ML082270029
| ML082270029 | |
| Person / Time | |
|---|---|
| Site: | Braidwood  |
| Issue date: | 08/13/2008 |
| From: | Richard Skokowski Region 3 Branch 3 |
| To: | Pardee C Exelon Generation Co |
| References | |
| FOIA/PA-2010-0209 IR-08-003 | |
| Download: ML082270029 (69) | |
See also: IR 05000456/2008003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
August 13, 2008
Mr. Charles G. Pardee
Chief Nuclear Officer and
Senior Vice President
Exelon Generation Company, LLC
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: BRAIDWOOD STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION
REPORT 05000456/2008003; 05000457/2008003
Dear Mr. Pardee:
On June 30, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated
inspection at your Braidwood Station, Units 1 and 2. The enclosed report documents the
inspection results, which were discussed on July 9, 2008, with Mr. B. Hanson 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, four NRC-identified findings of very low safety
significance (Green) were identified. The findings were also determined to involve 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 a
Non-Cited Violations, in accordance with Section VI.A.1 of the NRC=s Enforcement Policy.
If you contest the subject or severity of a Non-Cited Violation, you should provide a
response within 30 days of the date of this inspection report, with the basis for your denial,
to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington,
DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory
Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,
Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and
the Resident Inspector Office at the Braidwood Station.
C. Pardee -2-
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter
and its enclosure will be made available electronically for public inspection in the NRC
Public Document Room or from the Publicly Available Records (PARS) component of
NRCs 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. 50-456; 50-457
Enclosure: Inspection Report 05000456/2008003; 05000457/2008003
w/Attachment: Supplemental Information
cc w/encl: Site Vice President - Braidwood Station
Plant Manager - Braidwood Station
Regulatory Assurance Manager - Braidwood Station
Chief Operating Officer and Senior Vice President
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
J. Klinger, State Liaison Officer,
Illinois Emergency Management Agency
Chairman, Illinois Commerce Commission
C. Pardee -2-
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter
and its enclosure will be made available electronically for public inspection in the NRC
Public Document Room or from the Publicly Available Records (PARS) component of
NRCs 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. 50-456; 50-457
Enclosure: Inspection Report 05000456/2008003; 05000457/2008003
w/Attachment: Supplemental Information
cc w/encl: Site Vice President - Braidwood Station
Plant Manager - Braidwood Station
Regulatory Assurance Manager - Braidwood Station
Chief Operating Officer and Senior Vice President
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
J. Klinger, State Liaison Officer,
Illinois Emergency Management Agency
Chairman, Illinois Commerce Commission
DOCUMENT NAME: G:\Brai\Braidwood 2008 003.doc
Publicly Available Non-Publicly Available Sensitive Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy
OFFICE RIII RIII
NAME JDalzell:dtp RSkokowski
DATE 08/13/08 08/13/08
OFFICIAL RECORD COPY
Letter to C. Pardee from R. Skokowski dated August 13, 2008
SUBJECT: BRAIDWOOD STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION
REPORT 05000456/2008003; 05000457/2008003
DISTRIBUTION:
Meghan Thorpe-Kavanaugh
RidsNrrDirsIrib Resource
Mark Satorius
Kenneth Obrien
Roland Lickus
DRPIII
DRSIII
Cynthia Pederson (hard copy - IRs only)
Patricia Buckley
ROPreports@nrc.gov(inspection reports, final SDP letters, any letter with an IR number)
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-456; 50-457
Report No: 05000456/2008003 and 05000457/2008003
Licensee: Exelon Generation Company, LLC
Facility: Braidwood Station, Units 1 and 2
Location: Braceville, Illinois
Dates: April 1 through June 30, 2008
Inspectors: S. Ray, Senior Resident Inspector
B. Dickson, Senior Resident Inspector
G. Roach, Senior Resident Inspector (Acting)
A. Garmoe, Resident Inspector
B. Bartlett, Senior Resident Inspector, Byron
D. Betancourt, Resident Inspector (Acting)
N. Féliz, Reactor Engineer
T. Bilik, Reactor Inspector
J. Bozga, Reactor Inspector
M. Holmberg, Reactor Inspector
R. Jones, Reactor Engineer
V. Meghani, Reactor Engineer
M. Mitchell, Health Physicist
C. Zoia, Project Engineer
B. Metro, Illinois Department of Emergency Management
(IEMA)
M. Perry, Resident Inspector, IEMA
J. Roman, IEMA
Observers: J. Gilliam; Reactor Engineer
D. Hills, Branch Chief, Engineering Branch 1
M. Kunowski, Branch Chief, Reactor Projects Branch 5
Approved by: R. Skokowski, Chief
Branch 3
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS ......................................................................................................... 1
REPORT DETAILS..................................................................................................................... 4
Summary of Plant Status......................................................................................................... 4
1. REACTOR SAFETY ..................................................................................................... 4
1R01 Adverse Weather Protection (71111.01) ............................................................ 4
1R04 Equipment Alignment (71111.04)....................................................................... 8
1R05 Fire Protection (71111.05) ................................................................................. 9
1R06 Flooding (71111.06)......................................................................................... 10
1R07 Annual Heat Sink Performance (71111.07)...................................................... 11
1R08 In-service Inspection Activities (71111.08) ....................................................... 12
1R11 Licensed Operator Requalification Program (71111.11)................................... 15
1R12 Maintenance Effectiveness (71111.12) ............................................................ 16
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)........ 17
1R15 Operability Evaluations (71111.15) .................................................................. 17
1R18 Plant Modifications (71111.18)......................................................................... 19
1R19 Post Maintenance Testing (71111.19) ............................................................. 19
1R20 Outage Activities (71111.20)............................................................................ 20
1R22 Surveillance Testing (71111.22)....................................................................... 22
2. RADIATION SAFETY ................................................................................................. 25
2OS1 Access Control to Radiologically Significant Areas (71121.01) ........................ 25
2OS2 As-Low-As-Is-Reasonably-Achievable Planning And Controls (71121.02) ....... 29
2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems
(71122.01)......................................................................................................... 32
2PS2 Radioactive Material Processing and Transportation (71122.02) ..................... 32
4. OTHER ACTIVITIES .................................................................................................. 34
4OA1 Performance Indicator Verification (71151) ...................................................... 34
4OA2 Identification and Resolution of Problems (71152) ........................................... 35
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153) ............... 36
4OA5 Other Activities................................................................................................. 37
4OA6 Management Meetings .................................................................................... 49
SUPPLEMENTAL INFORMATION ............................................................................................. 1
KEY POINTS OF CONTACT ...................................................................................................... 1
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED............................................................ 1
LIST OF DOCUMENTS REVIEWED .......................................................................................... 3
LIST OF ACRONYMS USED.................................................................................................... 13
Enclosure
SUMMARY OF FINDINGS
IR 05000456/2008003, 05000457/2008003; 04/01/2008 - 06/30/2008; Braidwood Station,
Units 1 & 2; Adverse Weather Protection, Flooding, Radioactive Material Processing and
Transportation, and Other Activities.
This report covers a three-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. Four Green findings were identified by the
inspectors. The findings were considered Non-Cited Violations (NCVs) 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 Nuclear Regulatory Commissions (NRCs) program for overseeing
the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process, Revision 4, dated December 2006.
A. NRC-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
- Green. The inspectors identified a performance deficiency involving a NCV of Technical
Specifications 5.4.1, related to the unauthorized and improper storage of loose material
in the designated material exclusion area around the Unit 1 and Unit 2 transformers.
The inspectors identified this issue on a number of occasions. After each occurrence,
the licensee took immediate corrective actions by either removing loose material out of
the transformer yard or properly securing the material being stored in the transformer
yards.
The inspectors concluded that the finding was more than minor because
loose/unsecured material in the transformer yards increased the likelihood of those
events occurring that could upset plant stability. Specifically, during high wind speed
conditions the loose material could have affected the main power transformers and could
have caused a unit trip or it could have affected the station auxiliary transformers that
could increase the likelihood of a loss of mitigating systems. In each case however, the
inspectors concluded that there was not enough debris in either area to affect both
transformers simultaneously. The finding was determined to be of very low safety
significance because it did not contribute to both the likelihood of a reactor trip and the
likelihood that mitigating equipment or functions would not be available. The primary
cause of this NCV was related to the cross-cutting aspect in the area of Human
Performance in the Work Practices component (Item H.4.(b)). Multiple groups, including
contractors and operators failed to properly implement the procedures for control of
material in the transformer exclusion zones. The preliminary cause appeared to be
inadequate supervisory and management oversight of work activities. (Section 1R01.2)
- Green. The inspectors identified a performance deficiency involving a NCV of Title 10 of
the Code of Federal Regulations (10 CFR), Part 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings, related to a plant barrier impairment (PBI)
procedure. The procedure for PBI did not contain steps to ensure that relied-upon
compensatory measures were maintained. Specifically, while the B Train room of
essential service water had a flood barrier removed and covered under a PBI, the
compensatory measure of sump alarms were found not functioning. The licensee has
1 Enclosure
entered the issue into their corrective action program, repaired the sump alarms, and
plans to revise the PBI procedure.
The inspectors concluded that the finding was greater than minor because the licensee
failed to effectively manage prescribed compensatory measures related to a cornerstone
objective. The finding was determined to be of very low safety significance based on a
SDP Phase 1 screening in accordance with IMC 0609, Table 4a, because the finding did
not increase the likelihood of an external or internal flood. The primary cause of this
NCV was related to the cross-cutting component of Human Performance for Resources
(Item H.2.(c)) because the licensees PBI procedure was not adequate in that it did not
ensure safety margins were maintained by providing instructions to periodically verify
that the compensatory measures were still available. (Section 1R06)
Cornerstone: Mitigating Systems
- Green. The inspectors identified a performance deficiency involving a NCV of Technical
Specifications 5.4.1, for the licensees failure to provide procedural controls for the
unique identification of Regulatory Guide 1.97 post-accident instrumentation to aid the
control room operator. Specifically, the licensee failed to adequately control the labeling
on both units control panels and the simulator, resulting in several improperly marked
post-accident indicators. The licensee has entered the issue into their corrective action
program and labeled the appropriate post-accident instruments.
The finding was greater than minor because, if left uncorrected, it could become a more
significant safety concern. Inaccurately labeled control room indicators of post-accident
instrumentation could lead to confusion and hamper operator response if conflicting
indications resulted due to accident conditions. The finding was determined to be of
very low safety significance based on a SDP Phase 1 screening in accordance with
IMC 0609.04, Initial Screening and Characterization of Findings. The inspectors did
not identify a cross-cutting aspect to this finding. (Section 4OA5.3)
Cornerstone: Public Radiation Safety
- Green. A finding of very low safety significance and associated NCV of the Technical
Requirements Manual, Appendix L, and Technical Specifications 5.4.1(a) were identified
by the inspectors. On May 1, 2008, the inspectors identified that the licensee had failed
to sample the temporary wastewater storage tanks installed to hold shower and wash
water from the Unit 2 Containment Access Facility at the required frequency of seven
days. Procedure RP-BR-654, Unit 1(2) Containment Access Facility Liquid and Air
Sampling and Disposal Requirements, Revision 0, as written, did not direct the required
sampling frequency. The licensee took immediate corrective action by sampling the
temporary storage tank, revising the scheduling tool to ensure that the tanks are
sampled at least every seven days when radioactive material is being added to the tank,
and planning to revise the sampling procedure.
The finding involved an occurrence in the licensee's radioactive material control program
that is contrary to the licensees procedures. The finding was more than minor because
it impacted the program and process attribute of the Public Radiation Safety
Cornerstone and affected the cornerstone objective to ensure adequate protection of
public health and safety from exposure to radioactive material release into the public
domain, in that the failure to measure the levels of radioactivity in the temporary storage
2 Enclosure
tanks had the potential to impact the licensees effluent program. The inspectors applied
the IMC 0609, Appendix D, Public Radiation Safety Significance Determination
Process to this finding. The finding is in the licensees radiological effluent monitoring
program. The finding did not involve a failure to implement the effluent release program
nor did public dose exceed Appendix I, Criterion, or 10 CFR 20.1302(e) and the finding
was determined to be of very low safety significance. The primary cause of this NCV
was related to the cross-cutting component of Human Performance for Work Practices
(Item H.4.(c)) because the licensee did not ensure that supervisory and management
oversight of the procedure was adequate to assure nuclear safety. (Section 2PS2.1)
B. Licensee-Identified Violations
No violations of significance were identified.
3 Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at or near full power for the entire inspection period.
Unit 2 operated at or near full power until about April 15, 2008, when a gradual power coast
down was started toward a refueling outage. The unit was brought from 95 percent of full power
to 80 percent on April 17 for main steam relief valve testing and then back to 92 percent of full
power on April 18. The unit continued to coast down until being shutdown from 90 percent
power on April 20, 2008, for the refueling. The unit was made critical at the end of the outage
on May 16, 2008, the generator was placed on line on May 17, 2008, and the power was
gradually increased, reaching full power on May 25, 2008. The unit operated at or near full
power for the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Summer Readiness of Offsite and Alternating Current Power Systems
a. Inspection Scope
The inspectors verified that plant features and procedures for operation and continued
availability of offsite and alternating current (AC) power systems during adverse weather
were appropriate. The inspectors reviewed the licensees procedures affecting these
areas and the communications protocols between the transmission system operator
(TSO) and the plant to verify that the appropriate information was being exchanged
when issues arose that could impact the offsite power system. Examples of aspects
considered in the inspectors review included:
- coordination between the TSO and the plant during off-normal or emergency
events;
- explanations for the events;
- estimates of when the offsite power system would be returned to a normal state;
and
- notifications from the TSO to the plant when the offsite power system was
returned to normal.
The inspectors also verified that plant procedures addressed measures to monitor and
maintain availability and reliability of both the offsite AC power system and the onsite
alternate AC power system prior to or during adverse weather conditions. Specifically,
the inspectors verified that the procedures addressed the following:
- the actions to be taken when notified by the TSO that the post-trip voltage of the
offsite power system at the plant would not be acceptable to assure the
continued operation of the safety-related loads without transferring to the onsite
power supply;
4 Enclosure
- the compensatory actions identified to be performed if it would not be possible to
predict the post-trip voltage at the plant for the current grid conditions;
- a re-assessment of plant risk based on maintenance activities which could affect
grid reliability, or the ability of the transmission system to provide offsite power;
and
- the communications between the plant and the TSO when changes at the plant
could impact the transmission system, or when the capability of the transmission
system to provide adequate offsite power was challenged.
Documents reviewed were listed in the Attachment. The inspectors also reviewed
corrective action program (CAP) items to verify that the licensee was identifying adverse
weather issues at an appropriate threshold and entering them into their CAP in
accordance with station corrective action procedures.
This inspection constituted one readiness of offsite and alternate AC power systems
sample as defined in Inspection Procedure (IP) 71111.01-05.
b. Findings
No findings of significance were identified.
.2 Readiness for Summer Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of the licensees preparations for summer weather
for selected systems, including conditions that could lead to an extended drought as a
result of high temperatures.
During the inspection, the inspectors focused on plant specific design features and the
licensees procedures used to mitigate or respond to adverse weather conditions.
Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)
and performance requirements for systems selected for inspection, and verified that
operator actions were appropriate as specified by plant specific procedures. The
inspectors also reviewed CAP items to verify that the licensee was identifying adverse
weather issues at an appropriate threshold and entering them into their CAP in
accordance with station corrective action procedures. Documents reviewed were listed
in the Attachment. The inspectors reviews focused specifically on the following plant
systems:
- cooling water lake (ultimate heat sink);
- transformer yard; and
- turbine oil system.
