ML082270712
| ML082270712 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 08/14/2008 |
| From: | Pederson C Division Reactor Projects III |
| To: | Pardee C Exelon Generation Co, Exelon Nuclear |
| References | |
| EA-08-197 IR-08-003 | |
| Download: ML082270712 (76) | |
See also: IR 05000454/2008003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
August 14, 2008
Mr. Charles G. Pardee
Chief Nuclear Officer and
Senior Vice President
Exelon Nuclear
Exelon Generation Company, LLC
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: BYRON STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION
REPORT 05000454/2008-003 05000455/2008-003 PRELIMINARY
WHITE FINDING
Dear Mr. Pardee:
On June 30, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated
inspection at your Byron Station, Units 1 and 2. The enclosed report documents the inspection
findings, which were discussed on July 10, 2008, with Mr. D. Hoots and other members of your
staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
The enclosed inspection report discusses a finding that appears to have low to moderate safety
significance. As documented in Section 1R13 of this report, the licensee inadvertently entered
an elevated risk condition for Unit 2 in April 2008. At that time, the two Unit 1 essential service
water train cross-tie isolation valves were out of service for maintenance. These two valves
were opened locally to support the Unit 1 Train A emergency diesel generator testing and could
not to be closed from the main control room. The licensee later determined that this
configuration represented an elevated risk condition for Unit 2 due to degraded internal flood
mitigation capability.
This finding was assessed based on the best available information, including influential
assumptions, using the applicable significance determination process (SDP) and was
preliminarily determined to be of low to moderate safety significance (White) for Unit 2 and of
very low safety significance (Green) for Unit 1. The safety significance of the finding was
determined assuming a Unit 1 essential service water pipe break in the auxiliary building that is
not isolated due to unavailability of the two Unit 1 train cross-tie isolation valves and an
exposure time of 38 hours4.398148e-4 days <br />0.0106 hours <br />6.283069e-5 weeks <br />1.4459e-5 months <br />. The final resolution of this finding will convey the increment in the
importance to safety by assigning the corresponding color i.e. (White), a finding with some
increased importance to safety, which may require additional NRC inspection.
C. Pardee -2-
This finding was not an immediate safety concern because upon identification Byron Station
took immediate actions to assign a dedicated operator to locally close the valves when
necessary and to restore the remote actuation capability from the main control room. You have
also entered the issue into your corrective action program (CAP).
Based on the results of this inspection, one apparent violation was identified for Unit 2
and is being considered for escalated enforcement action in accordance with the NRC
Enforcement Policy. The current Enforcement Policy is included on the NRCs Web site at
http://www.nrc.gov/reading-rm/adams.html.
In accordance with Inspection Manual Chapter (IMC) 0609, we intend to complete our
evaluation using the best available information and issue our final determination of safety
significance within 90 days of this letter.
The significant determination process encourages an open dialog between the staff and
the licensee, however the dialogue should not impact the timeliness of the staffs final
determination. Before the NRC makes its enforcement decision, we are providing you an
opportunity to either: (1) present to the NRC your perspectives on the facts and assumptions,
used by the NRC to arrive at the finding and its significance at a Regulatory Conference or
(2) submit your position on the finding to the NRC in writing. If you request a Regulatory
Conference, it should be held within 30 days of the receipt of this letter and we encourage you
to submit supporting documentation at least one week prior to the conference in an effort to
make the conference more efficient and effective. If a conference is held, it will be open for
public observation. The NRC will also issue a press release to announce the conference. If
you decide to submit only a written response, such submittal should be sent to the NRC within
30 days of the receipt of this letter. If you decline to request a Regulatory Conference or to
submit a written response, your ability to appeal the final SDP determination can be affected, in
that by not doing either you fail to meet the appeal requirements stated in the Prerequisite and
Limitation sections of Attachment 2 of IMC 0609.
Please contact Richard Skokowski at 630-829-9620 within 10 days of the date of this letter to
notify the NRC of your intended response. If an adequate response is not received within the
time specified or an extension of time has not been granted by the NRC, the NRC will proceed
with its enforcement decision and you will be advised by separate correspondence of the results
of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for these inspection findings at this time. Please be advised that the number and
characterization of apparent violations described in the enclosed inspection report may change
as a result of further NRC review. You will be advised by separate correspondence of the
results of our deliberations on this matter. Since the finding for Unit 1 is of very low safety
significance, it is being treated as a Licensee Identified Non-Cited Violation in this report.
In addition, three NRC-identified and one self-revealed findings of very low safety significance
(Green) were also documented in the enclosed inspection report. All four findings were
determined to involve violations of NRC requirements. However, because of their very low
safety significance, and because the issues were entered into your CAP, the NRC is treating the
issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRC Enforcement
Policy. Furthermore, three licensee identified violations are listed in Section 4OA7 of this report.
C. Pardee -3-
If you contest the subject or severity of the Non-Cited Violations, you should provide a
response within 30 days of the date of this inspection report, with the basis for your denial,
to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington,
DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory
Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,
Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and
the Resident Inspector Office at the Byron Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the
Public Electronic Reading Room). To the extent possible, you response should not include any
personal privacy, proprietary, or safeguards information so that it can be made available to the
Public without redaction.
Sincerely,
/RA/
Cynthia D. Pederson, Director
Division of Reactor Projects
Docket Nos. 50-454; 50-455
Enclosure: Inspection Report 05000454/2008-003; 05000455/2008-003
w/Attachment: Supplemental Information
cc w/encl: Site Vice President - Byron Station
Plant Manager - Byron Station
Regulatory Assurance Manager - Byron 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
Illinois Emergency Management Agency
J. Klinger, State Liaison Officer,
Illinois Emergency Management Agency
P. Schmidt, State Liaison Officer, State of Wisconsin
Chairman, Illinois Commerce Commission
B. Quigley, Byron Station
C. Pardee -3-
If you contest the subject or severity of the Non-Cited Violations, you should provide a
response within 30 days of the date of this inspection report, with the basis for your denial,
to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington,
DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory
Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,
Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and
the Resident Inspector Office at the Byron Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the
Public Electronic Reading Room). To the extent possible, you response should not include any
personal privacy, proprietary, or safeguards information so that it can be made available to the
Public without redaction.
Sincerely,
Cynthia D. Pederson, Director
Division of Reactor Projects
Docket Nos. 50-454; 50-455
Enclosure: Inspection Report 05000454/2008-003; 05000455/2008-003
w/Attachment: Supplemental Information
cc w/encl: Site Vice President - Byron Station
Plant Manager - Byron Station
Regulatory Assurance Manager - Byron 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
Illinois Emergency Management Agency
J. Klinger, State Liaison Officer,
Illinois Emergency Management Agency
P. Schmidt, State Liaison Officer, State of Wisconsin
Chairman, Illinois Commerce Commission
B. Quigley, Byron Station
Document: G:\Byro\Byron 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 RIII RIII
NAME JDalzell:dtp RSkokowski KOBrien 1R13 CPederson
DATE 08/14/08 08/14/08 08/13/08 08/14/08
OFFICIAL RECORD COPY
Letter to C. Pardee from Cynthia Pederson dated August 14, 2008
SUBJECT: BYRON STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT
05000454/2008-003 05000455/2008-003 PRELIMINARY WHITE FINDING
DISTRIBUTION:
Meghan Thorpe-Kavanaugh
RidsNrrDirsIrib Resource
Mark Satorius
Kenneth OBrien
Roland Lickus
Cynthia Pederson (hard copy - IRs only)
DRPIII
DRSIII
Patricia Buckley
ROPreports@nrc.gov (inspection reports, final SDP letters, any letter with an IR number)
SECY
M. Virgilio, DEDMRS
C. Carpenter, OE
D. Starkey, OE
J. Wray, OE
A. Sapountzis, OE
E. Leeds, NRR
M. Ashley, NRR
F. Brown, NRR
J. Caldwell, RIII
L. Chandler, OGC
C. Marco, OGC
R. Romine, OGC
E. Brenner, OPA
H. Bell, OIG
G. Caputo, OI
D. Holody, RI
C. Evans, RII
W. Jones, RIV
V. Mitlyng, RIII
P. Chandrathil, RIII
A. Barker, RIII
J. Lynch, RIII
P. Lougheed, RIII
P. R. Pelke, RIII
M. Gryglak, RIII
OEMAIL
OEWEB
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-454; 50-455
Report Nos: 05000454/2008003 and 05000455/2008003
Licensee: Exelon Generation Company, LLC
Facility: Byron Station, Units 1 and 2
Location: Byron, Illinois
Dates: April 01, 2008, through June 30, 2008
Inspectors: B. Bartlett, Senior Resident Inspector
R. Ng, Resident Inspector
C. Acosta, Reactor Inspector
T. Bilik, Reactor Inspector
J. Cassidy, Senior Health Physicist
N. Féliz Adorno, Reactor Engineer
J. Jacobson, Senior Reactor Inspector
R. Jickling, Senior Emergency Preparedness Analyst
D. Jones, Reactor Inspector
V. Meghani, Reactor Inspector
R. Russell, Emergency Preparedness Analyst
C. Zoia, Project Engineer
C. Thompson, Resident Inspector, Illinois Department of
Emergency Management
Approved by: R. Skokowski, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
REPORT DETAILS .......................................................................................................................4
Summary of Plant Status...........................................................................................................4
1. REACTOR SAFETY ..........................................................................................................4
1R01 Adverse Weather Protection (71111.01) .....................................................4
1R04 Equipment Alignment (71111.04) ................................................................6
1R05 Fire Protection (71111.05)...........................................................................7
1R06 Flooding (71111.06) ....................................................................................9
1R08 Inservice Inspection (ISI) Activities (71111.08P) .......................................10
1R12 Maintenance Effectiveness (71111.12) .....................................................17
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
...................................................................................................................20
1R15 Operability Evaluations (71111.15) ...........................................................24
1R19 Post Maintenance Testing (71111.19).......................................................25
1R20 Outage Activities (71111.20) .....................................................................26
1R22 Surveillance Testing (71111.22)................................................................27
1EP2 Alert and Notification System (ANS) Evaluation (71114.02) .....................30
1EP3 Emergency Response Organization (ERO) Augmentation Testing
(71114.03) .................................................................................................31
1EP5 Correction of EP Weaknesses and Deficiencies (71114.05).....................31
2. RADIATION SAFETY ......................................................................................................32
2OS1 Access Control to Radiologically Significant Areas (71121.01) .................32
2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning And Controls
(71121.02) .................................................................................................33
4. Other Activities.................................................................................................................35
4OA1 PI Verification (71151) ...............................................................................35
4OA2 Identification and Resolution of Problems (71152)....................................37
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153) .......41
4OA5 Other Activities ..........................................................................................42
4OA6 Management Meetings ..............................................................................51
4OA7 Licensee-Identified Violations....................................................................52
KEY POINTS OF CONTACT ........................................................................................................1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ............................................................1
LIST OF DOCUMENTS REVIEWED ............................................................................................3
LIST OF ACRONYMS USED......................................................................................................15
Enclosure
SUMMARY OF FINDINGS
IR 05000454/2008-003; 05000454/2008-003; April 01 2008 - June 30, 2008; Byron Station,
Units 1 and 2; Fire Protection, Inservice Inspection Activities, Maintenance Effectiveness and
Maintenance Risk Assessments and Emergent Work Control.
This report covers a three-month period of inspection by resident inspectors and an announced
baseline inspections by six regional inspectors. Four Green findings were identified by the
inspectors. These findings were considered Non-Cited Violations (NCVs) of Nuclear Regulatory
Commission (NRC) regulations. In addition, one apparent violation with potential safety
significance greater than green was identified. The significance of most findings is indicated by
their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,
Significance Determination Process (SDP). Findings for which the SDP does not apply may
be Green or be assigned a severity level after NRC management review. The NRCs program
for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
A. NRC-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
- Green. The inspectors identified a finding of very low safety significance and associated
NCV of the Byron Unit 1 Operating License (OL), Condition 2.C.(6) for failure to comply
with the spacing standard for sprinkler systems of the Fire Protection Program (FPP).
Specifically, a permanent scaffold obstructed a fire protection suppression sprinkler in
the Unit 1, train A (1A) diesel oil storage rank room and no replacement sprinkler was
installed. The licensee entered the issue into the corrective action program (CAP) and
subsequently removed the scaffold decking.
This finding is more than minor because it was associated with the external factor
attribute of the Initiating Events (IE) cornerstone and affected the cornerstone objective
to limit the likelihood of those events that upset plant stability and challenge critical
safety functions during shutdown as well as power operations. The finding is of very low
safety significance because it has a low degradation rating as only one out of eleven
sprinklers in the room was obstructed and there was another functional head within
10 feet of the combustible concern. This finding has a cross-cutting aspect in the area of
Human Performance for Work Practices (H.4.(b)) because the licensee failed to define
and effectively communicate expectations regarding procedural compliance and
personnel following procedures. (Section 1R05.1.b)
- Green. The inspectors identified a finding of very low safety significance and associated
NCV of Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Section 50.55a,
for the failure to correctly disposition an ultrasonic (UT) examination indication found in
feedwater weld 1FW87CA-6O/C08A as required by American Society of Mechanical
Engineers (ASME) Code,Section XI. This issue was entered into the licensees CAP;
the indication was re-examined and correctly dispositioned.
The inspectors concluded that the finding was more than minor because a failure to
perform the required corrective action could have allowed an unacceptable flaw to
remain in service and so could become a more significant safety concern. The
1 Enclosure
inspectors applied the IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and
Characterization of Findings to this finding. The inspectors concluded that the finding
was of very low safety significance, because the licensee re-performed the UT
examination, and correctly dispositioned the indication in accordance with ASME Code.
Furthermore, the finding did not contribute to both the likelihood of a reactor trip, and the
likelihood that mitigation equipment will not be available. The inspectors determined that
this finding was related to the Decision Making Component (H.1(b)) for the cross-cutting
area of Human Performance. (Section 1R08.1.b)
Cornerstone: Mitigating Systems
- Green. The inspectors identified a finding of very low safety significance and associated
NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
regarding the licensees failure to perform adequate evaluations of the boric acid
leakage from bolted connections in accordance with Procedure ER-AP-331-1002, Boric
Acid Corrosion Control Program Identification, Screening, and Evaluations. This issue
was entered into the licensees CAP. Licensee corrective actions included revising the
procedure and re-performing the evaluation.
As implied by Example 4a of IMC 0612, Power Reactor Inspection Reports,
Appendix E, Examples of Minor Issues, the finding was not minor under the
category of Insignificant Procedural Errors, because the licensee routinely failed to
perform/document engineering evaluations for bolted connections with boric acid leaks.
A failure to adequately perform the required evaluation could result in equipment
susceptible to the corrosive effects of boric acid being returned to service in a degraded
condition and so could become a more significant safety concern.
The inspectors applied the IMC 0609, Attachment 0609.04, to this finding. The
inspectors checked the Reactivity Control Degraded box in the Mitigation System
Cornerstone column of Table 2, and answered no to all of the questions in the
Mitigation System Cornerstone column of Table 4a, to conclude that the finding was of
very low safety significance (Green). Specifically, the finding did not represent a loss of
any safety function. The inspectors determined that this finding was related to the cross-
cutting component of Human Performance for Work Practices (H.4.(b)).
(Section 1R08.3.b)
- Green. A finding of very low safety significance and associated NCV of Technical
Specification (TS) 5.4, Procedures, was self-revealed on May 27, 2008, when the
0B essential service water (SX) system makeup pump failed to start during a planned
monthly surveillance test. The pump failed to start due to a lack of fuel prime. The
licensee determined that on April 29, 2008, the check valve on the fuel oil supply line
between the day tank and the engine had been replaced as part of a routine preventive
maintenance program. The check valve was found in the installed condition with a loose
fitting. The loose fitting had leaked slowly allowing fuel oil to drain from the primed fuel
oil supply line. The issue has been entered into the licensees CAP (IR 779699). The
licensees corrective actions included repairing the check valve and associated
deficiencies, as well as revising the maintenance procedure.
The finding was considered more than minor because there was an actual loss of safety
function of a single train for greater than its TS allowed outage time. The finding was
determined to be of very low safety significance during a Phase 3 SDP. The primary
2 Enclosure
cause of this finding was related to the cross-cutting area of Human Performance for
Work Practices (H.4(c)) because licensee supervisory oversight of work activity failed to
ensure procedural compliance. (Section 1R12.1.b)
- AV. The licensee identified an apparent violation of 10 CFR 50.65, Requirements for
Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, (a)(4) for failure
to perform an updated risk evaluation prior to surveillance testing of the Unit 1 Train A
emergency diesel generator (EDG) based on existing plant conditions. This failure
resulted in an inadvertent entry into an elevated online risk condition for Unit 2. This
issue has potential safety significance greater than very low safety significance for
Unit 2, which may change pending completion of the SDP. This issue was entered into
their corrective action program as IR 759945. The licensee immediately implemented
the compensatory measure of an operator stationed at the valve. They also took
corrective actions to reassemble the valves and place them back in service.
The finding is more than minor in accordance with IMC 0612, Appendix E, Section 7,
Example f, because the elevated overall plant risk when correctly accessed, is greater
than 1.0E-6 Incremental Core Damage Probability (ICDP) and also put the plant into a
higher risk category with additional risk management actions. The cause of this finding
was related to the cross-cutting element of human performance for work control
(H.3.(b)). (Section 1R13.1.b)
B. Licensee-Identified Violations
Three violations of very low safety significance that were identified by the licensee have
been reviewed by inspectors. Corrective actions planned or taken by the licensee have
been entered into the licensees CAP. These violations and corrective action tracking
numbers are listed in Section 4OA7 of this report.
3 Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 was in a refueling outage at the start of this inspection period. Initial criticality following
the refueling outage was on April 14, 2008, and the unit returned to full power on April 22, 2008,
after fuel pre-conditioning. The unit remained at or near full power throughout the rest of the
inspection period with minor exceptions for testing.
Unit 2 operated at or near full power throughout the inspection period with minor exceptions.
On May 8, 2008, power was reduced to 87 percent for turbine valve testing.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Readiness of Offsite and Alternate Alternating Current (AC) Power Systems
a. Inspection Scope
The inspectors verified that plant features and procedures for operation and continued
availability of offsite and alternate AC power systems during adverse weather were
appropriate. The inspectors reviewed the licensees procedures affecting these areas
and the communications protocols between the transmission system operator (TSO) and
the plant to verify that the appropriate information was being exchanged when issues
arose that could impact the offsite power system. Examples of aspects considered in
the inspectors review included:
- The coordination between the TSO and the plant during off-normal or emergency
events;
- The explanations for the events;
- The estimates of when the offsite power system would be returned to a normal
state; and
- The notifications from the TSO to the plant when the offsite power system was
returned to normal.
