ML14045A320: Difference between revisions

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| number = ML14045A320
| number = ML14045A320
| issue date = 02/14/2014
| issue date = 02/14/2014
| title = EA-14-005-IR 05000259-13-005, 05000260-13-005, 05000296-13-005, 10/01/2013 and 12/31/2013, Browns Ferry, Units 1, 2, and 3, Adverse Weather Protection, Licensed Operator Requalification....
| title = EA-14-005-IR 05000259-13-005, 05000260-13-005, 05000296-13-005, 10/01/2013 and 12/31/2013, Browns Ferry, Units 1, 2, and 3, Adverse Weather Protection, Licensed Operator Requalification...
| author name = Croteau R P
| author name = Croteau R
| author affiliation = NRC/RGN-II/DRP
| author affiliation = NRC/RGN-II/DRP
| addressee name = Shea J W
| addressee name = Shea J
| addressee affiliation = Tennessee Valley Authority
| addressee affiliation = Tennessee Valley Authority
| docket = 05000259, 05000260, 05000296
| docket = 05000259, 05000260, 05000296
Line 15: Line 15:
| page count = 47
| page count = 47
}}
}}
See also: [[followed by::IR 05000259/2013005]]
See also: [[see also::IR 05000259/2013005]]


=Text=
=Text=
{{#Wiki_filter:
{{#Wiki_filter:UNITED STATES
[[Issue date::February 14, 2014]]
                              NUCLEAR REGULATORY COMMISSION
                                              REGION II
                          245 PEACHTREE CENTER AVENUE NE, SUITE 1200
                                    ATLANTA, GEORGIA 30303-1257
                                          February 14, 2014
EA-14-005
Mr. J.W. Shea
Vice President, Nuclear Licensing
Tennessee Valley Authority
1101 Market Street, LP 3D-C
Chattanooga, TN 37402-2801
SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION
            REPORT 05000259/2013005, 05000260/2013005, AND 05000296/2013005,
            PRELIMINARY WHITE FINDING AND APPARENT VIOLATIONS
Dear Mr. Shea:
On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Browns Ferry Nuclear Plant, Units 1, 2, and 3. On January 10 and 21, 2014,
the NRC inspectors discussed the results of this inspection with Mr. S. Bono and other
members of your staff. Inspectors documented the results of this inspection in the enclosed
inspection report.
Based on the results of this inspection, the report discusses a finding that has preliminarily been
determined to be a finding with low to moderate safety significance (White) that may require
additional inspections, regulatory actions, and oversight. As described in Section 1R11.2 of the
enclosed report, the licensees failure to maintain plant emergency response staffing levels in
accordance with NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency
Plan, was a performance deficiency. Specifically, the licensees process for maintaining
minimum emergency response shift staffing failed to adequately maintain staffing of the Shift
Technical Advisor (STA) and Incident Commander (IC) to ensure initial accident response in all
key functional areas. This finding did not present an immediate safety concern because the
licensee added additional staff to ensure they met the staffing requirements. This finding was
assessed based on the best available information, using the NRCs significance determination
process (SDP). The basis for the NRCs preliminary significance determination is described in
the enclosed report. The NRC will inform you in writing when the final significance has been
determined.
In addition, please be advised that the number and characterization of apparent violations
described in the enclosed inspection report may change as a result of further NRC review. You
will be advised by separate correspondence of the results of our deliberations on this matter.
Before the NRC makes a final decision on this matter, you may choose to (1) attend a
regulatory conference, where you can present to the NRC your point of view on the facts and
assumptions used to arrive at the finding and assess its significance, or (2) submit your position
on the finding to the NRC in writing. If you request a regulatory conference, it should be held
within 30 days of your receipt of this letter. We encourage you to submit supporting


EA-14-005
J. Shea                                       2
 
documentation at least one week prior to the conference in an effort to make the conference
Mr. Vice President, Nuclear Licensing Tennessee Valley Authority 1101 Market Street, LP 3D-C Chattanooga, TN 37402-2801
more efficient and effective. If you choose to attend a regulatory conference, it will be open for
 
public observation. The NRC will issue a public meeting notice and press release to announce
SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000259/2013005, 05000260/2013005, AND 05000296/2013005, PRELIMINARY WHITE FINDING AND APPARENT VIOLATIONS
the conference. If you decide to submit only a written response, it should be sent to the NRC
 
within 30 days of your receipt of this letter. If you choose not to request a regulatory conference
==Dear Mr. Shea:==
or to submit a written response, you will not be allowed to appeal the NRCs final significance
On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Browns Ferry Nuclear Plant, Units 1, 2, and 3. On January 10 and 21, 2014, the NRC inspectors discussed the results of this inspection with Mr. S. Bono and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.
determination.
 
The finding is also an apparent violation of NRC requirements and is being considered for
Based on the results of this inspection, the report discusses a finding that has preliminarily been determined to be a finding with low to moderate safety significance (White) that may require additional inspections, regulatory actions, and oversight. As described in Section 1R11.2 of the enclosed report, the licensee's failure to maintain plant emergency response staffing levels in accordance with NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan, was a performance deficiency. Specifically, the licensee's process for maintaining minimum emergency response shift staffing failed to adequately maintain staffing of the Shift Technical Advisor (STA) and Incident Commander (IC) to ensure initial accident response in all key functional areas. This finding did not present an immediate safety concern because the licensee added additional staff to ensure they met the staffing requirements. This finding was assessed based on the best available information, using the NRC's significance determination process (SDP). The basis for the NRC's preliminary significance determination is described in the enclosed report. The NRC will inform you in writing when the final significance has been determined.
escalated enforcement action in accordance with the Enforcement Policy, which appears on the
 
NRCs Web site at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.
In addition, please be advised that the number and characterization of apparent violations described in the enclosed inspection report may change as a result of further NRC review. You will be advised by separate correspondence of the results of our deliberations on this matter. Before the NRC makes a final decision on this matter, you may choose to (1) attend a regulatory conference, where you can present to the NRC your point of view on the facts and assumptions used to arrive at the finding and assess its significance, or (2) submit your position on the finding to the NRC in writing. If you request a regulatory conference, it should be held within 30 days of your receipt of this letter. 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 choose to attend a regulatory conference, it will be open for public observation. The NRC will issue a public meeting notice and press release to announce the conference. If you decide to submit only a written response, it should be sent to the NRC within 30 days of your receipt of this letter. If you choose not to request a regulatory conference or to submit a written response, you will not be allowed to appeal the NRC's final significance determination. The finding is also an apparent violation of NRC requirements and is being considered for escalated enforcement action in accordance with the Enforcement Policy, which appears on the NRC's Web site at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.
We intend to complete and issue our final safety significance determination within 90 days from
 
the date of this letter. The NRCs significance determination process is designed to encourage
We intend to complete and issue our final safety significance determination within 90 days from the date of this letter. The NRC's significance determination process is designed to encourage an open dialogue between your staff and the NRC; however, the dialogue should not affect the timeliness of our final determination.
an open dialogue between your staff and the NRC; however, the dialogue should not affect the
 
timeliness of our final determination.
The enclosed inspection report also discusses two apparent violations were identified and are being considered for escalated enforcement action in accordance with the NRC Enforcement Policy. The current Enforcement Policy is included on the NRC's Web site at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. As described in Section 1R11.2 of the enclosed report, two issues were identified that are being dispositioned using the traditional enforcement process. The first, an apparent violation of 10 CFR 50.9, Completeness and Accuracy of Information, was identified for the licensee's apparent failure to provide the NRC with complete and accurate information on two occasions when identifying the minimum required shift staffing to the NRC. The second, an apparent violation of 10 CFR 50.90, Amendment of License or Construction Permit at Request of Holder, was identified for the licensee apparently making a change to a license condition without submitting an amendment request. Both of these apparent violations were associated with the emergency response shift staffing requirements to achieve safe shutdown during an appendix R fire.
The enclosed inspection report also discusses two apparent violations were identified and are
 
being considered for escalated enforcement action in accordance with the NRC Enforcement
Before the NRC makes its enforcement decision, we are providing you an opportunity to: 1) respond to the apparent violations addressed in this inspection report within 30 days of the date of this letter; 2) request a Pre-decisional Enforcement Conference (PEC); or 3) request Alternative Dispute Resolution (ADR). If a PEC is held, it will be open for public observation and the NRC will issue a press release to announce the time and date of the conference. If you decide to participate in a PEC or pursue ADR, please contact Jonathan Bartley at 404-997-4607 within 10 days of the date of this letter. A PEC should be held within 30 days and an ADR session within 45 days of the date of this letter.
Policy. The current Enforcement Policy is included on the NRCs Web site at
 
http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. As described in Section
If you choose to provide a written response, it should be clearly marked as a "Response to Apparent Violations in NRC Inspection Report 05000259/2013005, 05000260/2013005, and 05000296/2013005; EA-14-005" and should include for each apparent violation: 1) the reason for the apparent violation or, if contested, the basis for disputing the apparent violation; 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 previously docketed correspondence, if the correspondence adequately addresses the required response. If an adequate response is not received within the time specified or an extension of time has not been granted by the NRC, the NRC will proceed with its enforcement decision or schedule a PEC. If you choose to request a PEC, the conference will afford you the opportunity to provide your perspective on these matters and any other information that you believe the NRC should take into consideration before making an enforcement decision. The decision to hold a PEC does not mean that the NRC has determined that a violation has occurred or that enforcement action will be taken. This conference would be conducted to obtain information to assist the NRC in making an enforcement decision. The topics discussed during the conference may include information to determine whether a violation occurred, information to determine the significance of a violation, information related to the identification of a violation, and information related to any corrective actions taken or planned.
1R11.2 of the enclosed report, two issues were identified that are being dispositioned using the
traditional enforcement process. The first, an apparent violation of 10 CFR 50.9, Completeness
and Accuracy of Information, was identified for the licensees apparent failure to provide the
NRC with complete and accurate information on two occasions when identifying the minimum
required shift staffing to the NRC. The second, an apparent violation of 10 CFR 50.90,
Amendment of License or Construction Permit at Request of Holder, was identified for the
licensee apparently making a change to a license condition without submitting an amendment
request. Both of these apparent violations were associated with the emergency response shift
staffing requirements to achieve safe shutdown during an appendix R fire.
Before the NRC makes its enforcement decision, we are providing you an opportunity to:
1) respond to the apparent violations addressed in this inspection report within 30 days of the
date of this letter; 2) request a Pre-decisional Enforcement Conference (PEC); or 3) request
Alternative Dispute Resolution (ADR). If a PEC is held, it will be open for public observation and
the NRC will issue a press release to announce the time and date of the conference. If you
decide to participate in a PEC or pursue ADR, please contact Jonathan Bartley at 404-997-4607
within 10 days of the date of this letter. A PEC should be held within 30 days and an ADR
session within 45 days of the date of this letter.
If you choose to provide a written response, it should be clearly marked as a Response to
Apparent Violations in NRC Inspection Report 05000259/2013005, 05000260/2013005, and
05000296/2013005; EA-14-005 and should include for each apparent violation: 1) the reason
for the apparent violation or, if contested, the basis for disputing the apparent violation; 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 previously docketed correspondence, if the correspondence adequately addresses
the required response. If an adequate response is not received within the time specified or an
extension of time has not been granted by the NRC, the NRC will proceed with its enforcement
decision or schedule a PEC.


J. Shea                                        3
If you choose to request a PEC, the conference will afford you the opportunity to provide your
perspective on these matters and any other information that you believe the NRC should take
into consideration before making an enforcement decision. The decision to hold a PEC does
not mean that the NRC has determined that a violation has occurred or that enforcement action
will be taken. This conference would be conducted to obtain information to assist the NRC in
making an enforcement decision. The topics discussed during the conference may include
information to determine whether a violation occurred, information to determine the significance
of a violation, information related to the identification of a violation, and information related to
any corrective actions taken or planned.
In lieu of a PEC, you may also request ADR with the NRC in an attempt to resolve this issue.
In lieu of a PEC, you may also request ADR with the NRC in an attempt to resolve this issue.
ADR is a general term encompassing various techniques for resolving conflicts using a third
party neutral. The technique that the NRC has decided to employ is mediation. Mediation is a
voluntary, informal process in which a trained neutral (the mediator) works with parties to help
them reach resolution. If the parties agree to use ADR, they select a mutually agreeable neutral
mediator who has no stake in the outcome and no power to make decisions. Mediation gives
parties an opportunity to discuss issues, clear up misunderstandings, be creative, find areas of
agreement, and reach a final resolution of the issues. Additional information concerning the
NRC's program can be obtained at http://www.nrc.gov/about-nrc/regulatory/enforcement/
adr.html. The Institute on Conflict Resolution (ICR) at Cornell University has agreed to facilitate
the NRCs program as a neutral third party. Please contact ICR at 877-733-9415 within 10 days
of the date of this letter if you are interested in pursuing resolution of these issues through ADR.
Please contact Jonathan Bartley at (404) 997-4607, 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. Because the NRC has
not made a final determination in this matter, no notice of violation is being issued for this
inspection finding at this time. In addition, please be advised that the number and
characterization of the apparent violations may change based on further NRC review.
NRC inspectors also documented two findings of very low safety significance (Green) in this
report. Both of these findings involved violations of NRC requirements. Additionally, NRC
inspectors documented a Severity Level IV violation with no associated finding.
Further, inspectors documented a licensee-identified violation which was determined to be of
very low safety significance in this report. The NRC is treating this violation as a non-cited
Violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.
If you contest the violation or significance of these NCVs, you should provide a response within
30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with
copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector
at the Browns Ferry Nuclear Plant.
In addition, if you disagree with a cross-cutting aspect assignment in this report, you should
provide a response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region II, and the NRC resident inspector at the
Browns Ferry Nuclear Plant.


ADR is a general term encompassing various techniques for resolving conflicts using a third party neutral. The technique that the NRC has decided to employ is mediation. Mediation is a voluntary, informal process in which a trained neutral (the "mediator") works with parties to help them reach resolution. If the parties agree to use ADR, they select a mutually agreeable neutral mediator who has no stake in the outcome and no power to make decisions. Mediation gives parties an opportunity to discuss issues, clear up misunderstandings, be creative, find areas of agreement, and reach a final resolution of the issues. Additional information concerning the NRC's program can be obtained at http://www.nrc.gov/about-nrc/regulatory/enforcement/
J. Shea                                      4
adr.html. The Institute on Conflict Resolution (ICR) at Cornell University has agreed to facilitate the NRC's program as a neutral third party. Please contact ICR at 877-733-9415 within 10 days of the date of this letter if you are interested in pursuing resolution of these issues through ADR.
As a result of the Safety Culture Common Language Initiative, the terminology and coding of
 
cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting
Please contact Jonathan Bartley at (404) 997-4607, 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. Because the NRC has not made a final determination in this matter, no notice of violation is being issued for this inspection finding at this time. In addition, please be advised that the number and characterization of the apparent violations may change based on further NRC review.
aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting
 
aspects identified in the last six months of 2013 using the previous terminology will be converted
NRC inspectors also documented two findings of very low safety significance (Green) in this report. Both of these findings involved violations of NRC requirements. Additionally, NRC inspectors documented a Severity Level IV violation with no associated finding.
to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-
 
Further, inspectors documented a licensee-identified violation which was determined to be of very low safety significance in this report. The NRC is treating this violation as a non-cited Violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.
 
If you contest the violation or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U.S.
 
Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Browns Ferry Nuclear Plant.
 
In addition, if you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC resident inspector at the Browns Ferry Nuclear Plant. As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-
cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-
cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-
cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.
cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment
 
review.
In accordance with Title 10 of the Code of Federal Regulations 2.390, "Public Inspections, Exemptions, Requests for Withholding," of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any), will be available electronically for public inspection in the NRC's Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be made available to the Public without redaction.
In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections,
 
Exemptions, Requests for Withholding, of the NRCs Rules of Practice, a copy of this letter, its
Sincerely,/RA/
enclosure, and your response (if any), will be available electronically for public inspection in the
Richard P. Croteau, Director Division of Reactor Projects  
NRCs Public Document Room or from the Publicly Available Records (PARS) component of the
 
NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is
Docket Nos.: 50-259, 50-260, 50-296 License Nos.: DPR-33, DPR-52, DPR-68  
accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public
 
Electronic Reading Room). To the extent possible, your response should not include any
===Enclosure:===
personal privacy, proprietary, or safeguards information so that it can be made available to the
NRC Integrated Inspection Report 05000259/2013005, 05000260/2013005 and 05000296/2013005  
Public without redaction.
 
                                              Sincerely,
                                              /RA/
                                              Richard P. Croteau, Director
                                              Division of Reactor Projects
Docket Nos.: 50-259, 50-260, 50-296
License Nos.: DPR-33, DPR-52, DPR-68
Enclosure: NRC Integrated Inspection Report 05000259/2013005,
              05000260/2013005 and 05000296/2013005
cc distribution via ListServ
cc distribution via ListServ


=SUMMARY=
IR 05000259/2013005, 05000260/2013005, 05000296/2013005; 10/01/2013-12/31/2013;


Browns Ferry Nuclear Plant, Units 1, 2 and 3; Adverse Weather Protection, Licensed Operator Requalification and Performance, Problem Identification and Resolution, and Follow Up of Events and Notices of Enforcement Discretion.
_ ML14045A320____________                        SUNSI REVIEW COMPLETE          FORM 665 ATTACHED
OFFICE            RII:DRP        RII:DRP        RII:DRP          RII:DRS          RII:DRP          RII:DRP        RII:DRS
SIGNATURE                        /VIA By E-mail/ /VIA By E-mail/  /VIA By E-mail/  /VIA By E-mail/  /VIA By E-mail/ /VIA By E-mail/
NAME              DDumbacher    LPressley      TStephen        ASengupta        CKontz          MRiches        RBaldwin
DATE                  2/1/1/2014    2/13/2014      2/12/2014      2/10/2014m        2/10/2014        2/11/2014      2/11/2014
E-MAIL COPY?        YES      NO  YES      NO    YES      NO      YES      NO      YES      NO      YES      NO    YES      NO
OFFICE            RII:EICS      RII:DRP        RII:DRP          RII:DRP
SIGNATURE          /RA/          /VIA By E-mail/ /RA/            /RA/
NAME              CEvans        JBartley        WJones          RCroteau
DATE                  /2/14/2014    2/14/2014      2/14/2014        2/14/2014
E-MAIL COPY?        YES      NO  YES      NO    YES      NO      YES      NO      YES      NO      YES      NO    YES      NO
       
J. Shea                                  5
Letter to Joseph W. Shea from Richard P. Croteau dated February 14, 2014.
SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION
              REPORT 05000259/2013005, 05000260/2013005, AND 05000296/2013005,
              PRELIMINARY WHITE FINDING AND APPARENT VIOLATIONS
Distribution:
C. Evans, RII
L. Douglas, RII
OE Mail
RIDSNRRDIRS
PUBLIC
RidsNrrPMBrownsFerry Resource


The report covered a three month period of inspection by the resident inspectors and four regional inspectors. The significance of most findings is identified by their color (Green, White, Yellow, and Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP); and, the cross-cutting aspects were 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 NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process" Revision 4, dated December 2006.
              U.S. NUCLEAR REGULATORY COMMISSION
                                REGION II
Docket Nos.:  50-259, 50-260, 50-296
License Nos.:  DPR-33, DPR-52, DPR-68
Report Nos.:  05000259/2013005, 05000260/2013005, 05000296/2013005
Licensee:      Tennessee Valley Authority (TVA)
Facility:      Browns Ferry Nuclear Plant, Units 1, 2, and 3
Location:      Corner of Shaw and Nuclear Plant Road
              Athens, AL 35611
Dates:        October 1, 2013, through December 31, 2013
Inspectors:    D. Dumbacher, Senior Resident Inspector
              L. Pressley, Resident Inspector
              T. Stephen, Resident Inspector
              A. Sengupta, Reactor Inspector
              C. Kontz, Senior Project Engineer
              M. Riches, Project Engineer
              R. Baldwin, Senior Operations Engineer
Approved by:  Jonathan H. Bartley, Chief
              Reactor Projects Branch 6
              Division of Reactor Projects
                                                                  Enclosure


===NRC Identified and Self-Revealing Findings===
                                            SUMMARY
IR 05000259/2013005, 05000260/2013005, 05000296/2013005; 10/01/2013-12/31/2013;
Browns Ferry Nuclear Plant, Units 1, 2 and 3; Adverse Weather Protection, Licensed Operator
Requalification and Performance, Problem Identification and Resolution, and Follow Up of
Events and Notices of Enforcement Discretion.
The report covered a three month period of inspection by the resident inspectors and four
regional inspectors. The significance of most findings is identified by their color (Green, White,
Yellow, and Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination
Process (SDP); and, the cross-cutting aspects were 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.
NRC Identified and Self-Revealing Findings
Cornerstone: Initiating Events
    *  Green: The NRC identified a non-cited violation (NCV) of 10 CFR 50, Appendix B,
        Criterion V, Procedures, for the licensees failure to implement 0-GOI-200-1, Freeze
        Protection Inspection. Specifically, the licensee failed to enter freeze protection
        discrepancies into the corrective action program as part of the Freeze Protection
        Discrepancy List per 0-GOI-200-1 for the residual heat removal service water (RHRSW)
        and emergency equipment cooling water (EECW) systems. As a corrective action, the
        licensee entered the required deficiencies onto the Freeze Protection Discrepancy List.
        The licensee has entered this issue into their corrective action program as problem
        evaluation reports 800190 and 821426.
        The finding was more than minor because, if left uncorrected, the performance
        deficiency would have the potential to lead to a more significant safety concern, in that
        the intake room piping would continue to be exposed to freezing temperatures without
        adequate freeze protection which could affect RHRSW and EECW systems ability to
        perform their safety functions. The inspectors performed a Phase 1 screening in
        accordance with IMC 0609, Significance Determination Process, Appendix A, Exhibit 1,
        Initiating Event screening question E, and determined the finding was of very low safety
        significance (Green) because it did not impact the frequency of an internal flooding
        event. The cause of this finding has a cross-cutting aspect in the Work Practices
        component of the Human Performance area, because the licensee failed to define and
        effectively communicate expectations regarding procedural compliance and that
        personnel follow procedures. [H.4(b)] (Section 1R01)
                                                                                          Enclosure


===Cornerstone: Initiating Events===
                                              3
* Green:  The NRC identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Procedures, for the licensee's failure to implement 0-GOI-200-1, Freeze Protection Inspection. Specifically, the licensee failed to enter freeze protection discrepancies into the corrective action program as part of the Freeze Protection Discrepancy List per 0-GOI-200-1 for the residual heat removal service water (RHRSW) and emergency equipment cooling water (EECW) systems. As a corrective action, the licensee entered the required deficiencies onto the Freeze Protection Discrepancy List.
Cornerstone: Mitigating Systems
 
  * Green: The NRC-identified a non-cited violation (NCV) of 10 CFR 50, Appendix B,
The licensee has entered this issue into their corrective action program as problem evaluation reports 800190 and 821426.
      Criterion III, Design Control, for the licensees failure to establish measures to ensure the
 
      EDG floor drains maintained the capability of performing their intended function as
The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern, in that the intake room piping would continue to be exposed to freezing temperatures without adequate freeze protection which could affect RHRSW and EECW systems' ability to perform their safety functions. The inspectors performed a Phase 1 screening in accordance with IMC 0609, Significance Determination Process, Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding was of very low safety significance (Green) because it did not impact the frequency of an internal flooding event. The cause of this finding has a cross-cutting aspect in the Work Practices component of the Human Performance area, because the licensee failed to define and effectively communicate expectations regarding procedural compliance and that personnel follow procedures. [H.4(b)] (Section 1R01) 
      described their design basis. The licensees immediate corrective action was to clean all
 
      the drains in all the EDG rooms. The licensee has entered this issue into their corrective
===Cornerstone: Mitigating Systems===
      action program as problem evaluation report 765575.
* Green: The NRC-identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensee's failure to establish measures to ensure the EDG floor drains maintained the capability of performing their intended function as described their design basis. The licensee's immediate corrective action was to clean all the drains in all the EDG rooms. The licensee has entered this issue into their corrective action program as problem evaluation report 765575.
      The finding was more than minor because, if left uncorrected, the performance
 
      deficiency would have the potential to lead to a more significant safety concern, in that,
The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern, in that, the EDG room floor drains could become sufficiently clogged such that internal flooding would cause the affected EDG to be unable to perform its safety function. The inspectors performed a Phase 1 screening in accordance with IMC 0609, Significance Determination Process, Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding was of very low safety significance (Green) because it did not impact the frequency of an internal flooding event. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because TVA did not identify floor drain issues completely, accurately, and in a timely manner commensurate with their safety significance. [P.1 (a)] (Section 4OA2.3)  
      the EDG room floor drains could become sufficiently clogged such that internal flooding
 
      would cause the affected EDG to be unable to perform its safety function. The
===Cornerstone: Emergency Preparedness===
      inspectors performed a Phase 1 screening in accordance with IMC 0609, Significance
* TBD: The NRC identified an apparent violation of 10 CFR 50.54(q), Emergency Plans, for the licensee's failure to maintain plant staffing levels in accordance with NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan. Specifically, the licensee's process for maintaining minimum emergency response shift staffing failed to adequately maintain staffing of the Shift Technical Advisor (STA) and Incident Commander to ensure initial accident response in all key functional areas. The licensee has entered this issue into their corrective action program as PERs 790092 and 801057.
      Determination Process, Appendix A, Exhibit 1, Initiating Event screening question E, and
 
      determined the finding was of very low safety significance (Green) because it did not
The inspectors determined the performance deficiency was more than minor because it was associated with the ERO readiness attribute of the emergency preparedness cornerstone and adversely impacted the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the failure to maintain required emergency response staffing levels reduced the licensee's capabilities to respond to an emergency. The inspectors assessed the finding in accordance with Appendix B, Emergency Preparedness Significance Determination Process and determined that this finding represented a Loss of Planning Standard Function and has preliminarily been determined to be a finding of White significance. Because the significance of this finding is not yet finalized, it is being characterized as "To Be Determined (TBD)," pending a final significance determination. The cause of the finding was determined to be associated with the cross-cutting aspect of thorough evaluation of problems in the corrective action component of the problem identification and resolution area because the licensee failed to ensure that issues potentially affecting nuclear safety were thoroughly evaluated. [P.1(c)] (Section 1R11.2.b(1))
      impact the frequency of an internal flooding event. This finding has a cross-cutting
      aspect in the area of Problem Identification and Resolution, Corrective Action Program
      Component, because TVA did not identify floor drain issues completely, accurately, and
      in a timely manner commensurate with their safety significance. [P.1 (a)] (Section
      4OA2.3)
Cornerstone: Emergency Preparedness
  * TBD: The NRC identified an apparent violation of 10 CFR 50.54(q), Emergency Plans,
      for the licensees failure to maintain plant staffing levels in accordance with NP-REP,
      Tennessee Valley Authority Nuclear Power Radiological Emergency Plan. Specifically,
      the licensees process for maintaining minimum emergency response shift staffing failed
      to adequately maintain staffing of the Shift Technical Advisor (STA) and Incident
      Commander to ensure initial accident response in all key functional areas. The licensee
      has entered this issue into their corrective action program as PERs 790092 and 801057.
      The inspectors determined the performance deficiency was more than minor because it
      was associated with the ERO readiness attribute of the emergency preparedness
      cornerstone and adversely impacted the cornerstone objective of ensuring that the
      licensee is capable of implementing adequate measures to protect the health and safety
      of the public in the event of a radiological emergency. Specifically, the failure to
      maintain required emergency response staffing levels reduced the licensees capabilities
      to respond to an emergency. The inspectors assessed the finding in accordance with
      Appendix B, Emergency Preparedness Significance Determination Process and
      determined that this finding represented a Loss of Planning Standard Function and has
      preliminarily been determined to be a finding of White significance. Because the
      significance of this finding is not yet finalized, it is being characterized as To Be
      Determined (TBD), pending a final significance determination. The cause of the finding
      was determined to be associated with the cross-cutting aspect of thorough evaluation of
      problems in the corrective action component of the problem identification and resolution
      area because the licensee failed to ensure that issues potentially affecting nuclear safety
      were thoroughly evaluated. [P.1(c)] (Section 1R11.2.b(1))
                                                                                          Enclosure


                                            4
Other
Other
* TBD: The NRC identified two examples of an Apparent Violation of 10 CFR 50.9, "Completeness and accuracy of information," for the licensee's apparent failure to provide complete and accurate information associated with emergency response on-shift staffing requirements. Specifically, on two occasions the licensee apparently provided inaccurate information to the NRC concerning onsite emergency response organization minimum staffing requirements. The licensee augmented on-shift staffing levels on October 30, 2013. These issues were entered into the Browns Ferry corrective action program as PERs 790109, 790092, and 801057. These apparent violations had the potential to impede or impact the regulatory process, and therefore subject to traditional enforcement as described in the NRC Enforcement Policy, dated July 9, 2013. Because these apparent violations involved the traditional enforcement process with no underlying technical violation that would be considered more than minor in accordance with IMC 0612, a cross-cutting aspect was not assigned to this violation. (Section 1R11.2.b(2))
  * TBD: The NRC identified two examples of an Apparent Violation of 10 CFR 50.9,
* TBD: The NRC identified an apparent violation (AV) of 10 CFR 50.90, Application for Amendment of License, Construction Permit, or Early Site Permit for the licensee's apparent failure to submit an application requesting an amendment to their operating license concerning on-shift staffing levels. The licensee augmented on-shift staffing levels on October 30, 2013. The issue was entered into the Browns Ferry corrective action program as PERs 790109 and 801057.
      Completeness and accuracy of information, for the licensees apparent failure to
 
      provide complete and accurate information associated with emergency response on-shift
This apparent violation had the potential to impede or impact the regulatory process, and therefore was subject to traditional enforcement as described in the NRC Enforcement Policy, dated July 9, 2013. Because this apparent violation involved the traditional enforcement process with no underlying technical violation that would be considered more than minor in accordance with IMC 0612, a cross-cutting aspect was not assigned to this violation. (Section 1R11.2.b(3))
      staffing requirements. Specifically, on two occasions the licensee apparently provided
* Severity Level IV: The NRC identified a non-cited violation (NVC) of 10 CFR 50.73(a)(2)(i)(B) for the licensee's failure to submit a License Event Report (LER) for a condition prohibited by plant technical specifications within 60 days of the event. The licensee entered this issue into their corrective action program as Problem Event Report 796578. LER 50-259 2013-006-00 was submitted on December 4, 2013. The failure to make reports to the NRC as required by 10 CFR 50.73(a)(2)(i)(B) impacted the regulatory process and was a violation of NRC requirements. The violation was processed using traditional enforcement and determined to be a Severity Level IV violation consistent with NRC's Enforcement Policy section 6.9.d.9, Inaccurate and Incomplete Information or Failure to Make a Required Report. Because this violation involved the traditional enforcement process with no underlying technical violation that would be considered more than minor in accordance with IMC 0612, a cross-cutting aspect was not assigned to this violation. (Section 4OA3.7)
      inaccurate information to the NRC concerning onsite emergency response organization
 
      minimum staffing requirements. The licensee augmented on-shift staffing levels on
=== 
      October 30, 2013. These issues were entered into the Browns Ferry corrective action
 
      program as PERs 790109, 790092, and 801057.
Licensee Identified Violations===
      These apparent violations had the potential to impede or impact the regulatory process,
* A violation of very low safety significance affecting the Barrier Integrity cornerstone that was identified by the licensee has been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and corrective action tracking number are listed in Section 4OA7 of this report.
      and therefore subject to traditional enforcement as described in the NRC Enforcement
 
      Policy, dated July 9, 2013. Because these apparent violations involved the traditional
=REPORT DETAILS=
      enforcement process with no underlying technical violation that would be considered
 
      more than minor in accordance with IMC 0612, a cross-cutting aspect was not assigned
===Summary of Plant Status===
      to this violation. (Section 1R11.2.b(2))
 
  * TBD: The NRC identified an apparent violation (AV) of 10 CFR 50.90, Application for
Unit 1 operated at 100 percent of rated thermal power (RTP) except for one planned downpower on December 14, 2013, for an oil addition to the 1B recirculation pump. Power remained at 100 percent RTP for the remainder of the quarter.
      Amendment of License, Construction Permit, or Early Site Permit for the licensees
 
      apparent failure to submit an application requesting an amendment to their operating
Unit 2 operated at 100 percent RTP except for three planned downpowers, November 16, 2013, for troubleshooting on the 2B3 feedwater heater, November 21, 2013, for repairs to the 2B3 feedwater heater, and December 6, 2013, for repairs to the 2A3 and 2C3 feedwater heaters.
      license concerning on-shift staffing levels. The licensee augmented on-shift staffing
 
      levels on October 30, 2013. The issue was entered into the Browns Ferry corrective
On October 12, 2013, an unplanned power reduction to 78 percent RTP occurred as a result of a recirculation pump runback caused by the failure of the main steam line and reactor feedwater flow indicators. Power remained at 100 percent RTP for the remainder of the quarter.
      action program as PERs 790109 and 801057.
 
