR 846420; 2SI8811A; Motor Found Degraded Per Inspection Criteria, November 18, 2008
EC 366163; Operations Evaluation 07-005, Unventable Gas Voids in Containment Recirculation
Sump Piping, November 20, 2008
EC 371879; Operations Evaluation 08-007, Gas Void at 2CS009A, November 20, 2008
EC 371965; Operations Evaluation 08-008, 2B AF Pump Jacket Water Overflow, Revision 000
EC 373393; Operations Evaluation 08-010, 1B DG Cylinder and Head Indications,
December 18, 2008
Fluid Analysis Report; Unit 2 AF Cooler, September 24, 2008
Attachment
5
Operational and Technical Decision Making 2008 - 2009; Suspect 1RC8002D Valve guide(s)
Not Properly Retained in Valve Body
Adverse Condition Monitoring and Contingency Plan; Unit 1 Loose Parts Monitoring System
(LPMS) Noise, August 26, 2008
CAE-02-31 Westinghouse Letter; LSIV Loose Parts 50.59 Screen EVAL-02-062, Revision 1,
March 21, 2002
WO 1072112 02; MOV PM, Actuator Inspection, Diagnostic testing, November 18, 2008
Section 1R18: Plant Modifications
IR 842362; 2CV181 2A RCP Standpipe PW Supply Valve Failed to Close, November 08, 2008
IR 843783; Unexpected Alarm, November 12, 2008
IR 846404; Revised Bars for TCP 373002 are Incorrect, November 18, 2008
EC 373002; Installation of Temporary Line to Connect the Drain Lines of RCP Standpipes 2A
and 2D, Revision 0
EC 371360; Install Vent Valve on 2SI05CA-8, Revision 2
EC 373224; Provide Temporary Fans for 1A DG Room, Revision 0
WO 01149077; Install Vent Valve on 2SI05CA-8, October 18, 2008
WO 01149077 13; SEP PMT: VT-2 of 2SI130, October 15, 2008
WO 01149077 14; OP PMT: Verify No Seat leakage on 2SI130, October 15, 2008
WO 01149077 15; SEP PMT: Record Vibe Data 2SI130 at Full Flow Conditions,
October 15, 2008
Section 1R19: Post Maintenance Testing
1BOSR 3.2.8-610B; Unit 1 ESFAS Instrumentation Slave Relay Surveillance and Automatic
Actuation Test (Train B Automatic Safety Injection - K610), Revision 2
2BOSR 7.5.5-2; Unit 2 Train B Auxiliary Feedwater Valve Emergency Actuation Signal
Verification Test, Revision 4
WO 999110; 1AP12E-A Relay #1-RCF2 for 1VP01CB Operations PMT Partial 1BOSR 3.2.8-
610B, November 25, 2008
2BOSR 3.2.8-632A; ESFAS Instrumentation Slave Relay Surveillance (Train A Auxiliary
Feedwater Actuation - Relays k632, K639, Revision 2
WO 1165207 01; MM-Repair of 2SI8818C During B2R14
WO 1165207 04; EP - Perform Visual Examination of Disassembled Check Valve
WO 1165207 06; Operations PMT - 2SI8818C SLT Per 2BOSR 4.14.1-1
WO 1165207 07; Operations PMT - 2SI8818C CO Per 2BOSR 5.5.8RH.2-2
WO 1020023 01; 2RH25 VT-2 Exam, October 15, 2008
ASME Section XI Repair/Replacement Plan; 2SI8818C (Loop 3 Cold Leg Accumulation
Injection Check Valve, September 29, 2008
BOP CV-19; Switching Charging Pumps, Revision 14
1BOSR 5.5.1-1; Unit 1 RCS Seal Injection Flow Verification Monthly Surveillance, Revision 4
2BVSR 5.c.2-1; Unit 2 Charging/Safety Injection System Flow Balance, Revision 4
Section 1R20: Refueling and Outage Activities
Ultrasonic Thickness Calibration Data Sheet; Report Number 2008-707
IR 826879; Calibrate/Repair 2FI-0928A, October 05, 2008
IR 834405; Need B2R15 W/O to Retrieve Rag and Wire From Upender Pit
B2R14 Work Orders Added to Date, October 15, 2008
Attachment
6
List of Work Orders Removed from B2R14 via SCARF Process as of 7:00 am on
October 16, 2008
1BGP 100-2; Plant Startup, Revision 37
1BGP 100-2A1; Reactor Startup, Revision 26
1BGP 100-2TI; Plant Startup Flowchart, Revision 10
1BGP 100-2T3; Reactor Startup Flowchart, Revision 5
1BGP 100-4; Power Descension, Revision 36
1BGP 100-4T1; Power Descension Flowchart, Revision 11
1BGP 100-5; Plant Shutdown and Cooldown, Revision 53
1BGP 100-5TI; Plant Shutdown and Cooldown Flowchart, Revision 26
BOP RH-6; Operation of the RH System in Shutdown Cooling, Revision 36