The inspectors also verified that plant procedures addressed measures to monitor and
maintain availability and reliability of both the offsite AC power system and the onsite
alternate AC power system prior to or during adverse weather conditions. Specifically,
the inspectors verified that the procedures addressed the following:
- The actions to be taken when notified by the TSO that the post-trip voltage of the
offsite power system at the plant would not be acceptable to assure the
continued operation of the safety-related loads without transferring to the onsite
power supply;
- The compensatory actions identified to be performed if it would not be possible to
predict the post-trip voltage at the plant for the current grid conditions;
4 Enclosure
- A re-assessment of plant risk based on maintenance activities that could affect
grid reliability, or the ability of the transmission system to provide offsite power;
and
- The communications between the plant and the TSO when changes at the plant
could impact the transmission system, or when the capability of the transmission
system to provide adequate offsite power was challenged.
Specific documents reviewed during this inspection are listed in the Attachment. The
inspectors also reviewed Corrective Action Program (CAP) items to verify that the
licensee was identifying adverse weather issues at an appropriate threshold and
entering them into their CAP in accordance with station corrective action procedures.
This inspection constitutes one readiness of offsite and alternate AC power systems
sample as defined in Inspection Procedure (IP) 71111.01-05.
b. Findings
No findings of significance were identified.
.2 Summer Seasonal Readiness Preparations
a. Inspection Scope
The inspectors performed a review of the licensees preparations for summer weather
for selected systems, including conditions that could lead to an extended drought as a
result of high temperatures.
During the inspection, the inspectors focused on plant specific design features and the
licensees procedures used to mitigate or respond to adverse weather conditions.
Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)
and performance requirements for systems selected for inspection, and verified that
operator actions were appropriate as specified by plant specific procedures. Specific
documents reviewed during this inspection are listed in the Attachment. The inspectors
also reviewed CAP items to verify that the licensee was identifying adverse weather
issues at an appropriate threshold and entering them into their CAP in accordance with
station corrective action procedures. The inspectors reviews focused specifically on the
following plant systems:
- Essential Service Water (SX) System Ultimate Heat Sink (UHS);
- Auxiliary Building Ventilation System; and
- Auxiliary Transformers
This inspection constitutes one seasonal adverse weather sample as defined in
IP 71111.01-05.
b. Findings
No findings of significance were identified.
5 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:
- Spent Fuel Pool Cooling following Unit 1 Core Off-Load;
- Unit 1 Train A Diesel Generator while Unit 1 Train B Diesel Generator was Out of
Service (OOS);
- Unit 1 Train B Safety Injection while Unit 1 Train A Safety Injection was OOS;
- Unit 2 Train A Residual Heat Removal (RHR) System while Unit 2 Train B RHR
System was OOS; and
The inspectors selected these systems based on their risk significance relative to the
reactor safety cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could impact the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work
orders, condition reports, and the impact of ongoing work activities on redundant trains
of equipment in order to identify conditions that could have rendered the systems
incapable of performing their intended functions. The inspectors also walked down
accessible portions of the systems to verify system components and support equipment
were aligned correctly and operable. The inspectors examined the material condition of
the components and observed operating parameters of equipment to verify that there
were no obvious deficiencies. The inspectors also verified that the licensee had properly
identified and resolved equipment alignment problems that could cause initiating events
or impact the capability of mitigating systems or barriers and entered them into the CAP
with the appropriate significance characterization. Documents reviewed are listed in the
Attachment.
These activities constituted five partial system walkdown samples as defined by
IP 71111.04-05.
b. Findings
No findings of significance were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
On April 9, 2008, through April 10, 2008, the inspectors performed a complete system
alignment inspection of Control Room Ventilation to verify the functional capability of the
system. This system was selected because it was considered safety-significant. The
inspectors walked down the system to review mechanical and electrical equipment line
ups, electrical power availability, system pressure and temperature indications as
appropriate, component labeling, component lubrication, component and equipment
6 Enclosure
cooling, hangers and supports, operability of support systems, and to ensure that
ancillary equipment or debris did not interfere with equipment operation. A review of a
sample of past and outstanding work requests was performed to determine whether any
deficiencies significantly affected the system function. In addition, the inspectors
reviewed the CAP database to ensure that system equipment alignment problems were
being identified and appropriately resolved. The documents used for the walkdown and
issue review are listed in the Attachment.
These activities constituted one complete system walkdown sample as defined by
IP 71111.04-05.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
.1 Routine Resident Inspector Tours (71111.05Q)
a. Inspection Scope
The inspectors conducted fire protection walkdowns that were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
- Unit 1 Diesel Oil Storage Tank Rooms (Zone 10.1-1 & 10.2-1);
- Unit 2 Diesel Oil Storage Tank Rooms (Zone 10.1-2 & 10.2-2);
- Fuel Handling Building (Zone 12.1-0); and
- River Screen House Including SX Makeup Pumps (Zones 18.11-0, 1 and 2).
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 four quarterly fire protection inspection samples as defined
by IP 71111.05-05.
7 Enclosure
b. Findings
(1) Fire Suppression Sprinkler Obstruction in the Diesel Oil Storage Tank Room
Introduction: A finding of very low safety significance and associated non-cited violation
(NCV) of the Byron Unit 1 Operating License (OL) Condition 2.C(6) for the licensees
failure to comply with the spacing standard for sprinkler systems of the Fire Protection
Program (FPP) was identified by the inspectors. Specifically, a permanent scaffold
obstructed a fire protection suppression sprinkler in the 1A diesel oil storage rank room
and no replacement sprinkler was installed.
Description: On April 30, 2008, the inspectors performed a fire protection walkdown of
the 1A diesel oil storage tank room. The inspectors identified that a permanent scaffold
with solid decking material was erected underneath a fire suppression sprinkler and next
to a working platform. This permanent scaffold, in conjunction with the working platform,
created a deck area below the sprinkler that was 8 feet 9 inches in the north-south
direction and 6 feet 5 inches in the east-west direction. Since this area was irregular
shaped, the shortest dimension was 4 feet 4 inches in the southwest diagonal direction.
The combination of the permanent scaffold and the working platform obstructed a major
portion of the spray pattern of one of the foam based fire suppression sprinklers to a
portion of the floor area in the diesel oil storage tank room. No sprinkler was installed to
supplement the one that had been obstructed. The 1A diesel oil storage tank room
houses two diesel oil storage tanks that contain the diesel fuel oil used by the 1A
emergency diesel generator (EDG) and 1A diesel driven auxiliary feedwater (AFW)
pump.
The licensee declared the fire suppression system for the 1A diesel oil storage tank
room inoperable and verified that the automatic fire detection instrumentation was
operable in accordance with the Technical Requirement Manual (TRM). The licensee
subsequently removed the decking of the permanent scaffold.
The inspectors reviewed that the Permanent Scaffold Request B-4855 and determined
that the permanent scaffold had been inspected, evaluated and approved by engineering
personnel in March 2004. However, the procedure in effect at the time of the scaffold
erection, MA-AA-716-025, Scaffold Installation, Modification, and Removal Request
Process, Revision 0, required that engineering review and evaluate the technical impact
of the proposed permanent scaffold and approve post erection inspections as needed.
One of the evaluation criteria specified by the procedure was to determine if the scaffold
would affect the coverage zone of any in-place fire protection sprinkler heads in the
immediate proximity. No specific concern or instruction was noted when the scaffold
request was approved by engineering.
The inspectors determined that the licensee was committed to National Fire Protection
Association (NFPA) Code 13, Standard for the Installation of Sprinkler Systems,
1983 Edition, and NFPA Code 16, Deluge Foam Water Sprinkler and Sprays Systems,
1980 Edition, according to the licensees Fire Protection Report. Per these standards,
sprinklers shall be installed under decks which are over four feet wide to prevent
obstruction for the spray pattern of the sprinkler. Specifically, Section 4-2.1 of NFPA-16
stated that foam-water sprinkler system designs shall conform to all of the applicable
requirements of NFPA-13 except where otherwise specified in NFPA-16. Section 4-4.11
of NFPA-13 specified that sprinklers be installed under decks and galleries which are
8 Enclosure
over four feet wide. As NFPA-16 did not specifically address sprinkler obstructions, the
requirements of NFPA-13 pertaining to obstructions applied.
Analysis: The inspectors determined that the licensees failure to comply with the
spacing standard for sprinkler systems in accordance with the FPP was a performance
deficiency that warranted a IMC 0609, Significance Determination Process (SDP)
evaluation. The inspector concluded that the finding was greater than minor in
accordance with IMC 0612, Appendix B, Issue Disposition Screening. Specifically, it
was associated with the external factor attribute of the Initiating Events cornerstone and
affected the cornerstone objective to limit the likelihood of those events that upset plant
stability and challenge critical safety functions during shutdown as well as power
operations.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Appendix F, Fire Protection Significance Determination
Process, because it was associated with fire protection defense-in-depth strategies
involving suppression system. The inspectors determined that the finding has a low
degradation rating since only one out of eleven sprinklers in the room was obstructed
and there was another functional head within ten feet of the combustible concern. In
addition, other aspects of the system complied with NFPA code. Therefore the finding
was determined to be of very low safety significance (Green).
This finding has a cross-cutting aspect in the area of Human Performance for Work
Practices (H.4.(b)) because the licensee failed to define and effectively communicate
expectations regarding procedural compliance and personnel following procedures.
Enforcement: Byron Unit 1 OL, Condition 2.C.(6) states, in part, that the licensee shall
implement and maintain in effect all provisions of the approved FPP as described in the
licensees Fire Protection Report. The Fire Protection Report stated that the licensees
sprinkler system conformed to NFPA Code 13, 1983, edition, and no deviation applied to
this fire area. Per the NFPA standard, sprinklers shall be installed under decks that are
over four feet wide. Contrary to the above, a permanent scaffold was erected in
conjunction with an existing platform structure, creating a deck area that was 4 feet 4
inches in the diagonal direction. This permanent scaffold, in conjunction with the
working platform, obstructed a fire suppression sprinkler and no sprinkler was installed
to supplement the obstructed one. Because this violation was of very low safety
significance and because it was entered into the licensees CAP as Issue Report (IR)
770364, this violation is being treated as a NCV, consistent with Section VI.A.1 of the
NRC enforcement policy. (NCV 05000454/2008003-01)
1R06 Flooding (71111.06)
a. Inspection Scope
The inspectors reviewed selected risk important plant design features and licensee
procedures intended to protect the plant and its safety-related equipment from internal
flooding events. The inspectors reviewed flood analyses and design documents,
including the UFSAR, engineering calculations, and abnormal operating procedures, for
licensee commitments. The specific documents reviewed are listed in the Attachment.
9 Enclosure
In addition, the inspectors reviewed licensee drawings to identify areas and equipment
that may be affected by internal flooding caused by the failure or misalignment of nearby
sources of water, such as the fire suppression or the circulating water systems. The
inspectors also reviewed the licensees CAP documents with respect to past
flood-related items identified in the CAP to verify the adequacy of the corrective actions.
The inspectors performed a walkdown of the following plant area to assess the
adequacy of watertight doors and to verify drains and sumps were clear of debris and
operable and that the licensee complied with its commitments:
- Turbine Building Basement.
These inspection activities constitute one internal flooding sample as defined in
IP 71111.06-05.
a. Findings
No findings of significance were identified.
1R08 Inservice Inspection (ISI) Activities (71111.08P)
From March 24, 2008, through April 3, 2008, the inspectors conducted a review of the
implementation of the licensees ISI Program for monitoring degradation of the reactor
coolant system, steam generator tubes, emergency feedwater systems, risk significant
piping, and components and containment systems.
The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, 1R08.4, and 1R08.5
below count as one inspection sample as defined by IP 71111.08-05.
.1 Piping Systems ISI
a. Inspection Scope
The inspectors reviewed records of the following nondestructive (NDE) examinations
mandated 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 Testing (UT) examination of Steam Generator (SG) 1RC-01-BB, N-3-
NIR inner radius; and
- Liquid penetrant examination of 1SI03DA-2, W-09.
The inspectors reviewed the following examinations completed during the previous
outage with relevant/recordable conditions/indications accepted for continued service to
determine if acceptance was in accordance with the ASME Code Section XI or an NRC
approved alternative.
RHEC-013; and
10 Enclosure
Review of pressure boundary welding was completed during performance of Temporary
Instruction (TI)-172 as documented in Section 4OA5, and this review is credited for
meeting this inspection procedure attribute.
b. Findings
(1) Failure to Correctly Evaluate and Disposition a Weld Indication
Introduction: The inspectors identified a Green NCV of 10 CFR Part 50.55a,
for failure of the licensee to correctly disposition a flaw found in feedwater weld
1FW87CA-6O/C08A as required by ASME Code Section XI discovered while
performing a Performance Demonstration Initiative (PDI) UT examination.
Description: During a records review of the UT examination performed on
September 15, 2006, of feedwater weld 1FW87CA-6O/C08A as directed by IP 71111.08
Section 02.01(e), the inspectors observed that the licensee had failed to correctly
evaluate and disposition a weld indication in accordance with ASME Code after it was
identified during a PDI UT examination.
While performing a PDI UT examination of a weld of a 6O, 0.432O nominal thickness,
ferritic feedwater pipe, using 45 degree and 60 degree shear waves, the examiners
identified a mid-wall indication, with an L max dimension of 2.0O. The indication
occurred outside of the minimum required exam volume and reportedly did not have an
inside diameter connection. A sketch included with the licensees report shows the
indication to be near the fusion zone of the weld, and the indication was detected with
the 60 degree search unit. While the examiners reported the indication as a recordable
indication, the reviewer indicated that no further evaluation of the flaw was required. The
decision to forgo further evaluation was supported by both the licensees UT Level III
and the Authorized Nuclear Inservice Inspector. In response to the inspectors question
as to why there was no further evaluation performed, the licensee stated that it was
because the indication was not located in the minimum required weld volume they had
interrogated, nor was there any guidance in the procedure for addressing indications
outside of the volume they intended to examine. However, the inspectors determined
that ASME evaluation requirements are not limited to just indications that are found in
the minimum weld volume.
Analysis: The inspectors determined that the failure of the licensee to perform
ASME Code required corrective actions for an indication found during PDI UT
examination of a feedwater weld, was a performance deficiency that warranted a SDP
evaluation. The inspectors compared this issue to the issues identified in Appendix E of
IMC 0612 to determine whether the issue was minor, and concluded that none of the
examples listed in Appendix E, accurately represented this example. As a result, the
inspector compared this issue to the minor questions contained in Section 3, Minor
Questions, to IMC 0612, Appendix B, Issue Screening. The inspectors concluded that
the finding was more than minor because a failure to perform the required corrective
action could have allowed an unacceptable flaw to remain in service and so could
become a more significant safety concern.
The inspectors applied the IMC 0609, Attachment IMC 0609.04, to this finding. The
inspectors checked the Primary System LOCA Initiator Contributor box in the Initiating
Events Cornerstone column of Table 2, and answered no to the question in the LOCA
11 Enclosure
Initiator Cornerstone column of Table 4a, to conclude that the finding was of very low
safety significance (Green).
Specifically, the licensee re-performed the UT examination and correctly dispositioned
the indication in accordance with ASME Code. Furthermore, the finding did not
contribute to both the likelihood of a reactor trip, and the likelihood that mitigation
equipment will not be available.
The inspectors determined that this finding was related to the Decision Making
Component (H.1(b)) aspect for the cross-cutting area of Human Performance, because
the licensee failed to make conservative assumptions in decisions affecting the integrity
of the feedwater piping. Specifically, the licensees presumption of weld integrity was
not based on sufficient information to be able to demonstrate that the action/decision to
leave the feedwater piping with an unevaluated piping weld indication in service was
safe.
Enforcement: Between March 24, 2008, and April 3, 2008, while performing baseline
IP 71111.08, the inspectors identified a NCV of 10 CFR 50.55(a)(g)(4), in that the
licensee failed to correctly disposition an indication found in feedwater weld
1FW87CA-6O/C08A, as required by ASME Code Section XI, discovered while
performing a PDI UT examination.
Title 10 CFR 50.55(a)(g)(4), required, in part, that pressurized water-cooled nuclear
power facility components classified as ASME Class 1, Class 2, and Class 3 meet the
requirements set forth in ASME Code Section XI. ASME Code,Section XI,
IWB-3131(c), required in part, that acceptance of components for continued service shall
be in accordance with Tables IWB-3132, IWB-3133, and IWB - 3134. IWB-3132.1,
stated in part, that a component that does not meet the acceptance standards of
Table IWB-3410-1 shall be corrected in accordance with the provisions of IWB-3132.2
(Acceptance by Repair/Replacement) or IWB-3132.3 (Acceptance by Analytical
Evaluation).
Contrary to the above, on September 15, 2006, during B1R14, after identifying a UT
indication in feedwater weld 1FW87CA-6O/C08A, which did not meet the acceptance
standards of Table IWB-3410-1 (identified in report number B1R14-UT-027), the
licensee failed to disposition by repair, replacement, or acceptance by evaluation as
required by the ASME Code prior to returning Unit 1 to service.
Because of the very low safety significance of this finding and because the issue was
entered into the licensees CAP (IR 756048), it is being treated as a NCV, consistent
with Section VI.A.1, of the NRC Enforcement Policy (NCV 05000454/2008003-02).
.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities
a. Inspection Scope
The inspectors reviewed a video recording of the visual examinations conducted on the
Unit 1 reactor vessel head to determine if the activities were performed in accordance
with the requirements of NRC Order EA-03-009, 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. The inspectors also reviewed the vessel
12 Enclosure
head visual examination procedure to determine if criteria existed for visual examination
quality and if instructions existed for resolving interference or masking issues.
The licensee did not perform any weld repairs to vessel head penetrations since the
beginning of the preceding outage for Unit 1. Therefore, no NRC review was completed
for this IP attribute.
b. Findings
No findings of significance were identified.
.3 Boric Acid Corrosion Control (BACC)
a. Inspection Scope
The inspectors observed the licensee BACC visual examinations for portions of the
Reactor Coolant System (RCS) to determine if these visual examinations emphasized
locations where boric acid leaks can cause degradation of safety significant
components.
The inspectors reviewed the following engineering evaluations of reactor coolant system
components with boric acid deposits to determine if degraded components were properly
documented in the CAP. The inspectors also evaluated corrective actions for any
degraded RCS components to determine if they met the ASME Code,Section XI, or
NRC approved alternative.
- IR 650150; 1CV066A Pipe Cap Leak (Boric Acid)-Valve Leak By Issue;
- IR 563581; 1CV8524B Body to Bonnet Leakage; and
- IR 641851; 1SI8812B Inactive Body-to Bonnet Leak.
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 640441; Damp Boric Acid Present on 1AB03T Tank FLGD Tap; and
- IR 616011; 2RH8702A Active Body to Bonnet Leak.
b. Findings
(1) Failure to Perform Evaluation of a Leaking Bolted Connection
Introduction: The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,
Criterion V, regarding the licensees failure to perform adequate evaluations of the boric
acid leakage from bolted connections in accordance with the procedure
ER-AP-331-1002, Boric Acid Corrosion Control Program Identification, Screening, and
Evaluations. Specifically, in the evaluations of the boric acid leaks documented in
IR 641851 and IR 563581, the licensee did not adequately address all applicable
considerations per ER-AP-331-1002, Attachment 3, Evaluation of Leakage from Bolted
Connection, Section 7.