      This apparent violation had the potential to impede or impact the regulatory process, and
Unit 3 operated at 100 percent RTP except for a planned downpower on October 4, 2013, for repairs to the 3C3 feedwater heater and to replace a power supply on the 3B reactor feed pump governor control circuit. Power remained at 100 percent RTP for the remainder of the quarter.
      therefore was subject to traditional enforcement as described in the NRC Enforcement
 
      Policy, dated July 9, 2013. Because this apparent violation involved the traditional
==REACTOR SAFETY==
      enforcement process with no underlying technical violation that would be considered
Cornerstones:  Initiating Events, Mitigating Systems, Barrier Integrity
      more than minor in accordance with IMC 0612, a cross-cutting aspect was not assigned
 
      to this violation. (Section 1R11.2.b(3))
{{a|1R01}}
  * Severity Level IV: The NRC identified a non-cited violation (NVC) of 10 CFR
==1R01 Adverse Weather Protection==
      50.73(a)(2)(i)(B) for the licensees failure to submit a License Event Report (LER) for a
 
      condition prohibited by plant technical specifications within 60 days of the event. The
===.1 Readiness for Seasonal Extreme Weather Conditions===
      licensee entered this issue into their corrective action program as Problem Event Report
 
      796578. LER 50-259 2013-006-00 was submitted on December 4, 2013.
====a. Inspection Scope====
      The failure to make reports to the NRC as required by 10 CFR 50.73(a)(2)(i)(B)
Prior to and during the onset of cold weather conditions, the inspectors reviewed the licensee's implementation of 0-GOI-200-1, Freeze Protection Inspection, including applicable checklists:  Attachment 1, Freeze Protection Annual Checklist; Attachment 2, Freeze Protection Operational Checklist; and as applicable, Attachments 3 through 12, Freeze Protection Daily Log Sheets for individual watch stations. The inspectors also reviewed the list of open FZ-coded Work Orders and 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 the main control rooms, residual heat removal service water (RHRSW) and emergency equipment cooling water (EECW) pump rooms, and all units emergency diesel generator (EDG) buildings, to verify that affected systems and components were properly configured and protected as specified by the procedure. The inspectors discussed cold weather conditions with Operations personnel to assess plant equipment conditions and personnel sensitivity to upcoming cold weather conditions. This constituted one Readiness for Seasonal Extreme Weather sample. Documents reviewed are listed in the Attachment.
      impacted the regulatory process and was a violation of NRC requirements. The violation
 
      was processed using traditional enforcement and determined to be a Severity Level IV
====b. Findings====
      violation consistent with NRCs Enforcement Policy section 6.9.d.9, Inaccurate and
 
      Incomplete Information or Failure to Make a Required Report. Because this violation
=====Introduction:=====
      involved the traditional enforcement process with no underlying technical violation that
The NRC identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Procedures, for the licensee's failure to implement 0-GOI-200-1, Freeze Protection Inspection. Specifically, the licensee failed to enter freeze protection discrepancies into the corrective action program (CAP) as part of the Freeze Protection Discrepancy List per 0-GOI-200-1 for the RHRSW and EECW systems.
      would be considered more than minor in accordance with IMC 0612, a cross-cutting
 
      aspect was not assigned to this violation. (Section 4OA3.7)
=====Description:=====
                                                                                      Enclosure
On October 24, 2013, NRC inspectors identified piping insulation removed and heat trace wires disconnected on multiple RHRSW and EECW pipes at the Browns Ferry plant intake rooms. These rooms have no roof and are exposed to outside conditions. Licensee procedure 0-GOI-200-1, Freeze Protection Inspection, required completion of Attachment 1, Freeze Protection Annual Checklist, by October 1, 2013. This checklist requires the performance of general area inspections of the RHRSW Pump Rooms, per Appendix A, section 4.0, General Area Checks Guideline, which included verification that heat trace circuits were functioning and insulation was installed on all piping and instrument lines. 0-GOI-200-1, Annual Check List had not been completed as of October 24, 2013.
 
Subsequently, on December 13, 2013, NRC inspectors observed that heat trace circuits in the RHRSW rooms did not have insulation covering the heat trace tape and no compensatory measures were in place to prevent pipe freezing. Temperatures earlier that week had routinely decreased below 25 degrees Fahrenheit (F) each night. Area temperatures had started dropping below 25 degrees F on November 13, 2013.
 
Section 5.0, Step 3.1 of 0-GOI-200-1, required outstanding discrepancies following completion of Attachment 1 to be evaluated and verification that a Service Request (SR)/Work Order (WO) with the term "FZ" in the narrative details section for the Focus Area have been initiated. Step 3.2 required that if compensatory measures were required that they be added to the Operator Work Around list.
 
s 3 and 4, of 0-GOI-200-1, Freeze Protection Daily Log Sheets, were required to be performed when outside ambient temperature dropped below 25 degrees F or stayed below 32 degrees F for an 8-hour period. Both attachments required area inspections of the RHRSW Pump Rooms, per Appendix A, section 4.0, General Area Checks Guideline. Discrepancies identified during area inspection were required to be recorded on Appendix B, Freeze Protection Remarks Log, and a SR/WO be initiated with the term "FZ" in the narrative details section or verified already in Freeze Protection Discrepancy List (MAXIMO Focus Area "FZ").


The inspectors noted that the missing insulation was not documented in the Annual Checklist or the Daily Log Sheets, nor was it included in the Official Freeze Protection Discrepancy List.
                                              5
Licensee Identified Violations
    *  A violation of very low safety significance affecting the Barrier Integrity cornerstone that
      was identified by the licensee has been reviewed by the NRC. Corrective actions taken
      or planned by the licensee have been entered into the licensees corrective action
      program. This violation and corrective action tracking number are listed in Section 4OA7
      of this report.
                                                                                          Enclosure


The inspectors noted that the operators performing Freeze Protection Daily Logs were not being provided or using Appendix A & B during the performance of the procedure. On November 27, 2013, the licensee entered the insulation and non-working heat trace deficiencies in the Official Freeze Protection Discrepancy List. In response to NRC questioning, the licensee performed a prompt operability review. This review documented that, on all four trains, over 80 feet of piping was missing insulation. The operability review stated that a break in piping due to freezing could overwhelm the RHRSW compartment sump pumps resulting in the failure of all three RHRSW pumps in that particular room. Additionally the review noted that the heat trace design calculation, MDQ0023880058, assumed that insulation is always installed and is required for heat trace functionality. The licensee's operability review concluded that past operability was maintained and on December 18, 2013, the licensee installed compensatory measures including heaters and tarpaulin.
                                          REPORT DETAILS
Summary of Plant Status
Unit 1 operated at 100 percent of rated thermal power (RTP) except for one planned
downpower on December 14, 2013, for an oil addition to the 1B recirculation pump. Power
remained at 100 percent RTP for the remainder of the quarter.
Unit 2 operated at 100 percent RTP except for three planned downpowers, November 16, 2013,
for troubleshooting on the 2B3 feedwater heater, November 21, 2013, for repairs to the 2B3
feedwater heater, and December 6, 2013, for repairs to the 2A3 and 2C3 feedwater heaters.
On October 12, 2013, an unplanned power reduction to 78 percent RTP occurred as a result of
a recirculation pump runback caused by the failure of the main steam line and reactor feedwater
flow indicators. Power remained at 100 percent RTP for the remainder of the quarter.
Unit 3 operated at 100 percent RTP except for a planned downpower on October 4, 2013, for
repairs to the 3C3 feedwater heater and to replace a power supply on the 3B reactor feed pump
governor control circuit. Power remained at 100 percent RTP for the remainder of the quarter.
1.      REACTOR SAFETY
        Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
.1      Readiness for Seasonal Extreme Weather Conditions
  a.  Inspection Scope
        Prior to and during the onset of cold weather conditions, the inspectors reviewed the
        licensees implementation of 0-GOI-200-1, Freeze Protection Inspection, including
        applicable checklists: Attachment 1, Freeze Protection Annual Checklist; Attachment 2,
        Freeze Protection Operational Checklist; and as applicable, Attachments 3 through 12,
        Freeze Protection Daily Log Sheets for individual watch stations. The inspectors also
        reviewed the list of open FZ-coded Work Orders and 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 the main
        control rooms, residual heat removal service water (RHRSW) and emergency equipment
        cooling water (EECW) pump rooms, and all units emergency diesel generator (EDG)
        buildings, to verify that affected systems and components were properly configured and
        protected as specified by the procedure. The inspectors discussed cold weather
        conditions with Operations personnel to assess plant equipment conditions and
        personnel sensitivity to upcoming cold weather conditions. This constituted one
        Readiness for Seasonal Extreme Weather sample. Documents reviewed are listed in
        the Attachment.
                                                                                        Enclosure


=====Analysis:=====
                                          7
The inspectors determined that the failure to enter freeze protection discrepancies into the CAP as part of the Freeze Protection Discrepancy List per 0-GOI-200-1, Freeze Protection Inspection, was a performance deficiency. Specifically, the licensee failed to document missing insulation on the RHRSW and EECW systems in accordance with Appendix B and Section 5.0 of 0-GOI-200-1. The finding is associated with the Initiating Events cornerstone. The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern, in that the intake room piping would continue to be exposed to freezing temperatures without adequate freeze protection which could affect RHRSW and EECW systems' ability to perform their safety functions. The inspectors performed a Phase 1 screening in accordance with IMC 0609, Significance Determination Process, Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding was of very low safety significance (Green) because it did not impact the frequency of an internal flooding event. The cause of this finding has a cross-cutting aspect in the Work Practices component of the Human Performance area, because the licensee failed to define and effectively communicate expectations regarding procedural compliance and that personnel follow procedures. [H.4(b)]. 
b. Findings
  Introduction: The NRC identified a Green non-cited violation (NCV) of 10 CFR 50,
  Appendix B, Criterion V, Procedures, for the licensees failure to implement 0-GOI-200-
  1, Freeze Protection Inspection. Specifically, the licensee failed to enter freeze
  protection discrepancies into the corrective action program (CAP) as part of the Freeze
  Protection Discrepancy List per 0-GOI-200-1 for the RHRSW and EECW systems.
  Description: On October 24, 2013, NRC inspectors identified piping insulation removed
  and heat trace wires disconnected on multiple RHRSW and EECW pipes at the Browns
  Ferry plant intake rooms. These rooms have no roof and are exposed to outside
  conditions. Licensee procedure 0-GOI-200-1, Freeze Protection Inspection, required
  completion of Attachment 1, Freeze Protection Annual Checklist, by October 1, 2013.
  This checklist requires the performance of general area inspections of the RHRSW
  Pump Rooms, per Appendix A, section 4.0, General Area Checks Guideline, which
  included verification that heat trace circuits were functioning and insulation was installed
  on all piping and instrument lines. 0-GOI-200-1, Annual Check List had not been
  completed as of October 24, 2013.
  Subsequently, on December 13, 2013, NRC inspectors observed that heat trace circuits
  in the RHRSW rooms did not have insulation covering the heat trace tape and no
  compensatory measures were in place to prevent pipe freezing. Temperatures earlier
  that week had routinely decreased below 25 degrees Fahrenheit (F) each night. Area
  temperatures had started dropping below 25 degrees F on November 13, 2013.
  Section 5.0, Step 3.1 of 0-GOI-200-1, required outstanding discrepancies following
  completion of Attachment 1 to be evaluated and verification that a Service Request
  (SR)/Work Order (WO) with the term FZ in the narrative details section for the Focus
  Area have been initiated. Step 3.2 required that if compensatory measures were
  required that they be added to the Operator Work Around list.
  Attachments 3 and 4, of 0-GOI-200-1, Freeze Protection Daily Log Sheets, were
  required to be performed when outside ambient temperature dropped below 25 degrees
  F or stayed below 32 degrees F for an 8-hour period. Both attachments required area
  inspections of the RHRSW Pump Rooms, per Appendix A, section 4.0, General Area
  Checks Guideline. Discrepancies identified during area inspection were required to be
  recorded on Appendix B, Freeze Protection Remarks Log, and a SR/WO be initiated
  with the term FZ in the narrative details section or verified already in Freeze Protection
  Discrepancy List (MAXIMO Focus Area FZ).
  The inspectors noted that the missing insulation was not documented in the Annual
  Checklist or the Daily Log Sheets, nor was it included in the Official Freeze Protection
  Discrepancy List.
  The inspectors noted that the operators performing Freeze Protection Daily Logs were
  not being provided or using Appendix A & B during the performance of the procedure.
  On November 27, 2013, the licensee entered the insulation and non-working heat trace
  deficiencies in the Official Freeze Protection Discrepancy List. In response to NRC
                                                                                      Enclosure


=====Enforcement:=====
                                        8
Title 10 CFR 50, Appendix B, Criterion V, Procedures, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings and shall be accomplished in accordance with these instructions, procedures and drawings. Browns Ferry procedure 0-GOI-200-1, Freeze Protection Inspection, is a quality related procedure which verified freeze protection on RHRSW and EECW pumps and associated components to ensure that they will operate at below freezing temperatures. Appendix B and Section 5.0 required documentation of freeze protection discrepancies in the CAP as part of the Freeze Protection Discrepancy List. Contrary to the above, between November 13, 2013, and November 27, 2013, the licensee failed to accomplish activities affecting quality in accordance with procedures.
questioning, the licensee performed a prompt operability review. This review
documented that, on all four trains, over 80 feet of piping was missing insulation. The
operability review stated that a break in piping due to freezing could overwhelm the
RHRSW compartment sump pumps resulting in the failure of all three RHRSW pumps in
that particular room. Additionally the review noted that the heat trace design calculation,
MDQ0023880058, assumed that insulation is always installed and is required for heat
trace functionality. The licensees operability review concluded that past operability was
maintained and on December 18, 2013, the licensee installed compensatory measures
including heaters and tarpaulin.
Analysis: The inspectors determined that the failure to enter freeze protection
discrepancies into the CAP as part of the Freeze Protection Discrepancy List per 0-GOI-
200-1, Freeze Protection Inspection, was a performance deficiency. Specifically, the
licensee failed to document missing insulation on the RHRSW and EECW systems in
accordance with Appendix B and Section 5.0 of 0-GOI-200-1. The finding is associated
with the Initiating Events cornerstone. The finding was more than minor because, if left
uncorrected, the performance deficiency would have the potential to lead to a more
significant safety concern, in that the intake room piping would continue to be exposed to
freezing temperatures without adequate freeze protection which could affect RHRSW
and EECW systems ability to perform their safety functions. The inspectors performed
a Phase 1 screening in accordance with IMC 0609, Significance Determination Process,
Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding
was of very low safety significance (Green) because it did not impact the frequency of an
internal flooding event. The cause of this finding has a cross-cutting aspect in the Work
Practices component of the Human Performance area, because the licensee failed to
define and effectively communicate expectations regarding procedural compliance and
that personnel follow procedures. [H.4(b)].
Enforcement: Title 10 CFR 50, Appendix B, Criterion V, Procedures, requires, in part,
that activities affecting quality shall be prescribed by documented instructions,
procedures, or drawings and shall be accomplished in accordance with these
instructions, procedures and drawings. Browns Ferry procedure 0-GOI-200-1, Freeze
Protection Inspection, is a quality related procedure which verified freeze protection on
RHRSW and EECW pumps and associated components to ensure that they will operate
at below freezing temperatures. Appendix B and Section 5.0 required documentation of
freeze protection discrepancies in the CAP as part of the Freeze Protection Discrepancy
List. Contrary to the above, between November 13, 2013, and November 27, 2013, the
licensee failed to accomplish activities affecting quality in accordance with procedures.
Specifically, the licensee failed to document missing insulation on the RHRSW and
EECW systems in the CAP as part of the Freeze Protection Discrepancy List as required
by procedure 0-GOI-200-1. As a result, the required heaters and tarpaulin were not
installed until December 18, 2013. On November 27, 2013, the licensee entered the
insulation and non-working heat trace deficiencies in the Official Freeze Protection
Discrepancy List. This violation is being treated as a non-cited violation (NCV),
consistent with Section 2.3.2 of the NRC Enforcement Policy. The violation was entered
into the licensees corrective action program as PERs 800190 and 821426. (NCV
05000259/2013005-01, Failure to Document Service Water Freeze Protection
Deficiencies)
                                                                                  Enclosure


Specifically, the licensee failed to document missing insulation on the RHRSW and EECW systems in the CAP as part of the Freeze Protection Discrepancy List as required by procedure 0-GOI-200-1. As a result, the required heaters and tarpaulin were not installed until December 18, 2013. On November 27, 2013, the licensee entered the insulation and non-working heat trace deficiencies in the Official Freeze Protection Discrepancy List. This violation is being treated as a non-cited violation (NCV),
                                            9
consistent with Section 2.3.2 of the NRC Enforcement Policy. The violation was entered into the licensee's corrective action program as PERs 800190 and 821426.  (NCV 05000259/2013005-01, Failure to Document Service Water Freeze Protection Deficiencies) 
1R04 Equipment Alignment
.1    Partial Walkdown
  a. Inspection Scope
      The inspectors conducted 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, Updated Final Safety Analysis Report (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.
      This activity constituted four Equipment Alignment Partial Walkdown inspection samples.
      Documents reviewed are listed in the Attachment.
      *    October 15, 2013, Unit 2 core spray (CS) system - Division I
      *    October 21, 2013, Unit 1 standby liquid control system
      *    October 23, 2013, Common switchyard with Bus 2 out of service
      *    December 12, 2013, Unit 3 reactor core isolation cooling (RCIC)
  b. Findings
      No findings were identified.
1R05 Fire Protection
.1    Fire Protection Tours
  a. Inspection Scope
      The inspectors reviewed licensee procedures for transient combustibles and fire
      protection impairments, and conducted a walkdown of the fire areas (FAs) and fire zones
      (FZs) 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. The inspectors verified that selected fire protection
      impairments were identified and controlled in accordance with procedures. Furthermore,
      the inspectors reviewed applicable portions of the Fire Protection Report, Volumes 1 and
      2, including the applicable Fire Hazards Analysis, 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. This activity constituted six Fire
      Protection Walkdown inspection samples. Documents reviewed are listed in the
      Attachment.
                                                                                        Enclosure


{{a|1R04}}
                                              10
==1R04 Equipment Alignment==
      *    October 1, 2013, Unit 1 Reactor Building, EL 639 feet (Fire Zone 1-6)
      *    October 1, 2013, Unit 2 Reactor Building South East Quad EL 519 feet and 541 feet
          (Fire Zone 2-2)
      *    October 2, 2013, Unit 2 Reactor Building, EL 621 feet 2A Electrical Board Room
          (Fire Area 9)
      *    October 2, 2013, Unit 2 Reactor Building, EL 621 feet 480V Shutdown board Room
          2A (Fire Area 10)
      *    October 2, 2013, Unit 2 Reactor Building, EL 621 feet 480V Shutdown board Room
          2B (Fire Area 11)
      *    November 5, 2013, Intake Pumping Station Cable Tunnel (Fire Zone 25-3)
  b. Findings
      No findings were identified.
1R11 Licensed Operator Requalification and Performance
.1    Licensed Operator Requalification
  a. Inspection Scope
      On October 15, 2013, the inspectors observed an as-found licensed operator
      requalification for an operating crew according to Unit 2 Simulator Exercise Guide (SEG)
      OPL173.R227, Anticipated Transient without Scram (ATWS), and Various Technical
      Specification entries.
      The inspectors specifically evaluated the following attributes related to the 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 procedures including Abnormal Operating
          Instructions (AOIs), Emergency Operating Instructions (EOIs) and Safe Shutdown
          Instructions (SSI)
      *    Timely control board operation and manipulation, including high-risk operator actions
      *    Timely oversight and direction provided by the shift supervisor, including ability to
          identify and implement appropriate TS actions such as reporting and emergency plan
          actions and notifications
      *    Group dynamics involved in crew performance
      The inspectors assessed the licensees ability to administer testing and assess the
      performance of their licensed operators. The inspectors attended the post-examination
      critique performed by the licensee evaluators, and verified 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
                                                                                          Enclosure


===.1 Partial Walkdown===
                                                11
        reference plant control room, such as physical location of panels, equipment,
        instruments, controls, labels, and related form and function). This activity constituted
        one Observation of Requalification Activity inspection sample. Documents reviewed are
        listed in the Attachment.
  b.  Findings
        No findings were identified.
.2      Control Room Observations
  a.  Inspection Scope
        Inspectors observed and assessed licensed operator performance in the plant and main
        control room, particularly during periods of heightened activity or risk and where the
        activities could affect plant safety. Inspectors reviewed various licensee policies and
        procedures covering Conduct of Operations, Plant Operations, and Power Maneuvering.
        The inspectors utilized activities such as post maintenance testing, surveillance testing
        and other activities to focus on the following conduct of operations as appropriate;
        *    Operator compliance and use of procedures.
        *    Control board manipulations.
        *    Communication between crew members.
        *    Use and interpretation of plant instruments, indications, and alarms.
        *    Use of human error prevention techniques.
        *    Documentation of activities, including initials and sign-offs in procedures.
        *    Supervision of activities, including risk and reactivity management.
        *    Pre-job briefs.
        This activity constituted one Control Room Observation inspection sample.
  b.  Findings and Violations
    (1) Failure To Maintain Emergency Response Staffing Levels
        Introduction: The NRC identified an apparent violation of 10 CFR 50.54(q), Emergency
        Plans, for the licensees failure to maintain plant staffing levels in accordance with
        NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan.
        Specifically, the process for maintaining emergency staffing requirements included
        implementation of the requirements of OPDP-1, Conduct of Operations, which identified
        the required on-shift staffing levels. However, this procedure was found to be
        inadequate to maintain shift staffing in compliance with the NP-REP for both the Shift
        Technical Advisor (STA) and Incident Commander positions.
                                                                                          Enclosure


====a. Inspection Scope====
                                      12
The inspectors conducted 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, Updated Final Safety Analysis Report (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.
Description: On November 15, 2006, the licensee submitted license amendment
requests (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) units 1, 2 and 3,
respectively. The LARs were submitted as part of the restart effort associated with Unit
1. In part, the LARs identified the minimum staffing levels necessary to ensure safe
shutdown can be achieved on the three operating units during an Appendix R fire, which
were one Shift Manager (SM), four Unit Supervisors (US), six Reactor Operators (ROs),
eight Assistant Unit Operators (AUOs), and one Shift Technical Advisor. The LARs
indicated that the stated staffing levels were required once Unit 1 achieved Mode 2 of
reactor operations, which occurred on May 21, 2007.
These staffing levels met the minimum on-shift facility staffing requirements defined in
Figure A-1, Site Emergency Organization, of Appendix A, Browns Ferry Nuclear Plant,
contained in revision 84 (dated February 17, 2007) of NP-REP, which required one SM,
one US for each unit, two ROs for each unit, two AUOs for each unit, and one STA. The
on-shift levels delineated in Figure A-1 have remained unchanged for the STA since
revision 84 of NP-REP. NP-REP Revision 100, dated December 21, 2012, added the
Incident Commander to the Figure A-1 as a required on-shift position.
In July 2013, inspectors questioned the licensee on how the safe shutdown actions for
an Appendix R fire could be implemented with a US that was also performing the
emergency response actions assigned to the STA function during a fire event. Initially,
the licensee stated that one of the other US would implement the safe shutdown actions
on both his assigned unit and the unit with the US that was fulfilling the STA function.
The inspectors questioned how one US could implement the safe shutdown actions on
two units simultaneously. The licensee stated that they could provide a staffing study
that supported the current staffing levels.
On October 3, 2013, the licensee notified the NRC via Event Notification (EN) 49406 that
the site was in an unanalyzed condition. In the event of an Appendix R fire in the
Control Bay, the current level of operations shift staffing would not be adequate to
perform all the actions in the SSIs to ensure safe shutdown of the units; specifically one
of the units would be without a US to direct the actions of the SSI. The licensee entered
the issue into corrective action program (CAP) via Problem Evaluation Report (PER)
790092. The licensee took actions to place a dedicated Incident Commander on shift for
each of the shifts that was either a licensed SRO, certified SRO or licensed RO that had
successfully completed BFN Incident Commander Training. Following further
investigation, the licensee determined that shift staffing on all three units was still not in
compliance with the license conditions for fire protection as contained in LARs 271, 300
and 259. On October 30, 2013, the licensee entered this issue into the CAP via PER
801057 and took the immediate corrective action to ensure five licensed SROs were
verified on shift and initiated actions to revise the Standing Order on minimum SSI
staffing to require five licensed SROs on each shift. The licensees root cause analysis
determined that between February 11, 2008, and July 8, 2012, twenty-six PERs relating
to operations staffing were written. All of the PERs resulted in a determination that
staffing levels were adequate.
                                                                                  Enclosure