BOP RH-8; Filling the Refueling Cavity for Refueling, Revision 18
BOP RH-9; Pump Down of the Refueling Cavity to the RWST, Revision 24
ALM Corporation Material Handling Platform Lift Manual
BAP 1450-1; Access to Containment, Revision 37
2BOSR Z.5.B.1-1; Containment Loose Debris Inspection, Revision 0
Issue 834555; B2R14 Reactor Cavity Hoist Cable Ties, October 22, 2008
LS-AA-125; Corrective Action Program Procedure, Revision 12
IR 833539; White Plastic Cable Tie Not Immediately Retrievable, October 20, 2008
IR 834002; Foreign Material in 2B ECCS Recirculation Sump, October 21,2008
IR 834087; Loose Debris Walkdown Items Requiring Disposition, October 21, 2008
IR 835427; B2R14 LL - Weakness in Control of Material Left in Containment, October 23, 2008
EC 372856; Evaluation of Foreign Material in Unit 2 Containment Building, November 12, 2008
Corrective Action Documents as a Result of NRC Inspection
IR 833612; Inactive Boric Acid Leak on 2SI8822C, October 20, 2008
IR 833613; Inactive Boric Acid Leak on 2SI8810C, October 20, 2008
IR 833881; Inactive Boric Acid Leak, System Not Verified At This Time, October 21, 2008
IR 834410; B2R14 NRC Mode 3 Containment Walkdown Identified Items, October 22, 2008
IR 856813; Operator Missing a Cover During Mode 4 Walkdown, December 16, 2008
IR 856819; 2LL091E Trickle Charge Light Is Out, December 16, 2008
IR 834410; B2R14 NRC Mode 3 Containment Walkdown Identified Items, October 22, 2008
Section 1R22: Surveillance Testing
1BOSR 6.1.1-11; Primary Containment Type C Local Leakage Rate Tests and IST Tests of
Pressurizer Relief System Partial for 1RY8028, Revision 7
2BOSR 7.5.4-2; Unit 2 Diesel Driven Auxiliary Feedwater Pump Monthly Surveillance,
Revision 16
2BOSR 7.5.5-2; Unit 2 Train B Auxiliary Feedwater Valve Verification Test, Revision 4
2BOSR 8.1.2-1; Unit 2 A Diesel Generator Operability Surveillance, Revision 21
2BVSR 5.c.2-1; Unit 2 Charging/Safety Injection System Flow Balance, Revision 4
WO 1024422 01; 2B Diesel Generator SI Signal Override Test, October 14, 2008
WO 1028733 01; Reactor Coolant System CheckValve Leakage Surveillance, October 21, 2008
WO 1157684 01; 1CV01PB Group A IST Requirement for CV Pump, November 06, 2008
Byron Inservice Testing Bases Document; Valve EPN 2SI8818A-D, Loop A-D Cold Leg
Accumulator Injection Check Valve
Byron Inservice Testing Bases Document; Valve EPN 2SI8948A, Accumulator Outlet to RC
Loop Second Check Valve
Attachment
7
BOP DG-11; Diesel Generator Startup, Revision 20
BOP DG-12; Diesel Generator Shutdown, Revision 19
Corrective Action Documents as a Result of NRC Inspection
IR 841953; IST Basis Documents for 1/2SI8818A-D Need Updating, November 06, 2008
IR 841953; IST Basis Documents for 1/2SI8818A-D Need Updating, November 07, 2008
Section 2OS1: Access Control to Radiologically Significant Areas
RP-AA-460; Controls for High Radiation and Locked High Radiation Areas; Revision 17
RP-AA-460-001; Controls for Very High Radiation Areas; Revision 1
RP-AA-460; Access to Reactor Incore Sump Area; Revision 2
RP- BY-500-1003; Radiological Controls for Handling Items and Hanging Activated Parts in the
Spent Fuel Pool
Radiation Work Permit and Associated ALARA Reviews; RWP 10008926; B2R14 Seal Table -
Rack Disconnect/Maintenance/Eddy Current/Restoration
Radiation Work Permit and Associated ALARA Reviews; RWP 10009830; P-68 Penetrant Test
and Vent Line Inspection
IR 795311; RWP Violations (PC Requirements); dated July 10, 2008
IR 761294; Level 1 Personal Contamination Event; dated 9, 2008
IR 756342; Worker Entered A/D Platform without Electronic Dosimeter; dated March 29, 2008
IR 754696; Worker Locked Out of RCA - Rad Worker Behavior; dated March 26, 2008
IR 756136; PCE: B1R15 Personal Contamination Event; dated March 28, 2008