13 Enclosure
Description: ASME Code,Section XI (2001, through 2003 Addenda), IWA-5250(a)(2),
requires removal and VT-3 examination of the bolts as corrective action, when a leak
occurs at a bolted connection in a borated system. Code Case N-566-2, Corrective
Action for Leakage Identified at Bolted Connections, provides for evaluation as an
alternative to removal of the bolts. The Code Case was approved by the NRC on
March 28, 2001, and is included in the Licensees ISI Program Plan. The Code Case
specifies the parameters to be included in the evaluation. The licensee has incorporated
these parameters in Attachment 3, of the Procedure ERAP331-1002.
During inspections performed between March 24, 2008, and April 3, 2008, the
inspectors identified that the licensee had failed to adequately document evaluations
of bolted connections with evidence of boric acid leakage. Specifically, in the
evaluations for body-to-bonnet leaks for Valve 1SI8812B documented in IR 563581
on November 30, 2006, and Valve 1CV8524B documented in IR 563581 on
February 1, 2007, the licensee concluded that it was not necessary to remove the bolts
for further examination without adequately addressing in the evaluation all the
parameters specified in Code Case N-566-2. The licensee used Attachment 3, of
Procedure ER-AP-331-1002, to document the evaluation. Section 7 of the Attachment
lists all the parameters included in the Code Case and required their consideration in the
evaluation. The inspectors however, were not able to verify through review of licensees
documentation that all the parameters were considered in the evaluation, which based
its conclusion of acceptability on the material being stainless steel, not susceptible to
boric acid corrosion. The inspectors found similar instances in other boric acid
evaluations including some where the affected bolt material was carbon steel and
therefore concluded that adequate evaluations were not being performed prior to
documenting the conclusions. After identification by the inspector, the licensee
documented the issue in their CAP as IR 755998, Inadequate Boric Acid Evaluations of
Mechanical Joints, dated March 3, 2008. The licensees corrective actions involved
revising the procedure and then re-performing the evaluations.
Analysis: The inspectors determined that the failure of the licensee to perform adequate
evaluation of bolted connections with evidence of leakage as required by the Code
Case N-566-2 and their procedure was a performance deficiency that warranted a
significance evaluation. The inspectors believed that for the evaluations reviewed,
based on the amount of leakage and degradation documented, the conclusion of the
evaluation would not have changed had an adequate evaluation been performed.
However, as implied by Example 4a of IMC 0612, Appendix E, the finding was not minor
under the category of Insignificant Procedural Errors, because the licensee routinely
failed to perform/document engineering evaluations for bolted connections with boric
acid leaks. The finding was also more than minor because a failure to adequately
perform the required evaluation could result in equipment susceptible to the corrosive
effects of boric acid being returned to service in a degraded condition and thus become
a more significant safety concern.
The inspectors applied the IMC 0609, Attachment 0609.04, to this finding. The
inspectors checked the Reactivity Control Degraded box in the Mitigation System
Cornerstone column of Table 2, and answered no to all of the questions in the
Mitigation System Cornerstone column of Table 4a, to conclude that the finding was of
very low safety significance (Green). Specifically, the finding did not represent a loss of
any safety function.
14 Enclosure
This finding was related to the cross-cutting component of Human Performance for Work
Practices (H.4.(b)) in that, the licensee failed to define and effectively communicate
expectations regarding procedural compliance. Specifically, the licensee repeatedly
failed to adequately perform/document the evaluations required per Attachment 3,
Section 7 of the ER-AP-331-1002, Revision 3.
Enforcement: During inspections performed between March 24, 2008, and April 3, 2008,
the inspectors identified a NCV of 10 CFR Part 50, Appendix B, Criterion V, in that the
licensee failed to perform engineering evaluations on bolted connections with evidence
of leakage in accordance with their procedure.
Title 10 CFR Part 50, Appendix B, Criterion V, requires in part, that activities affecting
quality shall be prescribed by documented instructions, procedures, or drawings of a
type appropriate to the circumstances, and shall be accomplished in accordance with
these instructions, procedures, or drawings.
License Procedure ER-AP-331-1002, Revision 3, Attachment 3, Section 7 lists the
parameters/attributes that must be considered in the evaluation.
Contrary to the above, on August 20, 2007, for Valve 1SI8812B, and on
January 31, 2007, for Valve 1CV8524B, the licensee failed to perform adequate
evaluations in accordance with Procedure ER-AP-331-1002, Revision 3. Specifically, in
the evaluations for leakage from bolted connections discovered per IR 641851 and
IR 563581, the licensee staff failed to perform/document evaluations considering all the
parameters/attributes specified in the Attachment 3, Section 7 of ER-AP-331-1002.
Because of the very low safety significance of this finding and because the issue was
entered into the licensees CAP (IR 755998), it is being treated as a NCV, consistent
with Section VI.A.1 of the Enforcement Policy (NCV 05000454/2008003-03).
.4 SG Tube Inspection Activities
a. Inspection Scope
The inspectors observed acquisition of eddy current (ET) data, interviewed ET resolution
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-107620,
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 numbers and sizes of SG tube flaws/degradation identified was bound by the
licensees previous outage Operational Assessment predictions;
the Technical Specifications, 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;
15 Enclosure
- 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;
the ET probes and equipment configurations used to acquire data from the SG
tubes were qualified to detect the known/expected types of SG tube degradation
in accordance with Appendix H, Performance Demonstration for Eddy Current
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
- inaccessible foreign objects were left within the secondary side of the SGs, and if
so, that the licensee implemented evaluations which included the effects of
foreign object migration and/or tube fretting damage.
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 Part 50,
Appendix B, Criterion XVI, Corrective Action, requirements. The CAP documents
reviewed by the inspectors are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
16 Enclosure
1R11 Licensed Operator Requalification Program (71111.11)
.1 Resident Inspector Quarterly Review (71111.11Q)
a. Inspection Scope
On June 3, 2008, the inspectors observed a crew of licensed operators in the plant
simulator during licensed operator requalification examinations to verify that operator
performance was adequate, evaluators were identifying and documenting crew
performance problems and training was being conducted in accordance with licensee
procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications.
The crews performance in these areas was compared to pre-established operator action
expectations and successful critical task completion requirements.
This inspection constitutes one quarterly licensed operator requalification program
sample as defined in IP 71111.11.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
.1 Routine Quarterly Evaluations (71111.12Q)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant systems:
- Station Auxiliary Transformer 242-2 Differential Overcurrent Trip; and
- Essential Service Water Makeup Pump 0B Failure to Start on Demand.
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;
17 Enclosure
- scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring;
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
- verifying appropriate performance criteria for structures, systems, and
components (SSCs)/functions classified as (a)(2) or appropriate and adequate
goals and corrective actions for systems classified as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the corrective action program with the appropriate
significance characterization. Documents reviewed are listed in the Attachment.
This inspection constitutes two quarterly maintenance effectiveness samples as defined
in IP 71111.12-05.
b. Findings
(1) Essential Service Water Makeup Pump 0B Failure to Start on Demand
Introduction: A finding of very low safety significance and an NCV of TS 5.4 was
self-revealed on May 27, 2008, when the 0B SX Makeup pump failed to start during a
planned monthly surveillance test. The pump failed to start due to a lack of fuel prime.
Description: On May 27, 2008, a routine monthly surveillance was initiated on the 0B SX
Makeup pump. The pump failed to start and troubleshooting was initiated. The diesel
portion of the pump was determined to have lost fuel oil prime in the fuel line from the
day tank to the engine. In addition, a loose fitting allowed air to be drawn into the line
resulting in an inability to prime the line.
The licensee determined that on April 29, 2008, the check valve on the fuel oil supply
line between the day tank and the engine had been replaced as part of a routine
preventive maintenance program. The check valve was found in the installed condition
with a loose fitting. The loose fitting had leaked slowly allowing fuel oil to drain from the
primed fuel oil supply line. This leak had also allowed air to enter the line when the
engine driven fuel pump operated during the start attempt. The fuel oil line has a sight
glass that allows operators, during their daily rounds, to check to ensure the line has
remained full of fuel. The licensee determined that following the maintenance in April
that the sight glass had been left with a slight down slope. This allowed fuel to remain in
the sight glass even though the fuel oil line it was attached to had drained. This slope
was not significant enough to be noticed by the operators.
Work Order (WO) 912183, Replace Parker check valve at SX Makeup pump fuel oil
line, was utilized by the workers when replacing the check valve. Document 1 of the
work package instructions required, Install new check valve using approved thread
sealant and tighten fittings in accordance with Parker Tightening Instructions. The
licensee determined that the fitting was loose when installed and did not become fully
tightened during assembly.
18 Enclosure
Technical Specification 3.7.9, Ultimate Heat Sink, Condition C, required that with both
units in Mode 1, 2, 3, or 4, that one inoperable SX makeup pump be restored to operable
within seven days and if not to perform a unit shutdown. The pump maintenance was
performed April 29, 2008, and while a precise leak rate could not be calculated as the
check valve as found condition was disturbed when it was replaced it was estimated to
be a small fraction of the 26 days between the maintenance activity and the discovery of
the failed pump. The estimation was performed by the inspectors after discussions with
licensee personnel, inspection of the check valve, inspection of the total volume of the
engine fuel oil system, and estimation of the relative size of the fuel oil leak given that an
in-leakage of air sufficient to prevent priming of the line was occurring.
Analysis: The inspectors determined that the licensees failure to adequately follow the
work instructions was a performance deficiency warranting a significance evaluation.
The inspectors concluded that the finding was greater than minor in accordance with
Appendix B of IMC 0612, because there was an actual loss of safety function of a single
train for greater than its TS allowed outage time.
The inspectors performed a SDP of this issue using IMC 0609, Attachment
IMC 0609.04. The inspectors determined the finding fell under the Mitigating Systems
Cornerstone and that the finding did not represent a design or qualification deficiency,
did not represent a loss of a safety system function, but did represent an actual loss of
safety function of a single train for greater than its TS allowed outage time. The
inspectors then performed a Phase 2 SDP using the risk informed inspection notebook.
The Phase 2 SDP result was greater than green assuming that the unavailability of the
0B SX make-up pump increases the likelihood of a loss of essential service water event
for an exposure period of between 3 and 30 days.
However, the Senior Reactor Analyst (SRA) determined that this result was overly
conservative because the unavailability of the 0B SX make-up pump would not increase
the likelihood of a loss of essential service water pump by an order of magnitude. A
Phase 3 SDP evaluation was completed using the Simplified Plant Analysis Risk Model
(SPAR) for Byron, Revision 3.31. The 0B SX make-up pump was assumed to be
unavailable and not recoverable for a bounding period of 30 days. The change in core
damage frequency was calculated to be 1E-7/yr, which represented a finding of very low
safety significance (Green). The dominant core damage sequence was a dual unit loss
of offsite power, failure of all SX makeup which in turn fails the DGs and results in a
station blackout. Recovery of offsite or onsite AC power fails resulting in core damage.
Therefore, the inspectors determined that the finding was of very low safety significance.
The primary cause of this finding was related to the cross-cutting area of Human
Performance for Work Practices (H.4.(c)) because licensee supervisory oversight of
work activity failed to ensure procedural compliance.
Enforcement: Technical Specification 5.4 required the implementation of the applicable
procedures recommended in Regulatory Guide 1.33, Quality Assurance Program
Requirements, Revision 2, dated February 1978. Regulatory Guide 1.33, Appendix A,
recommended procedures for the system. Maintenance Procedure MA-AA-716-011,
Work Execution and Close Out, Revision 11 was written in accordance with Section 9,
Performing Maintenance. Step 4.8.1.1.B required Perform work activities and
equipment checks in accordance with approved procedures or work instructions.
Contrary to this requirement, a work instruction contained within WO 912183 was not
followed in that fittings were not tightened resulting in an inoperable SX makeup pump.
19 Enclosure
However, because of the very low safety significance of the issue and because the issue
has been entered into the licensees CAP (IR 779699); the issue is being treated as an
NCV, consistent with Section VI.A.1, of the NRC Enforcement Policy. The licensees
corrective actions included repairing the check valve and associated deficiencies, as well
as revising the maintenance procedure. (NCV 05000454/2008003-04;
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:
- Emergent Shutdown Safety Change due to Extended Work on Unit 1 Train A
Charging Pump;
- Inadvertent Orange Risk Entry due to Both Unit 1 SX Unit Cross-tie Isolation
Valves Unavailable for Remote Operation; and
- Bus 22 Battery Charger while Unit 2 System Auxiliary Transformer (SAT) and
Unit 2 Train C Power Operated Relief Valves (PORVs) were OOS.
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.
These activities constituted four samples as defined by IP 71111.13-05.
b. Findings
(1) Failure to Perform an Updated Risk Evaluation Prior to Surveillance Testing of the Unit 1
Train A Diesel Generator Based on Existing Plant Conditions.
Introduction: The licensee identified an apparent violation of 10 CFR 50.65(a)(4) for the
licensees failure to perform an updated risk evaluation prior to surveillance testing of the
Unit 1 Train A EDG based on existing plant conditions.
Description: On March 31, 2008, Unit 1 was in a refueling outage with the head
removed, cavity flooded up and defueled. The spent fuel pool was at normal level and
decay heat was being removed via the component cooling exchanger to the SX system.
20 Enclosure
Unit 2 was at 100 percent power and normal operation. Online risk for Unit 2 was
evaluated as Yellow assuming all planned maintenance for the week occurred at the
same time. Shutdown risk for Unit 1 was Green.
The Unit 1 SX train cross-tie isolation valve (1SX034) was scheduled for replacement
during the week of March 31, 2008. As part of the maintenance isolation and
replacement activities, both Unit 1 SX train cross-tie isolation valves (1SX033 and
1SX034) were closed and electrically isolated. The licensees risk assessment
considered both Unit 1 train cross-tie valves closed. The valves are normally open but
need to be able to close to mitigate flooding in auxiliary building due to an SX system
pipe break.
The licensee began disassembling the electrical connection of the valve actuator for
1SX034 on March 31, 2008. Due to isolation issues, the scheduled replacement of
1SX034 was aborted but the electrical connection was not restored immediately. In
addition, 1SX033 was observed to have an actuator problem so maintenance activities
for 1SX033 commenced on April 2, 2008. Valve 1SX034 was utilized as an isolation
point for the maintenance on 1SX033. A new risk assessment was performed and
considered both valves unable to open. Online risk for Unit 2 was evaluated as Yellow
and shutdown risk for Unit 1 was evaluated as Green. Appropriate risk management
actions were carried out for this condition.
At 12:31 on April 3, 2008, Unit 1 entered Mode 6 when the first fuel assembly was
moved back into the reactor vessel. Time to boil was calculated to be 14.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> at the
time and shutdown risk for Unit 1 was Yellow for reactivity due to fuel moves.
At 03:04 on April 5, 2008, both the 1SX033 and 1SX034 valves were fully opened to
support Unit 1 Train A diesel generator testing. Remote manipulation capability of the
two valves remained unavailable in the main control room since the electrical isolations
remained in place. The open position is the normal operating position of both the
1SX033 and 1SX034 valves. This alignment cross-ties the SX pump supply to the A and
B headers for Unit 1 and is needed for diesel generator testing. This open valve
configuration was not evaluated for Unit 1 shutdown risk, nor was it evaluated for Unit 2
online risk. At the time, time to boil for Unit 1 was calculated to be 16.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
At 08:05 on April 6, 2008, core reload was completed and shutdown risk for Unit 1
returned to Green. At 13:00 on April 6, 2008, the upper internals were installed which
reduced time to boil to 7.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />.
At about mid-morning on April 6, 2008, while developing the risk evaluation for the week
of April 7, 2008, the work control cycle manager was informed by the cycle manager
from the previous week that the work for the two SX cross-tie valves was carrying over
to the week of April 7, 2008. The cycle manager identified the bounding cases for these
valves as 1SX033/34 unable to open if closed and 1SX033/34 unable to close if open.
These bounding cases were discussed with the site risk engineer and the engineer
performed a risk evaluation under those assumptions. The risk engineer determined
that with both valves opened and unable to be closed from the main control room, the
online risk profile for Unit 2 would be Orange. The shift manager was then contacted to
confirm the configuration of the valves and the cycle manager discovered that both
1SX033 and 1SX034 were electrically de-energized and in the open position.
21 Enclosure
At 16:52 on April 6, 2008, the licensee declared the Unit 2 online risk to be Orange due
to the inability to close 1SX033 and 1SX034 from the main control room to prevent
flooding. Unit 1 shutdown risk remained unchanged. At 17:12 on April 6, 2008, an
operator was stationed locally at 1SX033 to close the valve if necessary. The Unit 2
online risk was then returned to green. The total time the plant was in Orange risk
condition was 38 hours4.398148e-4 days <br />0.0106 hours <br />6.283069e-5 weeks <br />1.4459e-5 months <br /> and 8 minutes. Time to boil for Unit 1 remained at 7.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> at
that time. The licensee immediately implemented the compensatory measure of an
operator stationed at the valve. They also took corrective actions to reassemble the
valves and place them back in service.
Analysis: The inspectors determined that the licensee failed to update a prior risk
assessment due to changing plant conditions. Specifically, the licensee did not perform
an updated risk evaluation prior to surveillance testing of the Unit 1 Train A EDG based
on existing plant conditions with the 1SX033 and 1SX034 valves opened and unable to
close from the main control room. This plant configuration degraded auxiliary building
flooding mitigation capability during diesel generator testing. The inspectors determined
this to be a performance deficiency warranting a significance evaluation.
The inspectors determined that the licensee failed to consider risk significant SSCs that
were unavailable during maintenance and the issue was within the licensees ability to
foresee and correct and the condition could have been prevented.
The inspectors determined the performance deficiency was more than minor in
accordance with IMC 0612, Appendix E, Section 7, Example f, because the elevated
overall plant risk when correctly assessed was greater than 1.0E-6 Incremental Core
Damage Probability (ICDP) and also put the plant into a higher risk category with
additional risk management actions. This finding had the potential to become a more
significant event if the two isolation valves were required to mitigate flooding in the
auxiliary building.
IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management
Significance Determination Process, was used to determine the significance of the
finding for Unit 2, which was at power during the exposure period. The inspectors
requested that the licensee re-perform the 10 CFR 50.65(a)(4) assessment for the
exposure period of the finding assuming that both 1SX033 and 1SX034 valves were
unable to close. For Unit 2, which was operating at full power at the time, the
Incremental Core Damage Frequency (ICDF) was calculated to be 7.56E-4/yr. Given
that the condition existed for 38 hours4.398148e-4 days <br />0.0106 hours <br />6.283069e-5 weeks <br />1.4459e-5 months <br />, the ICDP was 3.3E-6.
Since the licensee failed to conduct an adequate risk evaluation for the maintenance
activities, the ICDP is equal to the Incremental Core Damage Probability Deficit
(ICDPD). No risk management actions (RMAs) were specified or taken because no risk
evaluation of the actual configuration was performed. Using flowchart 1 of IMC 0609
Appendix K, a finding with an ICDPD of 3.3E-6 with no RMAs is assessed as a White
finding (low to moderate safety significance).