This activity constituted four Equipment Alignment Partial Walkdown inspection samples. Documents reviewed are listed in the Attachment.
                                      13
* October 15, 2013, Unit 2 core spray (CS) system - Division I
The inspectors reviewed NP-REP, Tennessee Valley Authority Nuclear Power
* October 21, 2013, Unit 1 standby liquid control system
Radiological Emergency Plan, revision 100. Figure A-1, Site Emergency Organization,
* October 23, 2013, Common switchyard with Bus 2 out of service
in Appendix A of NP-REP required that both an STA and a US are part of the required
* December 12, 2013, Unit 3 reactor core isolation cooling (RCIC)
manning during an emergency on an affected unit. For the unaffected units, a US is
required on each of the unaffected units with an exception for units sharing a common
control area. In the case of an Appendix R fire, all three units are affected which would
require three US and an STA be staffed. The inspectors determined that since May 21,
2007, when Unit 1 entered Mode 2, to the present, the licensee could not meet the
staffing requirements of NP-REP during any Appendix R fire on any of the three units.
The inspectors also identified that beginning with NP-REP Revision 100, dated
December 21, 2012, an Incident Commander position was added to the Figure A-1 as a
required on-shift position, but no process was implemented to ensure it was continually
staffed.
The process for maintaining emergency staffing requirements includes implementation
of the requirements of OPDP-1, Conduct of Operations, which identified the required on-
shift staffing levels. This procedure was found to be inadequate to maintain shift staffing
in compliance with the NP-REP for both the STA and Incident Commander positions.
Analysis: The licensees failure to maintain plant staffing levels in accordance with NP-
REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan was a
performance deficiency. Specifically, the licensees process for maintaining minimum
emergency response shift staffing failed to adequately maintain staffing of the STA and
Incident Commander to ensure initial accident response in all key functional areas. The
inspectors determined the performance deficiency was more than minor because it was
associated with the ERO readiness attribute of the emergency preparedness
cornerstone and adversely impacted the cornerstone objective of ensuring that the
licensee is capable of implementing adequate measures to protect the health and safety
of the public in the event of a radiological emergency. Specifically, the failure to
maintain required emergency response staffing levels reduced the licensees capabilities
to respond to an emergency. The inspectors assessed the finding in accordance with
Appendix B, Emergency Preparedness Significance Determination Process, (February
24, 2012) of IMC 0609, Significance Determination Process, and using Table 5.2-1 -
Significance Examples §50.47(b)(2), determined that this finding represented a process
for on-shift staffing that would allow 2 or more shifts to go below E-plan minimum staffing
requirements. Specifically, the inspectors determined that the licensees process failed
to ensure shift staffing met E-plan minimum staffing requirements for a period of over 6
years. This corresponded to a Loss of Planning Standard Function and has preliminarily
been determined to be a finding of White significance.
Because the licensee has taken immediate corrective actions to increase staffing levels
consistent with the emergency plan, this issue does not represent an immediate safety
concern. Because the significance of this finding is not yet finalized, it is being
characterized as To Be Determined (TBD), pending a final significance determination.
                                                                                    Enclosure


====b. Findings====
                                            14
No findings were identified.
    The cause of the finding was determined to be associated with the cross-cutting aspect
{{a|1R05}}
    of thorough evaluation of problems in the corrective action component of the problem
==1R05 Fire Protection==
    identification and resolution area because the licensee failed to ensure that issues
    potentially affecting nuclear safety were thoroughly evaluated. [P.1(c)]
    Enforcement: 10 CFR 50.54(q) requires, in part, that a holder of a license under Part 50
    shall follow and maintain the effectiveness of the emergency plan that meets the
    planning standards of 10 CFR 50.47. 10 CFR 50.47(b)(2) states, in part, that adequate
    staffing to provide initial facility accident response in key functional areas is maintained
    at all times. NP-REP, Tennessee Valley Authority Nuclear Power Radiological
    Emergency Plan, of Appendix A, Figure A-1, Site Emergency Organization, Browns
    Ferry Nuclear Plant, defined the emergency plan staffing requirements for key functional
    areas including the staffing of a Shift Technical Advisor and Incident Commander.
    From May 21, 2007, through October 30, 2013, the licensee failed to follow and maintain
    the effectiveness of an emergency plan that met the planning standards of 10 CFR
    50.47 when the licensee did not ensure adequate staffing to provide initial facility
    accident response in key functional areas was maintained at all times. Specifically, the
    licensees process for maintaining minimum emergency response shift staffing failed to
    ensure continuous staffing of emergency response roles as defined in NP-REP,
    Tennessee Valley Authority Nuclear Power Radiological Emergency Plan as evidenced
    by the following examples:
    *    Failure to continuously staff the STA position beginning May 21, 2007
    *    Failure to continuously staff the Incident Commander position beginning
        December 21, 2012
    The licensee augmented on-shift staffing levels on October 30, 2013, and entered this
    issue into the corrective action program (CAP) as PERs 790092 and 801057. Pending
    determination of the findings final safety significance, this finding is identified as AV
    05000259, 260, 296/2013005-02, Failure to Maintain Emergency Response Staffing
    Levels.
(2) Inaccurate Information Provided Concerning Onsite Emergency Response Organization
    Staffing Requirements
    Introduction: Two examples of an NRC-identified apparent violation of 10 CFR 50.9,
    Completeness and accuracy of information, were identified for the licensees apparent
    failure to provide complete and accurate information associated with emergency
    response on-shift staffing requirements. Specifically, on two occasions the licensee
    apparently provided inaccurate information to the NRC concerning onsite emergency
    response organization minimum staffing requirements.
    Description: On November 15, 2006, TVA submitted license amendment requests
    (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) Units 1, 2 and 3, respectively.
    The LARs were submitted as part of the restart effort associated with Unit 1. In part, the
    LARs identified the minimum staffing levels necessary to ensure that safe shutdown can
    be achieved on the three operating units during an Appendix R fire. The LARs stated
                                                                                          Enclosure


===.1 Fire Protection Tours===
                                      15
 
that the minimum staffing levels were one Shift Manager (SM), four Unit Supervisors
====a. Inspection Scope====
(US), six Reactor Operators (ROs), eight Assistant Unit Operators (AUOs), and one Shift
The inspectors reviewed licensee procedures for transient combustibles and fire protection impairments, and conducted a walkdown of the fire areas (FAs) and fire zones (FZs) 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. The inspectors verified that selected fire protection impairments were identified and controlled in accordance with procedures. Furthermore, the inspectors reviewed applicable portions of the Fire Protection Report, Volumes 1 and 2, including the applicable Fire Hazards Analysis, 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. This activity constituted six Fire Protection Walkdown inspection samples. Documents reviewed are listed in the
Technical Advisor. The LARs indicated that the stated staffing levels were required once
.
Unit 1 achieved Mode 2 of reactor operations, which occurred on May 21, 2007.
* October 1, 2013, Unit 1 Reactor Building, EL 639 feet (Fire Zone 1-6)
On January 10, 2007, the licensee issued revision 7 of OPDP-1, Conduct of Operations,
* October 1, 2013, Unit 2 Reactor Building South East Quad EL 519 feet and 541 feet (Fire Zone 2-2)
which identified the required on-shift staffing levels to be one SM, three US, six ROs,
* October 2, 2013, Unit 2 Reactor Building, EL 621 feet 2A Electrical Board Room (Fire Area 9)
eight AUOs and one STA with the STA function allowed to be filled by one of the on-shift
* October 2, 2013, Unit 2 Reactor Building, EL 621 feet 480V Shutdown board Room 2A (Fire Area 10)
US. This change decreased the required staffing levels for on-shift Unit Supervisors
* October 2, 2013, Unit 2 Reactor Building, EL 621 feet 480V Shutdown board Room 2B (Fire Area 11)
from 4 to 3, and allowed the STA position to be filled by one of the on-shift US. This was
* November 5, 2013, Intake Pumping Station Cable Tunnel (Fire Zone 25-3)
not sufficient to meet the required staffing levels submitted in the LARs required prior to
 
reaching Mode 2 on Unit 1.
====b. Findings====
In the safety evaluation dated April 25, 2007 (ADAMS Accession Number ML
No findings were identified.
071160431), the NRC documented that the licensee conveyed to NRC staff that the
{{a|1R11}}
appropriate procedures had been revised to reflect the increase in staffing levels
==1R11 Licensed Operator Requalification and Performance==
contained in the LARs. On April 25, 2007, the NRC approved the LARs for all three
 
units.
===.1 Licensed Operator Requalification===
On February 17, 2010, the licensee determined that the guidance provided in OPDP-1
 
for minimum on-shift staffing did not meet the staffing levels submitted in LARs 271, 300,
====a. Inspection Scope====
and 259. On May 13, 2010, the licensee notified the Region II Regional Administrator
On October 15, 2013, the inspectors observed an as-found licensed operator requalification for an operating crew according to Unit 2 Simulator Exercise Guide (SEG) OPL173.R227, Anticipated Transient without Scram (ATWS), and Various Technical Specification entries.
(RA), via a conference call, of the issue and in a follow-up letter dated June 29, 2010,
 
the licensee informed the RA that they did not meet the requirements of their licensing
The inspectors specifically evaluated the following attributes related to the operating crew's performance:
basis. However, the licensee also stated that they had completed a staffing assessment
* Clarity and formality of communication
and determined that the current minimum staffing levels contained in OPDP-1 (i.e., three
* Ability to take timely action to safely control the unit
US with one US filling the STA function) were adequate for successful implementation of
* Prioritization, interpretation, and verification of alarms
all safe shutdown actions for the bounding Appendix R fire scenario. On November 30,
* Correct use and implementation of procedures including Abnormal Operating Instructions (AOIs), Emergency Operating Instructions (EOIs) and Safe Shutdown Instructions (SSI)
2011, the licensee submitted in Summary Report for 10 CFR 50.59 Evaluations, Fire
* Timely control board operation and manipulation, including high-risk operator actions
Protection Report Technical Specification Bases Changes, Technical Requirements
* Timely oversight and direction provided by the shift supervisor, including ability to identify and implement appropriate TS actions such as reporting and emergency plan actions and notifications
Manual Changes, and NRC Commitment Revision to change to the staffing level
* Group dynamics involved in crew performance  The inspectors assessed the licensee's ability to administer testing and assess the performance of their licensed operators. The inspectors attended the post-examination critique performed by the licensee evaluators, and verified 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). This activity constituted one Observation of Requalification Activity inspection sample. Documents reviewed are listed in the Attachment.
requirements in which they again provided information of their assessment and change
 
to their required staffing levels.
====b. Findings====
On September 06, 2013, the licensee initiated a self-assessment entitled Operations
No findings were identified.
Department Staffing Levels. The assessment evaluated three different scenarios:
 
===.2 Control Room Observations===
 
====a. Inspection Scope====
Inspectors observed and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Inspectors reviewed various licensee policies and procedures covering Conduct of Operations, Plant Operations, and Power Maneuvering.
 
The inspectors utilized activities such as post maintenance testing, surveillance testing and other activities to focus on the following conduct of operations as appropriate;
* Operator compliance and use of procedures.
* Control board manipulations.
* Communication between crew members.
* Use and interpretation of plant instruments, indications, and alarms.
* Use of human error prevention techniques.
* Documentation of activities, including initials and sign-offs in procedures.
* Supervision of activities, including risk and reactivity management.
* Pre-job briefs. This activity constituted one Control Room Observation inspection sample.
 
====b. Findings====
and Violations  (1) Failure To Maintain Emergency Response Staffing Levels
 
=====Introduction:=====
The NRC identified an apparent violation of 10 CFR 50.54(q), Emergency Plans, for the licensee's failure to maintain plant staffing levels in accordance with NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan.
 
Specifically, the process for maintaining emergency staffing requirements included implementation of the requirements of OPDP-1, Conduct of Operations, which identified the required on-shift staffing levels. However, this procedure was found to be inadequate to maintain shift staffing in compliance with the NP-REP for both the Shift Technical Advisor (STA) and Incident Commander positions.
 
=====Description:=====
On November 15, 2006, the licensee submitted license amendment requests (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) units 1, 2 and 3, respectively. The LARs were submitted as part of the restart effort associated with Unit
 
===1. In part, the LARs identified the minimum staffing levels necessary to ensure safe ===
 
shutdown can be achieved on the three operating units during an Appendix R fire, which were one Shift Manager (SM), four Unit Supervisors (US), six Reactor Operators (ROs),
eight Assistant Unit Operators (AUOs), and one Shift Technical Advisor. The LARs indicated that the stated staffing levels were required once Unit 1 achieved Mode 2 of reactor operations, which occurred on May 21, 2007.
 
These staffing levels met the minimum on-shift facility staffing requirements defined in Figure A-1, Site Emergency Organization, of Appendix A, Browns Ferry Nuclear Plant, contained in revision 84 (dated February 17, 2007) of NP-REP, which required one SM, one US for each unit, two ROs for each unit, two AUOs for each unit, and one STA. The on-shift levels delineated in Figure A-1 have remained unchanged for the STA since revision 84 of NP-REP. NP-REP Revision 100, dated December 21, 2012, added the Incident Commander to the Figure A-1 as a required on-shift position. In July 2013, inspectors questioned the licensee on how the safe shutdown actions for an Appendix R fire could be implemented with a US that was also performing the emergency response actions assigned to the STA function during a fire event. Initially, the licensee stated that one of the other US would implement the safe shutdown actions on both his assigned unit and the unit with the US that was fulfilling the STA function. The inspectors questioned how one US could implement the safe shutdown actions on two units simultaneously. The licensee stated that they could provide a staffing study that supported the current staffing levels.
 
On October 3, 2013, the licensee notified the NRC via Event Notification (EN) 49406 that the site was in an unanalyzed condition. In the event of an Appendix R fire in the Control Bay, the current level of operations shift staffing would not be adequate to perform all the actions in the SSIs to ensure safe shutdown of the units; specifically one of the units would be without a US to direct the actions of the SSI. The licensee entered the issue into corrective action program (CAP) via Problem Evaluation Report (PER) 790092. The licensee took actions to place a dedicated Incident Commander on shift for each of the shifts that was either a licensed SRO, certified SRO or licensed RO that had successfully completed BFN Incident Commander Training. Following further investigation, the licensee determined that shift staffing on all three units was still not in compliance with the license conditions for fire protection as contained in LARs 271, 300 and 259. On October 30, 2013, the licensee entered this issue into the CAP via PER 801057 and took the immediate corrective action to ensure five licensed SROs were verified on shift and initiated actions to revise the Standing Order on minimum SSI staffing to require five licensed SROs on each shift. The licensee's root cause analysis determined that between February 11, 2008, and July 8, 2012, twenty-six PERs relating to operations staffing were written. All of the PERs resulted in a determination that staffing levels were adequate.
 
The inspectors reviewed NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan, revision 100. Figure A-1, Site Emergency Organization, in Appendix A of NP-REP required that both an STA and a US are part of the required manning during an emergency on an affected unit. For the unaffected units, a US is required on each of the unaffected units with an exception for units sharing a common control area. In the case of an Appendix R fire, all three units are affected which would require three US and an STA be staffed. The inspectors determined that since May 21, 2007, when Unit 1 entered Mode 2, to the present, the licensee could not meet the staffing requirements of NP-REP during any Appendix R fire on any of the three units. The inspectors also identified that beginning with NP-REP Revision 100, dated December 21, 2012, an Incident Commander position was added to the Figure A-1 as a required on-shift position, but no process was implemented to ensure it was continually staffed.
 
The process for maintaining emergency staffing requirements includes implementation of the requirements of OPDP-1, Conduct of Operations, which identified the required on-shift staffing levels. This procedure was found to be inadequate to maintain shift staffing in compliance with the NP-REP for both the STA and Incident Commander positions.
 
=====Analysis:=====
The licensee's failure to maintain plant staffing levels in accordance with NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan was a performance deficiency. Specifically, the licensee's process for maintaining minimum emergency response shift staffing failed to adequately maintain staffing of the STA and Incident Commander to ensure initial accident response in all key functional areas. The inspectors determined the performance deficiency was more than minor because it was associated with the ERO readiness attribute of the emergency preparedness cornerstone and adversely impacted the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the failure to maintain required emergency response staffing levels reduced the licensee's capabilities to respond to an emergency. The inspectors assessed the finding in accordance with Appendix B, Emergency Preparedness Significance Determination Process, (February 24, 2012) of IMC 0609, Significance Determination Process, and using Table 5.2-1 -
Significance Examples §50.47(b)(2), determined that this finding represented a process for on-shift staffing that would allow 2 or more shifts to go below E-plan minimum staffing requirements. Specifically, the inspectors determined that the licensee's process failed to ensure shift staffing met E-plan minimum staffing requirements for a period of over 6 years. This corresponded to a Loss of Planning Standard Function and has preliminarily been determined to be a finding of White significance.
 
Because the licensee has taken immediate corrective actions to increase staffing levels consistent with the emergency plan, this issue does not represent an immediate safety concern. Because the significance of this finding is not yet finalized, it is being characterized as "To Be Determined (TBD)," pending a final significance determination.
 
The cause of the finding was determined to be associated with the cross-cutting aspect of thorough evaluation of problems in the corrective action component of the problem identification and resolution area because the licensee failed to ensure that issues potentially affecting nuclear safety were thoroughly evaluated. [P.1(c)] 
 
=====Enforcement:=====
10 CFR 50.54(q) requires, in part, that a holder of a license under Part 50 shall follow and maintain the effectiveness of the emergency plan that meets the planning standards of 10 CFR 50.47. 10 CFR 50.47(b)(2) states, in part, that adequate staffing to provide initial facility accident response in key functional areas is maintained at all times. NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan, of Appendix A, Figure A-1, Site Emergency Organization, Browns Ferry Nuclear Plant, defined the emergency plan staffing requirements for key functional areas including the staffing of a Shift Technical Advisor and Incident Commander.
 
From May 21, 2007, through October 30, 2013, the licensee failed to follow and maintain the effectiveness of an emergency plan that met the planning standards of 10 CFR 50.47 when the licensee did not ensure adequate staffing to provide initial facility accident response in key functional areas was maintained at all times. Specifically, the licensee's process for maintaining minimum emergency response shift staffing failed to ensure continuous staffing of emergency response roles as defined in NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan as evidenced by the following examples:
* Failure to continuously staff the STA position beginning May 21, 2007
* Failure to continuously staff the Incident Commander position beginning      December 21, 2012  The licensee augmented on-shift staffing levels on October 30, 2013, and entered this issue into the corrective action program (CAP) as PERs 790092 and 801057. Pending determination of the finding's final safety significance, this finding is identified as AV 05000259, 260, 296/2013005-02, Failure to Maintain Emergency Response Staffing Levels.  (2) Inaccurate Information Provided Concerning Onsite Emergency Response Organization Staffing Requirements 
 
=====Introduction:=====
Two examples of an NRC-identified apparent violation of 10 CFR 50.9, "Completeness and accuracy of information," were identified for the licensee's apparent failure to provide complete and accurate information associated with emergency response on-shift staffing requirements. Specifically, on two occasions the licensee apparently provided inaccurate information to the NRC concerning onsite emergency response organization minimum staffing requirements.
 
=====Description:=====
On November 15, 2006, TVA submitted license amendment requests (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) Units 1, 2 and 3, respectively.
 
The LARs were submitted as part of the restart effort associated with Unit 1. In part, the LARs identified the minimum staffing levels necessary to ensure that safe shutdown can be achieved on the three operating units during an Appendix R fire. The LARs stated that the minimum staffing levels were one Shift Manager (SM), four Unit Supervisors (US), six Reactor Operators (ROs), eight Assistant Unit Operators (AUOs), and one Shift Technical Advisor. The LARs indicated that the stated staffing levels were required once Unit 1 achieved Mode 2 of reactor operations, which occurred on May 21, 2007.
 
On January 10, 2007, the licensee issued revision 7 of OPDP-1, Conduct of Operations, which identified the required on-shift staffing levels to be one SM, three US, six ROs, eight AUOs and one STA with the STA function allowed to be filled by one of the on-shift US. This change decreased the required staffing levels for on-shift Unit Supervisors from 4 to 3, and allowed the STA position to be filled by one of the on-shift US. This was not sufficient to meet the required staffing levels submitted in the LARs required prior to reaching Mode 2 on Unit 1. In the safety evaluation dated April 25, 2007 (ADAMS Accession Number ML 071160431), the NRC documented that the licensee conveyed to NRC staff that the appropriate procedures had been revised to reflect the increase in staffing levels contained in the LARs. On April 25, 2007, the NRC approved the LARs for all three units.
 
On February 17, 2010, the licensee determined that the guidance provided in OPDP-1 for minimum on-shift staffing did not meet the staffing levels submitted in LARs 271, 300, and 259. On May 13, 2010, the licensee notified the Region II Regional Administrator (RA), via a conference call, of the issue and in a follow-up letter dated June 29, 2010, the licensee informed the RA that they did not meet the requirements of their licensing basis. However, the licensee also stated that they had completed a staffing assessment and determined that the current minimum staffing levels contained in OPDP-1 (i.e., three US with one US filling the STA function) were adequate for successful implementation of all safe shutdown actions for the bounding Appendix R fire scenario. On November 30, 2011, the licensee submitted in "Summary Report for 10 CFR 50.59 Evaluations, Fire Protection Report Technical Specification Bases Changes, Technical Requirements Manual Changes, and NRC Commitment Revision" to change to the staffing level requirements in which they again provided information of their assessment and change to their required staffing levels.
 
On September 06, 2013, the licensee initiated a self-assessment entitled "Operations Department Staffing Levels."  The assessment evaluated three different scenarios:
1) Loss of Coolant Accident (LOCA) with a simultaneous Loss of Offsite Power (LOOP);
1) Loss of Coolant Accident (LOCA) with a simultaneous Loss of Offsite Power (LOOP);
2) Fire in the Control Bay (Fire Area 16) that requires entry into the Safe Shutdown Instructions (SSIs), specifically 0-SSI-16; and 3) a Beyond Design Basis External Event postulated in response to the Fukushima Daiichi accident. The assessment assumed that shift staffing levels were at the minimum required by OPDP-1, revision 7. The self-assessment concluded that the current minimum staffing levels would not be sufficient to perform all the required actions in the event of a fire in the Control Bay (Event 2). The assessment contained a simplified time motion study that indicated the STA function could not be staffed during this event.
2) Fire in the Control Bay (Fire Area 16) that requires entry into the Safe Shutdown
 
Instructions (SSIs), specifically 0-SSI-16; and 3) a Beyond Design Basis External Event
On November 6, 2013, and in follow-up letter dated December 6, 2013, the licensee informed the Region II RA in accordance with 10 CFR 50.9(b), that TVA had inaccurately reported information regarding the required shift staffing for three-unit operation as originally submitted in LARs 271, 300, and 259. The inspectors determined that on multiple occasions the information provided to the NRC detailing required staffing levels was not complete and accurate in all material respects.
postulated in response to the Fukushima Daiichi accident. The assessment assumed
 
that shift staffing levels were at the minimum required by OPDP-1, revision 7. The self-
=====Analysis:=====
assessment concluded that the current minimum staffing levels would not be sufficient to
The inspectors determined that the licensee's apparent failure to provide complete and accurate information to the NRC were apparent violations of the requirements of 10 CFR 50.9, Completeness and Accuracy of Information. These apparent violations had the potential to impede or impact the regulatory process, and therefore are subject to traditional enforcement as described in the NRC Enforcement Policy, dated July 9, 2013. A cross-cutting aspect was not assigned because these violations were dispositioned using traditional enforcement.
perform all the required actions in the event of a fire in the Control Bay (Event 2). The
 
assessment contained a simplified time motion study that indicated the STA function
=====Enforcement:=====
could not be staffed during this event.
10 CFR 50.9(a) requires, in part, that information provided to the Commission by a licensee or information required by the statute or by the Commission's regulations, orders or license conditions to be maintained by the licensee shall be complete and accurate in all material respects.
                                                                                  Enclosure
 
TVA apparently provided information to the Commission that was not complete and accurate in all material respects as evidenced by the following examples:
* In a letter dated June 29, 2010, TVA apparently provided inaccurate information to the NRC indicating that the minimum staffing levels stated in their licensing basis were not required to achieve safe shutdown on the three-unit site during an Appendix R fire event.  "TVA has assessed the number of operators required to carry out the SSIs. The most demanding staffing is required by 0-SSI-16, "Control Building Fire EL 593 Through EL 617."  The evaluation concludes that the minimum staffing of three USs, six ROs, and eight AUOs is adequate for successful implementation of this SSI."
* In a letter dated November 30, 2011, TVA apparently provided inaccurate information to the NRC indicating that the minimum staffing levels stated in their licensing basis were not required to achieve safe shutdown on the three-unit site during an Appendix R fire event.  "-Total staffing level is one Shift Manager (SM), three Unit Supervisors (US), Six ROs, and eight AUOs. One of the US may be the STA-"
The licensee augmented on-shift staffing levels on October 30, 2013, and entered these issues into the corrective action program as PERs 790109, 790092, and 801057. These issues were preliminarily determined to be an apparent violation of 10 CFR 50.9 and pending final determination, this issue is identified as AV 05000259, 260, 296/2013005-03; Inaccurate Information Provided Concerning Onsite Emergency Response Organization Staffing Requirements.
 
(3) Inappropriate Amendment of License Conditions
 
=====Introduction:=====
The NRC identified an apparent violation (AV) of 10 CFR 50.90, Application for Amendment of License, Construction Permit, or Early Site Permit for the licensee apparent failure to submit an application requesting an amendment to their operating license concerning on-shift staffing levels.
 
=====Description:=====
On November 15, 2006, the licensee submitted license amendment requests (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) units 1, 2 and 3, respectively. The LARs were submitted as part of the restart effort associated with Unit 1. The LARs identified that the minimum staffing levels necessary to ensure safe shutdown could be achieved on the three operating units during an Appendix R fire, were 1 Shift Manager (SM), 4 Unit Supervisors (US), 6 Reactor Operators (ROs), 8 Assistant Unit Operators (AUOs), and 1 Shift Technical Advisor. The LARs indicated that the stated staffing levels were required once Unit 1 achieved Mode 2 of reactor operations, which occurred on May 21, 2007. On January 10, 2007, the licensee issued revision 7 of OPDP-1, Conduct of Operations, which decreased the required staffing levels for on-shift Unit Supervisors to 3, and allowed the STA position to be filled by one of the on-shift US. In the safety evaluation dated April 25, 2007 (ADAMS Accession No.ML 071160431), the NRC documented that the licensee conveyed to the NRC staff that the appropriate procedures had been revised to reflect the increase in staffing levels contained in the LARs. In addition, the staff's safety evaluation dated April 25, 2007 was referenced in the BFN Units 1, 2, and 3 licenses regarding the approved Fire Protection Program. On May 13, 2010, the licensee notified the Region II Regional Administrator (RA) via a conference call, that the staffing levels provided in OPDP-1 for minimum on-shift staffing did not meet the staffing levels submitted in LARs 271, 300, and 259. In a follow-up 10 CFR 50.9 letter dated June 29, 2010, the licensee informed the RA that they did not meet the requirements of their licensing basis. The licensee also stated that they had completed a staffing assessment and determined that the current minimum staffing levels contained in OPDP-1 (i.e., three US with one US filling the STA function) were adequate for successful implementation of all safe shutdown actions for the bounding Appendix R fire scenario. However, rather than apply for a license amendment, the licensee initiated a change to the staffing level requirements using NPG-SPP-03.3, NRC Commitment Management. TVA evaluated the staffing change as a regulatory commitment change and determined that NRC approval was not needed and this change should be reported to the NRC in a biennial report for the commitment changes TVA reported the required staffing change to the NRC in "Summary Report for 10 CFR 50.59 Evaluations, Fire Protection Report Technical Specification Bases Changes, Technical Requirements Manual Changes, and NRC Commitment Revision," (ADAMS Accession No. ML 11343A051) dated November 30, 2011. This decision by the licensee prevented the NRC from reviewing this change to the operating license prior to the licensee implementing the change.
 
=====Analysis:=====
The inspectors determined that the licensee's apparent failure to apply for a license amendment from the NRC was an apparent violation of 10 CFR 50.90. Had NRC reviewers been provided the correct information it would have impacted the regulatory decision making process. In addition, the NRC staff's reiteration of the staffing requirements from the November 15, 2006, LARs indicated the staff's reliance on this specific information in making their technical judgment. This apparent violation of 10 CFR 50.90 had the potential to impede or impact the regulatory process, and therefore was subject to traditional enforcement as described in the NRC Enforcement Policy, dated July 9, 2013. A cross-cutting aspect was not assigned since the violation was dispositioned using traditional enforcement.
 
=====Enforcement:=====
Title 10 CFR 50.90 requires, in part, that whenever a holder of an operating license under this part, desires to amend the license or permit, application for an amendment must be filed with the Commission, as specified in section 50.4 of this chapter, as applicable, fully describing the changes desired, and following as far as applicable, the form prescribed for original applications. From June 29, 2010, through October 30, 2013, the licensee in effect, apparently amended their operating license without filing an application for an amendment as specified in 10 CFR 50.90. Specifically, the licensee inappropriately amended the requirements for site staffing incorporated as part of license amendments 271, 300, and 259, without submission of a license amendment request. The licensee's decision to amend the staffing levels via a commitment change resulted in bypassing the review and approval that would occur as part of the licensing amendment process. The licensee augmented on-shift staffing levels on October 30, 2013, and entered this issue into the corrective action program as PERs 790109 and 801057. The failure to apply for a license amendment was preliminarily determined to be an apparent violation of 10 CFR 50.90 and, pending final determination, this issue is identified as AV 05000259, 260, 296/2013005-04; Inappropriate Amendment of License Conditions.
 
