ML110610641
| ML110610641 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 03/02/2011 |
| From: | Croteau R Division Reactor Projects II |
| To: | Krich R Tennessee Valley Authority |
| References | |
| EA-11-012, EA-11-018 IR-10-005 | |
| Download: ML110610641 (70) | |
See also: IR 05000259/2010005
Text
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
245 PEACHTREE CENTER AVENUE NE, SUITE 1200
ATLANTA, GEORGIA 30303-1257
March 2, 2011
Mr. R. M. Krich
Vice President, Nuclear Licensing
Tennessee Valley Authority
Chattanooga, TN 37402-2801
SUBJECT: NRC REPORT 05000259/2010005, 05000260/2010005, AND
05000296/2010005; PRELIMINARY GREATER THAN GREEN FINDING
BROWNS FERRY NUCLEAR PLANT
Dear Mr. Krich:
This letter discusses a finding that has preliminarily been determined to be Greater than Green,
that is, a finding of greater than very low safety significance resulting in the need for further
evaluation to determine significance and therefore the need for additional NRC action. This
finding involves the failure to establish adequate design control and perform adequate
maintenance on the Unit 1 low pressure coolant injection (LPCI) outboard injection valve,
1-FCV-74-66, resulting in the valve being left in a significantly degraded condition and residual
heat removal (RHR) loop II unable to fulfill its safety function. This finding was assessed based
on the best available information, using the applicable Significance Determination Process
(SDP) and was calculated to have a preliminary conditional core damage probability of 7.3E-4.
A factor that may reduce the preliminary probability result includes a reduction in the period of
exposure time that the valve was in a failed condition. In addition, the ability to maintain reactor
water levels and core cooling through the valve or by other sources may also reduce the
preliminary probability. The final resolution of this finding will be conveyed in separate
correspondence.
This finding was considered more than minor because it was associated with the Protection
Against External Factors attribute of the Reactor Safety/ Mitigating Systems Cornerstone and
adversely affected the cornerstone objective of ensuring availability and reliability of systems
designed to respond to initiating events to prevent undesirable consequences. Specifically, the
RHR loop II subsystem was rendered incapable of being aligned to perform its safe shutdown
function due to the failure of 1-FCV-74-66. Fire risk dominates the impact of this equipment
failure finding. Tennessee Valley Authoritys method for severe fire mitigation at Browns Ferry
implements a strategy that includes actions that procedurally de-energize all Emergency Core
Cooling System (ECCS) equipment and other sources of reactor coolant inventory makeup,
except those credited in the safe shutdown analysis depending upon the specific fire area
affected. This safe shutdown strategy was designed to ensure one protected train of equipment
Enclosure 2 transmitted herewith contains SUNSI. When separated from enclosure 2,
this transmittal document is decontrolled.
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TVA 2
would be available to mitigate a 10 CFR 50, Appendix R related fire in any fire area. A key
feature of this strategy was the LPCI function of RHR to provide long term water inventory
makeup and core cooling. However, the failure of 1-FCV-74-66 rendered the licensees safe
shutdown strategy incapable of accomplishing its safe shutdown functions for those fire areas
that specifically rely on RHR Loop II.
The NRC determined that this finding does not represent an immediate safety concern, because
the Browns Ferry staff has, as part of their immediate corrective actions, implemented repairs
and modifications in accordance with design requirements that returned 1-FCV-74-66 to an
operational condition. Also, the Browns Ferry staff conducted an internal inspection of the RHR
Loop I LPCI outboard injection valve (1-FCV-74-52) while the unit was shutdown. The 1-FCV-
74-52 was determined to be intact with no apparent damage or significant degradation.
Furthermore, as extent of condition compensatory measures, the Browns Ferry staff conducted
and continues to perform a combination of internal inspections, partial motor-operated valve
actuator testing, ultrasonic testing, shutdown cooling operation, and/or monthly venting to verify
proper conditions on the Unit 2 and 3, FCV-74-52 and FCV-74-66 LPCI outboard injection
valves.
The finding is also an apparent violation of Unit 1 Technical Specifications (TS) Limiting
Condition for Operations (LCO) 3.5.1, Emergency Core Cooling System (ECCS) - Operating, in
that between March 13, 2009, and October 23, 2010, the Loop II RHR subsystem was
inoperable for a time in excess of the seven day allowed outage time. This apparent violation is
being considered for escalated enforcement action in accordance with the Enforcement Policy,
which can be found on the NRCs Web site at http://www.nrc.gov/about-
nrc/regulatory/enforcement/enforce-pol.html.
In accordance with NRC 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 the date of the enclosed report. The significance determination
process encourages an open dialogue between the NRC staff and the licensee; however, the
dialogue should not impact the timeliness of the staffs final determination.
Before we make a final decision on this matter, we request your attendance at a Regulatory
Conference where you can present to the NRC your perspective on the facts and assumptions
the NRC used to arrive at the finding and assess its significance. The Regulatory Conference
will be open for public observation. We will contact you separately regarding the final
arrangements for the conference. The Regulatory Conference 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
you decline a Regulatory Conference, you relinquish your right to appeal the final SDP
determination, in that by not doing so, you fail to meet the appeal requirements stated in the
Prerequisite and Limitation sections of Attachment 2 of IMC 0609.
Please contact Eugene Guthrie at 404-997-4662 and in writing within 10 days from the issue
date of this letter to notify the NRC of your intentions. If we have not heard from you within 10
days, we will continue with our significance determination and enforcement decision. The final
resolution of this matter will be conveyed in separate correspondence.
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TVA 3
Because 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. In addition, please be advised that the
number and characterization of the apparent violation described in the enclosed inspection
report may change as a result of further NRC review.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and
Enclosure 1 will be made available electronically for public inspection in the NRC Public
Document Room or from the NRCs document system (ADAMS), accessible from the NRC Web
site at http://www.nrc.gov/reading-rm/adams.html. However, because of the security-related
information contained in Enclosure 2, and in accordance with 10 CFR 2.390, a copy of
Enclosure 2 will not be available for public inspection.
Sincerely,
/RA/
Richard P. Croteau, Director
Division of Reactor Projects
Docket No.: 50-259
License No.: DPR-33
Enclosures: 1. NRC Inspection Report 05000259/2010005, 05000260/2010005, and
2. SDP Phase 3 Summary (OFFICIAL USE ONLY - SECURITY-
RELATED INFORMATION)
cc w/encl: (See page 4)
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_________________________ G SUNSI REVIEW COMPLETE
OFFICE RII:DRP RII:DRP RII:DRP RII:EICS RII:DRS OE NRR
SIGNATURE EFG /RA/ WBJ /RA/ RXC /RA/ CFE /RA/ RHB /RA/ Via email Via email
NAME EGuthrie WJones RCroteau CEvans RBernhard CHolt MAshley
DATE 03/01/2011 03/01/2011 03/02/2011 03/01/2011 03/01/2011 02/28/2011 02/28/2011
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
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cc w/encl: James L. McNees, CHP
K. J. Polson Director
Vice President Office of Radiation Control
Browns Ferry Nuclear Plant Alabama Dept. of Public Health
Tennessee Valley Authority P. O. Box 303017
Electronic Mail Distribution Montgomery, AL 36130-3017
C.J. Gannon
General Manager
Browns Ferry Nuclear Plant
Tennessee Valley Authority
Electronic Mail Distribution
J. E. Emens
Manager, Licensing
Browns Ferry Nuclear Plant
Tennessee Valley Authority
Electronic Mail Distribution
T. C. Matthews
Manager, Corporate Nuclear Licensing -
Tennessee Valley Authority
Electronic Mail Distribution
State Health Officer
Alabama Dept. of Public Health
RSA Tower - Administration
Suite 1552
P.O. Box 30317
Montgomery, AL 36130-3017
E. J. Vigluicci
Assistant General Counsel
Tennessee Valley Authority
Electronic Mail Distribution
Chairman
Limestone County Commission
310 West Washington Street
Athens, AL 35611
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Letter to R. M. Krich from Richard P. Croteau dated March 2, 2011
SUBJECT: NRC REPORT 05000259/2010005, 05000260/2010005, AND
05000296/2010005; PRELIMINARY GREATER THAN GREEN FINDING
BROWNS FERRY NUCLEAR PLANT
Distribution w/encl:
RidsNrrPMBrownsFerry Resource
C. Evans, RII
L. Douglas, RII
B. Westreich, NSIR
E. McNiel, NSIR
RIDSNRRDIRS
OE Mail
Public
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
245 PEACHTREE CENTER AVENUE NE, SUITE 1200
ATLANTA, GEORGIA 30303-1257
February 9, 2011
Mr. R. M. Krich
Vice President, Nuclear Licensing
Tennessee Valley Authority
3R Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION
REPORT 05000259/2010005, 05000260/2010005, 05000296/2010005, AND
NOTICE OF VIOLATION
Dear Mr. Krich:
On December 31, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Browns Ferry Nuclear Plant, Units 1, 2, and 3. The enclosed inspection
report documents the inspection results which were discussed on January 11, 2011 with Mr.
Keith Polson 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, orders, and with the conditions of your
license. The inspectors reviewed selected procedures and records, observed activities, and
interviewed personnel.
This report documents one self-revealing apparent violation (AV) concerning the failure of a Unit
1 Residual Heat Removal (RHR) system low pressure injection valve. This violation has
potential safety significance greater than very low safety significance (Green). The violation did
not present an immediate safety concern because Unit 1 was shutdown for a refueling outage
and the other division of RHR was operable and available for service. Additionally, the licensee
repaired the low pressure injection valve prior to the startup of Unit 1. This violation with the
supporting circumstances and details are documented in the inspection report.
Additionally, the NRC has determined that a Severity Level IV violation of NRC requirements
occurred. The violation was evaluated in accordance with the NRC Enforcement Policy. This
violation is cited in the enclosed Notice of Violation (EA-11-012) and the circumstances
surrounding it are described in detail in the subject inspection report. The violation is being
cited in the enclosed Notice because information provided in the second revision of LER
05000296/2009-003 was also not complete and accurate in all material respects. This violation
is being cited because the criterion specified in Section 2.3.2.a.3 of the NRC Enforcement
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Enclosure 1
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TVA 2
Policy for a non-cited violation was not met. This criterion was not met because the violation
was repetitive and identified by the NRC. The initial violation, also identified by the NRC, was
documented in NRC inspection report 50-296/2010-003. The current Enforcement Policy is
included on the NRC's Web site at http://www.nrc.gov/about-nrc/regulatory/enforcement/
enforce-pol.htmlhttp://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.
You are required to respond to this letter and should follow the instructions specified in the
enclosed Notice when preparing your response. If you have additional information that you
believe the NRC should consider, you may provide it in your response to the Notice. The NRC
review of your response to the Notice will also determine whether further enforcement action is
necessary to ensure compliance with regulatory requirements.
Furthermore, this report contains one self-revealing finding that was evaluated under the risk
significance determination process as having very low safety significance (Green). The NRC
has also determined that a violation is associated with this finding. This violation is being
treated as a Non-Cited Violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy.
The NCV is described in the subject inspection report. If you contest this violation or
significance of the NCV, you should provide a response within 30 days of the date of this
inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington DC 20555-0001, with copies to: (1) the Regional
Administrator, Region II; (2) the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001; and (3) the Senior Resident Inspector at
Browns Ferry Nuclear Plant.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its
enclosure, and your response, will be available electronically for public inspection in the NRC
Public Document Room or from the Publicly Available Records (PARS) component of the NRCs
document system (ADAMS),accessible from the NRC Web site at http://www.nrc.gov/reading-
rm/adams.html. To the extent possible, your response should not include any personal, privacy
or proprietary information so that it can be made available to the public without redaction.
Sincerely,
/RA/
Eugene F. Guthrie, Chief
Reactor Projects Branch 6
Division of Reactor Projects
Docket Nos.: 50-259, 50-260, 50-296
License Nos.: DPR-33, DPR-52, DPR-68
Enclosures:
1. Notice of Violation
2. NRC Integrated Inspection Report 05000259/2010005, 05000260/2010005,
cc w/encl. (See page 3)
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Enclosure 1
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TVA 3
cc w/encl:
K. J. Polson
Vice President
Browns Ferry Nuclear Plant
Tennessee Valley Authority
P.O. Box 2000
Decatur, AL 35609
C. J. Gannon
General Manager
Browns Ferry Nuclear Plant
Tennessee Valley Authority
P.O. Box 2000
Decatur, AL 35609
J. E. Emens
Manager, Licensing and Industry Affairs
Browns Ferry Nuclear Plant
Tennessee Valley Authority
P.O. Box 2000
Decatur, AL 35609
E. J. Vigluicci
Assistant General Counsel
Tennessee Valley Authority
6A West Tower
400 West Summit Hill Drive
Knoxville, TN 37902
State Health Officer
Alabama Dept. of Public Health
RSA Tower - Administration
Suite 1552
P.O. Box 30317
Montgomery, AL 36130-3017
Chairman
Limestone County Commission
310 West Washington Street
Athens, AL 35611
James L. McNees, CHP
Director
Office of Radiation Control
Alabama Dept. of Public Health
P. O. Box 303017
Montgomery, AL 36130-3017
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Enclosure 1
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TVA 4
Letter to R. M. Krich from Eugene Guthrie dated February 9, 2011
SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION
REPORT 05000259/2010005, 05000260/2010005, 05000296/2010005, AND
NOTICE OF VIOLATION
Distribution w/encl:
C. Evans, RII
L. Douglas, RII
OE Mail
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NOTICE OF VIOLATION
Tennessee Valley Authority Docket No. 50-296
Browns Ferry Nuclear Plant License No. DPR-68
During an NRC inspection conducted on December 6, 2010, a violation of NRC requirements
was identified. In accordance with the NRC Enforcement Policy, the violation is listed below:
10 CFR 50.9, Completeness and Accuracy of Information, stated in part, that
Information provided to the Commission by a licensee shall be complete and accurate
in all material respects.
Contrary to the above, on August 31, 2010, the licensee submitted a revised LER, as a
corrective action for a previous 10 CFR 50.9 violation involving inoperability of the Unit 3
RCIC system, that was not complete and accurate in all material respects. The revised
LER did not report the correct event date, nor did it describe prior corrective actions
(e.g., maintenance and testing) taken for a previous related event and why these
corrective actions did not prevent recurrence (as specifically detailed in NCV
This is a Severity Level IV violation.
Pursuant to the provisions of 10 CFR 2.201, the Tennessee Valley Authority is hereby required
to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional
Administrator, Region II, and a copy to the NRC Senior Resident Inspector at the facility that is
the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of
Violation (Notice). This reply should be clearly marked as a "Reply to a Notice of Violation; EA-
11-012" and should include for each violation: (1) the reason for the violation, or, if contested,
the basis for disputing the violation or severity level, (2) the corrective steps that have been
taken and the results achieved, (3) the corrective steps that will be taken, and (4) the date when
full compliance will be achieved. Your response may reference or include previous docketed
correspondence, if the correspondence adequately addresses the required response. If an
adequate reply is not received within the time specified in this Notice, an order or a Demand for
Information may be issued as to why the license should not be modified, suspended, or
revoked, or why such other action as may be proper should not be taken. Where good cause is
shown, consideration will be given to extending the response time. If you contest this
enforcement action, you should also provide a copy of your response, with the basis for your
denial, to the Director, Office of Enforcement, United States Nuclear Regulatory Commission,
Washington, DC 20555-0001.Because your response will be made available electronically for
public inspection in the NRC Public Document Room or from the NRCs document system
(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to
the extent possible, it should not include any personal privacy, proprietary, or safeguards
information so that it can be made available to the public without redaction. If personal privacy
or proprietary information is necessary to provide an acceptable response, then please provide
a bracketed copy of your response that identifies the information that should be protected and a
redacted copy of your response that deletes such information. If you request withholding of
such material, you must specifically identify the portions of your response that you seek to have
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Enclosure 1
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2
withheld and provide in detail the bases for your claim of withholding (e.g., explain why the
disclosure of information will create an unwarranted invasion of personal privacy or provide the
information required by 10 CFR 2.390(b) to support a request for withholding confidential
commercial or financial information). If safeguards information is necessary to provide an
acceptable response, please provide the level of protection described in 10 CFR 73.21.
In accordance with 10 CFR 19.11, you may be required to post this Notice within two working
days of receipt.
Dated this 9th day of February 2011.
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Enclosure 1
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.: 50-259, 50-260, 50-296
License Nos.: DPR-33, DPR-52, DPR-68
Report No.: 05000259/2010005, 05000260/2010005, 05000296/2010005
Licensee: Tennessee Valley Authority (TVA)
Facility: Browns Ferry Nuclear Plant, Units 1, 2, and 3
Location: Corner of Shaw and Nuclear Plant Roads
Athens, AL 35611
Dates: October 1, 2010 through December 31, 2010
Inspectors: T. Ross, Senior Resident Inspector
C. Stancil, Resident Inspector
P. Niebaum, Resident Inspector
L. Pressley, Resident Inspector
A. Rogers, Reactor Inspector (1R08)
R. Baldwin, Senior Operations Engineer (1R11.2)
E. Lea, Senior Operations Engineer (1R11.3)
G. Johnson, Operations Engineer (1R11.3)
C. Kontz, Senior Project Engineer (4OA2.4, 4OA5.4)
M. King, Senior Project Inspector (4OA2.4)
J. Wray, Senior Enforcement Specialist (4OA5.4)
L. Jarriel, Agency Allegation Advisor (4OA5.4)
Approved by: Eugene F. Guthrie, Chief
Reactor Projects Branch 6
Division of Reactor Projects
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Enclosure 1
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SUMMARY OF FINDINGS
IR 05000259/2010005, 05000260/2010005, 05000296/2010005; 10/01/2010 - 12/31/2010;
Browns Ferry Nuclear Plant, Units 1, 2 and 3; Refueling and Other Outage Activities, Event
Follow-up.