The dominant sequence for this configuration is an Unit 1 pipe break in the auxiliary
building that is not isolated due to the unavailability of the 1SX033 and 1SX034 valves.
The failure of the 1SX033 and 1SX034 valves to close is assumed to result in the failure
to isolate the flood. As auxiliary building flooding continues, the SX pumps for both units
22 Enclosure
will be rendered inoperable resulting in a loss of all SX. Eventually an reactor coolant
pump (RCP) seal LOCA will occur with no inventory makeup capability.
The finding also affected the risk for Unit 1. Since the unit was in a refueling outage, all
maintenance risk assessments are qualitative; therefore the IMC 0609 Appendix K
approach cannot be applied. The risk impact to Unit 1 was considered to be lower than
for Unit 2 because the unit had been shutdown since March 23, 2008, decay heat load
was low, and the time to boil was long. Using these qualitative risk insights, the finding
is assessed to be of very low safety significance (Green) for Unit 1.
The licensee subsequently performed a risk evaluation of the condition that considered
1SX034 available through recovery efforts. In this evaluation, the licensee assumed that
once flooding isolation was needed the valve would be returned to service, the breaker
closed, and the valve operated as necessary from the control room with a slightly
increased human error probability. The inspectors determined that the assumption that
1SX034 was recoverable was incorrect because the valve was electrically isolated and
could not be operated from the control room. More specifically, workers would have to
re-connect wiring and perform other maintenance actions to return the valve to service,
which would not have been feasible in a potentially flooded environment.
The licensee performed another risk evaluation that credited an alternate strategy for
isolating leakage from an SX pipe break in the auxiliary building. The conclusion of this
evaluation was that the risk of the unavailability of the 1SX033 and 1SX034 valves was
of very low safety significance (Green). The inspectors and the SRA reviewed the
alternate strategy and determined that it was not appropriate to credit this strategy for
the reasons described in the following paragraphs.
The alternate strategy for isolating flooding is significantly different from the success
strategy credited in the licensees Probability Risk Analysis (PRA). The PRA credits
detection and isolation of the affected train by closing several motor-operated valves and
shutting down the pump in the train. The strategy is directed by the use of an Abnormal
Operating Procedure, 0BOA PRI-8, Auxiliary Building Flooding. Most of the actions are
performed from the control room. The alternate strategy relies on local visual
identification of the pipe break and local manual actions to close valves to isolate the
flood. Operators would be required to identify the specific section of pipe that failed, use
drawings and other reference information to determine which valves to close, and would
have to locally close valves in the auxiliary building. In some cases, the valves are
normally locked open and operators would be required to obtain a key and unlock the
valve before manually closing it. Since flooding would be in progress in the auxiliary
building, access to equipment is not assured and local actions cannot be considered to
be appropriately reliable to credit for mitigation.
The procedure guidance to implement the alternate strategy was weak. The alternate
strategy requires the use of reference Procedure BOP SX-22, Essential Service Water
Leak Isolation to specify which valves need to be closed based on the line segment of
piping that is determined to be failed. It is not clear how operators would transition from
abnormal operating Procedure 0BOA PRI-8 to reference Procedure BOP SX-22 based
on the inability to close the train Cross-tie Isolation Valves 1SX033 and 1SX034.
Abnormal Operating Procedure 0BOA PRI-8 does not have any actions in the Response
Not Obtained column for the failure of 1SX033 and 1SX034. Although Abnormal
Operating Procedure 0BOA PRI-8 references BOP SX-22, it is only in the system
23 Enclosure
restoration section of the procedure, not in the leak isolation procedure section. It
appears that reference Procedure BOP SX-22 was intended to provide guidance on
specific valves to close to isolate a section of SX piping for repair and not intended to be
required to stop internal flooding.
These procedures were recently implemented, and based on interviews there was
limited operator familiarity. A short training session, focusing on a single flood scenario
as an example, had been given to only three of five crews at the time this condition
existed.
In summary, due to the complex nature of the actions required to isolate flooding if
1SX033 and 1SX034 could not be closed, the lack of adequate procedure guidance, and
limited training and familiarity with leak isolation strategies, the NRC determined that the
likelihood of success was low and the alternate strategy should not be credited to
mitigate the risk from internal flooding if 1SX033 and 1SX034 are unavailable.
The primary cause of this issue is related to the cross-cutting area of Human
Performance for Work Control (H.3.(b)), because the licensee did not appropriately
coordinate work activities by incorporating actions to address the impact of 1SX033 and
1SX034 not able to be closed from control room during diesel generator testing and the
need for work groups to communicate coordinate and cooperate with each others.
Enforcement: 10 CFR 50.65(a)(4) requires in part, that the licensee shall assess and
manage the increase in risk that may result from the proposed maintenance activities
before performing maintenance. Contrary to the above, from April 5, 2008, to
April 6, 2008, the licensee failed to consider risk significant components that were
unavailable in their risk evaluation before performing maintenance. Specifically,
between 03:04 on April 5, 2008, and 17:12 on April 6, 2008, the licensee was at an
unrecognized Orange risk condition for Byron Unit 2 when the licensee conducted the
1A EDG testing with both Unit 1 essential service water train Cross-tie Isolation Valves,
1SX033 and 1SX034, left opened and unable to be closed in the main control room. For
Unit 2, this is an apparent violation of 10 CFR 50.65(a)(4) pending the completion of the
final significance determination. (AV 05000455/2008003-05)
Since the licensee restored the remote operation capability of one of the two isolation
valves after its discovery, the finding does not represent an immediate or current safety
concern. This issue was entered into their corrective action program as IR 759945.
For Unit 1, because of the very low safety significance of the issue and because the
issue has been entered into the licensees CAP, the issue is being treated as a NCV
consistent with Section VI.A.1 of the NRC Enforcement Policy. Since this violation was
licensee identified, the enforcement aspect is described in Section 4OA7 of this report.
1R15 Operability Evaluations (71111.15)
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
24 Enclosure
- Unit 2 Train A Diesel Generator Air Leak;
- Foreign Materials Left in Unit 1 Containment;
- Unit 1 Train B AFW Pump Fire Past Operability;
- RHR Air Operated Valve Positioner Arm Failure; and
- Unventable Gas Voids in Containment Recirculation Sump Piping.
The inspectors selected these potential operability issues based on the risk-significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the TS and UFSAR to the licensees evaluations, to determine
whether the components or systems were operable. Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled. The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations. Additionally, the inspectors also reviewed a sampling of corrective action
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations. Documents reviewed are listed in the
Attachment.
This inspection constitutes five samples as defined in IP 71111.15-05.
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:
- Unit 1 Train B AFW Pump Fire Related Repair;
- Auxiliary Building Ventilation 0E Charcoal Booster Fan Damper Work Window;
- Unit 0 Component Cooling Pump Work Window; and
- Unit 1 Train B Centrifugal Charging Pump Emergent Shaft Collar Repair.
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
25 Enclosure
TS, the UFSAR, 10 CFR 50 requirements, licensee procedures, and various NRC
generic communications to ensure that the test results adequately ensured that the
equipment met the licensing basis and design requirements. In addition, the inspectors
reviewed corrective action documents associated with post-maintenance tests to
determine whether the licensee was identifying problems and entering them in the
corrective action program and that the problems were being corrected commensurate
with their importance to safety. Documents reviewed are listed in the Attachment.
This inspection constitutes four 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 outage schedule and contingency plans for the Unit 1
refueling outage, conducted March 24, 2008, through April 14, 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.
- Licensee configuration management, including maintenance of defense-in-depth
commensurate with the outage schedule 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.
- Controls over the status and configuration of electrical systems to ensure that TS
and outage schedule requirements were met, and controls over switchyard
activities.
- Monitoring of decay heat removal processes, systems, and components.
- Controls to ensure that outage work was not impacting the ability of the operators
to operate the spent fuel pool cooling system.
- Reactor water inventory controls including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss.
- Controls over activities that could affect reactivity.
- Refueling activities, including fuel handling.
- Startup and ascension to full power operation, tracking of startup prerequisites,
walkdown of the containment to verify that debris had not been left which could
block emergency core cooling system (ECCS) suction strainers, and reactor
physics testing.
- Licensee identification and resolution of problems related to refueling outage
activities.
26 Enclosure
In addition to documentation reviews, the inspectors observed the initial Unit 1 head
removal lift as well as the final head reinstallation. The inspectors verified that the height
limitations were maintained during the lifts. Documents reviewed are listed in the
Attachment to this report.
This inspection constitutes one refueling outage sample as defined in IP 71111.20-05.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
.1 Routine Surveillance Testing
a. Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether
risk-significant systems and equipment were capable of performing their intended safety
function and to verify testing was conducted in accordance with applicable procedural
and TS requirements:
- Unit 2 Diesel Driven AFW Pump Monthly Surveillance;
- Unit 1 Bus 112 125V Battery Charger Operability Test;
- Fire Hazard Panel 18-month Surveillance;
- Unit 2 Reactor Containment Fan Cooler Monthly Surveillance; and
- Unit 1 Reheat and Intercept Valve Quarterly 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;
27 Enclosure
- 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.
Documents reviewed are listed in the Attachment.
This inspection constitutes five 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 activity to determine whether
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:
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 USAR,
procedures, and applicable commitments;
- measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy; applicable
prerequisites described in the test procedures were satisfied;
- test frequencies met TS requirements to demonstrate operability and reliability;
28 Enclosure
- 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;
- where applicable, actual conditions encountering high resistance electrical
contacts were such that the intended safety function could still be accomplished;
- prior procedure changes had not provided an opportunity to identify problems
encountered during the performance of the surveillance or calibration test;
- equipment was returned to a position or status required to support the
performance of its safety functions;
- and all problems identified during the testing were appropriately documented and
dispositioned in the CAP.
Documents reviewed are listed in the Attachment.
This inspection constitutes one inservice inspection sample as defined in Inspection
Procedure 71111.22-05.
b. Findings
No findings of significance were identified.
.3 RCS Leak Detection Inspection Surveillance
The inspectors reviewed the test results for the following activity to determine whether
the equipment was capable of performing its intended function of monitoring RCS
leakage and to verify testing was conducted in accordance with applicable procedural
and TS requirements:
- Unit 2 RCS Water Inventory Balance February 7, 2008
The inspectors observed in plant activities and reviewed procedures and associated
records to determine whether:
- 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;
29 Enclosure
- as left setpoints were within required ranges, and the calibration frequency were
in accordance with TSs, the USAR, procedures, and applicable commitments;
measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy;
- applicable prerequisites described in the test procedures were satisfied;
- 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;
- and all problems identified during the testing were appropriately documented and
dispositioned in the CAP.
Documents reviewed are listed in the Attachment.
This inspection constitutes one RCS leak detection inspection sample as defined in
IP 71111.22-05.
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert and Notification System (ANS) Evaluation (71114.02)
.1 ANS Evaluation
a. Inspection Scope
The inspectors reviewed documents and conducted interviews with Emergency
Preparedness (EP) staff regarding the operation, maintenance, and periodic testing of
the ANS in the Byron Stations plume pathway Emergency Planning Zone. The
inspectors reviewed monthly trend reports and siren test failure records from April 2006
through March 2008. Information gathered during document reviews and interviews was
used to determine whether the ANS equipment was maintained and tested in
accordance with Emergency Plan commitments and procedures.
This inspection constitutes one sample as defined in IP 71114.02-05.
b. Findings
No findings of significance were identified.
30 Enclosure
1EP3 Emergency Response Organization (ERO) Augmentation Testing (71114.03)
.1 ERO Augmentation Testing
a. Inspection Scope
The inspectors reviewed and discussed with plant EP staff the emergency plan
commitments and procedures that addressed the primary and alternate methods of
initiating an ERO activation to augment the on-shift ERO as well as the provisions for
maintaining the plants ERO roster. The inspectors also reviewed reports and a sample
of corrective action program records of unannounced off hour augmentation tests, which
were conducted from February 2006 through January 2008 to determine the adequacy
of problem identification and associated corrective actions. The inspectors also
reviewed a sample of the EP training records, approximately 26 records for ERO
personnel, who were assigned to key and support positions, to determine the status of
their training related to their assigned ERO positions.
This inspection constitutes one sample as defined in IP 71114.03-05.
b. Findings
No findings of significance were identified.
1EP5 Correction of EP Weaknesses and Deficiencies (71114.05)
.1 Correction of EP Weaknesses and Deficiencies
a. Inspection Scope
The inspectors reviewed a sample of the Nuclear Oversight staffs 2006 and 2007 audits
of the Byron Station EP program to determine whether these independent assessments
met the requirements of 10 CFR 50.54(t). The inspectors also reviewed critique reports
and samples of corrective action program records associated with the 2007 biennial
exercise, as well as various EP drills conducted in 2007, in order to determine whether
the licensee fulfilled its drill commitments and to evaluate the licensees efforts to
identify, track, and resolve concerns identified during these activities. Additionally, the
inspectors reviewed one actual emergency plan activation that involved an Alert
declaration on November 27, 2007, due to toxic or asphyxiate gases in the plant. The
inspectors independently evaluated the event and the licensee self-assessment to
determine if the licensee effectively implemented the requirements of the emergency
plan. The inspectors reviewed a sample of EP items and corrective actions related to
the facilitys EP program and activities to determine whether corrective actions were
completed in accordance with the sites CAP.
This inspection constitutes one sample as defined in IP 71114.05-05.
b. Findings
No findings of significance were identified.
31 Enclosure
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1 Review of Licensee Performance Indicators for the Occupational Exposure Cornerstone
a. Inspection Scope
The inspectors reviewed the licensees occupational exposure control cornerstone
performance indicators (PIs) to determine whether the conditions resulting in any PI
occurrences had been evaluated, and identified problems had been entered into the
CAP for resolution.
This inspection does not constitute an inspection sample as defined in IP 71121.01-5,
but it does supplements the sample reported in inspection report 05000454/2008002;
b. Findings
No findings of significance were identified.
.2 Plant Walkdowns and Radiation Work Permit (RWP) Reviews
a. Inspection Scope
The adequacy of the licensees internal dose assessment process for internal exposures
>50 millirem committed effective dose equivalent was assessed. There were no internal
exposures >50 millirem committed effective dose equivalent.
This inspection constitutes one required sample 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.
Also, the inspectors reviewed licensee documentation packages for all PI events
occurring since the last inspection to determine if any of these PI events involved dose
rates >25 R/hr at 30 centimeters or >500 R/hr at 1 meter. Barriers were evaluated for
failure and to determine if there were any barriers left to prevent personnel access.
There were no events of unintended exposures >100 millirem total effective dose
equivalent (or >5 rem shallow dose equivalent or >1.5 rem lens dose equivalent),
therefore a substantial potential for an overexposure did not occur.
32 Enclosure
This inspection constitutes two required samples as defined in IP 71121.01-5.
b. Findings
No findings of significance were identified.
2OS2 As-Low-As-Is-Reasonably-Achievable (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.
Also, the inspectors reviewed documents to determine if there were site-specific trends
in collective exposures and source-term measurements.
Additionally, the inspectors reviewed procedures associated with maintaining
occupational exposures ALARA and processes used to estimate and track work activity
specific exposures.
This inspection constitutes three 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 compared the results achieved including dose rate reductions and
person-rem used with the intended dose established in the licensees ALARA planning
for these work activities. Reasons for inconsistencies between intended and actual work
activity doses were reviewed.
This inspection constitutes one required sample as defined in IP 71121.02-5.
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
33 Enclosure
for estimating work activity-specific exposures and the intended dose outcome. Dose
rate and man-hour estimates were evaluated for reasonable accuracy.
Additionally, the licensees exposure tracking system was evaluated to determine
whether the level of exposure tracking detail, exposure report timeliness, and exposure
report distribution was sufficient to support control of collective exposures. RWPs were
reviewed to determine if they covered too many work activities to allow work activity
specific exposure trends to be detected and controlled. During the conduct of exposure
significant work, the inspectors evaluated if licensee management was aware of the
exposure status of the work and would intervene if exposure trends increased beyond
exposure estimates.
This inspection constitutes one required and one optional sample as defined in
IP 71121.02-5.
b. Findings
No findings of significance were identified.
.4 Source-Term Reduction and Control
a. Inspection Scope
The inspectors reviewed licensee records to determine the historical trends and current
status of tracked plant source terms and determined that the licensee was making
allowances and had developing contingency plans for expected changes in the source
term due to changes in plant fuel performance issues or changes in plant primary
chemistry.
Also, the inspectors verified that the licensee had developed an understanding of the
plant source-term, that this included knowledge of input mechanisms to reduce the
source term and that the licensee had a source-term control strategy in place that
included a cobalt reduction strategy and shutdown ramping and operating chemistry plan
which was designed to minimize the source-term external to the core. Other methods
used by the licensee to control the source term including component and system
decontamination, and use of shielding were evaluated.
This inspection constitutes one required and one optional sample as defined in
IP 71121.02-5.
b. Findings
No findings of significance were identified.
.5 Declared Pregnant Workers
a. Inspection Scope
The inspectors reviewed dose records of declared pregnant workers for the current
assessment period to verify that the exposure results and monitoring controls employed
by the licensee complied with the requirements of 10 CFR Part 20.
34 Enclosure
This inspection constitutes one required sample as defined in IP71121.02-5.
b. Findings
No findings of significance were identified.
.6 Problem Identification and Resolutions
a. Inspection Scope
The inspectors reviewed the licensees self-assessments, audits, and Special Reports
related to the ALARA program since the last inspection to determine if the licensees
overall audit programs scope and frequency for all applicable areas under the
Occupational Cornerstone met the requirements of 10 CFR 20.1101(c).
Additionally, the licensees CAP program was also reviewed to determine if repetitive
deficiencies and/or significant individual deficiencies in problem identification and
resolution had been addressed.
This inspection constitutes two required samples as defined in IP 71121.02-5.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 PI Verification (71151)
.1 Drill/Exercise Performance
a. Inspection Scope
The inspectors sampled licensee submittals for the Drill/Exercise Performance PI for the
period from the second quarter 2007 through fourth quarter 2007. To determine the
accuracy of the PI data reported during those periods, PI definitions and guidance
contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors
reviewed the licensees records associated with the performance indicator to verify that
the licensee accurately reported the indicators in accordance with relevant procedures
and the NEI guidance. Specifically, the inspectors reviewed licensee records and
processes including procedural guidance on assessing opportunities for the PI;
assessments of PI opportunities during pre-designated control room simulator training
sessions, performance during the 2007 biennial exercise, and performance during other
drills. Specific documents reviewed are described in the Attachment to this report.
This inspection constitutes one drill/exercise performance sample as defined by
IP 71151-05.
b. Findings
No findings of significance were identified.