===.3 Annual Licensed Operator Requalification Review===
 
====a. Inspection Scope====
Annual Review of Licensee Requalification Examination Results:  On December 31, 2013, the licensee completed the annual requalification operating examinations required to be administered to all licensed operators in accordance with Title 10 of the Code of Federal Regulations 55.59(a)(2), "Requalification requirements," of the NRC's "Operators' Licenses."  The inspector performed an in-office review of the overall pass/fail results of the individual operating examinations and the crew simulator operating examinations in accordance with Inspection Procedure (IP) 71111.11, "Licensed Operator Requalification Program and Licensed Operator Performance."  The results were compared to the thresholds established in Section 3.02, "Requalification Examination Results," of IP 71111.11.
 
====b. Findings====
No findings were identified.
{{a|1R12}}
==1R12 Maintenance Effectiveness==
 
===.1 Routine===
 
====a. Inspection Scope====
The inspectors reviewed the specific structures, systems and components (SSCs) within the scope of the Maintenance Rule (MR) (10 CFR 50.65) 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) Tracking 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 10 CFR 50.65(a)(1) goals, monitoring and corrective actions (i.e., Ten Point Plan). The inspectors also compared the licensee's performance against site procedures. The inspectors also reviewed, as applicable, WOs, SRs, 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. This activity constituted three Maintenance Effectiveness inspection samples.
 
Documents reviewed are listed in the Attachment.
* Unit 1, 2, and 3 control air system shift to (a)(1) status
* Unit 1, 2, and 3 residual heat removal (RHR) and RHRSW Systems evaluation of Heat Exchanger Asiatic Clam fouling
* Unit 1, 2, and 3 Control Bay Chillers and associated (a)(1) plan effectiveness
 
====b. Findings====
No findings were identified.
{{a|1R13}}
==1R13 Maintenance Risk Assessments and Emergent Work Control==
 
====a. Inspection Scope====
For planned online work and/or emergent work that affected the combinations of risk significant systems listed below, the inspectors examined four on-line 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 (RMAs) were conducted as required by 10 CFR 50.65(a)(4) applicable plant procedures. Furthermore, as applicable, the inspectors verified the actual in-plant configurations to ensure accuracy of the licensee's risk assessments and adequacy of RMA implementations. This activity constituted four Maintenance Risk Assessment inspection samples. Documents reviewed are listed in the Attachment.
* October 2, 2013, Units 1/2 'D' EDG, Unit 2 RCIC, Unit Common 'C' Emergency Equipment Cooling Water Strainer, and 161kV Trinity Line Out of Service
* October 23, 2013, Unit 3 Yellow Risk Status, 500kV Switchyard Maintenance (with loss of offsite power multiplier input), Unit 2 Main Bank Battery (respective Unit 3 RMOV boards control power to alternate), B1 RHRSW Pump, and G Control Air Compressor Out of Service
* October 30, 2013, Unit 3, '3A' EDG, '3A' RHR pump and heat exchanger, RCIC, common system 'A' RHRSW header, 'A1' and 'A2' RHRSW pumps, and G Control Air Compressor Out of Service
* November 13, 2013, Unit 1, 1A Control Rod Drive pump replacement required a lift over the Loop II CS subsystem. The Loop II CS was placed out of service as a preventative measure for the lift. D1 and D2 RHRSW pumps, G Control Air Compressor, 1A Component Cooling Water pump, and the C3 Emergency Equipment Cooling Water pump strainer Out of Service; (This also constitutes a Smart Sample per OpESS 2007-03 for the Control of Heavy Loads)
 
====b. Findings====
No findings were identified.
{{a|1R15}}
==1R15 Operability Determinations and Functionality Assessments==
 
====a. Inspection Scope====
The inspectors reviewed the 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 procedures to ensure that the licensee's evaluation met procedure requirements. 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 reviewed PERs on a daily basis to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. This activity constituted five Operability Evaluation inspection samples. Documents reviewed are listed in the
.
* Unit 1/2, 'B' 4kv shutdown board while 'B' EDG feeder breaker was racked to test with a wooden seismic device, (WO number 05-715371)
* Unit 3, '3D' EDG did not meet acceptance criteria for a pole drop test, (PER 732970)
* RHRSW Pump Seismic Restraints (PERs 794671, 796311, 798502) * '3D' EDG Heat Exchanger Fouling (PER 782689)
* Average Power Range Monitor Voter Relay Logic Module failures under 10 CFR Part 21 (PER 818017)
 
====b. Findings====
No findings were identified.
{{a|1R18}}
==1R18 Plant Modifications==
 
===.1 Permanent Plant Modifications===
 
====a. Inspection Scope====
The inspectors reviewed the Design Change Notice (DCN) and completed work package (WOs 113899709 and 113900042) for DCN 70752 to Eliminate Fault Propagation on 4kV Breakers, including related documents and procedures. The inspectors reviewed licensee procedures NPG-SPP-09.3, Plant Modifications and Engineering Change Control, and NPG-SPP-06.9.3, Post-Modification Testing, and observed part of the licensee's activities to implement this design change made while the unit was online.
 
The inspectors reviewed the associated 10 CFR 50.59 screening against the system design bases documentation to verify that the modifications had not affected system operability/availability. The inspectors reviewed selected ongoing and completed work activities to verify that installation was consistent with the design control documents.
 
This activity constituted one Permanent Plant Modification sample. Documents reviewed are listed in the Attachment.
 
====b. Findings====
No findings were identified.
{{a|1R19}}
==1R19 Post Maintenance Testing==
 
====a. Inspection Scope====
The inspectors witnessed and reviewed post-maintenance tests (PMTs) listed below to verify that procedures and test activities confirmed SSC operability and functional capability following the described maintenance. The inspectors reviewed the licensee's 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 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 licensee procedural requirements. Furthermore, the inspectors verified that problems associated with PMTs were identified and entered into the CAP. This activity constituted four Post Maintenance Test inspection samples. Documents reviewed are listed in the
.
* October 16, 2013, CS, Division II Breaker Testing following DCN 70752 to Eliminate Fault Propagation (WOs 113899709 and 113900042)
* November 8, 2013, '3A' EDG, 3-SR-3.8.1.1(3A), Monthly Operability Test Following Lube Oil Modifications (WO 114395126)
* November 13, 2013, Unit 2 RCIC digital flow controller test following replacement (WO 115269495)
* November 25, 2013, 'A' EDG, 0-SR-3.8.1.1(A), Monthly Operability Test (WO 114456082) Following Fuel Oil Line Repairs (WO 115302820)
 
====b. Findings====
No findings were identified.
 
==OTHER ACTIVITIES==
{{a|4OA1}}
==4OA1 Performance Indicator (PI) Verification==
 
===.1 Cornerstone:===
Initiating Events
 
====a. Inspection Scope====
The inspectors reviewed the licensee's procedures and methods for compiling and reporting the following Performance Indicators (PIs). The inspectors examined the licensee's PI data for the specific PIs listed below for the fourth quarter 2012 through third quarter of 2013. The inspectors reviewed the licensee's data and graphical representations as reported to the NRC to verify that the data was correctly reported. The inspectors also 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 verified that the PI data was appropriately captured, calculated correctly, and discrepancies resolved. The inspectors used the Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, to ensure that industry reporting guidelines were appropriately applied. This activity constituted nine Performance Indicator inspection samples. Documents reviewed are listed in the
.
* Unit 1, 2, and 3 Unplanned Scrams
* Unit 1, 2, and 3 Unplanned Scrams with Complications
* Unit 1, 2, and 3 Unplanned Power Changes
 
====b. Findings====
No findings were identified.
 
{{a|4OA2}}
==4OA2 Problem Identification and Resolution==
 
===.1 Review of items entered into the Corrective Action Program:===
As required by Inspection Procedure 71152, "Problem Identification and Resolution," 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 licensee's CAP. This review was accomplished by reviewing daily PER and SR reports, and periodically attending Corrective Action Review Board (CARB) and PER Screening Committee (PSC) meetings.
 
===.2 Semi-annual Trend Review:===
 
====a. Inspection Scope====
As required by Inspection Procedure 71152, the inspectors performed a review of the licensee's CAP and other associated programs and documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors' review was focused on repetitive equipment issues, but also included licensee trending efforts and licensee human performance results. The inspectors' review nominally considered the six-month period of July through December 2013, although some examples expanded beyond those dates when the scope of the trend warranted. The inspectors reviewed licensee trend reports for the period in order to determine the existence of any adverse trends that the licensee may not have previously identified. The inspectors' review also included the Integrated Trend Reports from April 1, 2013, to September 30, 2013. The inspectors verified that adverse or negative trends identified in the licensee's PERs, periodic reports, and trending efforts were entered into the CAP. This inspection constituted one Semi-annual Trend Review inspection sample. Documents reviewed are listed in the Attachment.
 
====b. Observations and Findings====
No findings were identified. In general, the licensee had identified trends and appropriately addressed them in their CAP. The inspectors observed that the licensee had performed a detailed review. The licensee routinely reviewed cause codes, involved organizations, key words, and system links to identify potential trends in their data. The inspectors compared the licensee process results with the results of the inspectors' daily screening. Trends that have been identified by the inspectors and reported to the licensee were appropriately entered into the licensee's trending program and the CAP. These trends included the following:
* Challenges to operability of the RHR heat exchangers due to Asiatic clam fouling
* Secondary plant systems challenging continued operation at 100 percent power and causing plant trips
* Control of transient combustible material in safety-related areas of the plant
 
===.3 Focused Annual Sample Review:===
 
====a. Inspection Scope====
The inspectors conducted a review of licensee maintenance of floor drain systems in the diesel buildings and reactor buildings with a focus on the preventative maintenance practices and design of the drains with respect to impact on CO2 actuation on a fire. This inspection constituted one Focused Annual Review inspection sample. Documents reviewed are listed in the Attachment.
 
====b. Observations and Findings====
The inspectors noted that licensee preventative maintenance frequency for maintaining plant drains was not identifying a trend of excessive debris on the as-found inspection.
 
Some plant areas did not have an assigned preventative maintenance task.
 
Additionally, the inspectors noted that the drains in the diesel rooms would allow CO2 concentrations to be diluted on any actuation into the adjacent corridor's floor drain sump.
 
=====Introduction:=====
The NRC identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensee's failure to establish design control measures ensure the capabilities of the 'B' EDG room floor drains.
 
=====Description:=====
On August 13, 2013, NRC inspectors identified significantly clogged floor drains in the 'B' EDG room. Per Browns Ferry Civil Design Criteria BFN-50-C-7105, Low Energy Piping Evaluation Requirements, the two floor drains installed in the EDG room were required to remove at least 135 gallons per minute (gpm) of water to sumps outside the room. The Browns Ferry Engineering staff reviewed the condition and concluded that the 'B' EDG was inoperable as the drains were incapable of removing flow. Subsequently, NRC inspectors observed licensee staff members dumping debris and dirty water down the '3D' EDG room drains. Despite observed fouling of the drains, licensee staff failed to recognize this as a condition adverse to quality and initiate SR's to address the condition. The inspectors determined that there were no preventative maintenance tasks or periodic testing to ensure the drain capability for the eight EDG rooms. Other plant rooms have a 26 week frequency preventative maintenance task to ensure the design drain capabilities were maintained.
 
The Browns Ferry EDG room internal flood mitigation strategy is to have the outside sump level alarm alert operators once the sump becomes full. The sump pumps are maintained in an "off" condition at the Browns Ferry plant. With the floor drains clogged, operator action would be delayed because the sump could not receive 135 gpm flood water through the drain piping. The licensee re-evaluated the 'B' EDG drain conditions one month later and determined the drains were only 90 percent and 45 percent clogged on August 13, 2013. This would have allowed the drain water to slowly fill the sump.
 
Based on sufficient operator response time, the 'B' EDG was determined to remain operable. The licensee's immediate corrective action was to clean all the drains in all the EDG rooms.
 
=====Analysis:=====
The inspectors determined that the licensee's failure to establish measures to assure the regulatory requirements and design basis of structures, systems, and components were correctly translated into procedures and instructions in accordance with 10 CFR 50, Appendix B, Criterion III, Design Control, was a performance deficiency that was reasonably within TVA's ability to foresee and prevent. Specifically, no measures were established to ensure the EDG floor drains maintained capability of performing their intended functions as described in the design basis. The finding was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the EDG room floor drains could become sufficiently clogged such that internal flooding would cause the affected EDG to be unable to perform its safety function. The inspectors performed a Phase 1 screening in accordance with IMC 0609, Significance Determination Process, Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding was of very low safety significance (Green) because it did not impact the frequency of an internal flooding event. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program Component, because TVA did not identify issues completely, accurately, and in a timely manner commensurate with their safety significance. Specifically, TVA did not identify that workers were challenging the drains design feature by routinely dumping dirty water and debris into the floor drains without a mechanism to verify the resultant capability of the drains. [P.1(a)]
 
=====Enforcement:=====
10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure the regulatory requirements and design basis of structures, systems, and components are correctly translated into procedures and instructions. Contrary to the above, prior to August 13, 2013, the Tennessee Valley Authority (TVA) did not correctly translate the design basis of the EDG floor drains into procedures and instructions and therefore no measures were established to ensure the EDG floor drains maintained capability of performing their intended function as described in their design basis. The licensee's immediate corrective action was to clean all the drains in all the EDG rooms thus verifying capability of the drains. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as PER 765575.
 
(NCV 05000259/2013005-05, Failure to Maintain Emergency Diesel Room Floor Drains)
{{a|4OA3}}
==4OA3 Follow-up of Events and Notices of Enforcement Discretion==
 
===.1 (Closed) Licensee Event Report (LER) 05000259/2009-002-01, Unexpected Logic Lockout of the Loop II Residual Heat Removal (RHR) System Pumps===
 
====a. Inspection Scope====
The inspectors reviewed LER 05000259/2009-002-01 dated September 27, 2013. The licensee event report was reviewed based on the changes that were made to the original report. The changes documented concurrent inoperability of systems described in other LERs. These systems included the Loop II of the RHR system (due to the failure of      1-FCV-74-66) and the RHR pump 1C (due to a rotor/shaft bow). All the other system operability issues were previously adjudicated in Browns Ferry inspection report 05000259, 260, 296/2010002 (ADAMS Accession No. ML101200508). This LER is closed.
 
====b. Findings====
No findings were identified.
 
===.2 (Closed) Licensee Event Report (LER) 05000259/2009-004-01, High Pressure Core Injection Found Inoperable During Condensate Header Level Switch Calibration and Functional Test===
 
====a. Inspection Scope====
The inspectors reviewed LER 05000259/2009-004-01 dated September 27, 2013. The licensee event report was reviewed based on the changes that were made to the previous report. The changes documented concurrent inoperability of systems described in other LERs. These systems included the Loop II of the RHR system (due to the failure of 1-FCV-74-66) and the RHR pump 1C (due to a rotor/shaft bow). All the other system operability issues were previously addressed in Browns Ferry inspection report 05000259, 260, 296/2009005 (ADAMS Accession No. ML100331517). This LER is closed.
 
====b. Findings====
No findings were identified.
 
===.3 (Closed) Licensee Event Report (LER) 05000259/2010-003-03, Failure of a Low Pressure Coolant Injection Flow Control Valve===
 
====a. Inspection Scope====
The inspectors reviewed LER 05000259/2010-003-03 dated September 30, 2013. The licensee event report was reviewed based on the changes that were made to the previous reports. The changes documented concurrent inoperability of systems described in other LERs and systems that were inoperable due to maintenance for periods of time less than the allowed limit. All system operability issues were previously addressed in Browns Ferry inspection reports 05000259/2011008 (ADAMS Accession No. ML111290500) and 05000259, 260, 296/2012002 (ADAMS Accession No. ML12121A507). This LER is closed.
 
====b. Findings====
No findings were identified.
 
===.4 (Closed) Licensee Event Report (LER) 05000259, 260, 296/2011-003-02, Loss of Safety Function (SDC) Resulting from Emergency Diesel Generator Output Breaker Trip===
 
====a. Inspection Scope====
The inspectors reviewed LER 05000259, 260, 296/2011-003-02 dated September 30, 2013, and all previous revisions. The licensee event report was reviewed based on the changes that were made to the previous reports. The key change was the documentation of the inoperability of the Diesel Generator based on the failure of the Overspeed Trip Limit Switch (OTLS). The previous revision did not include the total inoperability time. This issue was previously addressed in Browns Ferry Inspection reports 05000259, 260, 296/2011004 (ADAMS Accession No. ML113180503) and 05000259, 260, 296/2011005 (ADAMS Accession No. ML12045A063). This LER is closed.
 
====b. Findings====
No findings were identified.
 
===.5 (Closed) Licensee Event Report (LER) 05000259/2011-009-03, As-Found Undervoltage Trip for the Reactor Protection System 1A1 Relay that Did Not Meet Acceptance Criteria During Several Surveillances===
 
====a. Inspection Scope====
The inspectors reviewed LER 05000259/2011-009-03 dated July 29, 2013. The licensee event report was reviewed based on the changes that were made to the previous reports. The changes documented additional similar failures and a change to the causal factors. Standing order 174 was issued to establish Operations department expectations when as-found data is found outside of acceptable regulatory guidelines.
 
The RPS 1A1 relay and 3C1 relay were replaced. This issue was previously addressed in Browns Ferry Inspection reports 05000259, 260, 296/2012002 (ADAMS Accession No. ML12121A507) and 05000259, 260, 296/2012003 (ADAMS Accession No.
 
ML12227A711). Section
{{a|4OA7}}
==4OA7 of Inspection Report 2012-002 addressed the associated licensee identified violation.==
No additional findings were identified. This LER is closed.
 
====b. Findings====
No findings were identified.
 
===.6 (Closed) Licensee Event Report (LER) 05000296/2013-001-00 and 01, Inoperable Emergency Diesel Generator due to Failed Electric Generator Casing Fan Bearing===
 
====a. Inspection Scope====
The inspectors reviewed the LER, dated March 11, 2013, and May 10, 2013, and the associated PER 665217, including the root cause analysis, operability determinations, and corrective action plans. On January 9, 2013, while performing operator rounds near the Unit 3, 3D Emergency Diesel Generator (EDG), the licensee discovered metal residue and grease around the generator blower shaft. The licensee determined the generator blower inboard bearing (coupling side) had failed during a previous post maintenance test, as verified by licensee vibration data, rendering the 3D EDG inoperable. Following return to service of the 3D EDG and extent-of-condition inspections, the licensee determined that two additional Unit 3 EDGs had blower bearings that were degraded but not failed, and were also determined to be inoperable. The licensee concluded that the direct cause of the 3D EDG bearing failure was the absence of lubrication to the internal parts of the EDG blower bearing due to age related breakdown of the grease. The licensee determined two root causes to be inadequate component level assessment of the blower shielded bearings for failure modes and impacts and ineffective industry vibration monitoring standards. All four Unit 3 EDG generator blower bearings were replaced.
 
====b. Findings====
The enforcement aspects of this finding are discussed in Section 4OA7. This LER and its revision are closed.
 
===.7 (Closed) Licensee Event Report (LER) 05000259/2013-006-00, 1B Standby Liquid Control Pump Inoperable for Longer than Allowed by Technical Specifications===
 
====a. Inspection Scope====
The inspectors reviewed LER 05000259/2013-006-00 dated December 3, 2013. A licensee past operability review determined that 1B Standby Liquid Control pump was inoperable from December 1, 2012, to February 14, 2013, due to a piece of the motor breaker's arc chute that had become dislodged and re-located to between the breaker contacts. This LER is closed.
 
====b. Findings====
 
=====Introduction.=====
A Severity Level IV Non-Cited violation of 10 CFR 50.73(a)(2)(i)(B) was identified by the inspectors for the licensee's failure to submit a License Event Report (LER) within 60 days of a reportable event .
 
=====Description.=====
On September 26, 2013, in response to NRC inspector questioning, the licensee reevaluated the past operability results of the failure of the 1B Standby Liquid Control (SLC) pump which occurred on Feb 13, 2013. Following the reevaluation, a revision to the PER 618667 past operability evaluation was made which concluded the 1B SLC pump would not have been able to meet its mission time from December 1, 2012 to February 14, 2013 (74 days). The licensing staff also identified that 1A SLC pump had been out of service for accumulator repairs during the time period that 1B SLC pump was inoperable. Thus the failure was reportable as both a condition prohibited by technical specifications and a loss of system safety function. PER 796578 was initiated with an immediate corrective action to generate a LER. LER 50-259 2013-006-00 was submitted on December 3, 2013.
 
=====Analysis.=====
The inspectors determined that the failure to submit a License Event Report (LER) within 60 days of a reportable event was a violation of the requirements of 10 CFR 50.73(a)(2)(i)(B). This violation had the potential to impede or impact the regulatory process, and therefore subject to traditional enforcement as described in the NRC Enforcement Policy, dated July 9, 2013. The inspectors used the examples provided in Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required Report, of the NRC Enforcement Policy to determine the severity level (SL). Based on the wording of example 9 under the examples for SL IV violations, the inspectors determined that this violation should be characterized as a SL IV violation. Example 9 states "A licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73". A cross-cutting aspect was not assigned because the violation was dispositioned using traditional enforcement.
 
=====Enforcement.=====
10 CFR 50.73(a)(2)(i)(B) required, in part, that licensees report any conditions prohibited by plant technical specifications within 60 days via a License Event Report. Contrary to the above, from April 14, 2013, through December 3, 2013, the licensee did not report within 60 days the failure to comply with Condition A of Technical Specification 3.1.7 after the February 13, 2013, 1B SLC pump breaker failure. This issue was documented in the licensee's corrective action program as Problem Evaluation Reports 796578 and 817510. Corrective actions included reporting the conditions in LER 050000- 259/2013-06-00. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as PER 796578.  (NCV 05000259/2013005-06, [Failure to report a condition prohibited by Technical Specifications.])
 
===.8 (Closed) Licensee Event Report (LER) 050000260/2012-006-01, Automatic Reactor Scram Due to Loss of Power to the Reactor Protection System===
 
====a. Inspection Scope====
On December 22, 2012, Unit 2 automatically scrammed from approximately 100 percent power due to loss of power to both RPS buses. The 4kV Shutdown Board D had de-energized during testing of the emergency diesel generators which resulted in a loss of the RPS Bus 2B. While attempting to re-energize the RPS Bus 2B, a procedural error resulted in de-energizing the RPS Bus 2A which resulted in a reactor scram and closure of the main steam isolation valves.
 
The original LER 05000260/2012-006-00, dated February 20, 2013, and applicable PER 660862, were reviewed by the inspectors and documented in Section 4OA3.3 of NRC IR 05000260/2013002 (ADAMS Accession No. ML13134A237), where a self-revealing apparent violation (AV) of Technical Specification 5.4.1 was identified for the licensee's failure to properly implement procedure 2-OI-99, Reactor Protection System. The finding was determined to have a low to moderate safety significance (white) and a notice of violation was issued to Browns Ferry for this event in NRC IR 05000260/2013013 (ADAMS Accession No. ML13235A058).
 
The inspectors reviewed Revision 1 of the LER dated December 6, 2013, and applicable PER 740259, including the revised cause determination and corrective action plans. This revised LER was submitted to provide the results of the licensee's completed investigation and revised causal analysis. The inspectors verified that the supplemental information provided in the revised LER was complete and accurate. No additional licensee significant performance deficiencies were identified by the inspectors. This LER is closed
 
====b. Findings====
No additional findings were identified..
{{a|4OA5}}
==4OA5 Other Activities==
 
===.1 Operation of an Independent Spent Fuel Storage Installation (ISFSI)===
{{IP sample|IP=IP 60855}}
 
====a. Inspection Scope====
Under the guidance of IP 60855.1, the inspectors observed operations involving spent fuel transfer and storage for dry cask campaign number seven. Inspectors interviewed personnel and reviewed the licensee's documentation regarding storing spent fuel to verify that these independent spent fuel storage installation (ISFSI) related programs and procedures fulfill the commitments and requirements specified in the Safety Analysis Report (SAR), Certificate of Compliance (CoC), 10 CFR Part 72, and the Technical Specifications. Specifically one year of related 10 CFR 72.48 evaluations, 10 CFR 72.212(b) evaluations, and lid welding records associated with multi-purpose canisters (MPC) S/N 0326 and S/N 0330 were reviewed. The inspectors conducted independent ISFSI related activities to ensure that the licensee performed spent fuel loading and transport in a safe manner. Inspectors performed focused operational reviews on new methodologies concerning forced helium dehydration and supplemental cooling.
 
Inspectors attended briefings and observed operations in the field including overall supervisory involvement, coordination, and oversight of ISFSI-related work activities. The inspectors reviewed the fuel loading plan for MPC-0326 and verified that the fuel assemblies were properly selected and loaded in accordance with characterization documents and approved procedures. The inspectors verified that selected individuals had received the necessary training in accordance with approved procedures for their ISFSI-related job duties.
 
The inspectors reviewed work orders, completed procedures, logs, welding records, inspection records, qualification records, and overall guidelines for MPC-0326 ISFSI activities. The inspectors determined that the licensee had established, maintained, and implemented adequate control of dry cask processing operations, including loading, transportation, and storage per approved procedures and technical specification requirements. Records of spent fuel stored at the facility were properly maintained.
 
====b. Findings and Observations====
No findings were identified.
 
===.2 (Closed) Temporary Instruction 2515/182 - Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks===
 
====a. Inspection Scope====
The inspectors conducted a review of records and procedures related to the licensee's program for buried piping and underground piping and tanks in accordance with Phase II of temporary instruction (TI) 2515-182 to confirm that the licensee's program contained attributes consistent with Sections 3.3.A and 3.3.B of Nuclear Energy Institute (NEI) 09-14, "Guideline for the Management of Buried Piping Integrity,"
Revision 3, and to confirm that these attributes were scheduled and/or completed by the NEI 09-14 Revision 3 deadlines. The inspectors interviewed licensee staff responsible for the buried piping program and reviewed activities related to the buried piping program to determine if the program was managed in a manner consistent with the industry's buried piping initiative. The licensee's buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of the TI and it was confirmed that activities which correspond to completion dates specified in the program which have passed since the Phase 1 inspection was conducted, have been completed. The licensee's buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the TI and responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to the NRC headquarters staff.
 
====b. Findings====
No findings were identified. Based upon the scope of the review described above, Phase II of TI-2515/182 was completed.
 