The report covered a three month period of inspection by the resident inspectors, two senior
reactor operations engineers, a reactor operations engineer, two senior project engineers and a
reactor inspector from Region II. One apparent violation (AV), one severity level IV cited
violation (VIO), and one non-cited violation (NCV) were identified. The significance of most
findings is identified by their color (Green, White, Yellow, Red) using Inspection Manual Chapter
(IMC) 0609, Significance Determination Process (SDP); the cross-cutting aspect was
determined using IMC 0310, Components Within the Cross-Cutting Areas. 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-Revealing Findings
Cornerstone: Mitigating Systems
(TBD). A self-revealing Apparent Violation (AV) of Unit 1 Technical Specifications
(TS) Limiting Condition for Operations (LCO) 3.5.1, Emergency Core Cooling System
(ECCS) - Operating, was identified for the licensees failure to comply with the TS
LCO required actions for an inoperable Residual Heat Removal (RHR) and Low
Pressure Coolant Injection (LPCI) subsystem due to a failure of the RHR Loop II
LPCI Outboard Injection Valve (1-FCV-74-66) to open. The licensee entered this
issue into their corrective action program as problem evaluation report (PER)
271338. The 1-FCV-74-66 was subsequently repaired and returned to service
during the Unit 1 outage prior to restart.
This finding has potential safety significance greater than very low safety significance
(Green) and will remain indeterminate pending completion of the significance
determination process. The inspectors determined that the licensees failure to
establish adequate design control and perform adequate maintenance on the Unit1
outboard LPCI injection valve, 1-FCV-74-66, which resulted in the valve being left in
a significantly degraded condition and RHR loop II unable to fulfill its safety function,
was a performance deficiency. This finding was considered more than minor
because it was associated with the Protection Against External Factors attribute of
the Reactor Safety/ Mitigating Systems Cornerstone and adversely affected the
cornerstone objective of ensuring availability and reliability of systems designed to
respond to initiating events to prevent undesirable consequences. Specifically, the
RHR subsystem was rendered incapable of being aligned to perform its safe
shutdown function due to the failure of 1-FCV-74-66. The safety characterization of
this finding is not yet finalized and is currently characterized as To Be Determined
(TBD). This finding does not have a cross-cutting aspect because it is not reflective
of current licensee performance in the last three years. (Section 1R20.1(1))
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Enclosure 1
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3
- Green. A self-revealing non-cited violation (NCV) of Unit 1 Technical Specifications
(TS) Limiting Condition for Operations (LCO) 3.6.2.3, Suppression Pool Cooling was
identified for the licensees failure to correct a degraded condition of the 1C Residual
Heat Removal (RHR) pump motor that rendered it inoperable for greater than the TS
allowed outage time of 30 days. Specifically, the 1C RHR pump motor suffered a
catastrophic failure on October 27, 2010 and was subsequently determined to have
been in a degraded condition since November 2007. This condition would have
prevented the pump from performing its intended safety functions during the
systems required mission time. The licensee entered this issue into the corrective
action program as problem evaluation report (PER) 274840. The 1C RHR pump
motor was subsequently repaired during the Unit 1 refueling outage and returned to
service on November 10, 2010 prior to Unit 1 restart.
This performance deficiency was considered greater than minor because it was
associated with the Mitigating Systems cornerstone and adversely affected the
equipment performance objective to ensure the availability and capability of the RHR
system to respond to initiating events to prevent undesirable consequences (i.e.,
core damage). Specifically, the 1C RHR subsystem was degraded to the point that it
was incapable of performing its intended safety functions for the systems required
mission time. Since the 1C RHR pump motor failure occurred during Mode 5
shutdown conditions after a significant period of shutdown cooling operation, the
finding was evaluated according to Inspection Manual Chapter 609, Appendix G,
Shutdown Operations Significance Determination Process, Attachment 1, Phase 1
Operational Checklists, Checklist 7, Refueling Operation with Reactor Coolant Level
Above 23. Accordingly, the finding was determined to be of very low safety
significance (Green) because the 1A RHR pump and the Auxiliary Decay Heat
Removal (ADHR) system were available, when only one RHR pump was needed per
Section I.C of Checklist 7. The cause of this finding was directly related to the cross
cutting aspect of Thorough Evaluation of Identified Problems in the Corrective Action
Program component of the Problem Identification and Resolution area, because the
licensee did not adequately evaluate the precursors related to the degraded 1C RHR
motor performance and properly prioritize the resolution of a known condition
adverse to quality in time to preclude motor failure P.1(c). (Section 1R20.1(2))
B. Licensee Identified Violations
None.
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Enclosure 1
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REPORT DETAILS
Summary of Plant Status
Unit 1 operated at full Rated Thermal Power (RTP) for most of the report period except for three
unplanned downpowers, and a scheduled refueling outage (RFO). On October 4, 2010, an
unplanned downpower to approximately 94 percent RTP occurred due to a power cell failure in
the 1B variable frequency drive (VFD). Unit 1 returned to full RTP later that same day. On
October 23, 2010, Unit 1 was shutdown for a scheduled refueling outage that lasted 31 days.
The unit was restarted on November 22, 2010. During the power ascension, there was a
planned downpower from approximately 60% to 30% RTP on November 24, 2010, for single
loop operations in order to repair a power cell in the 1A VFD. The unit returned to full RTP on
November 25, 2010. On December 2, 2010, Unit 1 experienced an unplanned downpower to
45 percent RTP due to failures of a 1A VFD power cell. The unit returned to full RTP on
December 3, 2010 following repairs to the 1A VFD unit.
Unit 2 operated at essentially full RTP the entire report period except for two planned
downpowers. On October 24, 2010, a planned downpower to 90 percent RTP was conducted
to support a control rod exercise and the unit returned to full RTP later that same day. On
December 11, 2010, a planned downpower to 70 percent RTP was conducted to support a
control rod sequence exchange and the unit returned to full RTP later that same day.
Unit 3 operated at essentially full RTP the entire report period except for three planned
downpowers and one unplanned reactor shutdown. On October 3, 2010, a planned downpower
to 94 percent RTP was conducted for a control rod exercise and the unit returned to full RTP
later that same day. On October 26, 2010 a planned downpower to 93 percent RTP was
conducted for a control rod exercise and the unit returned to full RTP later that same day. On
December 17, 2010 a planned downpower was conducted to support a control rod sequence
exchange and the unit returned to full RTP later that same day. On December 26, 2010, Unit 3
experienced an unplanned downpower to 90 percent RTP followed by a manual reactor scram
due to high vibration on the main generator exciter bearings. Unit 3 remained shutdown through
the end of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
.1 Impending Adverse Weather Conditions - Cold Weather
a. Inspection Scope
On December 13th, 14th and 15th an adverse cold weather advisory was issued for the
Northern Alabama area. The inspectors reviewed the licensee=s overall
preparations/protection for the expected weather conditions and observed the licensees
implementation of general operating instruction GOI-200-1, Freeze Protection
Inspection. The inspectors also reviewed and discussed the implementation of
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GOI-200-1 with the responsible Unit Supervisors and Shift Managers. Furthermore, the
inspectors witnessed the licensees execution of freeze protection of vulnerable areas
and buildings inside and outside the power block. The inspectors also verified operator
staffing for the given conditions was adequate and reviewed any active, upcoming and
delayed work orders and surveillances. The inspectors also verified completion of the
freeze protection checklists. This satisfied one inspection sample.
b. Findings
No findings were identified.
.2 Impending Adverse Weather Conditions - Tornado Warning
a. Inspection Scope
On October 26, 2010, a Tornado Warning was declared for adjacent counties. The
inspectors reviewed the licensee=s overall preparations/protection for the expected
weather conditions and observed the licensees implementation of abnormal operating
instruction (AOI) 100-7, Severe Weather. The inspectors also reviewed and discussed
the implementation of AOI 100-7 with the responsible Unit Supervisor and Shift
Manager; along SSI-19.1, Post Requirements and Responsibilities, Temporary
Suspension of Security Measures, Tornado Emergency Guide/Checkoff with Security
supervision. Furthermore, the inspectors witnessed the licensees execution of
evacuation orders of vulnerable areas and buildings in and outside the power block,
including the termination of work and evacuation of the main turbine deck and refueling
floor. The inspectors also conducted walkdowns of critical plant areas and a general tour
of the plant grounds. Lastly, the inspectors reviewed available operator and security
staffing, and verified access controls and indications for those systems required for safe
control and physical protection of the plant. This satisfied one inspection sample.
b. Findings
No findings were identified.
.3 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors reviewed licensee procedure 0-GOI-200-1, Freeze Protection Inspection,
and reviewed licensee actions to implement the procedure in preparation for cold
weather conditions. The inspectors also reviewed the list of open Problem Evaluation
Reports (PERs) to verify that the licensee was identifying and correcting potential
problems relating to cold weather operations. In addition, the inspectors reviewed
procedure requirements and walked down selected areas of the plant, which included
residual heat removal service water (RHRSW) system and Emergency Equipment
Cooling Water (EECW) system rooms, Emergency Diesel Generators (EDGs) building,
and systems in the Intake Structure, to verify that affected systems and components
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were properly configured and protected as specified by the procedure. Furthermore, the
inspectors discussed cold weather conditions with Operations personnel to assess plant
equipment conditions and personnel sensitivity to upcoming cold weather conditions.
During actual cold weather conditions the later part of December, when outside
temperatures dropped below the 32 degree Fahrenheit (F) and 25F thresholds of 0-GOI-
200-1, the inspectors conducted walkdown tours of the main control rooms to assess
system performance and alarm conditions of systems susceptible to cold weather
conditions. In addition, the inspectors verified effectiveness of licensee implementation
of procedure EPI-0-000-FRZ001, Freeze Protection Program for RHRSW Pump Rooms,
to ensure RHRSW system and components were not adversely affected by the cold
weather. Furthermore, the inspectors verified that the applicable equipment walkdown
checklists required by 0-GOI-200-1 were implemented accordingly. This satisfied one
inspection sample.
b. Findings
No findings were identified.
.4 Readiness to Cope with External Flooding
a. Inspection Scope
The inspectors reviewed plant design features and licensee procedures intended to
protect the plant and its safety-related equipment from external flooding events. The
inspectors reviewed licensing basis flood analysis documents including: Updated Final
Safety Analysis Report (UFSAR) Section 2.4, Hydrology, Water Quality, and Marine
Biology, which included Appendix 2.4A, Maximum Possible Flood; UFSAR Section
12.2.9.2.3 Flood Gate, and BFN-50-C-7101, Protection from Wind, Tornado Wind,
Tornado Depressurization, Tornado Generated Missiles, and External Flooding. The
inspectors performed walkdowns of risk-significant areas, susceptible systems and
equipment, including the common Unit 1/2 A, B, C and D emergency diesel
generator (EDG) rooms and the Unit 3 EDG rooms 3A,3B, 3C, and 3D. The
inspectors review included flood-significant features such as the portable bulkhead used
as a temporary flood barrier, sump pump flowrates, sump drains and level switch
setpoints and watertight door seals for the common U1/2 EDG building and the U3
diesel generator building. Plant procedures and calculations for coping with flooding
events were also reviewed to verify that licensee actions and maintenance practices
were consistent with the plants design basis assumptions.
The inspectors also reviewed licensee corrective action documents for flood-related
items identified in PERs written from 2009 through early 2010 to verify the adequacy of
the corrective actions. The inspectors reviewed selected completed preventive
maintenance procedures and work orders for identified level switches, pumps and flood
barriers (e.g., Flood Doors) for completeness and frequency. This satisfied one
inspection sample.
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b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial Walkdown
a. Inspection Scope
The inspectors conducted three partial equipment alignment walkdowns to evaluate the
operability of selected redundant trains or backup systems, listed below, while the other
train or subsystem was inoperable or out of service. The inspectors reviewed the
functional systems descriptions, UFSAR, system operating procedures, and Technical
Specifications (TS) to determine correct system lineups for the current plant conditions.
The inspectors performed walkdowns of the systems to verify that critical components
were properly aligned and to identify any discrepancies which could affect operability of
the redundant train or backup system. Documents reviewed are listed in the
Attachment.
- Auxiliary Decay Heat Removal (ADHR) System
- Standby EDG 3D
- Unit 3 Core Spray (CS) System - Division I
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Fire Protection Tours
a. Inspection Scope
The inspectors reviewed licensee procedures, Standard Programs and Processes
(SPP)-10.10, Control of Transient Combustibles, and SPP-10.9, Control of Fire
Protection Impairments, and conducted a walkdown of the four fire areas (FA) and fire
zones (FZ) listed below. Selected FAs/FZs were examined in order to verify licensee
control of transient combustibles and ignition sources; the material condition of fire
protection equipment and fire barriers; and operational lineup and operational condition
of fire protection features or measures. Also, the inspectors verified that selected fire
protection impairments were identified and controlled in accordance with procedure
SPP-10.9. Furthermore, the inspectors reviewed applicable portions of the Site Fire
Hazards Analysis Volumes 1 and 2 and Pre-Fire Plan drawings to verify that the
necessary firefighting equipment, such as fire extinguishers, hose stations, ladders, and
communications equipment, was in place.
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- Unit 3 Fire Zone 3-2 EL 519 through 565, from column line R21 to 10 ft west of
column line R18.
b. Findings
No findings were identified.
1R08 Inservice Inspection (ISI) Activities (IP 71111.08B, Unit 1)
a. Inspection Scope
From November 1 through November 5, 2010, the inspectors observed and reviewed
the implementation of the licensee=s In-service Inspection (ISI) program for monitoring
degradation of the reactor coolant system (RCS) boundary and risk-significant piping
boundaries of Browns Ferry Unit 1 during the autumn 2010 refueling outage. The
inspectors= activities consisted of an on-site review of nondestructive examination (NDE)
and welding activities to evaluate compliance with Technical Specifications and the
applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and
Pressure Vessel Code, Sections XI and V (Code of record: 2001 Edition through the
2003 Addenda), for Class 1, 2, and 3 systems; and to verify that indications and defects
(if present) were appropriately evaluated and dispositioned in accordance with the
requirements of the ASME Code Section XI acceptance standards. For Browns Ferry
Unit 1, this was second outage in the first period of the second 10-year ISI inspection
interval. The inspectors also reviewed a sample of inspection activities associated with
components that were outside the scope of ASME Section XI requirements which were
performed in accordance with commitments to follow industry guidance documents, such
as the Boiling Water Reactor Vessel and Internals Project (BWRVIP).
.1 Piping Systems ISI.
a. Inspection Scope
The inspectors reviewed NDE activities, both by direct observation and record review,
specifically including examination procedures, NDE reports, equipment and
consumables certification records, personnel qualification records, and calibration
reports for compliance to requirements of ASME Section V, ASME Section XI, BWRVIP
documents, and other industry standards for the following examinations:
- Penetrant Testing (PT)
o Feedwater Weld Overlay, Weld #: RFW-1-028-001
o RHR Weld Attachment to Pipe, Weld #: 1-47B452-3047-IA
o Recirculation Weld Attachment to Pipe, Weld #: 1-47B465-462-IA
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- Ultrasonic Testing (UT)
o Feedwater Weld Overlay, Weld #: RFW-1-028-001
o Feedwater Pipe, Weld #: GFW-1-08
o Feedwater Pipe Butt Weld, Weld #: N-11B-1
o Feedwater Pipe Weld Overlay, Weld #: N-11B-1-OL
o Feedwater Pipe Weld Overlay, Weld #: RFW-1-028-001
o Feedwater Pipe, Weld #: KFW-1-29
o Feedwater Pipe, Weld #: KFW-1-38
o Feedwater Pipe, Weld #: KFW-1-39
o Recirculation System, Weld #: RWR-1-002-042
The inspectors conducted a Unit 1 containment walk-down of multiple drywell elevations
to assess, in general, the material condition of structures, systems, and components,
including leaks from bolted connections, coating integrity, cleanliness, hangers and
supports, etc.
The inspectors also reviewed welding activities from last outage for the following Class 1
and 2 components:
- Base Metal repairs to the cladding on the Reactor Vessel Head Flange
- Main Steam line Thermowell replacement
The inspectors completed a review of ISI-related problems that were identified by the
licensee and entered into the corrective action program. The inspectors reviewed these
corrective action documents to confirm that the licensee had appropriately described the
scope of the problems, and had implemented appropriate corrective actions. The
inspectors= review included confirmation that the licensee had an adequate threshold for
identifying issues. Through interviews with licensee staff and review of corrective action
documents, the inspectors evaluated the licensee=s threshold for identifying lessons
learned from industry issues related to ASME Section XI. The inspectors performed
these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI,
ACorrective Action,@ requirements. The corrective action documents reviewed by the
inspectors are listed in the Attachment.
b. Findings
No findings were identified.
.2 Reactor Vessel Internal Inspections
a. Inspection Scope
The inspectors reviewed the following NDE activities associated with the inspection of
Reactor Vessel internal components (Boiling Water Reactors Vessel Internals Project):
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- Visual Testing (VT)
o Jet Pump assemblies on shroud and vessel side
o Core Spray P4A downcomer
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification
.1 Resident Inspector Quarterly Review
a. Inspection Scope
On October 19, 2010, the inspectors observed two licensed operator requalification
(LOR) program annual simulator examinations for an Operations group. During each
exam the senior reactor operator and the reactor operator positions were rotated, except
for the shift manager. The examinations observed by the inspectors were the 2010 LOR
Exam-02 and the LOR Exam-13.
The inspectors specifically evaluated the following attributes related to each operating
crews performance:
- Clarity and formality of communication
- Ability to take timely action to safely control the unit
- Prioritization, interpretation, and verification of alarms
- Correct use and implementation of Abnormal Operating Instructions (AOIs), and
Emergency Operating Instructions (EOIs)
- Timely and appropriate Emergency Action Level declarations per Emergency Plan
Implementing Procedures (EPIP)
- Control board operation and manipulation, including high-risk operator actions
- Command and Control provided by the US and Shift Manager (SM)
The inspectors attended a post-examination critique to assess the effectiveness of the
licensee evaluators, and to verify that licensee-identified issues were comparable to
issues identified by the inspector. The inspectors also reviewed simulator physical
fidelity (i.e., the degree of similarity between the simulator and the reference plant
control room, such as physical location of panels, equipment, instruments, controls,
labels, and related form and function).
b. Findings
No findings were identified.