35 Enclosure
.2 ERO Drill Participation
a. Inspection Scope
The inspectors sampled licensee submittals for the ERO Drill Participation PI for the
period from the second quarter 2007 through fourth quarter 2007. To determine the
accuracy of the PI data reported during those periods, PI definitions and guidance
contained in the NEI Document 99-02, Revision 5, were used. The inspectors reviewed
the licensees records associated with the performance indicator to verify that the
licensee accurately reported the indicator in accordance with relevant procedures and
the NEI guidance. Specifically, the inspectors reviewed licensee records and processes
including procedural guidance on assessing opportunities for the PI; performance during
the 2007 biennial exercise and other drills; and revisions of the roster of personnel
assigned to key emergency response organization positions. Specific documents
reviewed are described in the Attachment to this report.
This inspection constitutes one ERO drill participation sample as defined by
IP 71151-05.
b. Findings
No findings of significance were identified.
.3 ANS
a. Inspection Scope
The inspectors sampled licensee submittals for the ANS PI for the period from the
second quarter 2007 through fourth quarter 2007. To determine the accuracy of the PI
data reported during those periods, PI definitions and guidance contained in the NEI
Document 99-02, Revision 5, were used. The inspectors reviewed the licensees
records associated with the PI to verify that the licensee accurately reported the indicator
in accordance with relevant procedures and the NEI guidance. Specifically, the
inspectors reviewed licensee records and processes including procedural guidance on
assessing opportunities for the PI and results of periodic ANS operability tests. Specific
documents reviewed are described in the Attachment to this report.
This inspection constitutes one alert and notification system sample as defined by
IP 71151-05.
b. Findings
No findings of significance were identified.
.4 Unplanned Power Changes per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Power Changes per 7000
Critical Hours PI for Units 1 and 2 for the second quarter 2007 through fourth quarter
2007. To determine the accuracy of the PI data reported during those periods, the
36 Enclosure
inspectors used PI definitions and guidance contained in Revision 5 of NEI 99-02. The
inspectors reviewed the licensees operator narrative logs, issue reports, maintenance
rule records, event reports, and NRC integrated inspection reports for this period 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. Specific documents
reviewed are described in the Attachment to this report.
This inspection constitutes two samples of the Unplanned Power Changes per
7000 Critical Hours PI as defined in IP 71151-05.
b. Findings
No findings of significance were identified.
.5 Occupational Exposure Control Effectiveness
a. Inspection Scope
The inspectors sampled licensee submittals for the Occupational Radiological
Occurrences PI for the period of July 2007 through March 2008. To determine the
accuracy of the PI data reported during those periods, PI definitions and guidance
contained in the NEI 99-02, Revision 5, were used. The inspectors reviewed the
licensees assessment of the PI for occupational radiation safety to determine if indicator
related data was adequately assessed and reported. To assess the adequacy of the
licensees PI data collection and analyses, the inspectors discussed with radiation
protection staff, the scope and breadth of its data review, and the results of those
reviews. The inspectors independently reviewed electronic dosimetry dose rate and
accumulated dose alarm and dose reports and the dose assignments for any intakes
that occurred during the time period reviewed to determine if there were potentially
unrecognized occurrences. The inspectors also conducted walkdowns of numerous
locked high and very high radiation area entrances to determine the adequacy of the
controls in place for these areas. Specific documents reviewed are described in the
Attachment to this report.
This inspection constitutes one required occupational radiological occurrences sample
as defined in 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. Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensees CAP at
37 Enclosure
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
Sections 1 and 2 of this report.
b. Findings
No findings of significance were identified.
a. (Open) Unresolved Item (URI) 05000454/455/2008003-06: Unit 1 and Unit 2 AFW
Tunnel Hatch Margin to Safety
Late in the inspection period 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 at another facility. The NRC
inspectors at that facility questioned why a dynamic load factor as a result of the impulse
pressure following a high energy line break had not been considered in an analytic
calculation perform to support the operability evaluation.
Following a review of the licensees evaluation, the inspectors questioned the licensees
conclusion that the operability of the AFW hatches continued to be supported despite
analytical results showing a factor of safety for the concrete expansion anchors
supporting the hatches of less than 2.0, which is contrary to the guidance provided in
NRC Bulletin 79-02, Pipe Support Base Plate Designs Using Concrete Expansion
Anchors. Additionally, the inspectors noted that the licensees evaluation did not
address Section C.13 of NRC Technical Guidance 9900, Operability Determinations &
Functionality Assessment for Resolution of Degraded or Nonconforming Conditions
Adverse to Quality or Safety. Specifically, Section C.13 stated that if a structure was
degraded, the licensee should assess the structures capability of performing its
specified function. As long as the identified degradation did not result in exceeding
acceptance limits specified in applicable design codes and standards referenced in the
design basis documents, the affected structure was either operable or functional. The
licensee also identified additional errors that reduced the margin of safety for the
structural integrity of a high energy line break barrier.
At the close of the inspection period temporary modifications had been implemented at
both facilities that restored the margin of safety to greater than 2.0. Pending additional
follow-up by the inspectors for the past operability and timeliness of corrective actions,
extent of condition, and corrective actions, this item will remain open.
(URI 005000454/2008003-06;05000455/2008003-06)
38 Enclosure
.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.
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 December 1, 2007 through
May 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.
This review constituted a single semi-annual trend inspection sample.
b. Findings
The inspectors identified two apparent trends during this review. The first trend is the
identification by the NRC of six findings or violations with a cross cutting aspect of
decision making within the last four calendar quarters. Three of these findings were
documented in NRC inspection report 05000454/2007009, two of the findings were
documented in NRC inspection report 05000454/2007004 and the remaining item was
documented in this inspection report. Four of these items were in the Mitigating
Systems cornerstone and two were in the Initiating Events cornerstone.
39 Enclosure
The licensee had previously implemented a Human Performance Improvement Plan
(HPIP) as part of a previous negative trend. This trend was initially documented in the
NRC Mid-Cycle Review dated August 30, 2005 as a substantive cross cutting issue.
The licensees corrective actions were assessed and based upon that assessment and a
declining trend of cross cutting issues the substantive cross cutting issue was closed in
the Mid-Cycle Review dated August 31, 2006.
The inspectors assessment determined that the licensee had recognized the new trend
and taken actions to address the declining performance. However, these actions had
not yet proven effective in substantially mitigating the adverse trend.
The second trend identified during this semi-annual trend review was a negative trend in
plant aging issues. Examples included:
Station Auxiliary Transformer 242-2 failure documented in this inspection report
was identified by the licensee as caused by age related failure of an electrical
insulator;
The fire on the Unit 1 Train B diesel driven auxiliary feedwater pump was
identified by the licensee as age related relaxation of the exhaust manifold bolts
along with an inadequate preventative maintenance program. This item was
documented in this inspection report;
The licensees unplanned entry into an Orange risk condition, documented in this
inspection report, was to correct long standing age-related issues with poor
material condition of certain SX valves. These valves had not been removed for
maintenance since initial startup;
The degradation of the SX return header piping risers to the Ultimate Heat Sink
cooling tower was an age related degradation combined with inadequate
corrective actions. This item was documented in NRC inspection report
In the Spring of 2006 the licensee identified degraded vacuum breakers on the
blowdown line to the river. The vacuum breakers had degraded over time and
were not receiving maintenance. The issue related to leaking vacuum breakers
was documented in NRC inspection report 05000454/2006-002 and
05000454/2006004; and
The degradation of non-safety related circulating water piping was identified in
the basement of the Unit 1 and Unit 2 turbine building. This degradation was
found as part of the extent of condition assessment by the licensee to the SX
riser issue. This piping was degraded due to the licensees practice of draining
water to the area around the piping during refueling outages which over many
years caused pipe corrosion.
Each of the first five examples listed above received appropriate regulatory follow-up in
the inspection reports listed. The last example was not of direct regulatory significance
and was not documented in an NRC inspection report. In response to the above issues,
most notably the SX riser degradation the licensee has greatly increased their
assessment of the current condition of plant equipment and has significantly increased
40 Enclosure
the efforts spent to address these issues. Nevertheless as the plant continues to
operate age related degradation will cause challenges.
No findings of significance were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
.1 Plant Response to Seismic Activity
a. Inspection Scope
The inspectors reviewed the plants response to a seismic event. On April 18, 2008, an
earthquake occurred in Southern Illinois. No individual at the licensees facility felt the
earthquake and no instrumentation on site detected the earthquake but personnel offsite
did feel the earthquake and reported it to the control room personnel. Shift personnel
entered the appropriate abnormal operating procedure and attempted to contact the
National Earthquake Information Center but were only able to leave a message.
Subsequently licensee personnel performed an inspection of selected plant facilities and
systems and did not identify any damage. The inspectors also performed a walkdown of
licensee facilities and systems and did not identify any damage. The licensee issued a
corporate wide Press Release and made a voluntary Event Notification to the NRC
Headquarters Operations Officer. Documents reviewed in this inspection are listed in
the Attachment.
This inspection constitutes one sample as defined in IP 71153.
b. Findings
No findings of significance were identified.
.2 (Closed) LER 05000454/2008-001-00: Technical Specification Non-Compliance of
Containment Sump Monitor Due to Improper Installation During Original Construction.
This LER, addresses a past operability issue with the Unit 1 containment floor
drain sump flow monitor that was discovered on March 28, 2008. Technical
Specification3.4.15, RCS Leakage Detection Instrumentation, required one
containment sump monitor to be operable in order to detect reactor coolant system
leaks. The sump was required to be able to detect a one gpm leak within one hour.
During a refueling outage a member of the licensees staff questioned the operability of
the sump with penetrations through the cover allowing water to flow into the sump while
bypassing the leakage measuring device. Subsequently the licensee determined the
sump was improperly installed and had been so since initial construction in 1976.
A corrective action document was written and the sump was modified to restore
operability prior to the restart of the unit. This same error had previously existed on
Unit 2 but had been inadvertently corrected in 2004 during a modification to install a
different type of sump level instrument. Alternative equipment existed to assist the
operators in identifying RCS unidentified leakage. These instruments included a
containment radiation monitor, volume control tank level indicators, post accident
containment sump level instruments, containment pressure indicators, containment
41 Enclosure
temperature indicators, and pressurizer level instruments. The enforcement aspects of
this finding are discussed in Section 4OA7 of this report. Documents reviewed as part of
this inspection are listed in the Attachment. This LER is closed.
This inspection constitutes one sample as defined in IP 71153.
.3 (Closed) LER 05000455/2008-001-00: Unit 2 Emergency Diesel Generators and
Auxiliary Feedwater Pump Automatic Start Resulting from a Loss of Offsite Power Due
to a Failed Insulator Causing a Differential Phase Overcurrent.
This event was previously discussed in Inspection Report 05000454/2008002;
05000455/2008002, Section 4OA3, and in Section 1R12 of this Report. The NRC
reviewed the event risk in accordance with Management Directive 8.3, NRC Incident
Investigation Program, and determined that the conditional core damage probability did
not warrant additional inspection. Documents reviewed as part of this inspection are
listed in the Attachment. This LER is closed.
This inspection constitutes one sample as defined in IP 71153.
4OA5 Other Activities
.1 Follow-up of Backfit Activities
a. Inspection Scope
As documented in Inspection Report 05000454/2008008; 05000455/2008008, the
inspectors identified the licensee did not consider spurious failure/opening of
the 4160 volt or 480 Volts AC as a valid single failure in Amendment No. 95. The
inspectors further noted that the NRC did not evaluate the potential for a passive failure
of the electrical breakers even though passive failures were required to be evaluated
under 10 CFR Part 50, Appendix A. After further review, the inspectors determined that
the provisions of 10 CFR 50.109(a)(4), were applicable and that a modification is
necessary to bring a facility into compliance with the rules or orders of the NRC. The
licensee was requested to respond with a description of the intended actions to address
the noncompliance including a proposed schedule to complete those actions.
In a letter dated June 4, 2008, from D. Hoots (ADAMS Accession No. ML081560649),
the licensee stated that a design basis re-analysis of the ultimate heat sink would be
completed by December 5, 2008. This issue is considered open pending completion of
the licensees re-analysis. (OTHR 05000454/2008003-07; 05000455/2008003-07)
.2 RCS Dissimilar Metal Butt Welds (DMBW) (TI 2515/172, Revision 0)
a. Inspection Scope
The inspectors conducted a review of the licensees activities regarding DMBW
mitigation and inspection 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. TI 2515/172, Reactor Coolant
System Dissimilar Metal Butt Welds, was issued February 21, 2008, to support the
42 Enclosure
evaluation of the licensees implementation of MRP-139. This review was conducted for
both Units 1 and 2 unless otherwise noted.
The documents reviewed by the inspector for this inspection are listed in the Attachment
to this report.
From March 24, 2008 through April 3, 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 verified that the licensees inspection program included inspections of the
pressurizer, hot let and cold leg temperature DMBWs and that the schedules for these
baseline inspections are consistent with the requirements stated in MRP-139. If any
baseline inspection schedules deviated from MRP-139 guidelines, the inspectors also
determined what deviations were planned and what the general basis for the deviation
was.
The inspectors verified that the licensee had completed MRP-139 baseline inspections
of all pressurizer DMBWs by December 31, 2007.
(2) Volumetric Examinations
The inspectors reviewed the volumetric examinations of the Unit 1 reactor vessel outlet
safe end to nozzle weld baseline inspection completed in 2005 and the Unit 2 reactor
vessel inlet safe end to nozzle weld baseline inspection completed in 2007 and verified
the examinations were performed in accordance with the guidelines in MRP-139,
Section 5.1. The inspectors also verified that these examinations were performed by
qualified personnel and that any deficiencies identified were appropriately dispositioned
and resolved.
The inspectors reviewed the volumetric examinations of the Unit 1 pressurizer surge
nozzle overlay completed in 2006 and the Unit 2 pressurizer relief valve nozzle overlay
completed in 2007 and verified the examination was performed consistent with the NRC
staff relief request authorization for the weld overlay. If the inspection coverage
warranted further evaluation, the inspector also reviewed the licensees documentation
of the basis for achieving the required inspection coverage.
The inspectors verified that the above examinations were performed by qualified
personnel and that any deficiencies identified were appropriately dispositioned and
resolved.
(3) Weld Overlays
During the current outage no weld overlays pertinent to MRP-139 were performed on
Unit 1. The inspectors reviewed weld overlay documentation for the Unit 1 pressurizer
surge nozzle overlay and the Unit 2 pressurizer relief valve nozzle overlay to verify that
the welds were performed in accordance with NRC staff relief request authorizations and
the ASME Code. The inspectors also verified that the welds were performed by qualified
personnel and that any deficiencies were appropriately dispositioned and resolved.
43 Enclosure
(4) Mechanical Stress Improvement
There were no mechanical stress improvement activities performed or planned by the
licensee to comply with their MRP-139 commitments. Hence, NRC inspection of such
mechanical stress improvements was not applicable.
(5) ISI Program
The inspectors verified that the licensees MRP-139 ISI program includes the applicable
welds and that the welds are included in categories consistent with MRP-139 guidelines.
The inspectors verified that the licensees inspection program and procedures specified
inspection frequencies consistent with Tables 6-1 and 6-2 of MRP-139. The inspectors
also determined if any welds were categorized as H or I, and for those welds reviewed
the licensees basis for the categorization and the licensees plans for addressing
potential primary water stress corrosion cracking. The inspector also determined if any
deviations were planned from the inspection guidelines of MRP-139.
b. Observations
Summary: Byron Units 1 and 2 are Westinghouse four loop design plants and were
determined by the licensee to contain susceptible DMBWs per MRP-139. To date,
the pressurizer DMBWs on both units have been mitigated by full structural overlays
and have received baseline volumetric examination. The remaining susceptible welds
(MRP-139 category "D" and "E") for Units 1 and 2 are planned for possible mitigation in
2011 and 2013 respectively. 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. a. Have the baseline inspections been performed or are they scheduled to be
performed in accordance with MRP-139 guidance?
Yes. Baseline inspections for pressurizer DMBWs were performed post
mitigation in the Fall of 2006 for Unit 1 and in the Spring of 2007 for
Unit 2. The Category "D" and "E" welds were inspected in the Spring of
2005 for Unit 1 and in the Fall of 2005 for Unit 2.
b. Were the baseline inspections of the pressurizer temperature DMBWs of the
nine plants listed in 03.01.b completed during the spring outages?
No. Byron is not one of the nine plants listed in 03.01.b.
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. No deviations from the MRP-139 baseline inspection requirements are
planned for either unit.
44 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. The inspectors reviewed the volumetric examinations of the Unit 1
pressurizer surge nozzle overlay completed in 2006 and the Unit 2 PORV
nozzle overlay completed in 2007 and verified the examination was
performed consistent with the NRC staff relief request authorization for
the weld overlay. The inspectors also reviewed the volumetric
examinations of the Unit 1 reactor vessel outlet safe end to nozzle weld
baseline inspection completed in 2005 and the Unit 2 reactor vessel inlet
safe end to nozzle weld baseline inspection completed in 2007 and
verified the examinations were performed in accordance with the
guidelines in MRP-139, Section 5.1.
2. Performed by qualified personnel? (Briefly describe the personnel
training/qualification process used by the licensee for this activity.)
Yes. The UT examiners were qualified to the applicable ASME Code,
Section XI, Appendix VIII, PDI requirements.
Performed such that deficiencies were identified, dispositioned, and resolved?
Yes. Indications were identified in the weld overlay for several DMBWs on both
the Unit 1 and Unit 2 pressurizers. The inspectors reviewed the
evaluations performed for the Unit 1 surge nozzle overlay and the Unit 2
PORV nozzle overlay and determined that the evaluations were
acceptable.
(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?
Yes. Weld overlay documentation for the Unit 1 surge nozzle overlay and the
Unit 2 PORV nozzle overlay were reviewed. The welds were performed
in accordance with NRC staff relief request authorizations and the ASME
Code.
2. Performed by qualified personnel? (Briefly describe the personnel
training/qualification process used by the licensee for this activity.)
Yes. Welders were qualified in accordance with ASME Code,Section IX and
were verified to be current.
3. Performed such that deficiencies were identified, dispositioned, and resolved?
45 Enclosure
Yes. Welds were performed in accordance with the ASME Code and
10 CFR 50, Appendix B requirements.
(4) Mechanical Stress Improvement
There were no stress improvement activities performed or planned by this licensee to
comply with their MRP-139 commitments.
(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.
Yes. Susceptible welds were appropriately included in the program and
categorization and inspection schedules are in accordance with MRP-139
guidance.
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. Welds included in the MRP-139 program were properly categorized.
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 inservice inspections frequencies called for by MRP-139?
Yes. Those DMBWs which have been overlaid and those yet to be mitigated
are scheduled for reexamination in accordance with 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 primary water
stress corrosion cracking (PWSCC).
Pressurizer DMBWs (safety valve, relief valve, spray, and surge line nozzles) for
both units were categorized as "H" due to a lack of qualified technique which
prevented an Appendix VIII examination. These welds, on both units have been
mitigated by full structural weld overlays.
5. If the licensee is planning to take deviations from the inservice inspection
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?
No. No deviations are currently planned for either unit.
c. Findings
No findings of significance were identified.