This inspection constituted one seasonal adverse weather sample as defined in
IP 71111.01-05.
b. Findings
Introduction: The inspectors identified a Non-Cited Violation (NCV) of Technical
Specifications (TS) 5.4.1.a having very low safety significance (Green) for unauthorized
5 Enclosure
and improper storage of unsecured material in the designated material exclusion area
around the Units 1 and 2 transformers.
Description: On April 30, 2008, the inspectors identified three metal scaffold poles and a
large floor rug in the exclusion area of the Unit 1 transformer yard. The inspectors
notified the shift manager who immediately had the material removed and entered the
issue into the CAP as Issue Report (IR) 770357. The Shift Manager indicated that he
had not given permission, as required by Procedure MA-AA-716-026, Station
Housekeeping/Material Condition Program, for the material to be in the exclusion area.
On May 22, 2008, the inspectors identified four metal stanchions and associated garden
hoses staged, two each, in the Units 1 and 2 transformer yards. The material had been
staged as a contingency for providing supplemental cooling to the main power
transformers as a summer readiness action, but the material was not secured. Although
the staging had the permission of the Shift Manager, it was not done in accordance with
the applicable Procedure, BwOP MP-26, Supplemental Main Power Transformer
Cooling, which required that all hoses in the transformer area be properly secured to
prevent the hoses from becoming wind-generated hazards that may cause a loss of
offsite power. The inspectors notified the Work Execution Center Supervisor who
immediately had the material properly secured with sandbags and entered the issue into
the CAP as IR 778589.
On May 28, 2008, the Illinois Department of Emergency Management (IEMA) inspector
identified a metal stanchion with a radiation warning sign in the Unit 2 transformer yard.
The sign had apparently been removed from the turbine building during floor refinishing
and placed in the transformer yard without the permission of the Shift Manager as
required by Procedure MA-AA-716-026. The IEMA inspector notified the Work
Execution Center Supervisor who immediately had the material removed and entered
the issue into the CAP as IR 780318.
On May 29, 2008, the inspectors identified two pieces of a metal door threshold in the
exclusion area of the Unit 2 transformers. The material was brought to the attention of
an operations supervisor who immediately removed the material and entered the issue
into the CAP as IR 780777. The inspectors noted that this instance, as well as some of
the previously mentioned ones, was probably the result of contractors working on turbine
building floor refinishing, and clearing material off the floor by putting it through the
turbine building door into the exclusion area. The inspectors noted that there were
multiple information signs explaining the exclusion area rules on most of the entry paths
into the exclusion areas except that there were no signs on the doors from the turbine
building directly into the areas. This observation was also entered into the licensees
CAP as part of IR 780777.
Analysis: The inspectors determined that the identification of multiple examples of
improperly placing unsecured material in the transformer yard exclusion zones was a
performance deficiency warranting a significance evaluation. The finding was more than
minor because it involved the external factors attribute of the Initiating Events
cornerstone and affected the cornerstone objective of limiting the likelihood of those
events that could upset plant stability. The inspectors applied the Phase 1 Screening
Worksheet of the Significance Determination Process (SDP) and determined that the
issue screened out as a Green finding because it did not contribute to both the likelihood
of a reactor trip and the likelihood that mitigating equipment or functions would not be
6 Enclosure
available. The material in the transformer yards could have affected the main power
transformers and caused a unit trip, or it could have affected the station auxiliary
transformers and increased the likelihood of a loss of mitigating systems, but it was not
reasonable that it was enough material to affect both simultaneously. The finding had a
cross-cutting aspect in the area of Human Performance in the Work Practices
component (H.4.(b)). Multiple groups, including contractors and operators failed to
properly implement the procedures for control of material in the transformer exclusion
zones. The preliminary cause appeared to be inadequate supervisory and management
oversight of work activities.
Enforcement: Technical Specification 5.4.1.a stated that written procedures shall be
established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978.
Section 1.c of Appendix A recommended procedures for equipment control. Among the
procedures the licensee used to implement that requirement were MA-AA-716-026 and
BwOP MP-26. Under the Storage Practices section of Attachment 1 of MA-AA-716-
026 were requirements that no material be brought into or stored inside the exclusion
zone areas unless prior permission is received from the Shift Manager, that material
shall be secured in the exclusion zone to prevent damage in the event of adverse
weather conditions, and that unsecured scaffold parts must be secured in a manner that
will prevent them from becoming missile hazards in the event of severe weather. For the
supplemental cooling equipment, BwOP MP-26 contained Precaution D.3, which
required that all hoses in the transformer area must be properly secured to prevent the
hoses from becoming wind-generated hazards that may cause loss of offsite power, and
Step F.7, which directed the operators to secure the hoses that will be used to provide
cooling to the main power transformers. Contrary to the above, on three occasions
during the inspection period, the inspectors identified unsecured material in the
transformer exclusion areas that were placed in the areas without the Shift Managers
approval or were not properly secured. Because the failure to properly implement the
material control procedures was of very low safety significance, and has been entered
into the licensees CAP, this violation was treated as an NCV consistent with
Section VI.A.1, of the NRC Enforcement Policy. (NCV 05000456/2008003-01;
.3 Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
On May 30, 2008, the plant experienced a tornado watch as well as high winds and
thunderstorms in the area. The inspectors reviewed the preparations and actions of site
personnel for protection of risk-significant equipment. The inspectors evaluated the
implementation of the licensees adverse weather procedures, risk assessment, and
compensatory actions. No actual tornado occurred in the area during this time period.
Documents reviewed were listed in the Attachment.
The inspection constitutes one readiness for impending adverse weather conditions
sample as defined in IP 71111.01-05,
b. Findings
No findings of significance were identified.
7 Enclosure
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:
replacement;
- 1A auxiliary feedwater (AFW) train while the 1B train was out of service for
troubleshooting and repair of the over speed trip circuit.
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;
- reviewed applicable operating procedures, system diagrams, UFSAR, TS
requirements, Administrative TS, outstanding work orders (WOs), 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;
- walked down accessible portions of the systems to verify system components
and support equipment were aligned correctly and operable;
- examined the material condition of the components and observed operating
parameters of equipment to verify that there were no obvious deficiencies; and
- 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 were listed in the Attachment.
These activities constituted three partial system walkdown samples as defined by
IP 71111.04-05.
b. Findings
No findings of significance were identified.
8 Enclosure
1R05 Fire Protection (71111.05)
.1 Routine Resident Inspector Tours (71111.05Q)
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
- engineered safety features switchgear room, Division 11 (Zone 5.1-1);
- engineered safety features switchgear room, (Zone 5.2-1);
- station auxiliary DG room and diesel oil tank room (Zones 8.7A-0 and 8.7B-0);
- auxiliary building elevation 426 (Zone 11.6-0); and
- compensatory actions for loss of various Appendix R light packs during Bus 234V
outage.
The inspectors reviewed areas to assess if the licensee had implemented a fire
protection program (FPP) 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 five quarterly fire protection inspection samples as defined
by IP71111.05-05.
b. Findings
No findings of significance were identified.
9 Enclosure
1R06 Flooding (71111.06)
a. Inspection Scope
The inspectors performed a walkdown of the following plant area 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:
- Essential service water (SX) pump rooms.
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;
- flood analyses and design documents, including the UFSAR, engineering
calculations, and abnormal operating procedures to identify licensee
commitments;
- 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; and
- the licensees CAP documents with respect to past flood-related items identified
in the CAP to verify the adequacy of the corrective actions.
The specific documents reviewed were listed in the Attachment to this report.
This inspection constituted one internal flooding sample as defined in IP 71111.06-05.
b. Findings
Introduction: The inspectors identified an NCV of 10 CFR Part 50, Appendix B,
Criterion V, having very low significance (Green) related to a plant barrier impairment
(PBI) procedure. Specifically, the procedure did not contain steps to ensure that
compensatory measures in the B Train room of SX were maintained, while required
access covers were removed.
Description: The SX was a safety related system needed to remove decay heat in the
event of an accident. The SX pumps were located in the lowest level of the Auxiliary
Building. The system was designed to prevent failure from flooding by separation of
components and by designing flood barriers in the doors, walls and ceiling. In order to
maintain access to equipment in the room, several removable access covers existed.
When installed, those access covers were designed to prevent flooding from system
failures in the areas above the SX pump rooms from leaking into the room. With the
covers removed, sump leak detection and high level alarms were depended upon to
warn operators should a leak from above the room occur.
When the access covers were removed, several compensatory measures were directed
to be put in place in accordance with Procedure BwAP 1110-3, Plant Barrier Impairment
Program. The compensatory measures were pre-evaluated for each cover.
10 Enclosure
On April 2, 2008, PBI 10586 was authorized to remove equipment cover 2SXFSO2-3.
This hatch had a pre-defined compensatory action to ensure that the room sump alarms
were available. On April 7, 2008, while the PBI was still in effect, operators determined
that the room sump alarms were not functioning. This was documented in the licensees
CAP as IR 760446. Work Order (WO) 103501 was initiated to repair the alarm function.
The WO was completed on April 21. The covers remained removed and the PBI in
effect until after the WO was completed, thus the warning for flooding from sources
above the SX pump room was known to be unavailable for up to fifteen days while an
access cover was removed.
Analysis: The inspectors determined that the failure to ensure the compensatory
measures remained viable was a performance deficiency warranting a significance
evaluation. The inspectors concluded that the finding was finding was greater than
minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor
Inspection Reports, Appendix B, Issue Disposition Screening, because the licensee
failed to effectively manage prescribed compensatory measures related to a cornerstone
objective.
The increase in flooding hazard affected the protection against external factors attribute
of the Initiating Events cornerstone. Using the SDP Phase 1 Screening Worksheet of
IMC 0609, Table 4a, the inspectors determined the finding screened as Green because
the finding did not increase the likelihood of an external or internal flood.
The finding was related to the cross-cutting area of Human Performance. This finding
was associated with the cross-cutting aspect of Resources (H.2.(c)) because the barrier
impairment procedure was not adequate because it did not ensure safety margins were
maintained by providing instructions to periodically verify that the compensatory
measures were still available.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V, required, in part, that
activities affecting quality be prescribed by documented procedures of a type appropriate
to the circumstances. Contrary to the above, BwAP 1110-3 was not adequate because
it did not ensure that the sump flooding alarms remained operational while the flood
barrier covers are removed. Once identified, the licensee entered the finding into their
CAP as IR 766773, PBI Compensatory Actions Changed, Not Identified by Shift.
Because the finding was of very low safety significance, and has been entered into the
licensees CAP, this violation was treated as an NCV consistent with Section VI.A.1 of
the NRC Enforcement Policy. Corrective actions included repairing the sump alarms
and planned revision to the PBI procedure. (NCV 05000456/2008003-02;
1R07 Annual Heat Sink Performance (71111.07)
.1 Heat Sink Performance
Annual Review
a. Inspection Scope
The inspectors reviewed the licensees cleaning and eddy current (ET) testing of the
Unit 2 component cooling heat exchanger to verify that potential deficiencies did not
11 Enclosure
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. The inspectors also reviewed the licensees
calculation to justify continued operability of the heat exchanger with the additional tubes
plugged as a result of these activities. Documents reviewed were listed in the
Attachment.
This inspection constituted one sample of the annual requirement as defined in
IP 71111.07-05.
b. Findings
No findings of significance were identified.
1R08 In-service Inspection (ISI) Activities (71111.08)
For Unit 2, from April 28, 2008, through May 6, 2008, the inspectors conducted a review
of the implementation of the licensees ISI Program for monitoring degradation of the
reactor coolant system (RCS), steam generator (SG) tubes, emergency feedwater
systems, risk significant piping and components and containment systems.
The inspections described in Sections 1R08.1, 1R08.2, R08.3, 1R08.4 and 1R08.5
below counted as one inspection sample as defined by IP 71111.08-05.
.1 Piping Systems ISI
a. Inspection Scope
The inspectors observed the following nondestructive examinations (NDE) required by
the American Society of Mechanical Engineers (ASME) Code,Section XI, to evaluate
compliance with the ASME Code,Section XI and Section V requirements and if any
indications and defects were detected, to determine if these were dispositioned in
accordance with the ASME Code or an NRC approved alternative requirement.
- ultrasonic examination (UT) of reactor vessel inlet nozzle-to-safe end weld
(2RV-01-024) at the 113 degrees azimuth;
- UT of ultrasonic examination upper shell weld (2RV-01-004) and lower shell weld
(2RV-02-001); and
The inspectors reviewed a record of the following NDE required by the ASME Code,
Section XI to evaluate compliance with the ASME Code,Section XI and Section V
requirements and if any indications and defects were detected, to determine if these
were dispositioned in accordance with the ASME Code or an NRC approved alternative
requirement.
12 Enclosure
- Magnetic particle examination of SG feedwater nozzle weld (2SG-03-SGN-02).
The licensee did not identify surface or volumetric examinations completed during the
previous outage with relevant/recordable conditions/indications accepted for continued
service. Therefore, no NRC review was completed for this inspection attribute.
The inspectors observed fabrication of the following pressure boundary welds (overlay
repairs) completed for pressure boundary risk significant systems during the current
Unit 2 refueling outage. The inspectors also reviewed weld related documents to
determine if the licensee applied the preservice NDE and acceptance criteria required by
the construction Code, and an NRC approved Relief Request 12R-48. Additionally, the
inspectors reviewed the welding procedure specification and supporting weld procedure
qualification records to determine if the weld procedures were qualified in accordance
with the requirements of the ASME Code, Section IX:
- weld overlay repair of the pressurizer safety A, nozzle-to-safe end weld
(2PZR-01-SE-02); and
- weld overlay repair of the pressurizer safety C, nozzle-to-safe end weld
b. Findings
No findings of significance were identified.
.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities
a. Inspection Scope
For the Unit 2 vessel head, no examination was required pursuant to NRC
Order EA-03-009 and the licensee did not complete one during the current
refueling outage. Therefore, no NRC review was completed for this IP attribute.
b. Findings
No findings of significance were identified.
.3 Boric Acid Corrosion Control
a. Inspection Scope
The inspectors observed licensee boric acid corrosion control visual examinations for
portions of the reactor coolant and/or emergency core cooling systems (ECCS) within
containment to determine if these visual examinations emphasized locations where boric
acid leaks can cause degradation of safety significant components.
The inspectors reviewed the following licensee evaluations of RCS components with
boric acid deposits to determine if degraded components were documented in the
corrective action system. The inspectors also evaluated corrective actions for any
degraded RCS components to determine if they met the licensees boric acid program
procedures and the ASME Code, Section XI:
13 Enclosure
- reactor coolant pump 2B No. 1 seal flow element;
- reactor coolant loop 2A pump suction leg isolation valve; and
- 2B RCS loop drain isolation valve.
The inspectors reviewed the following corrective actions related to evidence of boric acid
leakage to determine if the corrective actions completed were consistent with the
requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B,
Criterion XVI.
- IR 566386, boric acid leak 2RH01CA-16 bolted connection;
- IR 566370, boric acid leak 2RH01CB-16 flanged connection; and
- IR 543851, boric acid leak 2CV04AA inlet flange.
b. Findings
No findings of significance were identified.