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.2 Annual Review of Licensee Requalification Examination Results
a. Inspection Scope
October 20, 2010, the licensee completed the comprehensive biennial requalification
written examinations and annual requalification operating tests required to be
administered to all licensed operators in accordance with 10 CFR 55.59(a)(2). The
inspectors performed an in-office review of the overall pass/fail results of the written
examinations, individual operating tests and the crew simulator operating tests. These
results were compared to the thresholds established in Inspection Manual Chapter 609,
Appendix I, Operator Requalification Human Performance Significance Determination
Process.
b. Findings
No findings were identified.
.3 Biennial Review
a. Inspection Scope
The inspectors reviewed the facility operating history and associated documents in
preparation for this inspection. During the week of October 12, 2010, the inspectors
reviewed documentation, interviewed licensee personnel, and observed the
administration of operating tests associated with the licensees operator requalification
program. Each of the activities performed by the inspectors was done to assess the
effectiveness of the facility licensee in implementing requalification requirements
identified in 10 CFR Part 55, Operators Licenses. The evaluations were also
performed to determine if the licensee effectively implemented operator requalification
guidelines established in NUREG-1021, Operator Licensing Examination Standards for
Power Reactors, and Inspection Procedure 71111.11, Licensed Operator
Requalification Program. The inspectors also evaluated the licensees simulation
facility for adequacy for use in operator licensing examinations using ANSI/ANS-3.5-
1981, American National Standard for Nuclear Power Plant Simulators for use in
Operator Training and Examination. The inspectors observed three crews during the
performance of the operating tests. Documentation reviewed included written
examinations, Job Performance Measures (JPMs), simulator scenarios, licensee
procedures, on-shift records, simulator modification request records, simulator
performance test records, operator feedback records, licensed operator qualification
records, remediation plans, watchstanding records, and medical records. These records
were inspected using the criteria listed in Inspection Procedure 71111.11. Documents
reviewed during the inspection are documented in the List of Documents Reviewed.
b. Findings
No findings were identified.
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1R12 Maintenance Effectiveness
.1 Routine
a. Inspection Scope
The inspectors examined two specific equipment issues listed below for structures,
systems and components (SSC) within the scope of the Maintenance Rule (MR)
(10CFR50.65) with regard to some or all of the following attributes, as applicable:
(1) Appropriate work practices; (2) Identifying and addressing common cause failures;
(3) Scoping in accordance with 10 CFR 50.65(b) of the MR; (4) Characterizing reliability
issues for performance monitoring; (5) Charging unavailability for performance
monitoring; (6) Balancing reliability and unavailability; (7) Trending key parameters for
condition monitoring; (8) System classification and reclassification in accordance with 10
CFR 50.65(a)(1) or (a)(2); (9) Appropriateness of performance criteria in accordance
with 10 CFR 50.65(a)(2); and (10) Appropriateness and adequacy of (a)(1) goals and
corrective actions (i.e.- Ten Point Plan). The inspectors also compared the licensees
performance against site procedure SPP-6.6, Maintenance Rule Performance Indicator
Monitoring, Trending and Reporting; Technical Instruction 0-TI-346, Maintenance Rule
Performance Indicator Monitoring, Trending and Reporting; and SPP 3.1, Corrective
Action Program. The inspectors also reviewed, as applicable, work orders, surveillance
records, PERs, system health reports, engineering evaluations, and MR expert panel
minutes; and attended MR expert panel meetings to verify that regulatory and procedural
requirements were met.
- Units 1, 2, and 3 CS Systems Excessive Unavailability
- Failure of Magnesium Rotors in Safety-Related Motor Actuated Valve Actuators
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
For planned online work and/or emergent work that affected the combinations of risk
significant systems listed below, the inspectors reviewed three maintenance risk
assessments, and actions taken to plan and/or control work activities to effectively
manage and minimize risk. The inspectors verified that risk assessments and applicable
risk management actions (RMA) were conducted as required by 10 CFR 50.65(a)(4) and
applicable plant procedures such as SPP-7.0, Work Management; NPG-SPP-7.1, On-
Line Work Management; 0-TI-367, BFN Equipment to Plant Risk Matrix; NPG-SPP-7.3,
Work Activity Risk Management Process; and NPG-SPP-7.2, Outage Management.
Furthermore, as applicable, the inspectors verified the adequacy of the licensees risk
assessments, implementation of RMAs, and plant configuration.
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- On October 13, B Standby Gas Treatment (SBGT) Fan and G Control Air
Compressor were out of service (OOS) for maintenance with emergent work on 3C
- Unplanned Entry into Unit 1 ORAM Orange Condition Due To ADHR B Primary Heat
Exchanger Leak While Both Divisions of Residual Heat Removal (RHR) OOS
- Unplanned Entry into Unit 1 ORAM Orange Condition Due To Onset of Severe
Weather While Spent Fuel Gates Installed, and ADHR and Division II RHR OOS
b. Findings
No findings were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the six operability/functional evaluations listed below to verify
technical adequacy and ensure that the licensee had adequately assessed TS
operability. The inspectors also reviewed applicable sections of the UFSAR to verify that
the system or component remained available to perform its intended function. In
addition, where appropriate, the inspectors reviewed licensee procedure NEDP-22,
Functional Evaluations, to ensure that the licensees evaluation met procedure
requirements. Furthermore, where applicable, inspectors examined the implementation
of compensatory measures to verify that they achieved the intended purpose and that
the measures were adequately controlled. The inspectors also reviewed PERs on a
daily basis to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations.
- Unit 3: 3B EDG Immersion Heater and Circulating Oil Soak Back Pump Standby
Auxiliaries De-Energized in Manual Control (PER 260536)
209288)
- C3 EECW Pump Severe Shaft Degradation (PER 257317)
- EDG Buildings Emergency Drain Internal Flooding Operability Evaluation (PER
268624)
178142)
- Holtec MPC-68 Heat Load Limits (PER 255823)
b. Findings
No findings were identified.
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1R18 Plant Modifications
Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the temporary modification listed below and licensee procedure
NPG-SPP-9.5, Temporary Alterations, to verify regulatory requirements were met. The
inspectors also reviewed the associated 10 CFR 50.59 screening and evaluation and
compared each against the UFSAR and TS to verify that the modification did not affect
operability or availability of the affected system. Furthermore, the inspectors walked
down the modification to ensure that it was installed in accordance with the modification
documents and reviewed post-installation and removal testing to verify that the actual
impact on permanent systems was adequately verified by the tests.
- 1-SI-4.7.A.2.a-f, Primary Containment Leak Rate Test, Jumpering and Inhibiting for
Pressurization of Primary Containment
b. Findings
No findings were identified.
1R19 Post Maintenance Testing
a. Inspection Scope
The inspectors reviewed the six post-maintenance tests (PMT) listed below to verify that
procedures and test activities confirmed SSC operability and functional capability
following maintenance. The inspectors reviewed the licensees completed test
procedures to ensure any of the SSC safety function(s) that may have been affected
were adequately tested, that the acceptance criteria were consistent with information in
the applicable licensing basis and/or design basis documents, and that the procedure
had been properly reviewed and approved. The inspectors also witnessed the test
and/or reviewed the test data, to verify that test results adequately demonstrated
restoration of the affected safety function(s). The inspectors verified that PMT activities
were conducted in accordance with applicable WO instructions, or procedural
requirements, including NPG-SPP-6.3, Pre-/Post-Maintenance Testing, and MMDP-1,
Maintenance Management System. Furthermore, the inspectors reviewed problems
associated with PMTs that were identified and entered into the CAP.
- Unit Common: PMT for Standby Gas Treatment Train B Roughing Filter
Replacement and Outlet Damper Repair Per 0-SR-3.6.4.3.2(B VFTP), Standby Gas
Treatment Filter Pressure Drop and In-Place Leak Tests - Train B
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- Unit 1: PMT for Residual Heat Removal (RHR) System II Outboard Recirculation
Loop Valve Stem/Disc Separation Repair Per Work Orders (WOs) 111571105,
111571764, and 09-723979-000; and 1-SR-3.6.1.3.5(RHR II), RHR System MOV
Operability Loop II; and 1-SR-3.3.3.1.4(H II), Verification of Remote Position
Indicators for RHR System II Valves.
- Unit 1: PMT for Reactor Protection System Scram Contactor Relay Replacements
Per WOs 09-723912-000 and 09-723911-000; ECI-0-000-RLY003, Replacement of
Relays; EPI-0-099-RLY001, Reactor Protection System Scram Solenoid and Reset
Relays Channel A; and EPI-0-099-RLY002, Reactor Protection System Scram
Solenoid and Reset Relays Channel B
- Unit 2: PMT for HPCI Steam Admission Valve 73-16 Repairs Per WO 110811072
and 2-SR-3.5.1.7, HPCI Main and Booster Pump Set Developed Head and Flow
Rate Test at Rated Reactor Pressure
- Unit 3: PMT for Core Spray Division II Preventive Maintenance per 3-SR-
3.5.1.6(CSII), Core Spray Flow Rate Loop II, and applicable WOs
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
.1 Unit 1 Scheduled Refueling Outage (U1R8)
a. Inspection Scope
From October 23 through November 23, 2010, the inspectors examined critical outage
activities associated with the U1R8 refueling outage and the Unit 1 restart to verify that
they were conducted in accordance with TS, applicable operating procedures, and the
licensees outage risk assessment and management plans. Some of the more
significant inspection activities conducted by the inspectors were as follows:
Outage Risk Assessment
Prior to the Unit 1 scheduled U1R8 refueling outage that began on October 23, the
inspectors met with outage risk assessment team members and reviewed the Outage
Risk Assessment Report to verify that the licensee had appropriately considered risk,
industry experience, and previous site-specific problems in developing and implementing
an outage plan that assured the necessary levels of defense-in-depth of safety functions
were maintained. The inspectors also reviewed the daily U1R8 Refueling Outage
Reports, including the Outage Risk Assessment Management (ORAM) Safety Function
Status, and regularly attended the licensees outage status meetings. These reviews
were compared to the requirements in licensee procedure NPG-SPP-07.2, Outage
Management. These reviews were also done to verify that for identified high risk
significant conditions, due to equipment availability, severe weather and/or system
configurations, that contingency measures were identified and incorporated into the
overall outage and contingency response plan. Furthermore, the inspectors frequently
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discussed risk conditions and designated protected equipment with Operations and
outage management personnel to assess licensee awareness of actual risk conditions
and mitigation strategies.
Shutdown and Cooldown Process
The inspectors witnessed the shutdown and cooldown of Unit 1 in accordance with
licensee procedures OPDP-1, Conduct of Operations; 1-GOI-100-12A, Unit Shutdown
from Power Operations to Cold Shutdown and Reduction in Power During Power
Operations; and 1-SR-3.4.9.1(1), Reactor Heatup or Cooldown Rate Monitoring.
The inspectors reviewed licensee procedures 1-OI-74, Residual Heat Removal System
(RHR); 1-OI-78, Fuel Pool Cooling and Cleanup System; and Abnormal Operating
Instruction 0-AOI-72-1, Alternate Decay Heat Removal System Failures; and conducted
main control room panel and in-plant walkdowns of system and components to verify
correct system alignment. During planned evolutions that resulted in an increased
outage risk condition of Orange for shutdown cooling, inspectors verified that the plant
conditions and systems identified in the risk mitigation strategy were available. In
addition, the inspectors reviewed controls implemented to ensure that outage work was
not impacting the ability of operators to operate spent fuel pool cooling, RHR shutdown
cooling, and/or the ADHR system. Furthermore, the inspectors conducted several
walkdowns of the ADHR system during operation with the fuel pool gates removed.
Critical Outage Activities
The inspectors examined outage activities to verify that they were conducted in
accordance with TS, licensee procedures, and the licensees outage risk control plan.
Some of the more significant inspection activities accomplished by the inspectors were
as follows:
- Walked down the following selected safety-related equipment clearance orders (i.e.,
tag-outs)
o Tagout 1-TO-2010-0003, Clearance 1-074-0037A, RHR System II
o Tagout 1-TO-2010-0003, Clearance 1-071-0011D, RCIC Bearing Repair
o Tagout 1-TO-2010-0003, Clearance 1-063-0001A, SLC Injection Valve B
- Verified Reactor Coolant System (RCS) inventory controls
- Verified electrical systems availability and alignment
- Monitored important main control room plant parameters (e.g., RCS pressure, level,
flow, and temperature) and TS compliance during the various shutdown modes of
operation, and mode transitions
- Evaluated implementation of reactivity controls
- Reviewed control of containment integrity
- Examined foreign material exclusion controls particularly in proximity to and around
the reactor cavity, equipment pit, and spent fuel pool
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- Performed routine tours of the control room, reactor building, refueling floor and drywell
Reactor Vessel Disassembly and Refueling Activities
The inspectors witnessed selected activities associated with reactor vessel disassembly,
and reactor cavity flood-up and drain down in accordance with 1-GOI-100-3A, Refueling
Operations (Reactor Vessel Disassembly and Floodup). Also, on numerous occasions,
the inspectors witnessed fuel handling operations during the Unit 1 reactor core fuel
shuffle performed in accordance with TS and applicable operating procedures, such as
GOI-100-3A, Refueling Operations (In Vessel), GOI-100-3B, Operations in the Spent
Fuel Pool, and GOI-100-3C, Fuel Movement Operations During Refueling. The
inspectors verified specific fuel movements as delineated by the Fuel Assembly Transfer
Sheets (FATF).
Drywell Closeout
Between November 19 and November 21, 2010, the inspectors reviewed the licensees
conduct of 1-GOI-200-2, Drywell Closeout, and performed an independent detailed
closeout inspection of the Unit 1 Torus and drywell.
Restart Activities
The inspectors specifically conducted the following:
- Witnessed heatup and pressurization of Unit 1 reactor pressure vessel in accordance
with 1-SI-3.3.1.A, ASME Section XI System Leakage Test of the Reactor pressure
Vessel and Associated Piping
- Reviewed and verified completion of selected items of 0-TI-270, Refueling Test
Program, Attachment 2, Startup Review Checklist
- Reviewed 2-SR-3.6.1.1.1(OPT-A) Primary Containment Total Leak Rate - Option A,
Revision 6
- Attended multiple Unit 1 Restart PORC Meetings
- Witnessed Unit 1 approach to criticality and power ascension per 1-GOI-100-1A, Unit
Startup, and 1-GOI-100-12, Power Maneuvering
- Reactor Coolant Heatup/Pressurization to Rated Temperature and Pressure per 1-
SR-3.4.9.1(1), Reactor Heatup and Cooldown Rate Monitoring
Corrective Action Program
The inspectors reviewed PERs generated during U1R8 and attended management
review committee meetings to verify that initiation thresholds, priorities, mode holds,
operability concerns and significance levels were adequately addressed. Resolution and
implementation of corrective actions of several PERs were also reviewed for
completeness.
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b. Findings
Two findings were identified.
(1) Introduction: A self-revealing apparent violation (AV) of Unit 1 TS Limiting Condition for
Operation (LCO) 3.5.1, Emergency Core Cooling System (ECCS) - Operating, was
identified for the licensees failure to establish adequate design control and perform
adequate maintenance on the Unit 1 outboard Low Pressure Coolant Injection (LPCI)
valve, 1-FCV-74-66, which resulted in the valve being left in a significantly degraded
condition and RHR loop II unable to fulfill its safety function.
Description: On October 23, 2010, RHR Loop II LPCI Outboard Injection Valve, 1-FCV-
74-66 (Walworth 5509, 24 inch 600 pound angle globe valve), failed to open when
operators attempted to place RHR Shutdown Cooling, Loop II, in service to support
U1R8 refueling activities. Control room indications indicated the valve was open but no
flow was indicated in RHR Loop II with the 1B RHR pump in service. Operators
concluded the RHR Loop II flow path was inoperable, and proceeded to secure the 1B
RHR pump and promptly placed RHR Loop I in-service for shutdown cooling. Unit 1 was
in Mode 3 at the time.
Subsequent visual inspections of the FCV-74-66 valve stem, upper disc skirt, disc, skirt
to disc tack welds, and thread engagements identified the following:
- The valve disc was found to be seated and stuck in the valve seat, essentially
blocking all RHR Loop II flow.
- The disc was found separated from the stem and upper disc skirt, which would
normally be threaded onto the disc skirt and tack welded.
- The two 8 inch fillet welds between the disc skirt and the disc were fractured (welds
completely broken apart). Also, further examination discovered the welds to be
undersized.
- No upper disc skirt locking key was present.
- The threads on the upper disc skirt were found to be undersized, resulting in partial
engagement of thread faces between the disc skirt and disc.
- The thrust washer between the stem and disc was missing.
The licensee initiated PER 271338 to determine the root cause of the valve failure. The
licensees root cause analysis of 1-FCV-74-66 was not complete by the end of the
inspection. As part of their immediate corrective actions, the licensee implemented
appropriate repairs and modifications to restore FCV-74-66 prior to Unit 1 restart. Also,
the licensee conducted an internal inspection of the RHR Loop I LPCI outboard injection
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valve (1-FCV-74-52) prior to Unit 1 restart. The FCV-74-52 was determined to be intact
with no apparent damage or significant degradation. Furthermore, as extent of condition
compensatory measures, the licensee has conducted and continued to perform a
combination of internal inspections, partial motor-operated valve actuator testing, UT
testing, shutdown cooling operation, and/or monthly venting to verify proper conditions of
the Unit 2 and 3 FCV-74-52 and 66 LPCI outboard injection valves.
The inspectors found that 1-FCV-74-66 had been modified in 1983 by engineering
change notice ECN L2107 to install a V-notch lower disc skirt which was intended to
eliminate excessive vibrations experienced at low flow and high pressure drop conditions
and provide improved flow control.
Also in 2006, during the Unit 1 recovery an internal inspection of the 1-FCV-74-66 valve
was performed. Following this inspection, the 1-FCV-74-66 valve was refurbished and
the valve stem was replaced. However, this valve maintenance was performed using an
out-dated valve drawing, 0-A-12337-M-1E, and inadequate maintenance procedure for
valve internal assembly removal and reinstallation, MCI-0-74-VLV008. This procedure
and applicable drawings did not specify appropriate details for the disassembly of the
disc, stem, and skirt; installation of the disc locking key, modified skirt, and modified
stem; and overall correct design configuration of the valve. During the 2006 valve stem
replacement, the stem disc thrust washer was not installed, the disc-to-skirt joint was not
welded to specifications, and the installed disc skirt had undersized threads.