46 Enclosure
.3 (Closed) Unresolved Item (URI) 05000455/2008002-03: Unit 2 Notice of Unusual Event
due to Loss of Both SATs
On March 25, 2008, Unit 2 SAT 242-2 de-energized upon receipt of a C phase to ground
relay actuation. As designed the upstream switchyard breakers opened de-energizing
both SAT 242-1 and 242-2. Also, as designed, the downstream breakers opened
resulting in a fast transfer of the 6.9KiloVolt buses to the Unit Auxiliary Transformers and
the transfer of the 4KiloVolt buses to the EDGs which had automatically started. The
licensee entered a Notification of Unusual Event and the NRC entered the Monitoring
Mode. The licensee subsequently transferred the 4KiloVolt loads to the Unit 1 SATs and
began troubleshooting efforts. Following verification that a fault did not exist on the SAT
242-1 circuit all Unit 2 house loads were transferred to SAT 242-1. Subsequently the
licensee exited the Unusual Event and the NRC exited the Monitoring Mode.
The inspectors reviewed the plants and the operators responses to the loss of both unit
SATs to determine if the responses were appropriate and in accordance with design,
procedures and training.
At the close of the previous inspection period additional information was required to
determine if the loss of the SAT was a finding, or if it constituted a deviation or violation.
The additional information needed was the results of the licensees root cause
evaluation and proposed corrective actions. The inspectors reviewed the licensees root
cause analysis report, additional documentation, and interviewed licensee personnel.
The root cause analysis determined that the SAT tripped due to the failure of a ceramic
insulator on the B-Phase of the 4KiloVolt non-segregated bus duct. Routine preventive
testing of the bus duct did not identify the degraded insulator. The testing performed
was in accordance with licensee procedures and industry recommended practices.
Based upon these reviews, the inspectors determined that the loss of the SAT was not a
finding, deviation, or violation. Documents reviewed are listed in the Attachment. This
URI is closed.
.4 (Closed) URI 05000455/2008002-04: Unit 1 Train B Auxiliary Feedwater Pump Diesel
Fire and Shutdown During Surveillance
On March 21, 2008, during a routine 18-month surveillance test of the Unit 1 AFW pump,
the operator in the room reported that the diesel was on fire. The diesel driven AFW
pump was shutdown and declared inoperable resulting in the licensee entering a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
shutdown Limiting Condition for Operation. Subsequently, the licensee shutdown for a
planned refueling outage, exiting the applicable operating modes, and negating the need
to repair the diesel within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Prior to the end of the refueling outage the licensee
repaired the diesel, performed appropriate surveillance tests, and declared the diesel
driven pump operable. Review was performed as part of IP 71111.15, Operability
Evaluations and after reviewing engineering documents, interviewing operators, and
performing a specific assessment of the effects of a carbon dioxide release on the
operation of the diesel the inspectors agreed with the licensees conclusion that the
diesel remained operable during the fire. Even if the operators secure the AFW pump in
the event of a fire, they would be able to restart the pump as necessary as the pump is
fully operable. Documents reviewed are listed in that section. This URI is closed.
47 Enclosure
.5 (Closed) NRC Temporary Instruction (TI) 2515/166, Pressurized Water Reactor
Containment Sump Blockage (NRC Generic Letter 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 Generic Letter (GL) 2004-02,
Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis
Accidents at Pressurized Water Reactors. The inspectors performed walkdowns and
reviewed the Engineering Change Packages (ECs) associated with the ECCS throttle
valves modifications and the 10 CFR 50.59 evaluations for these ECs. In addition, the
inspectors reviewed: two samples of the completed and approved for use changes for
the UFSAR, Revision 12, that have not been incorporated yet; one sample of an in-route
change for the UFSAR, Revision 12; and one sample already incorporated in
Revision 11. The documents reviewed are listed at the end of the report. The
inspection was conducted in accordance with TI 2515/166.
b. 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. In addition, the licensee cancelled the cyclone
separator modification for Unit 1 because test results showed that they are not
susceptible to blockage as documented in EC 364979, Evaluate SI Throttle Valve Test
Results from Wyle Labs to Document Acceptability of New Trim Design. The
commitments included:
- Installation of permanent modification of the sump strainer assemblies.
This commitment was previously reviewed and documented in NRC Inspection
Reports 05000454/2007003 and 05000455/2007003. Structural analyses of
the new strainer assemblies were performed through BYR06-025, Design
Loads and Sizing Limitations for the ECCS Containment Sump Trash Rack,
and 3 SA-096-016, CCI Structural Analysis of Strainer and Support Structure.
- Installation of permanent modification of the ECCS throttle valves at Unit 2 and
replacement of the fibrous insulation with reflective metal insulation within the zone
of influence at Unit 1.
This commitment was previously reviewed and documented in NRC Inspection
Reports 05000454/2008006 and 05000455/2008006.
- Installation of permanent modification of the ECCS throttle valves at Unit 1 for which
licensee received approval for an extension until Spring 2008.
48 Enclosure
This modification was completed at the time of this inspection and was
documented in EC 359455, Downstream Activities Effects Related to [Generic
Safety Issue] (GSI) -191 - U1. In addition, the inspectors performed a
walkdown of this modification.
- Perform latent debris walkdowns, and debris generation and transport analyses.
The commitment to perform containment walkdowns was previously reviewed
and documented in NRC Inspection Report 05000454/2008006 and
05000455/2008006. The debris generation was estimated by S040-BY-5010,
GSI-191 Latent Debris Collection-Unit 1, and S040-BY-5030, GSI-191 Latent
Debris Collection-Unit 2. Debris generation was analyzed by BYR05-041,
GSI-191 post-LOCA Debris Generation. Debris transportation was analyzed
through BYR05-042, Post-LOCA Debris Transport Evaluation for Resolution of
GSI-191.
- Perform evaluation of strainer performance including chemical effects.
Head loss testing and analysis, including chemical effects, were previously
reviewed and documented in NRC Inspection Report 05000454/2008006
and 05000455/2008006. In addition, the following tests were reviewed:
(1) DIT-BYR-06-007, Debris Concentration Measurements Results, and
(2) BYR-05-061, GSI-191 Evaluation of Long Term Downstream Effects.
- Perform evaluation of downstream and upstream effects.
Downstream effects analysis for fuel, vessel, and component wear and
blockage were previously reviewed and documented in NRC Inspection Report 05000454/2008006 and 05000455/2008006. Testing of wear and blockage to
the ECCS throttle valves and Containment Spray System Cyclone Separator
was documented in EC 364979, Evaluate SI Throttle Valve Test Results from
Wyle Labs to Document Acceptability of New Trim Design. Upstream effects
were evaluated by S040-BYR-5032, GSI-191 Debris Generation Walkdown-
U2, and S040-BYR-5011, GSI-191 Debris Generation Walkdown-U1.
- 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 previously reviewed
and documented in NRC Inspection Report 05000454/2008006 and
05000455/2008006. The hydraulic model of the ECCS was performed
by BYR06-029, 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
49 Enclosure
upgraded OP-AA-116-101, Equipment Labeling, and committed to use
1/2 BOSR Z.5.1.1-1, Containment Loose Debris Inspection, CC-AA-205,
Control of Undocumented/Unqualified Coatings Inside Containment, and
1/2 BVSR XII-11, Containment Building Interior Surface Coating Inspection as
administrative controls for limiting debris sources inside containment. Also,
latent debris measurements inside containment every four refueling outages
are currently being tracked by Predefines 174052 and 174053. IR 777152 is
tracking the addition of a note explaining the basis for the activity and a caution
to factor in the impact of changes to it when the procedure is generated.
(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 one change to the UFSAR relevant to the
recently completed modification of the ECCS throttle valves for Unit 1. This UFSAR
change is pending licensee approval.
(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 of ECCS throttle valves for Unit 1. During the refueling outage
of spring 2008, the licensee completed this action.
Completed actions are:
- Installation of new strainer assemblies for both units;
- Installation of modified ECCS throttle valves at both units;
- 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:
- Licensing bases update relevant to the ECCS throttle valve modification at Unit 1
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 the 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 plant(s).
Completion of TI-2515/166 does not necessarily indicate that a licensee has finished all
testing and analyses needed to demonstrate the adequacy of their modifications and
procedure changes. Licensees may also have obtained approval of plant-specific
extensions that allow for later implementation of plant modifications. Licensees will
confirm completion of all corrective actions to the NRC. The NRC will track all such yet-
50 Enclosure
to-be-performed items identified in the TI-2515/166 inspection reports to completion and
may choose to inspect implementation of some or all of them.
.6 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
Exit Meeting Summary
On July 10, 2008, the inspectors presented the inspection results to Mr. Dave Hoots,
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.
Interim Exit Meetings
Interim exits were conducted for:
- The Emergency Preparedness Inspection with Mr. D. Hoots on April 11, 2008.
- The Inservice Inspection Procedure 71111.08 and TI 2515/172 with Mr. D. Hoots
on April 3, 2008. The inspectors returned proprietary information reviewed
during the inspection prior to leaving the site and the licensee confirmed that
none of the potential report input discussed was considered proprietary.
- The TI 2515/166, PWR Containment Sump Blockage (NRC Generic Letter 2004-02) Inspection with T. Hulbert on May 30, 2008. The licensee
acknowledged the issues presented. The inspectors confirmed that none of the
potential report input discussed was considered proprietary.
- The Occupational Radiation Safety Program for Access to Radiologically
Significant Areas and ALARA Planning and Controls Inspections with
Mr. D. Hoots and other members of the licensees staff on June 20, 2008.
51 Enclosure
4OA7 Licensee-Identified Violations
The following violations of very low significance (Green) were identified by the licensee
and are violations of NRC requirements which meet the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.
Cornerstone: Mitigating System
- Technical Specification 3.4.15, Condition A, requires that an inoperable
containment sump monitor be returned to operable status within 30 days.
Technical Specification 3.4.15, Condition C, requires that if Condition A was not
met, the unit must be in Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary
to these, Unit 1 was operated since 1976 with the containment sump monitor
inoperable. Alternative equipment existed to assist the operators in identifying
RCS unidentified leakage. These instruments included a containment radiation
monitor, volume control tank level indicators, post accident containment sump
level instruments, containment pressure indicators, containment temperature
indicators, and pressurizer level instruments. Based upon this, the violation was
of very low safety significance. The licensee entered this issue into the
corrective action program as IR 755837.
- Technical Specification 5.7.2(c) requires each person entering a locked
high radiation area to have an alarming radiation monitoring device that
continuously integrates the radiation dose rate (electronic dosimeter). Contrary
to the above, on March 29, 2008, an individual entered containment, a posted
high radiation area, without an electronic dosimeter. The inspector verified that
dose rates >1000 mR/hour were present and that there were no additional
physical controls to prevent unauthorized access to these areas. This was
identified in the licensees corrective action program as IR 756342 and corrective
actions included removing the individual from the area, reading the individuals
thermoluminescent dosimeter, and established single point accountability for
individuals controlling access to the locked high radiation area. The finding was
determined to be of very low safety significance because it was not an ALARA
planning issue, there was no overexposure nor potential for overexposure, and
the licensees ability to assess dose was not compromised. The inspectors
discussed with the licensee that this event should have been reported as a PI
occurrence for the first quarter of 2008.
- 10 CFR 50.65(a)(4) requires in part, that the licensee shall assess and manage
the increase in risk that may result from the proposed maintenance activities
before performing maintenance. Contrary to the above, between April 5, 2008 to
April 6, 2008, the licensee failed to consider that both Unit 1 Essential Service
Water Train Cross-tie Isolation Valves, 1SX033 and 1SX034, were left opened
and unable to be closed in the main control room in their risk evaluation before
conducting the 1A EDG testing. This finding affected the mitigating capability
during an internal flooding event in the auxiliary building. The finding was
determined to be of very low safety significance for Unit 1 because the unit had
been shutdown since March 23, 2008, decay heat load was low, and the time to
boil was long. The licensee entered this issue into their corrective action
program as IR 759945.
52 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
D. Hoots, Site Vice President
B. Adams, Plant Manager
A. Daniels, NOS Manager
A. Giancatarino, Performance Improvement Director
C. Gayheart, WC Manager
S. Greenlee, Engineering Director
B. Kouba, Operations Support Manager
D. Thompson, Radiation Protection Manager
W. Grundmann, Regulatory Assurance Manager
B. Spahr, Maintenance Director
R. Zuffa, IEMA
Nuclear Regulatory Commission
R. Skokowski, Chief, Branch 3, Division of Reactor Projects
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000454/2008-003-01 NCV Fire Suppression Sprinkler Obstruction in the Diesel Oil
Storage Tank Room
05000454/2008-003-02 NCV Failure to Correctly Evaluate and Disposition of a Weld
Indication
05000454/2008-003-03 NCV Failure to Perform Evaluation of a Leaking Bolted
Connection
05000454, 455/2008-003-04 NCV Failure to Correctly Tighten Fittings Leads to Failure to
Start During a Surveillance of the 0B SX Makeup Pump
05000455/2008-003-05 AV Failure to Perform an Updated Risk Evaluation Prior to
Surveillance Testing of the Unit 1 Train A Diesel
Generator Based on Existing Plant Conditions.
05000454, 455/2008-003-06 URI Unit 1 and Unit 2 Auxiliary Feedwater Tunnel Hatch
Margin to Safety
05000454, 455/2008-003-07 OTHR Design Basis Re-Analysis of the Ultimate Heat Sink
1 Attachment
Closed
05000454/2008-003-01 NCV Fire Suppression Sprinkler Obstruction in the Diesel Oil
Storage Tank Room
05000454/2008-003-02 NCV Failure to Correctly Evaluate and Disposition of a Weld
Indication
05000454/2008-003-03 NCV Failure to Perform Evaluation of a Leaking Bolted
Connection
05000454, 455/2008-003-04 NCV Failure to Correctly Tighten Fittings Leads to Failure to
Start During a Surveillance of the 0B SX Makeup Pump
05000454/2008-001-00 LER Technical Specification Non-Compliance of
Containment Sump Monitor Due to Improper
Installation During Original Construction
05000455/2008-001-00 LER Unit 2 Emergency Diesel Generators and Auxiliary
Feedwater Pump Automatic Start Resulting from a Loss
of Offsite Power Due to a Failed Insulator Causing a
Differential Phase Overcurrent
05000455/2008002-03 URI Unit 2 Notice of Unusual Event due to Loss of Both
System Auxiliary Transformers05000455/2008002-04 URI Unit 1 Train B Auxiliary Feedwater Pump Diesel Fire
and Shutdown During Surveillance
2 Attachment
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
Section 1R01: Adverse Weather Protection
Byron Condition Reports; Open, Auxiliary Building Ventilation System
Byron Condition Reports; Open, Auxiliary Power System
Byron Condition Reports; Open, Essential Service Water System
Oil Sample Results for UAT 241-2, September 1998 - May 2008
Oil Sample Results for SAT 242-1, September 1990 - March 2008
Oil Sample Results for SAT 242-2, June 1992 - May 2008
Oil Sample Results for 1W MPT, April 1989 - June 2008
IEEE Std C57.104-1991; IEEE Guide for the Interpretation of Gases Generated in Oil-Immersed
Transformers, November 20, 1991
IR 786022; Switchyard Thermography Needed Following Adverse Weather, June 13, 2008
IR 786025; Emergency Load Reduction Requested and Started, June 13, 2008
OP-AA-108-107-1001; Station Response to Grid Capacity Conditions, Revision 2
OP-AA108-107-1002; Interface Agreement Between Exelon Energy Delivery and Exelon
Generation for Switchyard Operations, Revision 4
OP-AA-108-107; Switchyard Control, Revision 2
WC-AA-8000; Interface Procedure Between Exelon Energy Delivery (Comed/Peco) and Exelon
Generation (Nuclear/Power) for Construction and Maintenance Activities, Revision 2
WC-AA-8003; Interface Procedure Between Exelon Generation (Nuclear/Power) for Design
Engineering and Transmission Planning Activities, Revision 1
Section 1R04: Equipment Alignment
IR 741835; Start/Stop OB VC from 1PL05JA not performed as scheduled; February 27, 2008
IR 666981; 1A DG Common Mode Failure Evaluation; March 21, 2008
IR 591516; 1A DG Tripped on High JW Temperature During Cooldown; February 14, 2007
IR 759737; 1A DG Failed 1BOSR 8.1.17-1 Due to Low Voltage; April 05, 2008
IR 747616; 1A DG Walkdown Results for NER NC-08-010; March 10, 2008
IR 733706; Auxiliary Electric Room Return Damper Failed Closed; February 08, 2008
IR 585935; OB VC M/U Fan Tripped During a Start for PMT; March 02, 2007
IR 461596; OA VC Train Inoperability - 0VC032Y Failure; March 02, 2006
IR 461319; 0VC032Y Fails, Retested w/o Determining Cause; March 02, 2006
IR 461245; 0VC032Y Will Not Close on M/U Signal; March 02, 2006
BOP VC-M1; Control Room Heating and Ventilation (HVAC) System Valve Lineup; Revision 5
BOP VC-E1; Control Room Ventilation Electrical Lineup; Revision 4
BOP VC-1; Startup of Control Room HVAC; Revision 5
BOP VC-17; Swapping Control Room Chiller and HVAC Trains; Revision 6
BOP DG M1A; Train A Diesel Generator System Valve Lineup; Revision 11
BOP DG-E1A; Diesel Generator Train A; Revision 2
BOP FC-E1; Fuel Pool Cooling System Electrical Lineup; Revision 2
BOP FC-T3; Spent Fuel Pool Skimmer One-Line Diagram; Revision 0
BOP FC-M1; Fuel Pool Cooling and Cleanup System Valve Lineup; Revision 17
3 Attachment
BOP RH-M2B; Train B Residual Heat Removal System Valve Lineup, Revision 7
BOP RH-E2B; Unit 2 Residual Heat Removal System, Train B Electrical Lineup, Revision 2
BOP SI-E1B; Unit 1 Safety Injection System Train B Electrical Lineup, Revision 3
BOP SI-E1; Unit 1 Safety Injection System Electrical Lineup, Revision 7
BOP SI-M1B; Train B Safety Injection System Valve Lineup, Revision 3
BOP SI-E1C; Unit 1 Safety Injection System Electrical Lineup, Revision 4
BOP RH-E2A; Unit 2 Residual Heat Removal System Electrical Lineup, Revision 3
BOP RH-M2A; Train A Residual Heat Removal System Valve Lineup, Revision 6
BOP RH-E2; Unit 2 Residual Heat Removal System Electrical Lineup, Revision 0
WR 231867; 1A DG Tripped on High JW Temperature During Cooldown; February 14, 2007
WR 268493; 1A DG Failed 1BOSR 8.1.17-1 Due to Low Voltage; April 06, 2008
WR 265663; DG Walkdown Results for NER NC-08-010; March 11, 2008
WR 262636; Auxiliary Electric Room Return Damper Failed Closed; February 08, 2008
WR 202809; 0VC032Y Will Not Close on M/U Signal; March 03, 2006
Diagram of Safety Injection M-61 Sheet Number 1B, Revision AW
Diagram of Residual Heat Removal M-137, Revision BD
Corrective Action Documents as a Result of NRC Inspection
IR 761127; NRC Identified Tagging Issues - Not B1R15 Related, April 9, 2008
IR 766819; NRC Identified - 1SI8804B Frayed Sealtite, April 23, 2008
IR 766814; NRC Identified - 1SI8806 Old Grease Leaking from Actuator, April 23, 2008
IR 769637; NRC Identified Procedure Discrepancy, April 30, 2008
Section 1R05: Fire Protection
Permanent Scaffold Request B4855, April 3, 2004
Unit 1 Diesel Fuel Oil Storage Room 1A, Zone 10.2-1, January 31, 2007
Unit 1 Diesel Fuel Oil Storage Room 1B, Zone 10.1-1
Unit 2 Diesel Fuel Oil Storage Room 2A, Zone 10.2-2, January 31, 2007
Unit 2 Diesel Fuel Oil Storage Room 2B, Zone 10.1-2, January 31, 2007
Pre-Fire Plan; Fuel Handling Building, Elevation 401-0, Zone 12.1-0, January 31, 2007
Pre-Fire Plan; Fuel Handling Building, Elevation 426-0, Zone 12.1-0, January 31, 2007
Fire Protection Report; Section 18.11-0, December 1998
Fire Protection Report; Section 18.11-1, December 1998
Fire Protection Report; Section 18.11-2, December 1998
Fire Protection Report; Figure 2.3-29
Fire Protection Report; Figure 2.3-30
PMID 106774; Disassemble, Clean and Inspect, Assemble Deluge System, August 21, 2007
IR 779116; Scaffold Planks Removed, May 23, 2008
MA-AA-716-025; Scaffold Installation, Modification, and Removal Request Process, Revision 0
Drawing M-1280; Auxiliary Building Ventilation Floor Plan Elevation 373-6, Revision U
Drawing M-245; Auxiliary Building Piping Plan Elevation 383-0, Revision P
M-603 - Sheet Number 64; Viking Sprinkler System Auxiliary Building Area 1-T1 & Area 1-T2,
Basement Elevation 373-0, Revision F
2BOSR 7.5.4-2; Unit 2 Diesel Driven Auxiliary Feedwater Pump Monthly Surveillance,
Revision 15
4 Attachment
Corrective Action Documents as a Result of NRC Inspection
IR 770364; NRC Questioning FP Sprinkler Potential Spray Obstructions, April 30, 2008
IR 775188; NRC Walkdown Items, May 13, 2008
IR 776571; NRC Raised FP Questions During FHB Tour, May 16, 2008
IR 787352; River Screenhouse 0A Diesel Exhaust Piping Penetration Insulation, June 17, 2008
IR 787353; River Screenhouse 0B Diesel Exhaust Piping Penetration Insulation, June 17, 2008
IR 788076; Bird Nest in Horizontal Exhaust, June 19, 2008
Section 1R06: Flood Protection
IR 761585; Door Handwheel is Binding When Door Closes, April 10, 2008
IR 767486; Inappropriate Engineering Involvement in Flooding Risk Issue, April 25, 2008
BAR 0-38-A14; Turbine Building Fire/Oil Sump Flood Level, Revision 5
DCR # 990198; Turbine Building Water Level After Circ. Water Line Break, October, 14, 1999
0BMSRDD-1; Water-Tight Barrier Inspection (CM-6.1.1), Revision 5
WO 836114-12; Remove & Repair Water-Tight Barrier 2DSFS002
Section 1R08: ISI Activities
IR 717257; NRC IN 2007-37; Buildup of Deposits in Steam Generators, January 2, 2008
IR 668998; NRC RIS 2007-20 Primary to Secondary Leakage, September 7, 2007
AT: 00717275-02; Buildup of Deposits in Steam Generators, NRC IN 2007-37
ER-AP-335-1012; Bare Metal Visual Examination of PWR Vessel Penetration and Nozzle
Safe-Ends, Revision 3
ER-AP-335-040; Evaluation of Eddy Current Data for Steam Generator Tubing Revision 3
ER-AP-335-039; Multi-frequency Eddy Current Data Acquisition of Steam Generator Tubing,
Revision 4
ER-MW-335-1009; Site Specific Performance Demonstration Program, Revision 3
LS-AA-115; Operating Experience Procedure, Revision 11
Byron Unit 1, B1R15 Degradation Assessment and Condition Monitoring Checklist, Revision 0
EXE-UT-68; Ultrasonic Examination of Unit 1 Replacement Steam Generator Main Feedwater
Nozzle Inside Radius Section at Braidwood, Revision 2
Westinghouse Data Pkg B1R15-UT-001; Ultrasound Examination of Feedwater Nozzle Inner
Radius 1RC-01-BB, N-3-NIR, March 30, 2008
Westinghouse Data Pkg B1R15-PT-001; Penetrant Examination of 1SI03DA-2/W-09,
March 29, 2008
08-11; Evaluation of B1R14 Imbedded Ultrasonic Indication Outside Required Examination
Volume, April 1, 2008
Section 1R12: Maintenance Effectiveness (Quarterly)
LER 455-2008-001-00; Unit 2 Emergency Diesel Generators and Auxiliary Feedwater Pump
Automatic Start Resulting from a Loss of Offsite Power Due to a Failed Insulator Causing a
Differential Phase Overcurrent.