===.3 Quarterly Resident Inspector Observations of Security Personnel and Activities===


====a. Inspection Scope====
                                      16
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.
On November 6, 2013, and in follow-up letter dated December 6, 2013, the licensee
informed the Region II RA in accordance with 10 CFR 50.9(b), that TVA had inaccurately
reported information regarding the required shift staffing for three-unit operation as
originally submitted in LARs 271, 300, and 259. The inspectors determined that on
multiple occasions the information provided to the NRC detailing required staffing levels
was not complete and accurate in all material respects.
Analysis: The inspectors determined that the licensees apparent failure to provide
complete and accurate information to the NRC were apparent violations of the
requirements of 10 CFR 50.9, Completeness and Accuracy of Information. These
apparent violations had the potential to impede or impact the regulatory process, and
therefore are subject to traditional enforcement as described in the NRC Enforcement
Policy, dated July 9, 2013. A cross-cutting aspect was not assigned because these
violations were dispositioned using traditional enforcement.
Enforcement: 10 CFR 50.9(a) requires, in part, that information provided to the
Commission by a licensee or information required by the statute or by the Commissions
regulations, orders or license conditions to be maintained by the licensee shall be
complete and accurate in all material respects.
TVA apparently provided information to the Commission that was not complete and
accurate in all material respects as evidenced by the following examples:
*  In a letter dated June 29, 2010, TVA apparently provided inaccurate information to
    the NRC indicating that the minimum staffing levels stated in their licensing basis
    were not required to achieve safe shutdown on the three-unit site during an Appendix
    R fire event.
    TVA has assessed the number of operators required to carry out the SSIs. The
    most demanding staffing is required by 0-SSI-16, "Control Building Fire EL 593
    Through EL 617." The evaluation concludes that the minimum staffing of three USs,
    six ROs, and eight AUOs is adequate for successful implementation of this SSI.
*  In a letter dated November 30, 2011, TVA apparently provided inaccurate
    information to the NRC indicating that the minimum staffing levels stated in their
    licensing basis were not required to achieve safe shutdown on the three-unit site
    during an Appendix R fire event.
    Total staffing level is one Shift Manager (SM), three Unit Supervisors (US), Six
    ROs, and eight AUOs. One of the US may be the STA
The licensee augmented on-shift staffing levels on October 30, 2013, and entered these
issues into the corrective action program as PERs 790109, 790092, and 801057. These
issues were preliminarily determined to be an apparent violation of 10 CFR 50.9 and
pending final determination, this issue is identified as AV 05000259, 260, 296/2013005-
03; Inaccurate Information Provided Concerning Onsite Emergency Response
Organization Staffing Requirements.
                                                                                  Enclosure


These observations took place during both normal and off-normal plant working hours.
                                          17
(3) Inappropriate Amendment of License Conditions
    Introduction: The NRC identified an apparent violation (AV) of 10 CFR 50.90,
    Application for Amendment of License, Construction Permit, or Early Site Permit for the
    licensee apparent failure to submit an application requesting an amendment to their
    operating license concerning on-shift staffing levels.
    Description: On November 15, 2006, the licensee submitted license amendment
    requests (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) units 1, 2 and 3,
    respectively. The LARs were submitted as part of the restart effort associated with Unit
    1. The LARs identified that the minimum staffing levels necessary to ensure safe
    shutdown could be achieved on the three operating units during an Appendix R fire,
    were 1 Shift Manager (SM), 4 Unit Supervisors (US), 6 Reactor Operators (ROs), 8
    Assistant Unit Operators (AUOs), and 1 Shift Technical Advisor. The LARs indicated
    that the stated staffing levels were required once Unit 1 achieved Mode 2 of reactor
    operations, which occurred on May 21, 2007. On January 10, 2007, the licensee issued
    revision 7 of OPDP-1, Conduct of Operations, which decreased the required staffing
    levels for on-shift Unit Supervisors to 3, and allowed the STA position to be filled by one
    of the on-shift US. In the safety evaluation dated April 25, 2007 (ADAMS Accession
    No.ML 071160431), the NRC documented that the licensee conveyed to the NRC staff
    that the appropriate procedures had been revised to reflect the increase in staffing levels
    contained in the LARs. In addition, the staffs safety evaluation dated April 25, 2007 was
    referenced in the BFN Units 1, 2, and 3 licenses regarding the approved Fire Protection
    Program.
    On May 13, 2010, the licensee notified the Region II Regional Administrator (RA) via a
    conference call, that the staffing levels provided in OPDP-1 for minimum on-shift staffing
    did not meet the staffing levels submitted in LARs 271, 300, and 259. In a follow-up 10
    CFR 50.9 letter dated June 29, 2010, the licensee informed the RA that they did not
    meet the requirements of their licensing basis. The licensee also stated that they had
    completed a staffing assessment and determined that the current minimum staffing
    levels contained in OPDP-1 (i.e., three US with one US filling the STA function) were
    adequate for successful implementation of all safe shutdown actions for the bounding
    Appendix R fire scenario. However, rather than apply for a license amendment, the
    licensee initiated a change to the staffing level requirements using NPG-SPP-03.3, NRC
    Commitment Management. TVA evaluated the staffing change as a regulatory
    commitment change and determined that NRC approval was not needed and this
    change should be reported to the NRC in a biennial report for the commitment changes
    TVA reported the required staffing change to the NRC in Summary Report for 10 CFR
    50.59 Evaluations, Fire Protection Report Technical Specification Bases Changes,
    Technical Requirements Manual Changes, and NRC Commitment Revision, (ADAMS
    Accession No. ML 11343A051) dated November 30, 2011. This decision by the licensee
    prevented the NRC from reviewing this change to the operating license prior to the
    licensee implementing the change.
    Analysis: The inspectors determined that the licensees apparent failure to apply for a
    license amendment from the NRC was an apparent violation of 10 CFR 50.90. Had
    NRC reviewers been provided the correct information it would have impacted the
                                                                                      Enclosure


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.
                                            18
      regulatory decision making process. In addition, the NRC staffs reiteration of the
      staffing requirements from the November 15, 2006, LARs indicated the staffs reliance
      on this specific information in making their technical judgment. This apparent violation of
      10 CFR 50.90 had the potential to impede or impact the regulatory process, and
      therefore was subject to traditional enforcement as described in the NRC Enforcement
      Policy, dated July 9, 2013. A cross-cutting aspect was not assigned since the violation
      was dispositioned using traditional enforcement.
      Enforcement: Title 10 CFR 50.90 requires, in part, that whenever a holder of an
      operating license under this part, desires to amend the license or permit, application for
      an amendment must be filed with the Commission, as specified in section 50.4 of this
      chapter, as applicable, fully describing the changes desired, and following as far as
      applicable, the form prescribed for original applications.
      From June 29, 2010, through October 30, 2013, the licensee in effect, apparently
      amended their operating license without filing an application for an amendment as
      specified in 10 CFR 50.90. Specifically, the licensee inappropriately amended the
      requirements for site staffing incorporated as part of license amendments 271, 300, and
      259, without submission of a license amendment request. The licensees decision to
      amend the staffing levels via a commitment change resulted in bypassing the review and
      approval that would occur as part of the licensing amendment process.
      The licensee augmented on-shift staffing levels on October 30, 2013, and entered this
      issue into the corrective action program as PERs 790109 and 801057. The failure to
      apply for a license amendment was preliminarily determined to be an apparent violation
      of 10 CFR 50.90 and, pending final determination, this issue is identified as AV
      05000259, 260, 296/2013005-04; Inappropriate Amendment of License Conditions.
.3    Annual Licensed Operator Requalification Review
  a. Inspection Scope
      Annual Review of Licensee Requalification Examination Results: On December 31,
      2013, the licensee completed the annual requalification operating examinations required
      to be administered to all licensed operators in accordance with Title 10 of the Code of
      Federal Regulations 55.59(a)(2), Requalification requirements, of the NRCs
      Operators Licenses. The inspector performed an in-office review of the overall
      pass/fail results of the individual operating examinations and the crew simulator
      operating examinations in accordance with Inspection Procedure (IP) 71111.11,
      Licensed Operator Requalification Program and Licensed Operator Performance. The
      results were compared to the thresholds established in Section 3.02, Requalification
      Examination Results, of IP 71111.11.
  b. Findings
      No findings were identified.
                                                                                      Enclosure


====b. Findings====
                                            19
No findings were identified
1R12 Maintenance Effectiveness
{{a|4OA6}}
.1    Routine
==4OA6 Meetings, Including Exit==
  a. Inspection Scope
On January 10, and 21, 2014, the resident inspectors presented the quarterly inspection results to Mr. Steve Bono, Plant Manager, and other members of the licensee's staff, who acknowledged the findings. The inspectors verified that all proprietary information was returned to the licensee.  
      The inspectors reviewed the specific structures, systems and components (SSCs) within
{{a|4OA7}}
      the scope of the Maintenance Rule (MR) (10 CFR 50.65) with regard to some or all of
==4OA7 Licensee-Identified Violations==
      the following attributes, as applicable: 1) Appropriate work practices; 2) Identifying and
The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.
      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) Tracking
      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 10 CFR 50.65(a)(1) goals, monitoring and corrective actions (i.e., Ten
      Point Plan). The inspectors also compared the licensees performance against site
      procedures. The inspectors also reviewed, as applicable, WOs, SRs, 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.
      This activity constituted three Maintenance Effectiveness inspection samples.
      Documents reviewed are listed in the Attachment.
      *  Unit 1, 2, and 3 control air system shift to (a)(1) status
      *  Unit 1, 2, and 3 residual heat removal (RHR) and RHRSW Systems evaluation of
          Heat Exchanger Asiatic Clam fouling
      *  Unit 1, 2, and 3 Control Bay Chillers and associated (a)(1) plan effectiveness
  b. Findings
      No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
  a. Inspection Scope
      For planned online work and/or emergent work that affected the combinations of risk
      significant systems listed below, the inspectors examined four on-line 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 (RMAs) were conducted as required by 10 CFR 50.65(a)(4)
      applicable plant procedures. Furthermore, as applicable, the inspectors verified the
      actual in-plant configurations to ensure accuracy of the licensees risk assessments and
      adequacy of RMA implementations. This activity constituted four Maintenance Risk
      Assessment inspection samples. Documents reviewed are listed in the Attachment.
                                                                                        Enclosure


Unit 3 Technical Specification 3.3.8.1, AC Sources - Operating, required EDGs to be operable in Modes 1, 2, and 3, and with multiple EDGs inoperable, required all but one EDG be returned to service in 2 hours or be in Mode 3 within 12 hours and in Mode 4 within 36 hours. Contrary to this, between December 22, 2012, and January 9, 2013, the licensee determined that multiple EDGs were inoperable as a result of failed 3D EDG and degraded 3A and 3B EDG generator blower bearings. This TS violation was entered into the licensee's CAP as PERs 665217, 675339, and 675952. This finding represented an actual loss of function of the 3D EDG for greater than the TS allowed outage time, and therefore, required a detailed risk evaluation. Because of the short exposure time related to the performance deficiency, the finding was determined to be of very low safety significance (Green).
                                            20
    *  October 2, 2013, Units 1/2 D EDG, Unit 2 RCIC, Unit Common C Emergency
        Equipment Cooling Water Strainer, and 161kV Trinity Line Out of Service
    *  October 23, 2013, Unit 3 Yellow Risk Status, 500kV Switchyard Maintenance (with
        loss of offsite power multiplier input), Unit 2 Main Bank Battery (respective Unit 3
        RMOV boards control power to alternate), B1 RHRSW Pump, and G Control Air
        Compressor Out of Service
    *  October 30, 2013, Unit 3, 3A EDG, 3A RHR pump and heat exchanger, RCIC,
        common system A RHRSW header, A1 and A2 RHRSW pumps, and G Control
        Air Compressor Out of Service
    *  November 13, 2013, Unit 1, 1A Control Rod Drive pump replacement required a lift
        over the Loop II CS subsystem. The Loop II CS was placed out of service as a
        preventative measure for the lift. D1 and D2 RHRSW pumps, G Control Air
        Compressor, 1A Component Cooling Water pump, and the C3 Emergency
        Equipment Cooling Water pump strainer Out of Service; (This also constitutes a
        Smart Sample per OpESS 2007-03 for the Control of Heavy Loads)
b.  Findings
    No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a.  Inspection Scope
    The inspectors reviewed the 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 procedures to ensure that
    the licensees evaluation met procedure requirements. 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
    reviewed PERs on a daily basis to verify that the licensee was identifying and correcting
    any deficiencies associated with operability evaluations. This activity constituted five
    Operability Evaluation inspection samples. Documents reviewed are listed in the
    Attachment.
    *  Unit 1/2, B 4kv shutdown board while B EDG feeder breaker was racked to test
        with a wooden seismic device, (WO number 05-715371)
    *  Unit 3, 3D EDG did not meet acceptance criteria for a pole drop test, (PER 732970)
    *  RHRSW Pump Seismic Restraints (PERs 794671, 796311, 798502)
    *  3D EDG Heat Exchanger Fouling (PER 782689)
    *  Average Power Range Monitor Voter Relay Logic Module failures under 10 CFR Part
        21 (PER 818017)
                                                                                      Enclosure


=SUPPLEMENTARY INFORMATION=
                                              21
  b. Findings
      No findings were identified.
1R18 Plant Modifications
.1    Permanent Plant Modifications
  a. Inspection Scope
      The inspectors reviewed the Design Change Notice (DCN) and completed work package
      (WOs 113899709 and 113900042) for DCN 70752 to Eliminate Fault Propagation on
      4kV Breakers, including related documents and procedures. The inspectors reviewed
      licensee procedures NPG-SPP-09.3, Plant Modifications and Engineering Change
      Control, and NPG-SPP-06.9.3, Post-Modification Testing, and observed part of the
      licensees activities to implement this design change made while the unit was online.
      The inspectors reviewed the associated 10 CFR 50.59 screening against the system
      design bases documentation to verify that the modifications had not affected system
      operability/availability. The inspectors reviewed selected ongoing and completed work
      activities to verify that installation was consistent with the design control documents.
      This activity constituted one Permanent Plant Modification sample. Documents
      reviewed are listed in the Attachment.
  b. Findings
      No findings were identified.
1R19 Post Maintenance Testing
  a. Inspection Scope
      The inspectors witnessed and reviewed post-maintenance tests (PMTs) listed below to
      verify that procedures and test activities confirmed SSC operability and functional
      capability following the described 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
      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 licensee procedural
      requirements. Furthermore, the inspectors verified that problems associated with PMTs
      were identified and entered into the CAP. This activity constituted four Post
      Maintenance Test inspection samples. Documents reviewed are listed in the
      Attachment.
                                                                                        Enclosure


==KEY POINTS OF CONTACT==
                                            22
      *  October 16, 2013, CS, Division II Breaker Testing following DCN 70752 to Eliminate
          Fault Propagation (WOs 113899709 and 113900042)
      *  November 8, 2013, 3A EDG, 3-SR-3.8.1.1(3A), Monthly Operability Test Following
          Lube Oil Modifications (WO 114395126)
      *  November 13, 2013, Unit 2 RCIC digital flow controller test following replacement
          (WO 115269495)
      *  November 25, 2013, A EDG, 0-SR-3.8.1.1(A), Monthly Operability Test (WO
          114456082) Following Fuel Oil Line Repairs (WO 115302820)
  b. Findings
      No findings were identified.
4.    OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
.1    Cornerstone: Initiating Events
  a. Inspection Scope
      The inspectors reviewed the licensees procedures and methods for compiling and
      reporting the following Performance Indicators (PIs). The inspectors examined the
      licensees PI data for the specific PIs listed below for the fourth quarter 2012 through
      third quarter of 2013. The inspectors reviewed the licensees data and graphical
      representations as reported to the NRC to verify that the data was correctly reported.
      The inspectors also 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 verified that the PI data was appropriately captured, calculated correctly, and
      discrepancies resolved. The inspectors used the Nuclear Energy Institute (NEI) 99-02,
      Regulatory Assessment Performance Indicator Guideline, to ensure that industry
      reporting guidelines were appropriately applied. This activity constituted nine
      Performance Indicator inspection samples. Documents reviewed are listed in the
      Attachment.
      *  Unit 1, 2, and 3 Unplanned Scrams
      *  Unit 1, 2, and 3 Unplanned Scrams with Complications
      *  Unit 1, 2, and 3 Unplanned Power Changes
  b. Findings
      No findings were identified.
                                                                                        Enclosure


Licensee
                                            23
: [[contact::E. Bates]], Licensing Engineer
4OA2 Problem Identification and Resolution
: [[contact::D. Campbell]], Assistant Ops Superintendent
.1    Review of items entered into the Corrective Action Program:
: [[contact::P. Campbell]], System Engineer
      As required by Inspection Procedure 71152, Problem Identification and Resolution, and
: [[contact::S. Christman]], Ops Shift Manager
      in order to help identify repetitive equipment failures or specific human performance
: [[contact::D. Drummonds]], Underground and Buried Piping Program Owner
      issues for follow-up, the inspectors performed a daily screening of items entered into the
: [[contact::J. Emens]], Nuclear Site Licensing Manager
      licensees CAP. This review was accomplished by reviewing daily PER and SR reports,
: [[contact::D. Green]], Licensing Engineer
      and periodically attending Corrective Action Review Board (CARB) and PER Screening
: [[contact::R. Guthrie]], System Engineer
      Committee (PSC) meetings.
: [[contact::L. Hughes]], Manager Operations
.2    Semi-annual Trend Review:
: [[contact::E. Johnson]], System Engineer
  a. Inspection Scope
: [[contact::J. Lacasse]], System Engineer
      As required by Inspection Procedure 71152, the inspectors performed a review of the
: [[contact::J. McCormack]], System Engineer
      licensees CAP and other associated programs and documents to identify trends that
: [[contact::M. Oliver]], Licensing Engineer
      could indicate the existence of a more significant safety issue. The inspectors review
: [[contact::J. Paul]], Nuclear Site Licensing Manager
      was focused on repetitive equipment issues, but also included licensee trending efforts
: [[contact::K. Polson]], Site Vice President
      and licensee human performance results. The inspectors review nominally considered
: [[contact::M. Roy]], Maintenance Rule Coordinator
      the six-month period of July through December 2013, although some examples
: [[contact::S. Samaras]], Civil Design Engineer
      expanded beyond those dates when the scope of the trend warranted. The inspectors
: [[contact::T. Scott]], Performance Improvement Manager
      reviewed licensee trend reports for the period in order to determine the existence of any
: [[contact::M. Webb]], Site Licensing
      adverse trends that the licensee may not have previously identified. The inspectors
: [[contact::A. Yarborough]], System Engineer 
      review also included the Integrated Trend Reports from April 1, 2013, to September 30,
      2013. The inspectors verified that adverse or negative trends identified in the licensees
      PERs, periodic reports, and trending efforts were entered into the CAP. This inspection
      constituted one Semi-annual Trend Review inspection sample. Documents reviewed
      are listed in the Attachment.
  b. Observations and Findings
      No findings were identified. In general, the licensee had identified trends and
      appropriately addressed them in their CAP. The inspectors observed that the licensee
      had performed a detailed review. The licensee routinely reviewed cause codes, involved
      organizations, key words, and system links to identify potential trends in their data. The
      inspectors compared the licensee process results with the results of the inspectors daily
      screening. Trends that have been identified by the inspectors and reported to the
      licensee were appropriately entered into the licensees trending program and the CAP.
      These trends included the following:
      *  Challenges to operability of the RHR heat exchangers due to Asiatic clam fouling
      *  Secondary plant systems challenging continued operation at 100 percent power and
          causing plant trips
      *  Control of transient combustible material in safety-related areas of the plant
                                                                                        Enclosure


==LIST OF ITEMS==
                                            24
.3    Focused Annual Sample Review:
  a. Inspection Scope
      The inspectors conducted a review of licensee maintenance of floor drain systems in the
      diesel buildings and reactor buildings with a focus on the preventative maintenance
      practices and design of the drains with respect to impact on CO2 actuation on a fire.
      This inspection constituted one Focused Annual Review inspection sample. Documents
      reviewed are listed in the Attachment.
  b. Observations and Findings
      The inspectors noted that licensee preventative maintenance frequency for maintaining
      plant drains was not identifying a trend of excessive debris on the as-found inspection.
      Some plant areas did not have an assigned preventative maintenance task.
      Additionally, the inspectors noted that the drains in the diesel rooms would allow CO2
      concentrations to be diluted on any actuation into the adjacent corridors floor drain
      sump.
      Introduction: The NRC identified a Green NCV of 10 CFR 50, Appendix B, Criterion III,
      Design Control, for the licensees failure to establish design control measures ensure the
      capabilities of the B EDG room floor drains.
      Description: On August 13, 2013, NRC inspectors identified significantly clogged floor
      drains in the B EDG room. Per Browns Ferry Civil Design Criteria BFN-50-C-7105, Low
      Energy Piping Evaluation Requirements, the two floor drains installed in the EDG room
      were required to remove at least 135 gallons per minute (gpm) of water to sumps
      outside the room. The Browns Ferry Engineering staff reviewed the condition and
      concluded that the B EDG was inoperable as the drains were incapable of removing
      flow. Subsequently, NRC inspectors observed licensee staff members dumping debris
      and dirty water down the 3D EDG room drains. Despite observed fouling of the drains,
      licensee staff failed to recognize this as a condition adverse to quality and initiate SRs to
      address the condition. The inspectors determined that there were no preventative
      maintenance tasks or periodic testing to ensure the drain capability for the eight EDG
      rooms. Other plant rooms have a 26 week frequency preventative maintenance task to
      ensure the design drain capabilities were maintained.
      The Browns Ferry EDG room internal flood mitigation strategy is to have the outside
      sump level alarm alert operators once the sump becomes full. The sump pumps are
      maintained in an off condition at the Browns Ferry plant. With the floor drains clogged,
      operator action would be delayed because the sump could not receive 135 gpm flood
      water through the drain piping. The licensee re-evaluated the B EDG drain conditions
      one month later and determined the drains were only 90 percent and 45 percent clogged
      on August 13, 2013. This would have allowed the drain water to slowly fill the sump.
      Based on sufficient operator response time, the B EDG was determined to remain
      operable. The licensees immediate corrective action was to clean all the drains in all
      the EDG rooms.
                                                                                          Enclosure


===OPENED, CLOSED AND DISCUSSED===
                                            25
      Analysis: The inspectors determined that the licensees failure to establish measures to
      assure the regulatory requirements and design basis of structures, systems, and
      components were correctly translated into procedures and instructions in accordance
      with 10 CFR 50, Appendix B, Criterion III, Design Control, was a performance deficiency
      that was reasonably within TVAs ability to foresee and prevent. Specifically, no
      measures were established to ensure the EDG floor drains maintained capability of
      performing their intended functions as described in the design basis. The finding was
      more than minor because, if left uncorrected, the performance deficiency would have the
      potential to lead to a more significant safety concern. Specifically, the EDG room floor
      drains could become sufficiently clogged such that internal flooding would cause the
      affected EDG to be unable to perform its safety function. The inspectors performed a
      Phase 1 screening in accordance with IMC 0609, Significance Determination Process,
      Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding
      was of very low safety significance (Green) because it did not impact the frequency of an
      internal flooding event. This finding has a cross-cutting aspect in the area of Problem
      Identification and Resolution, Corrective Action Program Component, because TVA did
      not identify issues completely, accurately, and in a timely manner commensurate with
      their safety significance. Specifically, TVA did not identify that workers were challenging
      the drains design feature by routinely dumping dirty water and debris into the floor drains
      without a mechanism to verify the resultant capability of the drains. [P.1(a)]
      Enforcement: 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part,
      that measures shall be established to assure the regulatory requirements and design
      basis of structures, systems, and components are correctly translated into procedures
      and instructions. Contrary to the above, prior to August 13, 2013, the Tennessee Valley
      Authority (TVA) did not correctly translate the design basis of the EDG floor drains into
      procedures and instructions and therefore no measures were established to ensure the
      EDG floor drains maintained capability of performing their intended function as described
      in their design basis. The licensees immediate corrective action was to clean all the
      drains in all the EDG rooms thus verifying capability of the drains. This violation is being
      treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The
      violation was entered into the licensees corrective action program as PER 765575.
      (NCV 05000259/2013005-05, Failure to Maintain Emergency Diesel Room Floor Drains)
4OA3 Follow-up of Events and Notices of Enforcement Discretion
.1    (Closed) Licensee Event Report (LER) 05000259/2009-002-01, Unexpected Logic
      Lockout of the Loop II Residual Heat Removal (RHR) System Pumps
  a. Inspection Scope
      The inspectors reviewed LER 05000259/2009-002-01 dated September 27, 2013. The
      licensee event report was reviewed based on the changes that were made to the original
      report. The changes documented concurrent inoperability of systems described in other
      LERs. These systems included the Loop II of the RHR system (due to the failure of
      1-FCV-74-66) and the RHR pump 1C (due to a rotor/shaft bow). All the other system
                                                                                        Enclosure


===Opened===
                                          26
: 05000259, 260, 296/2013005-02 AV Failure to Maintain Emergency Response Staffing Levels (Section 1R11.2) 
      operability issues were previously adjudicated in Browns Ferry inspection report
: 05000259, 260, 296/2013005-03 AV Inaccurate Information Provided Concerning Onsite Emergency Response Organization
      05000259, 260, 296/2010002 (ADAMS Accession No. ML101200508). This LER is
Staffing Requirements (Section 1R11.2)
      closed.
: 05000259, 260, 296/2013005-04 AV Inappropriate Amendment of License Conditions (Section 1R11.2)
  b. Findings
      No findings were identified.
.2    (Closed) Licensee Event Report (LER) 05000259/2009-004-01, High Pressure Core
      Injection Found Inoperable During Condensate Header Level Switch Calibration and
      Functional Test
  a. Inspection Scope
      The inspectors reviewed LER 05000259/2009-004-01 dated September 27, 2013. The
      licensee event report was reviewed based on the changes that were made to the
      previous report. The changes documented concurrent inoperability of systems
      described in other LERs. These systems included the Loop II of the RHR system (due
      to the failure of 1-FCV-74-66) and the RHR pump 1C (due to a rotor/shaft bow). All the
      other system operability issues were previously addressed in Browns Ferry inspection
      report 05000259, 260, 296/2009005 (ADAMS Accession No. ML100331517). This LER
      is closed.
  b. Findings
      No findings were identified.
.3    (Closed) Licensee Event Report (LER) 05000259/2010-003-03, Failure of a Low
      Pressure Coolant Injection Flow Control Valve
  a. Inspection Scope
      The inspectors reviewed LER 05000259/2010-003-03 dated September 30, 2013. The
      licensee event report was reviewed based on the changes that were made to the
      previous reports. The changes documented concurrent inoperability of systems
      described in other LERs and systems that were inoperable due to maintenance for
      periods of time less than the allowed limit. All system operability issues were previously
      addressed in Browns Ferry inspection reports 05000259/2011008 (ADAMS Accession
      No. ML111290500) and 05000259, 260, 296/2012002 (ADAMS Accession No.
      ML12121A507). This LER is closed.
  b. Findings
      No findings were identified.
                                                                                      Enclosure


===Opened and Closed===
                                          27
: 05000259, 260, 296/2013005-01  NCV Failure to Document Service Water Freeze Protection Deficiencies (Section 1R01)  
.4    (Closed) Licensee Event Report (LER) 05000259, 260, 296/2011-003-02, Loss of Safety
      Function (SDC) Resulting from Emergency Diesel Generator Output Breaker Trip
  a. Inspection Scope
      The inspectors reviewed LER 05000259, 260, 296/2011-003-02 dated September 30,
      2013, and all previous revisions. The licensee event report was reviewed based on the
      changes that were made to the previous reports. The key change was the
      documentation of the inoperability of the Diesel Generator based on the failure of the
      Overspeed Trip Limit Switch (OTLS). The previous revision did not include the total
      inoperability time. This issue was previously addressed in Browns Ferry Inspection
      reports 05000259, 260, 296/2011004 (ADAMS Accession No. ML113180503) and
      05000259, 260, 296/2011005 (ADAMS Accession No. ML12045A063). This LER is
      closed.
  b. Findings
      No findings were identified.
.5    (Closed) Licensee Event Report (LER) 05000259/2011-009-03, As-Found Undervoltage
      Trip for the Reactor Protection System 1A1 Relay that Did Not Meet Acceptance Criteria
      During Several Surveillances
  a. Inspection Scope
      The inspectors reviewed LER 05000259/2011-009-03 dated July 29, 2013. The licensee
      event report was reviewed based on the changes that were made to the previous
      reports. The changes documented additional similar failures and a change to the causal
      factors. Standing order 174 was issued to establish Operations department
      expectations when as-found data is found outside of acceptable regulatory guidelines.
      The RPS 1A1 relay and 3C1 relay were replaced. This issue was previously addressed
      in Browns Ferry Inspection reports 05000259, 260, 296/2012002 (ADAMS Accession
      No. ML12121A507) and 05000259, 260, 296/2012003 (ADAMS Accession No.
      ML12227A711). Section 4OA7 of Inspection Report 2012-002 addressed the associated
      licensee identified violation. No additional findings were identified. This LER is closed.
  b. Findings
      No findings were identified.
.6    (Closed) Licensee Event Report (LER) 05000296/2013-001-00 and 01, Inoperable
      Emergency Diesel Generator due to Failed Electric Generator Casing Fan Bearing
  a. Inspection Scope
      The inspectors reviewed the LER, dated March 11, 2013, and May 10, 2013, and the
      associated PER 665217, including the root cause analysis, operability determinations,
                                                                                        Enclosure


Attachment
                                            28
: 05000259, 260, 296/2013005-05 NCV Failure to Maintain Emergency Diesel Room Floor Drains (Section 4OA2.3)
      and corrective action plans. On January 9, 2013, while performing operator rounds near
: 05000260/2013005-06 SL-IV Failure to report a condition prohibited by Technical Specifications (Section 4OA3.7) 
      the Unit 3, 3D Emergency Diesel Generator (EDG), the licensee discovered metal
      residue and grease around the generator blower shaft. The licensee determined the
      generator blower inboard bearing (coupling side) had failed during a previous post
      maintenance test, as verified by licensee vibration data, rendering the 3D EDG
      inoperable. Following return to service of the 3D EDG and extent-of-condition
      inspections, the licensee determined that two additional Unit 3 EDGs had blower
      bearings that were degraded but not failed, and were also determined to be inoperable.
      The licensee concluded that the direct cause of the 3D EDG bearing failure was the
      absence of lubrication to the internal parts of the EDG blower bearing due to age related
      breakdown of the grease. The licensee determined two root causes to be inadequate
      component level assessment of the blower shielded bearings for failure modes and
      impacts and ineffective industry vibration monitoring standards. All four Unit 3 EDG
      generator blower bearings were replaced.
  b. Findings
      The enforcement aspects of this finding are discussed in Section 4OA7. This LER and
      its revision are closed.
.7    (Closed) Licensee Event Report (LER) 05000259/2013-006-00, 1B Standby Liquid
      Control Pump Inoperable for Longer than Allowed by Technical Specifications
  a. Inspection Scope
      The inspectors reviewed LER 05000259/2013-006-00 dated December 3, 2013. A
      licensee past operability review determined that 1B Standby Liquid Control pump was
      inoperable from December 1, 2012, to February 14, 2013, due to a piece of the motor
      breakers arc chute that had become dislodged and re-located to between the breaker
      contacts. This LER is closed.
  b. Findings
      Introduction. A Severity Level IV Non-Cited violation of 10 CFR 50.73(a)(2)(i)(B) was
      identified by the inspectors for the licensees failure to submit a License Event Report
      (LER) within 60 days of a reportable event .
      Description. On September 26, 2013, in response to NRC inspector questioning, the
      licensee reevaluated the past operability results of the failure of the 1B Standby Liquid
      Control (SLC) pump which occurred on Feb 13, 2013. Following the reevaluation, a
      revision to the PER 618667 past operability evaluation was made which concluded the
      1B SLC pump would not have been able to meet its mission time from December 1,
      2012 to February 14, 2013 (74 days). The licensing staff also identified that 1A SLC
      pump had been out of service for accumulator repairs during the time period that 1B
      SLC pump was inoperable. Thus the failure was reportable as both a condition
      prohibited by technical specifications and a loss of system safety function. PER 796578
      was initiated with an immediate corrective action to generate a LER. LER 50-259 2013-
      006-00 was submitted on December 3, 2013.
                                                                                        Enclosure