The licensees inspection of the valve found the threads on both the disc and upper disc
skirt in generally good condition. However, laboratory microscopic analysis indicated
beaking or rollover of disc skirt thread crowns. Laboratory analysis of the disc-to-skirt
welds also found that the welds were significantly undersized (i.e., a 0.20 inch fillet
versus 0.50 inch fillet) with general porosity and cracking. The licensees root cause
analysis of the stem and disc separation was still in progress at the end of the inspection
period.
The licensee had identified evidence of multiple impact strikes on the FCV-74-66 valve
disc from the blunt end of the separated stem. The inspectors found this to be evidence
pointing to how long the disc may have been separated from the stem because during
plant operations, the valve was only cycled during quarterly surveillance testing. The
inspectors concluded that FCV-74-66 was incapable of performing its safety function for
longer than its TS 3.5.1 allowed outage time (AOT) of seven days. As part of their root
cause analysis, the licensee was attempting to determine a more exact failure time and
duration in order to better evaluate the resultant safety significance. The last time Unit 1
RHR Loop II was successfully placed in-service, thereby demonstrating FCV-74-66 was
still operable, was on March 12, 2009 for shutdown cooling.
Analysis: The inspectors determined that the licensees failure to establish adequate
design control and perform adequate maintenance on the Unit 1 outboard LPCI injection
valve, 1-FCV-74-66, which resulted in the valve being left in a significantly degraded
condition and RHR loop II unable to fulfill its safety function, was a performance
deficiency. This performance deficiency was considered greater than minor because it
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was associated with the Protection Against External Factors attribute of the Reactor
Safety/ Mitigating Systems Cornerstone and adversely affected the cornerstone
objective of ensuring availability and reliability of systems designed to respond to
initiating events to prevent undesirable consequences. Specifically, the RHR subsystem
was rendered incapable of being aligned to perform its safe shutdown function due to
the failure of 1-FCV-74-66. The inspectors assessed the finding using Inspection
Manual Chapter (IMC) 0609, Significance Determination Process (SDP), and determined
the finding was potentially greater than very low safety significance because it adversely
affected the operators ability to achieve safe shutdown. Since this finding was
potentially greater than Green it will require a Phase 3 SDP assessment. The safety
characterization of this finding is not yet finalized and is currently characterized as To Be
Determined (TBD). This finding does not have a cross-cutting aspect because it is not
reflective of current licensee performance.
Enforcement: Technical Specification LCO 3.5.1, ECCS-Operating, in part, required that
each RHR subsystem shall be operable in Modes 1, 2 and 3, with an allowed outage
time of 7 days, or place the unit in Hot Shutdown (Mode 3) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Cold
Shutdown (Mode 4) within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary to the above, between March 13, 2009,
and October 23, 2010, the Loop II RHR subsystem was inoperable without the licensee
taking the required TS actions. Pending determination of safety significance, this finding
is identified as an apparent violation: AV 05000259/2010005-01, RHR Subsystem
Inoperable Beyond the Technical Specifications Allowable Outage Time.
(2) Introduction: A Green self-revealing non-cited violation (NCV) of Unit 1 RHR TS LCO
3.6.2.3, Suppression Pool Cooling, was identified for the licensees failure to comply with
the LCO required actions for an inoperable RHR suppression pool cooling subsystem.
Description: On October 27, 2010, the 1C RHR pump motor seized while Loop I was in
operation for shutdown cooling. Unit 1 was in Mode 5 with reactor vessel water level
greater than 23 above the flange, fuel pool gates open, and the auxiliary decay heat
removal (ADHR) in-service. Operators promptly started the 1A RHR pump to restore
shutdown cooling flow. The Loop II of RHR was OOS for repairs. Approximately three
hours later, operators secured the 1A RHR pump for outage work and declared the
ADHR system as the TS required system for core cooling.
The 1C RHR pump had been in-service for shutdown cooling for approximately 94 hours0.00109 days <br />0.0261 hours <br />1.554233e-4 weeks <br />3.5767e-5 months <br />
prior to experiencing a catastrophic failure of the motor on October 27. Total service
time for the 1C RHR pump since November 2007 was approximately 350 hours0.00405 days <br />0.0972 hours <br />5.787037e-4 weeks <br />1.33175e-4 months <br />. The
mission time of the 1C RHR pump to perform its intended safety functions was 30 days
(i.e., 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />). Consequently, the 1C RHR pump had been incapable of meeting its
required mission time, and thereby considered inoperable, since at least November
2007.
The inspectors found that as part of the Unit 1 recovery project, the 1A and 1C RHR
Loop I pump motors were sent offsite to the licensees Power Service Shop (PSS) in
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June 2004 to be refurbished. In March of 2005, the refurbished and reassembled 1C
RHR pump motor experienced excessive vibration during no-load run testing by PSS. In
August 2005, the motor was disassembled, inspected, bearings replaced, reassembled
and no-load tested again but vibration readings remained unacceptably high. In
September 2005, the 1C RHR pump motor was field balanced, no-load tested
acceptably, and returned to Browns Ferry. During uncoupled and coupled runs of the
1C RHR pump motor in September to October 2006, the licensee identified elevated iron
content in the lower motor bearing oil reservoir which was indicative of internal motor
wear (e.g., rubbing between stationary and rotating elements). This reservoir was
subsequently flushed on five separate occasions over a six week period due to
persistently elevated iron content in the oil which turned the oil completely black. Almost
immediately upon return to service (RTS) in 2007, the IC RHR pump motor exhibited an
increasing trend of high vibration as determined by the Predictive Maintenance Program.
Unit 1 was restarted on May 17, 2007.
After the Unit 1 restart, until October 2010, the 1C RHR pump motor continued to exhibit
an ever increasing trend of elevated radial and axial vibrations, and iron content in the
lower bearing oil reservoir. The inspectors concluded that these persistent symptoms
were indicative of internal wear that went undiagnosed by the licensee. From March
2009 through August 2010, four PERs and two WOs were initiated to specifically
address and correct the degraded equipment conditions associated with high motor
vibrations. The licensees initial diagnosis concluded the 1C RHR pump motor was
unbalanced and needed to be re-balanced. However, all four PERs were closed to two
WOs (initiated in March and August 2009) which were never worked. Both WOs were
removed and/or rejected from the daily work week schedule and the most recent U1R8
outage.
Subsequent disassembly, inspection, and root cause evaluation determined that the
rotor of the 1C RHR pump motor had come into physical contact with the stator which
resulted in mechanical seizure of the motor. The direct cause of the motor seizure was
due to a dynamic physical bow in the rotor shaft, compounded by the field balance
weights, which resulted in a significant loss of air gap between the rotor and stator when
the motor was in operation. This led to internal rubbing over approximately four years
which resulted in catastrophic mechanical failure of the motor. The licensee attributed
the root cause of this failure to a misdiagnosis of the dynamic rotor bow that was treated
as a rotor imbalance problem during the PSS motor refurbishment in 2005.
The inspectors identified that the 1C RHR pump motor performance over the past four
years provided evidence that the rotating elements of the motor (i.e., rotor assembly)
had been rubbing against the stationary elements (i.e., stator, upper/lower bearing air
and oil seals, and lower bearing). The inspectors concluded that the licensees
predictive maintenance and corrective action programs failed to adequately recognize,
evaluate and/or understand an adverse trend in elevated iron content of the lower
bearing oil reservoir and increased axial and radial vibrations that exceeded their alert
levels for the 1C RHR pump.
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Analysis: The inspectors determined that the licensees misdiagnosis and failure to
correct a dynamic physical bow in the 1C RHR pump motor rotor constituted a
performance deficiency that resulted in a degraded condition which directly led to
mechanical failure of the 1C RHR motor. This performance deficiency was considered
greater than minor because it was associated with the Mitigating Systems cornerstone
and adversely affected the equipment performance objective to ensure the availability
and capability of the RHR system to respond to initiating events to prevent undesirable
consequences (i.e., core damage). Specifically, the 1C RHR subsystem was degraded
to the point that it was incapable of performing its intended safety functions for the
required mission time. Since the 1C RHR motor failure occurred during Mode 5
shutdown conditions after a significant period of shutdown cooling operation, the finding
was evaluated according to IMC 609, Appendix G, Shutdown Operations SDP,
Attachment 1, Phase 1 Operational Checklists, Checklist 7, Refueling Operation with
Reactor Coolant Level Above 23. Accordingly, the finding was determined to be of very
low safety significance (Green) because the 1A RHR pump and the ADHR system were
available, when only one RHR pump was needed per Section I.C of Checklist 7.
The cause of this finding was directly related to the cross cutting aspect of Thorough
Evaluation of Identified Problems in the Corrective Action Program component of the
Problem Identification and Resolution area, because the licensee did not adequately
evaluate the precursors related to the degraded 1C RHR pump motor performance and
properly prioritize the resolution of a known condition adverse to quality in time to
preclude motor failure P.1(c).
Enforcement: The RHR TS LCO 3.6.2.3, Suppression Pool Cooling, in part, required
that four RHR suppression pool cooling subsystems shall be OPERABLE in Modes 1, 2
and 3, with an allowed outage time of 30 days, or place the unit in Hot Shutdown (Mode
3) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Cold Shutdown (Mode 4) within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary to the above,
between November 2007 and October 2010, the 1C RHR suppression pool cooling
subsystem was inoperable without the licensee taking the required TS LCO actions.
However, because the finding was determined to be of very low safety significance
(Green) and has been entered into the licensees CAP as PER 274840, this violation is
being treated as an NCV consistent with the Enforcement Policy. This NCV is identified
as NCV 05000259/2010005-02, Degraded 1C RHR Pump Motor Rendered One RHR
Subsystem Inoperable Beyond the Technical Specifications Allowable Outage Time.
.2 Unit 3 Forced Shutdown Due To Main Generator Exciter High Bearing Vibrations
a. Inspection Scope
On December 26, 2010, Unit 3 commenced a forced shutdown due to high vibrations on
the main generator/exciter bearings. The main control room received an alarm for high
vibrations and noticed two locations (bearings #11 and #12) had experienced a sudden
step change in vibrations that exceeded the turbine trip setpoint. The operators initiated
a manual reactor scram, followed by a trip of the main turbine, as required by their
operating procedures. The licensee initiated necessary repairs to the affected bearings
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and the main generator exciter. The licensee determined the cause of the high
vibrations was due to a high temperature difference between the 3A and 3B exciter
coolers that resulted in reduced clearances between the exciter casing and bearing
housings. Unit 3 remained shutdown through the end of the report period. During this
short notice forced outage, the inspectors examined the conduct of critical outage
activities pursuant to TS, applicable procedures, and the licensees outage risk
assessment and outage management plans. The more significant outage activities
witnessed, monitored, examined and/or reviewed by the inspectors were as follows:
- Shutdown and cooldown of Unit 3 in accordance with general operating instruction
(GOI) 3-GOI-100-12A, Unit Shutdown from Power Operations to Cold Shutdown and
Reduction in Power During Power Operations, and 3-SR-3.4.9.1(1), Reactor Heatup
and Cooldown Rate Monitoring
- Outage risk assessment and management
- Control and management of forced outage and emergent work activities
Corrective Action Program
The inspectors reviewed PERs generated during the Unit 3 forced outage and verified
that initiation thresholds, priorities, mode holds, and significance levels were assigned as
required.
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors witnessed portions and/or reviewed completed test data for the following
five surveillance tests of risk-significant and/or safety-related systems to verify that the
tests met TS surveillance requirements, UFSAR commitments, and in-service testing
and licensee procedure requirements. The inspectors review confirmed whether the
testing effectively demonstrated that the SSCs were operationally capable of performing
their intended safety functions and fulfilled the intent of the associated surveillance
requirement.
In-Service Tests:
- 2-SR-3.5.1.7, HPCI Main and Booster Pump Set Developed Head and Flow Rate
Test at Rated Reactor Pressure
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Routine Surveillance Tests:
- 0-SR-3.8.4.4 (SB-D), Shutdown Board D Battery Modified Performance Test
- 0-SR-3.7.3.2 (HEPA), Control Room Emergency Ventilation System In Place Leak
Test
- 1-SI-4.7.A.2.a-f, Primary Containment Integrated Leak Rate Test
Reactor Coolant System Leak Detection Tests:
- 3-SR-3.4.5.3, Drywell Floor Drain Sump Flow Integrator Calibration
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP7 Emergency Exercise Evaluation
a. Inspection Scope
On December 14, the inspectors observed the Emergency Preparedness (EP) portion of
a site exercise consistent with the requirements of NRC Inspection Procedure
711114.07. The inspectors observed emergency response operations in the simulated
control room to verify that event classification and notifications were done in accordance
with EPIP-1, Emergency Classification Procedure and other applicable Emergency Plan
Implementing Procedures. The inspectors also attended the licensees critique of the
drill to verify any inspector observed weaknesses were also identified by the licensee.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
Cornerstone: Initiating Events
a. Inspection Scope
The inspectors reviewed the licensees procedures and methods for compiling and
reporting the Performance Indicators (PIs) listed below, including procedure NPG-
SPP-02.2, Performance Indicator Program. The inspectors examined the licensees PI
data for the specific PIs listed below for the fourth quarter of 2009 through the third
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quarter of 2010. The inspectors compared the licensees raw data against graphical
representations and specific values reported to the NRC for the third quarter 2010 PI
report to verify that the data was correctly reflected in the report. Additionally, the
inspectors validated this data against relevant licensee records (e.g., PERs, Daily
Operator Logs, Plan of the Day, Licensee Event Reports, etc.), and assessed any
reported problems regarding implementation of the PI program. Furthermore, the
inspectors met with responsible plant personnel to discuss and go over licensee records
to verify that the PI data was appropriately captured, calculated correctly, and
discrepancies resolved. The inspectors also used the Nuclear Energy Institute (NEI) 99-
02, Regulatory Assessment Performance Indicator Guideline, to ensure that industry
reporting guidelines were appropriately applied.
- Unit 1 Unplanned Scrams
- Unit 2 Unplanned Scrams
- Unit 3 Unplanned Scrams
- Unit 1 Unplanned Scrams with Complications
- Unit 2 Unplanned Scrams with Complications
- Unit 3 Unplanned Scrams with Complications
- Unit 1 Unplanned Power Changes
- Unit 2 Unplanned Power Changes
- Unit 3 Unplanned Power Changes
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems
.1 Review of items entered into the Corrective Action Program:
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed a daily screening of items entered into the
licensees CAP. This review was accomplished by reviewing daily Service Request (SR)
report summaries, and periodically attending Corrective Action Review Board (CARB)
and PER Screening Committee (PSC) meetings.
.2 Semiannual Review to Identify Trends
a. Inspection Scope
As required by Inspection Procedure 71152, the inspectors performed a review of the
licensees CAP implementation and associated documents to identify trends that could
indicate the existence of a more significant safety issue. The inspectors review included
the results from daily screening of individual PERs (see Section 4OA2.1 above),
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licensee trend reports and trending efforts, and independent searches of the PER
database and WO history. The review also included issues documented outside the
normal CAP in system health reports, corrective maintenance WOs, component status
reports, site monthly meeting reports and maintenance rule assessments. The
inspectors review nominally considered the six-month period of July 2010 through
December 2010, although some PER database and WO searches expanded beyond
these dates. The inspectors reviewed the licensees integrated trend review (ITR)
program and the quarterly implementation of the process as documented in licensee
procedure NPG-SPP-02.8, Integrated Trend Review, Rev. 01. Furthermore, the
inspectors verified that adverse or negative trends identified in the licensees PERs,
periodic reports and trending efforts were entered into the CAP. Inspectors interviewed
the appropriate licensee management and also reviewed new procedures, NPG-SPP-
02.8, Integrated Trend Review, Rev. 01 and NPG-SPP-02.7 PER Trending, Rev. 01
issued during this period.
b. Findings and Observations
No findings were identified, but the inspectors did identify a number of observations as
discussed below.
The purpose of the licensees integrated trend review process was to identify the top
issues (gaps to excellence) requiring management attention. Other objectives of the ITR
program were to provide status of the top issues and their progress to resolution, identify
continuing issues, emerging trends and issues to be monitored, review progress towards
resolving past top issues, review issues identified by external organizations such as the
NRC, INPO, Nuclear Safety Review Board (NSRB), QA, etc., and determine why they
were not identified by line organizations. The inspectors determined that the new
guidance provided in NPG-SPP-02.8 was adequate to meet the purpose and objectives
of the ITR program. The inspectors also reviewed the two most recent Integrated Trend
(IT) reports. The licensee had identified certain departments that did not submit their
reports on time which contributed to the site report being issued after its required due
date. The inspectors noted that SRs were written for each occurrence. The inspectors
also noted that the new procedures improved the consistency of trend discussions and
the report format across departments.
The inspectors also identified several other observations related to the licensees
implementation of the ITR program. The licensee initiated PER 302232 for these
observations.
The inspectors conducted an independent review to identify potential adverse trends,
and identified several notable trends which were either verified to be in the licensees
CAP and/or referred to the licensee who entered them into their CAP. The potential
adverse trends were as follows:
- During the Unit 1 refueling outage (RFO) U1R8, the inspectors noted four service
requests (SR) were written to document foreign material in the Unit 1 spent fuel pool
(SFP). The licensee initiated SR 281642 and PER 282539 to address several
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additional examples of foreign material in the SFP and reactor vessel. The license
initiated PER 277764 to document the adverse trend in foreign material during the
U1R8 RFO. As foreign material issues were discovered, SRs were initiated and
appropriate corrective actions taken to remove the foreign material and provide
personnel coaching where appropriate. Additional actions to review and/or improve
the implementation of the sites foreign material exclusion (FME) program were
planned, but not completed by the end of this inspection period.
- PER 213116 was generated to address the licensees actions to address an
inspector identified trend, concerning the adequacy of post maintenance testing
(PMT), which has been previously documented in multiple inspection reports, but is
yet to be adequately addressed by the corrective action program. The licensee
developed another corrective action plan including actions to develop a PMT team
with a team charter. The inspectors reviewed the charter which included additional
actions for the team. However, due dates for those actions were not provided. The
PER was closed on July 22, 2010, upon development of the team charter. The
licensee identified the corrective actions from PER 213116 were not effective and
initiated PER 246534 on Aug. 25, 2010. This PER was assigned a higher level in
accordance with licensee procedure NPG-SPP-02.8. None of the corrective actions
were completed by the end of this inspection period. On Dec. 17, 2010, the
inspectors observed the PMT associated with the U2 HPCI system. It was
discovered that two additional work orders (WO) for the HPCI system did not have
PMTs assigned. The licensee captured this issue in their CAP as PER 299877.