.4 SG Tube Inspection Activities
a. Inspection Scope
The NRC inspectors observed acquisition of ET data, interviewed ET data analysts, and
reviewed documentation related to the SG ISI program to determine if:
- in-situ SG tube pressure testing screening criteria used were consistent with
those identified in the Electric Power Research Institute (EPRI) TR 1014983,
Steam Generator In-Situ Pressure Test Guidelines, and that these criteria were
properly applied to screen degraded SG tubes for in-situ pressure testing;
- the numbers and sizes of SG tube flaws/degradation identified was bound by the
licensees previous outage Operational Assessment predictions;
the TSs, and the EPRI 1003138, Pressurized Water Reactor Steam Generator
Examination Guidelines, Revision 6;
identified in prior outage SG tube inspections and/or as identified in NRC generic
industry operating experience applicable to these SG tubes;
- the licensee identified new tube degradation mechanisms and implemented
adequate extent of condition inspection scope and repairs for the new tube
degradation mechanism;
- the licensee implemented repair methods which were consistent with the repair
processes allowed in the plant TS requirements and to determine if qualified
depth sizing methods were applied to degraded tubes accepted for continued
service;
- the licensee implemented an inappropriate plug on detection tube repair
threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);
- the licensee primary-to-secondary leakage (e.g., SG tube leakage) was below
3 gallons-per-day or the detection threshold during the previous operating cycle;
tubes were qualified to detect the known/expected types of SG tube degradation
in accordance with Appendix H, Performance Demonstration for Eddy Current
14 Enclosure
Examination, of EPRI 1003138, Pressurized Water Reactor Steam Generator
Examination Guidelines, Revision 6;
- the licensee performed secondary side SG inspections for location and removal
of foreign materials; and
- the licensee implemented repairs for SG tubes damaged by foreign material.
The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC
review was completed for this inspection attribute.
b. Findings
No findings of significance were identified.
.5 Identification and Resolution of Problems
a. Inspection Scope
The inspectors performed a review of ISI/SG related problems entered into the
licensees CAP and conducted interviews with licensee staff to determine if:
- the licensee had established an appropriate threshold for identifying ISI/SG
related problems;
- the licensee had performed a root cause (if applicable) and taken appropriate
corrective actions; and
- the licensee had evaluated operating experience and industry generic issues
related to ISI and pressure boundary integrity.
The inspectors performed these reviews to evaluate compliance with 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action
documents reviewed by the inspectors were listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
.1 Resident Inspector Quarterly Review (71111.11Q)
a. Inspection Scope
On May 27, 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;
15 Enclosure
- 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.
This inspection constituted one quarterly licensed operator requalification program
sample as defined in IP 71111.11.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
.1 Routine Quarterly Evaluations
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant system:
- service air.
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/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 were listed in the Attachment.
This inspection constituted one quarterly maintenance effectiveness samples as defined
in IP 71111.12-05.
16 Enclosure
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the
maintenance and emergent work activities affecting risk-significant and safety-related
equipment listed below to verify that the appropriate risk assessments were performed
prior to removing equipment for work:
- planned work on the Unit 2 component cooling heat exchanger with emergent
work on the 1A containment spray train;
- change from Mode 4 to Mode 3 with the 2B AFW pump unavailable;
- emergent troubleshooting on the 2E main power transformer cooling fan power
transfer circuit;
- emergent work on 2A emergency DG; and
- Bus 242 outage during refueling outage.
These activities were selected based on their potential risk significance relative to the
reactor safety cornerstones. As applicable for each activity, the inspectors verified that
risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate
and complete. When emergent work was performed, the inspectors verified that the
plant risk was promptly reassessed and managed. The inspectors reviewed the scope
of maintenance work, discussed the results of the assessment with the licensee's
probabilistic risk analyst or shift technical advisor, and verified plant conditions were
consistent with the risk assessment. The inspectors also reviewed TS requirements and
walked down portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Documents
reviewed were listed in the Attachment.
These activities constituted five samples as defined by IP 71111.13-05.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- control room heating ventilation and air conditioning issues;
17 Enclosure
- Unit 2 containment integrity with equipment hatch removed during fuel
movements;
- 1A DG after failure of 1SX169A to automatically open as expected during a
monthly surveillance test;
- revision due to extended corrective action dates for AFW tunnel cover
modifications; and
- 1A containment spray motor oil leak.
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 were listed in the
Attachment.
This inspection constituted five samples as defined in IP 71111.15-05
b. Findings
(Open) Unresolved Item (URI)05000456/2008003-03; 05000457/2008003-03: AFW
Tunnel Hatch Margin to Safety
The inspectors reviewed Operability Evaluation 07-007, Revision 2. This operability
evaluation was performed because the licensee identified that the design analysis for
evaluation of the AFW tunnel flood seal covers did not include the effects of a high
energy line break in the main steam isolation valve tunnels. Following this review, the
inspectors 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
perform to support the operability evaluation. The licensee documented the inspectors
concerns in IR 783849.
Additionally, following a review of a subsequent revision of this operability 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 operability
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
18 Enclosure
standards referenced in the design basis documents, the affected structure was either
operable or functional.
At the close of the inspection period temporary modifications had been
implemented at both units that restored the margin of safety to greater than 2.0.
Pending additional follow-up by the inspectors for the timeliness of corrective actions,
extent of condition, corrective actions and past operability, this item will remain open.
(URI 005000456/2008003-03;05000457/2008003-03) Included in the NRC review will
be the licensees' evaluations of structural degradations to determine their technical
adequacy and conformance to licensing and regulatory requirements.
1R18 Plant Modifications (71111.18)
.1 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the following temporary modification:
- temporary modification on 1B AFW pump (substitution of automatic over speed
trip function with manual operator actions to trip diesel on over speed); and
- main steam isolation valve tunnel blowout panel/AFW hatch temporary
modification.
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, as applicable,
performed field verifications to ensure that the modification was installed as directed; the
modification operated as expected; modification testing adequately demonstrated
continued system operability, availability, and reliability; and that operation of the
modification did not impact the operability of any interfacing systems. Lastly, the
inspectors discussed the temporary modification with operations, engineering, and
training personnel to ensure that the individuals were aware of how extended operation
with the temporary modification in place could impact overall plant performance.
This inspection constituted two samples as defined in IP71111.18-05.
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing (71111.19)
.1 Post Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
19 Enclosure
- 2B SX pump following motor replacement;
- 2C heater drain pump after replacement and rework on shaft packing;
- 2B feedwater pump after work on the stop valve; and
- 1B AFW pump following troubleshooting of failure of the over speed trip.
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 were
listed in the Attachment to this report.
This inspection constituted five samples as defined in IP 71111.19-05.
b. Findings
No findings of significance were identified.
1R20 Outage Activities (71111.20)
.1 Refueling Outage Activities
a. Inspection Scope
The inspectors reviewed the Shutdown Safety Management Plan for the Unit 2 refueling
outage, conducted April 20, 2008, to May 17, 2008, to confirm 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 refueling outage, 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 were listed in the Attachment to this
report.
20 Enclosure
- Licensee configuration management, including maintenance of defense-in-depth
commensurate with the safety plan 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 safety plan 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.
- Maintenance of containment integrity as required by TS.
- Refueling activities, including fuel handling and sipping to detect fuel assembly
leakage.
- Startup and ascension to full power operation, tracking of startup prerequisites,
walkdown primary containment to verify that debris had not been left which could
block ECCS suction strainers, and reactor physics testing.
- Licensee identification and resolution of problems related to refueling outage
activities.
This inspection constituted one refueling outage sample as defined in IP 71111.20-05.
b. Findings
No findings of significance were identified.
.2 Review of Operating Experience Smart Sample Fiscal Year 2007-03, Revision 1, Crane
and Heavy Lift Inspection, Supplemental Guidance for IP71111.20
a. Inspection Scope
The inspectors used the above referenced smart sample to review the reactor head lift
procedures and load drop analysis to confirm that the procedures contained limitations
which bounded the assumptions and conclusions of the load drop analysis. The
inspectors also witnessed the actual head lift during the Unit 2 outage, using remote live
video, to confirm that the procedures were followed correctly. These observations
included pre-job briefs and relaying of instructions from the supervisor and crane
signalman to the crane operator.
This inspection was part of the outage activities sample discussed in Section 1R20.1
above and did not constitute a separate sample.
b. Findings
No findings of significance were identified.
21 Enclosure
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:
- 1A monthly DG surveillance;
- 1B DG bypass of automatic trips; and
- 2B Residual Heat Removal (RHR) ASME 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 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;
- the calibration frequency was in accordance with TS, 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, 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 the safety functions; and
- all problems identified during the testing were appropriately documented and
dispositioned in the CAP.
22 Enclosure
Documents reviewed were listed in the Attachment.
This inspection constituted three routine surveillance testing sample as defined in
IP 71111.22, Sections -02 and -05.
b. Findings
No findings of significance were identified.
.2 Inservice Testing 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:
- main steam safety valves operability test; and
- low flow feedwater isolation valve stroke test.
The inspectors observed 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 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 ASME Code,Section XI, 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;
23 Enclosure
- 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 two inservice testing samples as defined in IP 71111.22-05.
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:
- Unit 1 containment emergency air lock hatch gasket interspaces.
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
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.
24 Enclosure
This inspection constituted one containment isolation valve inspection sample as defined
in IP 71111.22-05.
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1 Review of Licensee Performance Indicators (PIs) for the Occupational Exposure
Cornerstone
a. Inspection Scope
The inspectors reviewed the licensees occupational exposure control cornerstone PIs to
determine whether the conditions resulting in any PI occurrences had been evaluated
and whether identified problems had been entered into the CAP for resolution.
Documents reviewed were listed in the Attachment.
This inspection constituted one sample as defined in IP 71121.01-5.
b. Findings
No findings of significance were identified.
.2 Plant Walkdowns and Radiation Work Permit (RWP) Reviews
a. Inspection Scope
The inspectors reviewed licensee controls and surveys for the following radiologically
significant work activities that were being conducted 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:
- pressurizer weld overlay insulation shielding and support activities;
- pressurizer weld overlay project;
- reactor head component disassembly and reassembly; and
- split pin modifications.
The inspectors reviewed the RWPs and work packages used to access these areas and
other high radiation work areas to identify the work control instructions and control
barriers that had been specified. Electronic dosimeter alarm set points for both
integrated dose and dose rate were evaluated for conformity with survey indications and
plant policy. Workers were interviewed to verify that they were aware of the actions
required when their electronic dosimeters noticeably malfunctioned or alarmed.
25 Enclosure
In addition, the inspectors walked down and surveyed (using an NRC survey meter)
these areas to verify that:
- prescribed RWP, procedure, and engineering controls were in place;
- licensee surveys, and postings were complete and accurate; and
- air samplers were properly located.
The inspectors reviewed RWPs for airborne radioactivity areas to verify barrier integrity
and engineering controls performance (e.g., high-efficiency particulate air ventilation
system operation) and to determine if there was a potential for individual worker internal
exposures of greater than 50 millirem committed effective dose equivalent.
Work areas having a history of, or the potential for, airborne transuranics were evaluated
to verify that the licensee had considered the potential for transuranic isotopes and
provided appropriate worker protection.
The adequacy of the licensees internal dose assessment process for internal
exposures greater than 50 millirem committed effective dose equivalent was assessed.
There were no internal exposures greater than 50 millirem committed effective dose
equivalent.
Documents reviewed were listed in the Attachment.
This inspection constituted five samples as defined in IP 71121.01-5.
b. Findings
No findings of significance were identified.
.3 Problem Identification and Resolution
a. Inspection Scope
The inspectors reviewed a sample of the licensees self-assessments, audits, Licensee
Event Reports (LERs), and Special Reports related to the access control program to
verify that identified problems were entered into the CAP for resolution.
The inspectors reviewed corrective action reports related to access controls and high
radiation area radiological incidents (issues that did not count as performance indicator
occurrences identified by the licensee in high radiation areas less than 1R/hr). Staff
members were interviewed and corrective action documents were reviewed to verify
follow-up activities were being conducted in an effective and timely manner
commensurate with their importance to safety and risk based on the following:
- initial problem identification, characterization, and tracking;
- disposition of operability/reportability issues;
- evaluation of safety significance/risk and priority for resolution;
- identification of repetitive problems;
- identification of contributing causes;
- identification and implementation of effective corrective actions;
26 Enclosure
- resolution of NCVs tracked in the corrective action system; and
- implementation/consideration of risk significant operational experience feedback.
Documents reviewed were listed in the Attachment.
This inspection constituted two samples as defined in IP 71121.01-5.
b. Findings
No findings of significance were identified.
.4 Job-In-Progress Reviews
a. Inspection Scope
The inspectors observed the following three 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:
- pressurizer weld overlay project;
- reactor head component disassembly and reassembly.
The inspectors reviewed radiological job requirements for these activities, including
RWP requirements and work procedure requirements, and attended as-low-as-is-
reasonably-achievable (ALARA) job briefings.
Job performance was observed with respect to these requirements to assess whether
radiological conditions in the work area were adequately communicated to workers
through pre-job briefings and postings. The inspectors also 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.
Radiological work in high radiation work areas having significant dose rate gradients was
reviewed to evaluate the application of dosimetry to effectively monitor exposure to
personnel and to assess the adequacy of licensee controls. These work areas involved
areas where the dose rate gradients were severe thereby increasing the necessity of
providing multiple dosimeters or enhanced job controls.
Documents reviewed were listed in the Attachment.
This inspection constituted three samples as defined in IP 71121.015.
b. Findings
No findings of significance were identified.
27 Enclosure
.5 High Risk Significant, High Dose Rate, High Radiation Area and Very High Radiation
Area Controls
a. Inspection Scope
The inspectors conducted plant walkdowns to assess the posting and locking of
entrances to high dose rate, high radiation area and very high radiation area.
Specifically, the inspectors reviewed the transient locked high radiation area and
potentially very high radiation area controls during the core barrel lift.
Documents reviewed were listed in the Attachment.
This inspection constituted one sample as defined in IP 71121.01-5.
b. Findings
No findings of significance were identified.
.6 Radiation Worker Performance
a. Inspection Scope
During job performance observations, the inspectors evaluated radiation worker
performance with respect to stated radiation protection work requirements and evaluated
whether workers were aware of the significant radiological conditions in their workplace,
of the RWP controls and limits in place, and of the level of radiological hazards present.
The inspectors also evaluated if worker performance accounted for these radiological
hazards.
Documents reviewed were listed in the Attachment.
This inspection constituted one sample as defined in IP71121.01-5.
b. Findings
No findings of significance were identified.
.7 Radiation Protection Technician Proficiency
a. Inspection Scope
During job performance observations, the inspectors evaluated radiation protection
technician performance with respect to radiation protection work requirements and
evaluated whether they were aware of the radiological conditions in their workplace, the
RWP controls, and limits in place, and if their performance was consistent with their
training and qualifications with respect to the radiological hazards and work activities.
Documents reviewed were listed in the Attachment.
This inspection constituted one sample as defined in IP71121.01-5.
28 Enclosure
b. Findings
No findings of significance were identified.
2OS2 ALARA Planning And Controls (71121.02)
.1 Inspection Planning
a. Inspection Scope
The inspectors reviewed plant collective exposure history, current exposure trends,
ongoing and planned activities in order to assess current performance and exposure
challenges. This included determining the plants current three-year rolling average for
collective exposure in order to help establish resource allocations and to provide a
perspective of significance for any resulting inspection finding assessment.
The inspectors reviewed the outage work scheduled during the inspection period and
associated work activity exposure estimates for the following five work activities, which
were likely to result in the highest personnel collective exposures:
- pressurizer weld overlay insulation shielding and support activities;
- pressurizer weld overlay project;
- reactor head component disassembly and reassembly; and
- split pin modifications.