===Closed===
                                            29
: [[Closes LER::05000259/LER-2009-002]]-01 LER Unexpected Logic Lockout of the Loop II Residual Heat Removal System Pumps
      Analysis. The inspectors determined that the failure to submit a License Event Report
(Section 4OA3.1)
      (LER) within 60 days of a reportable event was a violation of the requirements of 10 CFR
: [[Closes LER::05000259/LER-2009-004]]-01 LER High Pressure Core Injection Found Inoperable During Condensate Header Level Switch
      50.73(a)(2)(i)(B). This violation had the potential to impede or impact the regulatory
: Calibration and Functional Test (Section
      process, and therefore subject to traditional enforcement as described in the NRC
: 4OA3.2)
      Enforcement Policy, dated July 9, 2013. The inspectors used the examples provided in
: [[Closes LER::05000259/LER-2010-003]]-03 LER Failure of a Low Pressure Coolant Injection Flow Control Valve (Section 4OA3.3) 
      Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required
: 05000259, 260, 296/2011-003-02 LER Loss of Safety Function (SDC) Resulting from Emergency Diesel Generator Output Breaker
      Report, of the NRC Enforcement Policy to determine the severity level (SL). Based on
: Trip (Section 4OA3.4)
      the wording of example 9 under the examples for SL IV violations, the inspectors
: [[Closes LER::05000259/LER-2011-009]]-03  LER As-Found Undervoltage Trip for the Reactor
      determined that this violation should be characterized as a SL IV violation. Example 9
: Protection System 1A1 Relay that Did Not  Meet Acceptance Criteria During Several Surveillances (Section 4OA3.5)
      states A licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73. A
: [[Closes LER::05000259/LER-2013-006]]-00 LER 1B Standby Liquid Control Pump Inoperable for Longer than Allowed by Technical  
      cross-cutting aspect was not assigned because the violation was dispositioned using
: Specifications (Section 4OA3.7)
      traditional enforcement.
: [[Closes LER::05000260/LER-2012-006]]-01 LER Automatic Reactor Scram Due to Loss of Power to the Reactor Protection System (Section 4OA3.8)
      Enforcement. 10 CFR 50.73(a)(2)(i)(B) required, in part, that licensees report any
: [[Closes LER::05000296/LER-2013-001]]-00 LER Inoperable Emergency Diesel Generator due to Failed Electric Generator Casing Fan Bearing (Section 4OA3.6)
      conditions prohibited by plant technical specifications within 60 days via a License Event
: [[Closes LER::05000296/LER-2013-001]]-01 LER Inoperable Emergency Diesel Generator due to Failed Electric Generator Casing Fan Bearing
      Report. Contrary to the above, from April 14, 2013, through December 3, 2013, the
(Section 4OA3.6)  2515/182 TI Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks,
      licensee did not report within 60 days the failure to comply with Condition A of Technical
: Phase II (Section 4OA5.2)
      Specification 3.1.7 after the February 13, 2013, 1B SLC pump breaker failure. This
: Attachment
      issue was documented in the licensees corrective action program as Problem
===Discussed===
      Evaluation Reports 796578 and 817510. Corrective actions included reporting the
None 
      conditions in LER 050000- 259/2013-06-00. This violation is being treated as an NCV,
==LIST OF DOCUMENTS REVIEWED==
      consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into
==Section 1R01: Adverse Weather Protection==
      the licensees corrective action program as PER 796578. (NCV 05000259/2013005-06,
: 0-GOI-200-1, Freeze Protection Inspection, Rev. 76
      [Failure to report a condition prohibited by Technical Specifications.])
: EPI-0-000-FRZ001, Freeze Protection Program for RHRSW pump rooms and Diesel Generator Building, Rev. 19
.8    (Closed) Licensee Event Report (LER) 050000260/2012-006-01, Automatic Reactor
: PER 8000190
      Scram Due to Loss of Power to the Reactor Protection System
: PER 821246, Prompt Determination of Operability
  a. Inspection Scope
: SR 821249 System Code FZ Discrepancy WO List, dated December 16, 2013
      On December 22, 2012, Unit 2 automatically scrammed from approximately 100 percent
      power due to loss of power to both RPS buses. The 4kV Shutdown Board D had
      de-energized during testing of the emergency diesel generators which resulted in a loss
      of the RPS Bus 2B. While attempting to re-energize the RPS Bus 2B, a procedural error
      resulted in de-energizing the RPS Bus 2A which resulted in a reactor scram and closure
      of the main steam isolation valves.
      The original LER 05000260/2012-006-00, dated February 20, 2013, and applicable PER
      660862, were reviewed by the inspectors and documented in Section 4OA3.3 of NRC IR
      05000260/2013002 (ADAMS Accession No. ML13134A237), where a self-revealing
      apparent violation (AV) of Technical Specification 5.4.1 was identified for the licensees
      failure to properly implement procedure 2-OI-99, Reactor Protection System. The
      finding was determined to have a low to moderate safety significance (white) and a
      notice of violation was issued to Browns Ferry for this event in NRC IR
      05000260/2013013 (ADAMS Accession No. ML13235A058).
                                                                                        Enclosure


==Section 1R04: Equipment Alignment==
                                            30
: 3-OI-71/ATT-3 RCIC Electrical Lineup Checklist, Rev. 50 3-OI-71/ATT-1 Reactor Core Isolation Cooling (RCIC) Valve Lineup Checklist, Rev. 50 Browns Ferry Electrical Distribution drawing
      The inspectors reviewed Revision 1 of the LER dated December 6, 2013, and applicable
: Browns Ferry Plan of the Day, 10-15-2013
      PER 740259, including the revised cause determination and corrective action plans.
: DWG 2-47E814-1, Flow Diagram Core Spray System, Rev. 52 
      This revised LER was submitted to provide the results of the licensees completed
: FSAR Section 4.7, RCIC 
      investigation and revised causal analysis. The inspectors verified that the supplemental
: Load Dispatcher switching order for opening
      information provided in the revised LER was complete and accurate. No additional
: MOD 5240
      licensee significant performance deficiencies were identified by the inspectors. This
: NEDP-27, Past Operability Evaluations, Rev. 0
      LER is closed
: PER 696780, Frequency change required on SLC pump breakers
  b. Findings
: PER 681667, 1B SLC pump tripped
      No additional findings were identified..
: SR 791672, Unit 3 RCIC Steam flow indication reads 10,000 lbm/hr at zero flow
4OA5 Other Activities
: SR 791254, Unit 2 RCIC deferral of rupture disk replacement System Health Reports, Standby Liquid Control, 2-1-13 to 5-31-13
.1   Operation of an Independent Spent Fuel Storage Installation (ISFSI) (60855)
: System Health Reports, Standby Liquid Control, 6-1-13 to 9-30-13 Unit 2 Core Spray Fragnet Update dated 10-15-2013
  a. Inspection Scope
      Under the guidance of IP 60855.1, the inspectors observed operations involving spent
      fuel transfer and storage for dry cask campaign number seven. Inspectors interviewed
      personnel and reviewed the licensees documentation regarding storing spent fuel to
      verify that these independent spent fuel storage installation (ISFSI) related programs
      and procedures fulfill the commitments and requirements specified in the Safety Analysis
      Report (SAR), Certificate of Compliance (CoC), 10 CFR Part 72, and the Technical
      Specifications. Specifically one year of related 10 CFR 72.48 evaluations, 10 CFR
      72.212(b) evaluations, and lid welding records associated with multi-purpose canisters
      (MPC) S/N 0326 and S/N 0330 were reviewed. The inspectors conducted independent
      ISFSI related activities to ensure that the licensee performed spent fuel loading and
      transport in a safe manner. Inspectors performed focused operational reviews on new
      methodologies concerning forced helium dehydration and supplemental cooling.
      Inspectors attended briefings and observed operations in the field including overall
      supervisory involvement, coordination, and oversight of ISFSI-related work activities.
      The inspectors reviewed the fuel loading plan for MPC-0326 and verified that the fuel
      assemblies were properly selected and loaded in accordance with characterization
      documents and approved procedures. The inspectors verified that selected individuals
      had received the necessary training in accordance with approved procedures for their
      ISFSI-related job duties.
      The inspectors reviewed work orders, completed procedures, logs, welding records,
      inspection records, qualification records, and overall guidelines for MPC-0326 ISFSI
      activities. The inspectors determined that the licensee had established, maintained, and
      implemented adequate control of dry cask processing operations, including loading,
      transportation, and storage per approved procedures and technical specification
      requirements. Records of spent fuel stored at the facility were properly maintained.
                                                                                      Enclosure


==Section 1R05: Fire Protection Browns Ferry Nuclear Plant Fire Protection Report, Volume 1, Rev. 16 Browns Ferry Nuclear Plant Fire Protection Report, Volume 1A, Rev 16 Browns Ferry Nuclear Plant Fire Protection Report, Volume 2, Rev. 51==
                                            31
  b. Findings and Observations
      No findings were identified.
.2    (Closed) Temporary Instruction 2515/182 - Review of the Industry Initiative to Control
      Degradation of Underground Piping and Tanks
  a. Inspection Scope
      The inspectors conducted a review of records and procedures related to the licensees
      program for buried piping and underground piping and tanks in accordance with Phase
      II of temporary instruction (TI) 2515-182 to confirm that the licensees program
      contained attributes consistent with Sections 3.3.A and 3.3.B of Nuclear Energy
      Institute (NEI) 09-14, Guideline for the Management of Buried Piping Integrity,
      Revision 3, and to confirm that these attributes were scheduled and/or completed by
      the NEI 09-14 Revision 3 deadlines. The inspectors interviewed licensee staff
      responsible for the buried piping program and reviewed activities related to the buried
      piping program to determine if the program was managed in a manner consistent with
      the industrys buried piping initiative.
      The licensees buried piping and underground piping and tanks program was inspected
      in accordance with paragraph 03.02.a of the TI and it was confirmed that activities
      which correspond to completion dates specified in the program which have passed
      since the Phase 1 inspection was conducted, have been completed. The licensees
      buried piping and underground piping and tanks program was inspected in accordance
      with paragraph 03.02.b of the TI and responses to specific questions found in
      http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-
      2011-11-16.pdf were submitted to the NRC headquarters staff.
  b. Findings
      No findings were identified. Based upon the scope of the review described above,
      Phase II of TI-2515/182 was completed.
.3    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.
                                                                                        Enclosure


==Section 1R11: Licensed Operator Requalification==
                                          32
: NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan, Rev. 100 Training Focus Areas for Cycle 5, 2013 Unit 2 Simulator Exercise Guide (SEG) OPL173.R227, Anticipated Transient without Scram
b.  Findings
    No findings were identified
4OA6 Meetings, Including Exit
    On January 10, and 21, 2014, the resident inspectors presented the quarterly inspection
    results to Mr. Steve Bono, Plant Manager, and other members of the licensees staff,
    who acknowledged the findings. The inspectors verified that all proprietary information
    was returned to the licensee.
4OA7 Licensee-Identified Violations
    The following violation of very low safety significance (Green) was identified by the
    licensee and is a violation of NRC requirements which meets the criteria of the NRC
    Enforcement Policy, for being dispositioned as a Non-Cited Violation.
    Unit 3 Technical Specification 3.3.8.1, AC Sources - Operating, required EDGs to be
    operable in Modes 1, 2, and 3, and with multiple EDGs inoperable, required all but one
    EDG be returned to service in 2 hours or be in Mode 3 within 12 hours and in Mode 4
    within 36 hours. Contrary to this, between December 22, 2012, and January 9, 2013,
    the licensee determined that multiple EDGs were inoperable as a result of failed 3D
    EDG and degraded 3A and 3B EDG generator blower bearings. This TS violation was
    entered into the licensees CAP as PERs 665217, 675339, and 675952. This finding
    represented an actual loss of function of the 3D EDG for greater than the TS allowed
    outage time, and therefore, required a detailed risk evaluation. Because of the short
    exposure time related to the performance deficiency, the finding was determined to be of
    very low safety significance (Green).
                                                                                      Enclosure


==Section 1R12: Maintenance Effectiveness==
                              SUPPLEMENTARY INFORMATION
: 0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -
                                KEY POINTS OF CONTACT
: 10
Licensee
: CFR 50.65, Rev. 46
E. Bates, Licensing Engineer
: 0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -
D. Campbell, Assistant Ops Superintendent
: 10
P. Campbell, System Engineer
: CFR 50.65, Rev. 46, Attachment 11 (Control Air System) CDE Record 1371, 2A RHR HX Inspection Control Air Compressor Trips/Anomalies Report, dated 3/12/13 
S. Christman, Ops Shift Manager
: Attachment Control Bay Chilled Water System 031-E a(1) Plan Rev 1, 1-10-2012 DWG 0-47E845-1 DWG 0-47E845-2
D. Drummonds, Underground and Buried Piping Program Owner
: DWG 1-47E610-32-1
J. Emens, Nuclear Site Licensing Manager
: DWG 2-47E610-32-1
D. Green, Licensing Engineer
: FSAR Chapter 10.14 Service and Control Air
R. Guthrie, System Engineer
: NPG-SPP-03.4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting- 10
L. Hughes, Manager Operations
: CFR 50.65, Rev. 2 PDO for
E. Johnson, System Engineer
: PER 674502
J. Lacasse, System Engineer
: PER 674502
J. McCormack, System Engineer
: PER 692613
M. Oliver, Licensing Engineer
: PER 784085
J. Paul, Nuclear Site Licensing Manager
: PER 814796, Review the Maintenance Rule Performance Criteria Established in 0-TI-346 System Health Report for the Control Air System, dated 11/18/13
K. Polson, Site Vice President
: System Health Report, System 31, A/C, Heating and CREV, (6-1-2013 - 9-30-13)
M. Roy, Maintenance Rule Coordinator
: U0 RHRSW, Functions 023-B, C, & D (a)(1) Plan, Rev. 4
S. Samaras, Civil Design Engineer
: WO 111456773
T. Scott, Performance Improvement Manager
: WO 113206742
M. Webb, Site Licensing
: WO 113632455
A. Yarborough, System Engineer
: WO 114245152
                    LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
: WO 114245153
Opened
: WO 114687057
05000259, 260, 296/2013005-02      AV      Failure to Maintain Emergency Response
: WO 114731364
                                            Staffing Levels (Section 1R11.2)
: WO 114917994
05000259, 260, 296/2013005-03      AV      Inaccurate Information Provided Concerning
: WO 115045078
                                            Onsite Emergency Response Organization
: WO 115057307
                                            Staffing Requirements (Section 1R11.2)
05000259, 260, 296/2013005-04      AV      Inappropriate Amendment of License
                                            Conditions (Section 1R11.2)
Opened and Closed
05000259, 260, 296/2013005-01      NCV    Failure to Document Service Water Freeze
                                            Protection Deficiencies (Section 1R01)
                                                                                Attachment


==Section 1R13: Maintenance Risk Assessments and Emergent Work Control==
                                    2
: NPG-SPP-09.11.1, Equipment Out of Service Management, Revs. 6, 7 Operations EOOS Desktop Users Guide, Effective Date: 4/27/2012
05000259, 260, 296/2013005-05  NCV    Failure to Maintain Emergency Diesel Room
: 10/1-3/2013, Plan of the Day
                                      Floor Drains (Section 4OA2.3)
: 10/1-3/2013, Operators Daily Logs and EOOS Profiles
05000260/2013005-06            SL-IV  Failure to report a condition prohibited by
: 10/23-25/2013, Plan of the Day
                                      Technical Specifications (Section 4OA3.7)
: 10/23-25/2013, Operators Daily Logs and EOOS Profiles
Closed
: SR 797298, Expected EOOS Color Change Not Communicated to OPS Shift Crew 10/29-30/2013, Plan of the Day
05000259/2009-002-01          LER    Unexpected Logic Lockout of the Loop II
: 10/29-30/2013, Operators Daily Logs and EOOS Profiles
                                      Residual Heat Removal System Pumps
: 11/13/2013, Plan of the Day
                                      (Section 4OA3.1)
: 11/13/2013, Operators Daily Logs and EOOS Profiles Operating Experience Smart Sample Guidance (OpESS) 2007-03, Crane and Heavy Lift Inspection, Rev. 2
05000259/2009-004-01          LER    High Pressure Core Injection Found Inoperable
: Nuclear Energy Institute (NEI) 08-05 Industry Initiative on the Control of Heavy Loads, Rev. 0
                                      During Condensate Header Level Switch
: NRC Generic Letter 80-113 Control of Heavy Loads
                                      Calibration and Functional Test (Section
: MSI-0-000-LFT001, Lifting Instructions for the Control of Heavy Loads, Rev. 0064
                                      4OA3.2)
05000259/2010-003-03          LER    Failure of a Low Pressure Coolant Injection
                                      Flow Control Valve (Section 4OA3.3)
05000259, 260, 296/2011-003-02 LER      Loss of Safety Function (SDC) Resulting from
                                        Emergency Diesel Generator Output Breaker
                                        Trip (Section 4OA3.4)
05000259/2011-009-03          LER    As-Found Undervoltage Trip for the Reactor
                                      Protection System 1A1 Relay that Did Not
                                      Meet Acceptance Criteria During Several
                                      Surveillances (Section 4OA3.5)
05000259/2013-006-00          LER    1B Standby Liquid Control Pump Inoperable for
                                      Longer than Allowed by Technical
                                      Specifications (Section 4OA3.7)
05000260/2012-006-01          LER    Automatic Reactor Scram Due to Loss of Power
                                      to the Reactor Protection System (Section
                                      4OA3.8)
05000296/2013-001-00          LER    Inoperable Emergency Diesel Generator due to
                                      Failed Electric Generator Casing Fan Bearing
                                      (Section 4OA3.6)
05000296/2013-001-01          LER    Inoperable Emergency Diesel Generator due to
                                      Failed Electric Generator Casing Fan Bearing
                                      (Section 4OA3.6)
2515/182                      TI      Review of the Industry Initiative to Control
                                      Degradation of Underground Piping and Tanks,
                                      Phase II (Section 4OA5.2)
                                                                              Attachment


==Section 1R15: Operability Determinations and Functionality Assessments==
                                            3
: 0-GOI-300-2, Electrical General Operating Instruction Calculation
Discussed
: CD-Q0999-890268 
None
: Attachment Calculation MDQ0082000016, Diesel Generator Jacket Water Cooler Capacity and Tube Plugging, Rev. 2 Common cause failure evaluation for
                              LIST OF DOCUMENTS REVIEWED
: PER 728243 DWG 0-37W205-10, Mechanical Pumping Station & Water Treatment - Piping & Equipment, Rev. 6
Section 1R01: Adverse Weather Protection
: DWG 0-37W205-5, Mechanical Pumping Station & Water Treatment - Piping & Equipment, Rev. 6 EWR13-BOP-023-202, Evaluation of Conservatism within EPRI document
0-GOI-200-1, Freeze Protection Inspection, Rev. 76
: 1025271 and Applicability of EPRI Guidelines at BFN, Rev. Original Failure Analysis for
EPI-0-000-FRZ001, Freeze Protection Program for RHRSW pump rooms and Diesel Generator
: PER 732970
Building, Rev. 19
: IEEE-115 Code requirements for Pole Drop testing Past Operability Evaluation for
PER 8000190
: PER 782689 PDO for
PER 821246, Prompt Determination of Operability
: PER 732970
SR 821249
: PER 401732, 3C Diesel Generator Shorted Rotor Pole
System Code FZ Discrepancy WO List, dated December 16, 2013
: PER 728243, 3D Diesel Generator did not meet acceptance criteria for a pole drop test
Section 1R04: Equipment Alignment
: PER 732970, The PDO for
3-OI-71/ATT-3 RCIC Electrical Lineup Checklist, Rev. 50
: PER 728243 appeared inconclusive
3-OI-71/ATT-1 Reactor Core Isolation Cooling (RCIC) Valve Lineup Checklist, Rev. 50
: PER 782689, Fouling Seen During Raw Water Inspection of 3D DG HEX
Browns Ferry Electrical Distribution drawing
: PER 794671, Missing Bolts Found on B3 EECW Pump Seismic Restraint
Browns Ferry Plan of the Day, 10-15-2013
: PER 796311, Missing and Deteriorated Hardware Discovery on A3 RHRSW Pump Restraint
DWG 2-47E814-1, Flow Diagram Core Spray System, Rev. 52
: PER 798502, Repairs Needed to C1 RHRSW Pump Seismic Restraint Prompt Determination of Operability for PER's
FSAR Section 4.7, RCIC
: 794671,
Load Dispatcher switching order for opening MOD 5240
: 796311,
NEDP-27, Past Operability Evaluations, Rev. 0
: 798502
PER 696780, Frequency change required on SLC pump breakers
: UFSAR, Appendix C, Structural Qualification Of Subsystems And Components, Amendment 25
PER 681667, 1B SLC pump tripped
: UFSAR, Section 10.9, RHR Service Water System, Amendment 25 Unit 3 TS 3.8.1
SR 791672, Unit 3 RCIC Steam flow indication reads 10,000 lbm/hr at zero flow
: WO 115052074, Heat Exchanger Visual Inspection and Evaluation Form
SR 791254, Unit 2 RCIC deferral of rupture disk replacement
: WO number 05-715371
System Health Reports, Standby Liquid Control, 2-1-13 to 5-31-13
System Health Reports, Standby Liquid Control, 6-1-13 to 9-30-13
Unit 2 Core Spray Fragnet Update dated 10-15-2013
Section 1R05: Fire Protection
Browns Ferry Nuclear Plant Fire Protection Report, Volume 1, Rev. 16
Browns Ferry Nuclear Plant Fire Protection Report, Volume 1A, Rev 16
Browns Ferry Nuclear Plant Fire Protection Report, Volume 2, Rev. 51
Section 1R11: Licensed Operator Requalification
NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan, Rev. 100
Training Focus Areas for Cycle 5, 2013
Unit 2 Simulator Exercise Guide (SEG) OPL173.R227, Anticipated Transient without Scram
Section 1R12: Maintenance Effectiveness
0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -
10 CFR 50.65, Rev. 46
0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -
10 CFR 50.65, Rev. 46, Attachment 11 (Control Air System)
CDE Record 1371, 2A RHR HX Inspection
Control Air Compressor Trips/Anomalies Report, dated 3/12/13
                                                                                  Attachment


==Section 1R18: Plant Modifications==
                                            4
: NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 1
Control Bay Chilled Water System 031-E a(1) Plan Rev 1, 1-10-2012
: NPG-SPP-06.9.3, Post-Modification Testing, Rev. 4
DWG 0-47E845-1
: NPG-SPP-09.3, Plant Modifications and Engineering Change Control, Rev. 15
DWG 0-47E845-2
: DCN 70752, Install Separate Fusing for Trip Circuits on 4KV Breakers to Eliminate Fault Propagation issue, Rev. A
DWG 1-47E610-32-1
: WO 113899709,
DWG 2-47E610-32-1
: DCN 70752 - Stage 16: Install ATM6 Fuse in 4kV Board Trip Circuit
FSAR Chapter 10.14 Service and Control Air
: WO 113900042,
NPG-SPP-03.4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting-
: DCN 70752 - Stage 23: Install ATM6 Fuse in 4kV Board Trip Circuit
10 CFR 50.65, Rev. 2
: DCN 70752 - Stage 16, Testing Steps
PDO for PER 674502
: DCN 70752 - Stage 23, Testing Steps
PER 674502
: 2-SR-3.5.1.6(CS II), Core Spray Flow Rate Loop II, Rev. 33
PER 692613
: 0-GOI-300-2, Electrical, Rev. 122
PER 784085
: EII-0-000-BKR005, 4KV Horizontal Breaker 52STA Switch Test Linkage and Position Switch Blocking and Tie-Up, Rev. 7
PER 814796, Review the Maintenance Rule Performance Criteria Established in 0-TI-346
: NRC Generic Letter No. 96-01: Testing Of Safety-Related Logic Circuits
System Health Report for the Control Air System, dated 11/18/13
System Health Report, System 31, A/C, Heating and CREV, (6-1-2013 - 9-30-13)
U0 RHRSW, Functions 023-B, C, & D (a)(1) Plan, Rev. 4
WO 111456773
WO 113206742
WO 113632455
WO 114245152
WO 114245153
WO 114687057
WO 114731364
WO 114917994
WO 115045078
WO 115057307
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
NPG-SPP-09.11.1, Equipment Out of Service Management, Revs. 6, 7
Operations EOOS Desktop Users Guide, Effective Date: 4/27/2012
10/1-3/2013, Plan of the Day
10/1-3/2013, Operators Daily Logs and EOOS Profiles
10/23-25/2013, Plan of the Day
10/23-25/2013, Operators Daily Logs and EOOS Profiles
SR 797298, Expected EOOS Color Change Not Communicated to OPS Shift Crew
10/29-30/2013, Plan of the Day
10/29-30/2013, Operators Daily Logs and EOOS Profiles
11/13/2013, Plan of the Day
11/13/2013, Operators Daily Logs and EOOS Profiles
Operating Experience Smart Sample Guidance (OpESS) 2007-03, Crane and Heavy Lift
Inspection, Rev. 2
Nuclear Energy Institute (NEI) 08-05 Industry Initiative on the Control of Heavy Loads, Rev. 0
NRC Generic Letter 80-113 Control of Heavy Loads
MSI-0-000-LFT001, Lifting Instructions for the Control of Heavy Loads, Rev. 0064
Section 1R15: Operability Determinations and Functionality Assessments
0-GOI-300-2, Electrical General Operating Instruction
Calculation CD-Q0999-890268
                                                                                      Attachment