IR 673712; RP Not Effectively Using Corrective Action Program; dated September 20, 2007
IR 755986; Alpha Survey Documentation Gaps; dated March 27, 2008
IR 756296; RP-AA-460-1001; Not Completed in Timely Manner; dated March 28, 2008
IR 812338; Ni-63 Source Leak Tests Exceed 6-Month Surveillance Frequency; dated
August 22, 2008
Section 1EP6: Drill Evaluation
IR 844467; OSC Minimum Staffing Not Met for Crew D in Drill, November 13, 2008
Byron 2008 Drive-In Drill; Scenario Information
Nuclear Accident Reporting System (NARS) Form; Utility Message No. 2, November 12, 2008
Issue 844467; OSC Minimum Staffing Not Met for During Drill, November 12, 2008
Section 4OA1: Performance Indicator Verification
LS-AA-2090; Monthly Data Elements for NRC Reactor Coolant System (RCS) Specific Activity;
dated July 3, 2007 through September 2, 2008
LS-AA-2100; Monthly Data Elements for NRC Reactor Coolant System Leakage, Revision 5
LS-AA-2150; Monthly Data Elements for RETS/ODCM Radiological Effluent Occurrences; dated
July 10, 2007 through September 10, 2008
MSPI Derivation Report; Unit 1 and Unit 2 High Pressure Injection System Unavailability and
Unreliability Index, February 2008
Operations Log; February 01, 2008 - February 29, 2008
MSPI Derivation Report; Unit 1 and Unit 2 Cooling Water System Unavailability and Unreliability
Index, March 2008
IR 854124; Inconsequential Error identified in March 2008 MSPI Data for SX,
December 09, 2008
Attachment
8
Operations Log; March 01, 2008 - March 31, 2008
MSPI Derivation Report; Unit 1 and Unit 2 Residual Heat Removal System Unavailability and
Unreliability Index, July 2008
Operations Log; July 01, 2008 - July 31, 2008
MSPI Derivation Report; Unit 1 and Heat Removal System Unavailability and Unreliability Index,
October 2007
Operations Log; October 01, 2007 - October 31, 2007
MSPI Derivation Report; Unit 1 and Unit 2 Heat Removal System Unavailability and Unreliability
Index, April 2008
Operations Log; March 01, 2008 - March 31, 2008
Operations Log; October 01, 2007 - October 31, 2007
MSPI Derivation Report; Unit 1 and Unit 2 Emergency AC Power System Unavailability and
Unreliability Index, June 2008
Operations Log, June 01, 2008 - June 30, 2008
Section 4OA2: Identification and Resolution of Problems
IR 642107; IST Program Implementation, June 19, 2007
IR 678543; Possible Pre-Conditioning Issue - IST Testing, October 1, 2007
IR 686518; Byron Review of Braidwood Potential Pre-Conditioning Issue, October 18, 2007
ER-AA-302-1006; Generic Letter 96-05 Program Motor-Operated Valve Maintenance and
Testing Guidelines, Revision 7
Section 4OA5: Other Activities
1BOSR 8.1.14-1; Unit 1A Diesel Generator 24 Hour Endurance Run, Revision 10
1BOSR 8.1.14-2; Unit 1B Diesel Generator 24 Hour Endurance Run, Revision 8
2BOSR 8.1.14-1; Unit 2A Diesel Generator 24 Hour Endurance Run, Revision 10
2BOSR 8.1.14-2; Unit 2B Diesel Generator 24 Hour Endurance Run, Revision 10
Calculation 19-T-5; Diesel Generator Loading During LOOP/LOCA, Revision 6
Attachment
9
LIST OF ACRONYMS USED
Auxiliary Feedwater System
As Low As Reasonably Achievable
Corrective Action Program
CFR
Code of Federal Regulations
IMC
Inspection Manual Chapter
IP
Inspection Procedure
IR
Inspection Report
IR
Issue Report
Inservice Testing
Licensed Operator Requalification Training
Mitigating Systems Performance Index
Non-Cited Violation
NEI
Nuclear Energy Institute
NRC
U.S. Nuclear Regulatory Commission
Out of Service
Offsite Dose Calculation Manual
Outage Safety Plan
Performance Indicator
Reactor Containment Fan Cooler
Radiological Effluent Technical Specifications
Radiation Work Permit
Significance Determination Process
TI
Temporary Instructions
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
Work Order