The inspectors reviewed documents to determine if there were site-specific trends in
collective exposures and source-term measurements.
The inspectors reviewed procedures associated with maintaining occupational
exposures ALARA and processes used to estimate and track work activity specific
exposures.
Documents reviewed were listed in the Attachment.
This inspection constituted four required samples as defined in IP 71121.02-5.
b. Findings
No findings of significance were identified.
.2 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 five work activities of highest
exposure significance:
- pressurizer weld overlay insulation shielding and support activities;
- pressurizer weld overlay project;
29 Enclosure
- reactor head component disassembly and reassembly; and
- split pin modifications.
For these five 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. This also involved determining if the licensee had reasonably grouped the
radiological work into work activities, based on historical precedence, industry norms,
and/or special circumstances.
The inspectors compared the results achieved including dose rate reductions and
person-rem used with the intended dose established in the licensees ALARA planning
for these five work activities. Reasons for inconsistencies between intended and actual
work activity doses were reviewed.
Documents reviewed were listed in the Attachment.
This inspection constituted three required samples as defined in IP 71121.025.
b. Findings
No findings of significance were identified.
.3 Verification of Dose Estimates and Exposure Tracking Systems
a. Inspection Scope
The inspectors reviewed the assumptions and bases for the current annual collective
exposure estimate including procedures, in order to evaluate the licensees methodology
for estimating work activity-specific exposures and the intended dose outcome. Dose
rate and man-hour estimates were evaluated for reasonable accuracy.
The licensees process for adjusting exposure estimates or re-planning work, when
unexpected changes in scope, emergent work or higher than anticipated radiation levels
were encountered, was evaluated. This included determining that adjustments to
estimated exposure (intended dose) were based on sound radiation protection and
ALARA principles and not adjusted to account for failures to control the work. The
frequency of these adjustments was reviewed to evaluate the adequacy of the original
ALARA planning process.
Documents reviewed were listed in the Attachment.
This inspection constituted two required samples as defined in IP 71121.02-5.
a. Findings
No findings of significance were identified.
30 Enclosure
.4 Job Site Inspections and ALARA Control Inspection Scope
The inspectors observed the following five 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:
- pressurizer weld overlay insulation shielding and support activities;
- pressurizer weld overlay project;
- reactor head component disassembly and reassembly; and
- split pin modifications.
The licensees use of ALARA controls for these work activities was evaluated using the
following:
The licensees use of engineering controls to achieve dose reductions was evaluated to
verify that procedures and controls were consistent with the licensees ALARA reviews,
that sufficient shielding of radiation sources was provided for and that the dose
expended to install/remove the shielding did not exceed the dose reduction benefits
afforded by the shielding.
Documents reviewed were listed in the Attachment.
This inspection constituted one required sample as defined in IP 71121.02-5.
b. Findings
No findings of significance were identified.
.5 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 in practice by being
familiar with the work activity scope 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 constituted one required sample as defined in IP 71121.02-5.
b. Findings
No findings of significance were identified.
31 Enclosure
Cornerstone: Public Radiation Safety
2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01)
.1 Review of Blowdown Line Operations and Tritium Remediation Efforts
a. Inspection Scope
The inspectors continued to monitor the licensees activities resulting from historical
inadvertent leaks of tritiated liquid from the blowdown line. The inspectors continued to
accompany licensee employees and contractors during their collection of water samples
at 23 monitoring locations of interest. The inspectors verified by direct observation that
the water samples were being taken from the locations specified, that proper sampling
protocols were followed, and that split samples were properly obtained and labeled. The
inspectors took direct custody of the split samples and maintained a chain of custody as
the samples were sent to the NRCs contract laboratory. The inspectors also reviewed
the results of December 12, 2007, split samples to ensure that the results from the
licensees and NRCs contract laboratories matched within normal statistical variance.
Documents reviewed were listed in the Attachment.
This inspection does not constitute a sample as defined in IP 71122.02-5.
b. Findings
No findings of significance were identified.
2PS2 Radioactive Material Processing and Transportation (71122.02)
.1 Radioactive Waste System Walkdowns
a. Inspection Scope
The inspectors reviewed changes to the waste processing system to verify the changes
were reviewed and documented in accordance with 10 CFR 50.59 and to assess the
impact of the changes on radiation dose to members of the public.
Documents reviewed were listed in the Attachment.
This inspection does not constitute a sample as defined in IP 71122.02-5.
b. Findings
One finding of very low safety significance was identified.
Failure to Sample a Temporary Tank at the Required Periodicity
Introduction: The inspectors identified a finding of very low safety significance (Green)
and an NCV of TS 5.4, and Technical Requirements Manual (TRM), Appendix L, for
failure to sample temporary waste water tanks at the Unit 2 Containment Access facility.
32 Enclosure
Description: On May 1, 2008, the inspectors identified that the licensee had failed to
sample the temporary wastewater storage tanks that were installed for the Unit 2
refueling outage to hold shower and wash water from the Unit 2 Containment Access
Facility at the required frequency of seven days. This failure resulted in two missed
samples of the Unit 2 Containment Access Facility shower tanks. The licensees
corrective measures consisted of immediately collecting and monitoring the required
sample. The results of this sample indicated that the quantity of radioactive material was
well below the limits provided in the TRM. Additionally, the licensee started the process
to review and revise Procedure RP-BR-654, Revision 0. This revision was necessary to
reflect the temporary tank sampling requirement of TRM, Appendix L, implemented to
limit the quantity of radioactive material contained in outside temporary tanks and verify
the compliance with the limits by sampling the contents at least once per seven days
when in use. The inspectors observed that Procedure RP-BR-654, as written, did not
direct the required sampling frequency as outlined in TRM, Appendix L.
After identification by the inspectors, the licensee documented the issue in IR 770446,
conducted the required sampling, revised the scheduling tool to ensure the tank is
sampled at least every seven days, and planned to revise Procedure RP-BR-654.
Analysis: The inspectors determined that the failure to sample the contents in the
outdoor liquid radwaste storage tanks did not meet the requirements of TRM,
Appendix L and was a performance deficiency that warranted a significance evaluation.
The finding involves an occurrence in the licensee's radioactive material control program
that is contrary to the licensees procedures. The finding was more than minor because
it impacted the program and process attribute of the Public Radiation Safety
Cornerstone and affected the cornerstone objective to ensure adequate protection of
public health and safety from exposure to radioactive material released into the public
domain, in that the failure to measure the levels of radioactivity in the temporary storage
tanks had the potential to impact the licensees effluent program.
The inspectors applied the IMC 0609, Appendix D, to this finding. The finding is in the
licensees radiological effluent monitoring program. The finding did not involve a failure
to implement the effluent release program nor did public dose exceed Appendix I,
Criterion, or 10 CFR 20.1302(e) and the finding was determined to be of very low safety
significance (Green). This conclusion was based on no tank contents being released or
discharged without sampling, and the total content limits were not exceeded.
The primary cause of this sampling failure was related to the cross-cutting component of
Human Performance, Work Practices (Item H.4.C of IMC 0305) because the licensee did
not ensure that supervisory and management oversight of procedure development was
adequate to assure nuclear safety, specifically, procedures that are complete, accurate.
Enforcement: Technical Specification 5.4.1(a) requires written procedures be
established, implemented and maintained covering the applicable procedures
recommended in RG 1.33, Revision 2, Appendix A, February 1978. TRM, Appendix L,
required the quantity of radioactive material contained in any outside temporary tank be
determined to be within the acceptance criteria by analyzing a representative sample of
the tanks contents at least once per seven days when radioactive materials are being
added to the tank. Procedure RP-BR-654 was written to implement the requirements of
the TRM.
33 Enclosure
Contrary to the above, as of May 1, 2008, the licensees Procedure RP-BR-654 did
not include the requirement for sampling at least once per seven days. Consequently,
the licensee failed to sample decontamination drain waste tanks, temporary tanks,
adjacent to the Unit 2 Containment Access Facility at least once per seven days.
Because of the very low safety significance of this finding and because the issue was
entered into the licensees CAP (IR 770446), it was treated as an NCV, consistent with
Section VI.A.1 of the Enforcement Policy (NCV 05000456/2008003-04;
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
4OA1 Performance Indicator Verification (71151)
.1 RCS Specific Activity
a. Inspection Scope
The inspectors sampled licensee submittals for the RCS Specific Activity PI for
Braidwood, Units 1 and 2. To determine the accuracy of the PI data reported during
those periods, the PI definition and guidance contained in the Nuclear Energy Institute
(NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 5, was used. The inspectors reviewed the licensees RCS chemistry samples,
TS requirements, IRs, LERs, and NRC Integrated Inspection reports for the period of
April 1, 2007, to March 31, 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 RCS sample. Specific documents reviewed
were described in the Attachment.
This inspection constituted two RCS specific activity samples as defined by IP 71151-05.
b. Findings
No findings of significance were identified.
.2 RCS Leakage
a. Inspection Scope
The inspectors sampled licensee submittals for the RCS Leakage PI for Braidwood,
Units 1 and 2. To determine the accuracy of the PI data reported during those periods,
the PI definition and guidance contained in the NEI Document 99-02, Revision 5, was
used. The inspectors reviewed the licensees operator logs, RCS leakage tracking data,
IRs, LERs, and NRC Integrated Inspection Reports for the period of April 1, 2007, to
March 31, 2008, to validate the accuracy of the submittals. The inspectors also
reviewed the licensees issue report database to determine if any problems had been
34 Enclosure
identified with the PI data collected or transmitted for this indicator and none were
identified. Specific documents reviewed were described in the Attachment.
This inspection constituted two RCS leakage samples as defined by IP 71151-05.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1 Routine Review of items Entered Into the CAP
a. Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensees CAP at
an appropriate threshold, that adequate attention was being given to timely corrective
actions, and that adverse trends were identified and addressed. Attributes reviewed
included:
- the complete and accurate identification of the problem;
- that timeliness was commensurate with the safety significance;
- that evaluation and disposition of performance issues, generic implications,
common causes, contributing factors, root causes, extent of condition reviews,
and previous occurrences reviews were proper and adequate; and
- that the classification, prioritization, focus, and timeliness of corrective actions
were commensurate with safety and sufficient to prevent recurrence of the issue.
Minor issues entered into the licensees CAP as a result of the inspectors observations
are included in the attached list of documents reviewed.
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples. Instead, by procedure they were considered an
integral part of the inspections performed during the quarter and documented in the
Attachment.
b. Findings
No findings of significance were identified.
.2 Daily CAP Reviews
a. Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees CAP. This review was accomplished through
inspection of the stations daily condition report packages.
35 Enclosure
These daily reviews were performed by procedure as part of the inspectors daily plant
status monitoring activities and, as such, did not constitute any separate inspection
samples.
b. Findings
No findings of significance were identified.
.3 Semi-Annual Trend Review
a. Scope
The inspectors performed a review of the licensees CAP and associated documents to
identify trends that could indicate the existence of a more significant safety issue. The
inspectors review was focused on repetitive equipment issues, but also considered the
results of daily inspector CAP item screening discussed in Section 4OA2.2 above,
licensee trending efforts, and licensee human performance results. The inspectors
review nominally considered the six month period of September 1, 2007 through
March 31, 2008, although some examples expanded beyond those dates where the
scope of the trend warranted.
The review also included issues documented outside the normal CAP in major
equipment problem lists, repetitive and/or rework maintenance lists, departmental
problem/challenges lists, system health reports, quality assurance audit/surveillance
reports, self assessment reports, and Maintenance Rule assessments. The inspectors
compared and contrasted their results with the results contained in the licensees CAP
trending reports. Corrective actions associated with a sample of the issues identified in
the licensees trending reports were reviewed for adequacy.
Documents reviewed were listed in the Attachment.
This review constituted a single semi-annual trend inspection sample as defined in
Inspection Procedure 71152-05.
b. Findings
No findings of significance were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
.1 Seismic Event
a. Inspection Scope
The inspectors reviewed the plants response to a seismic event felt at the plant due to
an earthquake in southern Illinois on April 18, 2008. Although the ground motion was
felt in the plant, the motion was apparently not strong enough to activate the seismic
monitoring system and annunciators. The inspectors collected the information
necessary to communicate the event details to regional supervision, observed plant
parameters and licensee activities, confirmed that the licensee had properly classified
the event, and conducted independent walkdowns of risk significant plant areas to verify
36 Enclosure
that no damage had occurred. The walkdowns included an inspection of all blowdown
line vacuum breaker vaults, the areas over the buried blowdown piping, and the tritium
mitigation pumping systems. Documents reviewed in this inspection were listed in the
Attachment.
This inspection constituted one sample as defined in IP 71153-05.
b. Findings
No findings of significance were identified.
4OA5 Other Activities
.1 (Closed) NRC Temporary Instruction (TI) 2515/166, Pressurized Water Reactor
Containment Sump Blockage (NRC Generic Letter [GL] 2004-02) - Units 1 and 2
a. Inspection Scope
The inspectors reviewed the station implementation of the licensees commitments
documented in their December 31, 2007, response to GL 2004-02, Potential Impact of
Debris Blockage on Emergency Recirculation during Design Basis Accidents at
Pressurized Water Reactors. The inspectors reviewed the Engineering Change
Packages associated with the sump strainer modifications and the 10 CFR 50.59
evaluations for these Engineering Change Packages (ECs). The inspectors also
reviewed documentation from the licensee and vendor pertaining to the strainer
assembly specifications. In addition, the inspectors reviewed three samples of the
completed and approved for use changes for the UFSAR, Revision 12, that have not
been incorporated yet and one sample already incorporated in Revision 11. The
documents reviewed were listed at the end of the report. The inspection was
conducted in accordance with TI 2515/166.
Inspection Documentation
The inspectors determined the following answers to the Reporting Requirements
detailed in the TI 2515/166:
(1) Did the licensee implement the plant modifications and procedure changes
committed to in their GL 2004-02 responses?
The licensee has implemented the plant modifications and procedure changes
committed to in their GL 2004-02 response with the exception of the installation
and testing of ECCS (ECCS) throttle valves for Unit 2 for which an extension for
completion until Spring 2008 was requested and approved. In addition, the
licensee cancelled the cyclone separator modification for Unit 2 because test
results showed that they are not susceptible to blockage as documented in
EC 364979, Evaluation of Wyle Test Report. The commitments included:
- Installation of permanent modification of the sump strainer assemblies
including modification of the ECCS throttle valves and replacement of the
fibrous insulation with reflective metal insulation within the zone of
influence at Unit 1.
37 Enclosure
This commitment was previously reviewed and documented in NRC
Inspection Reports 05000456/2007006 and 05000457/2006005. The
licensee has received approval for an extension regarding the
downstream effects portion of their modification for Unit 2. Structural
analyses of the new strainer assemblies were performed through
BRW-06-0015-M, Design Loads and Sizing Limitations for the ECCS
Containment Sump Trash Racks; BRW-06-0030-S, Evaluation of
Auxiliary Steel for Sump Strainer Upper Sizing Restraints; and 3SA-
096.016, CCI Structural Analysis of Strainer and Support Structure.
- Perform latent debris walkdowns, and debris generation and transport
analyses.
The results of containment walkdowns were documented in analysis
S040-BRW-6042, [Generic Safety Issue] GSI-191 Latent Debris
Collection. The debris generation was estimated and analyzed by
BRW-05-0059-M, GSI-191 Post LOCA (loss of coolant accident)
Debris Generation. Debris transportation was analyzed through
BRW-05-0060-M, Post LOCA Debris Transport Evaluation for
Resolution of GSI 191.