==Section 1R19: Post Maintenance Testing==
                                          5
: 0-GOI-300-2, Electrical, Rev. 122
Calculation MDQ0082000016, Diesel Generator Jacket Water Cooler Capacity and Tube
: 0-SR-3.8.1.1(A), Diesel Generator 'A' Monthly Operability Test, Rev. 50 2-OI-71 Reactor Core Isolation Cooling Operating Instruction, Rev. 0068
Plugging, Rev. 2
: 2-SR-3.5.1.6(CS II), Core Spray Flow Rate Loop II, Rev. 33 
Common cause failure evaluation for PER 728243
: Attachment 3-SR-3.8.1.1(3A), Diesel Generator 3A Monthly Operability Test, Rev. 55
DWG 0-37W205-10, Mechanical Pumping Station & Water Treatment - Piping & Equipment,
: DCN 70752 - Stage 16, Testing Steps
Rev. 6
: DCN 70752 - Stage 23, Testing Steps
DWG 0-37W205-5, Mechanical Pumping Station & Water Treatment - Piping & Equipment,
: DCN 70752, Install Separate Fusing for Trip Circuits on 4KV Breakers to Eliminate Fault Propagation issue
Rev. 6
: EII-0-000-BKR005, 4KV Horizontal Breaker 52STA Switch Test Linkage and Position Switch Blocking and Tie-Up, Rev. 7
EWR13-BOP-023-202, Evaluation of Conservatism within EPRI document 1025271 and
: MMDP-1, Maintenance Management System, Rev. 27
Applicability of EPRI Guidelines at BFN, Rev. Original
: NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 1
Failure Analysis for PER 732970
: NPG-SPP-06.9.3, Post-Modification Testing, Rev. 4 NRC Generic Letter No. 96-01: Testing Of Safety-Related Logic Circuits
IEEE-115 Code requirements for Pole Drop testing
: PER 786196, Oil on Floor beneath 3A D/G Platform
Past Operability Evaluation for PER 782689
: PER 806291, Diesel Generator 3A Control Circuit Ground Alarm Received
PDO for PER 732970
: PER 807494, Fail light is illuminated on Unit 2 RCIC flow controller
PER 401732, 3C Diesel Generator Shorted Rotor Pole
: PER 808811, PDO Request for
PER 728243, 3D Diesel Generator did not meet acceptance criteria for a pole drop test
: PER 789196
PER 732970, The PDO for PER 728243 appeared inconclusive
: WO 113899709,
PER 782689, Fouling Seen During Raw Water Inspection of 3D DG HEX
: DCN 70752 - Stage 16: Install ATM6 Fuse in 4kV Board Trip Circuit
PER 794671, Missing Bolts Found on B3 EECW Pump Seismic Restraint
: WO 113900042,
PER 796311, Missing and Deteriorated Hardware Discovery on A3 RHRSW Pump Restraint
: DCN 70752 - Stage 23: Install ATM6 Fuse in 4kV Board Trip Circuit
PER 798502, Repairs Needed to C1 RHRSW Pump Seismic Restraint
: WO 114395126, Diesel Generator '3A' Monthly Operability Test
Prompt Determination of Operability for PERs 794671, 796311, 798502
: WO 114456082, Diesel Generator 'A' Monthly Operability Test
UFSAR, Appendix C, Structural Qualification Of Subsystems And Components, Amendment 25
: WO 115263298, Attachment 1 to Task 10,
UFSAR, Section 10.9, RHR Service Water System, Amendment 25
: BFN-3-ENG-082-0003A, Rev. 0
Unit 3 TS 3.8.1
: WO 115269495, Replacement of
WO 115052074, Heat Exchanger Visual Inspection and Evaluation Form
: BFN-2-FIC-071-0036A (Digital Flow controller for Unit 2 RCIC)
WO number 05-715371
: WO 115302820, Re-Seal NPT Pipe Threads at Inlet to Check Valve
Section 1R18: Plant Modifications
NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 1
NPG-SPP-06.9.3, Post-Modification Testing, Rev. 4
NPG-SPP-09.3, Plant Modifications and Engineering Change Control, Rev. 15
DCN 70752, Install Separate Fusing for Trip Circuits on 4KV Breakers to Eliminate Fault
Propagation issue, Rev. A
WO 113899709, DCN 70752 - Stage 16: Install ATM6 Fuse in 4kV Board Trip Circuit
WO 113900042, DCN 70752 - Stage 23: Install ATM6 Fuse in 4kV Board Trip Circuit
DCN 70752 - Stage 16, Testing Steps
DCN 70752 - Stage 23, Testing Steps
2-SR-3.5.1.6(CS II), Core Spray Flow Rate Loop II, Rev. 33
0-GOI-300-2, Electrical, Rev. 122
EII-0-000-BKR005, 4KV Horizontal Breaker 52STA Switch Test Linkage and Position Switch
Blocking and Tie-Up, Rev. 7
NRC Generic Letter No. 96-01: Testing Of Safety-Related Logic Circuits
Section 1R19: Post Maintenance Testing
0-GOI-300-2, Electrical, Rev. 122
0-SR-3.8.1.1(A), Diesel Generator A Monthly Operability Test, Rev. 50
2-OI-71 Reactor Core Isolation Cooling Operating Instruction, Rev. 0068
2-SR-3.5.1.6(CS II), Core Spray Flow Rate Loop II, Rev. 33
                                                                                  Attachment


==Section 4OA1: Performance Indicator (PI) Verification Browns Ferry Daily Operator Logs, October 1, 2012, through September 30, 2013==
                                            6
3-SR-3.8.1.1(3A), Diesel Generator 3A Monthly Operability Test, Rev. 55
DCN 70752 - Stage 16, Testing Steps
DCN 70752 - Stage 23, Testing Steps
DCN 70752, Install Separate Fusing for Trip Circuits on 4KV Breakers to Eliminate Fault
Propagation issue
EII-0-000-BKR005, 4KV Horizontal Breaker 52STA Switch Test Linkage and Position Switch
Blocking and Tie-Up, Rev. 7
MMDP-1, Maintenance Management System, Rev. 27
NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 1
NPG-SPP-06.9.3, Post-Modification Testing, Rev. 4
NRC Generic Letter No. 96-01: Testing Of Safety-Related Logic Circuits
PER 786196, Oil on Floor beneath 3A D/G Platform
PER 806291, Diesel Generator 3A Control Circuit Ground Alarm Received
PER 807494, Fail light is illuminated on Unit 2 RCIC flow controller
PER 808811, PDO Request for PER 789196
WO 113899709, DCN 70752 - Stage 16: Install ATM6 Fuse in 4kV Board Trip Circuit
WO 113900042, DCN 70752 - Stage 23: Install ATM6 Fuse in 4kV Board Trip Circuit
WO 114395126, Diesel Generator 3A Monthly Operability Test
WO 114456082, Diesel Generator A Monthly Operability Test
WO 115263298, Attachment 1 to Task 10, BFN-3-ENG-082-0003A, Rev. 0
WO 115269495, Replacement of BFN-2-FIC-071-0036A (Digital Flow controller for Unit 2 RCIC)
WO 115302820, Re-Seal NPT Pipe Threads at Inlet to Check Valve
Section 4OA1: Performance Indicator (PI) Verification
Browns Ferry Daily Operator Logs, October 1, 2012, through September 30, 2013
Section 4OA2: Problem Identification and Resolution
Integrated Trend Report, Q3FY13
Integrated Trend Report, Q4FY13
NPG-SPP 22.303, PER Analysis, Actions, Closures, and Approvals, Rev. 0001
NPG-SPP 22.305, Apparent Cause Analysis, Rev. 0001
NPG-SPP 22.306, Root Cause Analysis, Rev. 0001
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
2-AOP-99-1, Loss of Power to One RPS Bus, Rev. 27 and Rev. 29
2-OI-99, Reactor Protection System, Rev. 79 and Rev. 80
LER 259, 260, 296/2011-003-02, Loss of Safety Function (SDC) Resulting from Emergency
Diesel Generator Output Breaker Trip
LER 259/2009-002-01, Unexpected Logic Lockout of the Loop II Residual Heat Removal (RHR)
System Pumps
LER 259/2009-004-01, High Pressure Core Injection found Inoperable during Condensate
Header Level Switch Calibration and Functional Test
LER 259/2010-003-03, Failure of a Low Pressure Coolant Injection Flow Control Valve
PER 660235, 3D EDG Units in Parallel with D EDG Failed PMTI
PER 660862, U2 Scram while restarting 2B RPS using 2B RPS MG Set
PER 740259, RPS Scram, White Finding
Unit 1 FSAR
Unit 1 Technical Specifications 3.5.1 and 3.8.1
                                                                                  Attachment


==Section 4OA2: Problem Identification and Resolution Integrated Trend Report, Q3FY13==
                                          7
: Integrated Trend Report, Q4FY13
Section 4OA5: Other Activities
: NPG-SPP 22.303, PER Analysis, Actions, Closures, and Approvals, Rev. 0001
ISFSI Inspection
: NPG-SPP 22.305, Apparent Cause Analysis, Rev. 0001
10 CFR 72.212, Report of Evaluations, Rev. 5, dated 6/11/2012
: NPG-SPP 22.306, Root Cause Analysis, Rev. 0001
10 CFR 72.48 Screening Review, 0-GOI-100-3B, Manual Operation of the Refuel Platform
10 CFR 72.48 Screening Review, 0-SR-DCS3.1.2.1, High Storm Inspection log, attachment 1
10 CFR 72.48 Screening Review, DCN 64063A, Revised setpoint changes for radiation
monitors 2-R-90-142, 2-R-90-143, 3-R-90-142, 3-R-90-143
10 CFR 72.48 Screening Review, EDC 70586A, Use of HBF IAW Holtec CoC Amend. 5, Rev. 0
10 CFR 72.48 Screening Review, EDC 70586A, Use of HBF IAW Holtec CoC Amend. 5, Rev. 1
10 CFR 72.48 Screening Review, EPI-0-111-CRA009, Annual Inspection of Reactor Building
Crane, Rev. 000
10 CFR 72.48 Screening Review, MSI-0-079-DCS036, ISFSI Abnormal Conditions Procedure
10 CFR 72.48 Screening Review, MSI-0-079-DCS043, Dry Cask Campaign Review Program,
Rev. 1
10 CFR 72.48 Screening Review, MSI-0-079-DCS300.2, Alternate Cooling Water System
Operation, Rev. 3
10 CFR 72.48 Screening Review, MSI-0-079-DCS400.1, ISFSI Abnormal Conditions Procedure,
Placing the MPC in a Safe Condition
10 CFR 72.48 Screening Review, Work Order 1131655560
Certificate of Compliance No. 1014, Appendix B, Design Features for the HI-STORM 100 Cask
System, Section 3.6, Forced Helium Dehydration System, Amendment 5
Drawing 0-47E201, ISFSI Dry Storage Implementation Notes
Drawing 4838, Standard MPC Shell and Details for MPC24, 32, & 68
EDC 70586, Allow Use of the FHD and SCS to Enable the Storage of High Burnup Fuel in the
ISFSI, Rev. A
HOLTEC HI STORM 100 Cask System, Safety Evaluation Report, Amendment 1
MSI-0-079-DCS036, ISFSI Abnormal Conditions Procedure, Rev. 2
MSI-0-079-DCS200.1, Dry Cask Preparations and Start Up, Rev. 5
MSI-0-079-DCS200.2, MPC Loading and Transport Operations, Rev. 28
MSI-0-079-DCS300.10, Forced Helium Dehydration System Operation, Rev. 3
MSI-0-079-DCS300.11, Supplemental Cooling System Operation, Rev. 0
MSI-0-079-DCS300.2, Alternate Cooling Water System Operation, Rev. 3
MSI-0-079-DCS400.1, ISFSI Abnormal Conditions Procedure, Placing the MPC in a Safe
Condition, Rev. 3
MSI-0-079-DCS500.3, MPC Cooldown and Weld Removal, Rev. 3
MSI-0-079-DCS500.5, MPC Unloading Operations, Rev. 3
Work Order 1131655560
Corrective Action Documents Reviewed
PER 733056, UPTI Milestone Completion
PER 734268, UPTI Database Trending
PER 790632, Radwaste Discharge Pipe Leak Inspection
Corrective Action Documents Generated
SR 824118 Leaks
SR 824122 GPR
SR 824126 Programs
SR 824128 NACE SP0169
                                                                                Attachment


==Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion==
                                          8
: 2-AOP-99-1, Loss of Power to One RPS Bus, Rev. 27 and Rev. 29 2-OI-99, Reactor Protection System, Rev. 79 and Rev. 80
SR 824132 Soil Analysis
: LER 259, 260, 296/2011-003-02, Loss of Safety Function (SDC) Resulting from Emergency Diesel Generator Output Breaker Trip
SR 824136 Health Reporting
: LER 259/2009-002-01, Unexpected Logic Lockout of the Loop II Residual Heat Removal (RHR)
SR 824138 Pipe Location
: System Pumps
SR 824140 BP Manager
: LER 259/2009-004-01, High Pressure Core Injection found Inoperable during Condensate Header Level Switch Calibration and Functional Test
SR 824142 SBGT Pipe Repair
: LER 259/2010-003-03, Failure of a Low Pressure Coolant Injection Flow Control Valve
Procedure
: PER 660235, 3D EDG Units in Parallel with D EDG Failed PMTI
0-TI-364, ASME Section XI System Pressure Tests, Rev. 16
: PER 660862, U2 Scram while restarting 2B RPS using 2B RPS MG Set
0-TI-561, Underground Piping and Tanks Integrity Program (UPTI), Rev. 14
: PER 740259, RPS Scram, White Finding
0-TI-561, Underground Piping and Tanks Integrity Program (UPTI), Rev. 5
: Unit 1 FSAR
0-TI-561, Buried Piping Component Management Program (UPTI), Rev. 0
: Unit 1 Technical Specifications 3.5.1 and 3.8.1 
0-TI-623, Aging Management Program Basis Document for Buried Piping and Underground
: Attachment
Piping and Tanks, Rev. 0
2-SI-4.5.C.1(3), RHRSW Pump and Header Operability and Flow Test, Rev. 18
NPG-SPP-22.303, PER Analysis, Actions, Closures and Approvals, Rev. 1
NPG-SPP-09.15, Underground Piping and Tanks Integrity Program (UPTI), Rev. 6
NPG-SPP-09.16.1, System, Component and Program Health, Rev. 3
SI-GWT-100, Structural Integrity GWT Piping and Inspection General Procedure, Rev. 3
SI-GWT-103, Ultrasonic Thickness in Support of Guided Wave Testing (GWT), Rev. 1
Other Documents
Drawing # 0-17E300-8-23-13, Mechanical Isometric RHR Service Water Piping, Rev. 2
Drawing # 0-17E401-11, Mechanical Hardened Wetwell Vent Piping, Rev. 1
Drawing # 017W-9-67-1, Mechanical Isometric Emergency Equipment Cooling Water, Rev. 0
Drawing # 0-47E830-3-77-1, Flow Diagram Radwaste, Rev. 26
EPRI TR 1016456, Recommendations for an Effective Program to Control the Degradation of
Buried Pipe
Nuclear Energy Institute (NEI) 09-14, Guideline for the Management of Buried Piping Integrity,
Rev. 3
Program Health Report, 1/1/2013-6/30/2013
Program Health Report, 7/1/2012-12/31/2012
Report No. R06131219899, Radwaste Leak Inspection Report
Report No. R06121220058, Condition Assessment - Underground Piping and Tanks
Report No. R06131217892, Underground Piping and Tanks Inspection Plan, Rev. 5
Report No. BFN-ENG-F-10-002, Buried Piping Program Self-Assessment Report
Report No. 1200135.401, Structural Integrity Associates Report on GWT Excavation of
Radwaste Pipes
Report No. 04226.15, Underwater Construction Report on Condensate Storage Tank No. 1
Immersion Area In-Service Cleaning & Inspection
Report No. BFN-ENG-S-13-014, Self-Assessment of Buried Piping and Underground Piping
and Tanks
Report No. L2909128800, Benchmarking to Calloway Report
Report No. CRP-ENG-F-12-0002, TVA Fleet wide Piping and Tanks Inspection Program
Self-Assessment
Work Order No. 112816452, 2-SI-4.5.c.1(3) RHRSW Pump and Header Operability and Flow
Tests, 4/24/2012
                                                                                  Attachment


==Section 4OA5: Other Activities==
                              LIST OF ACRONYMS
: ISFSI Inspection 10
ADAMS - Agencywide Document Access and Management System
: CFR 72.212, Report of Evaluations, Rev. 5, dated 6/11/2012
ADS   - Automatic Depressurization System
: CFR 72.48 Screening Review, 0-GOI-100-3B, Manual Operation of the Refuel Platform 10
ARM   - area radiation monitor
: CFR 72.48 Screening Review, 0-SR-DCS3.1.2.1, High Storm Inspection log, attachment 1 10
CAD   - containment air dilution
: CFR 72.48 Screening Review,
CAP   - corrective action program
: DCN 64063A, Revised setpoint changes for radiation monitors 2-R-90-142, 2-R-90-143, 3-R-90-142, 3-R-90-143 10
CCW   - condenser circulating water
: CFR 72.48 Screening Review,
CFR   - Code of Federal Regulations
: EDC 70586A, Use of HBF IAW Holtec CoC Amend. 5, Rev. 0 10
CoC   - certificate of compliance
: CFR 72.48 Screening Review,
CRD   - control rod drive
: EDC 70586A, Use of HBF IAW Holtec CoC Amend. 5, Rev. 1
CS   - core spray
: CFR 72.48 Screening Review,
DCN   - design change notice
: EPI-0-111-CRA009, Annual Inspection of Reactor Building Crane, Rev. 000
EECW - emergency equipment cooling water
: CFR 72.48 Screening Review,
EDG   - emergency diesel generator
: MSI-0-079-DCS036, ISFSI Abnormal Conditions Procedure 10
FE   - functional evaluation
: CFR 72.48 Screening Review,
FPR   - Fire Protection Report
: MSI-0-079-DCS043, Dry Cask Campaign Review Program, Rev. 1
FSAR - Final Safety Analysis Report
: CFR 72.48 Screening Review,
IMC   - Inspection Manual Chapter
: MSI-0-079-DCS300.2, Alternate Cooling Water System Operation, Rev. 3
LER   - licensee event report
: CFR 72.48 Screening Review,
NCV   - non-cited violation
: MSI-0-079-DCS400.1, ISFSI Abnormal Conditions Procedure, Placing the MPC in a Safe Condition 10
NRC   - U.S. Nuclear Regulatory Commission
: CFR 72.48 Screening Review, Work Order
ODCM - Off-Site Dose Calculation Manual
: 1131655560
PER   - problem evaluation report
: Certificate of Compliance No. 1014, Appendix B, Design Features for the
PCIV - primary containment isolation valve
: HI-STORM 100 Cask System, Section 3.6, Forced Helium Dehydration System, Amendment 5 Drawing 0-47E201, ISFSI Dry Storage Implementation Notes Drawing 4838, Standard MPC Shell and Details for MPC24, 32, & 68
PI   - performance indicator
: EDC 70586, Allow Use of the FHD and SCS to Enable the Storage of High Burnup Fuel in the ISFSI, Rev. A
RCE   - Root Cause Evaluation
: HOLTEC HI STORM 100 Cask System, Safety Evaluation Report, Amendment 1
RCW   - Raw Cooling Water
: MSI-0-079-DCS036, ISFSI Abnormal Conditions Procedure, Rev. 2
RG   - Regulatory Guide
: MSI-0-079-DCS200.1, Dry Cask Preparations and Start Up, Rev. 5
RHR   - residual heat removal
: MSI-0-079-DCS200.2, MPC Loading and Transport Operations, Rev. 28
RHRSW - residual heat removal service water
: MSI-0-079-DCS300.10, Forced Helium Dehydration System Operation, Rev. 3
RTP   - rated thermal power
: MSI-0-079-DCS300.11, Supplemental Cooling System Operation, Rev. 0
RPS   - reactor protection system
: MSI-0-079-DCS300.2, Alternate Cooling Water System Operation, Rev. 3
RWP   - radiation work permit
: MSI-0-079-DCS400.1, ISFSI Abnormal Conditions Procedure, Placing the MPC in a Safe Condition, Rev. 3
SDP   - significance determination process
: MSI-0-079-DCS500.3, MPC Cooldown and Weld Removal, Rev. 3
SBGT - standby gas treatment
: MSI-0-079-DCS500.5, MPC Unloading Operations, Rev. 3
SLC   - standby liquid control
: Work Order
SNM   - special nuclear material
: 1131655560
SRV   - safety relief valve
: Corrective Action Documents Reviewed
SSC   - structure, system, or component
: PER 733056, UPTI Milestone Completion
TI   - Temporary Instruction
: PER 734268, UPTI Database Trending
TIP   - transverse in-core probe
: PER 790632, Radwaste Discharge Pipe Leak Inspection
TRM   - Technical Requirements Manual
: Corrective Action Documents Generated
TS   - Technical Specification(s)
: SR 824118 Leaks
UFSAR - Updated Final Safety Analysis Report
: SR 824122 GPR
URI   - unresolved item
: SR 824126 Programs
WO   - work order
: SR 824128 NACE SP0169 
                                                        Attachment
: Attachment
: SR 824132 Soil Analysis
: SR 824136 Health Reporting
: SR 824138 Pipe Location
: SR 824140 BP Manager
: SR 824142 SBGT Pipe Repair 
===Procedure===
: 0-TI-364, ASME Section XI System Pressure Tests, Rev. 16 0-TI-561, Underground Piping and Tanks Integrity Program (UPTI), Rev. 14
: 0-TI-561, Underground Piping and Tanks Integrity Program (UPTI), Rev. 5
: 0-TI-561, Buried Piping Component Management Program (UPTI), Rev. 0
: 0-TI-623, Aging Management Program Basis Document for Buried Piping and Underground Piping and Tanks, Rev. 0 2-SI-4.5.C.1(3), RHRSW Pump and Header Operability and Flow Test, Rev. 18
: NPG-SPP-22.303, PER Analysis, Actions, Closures and Approvals, Rev. 1
: NPG-SPP-09.15, Underground Piping and Tanks Integrity Program (UPTI), Rev. 6
: NPG-SPP-09.16.1, System, Component and Program Health, Rev. 3
: SI-GWT-100, Structural Integrity GWT Piping and Inspection General Procedure, Rev. 3
: SI-GWT-103, Ultrasonic Thickness in Support of Guided Wave Testing (GWT), Rev. 1 
===Other Documents===
: Drawing # 0-17E300-8-23-13, Mechanical Isometric RHR Service Water Piping, Rev. 2
: Drawing # 0-17E401-11, Mechanical Hardened Wetwell Vent Piping, Rev. 1 Drawing # 017W-9-67-1, Mechanical Isometric Emergency Equipment Cooling Water, Rev. 0 Drawing # 0-47E830-3-77-1, Flow Diagram Radwaste, Rev. 26
: EPRI
: TR 1016456, Recommendations for an Effective Program to Control the Degradation of Buried Pipe Nuclear Energy Institute (NEI) 09-14, Guideline for the Management of Buried Piping Integrity, Rev. 3 Program Health Report, 1/1/2013-6/30/2013
: Program Health Report, 7/1/2012-12/31/2012
: Report No. R06131219899, Radwaste Leak Inspection Report Report No. R06121220058, Condition Assessment - Underground Piping and Tanks Report No. R06131217892, Underground Piping and Tanks Inspection Plan, Rev. 5 Report No.
: BFN-ENG-F-10-002, Buried Piping Program Self-Assessment Report
: Report No. 1200135.401, Structural Integrity Associates Report on GWT Excavation of Radwaste Pipes Report No. 04226.15, Underwater Construction Report on Condensate Storage Tank No. 1
: Immersion Area In-Service Cleaning & Inspection Report No.
: BFN-ENG-S-13-014, Self-Assessment of Buried Piping and Underground Piping  and Tanks Report No. L2909128800, Benchmarking to Calloway Report Report No.
: CRP-ENG-F-12-0002, TVA Fleet wide Piping and Tanks Inspection Program Self-Assessment Work Order No.
: 112816452, 2-SI-4.5.c.1(3) RHRSW Pump and Header Operability and Flow Tests, 4/24/2012
==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]]
: [[RHR]] [[- residual heat removal]]
: [[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]]
: [[SLC]] [[- standby liquid control]]
: [[SNM]] [[- special nuclear material]]
: [[SRV]] [[- safety relief valve]]
: [[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]]
}}
}}

Latest revision as of 09:09, 4 November 2019

EA-14-005-IR 05000259-13-005, 05000260-13-005, 05000296-13-005, 10/01/2013 and 12/31/2013, Browns Ferry, Units 1, 2, and 3, Adverse Weather Protection, Licensed Operator Requalification...
ML14045A320
Person / Time
Site: Browns Ferry  Tennessee Valley Authority icon.png
Issue date: 02/14/2014
From: Croteau R
Division Reactor Projects II
To: James Shea
Tennessee Valley Authority
References
EA-14-005 IR-13-005
Download: ML14045A320 (47)
v • d • e


See also: IR 05000259/2013005

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION II

245 PEACHTREE CENTER AVENUE NE, SUITE 1200

ATLANTA, GEORGIA 30303-1257

February 14, 2014

EA-14-005

Mr. J.W. Shea

Vice President, Nuclear Licensing

Tennessee Valley Authority

1101 Market Street, LP 3D-C

Chattanooga, TN 37402-2801

SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION

REPORT 05000259/2013005, 05000260/2013005, AND 05000296/2013005,

PRELIMINARY WHITE FINDING AND APPARENT VIOLATIONS

Dear Mr. Shea:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Browns Ferry Nuclear Plant, Units 1, 2, and 3. On January 10 and 21, 2014,

the NRC inspectors discussed the results of this inspection with Mr. S. Bono and other

members of your staff. Inspectors documented the results of this inspection in the enclosed

inspection report.

Based on the results of this inspection, the report discusses a finding that has preliminarily been

determined to be a finding with low to moderate safety significance (White) that may require

additional inspections, regulatory actions, and oversight. As described in Section 1R11.2 of the

enclosed report, the licensees failure to maintain plant emergency response staffing levels in

accordance with NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency

Plan, was a performance deficiency. Specifically, the licensees process for maintaining

minimum emergency response shift staffing failed to adequately maintain staffing of the Shift

Technical Advisor (STA) and Incident Commander (IC) to ensure initial accident response in all

key functional areas. This finding did not present an immediate safety concern because the

licensee added additional staff to ensure they met the staffing requirements. This finding was

assessed based on the best available information, using the NRCs significance determination

process (SDP). The basis for the NRCs preliminary significance determination is described in

the enclosed report. The NRC will inform you in writing when the final significance has been

determined.

In addition, please be advised that the number and characterization of apparent violations

described in the enclosed inspection report may change as a result of further NRC review. You

will be advised by separate correspondence of the results of our deliberations on this matter.

Before the NRC makes a final decision on this matter, you may choose to (1) attend a

regulatory conference, where you can present to the NRC your point of view on the facts and

assumptions used to arrive at the finding and assess its significance, or (2) submit your position

on the finding to the NRC in writing. If you request a regulatory conference, it should be held

within 30 days of your receipt of this letter. We encourage you to submit supporting

J. Shea 2

documentation at least one week prior to the conference in an effort to make the conference

more efficient and effective. If you choose to attend a regulatory conference, it will be open for

public observation. The NRC will issue a public meeting notice and press release to announce

the conference. If you decide to submit only a written response, it should be sent to the NRC

within 30 days of your receipt of this letter. If you choose not to request a regulatory conference

or to submit a written response, you will not be allowed to appeal the NRCs final significance

determination.

The finding is also an apparent violation of NRC requirements and is being considered for

escalated enforcement action in accordance with the Enforcement Policy, which appears on the

NRCs Web site at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.

We intend to complete and issue our final safety significance determination within 90 days from

the date of this letter. The NRCs significance determination process is designed to encourage

an open dialogue between your staff and the NRC; however, the dialogue should not affect the

timeliness of our final determination.

The enclosed inspection report also discusses two apparent violations were identified and are

being considered for escalated enforcement action in accordance with the NRC Enforcement

Policy. The current Enforcement Policy is included on the NRCs Web site at

http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. As described in Section

1R11.2 of the enclosed report, two issues were identified that are being dispositioned using the

traditional enforcement process. The first, an apparent violation of 10 CFR 50.9, Completeness

and Accuracy of Information, was identified for the licensees apparent failure to provide the

NRC with complete and accurate information on two occasions when identifying the minimum

required shift staffing to the NRC. The second, an apparent violation of 10 CFR 50.90,

Amendment of License or Construction Permit at Request of Holder, was identified for the

licensee apparently making a change to a license condition without submitting an amendment

request. Both of these apparent violations were associated with the emergency response shift

staffing requirements to achieve safe shutdown during an appendix R fire.

Before the NRC makes its enforcement decision, we are providing you an opportunity to:

1) respond to the apparent violations addressed in this inspection report within 30 days of the

date of this letter; 2) request a Pre-decisional Enforcement Conference (PEC); or 3) request

Alternative Dispute Resolution (ADR). If a PEC is held, it will be open for public observation and

the NRC will issue a press release to announce the time and date of the conference. If you

decide to participate in a PEC or pursue ADR, please contact Jonathan Bartley at 404-997-4607

within 10 days of the date of this letter. A PEC should be held within 30 days and an ADR

session within 45 days of the date of this letter.

If you choose to provide a written response, it should be clearly marked as a Response to

Apparent Violations in NRC Inspection Report 05000259/2013005, 05000260/2013005, and

05000296/2013005; EA-14-005 and should include for each apparent violation: 1) the reason

for the apparent violation or, if contested, the basis for disputing the apparent violation; 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 previously docketed correspondence, if the correspondence adequately addresses

the required response. If an adequate response is not received within the time specified or an

extension of time has not been granted by the NRC, the NRC will proceed with its enforcement

decision or schedule a PEC.

J. Shea 3

If you choose to request a PEC, the conference will afford you the opportunity to provide your

perspective on these matters and any other information that you believe the NRC should take

into consideration before making an enforcement decision. The decision to hold a PEC does

not mean that the NRC has determined that a violation has occurred or that enforcement action

will be taken. This conference would be conducted to obtain information to assist the NRC in

making an enforcement decision. The topics discussed during the conference may include

information to determine whether a violation occurred, information to determine the significance

of a violation, information related to the identification of a violation, and information related to

any corrective actions taken or planned.

In lieu of a PEC, you may also request ADR with the NRC in an attempt to resolve this issue.

ADR is a general term encompassing various techniques for resolving conflicts using a third

party neutral. The technique that the NRC has decided to employ is mediation. Mediation is a

voluntary, informal process in which a trained neutral (the mediator) works with parties to help

them reach resolution. If the parties agree to use ADR, they select a mutually agreeable neutral

mediator who has no stake in the outcome and no power to make decisions. Mediation gives

parties an opportunity to discuss issues, clear up misunderstandings, be creative, find areas of

agreement, and reach a final resolution of the issues. Additional information concerning the

NRC's program can be obtained at http://www.nrc.gov/about-nrc/regulatory/enforcement/

adr.html. The Institute on Conflict Resolution (ICR) at Cornell University has agreed to facilitate

the NRCs program as a neutral third party. Please contact ICR at 877-733-9415 within 10 days

of the date of this letter if you are interested in pursuing resolution of these issues through ADR.