- The inspectors identified a potential adverse trend regarding inaccuracy and
incomplete information contained in LERs. During the review of LERs from 2009
through 2010, inspectors identified seven examples where LERs contained
inaccurate statements, incomplete descriptions and details, and other technical and
editorial errors. The licensee had previously initiated the following PERs to resolve
the issues identified by the inspectors: PERs 215479, 205308, 201410, and 163176.
Additionally, as documented in report Section 4OA3.1 below, the inspectors
identified two violations associated with inadequate and incomplete information in
Unit 3 LER 2009-003. The licensee initiated SR 314177 to address this apparent
adverse trend.
- Over the past operating cycle, Units 2 and 3 have developed a large number of
control rod Rod Position Indication System (RPIS) component problems. Unit 2 had
outstanding WOs on about 25 different control rods with RPIS related problems, and
Unit 3 had about 15 control rods with WOs. These problems involved incorrect back
lighting, intermittent drift alarms, and primarily inaccurate rod position indication at
one or more positions. The licensee initiated SRs 313460 and 313465 to address
this adverse trend.
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.3 Annual Sample: Review of Cross Cutting Aspect H.2.c
a. Inspection Scope
The inspectors reviewed the cause analysis and specific corrective actions associated
with PER 228347, Emerging Trend in Human Performance Cross-Cutting Area. This
PER was initiated to evaluate an overall adverse trend in NRC findings and licensee
events attributed to human performance issues associated with the Resources
component area (i.e., H.2) defined by Inspection Manual Chapter (IMC) 0310,
Components Within The Cross Cutting Areas. During this inspection, the inspectors
focused primarily upon the cross-cutting aspect (CCA) of H.2.c. In IMC 310, this CCA is
described as the licensee ensures that personnel, equipment, procedures, and other
resources are available to assure nuclear safety, specifically, those necessary for
complete, accurate, and up-to-date design documentation, procedures, and work
packages, and correct labeling of components. Within the preceding 12 months, the
NRC has cited three violations with a cross-cutting aspect of H.2.c that were included as
part of PER 228347. The violations for which the CCA is cited include: Failure to
perform an adequate risk assessment during severe weather conditions (PER 171402);
Inadequate operating procedures cause partial loss of reactor feedwater, which results
in Unit 2 manual reactor scram (PER 203538); and Inadequate surveillance procedure to
ensure all relevant RPV metal temperatures were monitored during leak testing (PERs
223539 and 224778). The licensee also included an additional 57 PERs for review in
the common cause analysis of this PER. The inspectors reviewed the events and
analysis of the events, the extent of condition, previous similar events, root and
contributing causes, the licensees safety culture evaluation, and corrective actions
taken or planned for this PER.
b. Findings and Observations
No findings were identified. Inspectors determined that, in general, the licensees root
cause analysis (RCA) of the human performance cross cutting implications of the NRC
findings associated with the H.2.c CCA was technically accurate, of sufficient depth, and
consistent with the licensees process. The RCA was determined to have adequately
addressed operability, reportability, common cause, generic concerns, extent-of-
condition, and extent-of-cause. The inspectors also determined that the licensee had
appropriately identified and prioritized corrective actions. Furthermore, in general, the
corrective actions to prevent recurrence (CAPRs) and additional corrective actions
implemented to date, or scheduled to be implemented, are considered reasonable to
address the root cause. However, the inspectors identified the following observations
which were discussed with the licensee:
Not all of the licensees corrective actions were completed. As part of the licensees
corrective actions, various communication methods of management expectations have
been ongoing. Training teams were formed or forming, and industry benchmarking was
in progress. The plant procedure upgrade was also in progress and lists of the most
difficult procedures for each department have been generated. However, after these
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more difficult procedures were identified it was unclear as to what actions the licensee
was taking to ensure personnel and management were taking any compensatory actions
regarding future use of these procedures until the planned improvements were
implemented. In response to the inspectors observations, PER 302263 was initiated to
evaluate whether some form of compensatory measures should be established when
working with these procedures.
In addition, the licensee had identified prior similar events related to human performance
through self assessments, benchmarking and QA assessments. However, previous
corrective actions related to these prior events had failed to provide sustainable
resolution of the issues in the past. Since the licensees corrective actions for the H.2
adverse trend were still ongoing, a final effectiveness review of these actions has not
been accomplished. The inspector noted that in the interim, since the licensee identified
this adverse trend, and began taking corrective actions; there have been no new NRC
findings or violations with a CCA of H.2.c.
.4 Annual Follow-up of Selected Issues - Assessment of Progress in Addressing the
Substantive Cross-Cutting Issue (SCCI)
a. Inspection Scope
The inspectors reviewed the licensees progress on the development and
implementation of corrective actions to address the SCCI identified in the NRC Annual
Assessment Letter for the period of January - December 2009. The SCCI was identified
in the problem identification and resolution area, in the aspect of thorough evaluation of
identified problems (P.1 (c)). The SCCI was subsequently held open in NRC Mid-Cycle
Performance Review Letter for the period January - July 2010 in order to give the
licensee time to develop and schedule a corrective action plan. This PI&R inspection
was the first opportunity to review the licensees actions to address the open SCCI.
The inspectors conducted a detailed review of the licensees common cause and root
cause analysis (PER 223536) related to the open SCCI to assess the adequacy of the
licensees evaluation of the problems identified. The inspectors reviewed these
evaluations against the guidance in licensee procedure NPG-SPP-03.1.6, Root Cause
Analysis and the performance attributes of NRC Inspection Procedure 71152. The
inspectors assessed if the licensee had adequately determined the cause(s) of identified
problems, and had adequately addressed operability, reportability, common cause,
generic concerns, extent-of-condition, and extent-of-cause. The review also assessed if
the licensee had appropriately identified and prioritized corrective actions to prevent
recurrence. Inspectors also reviewed a sample of completed corrective actions (twenty-
five of fifty-two total corrective actions were complete at the time of the inspection) to
independently verify that the corrective actions were implemented as intended.
The inspectors also noted that the licensee had identified a trend of findings in the
problem identification and resolution area, in the aspect of timely corrective actions
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(P.1 (d)) which they included in their root cause analysis and corrective actions to
address the open SCCI. Because of the inclusion of both cross cutting areas in their
root cause analysis and corrective actions, the observations of the inspectors reflect the
licensees progress in addressing both areas. Documents reviewed are listed in the
Attachment.
b. Assessment
Inspectors determined that, in general, the licensees evaluation of the SCCI was
technically accurate and of sufficient depth to address the issue. The analysis was
determined to have adequately addressed operability, reportability, common cause,
generic concerns, extent-of-condition, and extent-of-cause. The inspectors also
determined that the licensee had appropriately identified and prioritized corrective
actions. However, the inspectors did make the following observations regarding the
licensees evaluation of the SCCI (for which the licensee initiated PER 311304):
- Inspectors noted that many of the actions identified to address the open SCCI were
similar to previous corrective actions to address weaknesses in the Problem
Identification and Resolution area (PERs 151140, 153438 and 136489) that had
proven to be ineffective over the long term. Inspectors also noted that previous
corrective actions (CA) included the actions taken to address weaknesses in the
area of timeliness of corrective actions for the P.1(d) SCCI closed out in NRC Mid-
Cycle Performance Review Letter for the period January - July 2009. The licensees
discussion of previous similar events included in the root cause report noted that
previous corrective actions had been unsuccessful at ensuring sustainable
improvements. However, a rigorous evaluation of why previous actions were
ineffective was not included.
- Inspectors noted that clearly defined success measures were not defined for the
critical aspects of all of the corrective actions to prevent recurrence (CAPRs)
identified in the root cause as required by licensee procedure PIDP-6, Root Cause
Analysis. Most notably, no success measures were defined in the root cause to
measure the critical aspect of sustainability of the CAPRs. Inspectors concluded
that, given the history of unsustainable corrective actions to address weaknesses in
the Problem Identification and Resolution area noted in the root cause, additional
success measures and effectiveness review actions were warranted to ensure
sustainable and effective corrective actions.
Inspectors determined that, in general, the corrective actions implemented to date or
scheduled to be implemented to address the SCCI were appropriate. The licensee
initiated CAPRs and additional corrective actions to address the three common causes
identified. The inspectors were able to evaluate the implementation of a sample of the
twenty-five completed corrective actions. During the review of selected records, the
inspectors identified two corrective actions which were not completely implemented as
intended, as follows:
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- CA 223536-039 was created as an Interim Corrective Action to address the Extent of
Cause (EOC) for the root cause. This action directed the CARB to reevaluate all
open root cause PERs to determine if the following were adequately addressed:
plant risk significance, timeliness of actions, and sufficiently detailed and timely
interim actions. The action was closed to a previously completed action from a
different PER, CA 214592-010, which was completed five months earlier. However,
inspectors identified that the scope of the completed action only included PERs
greater than one year old. The licensee initiated SR 294998 to address this issue.
important to safety for the previous two years to verify the adequacy of the previous
evaluations and CAs. The CA also directed an increase in sample size if necessary.
A contractor conducted the backwards assessment for the licensee and provided the
results in a report dated September 2, 2010. The licensee subsequently marked the
CA as complete. Inspectors reviewed the report and noted that it documented
eleven separate issues for immediate follow-up out of a sample of seven RCEs and
thirty-one ACEs reviewed. However, at the time of the inspection, 3 months after the
report was completed, the issues had not been evaluated and no consideration was
given to increasing the sample size based on the number issues identified. The
licensee initiated SR 295007 to address this issue.
Inspectors were unable to assess the effectiveness of the completed and open
corrective actions due to the number of open corrective actions and the limited time
since implementation of completed corrective actions.
c. Findings
No findings were identified.
4OA3 Event Follow-up
.1 (Closed) Licensee Event Reports (LERs) 05000296/2009-003-01 and -02, Reactor Core
Isolation Cooling System Inoperable Longer Than Allowed By the Technical
Specifications
a. Inspection Scope
The original LER 50-296/2009-003-00 dated May 24, 2010, and applicable PERs
200183,119628 and 246527, including cause determination and corrective action plans,
were reviewed by the inspectors and documented in Section 4OA3.2 of NRC inspection
report (IR) 05000296/2010003. As a result of this prior review, two violations of NRC
requirements were identified: NCV 05000296/2010003-02, Unit 3 RCIC System
Inoperable beyond the Technical Specifications Allowed Outage Time; and NCV
05000296/2010003-03, Failure to Provide Complete and Accurate Information in LER
0500296/2009-003-00. The NCV 05000296/2010003-03 was the result of the review of
the original LER, when the inspectors determined that, contrary to 10 CFR 50.9, LER
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0500296/2009-003-00 was not accurate or complete in all material aspects for which the
licensee initiated PER 246527. Specifically, the LER inaccurately reported the duration
of system inoperability, inaccurately reported the availability of HPCI while the RCIC was
inoperable, and did not report a previous event that occurred on the same unit with the
same cause as required by 10 CFR 50.73(b)(5).
As part of the PER 246527 corrective actions, the licensee issued a revised LER
0500296/2009-003-01 on July 15, 2010. The principal intent of this LER revision was to
establish the date that began the period of RCIC inoperability as March 22, 2006, and to
notify the NRC that additional time was needed to complete a determination of any
concurrent HPCI system inoperability. The licensee revised their commitment to
supplement the LER to September 30, 2010. Subsequently, the licensee issued their
second revised LER 0500296/2009-003-02 on August 31, 2010. This LER was revised
by the licensee to correct and update the LER narrative with an expanded timeline and
results from their efforts to retrieve high speed computer data regarding actual RCIC
pump performance. This second revision was also intended to address and correct any
missing or inaccurate information identified by the inspectors in the original LER. This
revised LER included changes to the Abstract, Description of Event, Cause of the Event,
Analysis of the Event, and Corrective Actions.
The second revision of the LER did specifically report a more accurate duration of
system inoperability, including when the nonconforming turbine electric governor-remote
(EG-R) had been installed; a discussion of concurrent HPCI unavailability while RCIC
was inoperable; and a discussion of the previous event on February 9, 2007 that
occurred on the same unit with the same cause. The inspectors reviewed the revisions
1 and 2 of the LERs, and verified the root causes and previously identified corrective
actions for the RCIC flow instabilities were not substantially different, except for the
additional clarifying information provided.
b. Findings
This LER is considered closed with one NRC identified finding related to the LER itself.
Introduction: A Severity Level IV, cited violation (VIO) of 10 CFR 50.9, Completeness
and Accuracy of Information, was identified by the inspectors for the licensees repeat
failure to provide complete and accurate information regarding the licensees LER
0500296/2009-003-02, Reactor Core Isolation Cooling System Inoperable Longer than
Allowed by Technical Specifications.
Description: Following the Unit 3 reactor scram on August 24, 2009, the RCIC system
auto-initiated as designed and injected into the reactor pressure vessel (RPV) restoring
reactor water level. Subsequent review of RCIC system operating parameters revealed
an unexpected level of instability in system flow and turbine control system response.
The RCIC system flowrate was discovered to have oscillated between approximately
300 gpm to 900 gpm. On September 12, 2009, Unit 3 conducted a shutdown for
unrelated maintenance and the RCIC EG-R hydraulic actuator was replaced. The
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licensee had the EG-R vendor conduct testing and inspection of the original EG-R to
determine the cause of the oscillations. The vendor determined that the cause of the
oscillations was due to a missing buffer piston and buffer spring in the EG-R. These
components were essential in providing the smoothing and/or dampening function of the
controller, without which resulted the observed flow oscillations. It was determined that
the EG-R was missing these components since original installation in 2006. On March
25, 2010, the licensee determined that the installation of this EG-R had rendered the
Unit 3 RCIC system inoperable which represented a condition prohibited by TS since
RCIC had been inoperable beyond the AOT of TS LCO 3.5.3. In addition, Unit 1 had
changed modes of operation without evaluating the impact on risk as required by TS
On May 24, 2010, the licensee submitted LER 05000296/2009-003-00. The LER
attributed the root cause for the RCIC flow oscillations to be the missing EG-R
components. However, the LER did not mention when the faulty EG-R had been
installed. Also, this LER inaccurately stated that RCIC had been inoperable from August
26, 2009, to September 12, 2009, and that HPCI was operable during this time period.
Furthermore, the LER failed to identify and describe the reactor scram event on
February 9, 2007 when the Unit 3 RCIC flow oscillations were first recognized, and did
not describe the subsequent corrective actions. The corrective actions following this
event included maintenance on a control system wiring terminal lug, EG-R needle valve
adjustment and turbine governor valve replacement. However, the subsequent post
maintenance testing was conducted using the routine quarterly surveillance procedure
which operated RCIC in a condensate storage tank (CST) recirculation mode, rather
than aligned for RPV injection. Since no RCIC oscillations were identified during the
surveillance test, the licensee erroneously concluded that the flow oscillations had been
corrected. Unbeknownst to the licensee the faulty EG-R only became a factor when
RCIC was actually injecting against the dynamic pressure head of the RPV. The
inspectors determined that, contrary to 10 CFR 50.9, the initial LER 0500296/2009-003-
00 was not accurate or complete in all material aspects for the reasons mentioned
above. The licensee then initiated PERs 232668 and 246527 and the NRC documented
a non-cited violation (i.e., NCV 05000296/2010003-03).
Subsequently, the licensee issued revised LERs 05000296/2009-003-01 on July 15,
2010, and 05000296/2009-003-02 on August 31, 2010. The inspectors reviewed the
revised LERs, and identified incomplete and inaccurate information in LER
0500296/2009-003-02. The inspector identified issues are detailed below:
- Section 5 Event Date was incorrectly documented as August 26, 2009. The event
date was March 22, 2006, following the replacement of the RCIC EG-R as
documented by the licensee in the cover letter of the first LER revision.
- Section I referenced time is not specific for when the licensee had actually
determined the RCIC had been previously inoperable which was March 25, 2010,
significantly distanced from the event date.
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- The narrative, Sections II, IV and VI, discussed the previous RCIC instability event
on February 9, 2007, but failed to describe the corrective actions taken to address
the RCIC oscillations (i.e., maintenance activities and post maintenance testing) that
proved unsuccessful but led the licensee to conclude via a functional evaluation that
the RCIC system was operable. Furthermore, the narrative did not describe why
these repairs and subsequent post maintenance testing did not resolve the RCIC
instabilities. The licensees business procedure BP-213, Managing TVAs Interface
With NRC, established the required guidance for writing and submitting LERs. This
guidance directed the licensee to utilize NUREG-1022, Event Reporting Guidelines
10 CFR 50.72 and 50.73. Section 5.2.5, Previous Occurrences, of NUREG-1022
states that if any earlier events, in retrospect, were significant in relation to the
subject event to discuss why prior corrective action did not prevent recurrence. This
same omission by the licensee, and the specific NUREG-1022 guidance, was
documented in detail as part of NCV 05000296/2010003-03.
- The narrative,Section IV, Analysis of the Event, incorrectly referenced oscillations
that occurred on February 9, 2007 as occurring on February 13, 2007.
- The narrative,Section V, Assessment of Safety Consequences, while discussing
periods of coincident HPCI unavailability with RCIC being inoperable, did not
address the resultant TS impacts to Unit 3.
- The narrative,Section VII.B, Previous LERs on Similar Events, indicated no similar
events. However, NUREG 1022 states that previous similar events are not
necessarily limited to events reported in LERs.
- The narrative,Section VII.C, Additional Information, referenced the two PERs for the
two separate RCIC flow oscillation events, but does not reference a PER for the
previous 10CFR50.9 NCV for incomplete and inaccurate LER information.
- The corrective actions established by PERs 232668 and 246527 to develop and
submit another LER revision that would address the inaccurate and incomplete
information, specifically documented in IR 05000296/2010003 for NCV
05000296/2010003-03, were not effective.