- Perform evaluation of strainer performance including chemical effects.
Strainer performance was evaluated in calculation 3SA-096.018, Head
Loss Calculation, which received inputs from strainer head loss testing
documented in CCI Test Report 680/41222, Chemical Filter Performance
Report. In addition, the following tests were performed: (1) DIT-BRW-
2006-0007, Results of Test Debris Concentrations; (2) Q.003.87 748,
Large Size Filter Performance Test Specification; and (3) CCI Test
Report 680/41134, Large Size Filter Performance Test Report.
- Perform evaluation of downstream and upstream effects.
Downstream effects were evaluated by calculation BRW-05-0084-M,
Byron Units 1 and 2, and Braidwood Units 1 and 2, GSI-191 Downstream
Effects - Vessel Blockage and Fuel Evaluation. Downstream wear and
blockage was evaluated by calculation BRW-05-0063-M, GSI-191
Evaluation of Long Term Downstream Effects. Testing of wear and
blockage to the ECCS throttle valves and CSS cyclone separator was
documented in WLTR53637, Wyle Test Report on Debris Latent Test
Results of 1 1/2" Copes Volcan Control Valve (SI 8810), A 2" Copes
Volcan Control Valve (SI 8816), A 2" Copes Volcan Control Valve
(SI 8822) and Cyclone Separator. Upstream effects were evaluated by
S040-BRW-6054, GSI-191 Debris Generation Walkdown.
- Determine minimum available net positive suction head margin for the
RHR pumps at switchover to sump recirculation.
Minimum available net positive suction head margin was determined by
BRW-06-0035-M, NPSHA for RHR and containment spray pumps during
Post LOCA Recirculation. The hydraulic model of the ECCS was
38 Enclosure
performed by BRW 06-0016-M, SI/RHR/CS/CV System Hydraulic
Analysis in Support of GSI 191.
- Establish programmatic controls to ensure that potential sources of debris
introduced into containment are assessed for adverse affects.
The licensee performed an enhancement to CC-AA-102, Design Input
and Configuration Change Impact Screening, to introduce a requirement
to review the impact of a proposed change on the documentation that
forms the design basis for their response to GL 2004-02. In addition, the
licensee upgraded OP-AA-116-101, Equipment Labeling, and
committed to use 1BwOS TRM 2.5.b.1, Unit 1 Containment Loose Debris
Inspection; 2BwOS TRM 2.5.b.1, Unit 2 Containment Loose Debris
Inspection; and CC-AA-205, Control of Undocumented/Unqualified
Coatings Inside Containment as administrative controls for limiting debris
sources inside containment. Also, IR 282077 is tracking the creation of a
procedure for latent debris measurements inside containment every four
refueling outages. This activity was tracked by Service Request
No. 53465.
(2) Has the licensee updated its licensing bases to reflect the corrective
actions taken in response to GL 2004-02?
The licensee has updated its licensing bases to reflect the corrective
actions taken in response to GL 2004-02 with the exception of the
portions relative to the ECCS throttle valves modification at Unit 2
scheduled in Spring 2008.
(3) If the licensee or plant has obtained an extension past the completion
date of this TI, document what actions have been completed and what
actions are outstanding.
The licensee requested and received approval for an extension until
Spring 2008 to complete the installation and testing of ECCS throttle
valves for Unit 2.
Completed actions are:
- installation of new strainer assemblies for both units;
- installation of modified ECCS throttle valves at Unit 1;
- replacement of fibrous insulation with reflective metal insulation
within the zone of influence at Unit 1;
- programmatic controls had been put in place;
- associated analyses and testing; and
- licensing bases update of the pertinent completed actions.
Outstanding actions are:
- installation of modified ECCS throttle valves at Unit 2;
- update of licensing bases associated with installation of new
strainer assemblies for both units; and
39 Enclosure
- IR 282077 is tracking the creation of a procedure for latent debris
measurements inside containment every four refueling outages.
This activity is being currently tracked by Service Request
No. 53465.
This TI is closed for both units. This documentation of TI-2515/166
completion as well as any results of sampling audits of licensee actions
will be reviewed by the NRC staff (Office of Nuclear Reactor Regulation -
NRR) as input along with licensees GL 2004-02 responses to support
closure of GL 2004-02 and GSI-191 Assessment of Debris Accumulation
on Pressurized-Water Reactor (PWR) Sump Performance." The NRC will
notify each licensee by letter of the results of the overall assessment as to
whether GSI-191 and GL 2004-02 have been satisfactorily addressed at
that licensees plants.
b. Findings
No findings of significance were identified.
.2 RCS Dissimilar Metal Butt Welds (DMBW) (TI 2515/172, Revision 0)
a. Inspection Scope
The inspectors conducted a review of the licensees DMBW mitigation and inspection
program to determine if it was implemented in accordance with the industry self-imposed
mandatory requirements of Materials Reliability Program (MRP) -139, Primary System
Piping Butt Weld Inspection and Evaluation Guidelines. This review was conducted in
accordance with TI 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds for
both Units 1 and 2.
The documents reviewed by the inspector for this inspection were listed in the
Attachment.
From April 28, 2008, through May 6, 2008, the inspectors performed a review in
accordance with TI-172 which included the following:
(1) Licensees Implementation of the MRP-139 Baseline Inspections
The inspectors performed a review of the licensees DMBW program to
determine:
- if the licensees inspection program for DMBWs included
applicable welds exposed to pressurizer, hot let and cold leg
temperatures;
- if the schedules for these baseline inspections were consistent
with the requirements stated in MRP-139;
- if the baseline inspection schedules deviated from MRP-139
guidelines;
- the basis for any planned deviations from MRP-139 baseline
inspection schedules; and
40 Enclosure
- the inspectors verified that the licenses had completed weld
overlays on all Unit 2 pressurizer DMBWs during the Spring 2008
refueling outage.
(2) Volumetric Examinations
The inspectors observed and/or reviewed records for the following volumetric
examinations for:
- Unit 1, the inspectors performed a review of UT records from the
Fall 2007 for the unmitigated reactor vessel outlet nozzle-to-safe
end Inconel weld (1RV 01-22) at the 22 degree azimuth location;
and
- Unit 2, the inspectors observed the licensees vendor acquiring
and analyzing UT data for the unmitigated reactor vessel inlet
nozzle-to-safe end Inconel weld (2RV-01-24) at the 113 degree
azimuth location.
The inspectors reviewed records of the following weld overlay volumetric
examinations for:
- Unit 1, the inspectors performed a review of UT records from the
Fall 2007 outage for the weld overlay repair of the pressurizer
surge nozzle DMBW (1PN 01-SW-1) and the adjacent stainless
steel safe-end to pipe/fitting welds; and
- Unit 2, the inspectors performed a records review from the current
outage of the UT data for the weld overlay repair of two
pressurizer safety nozzle DMBWs (2PN-04-SW-4 and
2PN-06-SW-6) and the adjacent stainless steel safe-end to
pipe/fitting welds.
The inspectors performed the reviews of volumetric examinations identified
above to determine if:
- the examinations were performed in accordance with the
guidelines in MRP-139 Section 5.1;
- the examinations were performed consistent with the NRC staff
relief request authorization for the weld overlay;
- the examination coverage warranted further evaluation and if so,
the inspector reviewed the licensees basis for achieving the
inspection coverage credited;
- the volumetric examinations were performed by qualified
personnel; and
- deficiencies were appropriately dispositioned.
(3) Weld Overlays
For Unit 1, the inspectors performed a review of licensee records for the
pressurizer surge nozzle (1-PN-01-SW-1) weld overlay completed in the
Fall 2007.
41 Enclosure
For Unit 2, the inspectors observed the weld overlay repairs completed for the
pressurizer safety nozzle A (2PZR-01-SE-02) and safety nozzle B
The inspectors performed the review of weld overlays identified above to
determine if:
- the overlays were performed in accordance with ASME Code
requirements as modified by NRC staff relief request
authorizations;
- the licensee submitted appropriate relief requests and obtained
NRR staff authorization to install the weld overlays;
- the overlay welding was performed by qualified personnel; and
- deficiencies were appropriately dispositioned, and resolved.
(4) Mechanical Stress Improvement (SI)
There were no stress improvement activities performed or planned by the
licensee. Therefore, the inspectors did not perform a review for this inspection
attribute.
(5) ISI Program
The inspectors performed a review of the licensees DMBW inspection program
to determine if:
- it included the applicable welds required by MRP-139;
- the welds were identified with inspection categories consistent
with the MRP-139 guidelines;
- the licensees DMBW program and procedures required
inspection frequencies consistent with Tables 6-1 and 6-2 of
- any DMBWs were categorized as H or I and for these welds,
the licensees basis for this categorization and the licensees plans
to address the potential for primary water stress corrosion
cracking; and
- deviations were planned from the inspection guidelines of
b. Observations
Summary: Braidwood Units 1 and 2 are Westinghouse four loop design plants. For
each unit, the licensee had identified a population of DMBWs susceptible to primary
water stress corrosion cracking in accordance with MRP-139 guidelines. The licensee
had completed mitigation by weld overlay repairs to the pressurizer DMBWs on both
units. The licensee had not decided on mitigation methods for the remaining DMBW
susceptible to primary water stress corrosion cracking (e.g., MRP-139 categories D
and E).
42 Enclosure
For Unit 1, during the Fall 2007 outage, the licensee completed baseline examinations of
the pressurizer DMBWs after completing weld overlay repairs and had not deviated from
the MRP-139 inspection guidelines.
For Unit 2, the licensee had previously taken a deviation from MRP-139 for the
DMBW on the pressurizer surge line, since it was not inspected or mitigated by
December 31, 2007. The licensee completed weld overlay repairs on the pressurizer
DMBWs during the current outage including the DMBW at the pressurizer surge line.
The inspectors confirmed that the licensee performed appropriate weld overlay repairs
and UT to the pressurizer surge line weld such that a deviation from the MRP-139
guidelines no longer existed.
In accordance with requirements of TI 2515/172, Revision 0, the inspectors evaluated
and answered the following questions:
(1) Licensees Implementation of the MRP-139 Baseline Inspections
1. Have the baseline inspection been performed or are they scheduled to be
performed in accordance with MRP-139 guidance?
Yes. Baseline inspections of all hot and cold leg DMBWs were
completed.
Were the baseline inspections of the pressurizer temperature DMBWs of
the nine plants listed in 03.01.b completed during the spring outages?
Yes. Baseline inspections of the Braidwood Unit 2 pressurizer DMBWs
were completed after applying weld overlay repairs during the
Spring 2008 outage.
2. Is the licensee planning to take any deviations from the MRP-139
baseline inspection requirements? If so, what deviations are planned,
what is the general basis for the deviation, and was the NEI- 03-08
process for filing a deviation followed?
No. The licensee was not planning to take any further deviations from
the MRP-139 baseline inspection requirements. For Unit 2, the
licensee had previously taken a deviation from MRP-139 for the
pressurizer DMBWs, since they were not inspected or mitigated
by December 31, 2007. The basis for this deviation was the low
susceptibility of the material and the timing of the Spring 2008
refueling outage. The NEI-03-08 process for filing the deviation
was followed. The licensee completed weld overlay repairs on the
pressurizer DMBWs during the current outage. The inspectors
confirmed that the licensee performed appropriate weld overlay
repairs and UT to the pressurizer DMBWs such that a deviation
from the MRP-139 guidelines no longer existed.
43 Enclosure
(2) Volumetric Examinations
1. Performed in accordance with the examination guidelines in MRP-139,
Section 5.1, for unmitigated welds or mechanical stress improvement
welds and consistent with NRC staff relief request authorization for weld
overlaid welds?
Yes. For Unit 1, the inspectors performed a records review of the UT
data for the unmitigated reactor vessel outlet nozzle-to-safe end
Inconel weld at the 22 degree azimuth location. The licensees
vendor use a Performance Demonstrated Initiative (PDI) qualified
automated UT technique and achieved the ASME Code, Section
XI required weld volume.
Yes. For Unit 2, the inspectors observed the licensees vendor
acquiring and analyzing UT data for the unmitigated reactor vessel
inlet nozzle-to-safe end Inconel weld at the 113 degree azimuth
location. The licensees vendor used a PDI qualified automated
UT technique and achieved the ASME Code Section XI required
weld volume.
2. Performed by qualified personnel? (Briefly describe the personnel
training/qualification process used by the licensee for this activity.)
Yes. For both Units, the licensees vendor staff that analyzed the UT
data for the unmitigated reactor coolant loop nozzle-to-safe end
welds, were certified to UT Level II requirements in accordance
with a vendor procedure (WDP-9.2 WesDyne International
Qualification and Certification of Personnel in Nondestructive
Examination) to meet the training and certification requirements of
the ASME Code Section XI, Appendix VII and VIII. For Unit 2, the
inspectors also confirmed that the two dayshift vendor UT analysts
had certification records issued by the PDI program established by
EPRI, which documented successful performance testing required
to meet the applicable ASME Code,Section XI, Appendix VIII
supplement for examination of these welds.
3. Performed such that deficiencies were identified, dispositioned, and
resolved?
Not applicable. No deficiencies or recordable indications were identified
in the unmitigated nozzle-to-safe end Inconel welds.
(3) Weld Overlays
1. Performed in accordance with ASME Code welding requirements and
consistent with NRC staff relief request authorizations? Has the licensee
submitted a relief request and obtained NRR staff authorization to install
the weld overlays?
44 Enclosure
Yes. For each Unit, the weld overlays were performed in accordance
with ASME Code welding requirements and consistent with the
approved NRC relief request.
Yes. For each Unit, the licensee submitted a relief request and
obtained NRR staff authorization to install the weld overlays.
2. Performed by qualified personnel? (Briefly describe the personnel
training/qualification process used by the licensee for this activity.)
Yes. For the weld overlays reviewed by the inspectors in each Unit, the
welders fabricating the overlay had performed an ASME Code,
Section IX - Welder Performance Qualification in accordance with
the vendors program for the weld overlay activities performed.
The welder qualification records were transmitted to Exelon for
review and concurrence in support of the A2R13 weld overlay
work. The inspectors reviewed the welder qualification records
including the welders ASME Code - Welder Maintenance Log.
3. Performed such that deficiencies were identified, dispositioned, and
resolved?
Yes. For Unit 1, rejectable surface indications were identified during the
final weld overlay dye penetrant examination (PT). The licensee
removed a small amount of weld material to remove these
indications (e.g., buffed out) and reperformed a final PT to accept
the weld overlay repairs. The inspectors reviewed the final PT
records for the weld overlays affected and considered these
deficiencies appropriately dispositioned and resolved.
Yes. For Unit 2, the licensees vendor encountered problems resulting
in loss of shielding gas during weld overlay fabrication. The
licensees vendor ground out affected weld metal and rewelded
portions of the overlay repair. Similar to the Unit 1 overlay, the
licensee identified rejectable indications during the final weld
overlay PT examinations for Unit 2. The licensee removed a small
amount of weld material to remove these indications (e.g., buffed
out) and reperformed a final PT to accept the weld overlay repairs.
The inspectors reviewed the final PT records for the weld overlays
affected and considered these deficiencies appropriately
dispositioned and resolved.
For Unit 2, during fabrication of the B safety nozzle, the licensee
vendor identified that the overlap for the sacrificial layer weld was
not in accordance with the weld procedure. The licensee removed
(e.g., ground off) the incorrect weld overlap, completed a PT of the
ground area, and then completed a proper weld overlap. The
inspectors concluded that the licensee had taken appropriate
corrective actions to resolve this deficiency.