Root Cause Report; Byron Station Unit 2 Loss of Off-Site Power Event, March 25, 2008
NRC Information Notice 98-36; Inadequate or Poorly Controlled, Non-Safety-Related
Maintenance Activities Unnecessarily Challenged Safety Systems, September 18, 1998
Drawing No. 6E-2-4419; Three Line Diagram System Auxiliary Transformers 242-1 & 242-2,
Revision C
5 Attachment
Drawing No. 6E-2-4016D; Relaying & Metering Diagram Differential Relay Transfer Scheme
System Auxiliary Transformers 242-1 & 242-2, Revision D
6E-2-4016C; Relaying & Metering Diagram System Auxiliary Transformers 242-1 & 242-2,
Revision J
Calibration Data; Attachment 3 HU, HU-1, HU-4 Type Differential relay, March 26, 2008
Nuclear Accident Reporting System (NARS) Form, March 25, 2008
B1R15 Shutdown Risk, March 25, 2008
BOP AP-86; Isolating SAT 242-2 At Power, Revision 9
EC 370080 00; Engineering Evaluation of the SAT 242-1 Testing Requirements Following the
Actuation of the Differential Protection for SAT 242-2, March 27, 2008
EPRI TR-112784; Isolated Phase Bus Maintenance Guide, May 1999
Drawing No. 6E-2-4003A; Phasing Diagram Part 1, Revision B
Drawing No. 6E-2-4003B; Phasing Diagram Part 2, Revision C
NES-EIC-17.03; Nuclear Engineering Standards, High Potential Tests, Revision 0
Log No.08-031; Unit 2 Standing Order, June 13, 2008
IR 772956; Maintenance Rule (A)(1) Determination Required for MP2, May 7, 2008
IR 773419; Work Request to Install Filter Drain in Rubber Boot Seals, May 8, 2008
IR 783134; 0B SX Makeup Pump Needs Reportability Review, June 5, 2008`
Project No. BYR-92592; Failure Analysis of the Byron Auxiliary 242-2, Non-Segregated Bus
Duct, Section 15, B Phase Insulator, April 25, 2008
IR 754582; Unit 2 Loss of Off-Site Power, March 25, 2008
IR 754585; Two of Four Fans Not Running on 2B SX Pump Cubicle Cooler, March 25, 2008
IR 754602; SAT 242-2 Phase C Overcurrent, March 25, 2008
IR 755875; Maintenance Rule (A)(2) at Risk Due to Unplanned SAT Outage, March 28, 2008
IR 760354; Bolted Connection on 6.9KV Non Seg Found Loose, April 7, 2008
IR 761246; Non-Seg Bus Duct Inspection, April 9, 2008
IR 762409; Replace Rubber Expansion Boot Around Non-Seg Bus Duct, April 11, 2008
IR 762638; Megger Test UAT 141-1 4KV & 6.9KV, April 12, 2008
IR 768314; Unexpected Alarms - Unit 2 SATs, April 27, 2008
IR 768317; SAT 242-2 Phase -A Differential Overcurrent Lockout When SAT Energized,
April 27, 2008
IR 774259; SAT Isolation Procedure Differences - Plant and OLR Impacts, May 11, 2008
IR 779699; 0B SX M/U Pump Failed to Run During Low Level Start, May 27, 2008
WO 912183 01; Replace Parker Check Valve at SX M/U Pump Fuel Oil Line, April 29, 2008
MA-AA-716-011; Work Execution & Close Out, Revision 11
Corrective Action Documents as a Result of NRC Inspection
IR 770417; NRC Concern on SAT 242-2 Trip When Energized, April 28, 2008
IR 780732; NRC Requested Past Operability Evaluation - 0B SX M/U Pump, May 29, 2008
Section 1R13: Maintenance Risk Assessments and Emergent Work Evaluation
Unit 2 Risk Configurations, Week of March 31, 2008
Unit 2 Risk Configurations, Week of March 31, 2008, Revision 1
Unit 2 Risk Configurations, Week of March 31, 2008, Revision 2
Unit 2 Risk Configurations, Week of March 31, 2008, Revision 3
Unit 2 Risk Configurations, Week of April 7, 2008
Unit 2 Risk Configurations, Week of April 7, 2008, Revision 1
Unit 2 Risk Configurations, Week of May 5, 2008, Revision 1
Unit 2 Risk Configurations, Week of May 26, 2008, Revision 3
6 Attachment
Protected Equipment Log, May 7, 2008
Protected Equipment Log, May 28, 2008
IR 562336-13; License Amendment Implementation Consider License Amendment for
RPS/ESFAS Test times and Completion Times Relaxations for Operator Training,
September 1, 2007
IR 759929; Clearance Order Returned with Dead Man Switch Still Installed, April 6, 2008
IR 759945; Unplanned Unit 2 Online Risk Orange Condition, April 6, 2008
Unit 1/2 Standing Order 08-011; Technical Specification Amendment 153, February 14, 2008
WO 836114; Replace 1SX034 in B1R15, April 7, 2008
WO 836114 06; Remove/Reinstall Flood Seal 2DSFS003 to Support 1SX034 Valve
Replacement
WO 1120558 01; 1SX033 - Remove and Inspect/Rebuild Limitorque Operator and Gear,
April 9, 2008
Clearance 63416; EPN 1SX033
Clearance 57893; 1SX034 - De-Term/Re-Term Valve for Replacement
Clearance 57894; 1SX034 - Replace Valve, April 1, 2008
B1R15 OCC Turnover, April 5, 2008 - June 7, 2008
Quick Human Performance Investigation Report; Unplanned Unit 2 On-Line Risk (OLR) Orange
Condition, April 7, 2008
EST 08-0242; Abnormal Component Position 1SX033, April 5, 2008
Byrons Archival Operations Narrative Logs, March 31, 2008 to April 7, 2008
B1R15 Shutdown Risk; April 5, 2008 and April 6, 2008
BYR-1SX034; Diagnostic Test Instructions - Control Circuit Changes to Support Testing,
April 7, 2008
Draft Unplanned Unit 2 On-Line Risk (OLR) Orange Condition Root Cause Investigation Report
PBI 07-513; Plant Barrier Impairment Permit
WC-AA-101; Attachment 6 Unavailability Guidelines, Revision 14
0B0A PRI-8; Auxiliary Building Flooding Unit 0, Revision 0
1BOA PRI-7; Essential Service Water Malfunction Unit 1, Revision 104
2BOA PRI-7; Essential Service Water Malfunction Unit 2, Revision 105
BB PRA-017.91B; Byron SDP Evaluation of Failure to Conduct a Risk Evaluation Prior to
Disabling 1SX033 and 1SX034 Remote Isolation Capability, Revision 0
BOP SX-22; Essential Service Water Leak Isolation, Revision 0
BAR 0PLO1J-9B1; Essential Service Water Pump 2A Leak Detected - Pump Level High,
Revision 1
Diagram of Essential Service Water; M-42 Sheet Number 3, Revision AZ
Diagram of Essential Service Water; M-42 Sheet Number 5A &5B Revision AE
Diagram of Essential Service Water; M-42 Sheet Number 1A & 1B, Revision AN
Diagram of Essential Service Water; M-42 Sheet Number 2A & 2B Revision AW
Corrective Action Documents as a Result of NRC Inspection
IR 773344; DC Emergency Light 0LL076E is Malfunctioning, May 8, 2008
Section 1R15: Operability Evaluations
Analysis No. ATD-0111; Containment Flood Level, Revision 013D
Analysis No. BYR2000-180; Available Margin for Miscellaneous Hydrogen Producing Materials
in the Byron Unit 1 and 2 Containment Buildings, Revision 8
Calculation No. CN-LIS-00-55; LBL0CA/SBL0CA Evaluation of Revised Containment Data for
Byron/Braidwood Units 1 and 2 (CAE/CBE/CCE/ CAE), Revision 0
7 Attachment
EC 370179; Machining of Flange Surface of 1B AF Diesel Exhaust Manifold, Revision 0
EC 370163; Operations Evaluation 08-005, 1B/2B AF Diesel Insulation, Revisions 1 & 2
EC 370270; Foreign Material (Scaffold) Potentially Left in Unit 1 Containment for a Cycle,
Revision 000
EC 370369; Past Operability of the 1B AF Pump with Respect to Exhaust Manifold Fire,
Revision 0
EC 333036; Install Scaffold Saddles on 401 IMB Between SG AD and BC. This EC
Incorporates All Permanent Scaffold Storage Requirements for Containment, Revision 000
EC No. 362730; Foreign Material Not Recovered From Unit 1 ECCS Sump Trash Rack Area,
Revision 000
EC 363000; Evaluation for Foreign Material Left in Unit 1 Containment, Revision 000
EC 366163 01; OP Evaluation 07-005 Unventable Gas Voids in Containment Recirculation
Pump Piping, February 12, 2008
EC Request 147981; DG: Sealant for Exterior of Intake to Head Flange Interface, June 24, 1999
EC Request 072499; DG Intake Manifolds Leaking Air Around Flange, January 12, 1996
EC Request 358726; Evaluate Permanent/Temporary Repair for Oil Leakage Coming from what
Appears to be the CAM Housing Gasket Area, February 26, 2003
IR 493593; 2A DG Minor Air Leak on L8 Cylinder Head Intake Flange, May 25, 2006
IR 727020; Unexpected 2C SI Accumulator Level Drop, January 25, 2008
IR 729265; Gas Void UT Exam Results for Unit 2 SI, January 30, 2008
IR 753008; Cause of 1B AF Pump Fire Conditions May Exist on 2B AF Pump, March 21, 2008
IR 753012; During 1B AFW Pump Test an Oil Leak Developed with Flames, March 21, 2008
IR 753383; Starter Motor Shorted during Pump Start, March 23, 2008
Quick Human Performance Investigation Report on IR 753383
IR 755140; 1RH619 Failed Open, March 26, 2008
IR 759028; As Found Results of 1B AF Exhaust Manifolds Out of Spec, April 3, 2008
IR 760408; Insulation in Poor Condition, April 8, 2008
IR 761633; VTIP Information Conflicts with As Built, April 10, 2008
IR 763216; AF System to Remain Yellow in Ship, April 14, 2008
IR 771208; ECs for Equipment Stored in Containment Due to GSI-191, May 2, 2008
IR 775293; Need a WR to Resolve Potential Failure of RH Valves, May 14, 2008
IR 776353; Void Found at 2SI8811A After 2A RH Pump Window, May 16, 2008
IR 756739; Scaffold Left IMB Since B1R14, March 30, 2008
IR 765637; Fires Involving Diesel Engine Exhaust Manifolds, April 21, 2008
IR 779122; Gas Void Discovered After Fill & Vent of 1A RH Suction, May 23, 2008
IR 783173; Delamination Issue with Valve Cover Gasket for AF Diesel, June 5, 2008
WO Task; 934752 01; MM-2DG01KA-24 Month Mechanical Inspection, April 24, 2008
WC-BY-106; Condition Based Monitoring Program, Appendix A, Revision 1
BYR-92045; Evaluation of Exhaust Manifold Gaskets from the Byron 1B AF Pump Diesel
Engine, April 7, 2008
BYR-92276; Laboratory Examination of Insulation from the Byron Unit 1 1B AF Pump Diesel
SW Exhaust Manifold, April 4, 2008
IR 776484; Additional Voiding at 2SI8811A After 2A RH Pump Window, May 16, 2008
IR 783051; Check Rocker Covers for Flatness at Next Work Window, April 9, 2008
IR 783052; Check Rocker Covers for Flatness at Next Work Window, April 9, 2008
Report Number 2008-418; Ultrasonic Examination for 2SI06BB-24, May 16, 2008
Report Number 2008-419; Ultrasonic Examination for 2SI06BB-24, May 16, 2008
Report Number 2008-432; Ultrasonic Examination for 1A RH Suction Line, May 23, 2008
Report Number 2008-434; Ultrasonic Examination for 1A RH Suction Line, May 24, 2008
Report Number 2008-436; Ultrasonic Examination for 1A RH Suction Line, May 27, 2008
8 Attachment
NRC Generic Letter 2008-01; Managing Gas Accumulation in Emergency Core Cooling, Decay
Heat Removal, and Containment Spray Systems, January 11, 2008
Corrective Action Documents as a Result of NRC Inspection
IR 786168; Limited Operations Involvement in Past Operability Calls, June 13, 2008
IR 778656; NRC Questions on Positioners for RH Valves, May 22, 2008
Section 1R19: Post Maintenance Testing
WO 0112/189; PMT ESF Relay K602B Start for OE Charcoal Booster Fan, May 7, 2008
WO 920901 02; OPS PMT Functional 0VA052Y, May 7, 2008
WO 792520 01; Replace Aux FW Pump 1B Eng Fuel Shutoff Solenoid
WO 868574 02; OPS PMT Stroke Damper Run 0VA03CE, May 7, 2008
WO 884583-01; Calibration of Component Cooling Pump OC Suction Pressure Indicator,
0PI-069, November 16, 2006
WO 884584-01; Calibration of Component Cooling Pump Discharge Pressure Indicator,
1PI-0673, December 6, 2006
WO 961008 01; Auxiliary Feedwater Diesel Prime Mover Inspection, April 10, 2008
WO 961101 02; Start/Stop 1B AF PP Locally From MCR
WO 961715 03; Verify 1B AF Diesel Starts and Does Not Trip
WO 962127 01; 1B AF Pump Emergency Actuation Signal Verification Test, April 12, 2008
WO 997550 03; OPS PMT - Startup Unit 1 AF Diesel, Verify No Unexpected Alarms
WO 1037480-04; Unit 0 Back Flow Test for Component Cooling Discharge Check Valve
0CC9464, May 19, 2008
WO 1139777 01; 1B PP Shaft Collar Shifted BY - 3/4 inch, June 04, 2008
WO Task 01139777 02; OPS PMT Verify Inboard/Outboard Shaft Bushings in Proper
Orientation, June 4, 2008
WO 525537-08; Unit 0 Comprehensive In-service Testing (IST) Surveillance Requirements for
Component Cooling Pump 0CC01P, May 19, 2008
WO Task 961104 02; Verify the AF Diesel Starts from Both Battery Banks, April 12, 2008
Schematic Diagram; Auxiliary Building Non-Accessible Area Exhaust Filter Plenum C Charcoal
Booster Fans 0B & 0E Isolation & Control Dampers - 0VA086yA, 0VA067YA&B, 0VA023YA&B,
Revision L
IR 781947; Request Calibration Check on CC Pump Discharge Gauge for ASME Test,
June 2, 2008
IR 781948; Request Calibration Check on CC Pump Suction Press Gauge for ASME Test,
June 2, 2008
IR 782306; 1B CV PP Shaft Collar Shifted BY - 3/4 inch, June 03, 2008
EC 357768; Replace Pressure Gauges to Improve Accuracy for IST Testing, Revision 001,
January 26, 2007
Service Request 13127; Various CC Instrument Loops Calibration Frequency Change,
September 15, 2002
Corrective Action Documents as a Result of NRC Inspection
IR 782298; NRC Question Concerning Instrument Calibrations, June 3, 2008
9 Attachment
Section 1R20: Refueling and Outage Activities
WO 885776 01; IM Calibrate and Install New Press Indicator 1PI-AF058, Per EC 357770
WO 885779 01; IM Calibrate and Install New Press Indicator 1PI-AF151, Per EC 357770
WO 01001347 01; 1AF01PB Comprehensive IST Requirements for the Diesel Driven AF PMP,
April 29, 2008
WO 972033; Unit 1 PRT Slow Fill Rate - Inspect 1PW005 During B1R15, March 14, 2008
IR 753603; RY Surge Line Insulation Damaged, March 24, 2008
IR 768943; Adverse Atmosphere for 1B AF PP Rounds, April 29, 2008
IR 768955; Room Uninhabitable During 1B AF PP Full Flow Test, April 29, 2008
IR 762543l 1B AF PP Exhaust Leaks and Cancer, April 12, 2008
IR 768979; 1B AF Diesel Gear Box and Right Angle Gear Drive VIBS High, April 29, 2008
Selected B1R15 Shutdown Risk, April 1 - April 14, 2008
Selected B1R15 OCC Turnover, April 1 - April 14, 2008
Selected B1R15 Outage News, April 1 - April 14, 2008
Corrective Action Documents as a Result of NRC Inspection
IR 00758286; NRC Identified Concern Over Timeliness of repair of UFSAR Function,
April 2, 2008
Section 1R22: Surveillance Testing
WO 979055 01; Unit 2 Fire Hazards Panel Instrumentation 18 Month Surveillance,
May 17, 2008
WO 1120857 01; 2BOSR 7.5.4-2, 2B AF PP Run
1BOSR 3.g.3-1; Unit 1 Reheat and Intercept Valve Quarterly Surveillance, Revision 13
2BOSR 6.6.2-1; Unit 2 Reactor Containment Fan Cooler Monthly Surveillance, Revision 19