The licensee initiated PER 304722 to determine the cause of the inaccurate and
incomplete information contained in revised LER 0500296/2009-003-02, and to evaluate
if the LER should be further supplemented. The licensees guidance for corresponding
with the NRC required multiple levels of supervisory and management review and
concurrence on submittals, including LERs. Despite these multiple levels of review and
previous NRC identification of incomplete or inaccurate information for the original LER
documented in IR 05000296/2010-003, the licensees CAP and LER review process did
not prevent LER revision 2 from again containing inaccurate and incomplete information.
Based on extensive NRC involvement on the issue and previously completed NRC
regulatory action, the inspectors determined that the licensees failure to provide
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complete and accurate information in the LER was not a willful attempt to withhold
information, but rather a break down in the CAP, and LER submittal review and approval
process.
Analysis: Because violations of 10 CFR 50.9 are considered to potentially impede or
impact the regulatory process, they are dispositioned using the traditional enforcement
process. The inspectors concluded that the licensee had reasonable opportunity to
foresee and correct the incomplete/inaccurate information prior to the information being
submitted to the NRC. As a result, this issue was considered a performance deficiency.
The performance deficiency was ultimately considered to be more than minor per the
NRC Enforcement Manual, Section 2.10.F, since adequate corrective action was not
taken to ensure complete and accurate information was provided in LER revision 2, and
this finding was identified by the NRC. Furthermore, because the violation was NRC
identified and repetitive, this violation was dispositioned as a cited violation in
accordance with Section 2.3 of the NRC Enforcement Policy and Section 3.1.2 of the
NRC Enforcement Manual, and determined to be of Level IV significance based on
Section 6.9 of the NRC Enforcement Policy. No cross cutting aspect was assigned
because the ROP was not applicable.
Enforcement: 10 CFR 50.9, Completeness and Accuracy of Information, required, in
part, that information provided to the Commission by a licensee shall be complete and
accurate in all material respects. Contrary to the above, on August 31, 2010, the
licensee submitted a revised LER, as corrective action for a previous 10 CFR 50.9
violation involving the inoperability of the Unit 3 RCIC system, which was not complete
and accurate in all material respects. Specifically, the revised LER did not report the
correct event date, did not discuss prior corrective actions (e.g., maintenance and
testing) for a previous event, and why these corrective actions did not prevent
recurrence (as specifically documented in IR 05000296/2010003). This violation was
determined to be a Severity Level IV violation and was entered into the licensees
corrective action program as PER 304722. This is a violation of 10 CFR 50.9 and is
identified as VIO 05000296/2010005-03, Repeated Failure to Provide Complete and
Accurate Information in LER 0500296/2009-003-02. A notice of violation is attached.
.2 (Closed) LER 05000260/2010-003-00, Reactor Scram Due to Closure of the Main Steam
Isolation Valves and Subsequent Invalid RPS Scram from the Intermediate Range
Monitoring System
a. Inspection Scope
On June 9, 2010, Unit 2 experienced an automatic reactor scram from full power due to
an unexpected closure of the main steam isolation valves (MSIV) from a Primary
Containment Isolation Signal (PCIS) Group 1 actuation. The inspectors initial event
followup and evaluation of this event were documented in Section 4OA3.1 of IR
05000260/2010003. Since then, the inspectors reviewed the associated LER dated
August 9, 2010. Following completion of the root cause analysis, the licensee was
unable to determine a definitive cause for this event. However, two possible causes
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were identified: 1) Foreign material from the control air system might have caused the
2A (MSIV) direct current (DC) solenoid valve to bind; or 2) Intermittent electrical fault in
the DC power system. Although neither of these possible causes were confirmed, the
licensee developed corrective actions to address both of them.
b. Findings
No findings were identified. This LER is considered closed.
.3 (Closed) LER 05000260/2010-001-00, Condition Prohibited By Technical Specifications
When Two Emergency Core Cooling Systems, Loops I and II of the Residual Heat
Removal System Low Pressure Coolant Injection System, Became Inoperable
a. Inspection Scope
The inspectors reviewed LER 50-260/2010-001, dated April 26, 2010, and the applicable
PER 218493, including associated apparent cause determination and corrective action
plans.
On February 25, 2010, operators determined that Unit 2 had entered TS Limiting
Condition of Operation (LCO) 3.0.3 when both loops of RHR were declared inoperable.
Within an hour of entering TS LCO 3.0.3, operators began reducing reactor power to
shutdown Unit 2 as required by TS. However, once operators realigned the ECCS keep
fill system to increase RHR Loop II system pressure, they were able to declare RHR
Loop II operable again. At which point, TS LCO 3.0.3 was exited and reactor power was
returned to 100 percent the same day. Unit 2 had entered TS LCO 3.0.3 for
approximately 80 minutes due to both loops of RHR being inoperable. The conditions
that led up to both loops of RHR being declared inoperable are described below.
On December 18, 2009, Operational Decision Making Issue (ODMI) 210437 was issued
to address RHR system Loop II discharge piping elevated temperatures due to reactor
coolant seat leakage past the RHR Loop II injection line discharge check valve and gate
valve. This ODMI established monitoring guidelines and specific temperature thresholds
for ensuring RHR Loop II discharge piping remained sub-cooled to preclude steam
voiding. On February 24, 2010, RHR system Loop I was removed from service for
planned maintenance. Then on February 25, operators recognized that RHR Loop II
discharge temperature had increased to 264° Fahrenheit (F) which exceeded the ODMI
trigger value (i.e., 260°F) for ensuring operability. However, per the ODMI instructions,
operators were able to promptly lineup an alternate keep fill source that increased RHR
Loop II discharge pressure which restored sub-cooled conditions.
Subsequent engineering evaluation by the licensee, determined that the actual ODMI
trigger value was indeed conservative for the actual RHR Loop II discharge piping
temperatures and keep fill pressure. This evaluation was able to conclude that the
elevated RHR Loop II discharge temperatures of February 25 had not reached steam
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saturation conditions. Furthermore, an ultrasonic testing (UT) examination of the RHR
Loop II discharge piping on February 26 confirmed the absence of any steam voiding.
Based on the licensees evaluation, and UT exam, the RHR system Loop II was fully
operable and capable of performing its intended safety functions on February 25, 2010.
b. Findings
No findings were identified. This LER is considered closed.
.4 Unit 3 Manual Reactor Scram
a. Inspection Scope
On December 26, 2010, Unit 3 was manually scrammed from approximately 90% power
due to high vibrations on the main generator exciter bearings that exceeded the required
threshold for tripping the main turbine. Upon notification by the shift manager, the
inspector responded to the control room and verified that the unit was stable in Mode 3
(Hot Shutdown), and confirmed that all safety-related mitigating systems had operated
properly. The inspector evaluated safety equipment and operator performance before
and after the event by examining existing plant parameters, strip charts, plant computer
historical data displays, operator logs, and the critical parameter trend charts in the
reactor scram report. The inspector also interviewed available onshift Operations
personnel, examined the implementation of the applicable ARPs and AOIs, including 3-
AOI-100-1, Reactor Scram, and reviewed the written notification made in accordance
with 10 CFR 50.72. The inspector discussed the preliminary cause of the bearing high
vibrations with responsible Operations personnel.
b. Findings
No findings were identified during the initial event followup.
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4OA5 Other Activities
.1 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 reviews and inspection activities.
b. Findings
No findings were identified.
.2 (Closed) Unresolved Item (URI) 05000259, 260 and 296/2010004-01, Uncontrolled
Materials Adversely Impacted the Capability of the EDG Building Emergency Drainage
System to Mitigate an Internal Flooding Event
a. Inspection Scope
This URI 05000259, 260 and 296/2010004-01 was opened pending additional
information from the licensee and subsequent review by the inspectors. The licensee
initiated PER 256390 to remove the temporary equipment from the Unit 1/2, and Unit 3,
EDG building lower corridors. The inspectors reviewed the licensees actions and
conducted tours of the EDG buildings to verify whether all temporary equipment was
removed or properly restrained per the licensees procedural requirements. Additionally,
the inspectors reviewed the results of WOs 111530751 and 111530754 to verify the as-
found condition of the EDG building floor drain sumps were operable, and whether the
building sump high level alarm would alert the main control room. The licensee also
initiated PER 268624 to perform a past operability evaluation of the EDG building
emergency drain function which considered the potential adverse impacts of the specific
items left in the EDG building lower corridors. Furthermore, the inspectors reviewed the
licensees annunciator response procedures (ARP) for a high water level in the DG
building sump to verify whether required operator actions would be timely and sufficient
to prevent an adverse impact to the EDGs from an internal flooding event.
b. Findings
No findings were identified. However the inspectors identified a minor violation of TS
5.4.1.a because the licensee failed to implement the requirements of licensee procedure
0-TI-471, Temporary Equipment Control, Rev. 04 in the common U1/2 EDG building
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and U3 EDG building. TS 5.4.1.a required, in part, that written procedures shall be
established, implemented, and maintained covering the activities and procedures
recommended in Regulatory Guide (RG) 1.33, Rev. 2, Appendix A. Section 1c, of RG
1.33, Rev. 2, Appendix A required the licensee to have a procedure for Equipment
Control. Licensee procedure, 0-TI-471, Temporary Equipment Control, section 7.1.1
required temporary equipment to be removed from plant areas; or, attended, restrained
or stored. Contrary to the above requirements, the inspectors identified unattended and
loose materials in the EDG building lower corridors that included potential licensing basis
internal flooding sources (e.g., the EECW North and South supply header piping). This
failure to comply with TS 5.4.1.a constitutes a violation of minor significance that is not
subject to enforcement action in accordance with the NRCs Enforcement Policy.
.3 (Closed) Notice of Violation (VIO) 07200052/2010-003-01 (EA-10-215), Repeated
Failure to Control Transient Combustibles in Proximity of the Independent Spent Fuel
Storage Facility (ISFSI)
a. Inspection Scope
The inspectors reviewed the licensees response to VIO 07200052/2010-003-01 (EA-10-
215) dated November 29, 2010. The licensees corrective actions included
establishment of an ISFSI Pad Escort Zone (i.e., fenced in area of the ISFSI pad) with
appropriate posted signage and gate locks to preclude unattended vehicles from being
parked on the pad and to require Operations escort for any access to the ISFSI pad.
The licensee also established an ISFSI Pad Exclusion Zone (i.e., an area 150 feet from
any point on the ISFSI pad) that would be routinely monitored by Operations to ensure
transient combustibles were maintained at least 150 feet from the ISFSI pad.
The inspectors conducted a tour of the ISFSI Pad Escort Zone and ISFSI Pad Exclusion
Zone to verify the licensees controls were in place and were being effectively applied.
The inspectors also reviewed the ISFSI Pad Protection Plan instructions and briefing
sheet guidance contained in the latest BFN Operations Daily Instructions (ODI) dated
December 15, 2010. Furthermore, the inspectors reviewed the latest revision (revision
210) of 0-GOI-300-1, Operator Round Logs, Attachment 12, Outside Operator Round
Log, Sections 6.0, Steps (23) and (24), that define and verify the ISFSI Pad and
Exclusion Zones are clear of uncontrolled transient combustibles.
b. Findings
No findings were identified. This VIO is considered closed.
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.4 Follow-up On Alternative Dispute Resolution Confirmatory Orders (IP 92702)
a. Inspection Scope
During the inspection period the inspectors completed a review of TVAs completion of
Confirmatory Order for Office of Investigation Report Nos. 2-2006-025 & 2-2009-003,
item numbers 2, 5, 7, 8, and 9. These individual items are considered closed.
2. By no later than seven (7) calendar days after the issuance of this Confirmatory
Order, a member of TVAs executive management responsible for the licensees
nuclear power plant fleet will, in writing, communicate TVAs policy, and the
expectations of management, regarding the employees rights to raise concerns
without fear of retaliation in the context of this Confirmatory Order.
5. By no later than sixty (60) calendar days after the issuance of this Confirmatory
Order, representatives from the TVAs OGC and Human Resources shall conduct a
lessons learned training session
7. TVA shall incorporate a discussion of NRCs employee protection rule in the next
revision of the One Team, One Fleet, One TVA booklet. The next revision will be
completed by no later than December 31, 2010.
8. By no later than ninety (90) calendar days after the issuance of this Confirmatory
Order, TVA shall modify its contractor in-processing program to ensure that a TVA
representative provides a presentation regarding the CRP program and the TVAs
SCWE policy during the contractor in-processing sessions.
9. By no later than ninety (90) calendar days after the issuance of this Confirmatory
Order, TVA shall revise its training program for new supervisors to incorporate a
classroom discussion of the NRCs employee protection rule and the Companys
policy on SCWE.
The inspectors also performed a follow-up review of TVAs implementation of
Confirmatory Order for Office of Investigation Report Nos. 2-2006-025 & 2-2009-003,
item numbers 1, 6, and 10. These items are not closed.
1. By no later than ninety (90) calendar days after the issuance of this Confirmatory
Order, TVA shall implement a process to review proposed licensee adverse
employment actions at TVAs nuclear plant sites before actions are taken to
determine whether the proposed action comports with employee protection
regulations, and whether the proposed actions could negatively impact the SCWE.
6. Through calendar year 2013, TVA shall conduct Town Hall-type meetings at least
annually at its nuclear power plants and corporate office with TVA and contractor
employees which address topics of interest, including a discussion on TVAs policy
regarding fostering a SCWE.
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10. TVAs annual online computer-based training course initiative, which discusses the
components of a nuclear safety culture, what is meant by a SCWE, and the avenues
available to raise concerns, shall be maintained through calendar year 2013.
b. Findings and Observations
No findings were identified.
The inspectors raised a concern during the inspection of item #1 about the content of
TVA's Adverse Employment Action Procedure - TVA-SPP-11.10. TVA staff understood
the concern and were in the process of incorporating modifications to the procedure with
an expected completion of late February or early March 2011.
4OA6 Meetings, Including Exit
.1 Exit Meeting Summary
On January 11, 2011, the senior resident inspector presented the inspection results to
Mr. Keith Polson and other members of the sites staff, who acknowledged the findings.
All proprietary information reviewed by the inspectors as part of routine inspection
activities were properly controlled, and subsequently returned to the licensee or
disposed of appropriately.