45 Enclosure
(4) Mechanical Stress Improvement
No stress improvement activities have been performed for DMBWs nor did the
licensee plan to perform mechanical stress improvement as a mitigation strategy
for DMBWs.
(5) ISI Program
1. Has the licensee prepared an MRP-139 ISI program? If not, briefly
summarize the licensees basis for not having a documented program
and when the licensee plans to complete preparation of the program.
No. The licensee had not prepared a separate MRP-139 ISI program.
However, the licensee had scheduled baseline and ISIs of
DMBWs at frequencies consistent with the MRP-139 guidelines
and the ASME Code,Section XI requirements.
2. In the MRP-139 ISI program, are the welds appropriately categorized in
accordance with MRP-139? If any welds are not appropriately
categorized, briefly explain the discrepancies.
Yes. For each Unit, the DMBWs were categorized in accordance with
3. In the MRP-139 ISI program, are the ISI frequencies, which may differ
between the first and second intervals after the MRP-139 baseline
inspection, consistent with the ISI frequencies called for by MRP-139?
Yes. The ISI frequencies, for DMBWs in each Unit, were consistent
with the ISI frequencies required by MRP-139.
4. If any welds are categorized as H or I, briefly explain the licensees basis
of the categorization and the licensees plans for addressing potential
For Unit 2, the pressurizer welds were categorized as H prior to the
application of a structural weld overlay. The Category H was assigned
due the difficulty of performing a PDI UT examination of these welds.
After completing the weld overlay repairs, the licensee indicated that
these DMBWs would be re-categorized as Category F in accordance with
MRP-139 guidance.
For Unit 1, the licensee did not have DMBWs in the H or I Categories.
5. If the licensee is planning to take deviations from the ISI requirements of
MRP-139, what are the deviations and what are the general bases for the
deviations? Was the NEI 03-08 process for filing deviations followed?
Not applicable. The licensee was not planning to take deviations from the
MRP-139 guidelines.
46 Enclosure
c. Findings
No findings of significance were identified.
.3 (Closed) URI 05000456/2008001-01; 05000457/2008001-01, Failure to Control
Regulatory Guide 1.97 Instrumentation Marking
a. Inspection Scope
During an initial operator licensing examination documented in Examination Report
05000456/2007301(DRS); 05000457/2007301(DRS), NRC inspectors identified a
URI concerning the lack of procedural controls for labeling Regulatory Guide
(RG) 1.97 post-accident indications on the main control room control panels. The
inspectors opened URI 05000456/2008001-01; 05000457/2008001-01, Failure to
Control RG 1.97 Instrumentation Marking, to track this possible violation of NRC
requirements. The licensee then found and provided copies of letters to the NRC and
other information documenting commitments, current status, and corrective actions to be
taken for post-accident instrument labeling deficiencies.
The inspectors reviewed the corrective action document (IR 688723), the licensees
plans to revise Procedures 1BwOSR 3.3.3.1, Unit One Accident Monitoring
Instrumentation Channel Checks and 2BwOSR 3.3.3.1, Unit Two Accident Monitoring
Instrumentation Channel Checks, and Training Requests submitted to ensure familiarity
with equipment included in Braidwood TS, Table 3.3.3-1, Post Accident Monitoring
Instrumentation.
b. Findings
Introduction: The inspectors identified a finding of very low safety significance (Green)
and associated NCV of TS 5.4.1, for failure to maintain adequate procedural controls for
labeling RG 1.97 post-accident indicators on the control panels.
Description: UFSAR Appendix A1 described an NRC submittal for Braidwood Stations
RG 1.97 instruments dated September 1, 1987. This letter committed the licensee to
identifying post-accident instruments per RG 1.97, Revision 3, as part of their Detailed
Control Room Design Review. Currently, no Braidwood Station procedure describes or
controls these markings, which consist of a black dot on the panel next to the indicator.
The markings were intended to indicate qualification for reliability under accident
conditions. Therefore, if multiple indications conflicted during an accident, the operators
should prefer the indicators with a black dot.
The inspectors identified that markings existed for numerous post-accident indications
on both units control panels and the simulator. When questioned about how these
markings were controlled, the licensee stated that they were informally controlled as part
of the PASSPORT database panels and was initially unable to provide a list of marked
instruments due to the large number of RG 1.97 instruments and unmarked
subcomponents which were also contained in the PASSPORT database.
To address the concern regarding the accuracy of these markings, the licensee walked
down the panels, and reviewed the source documents and PASSPORT further. It was
47 Enclosure
determined that there were errors in both the Unit 1 and Unit 2 control rooms and the
simulator, which included the following discrepancies:
labeled with a black dot;
level, was not labeled with a black dot;
dot;
dot;
dot;
dot;
dot;
dot;
dot; and
with a black dot.
The licensee initiated IR 688723, corrected the discrepancies identified by labeling the
appropriate post-accident instruments and initiated Training Requests to evaluate the
need for familiarization on post-accident monitoring instrumentation. In addition, the
licensee planned to revise Procedures 1BwOSR 3.3.3.1, Unit One Accident Monitoring
Instrumentation Channel Checks and 2BwOSR 3.3.3.1, Unit Two Accident Monitoring
Instrumentation Channel Checks to validate RG 1.97 labeling periodically. The
procedure revisions were being tracked by action tracking item 709180-02.
Analysis: The inspectors determined that the licensees failure to perform adequate
procedural controls was a performance deficiency warranting a significance evaluation in
accordance with IMC 0612, Appendix B. The inspectors concluded that the finding was
greater than minor because it could become a more significant safety issue if left
uncorrected. Inaccurately labeled control room indicators of post-accident
instrumentation could lead to confusion and hamper operator response if conflicting
indications resulted due to accident conditions.
Using IMC 0609.04, the inspectors concluded that this issue was of very low safety
significance (Green) because the finding was did not represent; a design or structure,
system and component qualification deficiency; a loss of system safety function; an
actual loss of safety function or exceed TS allowed outage time; an actual loss of safety
function of one or more non-TS, risk-significant trains; or a potentially risk-significant
scenario related to external initiating events.
The inspectors did not identify a cross-cutting aspect to this finding.
48 Enclosure
Enforcement: Technical Specification 5.4.1 required, in part, that written procedures be
established and implemented for activities provided in RG 1.33, Revision 2, Appendix A,
February 1978. Procedures specified in RG 1.33 included administrative procedures for
equipment control. UFSAR 13.5, Plant Procedures, stated that a formalized system of
written procedures containing administrative and operating instructions in conformance
with RG 1.33 was employed to ensure that all abnormal or emergency activities were
conducted in a safe manner.
Contrary to the above, the inspectors identified that the licensee failed to control labeling
of control panels for uniquely identifying RG 1.97 equipment. Specifically, the licensee
failed to control labeling on both units control panels and the simulator, resulting in
improperly marked post-accident indicators. However, because this violation was of
very low safety significance and was entered into the licensees CAP, this violation was
treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy. (NCV
05000456/2008003-05; 05000457/2008003-05)
This URI (05000456/2008001-01; 05000457/2008001-01) is closed.
.4 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.
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.
b. Findings
No findings of significance were identified.
4OA6 Management Meetings
.1 Exit Meeting Summary
On July 9, 2008, the inspectors presented the inspection results to Mr. B. Hanson, and
other members of the licensee staff. The licensee acknowledged the issues presented.
The inspectors confirmed that none of the potential report input discussed was
considered proprietary.
.2 Interim Exit Meetings
Interim exits were conducted for:
- On April 2, 2008, the inspectors presented the TI 2515/166, PWR Containment
Sump Blockage (NRC GL 2004-02), results to Mr. J. Petty, and other members
of the licensee staff. The licensee acknowledged the issues presented.
49 Enclosure
- The results of the Access Control to Radiologically Significant Areas and ALARA
Planning And Controls inspection with the Site Vice President, Mr. B. Hanson, on
May 2, 2008.
Vice President on May 6, 2008. The inspectors returned proprietary information
reviewed during the inspection prior to leaving the site.
- Licensed Operator Requalification Program Unresolved Item Inspection with
Mr. G. Golwitzer, Acting Regulatory Assurance Manager, Braidwood Station,
June 23, 2008, via telephone.
The inspectors confirmed that none of the potential report input discussed was
considered proprietary.
50 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
B. Hanson, Site Vice President
L. Coyle, Plant Manager
K. Aleshire, Emergency Preparedness Manager
D. Burton, Licensed Operator Requalification Training Group Lead
S. Butler, Operations Training Manager
B. Casey, Inservice Inspection Program
G. Dudek, Site Training Director
R. Gadbois, Maintenance Director
G. Golwitzer, Acting Regulatory Assurance Manager
D. Gullott, Regulatory Assurance Manager
K. Hall, Operations
J. Knight, Nuclear Oversight Manager
T. McCool, Operations Director
J. Moser, Radiation Protection Manager
J. Neybart, Maintenance Department
G. Panici, Senior Engineer
J. Petty, Licensing Engineer
L. Sanna, Maintenance Department
J. Sanchez, Operations Department
B. Schipiour, Work Management
M. Sears, Steam Generator Engineer
M. Smith, Engineering Director
T. Tierney, Chemistry, Environmental, and Radioactive Waste Manager
Nuclear Regulatory Commission
R. Skokowski, Chief, Reactor Projects Branch 3
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
05000456, 457/2008003-03 URI AFW Tunnel Hatches Margins of Safety (Section 1R15)
Opened and Closed
05000456, 457/2008003-01 NCV Failure to Properly Implement Material control
Procedures (Section 1R01)
05000456, 457/2008003-02 NCV Inadequate Procedure (Section 1R06)
05000456, 457/2008003-04 NCV Failure to Sample a Temporary Tank at the Required
Periodicity (Section 2PS2)
1 Attachment
05000456, 457/2008003-05 NCV Failure to Control Labeling on Both Units Control
Panels and Simulator (Section 4OA5)
Closed
05000456, 457/2008001-01 URI Failure to Control RG 1.97 Instrumentation Marking
(Section 1R15)
2 Attachment
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this list
does not imply that the NRC inspector reviewed the documents in their entirety, but rather that
selected sections or 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
- 0BwOA ENV-1; Adverse Weather Conditions Unit 0; Revision 106
- 0BwOS XHT-A1; Unit Common High Temperature Equipment Protection Surveillance;
Revision 2
- BwOP MP-26; Supplemental Main Power Transformer Cooling; Revision 0
- EN-BR-402-0005; Extreme Heat Implementation Plan; Revision 1
- MA-AA-718-026; Station Housekeeping/Material Condition Program; Revision 5
- WC-AA-107; Seasonal Readiness; Revision 5
- Exelon Nuclear Letter; Certification of 2008 Braidwood Summer Readiness; May 15, 2008
- IR 752473; NOS Identified Summer Readiness Procedure Action Dates Not Met,
March 20, 2008
- IR 758730; Procedure Enhancement for 0BwOA ENV-1; April 3, 2008 [IEMA-Identified]
- IR 763083; 2CW003B Summer Readiness Action Not Being Performed in A2R13;
April 4, 2008
- IR 767822; Safety - Flying Debris On Site; April 25, 2008
- IR 767858; Adverse Weather Conditions - Entered BwOA ENV-1; April 25, 2008
- IR 770357; Three Scaffold Poles and Material in Unit 1 Transformer Yard; May 1, 2008
[NRC-Identified]
- IR 771219; 0/1/2/ENV-1 Entry; May 2, 2008
- IR 775201; Unit 1 Turbine Oil Transient; May 13, 2008
- IR 778589; Main Power Transformer Supplemental Cooling Not Secured Properly;
May 22, 2008 [NRC-Identified]
- IR 780318; IEMA Inspector Identified Housekeeping Concerns; May 28, 2008 [IEMA-Identified]
- IR 780777; NRC Identified Miscellaneous Debris in Transformer Yard; May 29, 2008
[NRC-Identified]
- IR 780979; Entry Into 0BwOA ENV-1, 1BwOA ENV-1, and 2BwOA ENV-1; May 30, 2008
- IR 781334; Security Camera 9 Went Out Due to Severe Weather; May 30, 2008
- IR 781339; Security Camera 5 Went Out Due to Severe Thunderstorm; May 30, 2008
- IR 781352; Entry Into 0/1/2 BwOA ENV-1; May 30, 2008
- IR 781363; Received Annunciator 0-38-E5, Accelerograph Acceleration High; May 30, 2008
- IR 781945; IEMA Identified Discharge Flex Hose Broken on 2VE09S; June 2, 2008
[IEMA-Identified]
- IR 782644; Replace D-181 Door Threshold; June 4, 2008 [NRC-Identified]
- 0BwOA ELEC-1 Abnormal Grid Conditions Unit 0; Revision 6
- OP-AA-108-107-1001 Station Response to Grid Capacity Conditions; Revision 2
- OP-AA-108-107 Switchyard Control; Revision 2
Section 1R04: Equipment Alignment