1BVSR 8.4.2-2; Unit 1 BUS 112 125V Battery Charger Operability, Revision 3
IR 742714; Implement RCS Leak Rate Recommendations in OG-07-387, February 29, 2008
IR 647077; RCS Leak-rate Program (Applies to Both Units), July 3, 2007
IR 707153; Unit 2 RCS Leak-rate Procedures, December 4, 2007
IR 709143; 1/2 BOSR 4.13.1-2 Utilize Same RCS Volume Number, December 8, 2007
NFS Memo PSA: 97-005; Braidwood Unit 1/2 RCS Leakage Rate, February 26, 1997
Reactor Coolant System Leak-rate Package Software Design Description; PCS Product
Number GN05038, Revision 0.1 October 5, 1988, date signed January 18, 1989
2BOSR 4.13.1-2; Reactor Coolant System Water Inventory Balance Daily Surveillance Manual
Calculation
2BOSR 4.13.1-1; Unit 2 Reactor Coolant System Water Inventory Balance Daily Surveillance
Computer Calculation, Revision 16
Document Identification Number SSS-89-002, Revision 1.1; Functional Requirement
Specification for the Reactor Coolant System Leakage Rate Program, March 1, 1989
Document Identification Number PSA-B-97-02; Braidwood Unit 1/2 RCS Leakage Rate Statistical
Analysis, February 26, 1997
Document Identification Number SSS-88-001; Functional Requirement Specification for the
Reactor Coolant System Leakage Rate Program, Revision 1
10 Attachment
Corrective Action Documents as a Result of NRC Inspection
IR 619429; Questions on RCS Leak-rate Methods, April 19, 2007
IR 753983; NRC Identified Potential Discrepancies with RCS Leak-rate Calculations,
March 24, 2008
IR 777782; NRC Identified Error in Completed 2BOSR XFP-R1 Surveillance, May 20, 2008
Corrective Action Documents as a Result of NRC Inspection
IR 767699; NRC Resident Reported Significant Oil Buildup on 2B CV Pump, April 25, 2008
IR 770647; Air Intake Leak on 1B DG, April 30, 2008
IR 770651; Diesel Fuel Leak on 1B DG, April 30, 2008
IR 779045; NRC Identified Corrosion on Alternate Train SX Blow-down Vent Piping,
May 23 2008
Corrective Action Documents as a Result of NRC Inspection
IR 757172; Lessons Learned on Report Outs on NRC IRC Status Calls, March 31, 2008
Section 1E92: EP
Byron Off-Site Siren Test Plan; April 2008
IR 00491028; ANS Servicing Byron EPZ Reached 25% Unavailability; May 17, 2006
IR 00510166; One Off-Site Alert and Notification System Siren Lost Power; July 17, 2006
IR 00510239; Warning Siren Failure During Thunderstorm; July 17, 2006
IR 00510575; 25% Inoperability of the Byron Station ANS Due to Loss of AC; July 18, 2006
IR 00707169; Winter Storm Causing Siren Power Outage; December 4, 2007
IR 00490356; Loss of 28 EPZ Sirens Due to Offsite Power Issue; May 16, 2006
Byron Plant Warning System Maintenance and Operational Report; March 13 - June 7, 2007
Byron Plant Warning System Maintenance and Operational Report; February 16 - May 19, 2006
Annual Siren Daily Operability Reports; 2006 - 2008
Siren Monthly Operability Report - Byron Monthly Siren Availability Report (Telemetry);
2006 - 2008
An Off-Site Emergency Plan Prompt Alert and Notification System Addendum for the Byron
Nuclear Power Station, submitted by: Illinois Emergency Management Agency and
Commonwealth Edison Company; October 1992
Exelon Semi-Annual Siren Report; January 1 - June 30, 2007
Exelon Semi-Annual Siren Report; July 1 - Dec. 31, 2007
Section 1EP3: ERO Augmentation Testing
EP-AA-1000; Exelon Nuclear Standardized Radiological Emergency Plan, Section B;
Emergency Response Training; Revision 19
EP-AA-1000; Exelon Nuclear Standardized Radiological Emergency Plan, Part II, Section B,
Table B-1; Revision 19
EP-AA-122-1001; Drill & Exercise Scheduling, Development and Conduct; Revision 9
EP-AA-112-100-F-01; Shift Emergency Director Checklist; Revision H
EP-AA-112-100-F-06; Midwest ERO Notification or Augmentation; Revision G
IR 00474834; On-Call Emergency Response Organization Failed to Respond to Call In Drill,
April 3, 2006
IR 00476632; EP-AA-1221001 T& RM Non-Compliance (Drive in Drills), April 9, 2006
11 Attachment
IR 00681706; OSC RP Group Lead/Asst. OSC Director Not Available for Duty, October 8, 2007
IR 00682166; Degraded Performance in Alpha Pager Response, October 9, 2007
Unannounced, Off-Hour Call-in Drill Results and Records, February 2006 - January 2008
Memorandum; Exelon Nuclear Byron Station EP-ERO Expectations, January 25, 2008
Memorandum; Emergency Response Organization Roster, April 2008
Section 1EP5: Correction of EP Weaknesses and Deficiencies
EP-AA-1002; Emergency Action level HA7, Revision 21 and 22
EP-AA-120F-05; Event Review Checklist, Revision A
RP-AA-440; Respiratory Protection Program, Revision 8
LS-AA-126-1005; 2008 NRC EP Baseline Program Inspection Readiness Assessment,
Revision 3
IR 00559030; NSRB Comments of Emergency Preparedness, November 16, 2006
IR 00624526; NOS ID: RP Issue with EP Equipment, May 2, 2007
IR 00625086; Meteorology Instrument Accuracy Does Not Meet Requirements, May 3, 2007
IR 00621691; NOS ID Inconsistent Requirements Between EOF Director Checklist and E-Plan,
April 25, 2007
IR 00698053; EP Baseline Inspection Check-In, November 12, 2007
IR 00639899; Byron EP Pre-Exercise Low Level OSC Items, June 13, 2007
IR 00640485; NOS ID Review EP Pre-Exercise Conclusion for Potential DEP Failure,
June 14, 2007
IR 00636115; DEP Hit and Failed Objective EP Pre-Exercise, June 1, 2007
IR 00651666; Byron 07 EP Exercise TSC Failed Demonstration Criteria, July 19, 2007
IR 00638881; Byron Pre-Exercise TSC Failed Demonstration Criteria, June 10, 2007
IR 00638883; Byron Pre-Exercise OSC Failed Demonstration Criteria, June 10, 2007
IR 00708316; ERO Response to ALERT on 11/27/2007, December 6, 2007
IR 00709554; Training - LORT Cycle 07-06 EP Roll Up, December 10, 2007
IR 00709563; Training - Week 4 Annual and Comprehensive Written, December 10, 2007
IR 00708906; NRC Follow-up Question on November 27, 2007, Alert, December 7, 2007
IR 00708316; Emergency Response Organization Response to Alert, November 27, 2007
IR 00704697; Emergency Operations Center Communicator Failed to Meet EP Expectations,
November 28, 2007
IR 00703919; Apparent Cause Report, Alert (HA7) Declared Due to Low Oxygen Levels in 1B
Containment Spray Pump Room, November 27, 2007
Byron 2007 NARS/PARS/EALs Performance Indicator Drills, November 13 - December 4, 2007
Byron 2007 EP/Security Integrated Drill Findings and Observation Report, November 15, 2007
Byron Nuclear Power Station In-Plant Health Physics Drill Report First Half 2007, June 25, 2007
Byron 2007 NRC Graded Exercise Evaluation Report, June 20, 2007
Byron Station Alert Event Report for 11/27/2007, December 26, 2007
NOSA-BYR-06-03, IR 437588; Byron Station Emergency Preparedness Audit for 4/10 through
4/14/2006, April 18, 2006
NOSA-BYR-07-04, IR 571163; Emergency Preparedness Audit for 4/30 through 5/4/2007,
May 9, 2007
NOSA-NCS-06-03, IR 469749; Emergency Preparedness Audit Report
NOSA-NCS-07-04, IR 574311; Emergency Preparedness Audit Report, Cantera and Kennett
Square
NO-AA-1024, Attachment 1; NOS Objective Evidence Report, April 28, 2006 & May 18, 2007
Byron EP Information Newsletter #08-01, January 2008
Byron EP Information Newsletter #08-03, March 2008
12 Attachment
Memo to M. Snow from D. Drawbaugh; Byron Station November 27, 2007, Alert Event Report,
December 26, 2007
Letter to D. Smith from W. King; FEMA Conditional Approval of IEMA 11/14/2007 ANS
Proposal, March 19, 2008
Nuclear Accident Report System Form, November 27, 2007
Section 40A1: Performance Indicator Verification
EP-AA-125-1001; EP Performance Indicator Guidance, Revision 5
EP-AA-125-1002; ERO Performance - Performance Indicator Guidance, Revision 4
EP-AA-125-1003; ERO Readiness - Performance Indicator Guidance, Revision 6
EP-AA-125-1004; Emergency Response Facilities and Equipment Performance Indicator
Guidance, Revision 4
IR 00648201; Training - LORT WD.3E OBE Failure Rate PI in Variance, July 9, 2007
NRC Emergency Response Organization Drill Participation Records, April - December, 2007
LS-AA-2110; Monthly Data Elements for NRC Drill/Exercise Participation, April -
December, 2007
LS-AA-2120; Monthly Data Elements for NRC Drill/Exercise Performance,
April-December, 2007
Section 40A2: Identification and Resolution of Problems
OP-AA-101-113-1001; Station event Free Clock Program, Revision 4
Section 40A3: Event Followup
0B0A ENV-4; Earthquake Unit 0, Revision 102
1B0A-ENV-4; Earthquake Unit 1, Revision 100
2B0A-ENV-4; Earthquake Unit 2, Revision 100
EC 370132 00; Provide Patches for Holes around the Tube Track in RF Sump (1RF02T) Cover
Condition Report 755837; RF Sump Not Constructed in Accordance with Design
LER 454-2008-001-00; Technical Specification Non-Compliance of Containment Sump Monitor
Due to Improper Installation During Original Construction, June 13, 2008
Section 4OA5: Other Activities
EPRI 1010087; Materials Reliability Program: Primary System Piping Butt Weld Inspection and
Evaluation Guideline (MRP-139), July 14, 2005
Byron Letter 2006-0050; Third 10-Year Inservice Inspection Interval, Relief Request 13R-08,
Structural Weld Overlays on Pressurizer Spray, Relief, Safety and Surge Nozzle Safe-Ends and
Associated Alternative Repair Techniques, April 28, 2006
EXE-PDI-108; Ultrasonic Examination of Weld Overlaid Similar and Dissimilar Welds in
Accordance with PDI-UT-8, Revision 0
EXE ISI-11; Liquid Penetrant Examination, Revision 2
PDI-UT-8; Generic Procedure for the Ultrasonic Examination of Weld Overlaid Similar and
Dissimilar Metal Welds, Revision F
PCI WPS 3-8/52-TB MC-GTAW-N638; Ambient Temperature Temper Bead Structural Overlay
Without Elevated Preheat, Revision 5 & 7
PCI WPS 8 MC-GTAW; Grove, Fillet, no PWHT, with Supplement dated 2/21/2007, Revision 10
Westdyne Data Pkg, B1R14-PN-01-SWI; Surge Line Nozzle, September 23, 2006
Westdyne Evaluation B1R14-PN-01-SW1-EVAL-01; Surge Line Nozzle, September 23, 2006
13 Attachment
Westdyne Data Pkg B2R13-PN-03-SW3; PORV Nozzle, April 16, 2007
Westdyne Evaluation B2R13-PN-03-SW3; PORV Nozzle, April 17, 2007
Westdyne Data Pkg B1R14-PN-01-SW1; Surge Line Nozzle, September 23, 2006
Westdyne Evaluation B1R14-PN-01-SW1-Eval-01; Surge Line Nozzle, September 23, 2006
PN-03-F3; Weld Overlay Process Traveler with Sacrificial Layer - Pressurizer Unit 2 PORV
Nozzle, March 27, 2007
PN-01-F1; Weld Overlay Process Traveler - Pressurizer 1RY01 Surge Nozzle,
September 8, 2006
CN-PAFM-06-139; Byron Units 1 and 2 Pressurizer Surge, Spray and Safety and Relief Nozzles
Maximum Allowable Flaw Sizes in Weld Overlay, Revision 5
3SA-096-016; CCI Structural Analysis of Strainer and Support Structure, Revision 3
Service Request 174053; Latent Debris Walkdown - Unit 2, September 27, 2008
Service Request 174052; Latent Debris Walkdown - Unit 1, September 27, 2008
EC 364979; Evaluate SI Throttle Valve Test Results from Wyle Labs to Document Acceptability
of New Trim Design, April 23, 2007
EC 360120; Replace SI Throttle Valve Trim, Bonnet, Stem and Operators, and Remove
Downstream Orifices Plates to Support GSI-191 - Unit 2, Revision 0
EC 359455; Downstream Activities Effects Related to GSI-191 - Unit 1, Revision 0
S040-BY-5010; GSI-191 Latent Debris Collection Unit 1, April 4, 2005
S040-BY-5030; GSI-191 Latent Debris Collection Unit 1, November 15, 2005
S040-BYR-5032; GSI-191 Debris Generation Walkdown - Unit 2, May 8, 2006
S040-BYR-5011; GSI-191 Debris Generation Walkdown - Unit 1, April 8, 2005
BYR05-041; GSI-191 Post-LOCA Debris Generation, Revision 1
BYR05-042; Post-LOCA Debris Transport Evaluation for Resolution of GSI-191, Revision 1
BYR05-061; GSI-191 Evaluation of Long Term Downstream Effects, Revision 2
BYR06-025; Design Loads and Sizing Limitations for the ECCS Containment Sump Trash Rack,
Revision 0
OP-AA-116-101; Equipment Labeling, Revision 1
CC-AA-102; Design Input and Configuration Change Impact Screening, Revision 14
1/2 BOSR Z.5.1.1-1; Containment Loose Debris Inspection, Revision 8
CC-AA-205; Control of Undocumented/Unqualified Coatings Inside the Containment, Revision 4
1/2 BVSR XII-11; Containment Building Interior Surface Coating Inspection, Revision 4
DIT-BYR-06-007; Debris Concentration Measurements Results, January 27, 2006
IR 777152; Actions Related to Latent Debris Surveillance (G2004-02), May 19, 2008
14 Attachment
LIST OF ACRONYMS USED
AC Alternating Current
ALARA As-Low-As-Is-Reasonably-Achievable
ANS Alert and Notification System
ASME American Society of Mechanical Engineers
BACC Boric Acid Corrosion Control
CAP Corrective Action Program
CFR Code of Federal Regulations
CSS Containment Spray System
CV Charging Pump
DMBW Dissimilar Metal Butt Weld
EC Engineering Change
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generator
ERO Emergency Response Organization
EPRI Electric Power Research Institute
ET Eddy Current
GL Generic Letter
GSI Generic Safety Issue
ICDF Incremental Core Damage Frequency
ICDP Incremental Core Damage Probability
ICDPD Incremental Core Damage Probability Deficit
IMC Inspection Manual Chapter
IP Inspection Procedure
IR Issue Report
ISI Inservice Inspection
LER Licensee Event Report
LOCA Loss of Coolant Accident
MRP Material Reliability Program
NCV Non-Cited Violation
NDE Non-destructive Examination
NEI Nuclear Energy Institute
NFPA National Fire Protection Association
NRC U.S. Nuclear Regulatory Commission
OL Operating License
OOS Out of Service
PDI Performance Demonstration Initiative
PI Performance Indicator
PORV Power Operated Relief Valve
PRA Probabilistic Risk Assessment
RMA Risk Management Action
RP Radiation Protection
SAT System Auxiliary Transformer
SDP Significance Determination Process
15 Attachment
SI Safety Injection
SPAR Simplified Plant Analysis Risk Model
SX Essential Service Water System
TI Temporary Instruction
TLD Thermoluminescent Dosimeters
TRM Technical Requirements Manual
TS Technical Specification
TSO Transmission System Operator
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
UT Ultrasonic Testing
WO Work Order 16 Attachment