An exit meeting was conducted on October 15, 2010, to discuss the findings of the
71111.11B inspection. The inspectors confirmed that no proprietary information was
reviewed during this inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Enclosure 1
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
T. Albright, Simulator Manager
S. Austin, Licensing
W. Baker, Operations Support Superintendent
S. Bono, Maintenance Manager
J. Boyer, System Engineering Manager
O. Brooks, Operations LOR Supervisor
W. Byrne, Site Security Manager
P. Chase, Site Nuclear Assurance Manager
J. Colvin, Engineering Programs Manager
P. Donahue, Assistant Engineering Director
G. Doyle, Assistant to the Site Vice President
M. Durr, Director of Engineering
M. Ellet, Maintenance Rule Coordinator
J. Emens, Licensing Manager
B. Evans, Instrumentation and Controls Superintendent
A. Feltman, Emergency Preparedness Manager
N. Gannon, Plant General Manager
K. Gregory, Director Projects
K. Groom, Mechanical Design Engineering Supervisor
B. Jones, Mechanical Maintenance Superintendent
J. Keck, Reactor Engineering Manager
S. Kelly, Assistant Work Control Manager
R. King, Design Engineering Manager
D. Malinowski, Operations Training Manager
T. Marlow, Director of Safety and Licensing
M. McAndrew, Assistant Operations Manager
O. Miller, Operations Manager
J. Morris, Director Training
R. Norris, Radiation Protection Manager
W. Nurnberger, Work Control Manager
W. Pearce, Performance Improvement Manager
K. Polson, Site Vice President
M. Rasmussen, Operations Superintendent
T. Smith, Component Engineering Manager
J. Underwood, Chemistry Manager
S. Walton, Electrical Maintenance Superintendent
D. Zielinski, Operations Training
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
05000259/2010005-01 AV RHR Subsystem Inoperable Beyond the TS
Allowed Outage Time (Section 1R20.1(1))05000296/2010005-03 VIO Repeated Failure to Provide Complete and
Accurate Information in LER 0500296/2009-003-02
(Section 4OA3.1)
Opened and Closed
05000259/2010005-02 NCV Degraded 1C RHR Motor Rendered One RHR
Subsystem Inoperable Beyond the TS Allowed
Outage Time (Section 1R20.1(2))
Closed
07200052/2010-003-01 VIO Repeated Failure to Control Transient
Combustibles in Proximity of the Independent
Spent Fuel Storage Facility (Section 4OA5.3)
05000296/2009-003-01 LER Reactor Core Isolation Cooling System Inoperable
Longer Than Allowed By the Technical
Specifications (Section 4OA3.1)
05000296/2009-003-02 LER Reactor Core Isolation Cooling System Inoperable
Longer Than Allowed By the Technical
Specifications (Section 4OA3.1)
05000260/2010-003-00 LER Reactor Scram Due to Closure of the Main Steam
Isolation Valves and Subsequent Invalid RPS
Scram from the Intermediate Range Monitoring
System (section 4OA3.2)
05000260/2010-001-00 LER Condition Prohibited By Technical Specifications
When Two Emergency Core Cooling Systems,
Loops I and II of the Residual Heat Removal
System Low Pressure Coolant Injection System,
Became Inoperable (section 4OA3.3)
05000259, 260, 296/2010004-01 URI Uncontrolled Materials Adversely Impacted the
Capability of the EDG Building Emergency
Drainage System to Mitigate an Internal Flooding
Event (Section 4OA5.2)
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
3
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 2 (Section
4OA5.4)
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 5 (Section
4OA5.4)
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 7 (Section
4OA5.4)
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 8 (Section
4OA5.4)
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 9 (Section
4OA5.4)
Discussed
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 1 (Section
4OA5.4)
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 6 (Section
4OA5.4)
05000259, 260, 296- 00 ORD 12/29/2009 Confirmatory Order Action 10 (Section
4OA5.4)
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
0-GOI-200-1, Freeze Protection Inspection, Rev. 66
Operating Logs
0-AOI-100-3, Flood Above Elevation 558, Rev. 33
MPI-0-260-DRS001, Inspection and Maintenance of Doors, Rev. 38
MPI-0-000-INS001, Inspection of Flood Protection Devices, Rev. 12
SPP-10.14, Freeze Protection, Rev. 0
0-GOI-200-1, Freeze Protection Inspection, Revs. 64, 65, 66
SR 271672
PER 272691
SR 288551
PER 289066
WO 110821237 - Perform Inspection of the Diesel Bldg Flood Protection Portable Bulkheads
WO 06-714206-000 - Perform Inspection of the Diesel Bldg Flood Protection Portable
Bulkheads
WO 08-713109-000 - Perform Inspection of the Diesel Bldg Flood Protection Portable
Bulkheads
FPDQ (Freeze Protection Report), RFP-NWM117, dated 11/2/2010
WO # 01-011443-001, Generate Report
WO # 05-725438, Duct Heater
WO # 08-710085-000, D/G Heaters
WO # 09-725938-000, D/G Space Heater
WO # 09-726137-000, Strip Heater
WO # 110980907, RCW A Drain Valve
WO # 111300432, Expansion Tank Safety Valve
WO # 111361895, ADHR Instrumentation Heaters
WO # 111537776, RHRSW Pump B1
WO # 111581385, EECW Strainer Valve
SR # 271610, EECW Strainer Valve
SR # 277461, Freeze Protection GOI
SR # 277480, RHRSW Tunnel Doors
SR # 277481, Cancel WO
PER # 277476, Freeze Protection GOI
PER # 277482, RHRSW Tunnel Doors
PER # 277484, Cancel WO
BFN Operations Log, 11/6/2010 Midnight Shift, 11/7/2010 Day Shift
44N267, Diesel Generator Building Personnel Access Doors Portable Bulkhead, Rev. A
3-47W587-1, Standby Diesel Gen Bldg Unit 3, Mechanical Drains & Embedded Piping, Rev. 3
3-47W587-2, Standby Diesel Gen Bldg Unit 3, Mechanical Drains & Embedded Piping, Rev. 2
0-47E851-4, Flow Diagram Drainage, Rev. 13
Section 1R04: Equipment Alignment
0-OI-72, Auxiliary Decay Heat Removal System, Rev. 48
0-OI-72, ADHR System, Attachment 1, Valve Lineup Checklist, Eff. Date 11-10-2009
0-OI-72, ADHR System, Attachment 2, Panel Lineup Checklist, Eff. Date 7-14-2006
0-OI-72, ADHR System, Attachment 3, Electrical Lineup Checklist, Eff. Date 5-04-2010
0-OI-72, ADHR System, Attachment 2, Instrument Inspection Checklist, Eff. Date 11-12-2007
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
5
FSAR 10.22 Auxiliary Decay Heat Removal System (ADHR)
3-OI-82, Standby Diesel Generator System, Rev. 99
3-OI-82/ATT-1D, Standby Diesel Generator 3D Valve Lineup Checklist, Rev. 96
3-OI-82/ATT-2D, Standby Diesel Generator 3D Panel Lineup Checklist, Rev. 96
3-OI-82/ATT-3D, Standby Diesel Generator 3D Electrical Lineup Checklist, Rev. 95
3-OI-82/ATT-4D, Standby Diesel Generator 3D Instrument Inspection Checklist, Rev. 96
FSAR 8.5 Standby AC Power Supply and Distribution
3-OI-75, Core Spray System, Rev. 50
3-OI-75, Attachment 1, Core Spray System Valve Lineup Checklist, Eff. Date 8-28-09
3-OI-75, Attachment 2, Core Spray System Panel Lineup Checklist, Eff. Date 4-08-08
3-OI-75, Attachment 3, Core Spray System Electrical Lineup Checklist, Eff. Date 8-28-09
3-47E814-1, Core Spray System Flow Diagram, Rev. 34
0-47E873-1, -2, Flow Diagram Aux Decay Heat Removal System, Sheet 1 & 2, Date 7-12-97
0-47E610-72-1, -2, Control Diagram Aux Decay Heat Removal System, Sheet 1 & 2, Date 7-12-97
0-15E900-1, Electrical Instrument Details, Date 8-6-97
0-15E740-1, Single-Line Diagram ADHR Service Entrance and MCC, Date 7-12-97
Section 1R05: Fire Protection
Fire Protection Report, Volume 1, Fire Protection Plan, Units1/2/3, Rev. 8
Fire Protection Report, Volume 1, Fire Hazards Analysis, Units1/2/3, Rev. 8
Fire Protection Report, Volume 2, Sections IV.7, Pre-Plan No. RX3-519, Rev. 7
Fire Protection Report, Volume 2, Sections IV.8, Pre-Plan No. RX3-519, Rev. 7
Fire Protection Report, Volume 2, Sections IV.8, Pre-Plan No. RX3-565, Rev. 7
Fire Protection Impairment Permit #s; 09-1920
Fire Watch Route/Coverage Sheet: Permit/Route #: Reactor Bldg. & Turbine Bldg, 10/16/10 to
10/18/10
TVAN Fire Watch Briefing and Turnover Form: Permit/Route #: U1, 2, &3 RX/TB Bldg, Multiple
Sheets from 10/16/10 to 10/18/10
SR 268995
SR267561
SR267696
SR267624
SR267677
SR267630
Fire Protection Report, Volume 2, Sections IV.13, Pre-Plan No. DG3-565, Revision 8
Fire Protection Report, Volume 2, Sections IV.13, Pre-Plan No. DG3-583, Revision 8
Fire Protection Report, Volume 1, Fire Hazards Analysis, Units1/2/3, Rev. 8
Fire Protection Report, Volume 1, Fire Protection Plan, Units1/2/3, Rev. 8
Section 1R08: Inservice Inspection Activities
GE-UT-511, Procedure for the Automated Examination of Core Spray Piping Welds Contained
within the Reactor Pressure Vessel, Revision 7
N-PT-9, Liquid Penetrant Examination of ASME and ANSI Code Components and Welds,
Revision 0034
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
6
N-UT-64, Generic Procedure for the Ultrasonic Examination of Austenitic Pipe Welds, Revision
0011
N-UT-66, Generic Procedure for the Ultrasonic Examination of Weld Overlay Austenitic Pipe
Weld, Revision 0006
N-UT-76, Generic Procedure for the Ultrasonic Examination of Ferritic Pipe Welds, Revision
0007
NETP-112, BWR Reactor Pressure Vessel Internals Inspections (RPVII), Revision 0000
54-ISI-363-05, Remote Underwater In-Vessel Visual Inspection of Reactor Pressure Vessel
Internals, Components, and Associated Repairs in Boiling Water Reactors, Revision
10/21/2008
54-ISI-850-007, Manual Ultrasonic Examination of BWR Reactor Vessel Nozzle Inner Radius
Regions and Nozzle to Shell Welds (inner 15%), Revision 9/7/2010
PDI-UT-6, Generic Procedure for Ultrasonic Examination of Reactor Pressure Vessel Welds,
Revision 3/17/2009
Problem Evaluation Report (PER) 156982, U1C7 Jet Pump Restrainer Bracket Indication
PER 275955, Indications found on Core Spray Downcomer A, Weld P4a
PER 275958, Lost Quals after being requalified
PER 277618, U1R8 Jet Pump Wedge Wear and Set Screw Gaps/Indications
Report #: 0801464.401.R0, BFNP Unit 1 Cracked Jet Pump Set Screw Tack Welds Evaluation
Report #: BFN1-01-JLCJ2, Browns Ferry Nuclear Power Station- Unit 1 Core Spray Piping
Ultrasonic Examination
Section 1R11: Licensed Operator Requalification
TRN-11.4, Continuing Training for Licensed Personnel, Rev. 16
SPP-10.0, Plant Operations, Rev. 05
OPDP-1, Conduct of Operations, Rev. 18
Benchmark Tests:
Unit 2 PLU Trip from 100% power 7/8/04
Unit 2 Scram(RFP 2A/2B trip) at 100% power 8/5/05
Unit 3 Power Level Imbalance 12/31/07
Design Changes:
DCR B 1538 (SDCR B1538) "Replace Unit 2 Main Generator Circuit Brown Boveri DR Air Blast
breaker with new ABB SF6 HEC-7 type
General Items Reviewed:
License Reactivation Packages (5).
LORP Training Attendance records (15).
Medical Files (20).
Remedial Training Records (15).
Remedial Training Examinations (15).
Feedback Summaries (50).
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
7
License Event Reports (LER):
LER 50-259/2009-001-00, Turbine Trip and Reactor Scram Due to Power Load Unbalance
Signal on Main Generator (2/18/2009)
LER 50-259/2009-002-00, Unexpected Logic Lockout Of The Loop II Residual Heat Removal
System Pumps (3/21/2009)
LER 50-259/2009-003-00, A Train Standby Gas Treatment System Inoperable Longer Than
Allowed by The Technical Specification (6/19/2009)
LER 50-259/2009-004-00, High Pressure Core Injection Found Inoperable During Compensate
Header Level Switch Calibration and Functional Test (7/24/2009)
LER 50-260/2009-001-00, Manual Reactor Scram following Stator Cooling Water Equipment
Failure (2/16/2009)
LER 50-260/2009-007, Manual Scram During Removal of a Reactor Feedwater Pump from
Service
LER 50-260/2009-002-01, Leak In An ASME Class 1 Code Reactor Pressure Boundary Pipe
(05/21/2009
LER 50-260/2009-003-00, Main Steam Relief Valve As found Setpoint Exceeded Technical
Specification Lift Pressure (6/9/2009)
LER 50-260/2010-003, Reactor Scram Due to Closure of the Main Steam Isolation Valves and
Subsequent Invalid RPS Scram From the Intermediate Range Monitoring System (6/9/2010)
LER 50-260/2010-001, Condition Prohibited by Technical Specifications, (2/25/2010)
LER 50-260/2010-002, Failure to Meet the Requirement of Technical Specification Limiting
Condition for Operation Due to Inoperable Primary containment Isolation Instrumentation
LER 50-260/2010-004, HPCI Isolation During Time Delay Relay Calibration (6/16/2010)
LER 50-260/2010-005, High Pressure Coolant Injection System Isolation Experienced During
Performance of High Pressure Coolant Isolation Steam Supply Low Pressure Functional Test
(7/12/2010)
LER 50-269/2010-001, Safety relief Valves As-Found Setpoints Exceeded Technical
Specification Lift Pressure Values (4/20/1010)
LER 50-269/2010-002-00, A Subsystem of the Standby Liquid Control System was Inoperable
Longer than Allowed by the Plants Technical Specification (4/20/2010)
LER 50-269/2010-003-01, Multiple Test Failures of Excess Flow Check Valves (3/26/2010)
Malfunction Tests:
Condensate Pump Trip (FW01) completed 9/4/09
Loss of Condenser Vacuum (OG02) Completed 9/18/09
RCIC Low Suction Pressure Turbine Trip (RC03 Completed 9/27/09)
JPM Packages:
JPM 231 Operator 1 Manual Actions 0-SSI-16
JPM 249 Control Room Abandonment Attachment 4 Part A
JPM 224 Transfer of 480V HVAC Board B Power Supplies
JPM 238 Operator 3 Manual Actions 0-SSI-1-1
Unit 2 Simulator Information:
Transient #1 Manual Scram Completed 8/26/09
Transient #2 Simultaneous Trip of all Feed Pumps Completed 8/26/09
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
8
Transient #3 Simultaneous Closure of all MSIVs Completed 8/26/09
Transient #4 Simultaneous Trip of all Recirc Pumps Completed 8/26/09
Transient #5 Single Recirc Pump Trip Completed 8/26/09
Transient #6 Turbine Trip < 30% Power Completed 8/26/09
Transient #7 Manual Rate Power Ramp Completed 8/26/09
Transient #8 Max Size LOCA with LOOP Completed 8/26/09
Transient #9 Max Size Unisolable Main Steam Line Rupture Completed 8/26/09
Transient #10 MSIV Isolation and Relief Valve Failure Completed 8/26/09
100% Steady State Test Completed 8/26/09
75% Steady State Test Completed 8/26/09
50% Steady State Test Completed 8/26/09
Stability Test (Drift) Completed 8/26/09
Real Time Test Completed 8/26/09
Written Examination Reviewed:
Requal Written SRO exams for weeks 2 and 5 of 2009.
Section 1R12: Maintenance Effectiveness
Cause Determination Evaluation (CDE) 750, CS System I Logic Power Functional Failure
CDE 823, 1B CS Room Cooler Fan Functional Failure
CDE 867, 1B CS Room Cooler Low EECW Flow 1/28/09
CDE 864, 1B CS Room Cooler Low EECW Flow 2/09/09
CDE 862, 1B CS Room Cooler Low EECW Flow 9/13/09
CDE 852, 1B CS Room Cooler Low EECW Flow 11/19/09
CDE 897, 1B CS Room Cooler Low EECW Flow 2/17/10
CDE 925, 1B CS Room Cooler Functional Failure Due to Low EECW Flow
CDE 835, Unit 2 CS I Unavailable Due to Elevated Fluid Temperature 10/05/09
CDE 863, 2B CS Room Cooler Low EECW Flow
CDE 880, 2D CS Pump Breaker Functional Failure
CDE 881, Unit 2 CS I Unavailable Due to Elevated Fluid Temperature 1/10/10
CDE 836, 3EA Shutdown Board Loss of Control Power Functional Failure
FSAR Section 6.4.3 Core Spray System, BFN-23.3
OPL171.045 License Operator Training, Core Spray System, Rev. 11
PER 209302, Core Spray Venting
PER 219100, 3A CS and 3A RHR Room Cooling Coils Not Meet Original Specifications
PER 221650, U3 Core Spray Piping Indications Re-Inspection
PER 227894, Re-Status of CS Systems to (a)(1)
PER 236909, 1B CS Room Cooler Failed
PER 238523, CS II Room Cooler Testing Weekly
Technical Specifications and Bases 3.5.1 ECCS-Operating, Amendment 249 and Rev. 50
respectively
Units 1, 2, and 3 Function 75-B Core Spray (a)(1) Plan, Rev 0, Effective Date 6/29/10
WO 10569918, Replacement of Unit 1 Testable Check Valve 75-26
WO 10569919, Replacement of Unit 3 Testable Check Valve 75-26
WO 110717766, 3A CS Pump Oil Change Due to ISO Particle Count
WO 110714652, 3C CS Pump Oil Change Due to ISO Particle Count
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
9
WO 110874232, CS 75-53 Metal Particles in Motor Clutch Housing
WO 110900580, 3A CS Pump Cyclone Separator Tubing Against Pedestal
BFPER940777, Recirculation Pump 2B Discharge Valve Failure to Close
BWROG-TP-09-005, Inspection of Motor Operated Valve Limitorque AC Motors with
Magnesium Rotors, Rev. 0
Flowserve Technical Update 06-01, Reliance Motors/Magnesium Rotors, dated December 26,
2006
Flowserve Technical Update 08-01, Reliance Motors/Magnesium Rotors, dated December 19,
2008
GE SIL 425, EQ Test Anomalies of Reliance Motors in Limitorque Valve Operators, Rev. 1
NRC Information Notice 86-02: Failure of Valve Operator Motor During Environmental
Qualification Testing, dated November 20, 2006
NRC Information Notice 2006-26: Failure of Magnesium Rotors in Motor-Operated Valve
Actuators, dated November 20, 2006
PER 95431, Failure of 3-MVOP-68-77
PER 95610, PM Program for Magnesium Rotor Motors
PER 95611, Motor Start Attempts
PER 98884, Predictive Monitoring of Reactor Recirc Motors
PER 162116, MOV Users Group Inspection Guidance
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
PRA Evaluation Response BFN-0-10-114, Revs 0 and 1
Unit 1 Operator Work Around #1-072-OWA-2010-0135, Alternate Makeup to Secondary Basin
for ADHR B Primary Heat Exchanger Leak
Unit 1 ORAM Safety Function Status reports dated October 28, 2010
Operator chronological logs for October 28, 2010
Unit 1 ORAM Safety Function Status reports dated October 26, 2010
Operator chronological logs for October 26, 2010
Section 1R15: Operability Evaluations
BFN Operators Log for October 4 through 6, 2010
Design Criteria BFN-50-7082, Standby Diesel Generator, Rev. 13
EMD-ESI Diesel Generator Owners Group, Lube Oil Issue and Guidance Document, Rev. 1,
January, 2006
EMD-ESI Diesel Generator Owners Group, Operating Practice Guidance: Loss of Circulating
and/or Turbocharger/Soak Back Oil Pump, Revised April 2006
FSAR Section 8.5, Standby AC Power Supply and Distribution, BFN-23
Licensed Operator Lesson Plan OPL171.038, Diesel Generators and Standby Auxiliary Power
Systems, Rev. 14
Operating Instruction 3-OI-82, Standby Diesel Generator System, Rev. 99
Operator Workaround 3-082-OWA-2010-0124, 3-TS-82-7B Diesel Generator 3B Immersion
Heater Temperature Switch has failed
PER 260536, DG 3EB TS-82-7B Immersion Heater Temperature Switch Not Controlling
Properly
Technical Specifications and Bases 3.8.1, AC Sources - Operating, Amendment 215
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
10
Unit 3 Reactor Building Operator Rounds for October 1 through 7, 2010
PER 209288
PER 254463
PER 2710558
SR 269892
SR 92821
WO 08-712742-001,
WO 09-710550-000
Functional Evaluation, B Diesel Generator Loading Limitation PER 209288, 254463, SR 269892
0-OI-82, Standby Diesel Generator System, Rev. 112
0-SR-3.8.1.1(B), Diesel Generator B Monthly Operability Test, Rev. 45
0-SR-3.8.1.7(B), Diesel Generator B 24 Hour Run, Rev. 17
FSAR Section 8.5
Prompt Operability for C3 EECW Pump (PER 257317)
WO 111031504, BFN-0-PMP-023-0091 [C3 EECW Pump] Packing Replacement
EECW Pump Shaft Evaluation by OEM dated October 6, 2010
WO: 111530751
WO: 111530754
PER 268624
Diesel Generator Building Emergency Drain Piping Past Operability Evaluation, PER 268624
PER 256390
SR 263466
SR 263491
0-TI-471, Temporary Equipment Control, Rev. 04
1-ARP-9-7C, Annunciator Response Procedure Panel 9-7, Rev. 21
3-ARP-9-7C, Annunciator Response Procedure Panel 9-7, Rev. 31
1-ARP-9-20A, Annunciator Response Procedure Panel 1-9-20, Rev. 29
PER 178142
Functional Evaluation 43661, Rev. 4
Operator Work Around (OWA) 0-082-OWA-2009-0095
SR 73153
SR 230938
PER 244607
PER 217659
WO-09-720120-001
2-BFN-RTP-082, Restart Test Program for the Standby Diesel Generators, Rev. 0
2-BFN-RTP-082, Restart Test Program for the Standby Diesel Generators, Rev. 1
2-BFN-RTP-082, Restart Test Program for the Standby Diesel Generators, Rev. 2
BFN-50-7082, Detailed Design Criteria Document Standby Diesel Generator, Rev. 15
BFN-50-7200E, Detailed Design Criteria Document 4kV AC Auxiliary Power System, Rev. 12
Drawing: 0-45E724-1, Wiring Diagram 4160V Shutdown BD A Single Line, Rev. 26
0-AOI-57-1A, Loss of Offsite Power (161 and 500kV)/Station Blackout, Rev. 77
PER 255823, Holtec cask FSAR information insufficient to ensure MPC-68 loaded per analysis
assumptions.