- BwOP DG-M4; Operating Mechanical Lineup Unit 2 2B D/G; Revision 11
- BwOP DG-E4; Electrical Lineup - Unit 2 2B Diesel Generator; Revision 5
- BwOP DG-M1; Operating Mechanical Lineup Unit 1 1A D/G; Revision 14
3 Attachment
- BwOP DG-E1; Electrical Lineup - Unit 1 2A Diesel Generator; Revision 6
- BwOP AF-E1; Electrical Lineup - Unit 1 Operating; Revision 11
- BwOP AF-M!; Operating Mechanical Lineup Unit 1; Revision 10
- IR 787664; NRC Identified - Add Hand Switch Equipment Part Numbers to Shutdown Panel
Labels; June 18, 2008 [NRC-Identified]
Section 1R05: Fire Protection
- Byron/Braidwood Nuclear Stations Fire Protection Report; Amendment 22; December 2006
- GOCAR Required Compensatory Measures Action Response Appendix R Emergency
Lighting; May 5, 2008
- CC-AA-211; Fire Protection Program; Revision 2
- BwAP 110-1; Fire Protection Program System Requirements; Revision 28
- IR 760766; NRC Identified Rags in the 1B Containment Spray Pump Room; April 8, 2008
[NRC-Identified]
- IR 761728; Material Found Behind Fuel Oil Line on 2A Diesel Generator; April 10, 2008 [NRC-
Identified]
- IR 761734; Material Left in 2A Safety Injection Pump Room; April 10, 2008 [NRC-Identified]
- IR 761778; IEMA Inspector Told the Work Execution Center the Back of MCC 133V4 Was
Open; April 10, 2008 [IEMA-Identified]
- IR 764634; IEMA Inspector Identified Issues in 2A Safety Injection Pump Room; April 17, 2008
[IEMA-Identified]
- IR 771999; Appendix R Lights Almost Dead During 234V Bus Outage; May 5, 2008
[NRC-Identified]
- IR 772946; IEMA Identified Transient Combustible Material Behind MCC 233V5; May 7, 2008
[IEMA-Identified]
- IR 787368; NRC Identified Door D-226 Not Latching Closed Following Passage;
June 17, 2008 [NRC-Identified]
Section 1R06: Flooding
- BwAP 1110-3; Plant Barrier Impairment Program; Revision 15
- IR 760446; Unit 2 SX Room Sump Alarm not Alarming; April 7, 2008
- IR 766773; Plant Barrier Impairment Compensatory Actions Changed, Not Identified by Shift;
April 23, 2008 [IEMA-Identified]
- IR 771437; Missed Flood Watch on 2SXFS02-1 For Entire 12 Hour Shift; May 2, 2008
Section 1R07: Heat Sink Performance
- Calculation BRW-97-1072-M; Component Cooling Heat Exchanger Tube Plugging Evaluation;
Revision 0
- Engineering Change EC 357161; Heat Exchanger Visual Inspection Acceptance Criteria;
Revision 0
- IR 760868; 2CC01A - Unit 2 Component Cooling Heat Exchanger East Head Flange
Degradation Increasing; April 9, 2008
- IR 761744; Cleaning Scrappers Stuck in Three Tubes in Unit 2 Component Cooling Heat
Exchanger; April 10, 2008
- IR 761765; Seacure Tubing Eddy Current Inspection 2CC01A; April 10, 2008
- IR 763185; 2CC01A - 8 Tubes Plugged Per Eddy Current Test Data - Total = 49 Tubes;
April 14, 2008
4 Attachment
Section 1R08: ISI Activities
- IR 547480; Incorrect ISI Weld Inspected; October 22, 2006
- IR 550299; FME Event Steam Generator; October 28, 2006
- IR 552261; Steam Generator Chemistry Action Level 1; November 2, 2006
- IR 566370; Boric Acid Leak 2RH01CB-16 Flanged Connection; December 7, 2006
- IR 543851; Boric Acid Leak 2CV04AA Inlet Flange; October 13, 2006
- IR 549559; UT of 5 Welds Deferred to A2R13; October 26, 2006
- IR 576532; Degradation of Hydraulic Snubber Fluid; January 5, 2007
- IR 628474; Through-Wall Leakage 2SX27DA-10; May 11, 2007
- IR 628554; Misapplication of CGI Gaskets; October 10, 2007
- IR 664847; 2RC8037A Boric Acid Leakage; August 23, 2007
- IR 664853; 2RC8037B Boric Acid Leakage; August 27, 2007
- IR 681083; FME Event Steam Generator; October 6, 2007
- IR 681801; FME Event Steam Generator; October 8, 2007
- IR 684599; FME Event Reactor Vessel; October 14, 2007
- IR 768257; Flaw Evaluation not Scheduled; April 29, 2008
- IR 679564; PT Indication Discovered on Base Metal Exam on C Nozzle; October 3, 2007
- IR 679792; PT Indication Discovered on the A Safety Nozzle; October 3, 2007
- IR 684405; Weld Overlay Rejectable PT Indication; October 13, 2007
- IR 549140; NDE Indications Found During Weld Exam for VLV 2SI8952B; October 26, 2006
- IR 768009; Pressurizer Weld Overlay Anomaly; April 26, 2008
- UT Calibration Sheet A2R13-UT-045; Elbow-to-pipe Weld 2SI-01-03; April 29, 2008
- UT Calibration Sheet A2R13-UT-044; Elbow-to-pipe Weld 2SI-30-15; April 29, 2008
- Surface Examination Data (Magnetic Particle Examination); Steam Generator 16-inch
Feedwater Nozzle to Stub Barrel; May 3, 2008
- UT Calibration Sheet A2R13-PN-04-SW-4; Pressurizer Safety A SWOL; May 4, 2008
- UT Calibration Sheet A2R13-PN-06-SW-6; Pressurizer Safety C SWOL; May 5, 2008
- PT Examination Sheets; Pressurizer Safety Nozzle A (PN-04-A); May 4, 2008
- PT Examination Sheets; Pressurizer Safety Nozzle C (PN-04-C); May 3, 2008
- UT Calibration Sheet A1R13-PN-01-SW-1; Pressurizer Surge Nozzle SWOL;
October 14, 2007
- 900638-PT-008 (PT Examination Sheets); Pressurizer Surge Nozzle to Pipe 1PN-01-SW-1;
Pressurizer Surge Nozzle to Pipe 1PN-01-SW-1
- ISI-PDI-UT-2; Ultrasonic Examination of Austenitic Piping Welds in Accordance with PDI-UT-2;
Revision 4
- EXE-ISI-70; Magnetic Particle Examination; Revision 2
- PDI-ISI-254-SE; Remote Inservice Examination of Reactor Vessel Nozzle to Safe End, Nozzle
to Pipe and Safe End; Revision 2
- PDI-ISI-254; Remote Inservice Examination of Reactor Shell Welds; Revision 7
- ER-AP-420-0051; Conduct of Steam Generator Management Program Activities; Revision 11
- ER-AP-331; Boric Acid Corrosion Control (BACC)Program; Revision 3
- ER-AP-331-1001; BACC Locations, Implementation and Inspection Guidelines; Revision 3
- ER-AP-331; BACC Program Identification, Screening and Evaluation; Revision 3
- GDP-9.7; Liquid Penetrant Examination and Acceptance Standards for Welds, Base Materials
and Cladding; Revision 11
- PS-03; GQP 9.7 Procedure Supplement; March 13, 2008
- EXE-PDI-UT-108; Ultrasonic Examination of Weld Overlay Similar and Dissimilar Welds in
Accordance with PDI-UT-8; Revision 1
- WDI-STD-1016; Generic Procedure for the Ultrasonic Informational Only Examinations of
Weld Overlay Material Using Straight Bea (0o) and Angle Beam Probes; Revision 1
5 Attachment
- WDI-SSP-1112; Procedure for Acquiring Material Thickness and Circumference
Measurements of Liquid Penetrant Examination; Revision 4
- Examination Plan; 2008 - 10 Year Reactor Vessel Examination Program Plan (Scan Plan);
Revision 0
- Report; Steam Generator Condition Monitoring Operational Assessment Report; Revision 0
- Report ED-BWR-08-003; Braidwood Unit 2 Steam Generator Inspection Degradation
Assessment and Condition Monitoring Input Checklist for A2R13; April 14, 2008
- Report ED-BWR-08-005; Braidwood Unit 2 Steam Generator Inspection Degradation
Assessment and Condition Monitoring Inp Use of Appendix H Qualified Techniques at
Braidwood Unit 2 A2R13 Outage; March 10, 2008
- Boric Acid Evaluation; RCP 2B No 1 Seal Flow Element; January 15, 2007
- Boric Acid Evaluation; 2B Reactor Coolant System Loop Drain Isolation Valve;
December 7, 2007
- ETSS CDE-001-0408; 0.610 Bobbin 40 IPS; Revision 0
- ETSS CDE-002-0408; 0.590 Bobbin 24 IPS; Revision 0
- ETSS CDE-003-0408; 3 Coil +Point; Revision 0
- ETSS CDE-004-0408; 3 Coil +Point (Dent); Revision 0
- ETSS CDE-005-0408; 3 Coil +Point (Mag Bias); Revision 1
- ETSS CDE-006-0408; Low Row U-Bend +Point; Revision 1
- ETSS CDE-007-0408; High Row U-Bend +Point; Revision 0
- WDI-PJF-1303502-TR-003; Investigation on the Variation in Reference Sensitivity Between
Nominal 3/32-Inch (0.094) Diameter Side-Drilled Holes with Diameter Increases Up to 0.0025-
Inch; Revision 0
- CMTR; Inconel Filler Metal 52M .045 x 10Spl; June 1, 2007
- WPS 8 MC-GTAW; Machine GTAW for SWOL; Revision 10
- PQR 046 R/3; PQR for WPS 8 MC-GTAW; Revision 3
- PQR 062 R/3; PQR for WPS 8 MC-GTAW; Revision 3
- PQR 600; PQR for WPS 8 MC-GTAW; Revision 4
- WPS 8-MN-GTAW/SMAW; Manual GTAW/SMAW for SWOL; Revision 15
- PQR 063; PQR for WPS 8-MN-GTAW/SMAW; Revision 3
- WO 00985967; Weld Overlay for Unit 1 Pressurizer Surge Nozzle (PN-01);
September 27, 2007
- Contract 00412187; Transmittal of PCI Welder Qualification Records for A2R13 Pressurizer
SWOL; April 16, 2008
- WO 01078103-04; Weld Overlay Traveler for Pressurizer Unit 2 A Nozzle Overlay; March 14,
WO 01078103-08; Weld Overlay Traveler for Pressurizer Unit 2 C Nozzle Overlay;
March 14, 2008
- WEG-SWOL-01; Determination of SWOL Weld Track Travel Speed; Revision 0
- WPS 3-8/52-TB MC-GTAW-N638; Machine GTAW for SWOL (P3-P8); Revision 7
- PQR 677; PQR for WPS 3-8/52-TB MC-GTAW-N638; April 9, 2001
- PQR 750; PQR for WPS 3-8/52-TB MC-GTAW-N638; Revision 1
- PQR 770; PQR for WPS 3-8/52-TB MC-GTAW-N638; Revision 4
Section 1R12: Maintenance Effectiveness
- BwOP SA-1; Startup and Operation of Station Air Compressors; Revision 36
- IR 772936; NRC Identified Maintenance Rule Website Not Up-to-Date For SA System;
May 7, 2008 [NRC-Identified}
- IR 352740; Unit 1 Station Air Compressor Tripped During Start Attempt; July 15, 2005
- IR 502360; U-2 SAC has High Vibes; June 21, 2006
- IR 503175; Unit 2 SAC Tripped on High Vibrations; June 24, 2006
6 Attachment
- IR 501537; U-2 SAC Tripped on Hi Oil Temperature; June 19, 2006
- IR 613656; Unit 0 SAC High Speed Vib was Noted Higher During Post Maintenance Testing;
April 4, 2007
- IR 659297; Unexpected Alarm, High CO content in Service Air; August 10, 2007
- IR 577250; Corrective Actions from EACE Not incorporated into SAC Work; January 10, 2007
- IR 601858; U2 SAC Tripped on Driver Fault During Run After Maintenance; March 10, 2007
- IR 618457; Unit 2 SA System Exceeding MR Unavailability; April 17, 2007
- IR 640810; Service Air Drop Drain is Clogged; June 15, 2007
- IR 502397-04;(a)(1) Determination; April 24, 2007
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
- Unit 2 Component Cooling Heat Exchanger Work Window Protected Equipment; April 7, 2008
- Braidwood Operating Department Memorandum 3-04; Physical Posting of Protected
Equipment; Revision 3
- TS 3.0.4.b Evaluation - Mode 3 Entry With 2AF01PB Unavailable; Revision 0
- ER-AA-600-1042; On-Line Risk Management; Revision 4
- Protected Equipment List; 2B AFW Pump Unavailable During Mode 3 Entry; May 15, 2008
- WO 1135330-05; Troubleshoot 2E Main Power Transformer Transfer Circiut
- IR 775470; 2B AFW Pump did not Start While Performing Testing; May 14, 2008
- IR 775798; 2B AFW Pump Gear Box Auxiliary Lube Oil Pump did not Shut Off; May 15, 2008
- IR 776054; 3.0.4.B Risk Assessment - 2AF01PB Wrong Revision Referenced; May 15, 2008
[NRC-Identified]
- IR 776288; Bolting Issue with 2B AFW Pump Gear Driven New Pump, May 16, 2008
- IR 776728; 2E Main Power Transformer Cooling Fans Will Not Auto-Transfer; May 16, 2008
Section 1R15: Operability Evaluations
- BwAP 2200-2; Shutdown Safety Contingency Plan for the Reactor Head Reassembly
Sequence; Revision 0
- 1BwEP-0 Reactor Trip or Safety Injection Unit 1; Revision 2
- BwMP 3300-005; Primary Containment Equipment Hatch Removal and Installation; Revision 5
- 2BwOA PRI-10; Loss of RH Cooling Unit 2; Revision 102
- 2BwOS XPC-W1; Unit 2 Containment Penetration Status Weekly Surveillance; Revision 15
- ER-AA-1200; Critical Component Failure Clock; Revision 4
- Shaw A2R13 Containment Closure Plan; April 24, 2008
- EC 369245; Auxiliary Feedwater Tunnel Flood Seal Cover Modification, Unit 1; Revision 0
- Design Analysis 5.6.3-BRW-08-0045-S; Structural Evaluation of the Flood Seal Cover Support
in the Main Steam Isolation Valve Rooms, Unit 1, Per EC 369245; Revision 0
- IR 620080 (Byron); Auxiliary Feedwater Tunnel Cover Bolt Uses Non-Standard Safety Factor;
April 21, 2007
- IR 623323 (Byron); Request Permission to Look For Problem; April 30, 2007
- IR 629677 (Byron); Difference in Professional Opinion on Jet Impingement; May 15, 2007
- IR 653093 (Byron); The Auxiliary Feedwater Tunnel Covers do not Meet Expected Safety
Factors (July 24, 2007
- IR 654270; Auxiliary Feedwater Tunnel Cover Bolt Evaluation Uses Non-Standard Safety
Factors; July 26, 2007
- IR 759038; 0VC21YC Damper Does not open when required; April 3, 2008
- IR 759803 1CS01PA-M Lower Motor Oil Reservoir Shows Low oil; April 6, 2008
- IR 762106; 1SX169A Failed to Open when 1A D/G was Started
- IR 763028 1A CS Add Flow Surveillance invalid- Test Gauge Failed Post Cal; April 14, 2008
7 Attachment
- IR 763179 1CS021A- U1 TR A CS Spray Add Flow Test As-Found Unsat; April 14, 2008
- IR 764362; Small Oil Leak on 2CV01PA; April 17, 2008 [IEMA-Identified}
- IR 764527 (Byron); Unit 1 Auxiliary Feedwater Tunnel Cover Modification - WO Needs
Research; April 17, 2008
- IR 772939; NRC Identified Enhancement for A2R13 Containment Closure Plan; May 7, 2008
[NRC-Identified]
- IR 780531; Confusion Regarding Traceability of Past Operability Determinations;
May 29, 2008 [IEMA-Identified]
- IR 783849; Load Factor Not Used For Evaluation of Auxiliary Feedwater Tunnel Cover;
June 6, 2008 [NRC-Identified]
Section 1R19: Post Maintenance Testing
- BwOP FW-1; Start up of a Turbine Driven Main Feedwater Pump ;Revision 27
- 2BwOS DG-2B; 2B Diesel Generator Overspeed Trip Test; Revision 2
- 2BwOSR 3.8.1.2-2; Unit 2 2B Diesel Generator Operability Surveillance; Revision 21
- BwVSR 900-35; Diesel Generator Governor Set-Up Following Governor Replacement;
Revision 6
- 2BwVSR 5.5.8.SX.2 ASME Surveillance Requirements for 2B Essential Service Water Pump;
Revision 7
- IR 771344; 2DG01KB - A Lube Oil Pump Trips on Thermals; May 3, 2008
- IR 771613; 2B DG - No Lube Oil Pressure After Start; May 4, 2008
- IR 771646; 2B DG Lube Oil Pressure; May 5, 2008
- IR 772525; 2B DG Electronic Governor did not Control; May 6, 2008
- IR 773044; 2B DG Turbocharger Oil Pressure Requires Adjustment; May 8, 2008
- IR 771363; Moderate Corrosion Found on 2B SX PP Suction Piping; May 3, 2008
- IR 772055; Minor Corrosion Identified on Piping Associated with 2SX001B; May 5, 2008
- IR 774321; 2SX01PB Suction Flange Torque Incorrect in WO; May 11, 2008
- IR 774334; Minor Oil and Water Leaks on 2B SX Pump; May 11, 2008
- IR 782115; Poor Coordination of Heater Drain Pump Post Maintenance Test; June 2, 2008
- IR 782163 2B FW PP Oil Pressure Up Light Anomaly- 2FW01PB-A; June 2, 2008
- IR 782558; Evaluate the 2C Heater Drain Pump Return to Service Process; June 3, 2008
- IR 788991; 1FW039A Exceeds Operability Stroke Time; June 21, 2008
- MA-AA-716-004; Attachment 1 Troubleshooting Log; Revision 6
- MA-AA-716-004; Attachment 1 Troubleshooting Log; Revision 7
- WC-AA-114; 1BwOSR 3.6.3.5.FW-3, Low Low Feedwater Isolation Valve 1FW039 Valve
Stroke Surveillance; Revision 16
- WO 113913; 2BMFP Stop Valve
- WO 436515 MM-SX Pump/Motor Replacement; April 21, 2008
Section 1R20: Outage Activities
- 2BwGP 100-2; Plant Startup; Revision 23
- 2BwGP 100-3; Power Ascension 5 Percent to 100 Percent; Revision 44
- 2BwGP 100-4; Power Descension; Revision 26
- 2BwGP 100-5; Plant Shutdown and Cooldown; Revision 31
- BwVS 500-6; Low Power Physics Test Program
- A2R13 Shutdown Safety Management Plan; Revision 0
- A2R13 Containment Load Path Risk Assessment; Revision 0
- A2R13 Containment Atmosphere Management Plan; Revision 0
8 Attachment
- Operating Experience Smart Sample FY2007-03; Crane and Heavy Lift Inspection,
Supplemental Guidance for IP-71111.20; Revision 1
- IR 779213; A2R13 In-Mast Sipping Identified Two Leaking Fuel Assemblies; May 1, 2008
- IR 770869; IEMA Identified Issues With Risk Colors on Unit 2; May 2, 2008 {IEMA-Identified]
- IR 772605; 2B Tendon Tunnel Sump Pump Discharge Flange Leak; May 7, 2008 [NRC-
Identified]
- IR 772453; Primary Containment Tendon End Cover V320 Grease Leakage; May 6, 2008
[NRC-Identified]
Section 1R22: Surveillance Testing
- BwOP PC-1; Local Leak Rate Flowmeter Monitor Operation; Revision 12
- BwOP DG-12; Diesel Generator Shutdown; Revision 24
- BwOP DG-11; Diesel Generator Startup; Revision 34
- BwOP RH-5; RH system Startup for Recirculation; Revision 20
- 1BwOSR 3.6.2.1-4; Unit One Primary Containment Type B Local Leakage Rate Test of the
Emergency Hatch Airlock Door Gasket Interspaces; Revision 8
- 1BwOSR 3.7.5.4-2; U1 Diesel Driven Auxiliary Feedwater Pump Surveillance; Revision 14
- 1BwOSR 3.8.1.2-1; Unit One 1A Diesel Generator Operability Surveillance; Revision 23
- 1BwOSR 3.8.1.13-2; Diesel Generator Bypass of Automatic Trip Surveillances; Revision 7
- 1BwOSR 3.8.1.13-2; 1B Diesel Generator Bypass of Automatic Trip Surveillance; Revision 7
- BwVSR 3.7.1.1; Main Steam Safety Valves Operability Test; Revision 5
- 1BwVSR 5.5.8.AF.2; U1 Diesel Driven Auxiliary Feedwater Pump ASME Quarterly
Surveillance; Revision 12
- 2BwVSR 5.5.8.RH.2; ASME Surveillance Requirements for Residual Heat Removal Pump
2RH01PB; Revision 7
- BwMP 3305-107; Main Steam Safety Valves Lift Point Verification Using the Furmanite
Trevitest System; Revision 13
- IR 726426; 2B RH Recirc flow Below the Acceptance Criteria; January 24, 2008
- IR 762106; 1SX169A Failed to Open When 1A Diesel Generator Was Started; April 11, 2008
- IR 762445; 1A Diesel Generator Failed to Run for 5 Minutes in Cooldown; April 11, 2008
- IR 763170; Potential Local Leak Rate Test Issue on Emergency Hatch Surveillance;
April 14, 2008 [NRC-Identified]
- IR 777831; 1B D/G Running Without being Able to Use Proper VC Alignment; May 20, 2008
- IR 787525; 1B AFW Pump Maintenance run Results - 1AF01PB; June 18, 2008
- WO 9629213; Main Steam Safety Valves Operability Test
- WO 1122729 01; September ASME Surveillance Requirement for 2B Residual Heat Removal
Pump; June 25, 2008
Section 2OS1: Access Control to Radiologically Significant Areas
- IR 760253; Detector Maximum Dose Rate in UFSAR Higher Than Seen in; A1R13;
April 7, 2008
- IR 767338; Hydrogen Alarms Occurring in Unit 2 Containment Cause Delays; April 24, 2008
- RP-AA-376; Radiological Postings, Labeling, and Markings; Revision 2
- RP-AA-460; Controls for High and Very High Radiation Areas; Revision 12
- ASSA 560706; Self Assessments - Access Control to Radiologically Significant Areas;
May 2, 2007
9 Attachment
Section 2OS2: ALARA Planning And Controls
- IR 762961; Dose Estimate Not Sufficient to Complete Work; April 14, 2008
- IR 763295; Job Stopped Dose Concerns for Work; April 14, 2008
- IR 763451; Mechanical Maintenance Received Unplanned Dose for Hot Shop Work;
April 4, 2008
- IR 764139; Dose Goal Exceeded For Safety Injection Pump Room Scaffolds; April 15, 2008
- IR 0770531; Decision on Pressurizer Spray Nozzle Flush/Peroxide Addition; May 1, 2008
- RP-AA-400; ALARA Program; Revision 4
- RP-AA-401; Operational ALARA Planning and Controls; Revision 8
- RWP 10008701; Reactor Head Component Disassembly and Reassembly; Revision 1
- RWP 10008715; Split Pin Modifications; Revision 2
- RWP 10008730; Pressurizer Weld Over Lay Project; Revision 0
- RWP 10008731; Pressurizer Weld Over Lay Insulation, Shielding and Support Activities;
Revision 0
- RWP 10008740; Steam Generator Eddy Current Testing and All Tube Repairs; Revision 0
- RWP 10008669; ALARA Work in Progress Review Routine Fuel Handling Activities;
Revision 9
- RWP 10008670; ALARA Work in Progress Review Fuel Moves; Revision 9
- RWP 10008678; ALARA Work in Progress Review In-service Inspections; Revision 9
- ASSA 560752; Self Assessments - Radiological Work permits and ALARA Hold Points;
December 12, 2007
- RWP 10008741; ALARA Work in Progress Review Sludge Lance; Revision 9
Section 2PS1: Radioactive Gaseous And Liquid Effluent Treatment And Monitoring
Systems
- EC 362141; Installation of New 500,000 Gallon Radwaste Storage Tank; Revision 001
- IR 761293; Post Modification Test for EC 362141 Stopped and System Restored; April 9, 2008
- IR 761802; Water in Radwaste Storage Tank Berm at 3,374 PICI/L; April 10, 2008
- IR 762422; 0WX027T Concrete Pad Tritium Analysis High; April 11, 1008
- IR 772572; North Oil Separator Tritium Concentration Exceeds 1150 PCI/L; May 6, 2008
- IR 773004; Tritium Concentration Higher Than Desired in Turbine Equipment and Fire and Oil
Sumps; May 7, 2008
- IR 773067; ODCM - Unit 2 Gas Effluent Dose Projection Exceeds 0.3 MREM; May 8, 2008
- IR 775872; Challenge to Annual Liquid Release Curie Limit; May 15, 2007
- IR 777809; Watchdog Alarms Multiple Vacuum Breakers; May 20, 2008
- IR 781144; Dispose of Drums by Vacuum Breaker #2; May 30, 2008
Section 2PS2: Radioactive Material Processing and Transportation
- IR 770446; Sampling of Shower Tanks for Containment Access Facility Not Sampled Per
Technical Requirements Manual Appendix L; May 1, 2008
- EC 368927; Unit 2 Containment Access Facility: Fire Protection and Temporary
Decontamination Tanks; Revision 001
- RP-BR-654; Unit 1(2) Containment Access Facility Liquid and Air Sampling and Disposal
Requirements; Revision 0
- Technical Requirements Manual, App L; Explosive Gas and Storage Tank Radioactivity
Monitoring Program; Revision 44
10 Attachment
Section 4OA1: PI Verification
- LS-AA-2090, Monthly Data Elements for NRC Reactor Coolant System (RCS) Specific
Activity, Revision 4
- LS-AA-2100, Monthly Data Elements for NRC RCS Leakage, Revision 5
- 1BwOSR 3.4.13.1, Unit One RCS Water Inventory Balance Surveillance, Revision 18
- 2BwOSR 3.4.13.1, Unit Two RCS Water Inventory Balance Surveillance, Revision 18
Section 4OA2: Identification and Resolution of Problems
- Braidwood Quarterly System Health Report; 4th quarter 2007
- Standing Order 07-002; Human Performance Expectation; March 19, 2008
Section 4OA3: Followup of Events and Notices of Enforcement Discretion
- 0BwOA ENV-4; Earthquake Unit 0; Revision 104
- 1BwOA ENV-4; Earthquake Unit 1; Revision 100
- 2BwOA ENV-4; Earthquake Unit 2; Revision 100
- EP-AA-1001; Radiological Emergency Plan Annex for Braidwood Station; Revision 21
- IR 764738; Unplanned Entry Into 0/1/2BwOA ENV-4 Due to Earthquake; April 18, 2008
- IR 767223; Procedure Enhancements for 0BwOA Env-4; April 24, 2008 [NRC-Identified]
- IR 768709; Internet ESOMS Does Not Display Annotated Log Entries; April 28, 2008 [NRC-
Identified]
- Voluntary Event Notification; Press Release Concerning Seismic Event; April 18, 2008
Section 4OA5: Other Activities
- IR 282077; Tracking IR for PWR Sump Blockage Generic Letter and Bulleting;
October 29, 2007
- IR 694755; Enhancement to Braidwood Station Labeling Program; November 05, 2007
- ICC-AA-102; Design Input and Configuration Change Impact Screening; Revision 13
- OP-AA-116-101; Equipment Labeling; Revision 11
- 1BWOS TRM 2.5.b.1; Unit 1 Containment Loose Debris Inspection; Revision 1
- 2BWOS TRM 2.5.b.1; Unit 2 Containment Loose Debris Inspection; Revision 2
- CC-AA-205; Control of Undocumented/Unqualified Coatings Inside Containment; Revision 4
- Service Request 53465; Perform Latent Debris Walkdown; November 13, 2007
- BRW-05-0059-M; GSI 191 Post LOCA Debris Generation; September 08, 2006
- BRW-05-0060-M; Post LOCA Debris Transport Evaluation for Resolution of GSI 191;
September 07, 2006
- BRW-06-0016-M; SI/RHR/CS/CV System Hydraulic Analysis in Support of GSI 191;
December 28, 2007
- BRW-06-0035-M; NPSHA for RHR and CS Pumps during Post LOCA Recirculation;
September 06, 2007
- BRW-05-0063-M; GSI 191 Evaluation of Long Term Downstream Effects; December 31, 2007
- BRW-05-0084-M; Byron Units 1 and 2, and Braidwood Units 1 and 2, GSI 191 Downstream
Effects - Vessel Blockage and Fuel Evaluation; January 31, 2006
- BRW-06-0030-S; Evaluation of Auxiliary Steel for Sump Strainer Upper Sizing Restraints;
September 07, 2006
- BRW-06-0015-M; Design Loads and Sizing Limitations for the ECCS Containment Sump
Trash Racks; September 07, 2006
- DIT-BRW-2006-0007; Results of Test Debris Concentrations; January 27, 2006
11 Attachment
- Q.003.87 748; Large Size Filter Performance Test Specification; December 15, 2005
- CCI Test Report 680/41134; Large Size Filter Performance Test Report; September 18, 2006
- CCI Test Report 680/41222; Chemical Filter Performance Report; July 16, 2007
- WLTR53637; Wyle Test Report on Debris Latent Test Results of 1 1/2" Copes Volcan Control
Valve (SI 8810), A 2" Copes Volcan Control Valve (SI 8816), A 2" Copes Volcan Control Valve
(SI 8822) and Cyclone Separator; March 30, 2007
- S040-BRW-6042; GSI 191 Latent Debris Collection; May 31, 2006
- S040-BRW-6054; GSI 191 Debris Generation Walkdown; June 30, 2006
- Q.003.84 767; MFTL Chemical Filter Performance Test; June 01, 2006
- 3SA-096.016; CCI Structural Analysis of Strainer and Support Structure; Revision 1
- 3SA-096.018; Head Loss Calculation; November 22, 2006
- Regulatory Guide 1.97, Instrumentation for Light-Water-Cooled Nuclear Power Plants to
Assess Plant and Environs Conditions During and Following an Accident; Revision 3
- Technical Evaluation Report, EGG-NTA-7643, Conformance to Regulatory Guide 1.97:
Byron 1/-2 and Braidwood-1/-2; March 1989
- Letter dated May 19, 1989, to Mr. Thomas Kovach, Commonwealth Edison Nuclear Licensing
Manager, from Stephen Sands, NRC Project Manager, Documenting the Final Technical
Evaluation Report and the Safety Evaluation Report Reviewed by the NRC
- TR 08-86, CRC to Evaluate the Addition of Regulatory Guide 1.97 Components License
Training to Familiarize Licensed Personnel; January 22, 2008
- TR 08-87, CRC to Evaluate the Addition of Regulatory Guide 1.97 Components License
Training to Familiarize Licensed Personnel; January 22, 2008
- 1BwOSR 3.3.3.1; Unit One Accident Monitoring Instrumentation Channel Checks;
Revision 11
- IR 688723; NRC Request for Information on PAM Identification; October 24, 2007
- IR 709175; U-2 Accident Monitoring Instruments Missing Identities; December 8, 2007
- IR 709180; U-1 Accident Monitoring Instruments Missing Identities; December 8, 2007
- IR 723753; URI from NRC Initial License Exam Report (Reg. Guide 1.97); January 17, 2008
Other Inspector-Identified Minor Issues
- IR 769737; BRC Identified Security Delay Fencing Left Open; April 30, 2008 [NRC-Identified]
- NRC Nuclear General Employee Training System not Updated in NSMarT System;
May 1, 2008 [NRC-Identified]
12 Attachment
LIST OF ACRONYMS USED
AC Alternating Current
ALARA As-Low-As-Is-Reasonably-Achievable
ASME American Society of Mechanical Engineers
CAP Corrective Action Program
CFR Code of Federal Regulations
DG Diesel Generator
DMBW Dissimilar Metal Butt Weld
DRS Division of Reactor Safety
EC Engineering Change Package
ECCS Emergency Core Cooling System
EPRI Electric Power Research Institute
ET Eddy Current
GL Generic Letter
IEMA Illinois Department of Emergency Management
IMC Inspection Manual Chapter
IP Inspection Procedure
IR Issue Report
ISI Inservice Inspection
LER Licensee Event Report
LOCA Loss of Coolant Accident
MRP Materials Reliability Program
NCV Non-Cited Violation
NDE Nondestructive Examination
NEI Nuclear Energy Institute
NRC U.S. Nuclear Regulatory Commission
PBI Plant Barrier Impairment
PDI Performance Demonstrated Initiative
PI Performance Indicator
PT Penetrant Examination
PWR pressurized Water Reactor
RG Regulatory Guide
RWP Radiation Work Permit
RWST Refueling Water Storage Tank
SDP Significance Determination Process
SX Essential Service Water
TI Temporary Instruction
TRM Technical Requirements Manual
TS Technical Specification
TSO Transmission System Operator
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
UT Ultrasonic Examination
WO Work Order 13 Attachment