Functional Evaluation for PER 255823, Rev. 0
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
11
Functional Evaluation Quality Review Grading Sheet, PER 255823, Dated 11/02/2010
SR 254930, Holtec cask MPC-68
Holtec Document ID 1031135, dated 9-23-2010
Holtec Document ID 1031137RI dated 10-27-2010
Holtec FSAR, Rev. 2
Holtec Technical Specification Bases, Rev. 7
Section 1R18: Plant Modifications
1-SI-4.7.A.2.a-f, Primary Containment Integrated Leak Rate Test, Rev. 4
SR 301210, CILRT Procedure Enhancement
PER 302266, CILRT Procedure Enhancement
NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 0
SPP-9.4, 10 CFR 50.59 Evaluations of Changes, Tests, and Experiments, Rev. 8
1-SR-3.3.5.1.2 (ATU A), Core and Containment Cooling Systems Analog Trip Unit Functional
Test, Rev. 4
1-SR-3.3.5.1.2 (ATU B), Core and Containment Cooling Systems Analog Trip Unit Functional
Test, Rev. 5
1-SR-3.3.5.1.2 (ATU C), Core and Containment Cooling Systems Analog Trip Unit Functional
Test, Rev. 4
1-SR-3.3.5.1.2 (ATU D), Core and Containment Cooling Systems Analog Trip Unit Functional
Test, Rev. 3
DWG 1-45E670-2, Wiring Diagrams, ECCS Div. I Analog Trip Units Schematic, Rev. 3
DWG 1-45E670-8, Wiring Diagrams, ECCS Div. II Analog Trip Units Schematic, Rev. 3
BFN-VTD-AG01-0060, AGASTAT, Nuclear Qualified Control Relays, Rev. 0
NEI 96-07, Guidelines for 10 CFR 50.59 Implementation, Rev. 1
Section 1R19: Post-Maintenance Testing
0-OI-72, Auxiliary Decay Heat Removal System, Rev. 48
0-OI-72, ADHR System, Attachment 1, Valve Lineup Checklist, Eff. Date 11-10-2009
0-OI-72, ADHR System, Attachment 2, Panel Lineup Checklist, Eff. Date 7-14-2006
0-OI-72, ADHR System, Attachment 3, Electrical Lineup Checklist, Eff. Date 5-04-2010
0-OI-72, ADHR System, Attachment 2, Instrument Inspection Checklist, Eff. Date 11-12-2007
FSAR 10.22 Auxiliary Decay Heat Removal System (ADHR)
WO# 110989877, Connect two diesel generators to the ADHR MCC
WO# 224816-001, Electrical Capacity Determination needed for the ADHR D/G.
EPI-0-072-ADR001, Installation of Feeder Cables for Alternate Supply From Backup Diesel
Generator for ADHR in Support of Refueling Outages, Rev. 12
Calculation Number EDN000072201000002, Sizing ADHR Backup Diesel Generator, Rev. 0
0-SR-3.6.4.3.2(B VFTP), Standby Gas Treatment Filter Pressure Drop and In-Place Leak Tests
- Train B
PER 266981 Secondary Containment Breach not Identified
PER 267418 RCA Boundary in SBGT Building not in Proper Place
PER 267490 Inadequate PMT for WO 111543852
PER 268312 0-DMP-65-503 Found Twisted
PER 268557 Two WO 111543852 Discrepancies
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
12
WO 111543852, Repair of 0-DMP-65-503
1-SR-3.6.1.3.5(RHR II), RHR System MOV Operability Loop II, Rev. 7, dated 11/14/10
1-SR-3.3.3.1.4(H II), Verification of Remote Position Indicators for RHR System II Valves, Rev.
2, dated 11/15/10
ECI-0-000-MOV001, Maintenance for Limitorque Motor Operated Valves, Rev. 42
ECI-0-000-MOV009, Testing of Motor Operated Valves Using MOVATS Universal Diagnostic
System (UDS) and Viper 20, Rev. 22
EPI-0-000-MOV001, Electrical Preventive Maintenance for Limitorque Motor Operated Valves,
Rev. 52
MCI-0-000-PCK001, Generic Maintenance Instructions for Valve Packing, Rev. 24
MCI-0-074-VLV008, Residual Heat Removal Motor Operated Valves FCV-74-52 and FCV-74-
66, Maintenance, Rev. 15
WO 09-723979-000, Partial MOVATS 74-66
WO 111569660, 1-FCV-74-66 Troubleshooting of Failure to Pass Flow
WO 111571105, Refurbishment of RHR 1-FCV-74-66
WO 111571764, EM Support of 1-FCV-74-66 Maintenance
WO 111620630, 74-66 Stem-Skirt Weld Build-Up and Re-Thread
Drawing 1-730E915RE, Sheets 11 and 12, Reactor Protection System, Revs. 6 and 5
respectively
FSAR Section 7.2, Reactor Protection System, Amendment BFN-22
SR 272881, Problems with Screws on CR305 Scram Contactors
SR 277297, Minor Package Closure Issues with Scram Contactor Replacements
SR 298856 Overall PMT Process
SR 298862 Oil Seepage WO Not Having PMT
SR 298871 PMT for Sight Glass Signed Prematurely
SR 299098 ECI-MOV009 Not Included in Work Package
SR 299102 MCIs Missing Sign-Offs
Technical Specifications and Bases 3.5.1, ECCS - Operating, Rev. 47
WO 111105764, EM Support for 73-16
WO 04-723582-000, High Point Sight Glass Vent Cleaning
WO 09-723049-000, Tighten Oil Leaks
3-SR-3.5.1.6(CSII), Core Spray Flow Rate Loop II
WO 09-719726-000, CS Minimum Flow Valve (3-FCV-75-37)
WO 110965566, Core Spray Test Return Valve (3-FCV-75-50)
WO 110979949, 3B CS Motor Oil Replacement
WO 110965563, CS Loop Injection Valve (3-FCV-75-53)
WO 110784067, BFN-3-MVOP-075-0037
WO 110984071, BFN-3-MVOP-075-0050
0-47E873-1, -2, Flow Diagram Aux Decay Heat Removal System, Sheet 1 & 2, Date 7-12-97
0-47E610-72-1, -2, Control Diagram Aux Decay Heat Removal System, Sheet 1 & 2, Date 7-12-97
0-15E900-1, Electrical Instrument Details, Date 8-6-97
0-15E740-1, Single-Line Diagram ADHR Service Entrance and MCC, Date 7-12-97
Section 1R20: Refueling and Other Outage Activities
SPP-10.4, Reactivity Management Program, Rev. 09
SR 304778
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
13
1-SR-3.5.1.1(RHRII), RHR System Venting Loop II
2-SR-3.5.1.1(RHR II), RHR System Venting Loop II
Drawing 1-47E811-1, Flow Diagram Residual Heat Removal System, Rev. 25
Drawing 3-A-12337-M-3A, Cast Steel Pressure Seal Angle Valve with Limitorque SMB-5T
Operator (Nuclear) Assembly, Rev. 2
Drawing C-12337-7-3A, Cast Steel Pressure Seal Angle Valve Special Disc Skirt, Rev. 0
Drawing C-12337-8-1, Cast Steel Pressure Seal Angle Valve with Limitorque SMB-5T Operator
& V-Notched Disc Detail of Special Stem, Rev. 0
General Design Criteria Document BFN-50-7074, Residual Heat Removal System, Rev. 20
Operator Logs, 2/18/09 - 3/13/09
PER 271338, 1-FCV-74-66 Valve Failure A Level Root Cause
PER 303097, Units 2 and 3 FE for RHR Outboard Isolation Valves
Sketch Showing Assembled Parts for Conversion to V-Notch Disc, Dated June 5, 1975
Technical Specifications and Bases 3.5.1 ECCS-Operating, Amendment 269 and Rev. 53
respectively
U1R8 PORC Presentation, 1-FCV-74-66 Valve Failure, PER 271338 A Level Root Cause
WO 111569660, 1-FCV-74-66 Troubleshooting of Failure to Pass Flow
WO 06-724612-000, 1-FCV-74-66 Will Not Close-Limit Switches
WO 05-722286-001, 1-MVOP-74-66 Anti-Rotation Device Needs Adjustment
1-SR-3.4.9.1(1), Rector Heatup and Cooldown Rate Monitoring, Rev. 06
SPP-10.4, Reactivity Management Program, Rev. 09
1-SR-3.4.1 (SLO), Reactor Recirculation System Single Loop Operation, Rev. 02
1-SR-3.4.2.1, Jet Pump Mismatch Operability, Rev. 12
1-SR-3.4.3.2, Main Steam Relief Valve Manual Cycle Test, Rev. 02
3-AOI-100-1, Reactor Scram, Rev. 53
3-GOI-100-12A, Unit S/D from Power Ops to Cold S/D, Rev. 47
3-ARP-9-7B, ARP for Panel 9-7, 3-XA-55-7B
Unit 3 Reactor Scram report dated 12/27/2010
Quick Human Error Analysis Tool report dated 12/26/2010
PER 301505
3-SR-3.4.9.1(1), Reactor Heatup and Cooldown Rate Monitoring, Rev. 17
3-GOI-200-2, Primary Containment Initial Entry and Closeout Inspection, Rev. 30
1C RHR Run History from 2006 through 2010
PER 274840, 1C RHR Motor Failure, Root Cause Analysis Report
Operator Chronological Logs from October 23 thru October 28, 2010
PORC Presentation for 1C RHR Motor Failure
Section 1R22: Surveillance Testing
SR266363
0-SR-3.7.3.2 (HEPA), Control Room Emergency Ventilation System In Place Leak Test
WO 110725406, CREVS in Place Leak Test
Chronological Test Log (CTL) Procedure No. 0-SR-3.7.3.2 (HEPA)
Nucon International, Inc., Acceptance for In-place Testing
Nucon International, Inc., In-place Test Report
Nucon International, Inc., Airflow Capacity and / or Distribution Test Report
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
14
Nucon International, Inc., HEPA Test Raw Data Sheet
Nucon International, Inc., Calibration Certificate
Nucon International, Inc., Qualifications of Nucon Personnel
1-SI-4.7.A.2.a-f, Primary Containment Integrated Leak Rate Test
Calibration Certificates #22694 & 22695, Mass Flow Indicator (Alicat Scientific)
Calibration Certificates #21276 thru 21313, Temperature Detectors (Graftel)
Calibration Certificates #21314 thru 21326, and 23295, Relative Humidity Chambers (Graftel)
Calibration Certificates #09100015, 22724 and 22725, Pressure Detectors (Paroscientific)
SR 299079, EOI-2 Entry
SR 299090, EOI-3 Entry
SR 298907, HPCI Temporary D/P Gage Tubing Rupture
SR 299213, EOI Label Missing On 2-RI-90-24A
Technical Specifications and Bases 3.5.1, ECCS - Operating, Rev. 47
3-SR-3.4.5.3, Drywell Floor Drain Sump Flow Integrator Calibration, Rev. 08
NPG-SPP-06.9.1, Conduct of Testing, Rev. 01
PER: 2330701
SR: 276465
0-45E709-1
0-45E710-1
Section 4OA2: Identification and Resolution of Problems
3QFY10 Integrated Trend Report
4QFY10 Integrated Trend Report
PER 285375 Late Site ITR submittal
PER 276796 Late Engineering ITR submittal
PER 276074 Late Operations ITR submittal
PER 277764 FME trend for U1R8
PER 282539 FME issues in the reactor vessel and SFP
SR 277796 FME trend for U1R8
SR 281642 Document SRs and status of FME found during U1R8
PER 136489 Cross Cutting issue for untimely corrective actions
Effectiveness Review of PER 136489
PERs 216386, 225844, 204364 177206-005774364, 177206-005774389,147726, 148788.
PER 177206 ACE Grading 092800402
PER 177206 Extension 005769041
PER 177206 Extension request#1
PER 177206 ACE Grading 092680535
LER write up for HPCI 1-PCV-073-0018Crev8 005774357
LER write up for HPCI 1-PCV-073-0018Crev8 005774383
ACE Report for PER 177206 rev6 092650456
Central Labs report (M29-0189 Preliminary results) 005774350
FW PER 177206 ACE Grading [1].doc 005781152
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
15
ACE 177206 rev7 005783907
ACE Report for PER 177206 rev6 005774382
Procedures:
NPG-SPP-03.1, Corrective Actions Program
NPG-SPP-03.1.4, Corrective Action Program Screening and Oversight, Rev. 0001
NPG-SPP-03.1.10, PER Effectiveness Reviews, Rev. 0001
SRs:
SR 294998, PER action 223536-039 closed without performing all actions
SR 295007, Evaluate the Certrec report
PERs:
PER 136489, Cross Cutting issue for untimely corrective actions
PER 138724, Potential negative trend in work practices
PER 147726, Functional Evaluations
PER 151140, Potential negative trend in the cross cutting program corrective action program
PER 153438, Infrequent Reinforcement of High Performance Standards by Managers and
Supervisors
PER 172053, Scheduled item not performed
Section 4OA3: Event Follow-up
PER 200183, RCIC Flow Oscillations during Unit 3 Scram
BFN Unit 3 Technical Specifications and Bases 3.5.3, RCIC System
FSAR Section 4.7, Reactor Core Isolation Cooling System
BFN-50-7071, Design Criteria, Reactor Core Isolation Cooling System, Rev. 15
LER 50-296/2009-003-00, Reactor Core Isolation Cooling System Inoperable Longer Than
Allowed By the Technical Specifications
LER 50-296/2009-003-01, Reactor Core Isolation Cooling System Inoperable Longer Than
Allowed By the Technical Specifications
LER 50-296/2009-003-02, Reactor Core Isolation Cooling System Inoperable Longer Than
Allowed By the Technical Specifications
3-AOI-100-1, Reactor Scram, Rev. 53
3-GOI-100-12A, Unit S/D from Power Ops to Cold S/D, Rev. 47
3-ARP-9-7B, ARP for Panel 9-7, 3-XA-55-7B
Unit 3 Reactor Scram report dated 12/27/2010
Quick Human Error Analysis Tool report dated 12/26/2010
PER 301505
Section 4OA5: Other
BFN Leadership Development 2011 Plan, October 2010
SR 277529 FME in U1 reactor cavity
SR 277541 FME in U1 reactor cavity
PER 278148 FME in U1 reactor vessel
SR 280474 Protected equipment negative trend
PER 280429 ODM 4.18 protected equipment negative trend
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
16
PER 289002 SPP-9.17 Temporary Equipment Control violations
PER 244854 3QFY10 ITR Analysis of Housekeeping Temporary Equipment Control
SR 297502 Temporary Equipment Control
PER 288827 SPP-9.17 Temporary Equipment Control Violations
SR 298856, PMT process
PER 299877, PMT process
PER 213116, PMT not performed
PER 246534, Potential negative trend in the adequacy of PMTs
NPG-SPP-02.7, PER Trending, Rev. 01
TVA's Adverse Employment Action Procedure - TVA-SPP-11.10
One Team, One Fleet, One TVA booklet
NPG-SPP-02.8, Integrated Trend Review, Rev. 01
PER 248347, Emerging Trend in H.2.c
Root Cause Analysis Report PER 228347
PER 215591, Potential substantive cross-cutting issue in PI&R
PER 302263, Comp measure for each Dept. working with most difficult procedures
NPG-SPP-03.1, Corrective Action Program, Rev. 1
NPG-SPP-03.1.6, Root Cause Analysis, Rev. 1
NPG-SPP-07.3, Work Activity Risk Management Process, Rev. 1
NPG-SPP-18.2, Human Performance Program, Rev. 0
NPG-SPP-18.2.2, Human Performance Tools, Rev. 0
CRP-PAN-F-09-001, NPG Focused Self-Assessment Report
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
LIST OF ACRONYMS
ADAMS - Agencywide Document Access and Management System
ADS - Automatic Depressurization System
ARM - area radiation monitor
CAD - containment air dilution
CAP - corrective action program
CCW - condenser circulating water
CFR - Code of Federal Regulations
CoC - certificate of compliance
CRD - control rod drive
CS - core spray
DCN - design change notice
EECW - emergency equipment cooling water
EDG - emergency diesel generator
FE - functional evaluation
FPR - Fire Protection Report
FSAR - Final Safety Analysis Report
IMC - Inspection Manual Chapter
LER - licensee event report
NCV - non-cited violation
NRC - U.S. Nuclear Regulatory Commission
ODCM - Off-Site Dose Calculation Manual
PER - problem evaluation report
PCIV - primary containment isolation valve
PI - performance indicator
RCE - Root Cause Evaluation
RCW - Raw Cooling Water
RG - Regulatory Guide
RHRSW - residual heat removal service water
RTP - rated thermal power
RPS - reactor protection system
RWP - radiation work permit
SDP - significance determination process
SBGT - standby gas treatment
SNM - special nuclear material
SSC - structure, system, or component
TI - Temporary Instruction
TIP - transverse in-core probe
TRM - Technical Requirements Manual
TS - Technical Specification(s)
UFSAR - Updated Final Safety Analysis Report
URI - unresolved item
WO - work order
OFFICIAL USE ONLY - SECURITY RELATED INFORMATION
Attachment