Please contact Jonathan Bartley at (404) 997-4607, 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. Because the NRC has

not made a final determination in this matter, no notice of violation is being issued for this

inspection finding at this time. In addition, please be advised that the number and

characterization of the apparent violations may change based on further NRC review.

NRC inspectors also documented two findings of very low safety significance (Green) in this

report. Both of these findings involved violations of NRC requirements. Additionally, NRC

inspectors documented a Severity Level IV violation with no associated finding.

Further, inspectors documented a licensee-identified violation which was determined to be of

very low safety significance in this report. The NRC is treating this violation as a non-cited

Violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violation or significance of these NCVs, you should provide a response within

30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with

copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector

at the Browns Ferry Nuclear Plant.

In addition, if you disagree with a cross-cutting aspect assignment in this report, you should

provide a response within 30 days of the date of this inspection report, with the basis for your

disagreement, to the Regional Administrator, Region II, and the NRC resident inspector at the

Browns Ferry Nuclear Plant.

J. Shea 4

As a result of the Safety Culture Common Language Initiative, the terminology and coding of

cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting

aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting

aspects identified in the last six months of 2013 using the previous terminology will be converted

to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-

cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-

cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment

review.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections,

Exemptions, Requests for Withholding, of the NRCs Rules of Practice, a copy of this letter, its

enclosure, and your response (if any), will be available electronically for public inspection in the

NRCs Public Document Room or from the Publicly Available Records (PARS) component of the

NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public

Electronic Reading Room). To the extent possible, your response should not include any

personal privacy, proprietary, or safeguards information so that it can be made available to the

Public without redaction.

Sincerely,

/RA/

Richard P. Croteau, Director

Division of Reactor Projects

Docket Nos.: 50-259, 50-260, 50-296

License Nos.: DPR-33, DPR-52, DPR-68

Enclosure: NRC Integrated Inspection Report 05000259/2013005,

05000260/2013005 and 05000296/2013005

cc distribution via ListServ

_ ML14045A320____________ SUNSI REVIEW COMPLETE FORM 665 ATTACHED

OFFICE RII:DRP RII:DRP RII:DRP RII:DRS RII:DRP RII:DRP RII:DRS

SIGNATURE /VIA By E-mail/ /VIA By E-mail/ /VIA By E-mail/ /VIA By E-mail/ /VIA By E-mail/ /VIA By E-mail/

NAME DDumbacher LPressley TStephen ASengupta CKontz MRiches RBaldwin

DATE 2/1/1/2014 2/13/2014 2/12/2014 2/10/2014m 2/10/2014 2/11/2014 2/11/2014

E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO

OFFICE RII:EICS RII:DRP RII:DRP RII:DRP

SIGNATURE /RA/ /VIA By E-mail/ /RA/ /RA/

NAME CEvans JBartley WJones RCroteau

DATE /2/14/2014 2/14/2014 2/14/2014 2/14/2014

E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO

J. Shea 5

Letter to Joseph W. Shea from Richard P. Croteau dated February 14, 2014.

SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION

REPORT 05000259/2013005, 05000260/2013005, AND 05000296/2013005,

PRELIMINARY WHITE FINDING AND APPARENT VIOLATIONS

Distribution:

C. Evans, RII

L. Douglas, RII

OE Mail

RIDSNRRDIRS

PUBLIC

RidsNrrPMBrownsFerry Resource

U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos.: 50-259, 50-260, 50-296

License Nos.: DPR-33, DPR-52, DPR-68

Report Nos.: 05000259/2013005, 05000260/2013005, 05000296/2013005

Licensee: Tennessee Valley Authority (TVA)

Facility: Browns Ferry Nuclear Plant, Units 1, 2, and 3

Location: Corner of Shaw and Nuclear Plant Road

Athens, AL 35611

Dates: October 1, 2013, through December 31, 2013

Inspectors: D. Dumbacher, Senior Resident Inspector

L. Pressley, Resident Inspector

T. Stephen, Resident Inspector

A. Sengupta, Reactor Inspector

C. Kontz, Senior Project Engineer

M. Riches, Project Engineer

R. Baldwin, Senior Operations Engineer

Approved by: Jonathan H. Bartley, Chief

Reactor Projects Branch 6

Division of Reactor Projects

Enclosure

SUMMARY

IR 05000259/2013005, 05000260/2013005, 05000296/2013005; 10/01/2013-12/31/2013;

Browns Ferry Nuclear Plant, Units 1, 2 and 3; Adverse Weather Protection, Licensed Operator

Requalification and Performance, Problem Identification and Resolution, and Follow Up of

Events and Notices of Enforcement Discretion.

The report covered a three month period of inspection by the resident inspectors and four

regional inspectors. The significance of most findings is identified by their color (Green, White,

Yellow, and Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination

Process (SDP); and, the cross-cutting aspects were 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.

NRC Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Criterion V, Procedures, for the licensees failure to implement 0-GOI-200-1, Freeze

Protection Inspection. Specifically, the licensee failed to enter freeze protection

discrepancies into the corrective action program as part of the Freeze Protection

Discrepancy List per 0-GOI-200-1 for the residual heat removal service water (RHRSW)

and emergency equipment cooling water (EECW) systems. As a corrective action, the

licensee entered the required deficiencies onto the Freeze Protection Discrepancy List.

The licensee has entered this issue into their corrective action program as problem

evaluation reports 800190 and 821426.

The finding was more than minor because, if left uncorrected, the performance

deficiency would have the potential to lead to a more significant safety concern, in that

the intake room piping would continue to be exposed to freezing temperatures without

adequate freeze protection which could affect RHRSW and EECW systems ability to

perform their safety functions. The inspectors performed a Phase 1 screening in

accordance with IMC 0609, Significance Determination Process, Appendix A, Exhibit 1,

Initiating Event screening question E, and determined the finding was of very low safety

significance (Green) because it did not impact the frequency of an internal flooding

event. The cause of this finding has a cross-cutting aspect in the Work Practices

component of the Human Performance area, because the licensee failed to define and

effectively communicate expectations regarding procedural compliance and that

personnel follow procedures. H.4(b) (Section 1R01)

Enclosure

3

Cornerstone: Mitigating Systems

Criterion III, Design Control, for the licensees failure to establish measures to ensure the

EDG floor drains maintained the capability of performing their intended function as

described their design basis. The licensees immediate corrective action was to clean all

the drains in all the EDG rooms. The licensee has entered this issue into their corrective

action program as problem evaluation report 765575.

The finding was more than minor because, if left uncorrected, the performance

deficiency would have the potential to lead to a more significant safety concern, in that,

the EDG room floor drains could become sufficiently clogged such that internal flooding

would cause the affected EDG to be unable to perform its safety function. The

inspectors performed a Phase 1 screening in accordance with IMC 0609, Significance

Determination Process, Appendix A, Exhibit 1, Initiating Event screening question E, and

determined the finding was of very low safety significance (Green) because it did not

impact the frequency of an internal flooding event. This finding has a cross-cutting

aspect in the area of Problem Identification and Resolution, Corrective Action Program

Component, because TVA did not identify floor drain issues completely, accurately, and

in a timely manner commensurate with their safety significance. [P.1 (a)] (Section

4OA2.3)

Cornerstone: Emergency Preparedness

for the licensees failure to maintain plant staffing levels in accordance with NP-REP,

Tennessee Valley Authority Nuclear Power Radiological Emergency Plan. Specifically,

the licensees process for maintaining minimum emergency response shift staffing failed

to adequately maintain staffing of the Shift Technical Advisor (STA) and Incident

Commander to ensure initial accident response in all key functional areas. The licensee

has entered this issue into their corrective action program as PERs 790092 and 801057.

The inspectors determined the performance deficiency was more than minor because it

was associated with the ERO readiness attribute of the emergency preparedness

cornerstone and adversely impacted the cornerstone objective of ensuring that the

licensee is capable of implementing adequate measures to protect the health and safety

of the public in the event of a radiological emergency. Specifically, the failure to

maintain required emergency response staffing levels reduced the licensees capabilities

to respond to an emergency. The inspectors assessed the finding in accordance with

Appendix B, Emergency Preparedness Significance Determination Process and

determined that this finding represented a Loss of Planning Standard Function and has

preliminarily been determined to be a finding of White significance. Because the

significance of this finding is not yet finalized, it is being characterized as To Be

Determined (TBD), pending a final significance determination. The cause of the finding

was determined to be associated with the cross-cutting aspect of thorough evaluation of

problems in the corrective action component of the problem identification and resolution

area because the licensee failed to ensure that issues potentially affecting nuclear safety

were thoroughly evaluated. P.1(c) (Section 1R11.2.b(1))

Enclosure

4

Other

  • TBD: The NRC identified two examples of an Apparent Violation of 10 CFR 50.9,

Completeness and accuracy of information, for the licensees apparent failure to

provide complete and accurate information associated with emergency response on-shift

staffing requirements. Specifically, on two occasions the licensee apparently provided

inaccurate information to the NRC concerning onsite emergency response organization

minimum staffing requirements. The licensee augmented on-shift staffing levels on

October 30, 2013. These issues were entered into the Browns Ferry corrective action

program as PERs 790109, 790092, and 801057.

These apparent violations had the potential to impede or impact the regulatory process,

and therefore subject to traditional enforcement as described in the NRC Enforcement

Policy, dated July 9, 2013. Because these apparent violations involved the traditional

enforcement process with no underlying technical violation that would be considered

more than minor in accordance with IMC 0612, a cross-cutting aspect was not assigned

to this violation. (Section 1R11.2.b(2))

  • TBD: The NRC identified an apparent violation (AV) of 10 CFR 50.90, Application for

Amendment of License, Construction Permit, or Early Site Permit for the licensees

apparent failure to submit an application requesting an amendment to their operating

license concerning on-shift staffing levels. The licensee augmented on-shift staffing

levels on October 30, 2013. The issue was entered into the Browns Ferry corrective

action program as PERs 790109 and 801057.

This apparent violation had the potential to impede or impact the regulatory process, and

therefore was subject to traditional enforcement as described in the NRC Enforcement

Policy, dated July 9, 2013. Because this apparent violation involved the traditional

enforcement process with no underlying technical violation that would be considered

more than minor in accordance with IMC 0612, a cross-cutting aspect was not assigned

to this violation. (Section 1R11.2.b(3))

  • Severity Level IV: The NRC identified a non-cited violation (NVC) of 10 CFR

50.73(a)(2)(i)(B) for the licensees failure to submit a License Event Report (LER) for a

condition prohibited by plant technical specifications within 60 days of the event. The

licensee entered this issue into their corrective action program as Problem Event Report

796578. LER 50-259 2013-006-00 was submitted on December 4, 2013.

The failure to make reports to the NRC as required by 10 CFR 50.73(a)(2)(i)(B)

impacted the regulatory process and was a violation of NRC requirements. The violation

was processed using traditional enforcement and determined to be a Severity Level IV

violation consistent with NRCs Enforcement Policy section 6.9.d.9, Inaccurate and

Incomplete Information or Failure to Make a Required Report. Because this violation

involved the traditional enforcement process with no underlying technical violation that

would be considered more than minor in accordance with IMC 0612, a cross-cutting

aspect was not assigned to this violation. (Section 4OA3.7)

Enclosure

5

Licensee Identified Violations

  • A violation of very low safety significance affecting the Barrier Integrity cornerstone that

was identified by the licensee has been reviewed by the NRC. Corrective actions taken

or planned by the licensee have been entered into the licensees corrective action

program. This violation and corrective action tracking number are listed in Section 4OA7

of this report.

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at 100 percent of rated thermal power (RTP) except for one planned

downpower on December 14, 2013, for an oil addition to the 1B recirculation pump. Power

remained at 100 percent RTP for the remainder of the quarter.

Unit 2 operated at 100 percent RTP except for three planned downpowers, November 16, 2013,

for troubleshooting on the 2B3 feedwater heater, November 21, 2013, for repairs to the 2B3

feedwater heater, and December 6, 2013, for repairs to the 2A3 and 2C3 feedwater heaters.

On October 12, 2013, an unplanned power reduction to 78 percent RTP occurred as a result of

a recirculation pump runback caused by the failure of the main steam line and reactor feedwater

flow indicators. Power remained at 100 percent RTP for the remainder of the quarter.

Unit 3 operated at 100 percent RTP except for a planned downpower on October 4, 2013, for

repairs to the 3C3 feedwater heater and to replace a power supply on the 3B reactor feed pump

governor control circuit. Power remained at 100 percent RTP for the remainder of the quarter.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

Prior to and during the onset of cold weather conditions, the inspectors reviewed the

licensees implementation of 0-GOI-200-1, Freeze Protection Inspection, including

applicable checklists: Attachment 1, Freeze Protection Annual Checklist; Attachment 2,

Freeze Protection Operational Checklist; and as applicable, Attachments 3 through 12,

Freeze Protection Daily Log Sheets for individual watch stations. The inspectors also

reviewed the list of open FZ-coded Work Orders and 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 the main

control rooms, residual heat removal service water (RHRSW) and emergency equipment

cooling water (EECW) pump rooms, and all units emergency diesel generator (EDG)

buildings, to verify that affected systems and components were properly configured and

protected as specified by the procedure. The inspectors discussed cold weather

conditions with Operations personnel to assess plant equipment conditions and

personnel sensitivity to upcoming cold weather conditions. This constituted one

Readiness for Seasonal Extreme Weather sample. Documents reviewed are listed in

the Attachment.

Enclosure

7

b. Findings

Introduction: The NRC identified a Green non-cited violation (NCV) of 10 CFR 50,

Appendix B, Criterion V, Procedures, for the licensees failure to implement 0-GOI-200-

1, Freeze Protection Inspection. Specifically, the licensee failed to enter freeze

protection discrepancies into the corrective action program (CAP) as part of the Freeze

Protection Discrepancy List per 0-GOI-200-1 for the RHRSW and EECW systems.

Description: On October 24, 2013, NRC inspectors identified piping insulation removed

and heat trace wires disconnected on multiple RHRSW and EECW pipes at the Browns

Ferry plant intake rooms. These rooms have no roof and are exposed to outside

conditions. Licensee procedure 0-GOI-200-1, Freeze Protection Inspection, required

completion of Attachment 1, Freeze Protection Annual Checklist, by October 1, 2013.

This checklist requires the performance of general area inspections of the RHRSW

Pump Rooms, per Appendix A, section 4.0, General Area Checks Guideline, which

included verification that heat trace circuits were functioning and insulation was installed

on all piping and instrument lines. 0-GOI-200-1, Annual Check List had not been

completed as of October 24, 2013.

Subsequently, on December 13, 2013, NRC inspectors observed that heat trace circuits

in the RHRSW rooms did not have insulation covering the heat trace tape and no

compensatory measures were in place to prevent pipe freezing. Temperatures earlier

that week had routinely decreased below 25 degrees Fahrenheit (F) each night. Area

temperatures had started dropping below 25 degrees F on November 13, 2013.

Section 5.0, Step 3.1 of 0-GOI-200-1, required outstanding discrepancies following

completion of Attachment 1 to be evaluated and verification that a Service Request

(SR)/Work Order (WO) with the term FZ in the narrative details section for the Focus

Area have been initiated. Step 3.2 required that if compensatory measures were

required that they be added to the Operator Work Around list.

Attachments 3 and 4, of 0-GOI-200-1, Freeze Protection Daily Log Sheets, were

required to be performed when outside ambient temperature dropped below 25 degrees

F or stayed below 32 degrees F for an 8-hour period. Both attachments required area

inspections of the RHRSW Pump Rooms, per Appendix A, section 4.0, General Area

Checks Guideline. Discrepancies identified during area inspection were required to be

recorded on Appendix B, Freeze Protection Remarks Log, and a SR/WO be initiated

with the term FZ in the narrative details section or verified already in Freeze Protection

Discrepancy List (MAXIMO Focus Area FZ).

The inspectors noted that the missing insulation was not documented in the Annual

Checklist or the Daily Log Sheets, nor was it included in the Official Freeze Protection

Discrepancy List.

The inspectors noted that the operators performing Freeze Protection Daily Logs were

not being provided or using Appendix A & B during the performance of the procedure.

On November 27, 2013, the licensee entered the insulation and non-working heat trace

deficiencies in the Official Freeze Protection Discrepancy List. In response to NRC

Enclosure

8

questioning, the licensee performed a prompt operability review. This review

documented that, on all four trains, over 80 feet of piping was missing insulation. The

operability review stated that a break in piping due to freezing could overwhelm the

RHRSW compartment sump pumps resulting in the failure of all three RHRSW pumps in

that particular room. Additionally the review noted that the heat trace design calculation,

MDQ0023880058, assumed that insulation is always installed and is required for heat

trace functionality. The licensees operability review concluded that past operability was

maintained and on December 18, 2013, the licensee installed compensatory measures

including heaters and tarpaulin.

Analysis: The inspectors determined that the failure to enter freeze protection

discrepancies into the CAP as part of the Freeze Protection Discrepancy List per 0-GOI-

200-1, Freeze Protection Inspection, was a performance deficiency. Specifically, the

licensee failed to document missing insulation on the RHRSW and EECW systems in

accordance with Appendix B and Section 5.0 of 0-GOI-200-1. The finding is associated

with the Initiating Events cornerstone. The finding was more than minor because, if left

uncorrected, the performance deficiency would have the potential to lead to a more

significant safety concern, in that the intake room piping would continue to be exposed to

freezing temperatures without adequate freeze protection which could affect RHRSW

and EECW systems ability to perform their safety functions. The inspectors performed

a Phase 1 screening in accordance with IMC 0609, Significance Determination Process,

Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding

was of very low safety significance (Green) because it did not impact the frequency of an

internal flooding event. The cause of this finding has a cross-cutting aspect in the Work

Practices component of the Human Performance area, because the licensee failed to

define and effectively communicate expectations regarding procedural compliance and

that personnel follow procedures. H.4(b).

Enforcement: Title 10 CFR 50, Appendix B, Criterion V, Procedures, requires, in part,

that activities affecting quality shall be prescribed by documented instructions,

procedures, or drawings and shall be accomplished in accordance with these

instructions, procedures and drawings. Browns Ferry procedure 0-GOI-200-1, Freeze

Protection Inspection, is a quality related procedure which verified freeze protection on

RHRSW and EECW pumps and associated components to ensure that they will operate

at below freezing temperatures. Appendix B and Section 5.0 required documentation of

freeze protection discrepancies in the CAP as part of the Freeze Protection Discrepancy

List. Contrary to the above, between November 13, 2013, and November 27, 2013, the

licensee failed to accomplish activities affecting quality in accordance with procedures.

Specifically, the licensee failed to document missing insulation on the RHRSW and

EECW systems in the CAP as part of the Freeze Protection Discrepancy List as required

by procedure 0-GOI-200-1. As a result, the required heaters and tarpaulin were not

installed until December 18, 2013. On November 27, 2013, the licensee entered the

insulation and non-working heat trace deficiencies in the Official Freeze Protection

Discrepancy List. This violation is being treated as a non-cited violation (NCV),

consistent with Section 2.3.2 of the NRC Enforcement Policy. The violation was entered

into the licensees corrective action program as PERs 800190 and 821426. (NCV 05000259/2013005-01, Failure to Document Service Water Freeze Protection

Deficiencies)

Enclosure

9

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

The inspectors conducted 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, Updated Final Safety Analysis Report (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.

This activity constituted four Equipment Alignment Partial Walkdown inspection samples.

Documents reviewed are listed in the Attachment.

  • October 15, 2013, Unit 2 core spray (CS) system - Division I
  • October 23, 2013, Common switchyard with Bus 2 out of service

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Fire Protection Tours

a. Inspection Scope

The inspectors reviewed licensee procedures for transient combustibles and fire

protection impairments, and conducted a walkdown of the fire areas (FAs) and fire zones

(FZs) 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. The inspectors verified that selected fire protection

impairments were identified and controlled in accordance with procedures. Furthermore,

the inspectors reviewed applicable portions of the Fire Protection Report, Volumes 1 and

2, including the applicable Fire Hazards Analysis, 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. This activity constituted six Fire

Protection Walkdown inspection samples. Documents reviewed are listed in the

Attachment.

Enclosure

10

  • October 1, 2013, Unit 1 Reactor Building, EL 639 feet (Fire Zone 1-6)
  • October 1, 2013, Unit 2 Reactor Building South East Quad EL 519 feet and 541 feet

(Fire Zone 2-2)

  • October 2, 2013, Unit 2 Reactor Building, EL 621 feet 2A Electrical Board Room

(Fire Area 9)

  • October 2, 2013, Unit 2 Reactor Building, EL 621 feet 480V Shutdown board Room

2A (Fire Area 10)

  • October 2, 2013, Unit 2 Reactor Building, EL 621 feet 480V Shutdown board Room

2B (Fire Area 11)

  • November 5, 2013, Intake Pumping Station Cable Tunnel (Fire Zone 25-3)

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification and Performance

.1 Licensed Operator Requalification

a. Inspection Scope

On October 15, 2013, the inspectors observed an as-found licensed operator

requalification for an operating crew according to Unit 2 Simulator Exercise Guide (SEG)

OPL173.R227, Anticipated Transient without Scram (ATWS), and Various Technical

Specification entries.

The inspectors specifically evaluated the following attributes related to the 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 procedures including Abnormal Operating

Instructions (AOIs), Emergency Operating Instructions (EOIs) and Safe Shutdown

Instructions (SSI)

  • Timely control board operation and manipulation, including high-risk operator actions
  • Timely oversight and direction provided by the shift supervisor, including ability to

identify and implement appropriate TS actions such as reporting and emergency plan

actions and notifications

  • Group dynamics involved in crew performance

The inspectors assessed the licensees ability to administer testing and assess the

performance of their licensed operators. The inspectors attended the post-examination

critique performed by the licensee evaluators, and verified 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

Enclosure

11

reference plant control room, such as physical location of panels, equipment,

instruments, controls, labels, and related form and function). This activity constituted

one Observation of Requalification Activity inspection sample. Documents reviewed are

listed in the Attachment.

b. Findings

No findings were identified.

.2 Control Room Observations

a. Inspection Scope

Inspectors observed and assessed licensed operator performance in the plant and main

control room, particularly during periods of heightened activity or risk and where the

activities could affect plant safety. Inspectors reviewed various licensee policies and

procedures covering Conduct of Operations, Plant Operations, and Power Maneuvering.

The inspectors utilized activities such as post maintenance testing, surveillance testing

and other activities to focus on the following conduct of operations as appropriate;

  • Operator compliance and use of procedures.
  • Control board manipulations.
  • Communication between crew members.
  • Use and interpretation of plant instruments, indications, and alarms.
  • Use of human error prevention techniques.
  • Documentation of activities, including initials and sign-offs in procedures.
  • Supervision of activities, including risk and reactivity management.
  • Pre-job briefs.

This activity constituted one Control Room Observation inspection sample.

b. Findings and Violations

(1) Failure To Maintain Emergency Response Staffing Levels

Introduction: The NRC identified an apparent violation of 10 CFR 50.54(q), Emergency

Plans, for the licensees failure to maintain plant staffing levels in accordance with

NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan.

Specifically, the process for maintaining emergency staffing requirements included

implementation of the requirements of OPDP-1, Conduct of Operations, which identified

the required on-shift staffing levels. However, this procedure was found to be

inadequate to maintain shift staffing in compliance with the NP-REP for both the Shift

Technical Advisor (STA) and Incident Commander positions.

Enclosure

12

Description: On November 15, 2006, the licensee submitted license amendment

requests (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) units 1, 2 and 3,

respectively. The LARs were submitted as part of the restart effort associated with Unit

1. In part, the LARs identified the minimum staffing levels necessary to ensure safe

shutdown can be achieved on the three operating units during an Appendix R fire, which

were one Shift Manager (SM), four Unit Supervisors (US), six Reactor Operators (ROs),

eight Assistant Unit Operators (AUOs), and one Shift Technical Advisor. The LARs

indicated that the stated staffing levels were required once Unit 1 achieved Mode 2 of

reactor operations, which occurred on May 21, 2007.

These staffing levels met the minimum on-shift facility staffing requirements defined in

Figure A-1, Site Emergency Organization, of Appendix A, Browns Ferry Nuclear Plant,

contained in revision 84 (dated February 17, 2007) of NP-REP, which required one SM,

one US for each unit, two ROs for each unit, two AUOs for each unit, and one STA. The

on-shift levels delineated in Figure A-1 have remained unchanged for the STA since

revision 84 of NP-REP. NP-REP Revision 100, dated December 21, 2012, added the

Incident Commander to the Figure A-1 as a required on-shift position.

In July 2013, inspectors questioned the licensee on how the safe shutdown actions for

an Appendix R fire could be implemented with a US that was also performing the

emergency response actions assigned to the STA function during a fire event. Initially,

the licensee stated that one of the other US would implement the safe shutdown actions

on both his assigned unit and the unit with the US that was fulfilling the STA function.

The inspectors questioned how one US could implement the safe shutdown actions on

two units simultaneously. The licensee stated that they could provide a staffing study

that supported the current staffing levels.

On October 3, 2013, the licensee notified the NRC via Event Notification (EN) 49406 that

the site was in an unanalyzed condition. In the event of an Appendix R fire in the

Control Bay, the current level of operations shift staffing would not be adequate to

perform all the actions in the SSIs to ensure safe shutdown of the units; specifically one

of the units would be without a US to direct the actions of the SSI. The licensee entered

the issue into corrective action program (CAP) via Problem Evaluation Report (PER)

790092. The licensee took actions to place a dedicated Incident Commander on shift for

each of the shifts that was either a licensed SRO, certified SRO or licensed RO that had

successfully completed BFN Incident Commander Training. Following further

investigation, the licensee determined that shift staffing on all three units was still not in

compliance with the license conditions for fire protection as contained in LARs 271, 300

and 259. On October 30, 2013, the licensee entered this issue into the CAP via PER

801057 and took the immediate corrective action to ensure five licensed SROs were

verified on shift and initiated actions to revise the Standing Order on minimum SSI

staffing to require five licensed SROs on each shift. The licensees root cause analysis

determined that between February 11, 2008, and July 8, 2012, twenty-six PERs relating

to operations staffing were written. All of the PERs resulted in a determination that

staffing levels were adequate.

Enclosure

13

The inspectors reviewed NP-REP, Tennessee Valley Authority Nuclear Power

Radiological Emergency Plan, revision 100. Figure A-1, Site Emergency Organization,

in Appendix A of NP-REP required that both an STA and a US are part of the required

manning during an emergency on an affected unit. For the unaffected units, a US is

required on each of the unaffected units with an exception for units sharing a common

control area. In the case of an Appendix R fire, all three units are affected which would

require three US and an STA be staffed. The inspectors determined that since May 21,

2007, when Unit 1 entered Mode 2, to the present, the licensee could not meet the

staffing requirements of NP-REP during any Appendix R fire on any of the three units.

The inspectors also identified that beginning with NP-REP Revision 100, dated

December 21, 2012, an Incident Commander position was added to the Figure A-1 as a

required on-shift position, but no process was implemented to ensure it was continually

staffed.

The process for maintaining emergency staffing requirements includes implementation

of the requirements of OPDP-1, Conduct of Operations, which identified the required on-

shift staffing levels. This procedure was found to be inadequate to maintain shift staffing

in compliance with the NP-REP for both the STA and Incident Commander positions.

Analysis: The licensees failure to maintain plant staffing levels in accordance with NP-

REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan was a

performance deficiency. Specifically, the licensees process for maintaining minimum

emergency response shift staffing failed to adequately maintain staffing of the STA and

Incident Commander to ensure initial accident response in all key functional areas. The

inspectors determined the performance deficiency was more than minor because it was

associated with the ERO readiness attribute of the emergency preparedness

cornerstone and adversely impacted the cornerstone objective of ensuring that the

licensee is capable of implementing adequate measures to protect the health and safety

of the public in the event of a radiological emergency. Specifically, the failure to

maintain required emergency response staffing levels reduced the licensees capabilities

to respond to an emergency. The inspectors assessed the finding in accordance with

Appendix B, Emergency Preparedness Significance Determination Process, (February

24, 2012) of IMC 0609, Significance Determination Process, and using Table 5.2-1 -

Significance Examples §50.47(b)(2), determined that this finding represented a process

for on-shift staffing that would allow 2 or more shifts to go below E-plan minimum staffing

requirements. Specifically, the inspectors determined that the licensees process failed

to ensure shift staffing met E-plan minimum staffing requirements for a period of over 6

years. This corresponded to a Loss of Planning Standard Function and has preliminarily

been determined to be a finding of White significance.

Because the licensee has taken immediate corrective actions to increase staffing levels

consistent with the emergency plan, this issue does not represent an immediate safety

concern. Because the significance of this finding is not yet finalized, it is being

characterized as To Be Determined (TBD), pending a final significance determination.

Enclosure

14

The cause of the finding was determined to be associated with the cross-cutting aspect

of thorough evaluation of problems in the corrective action component of the problem

identification and resolution area because the licensee failed to ensure that issues

potentially affecting nuclear safety were thoroughly evaluated. P.1(c)

Enforcement: 10 CFR 50.54(q) requires, in part, that a holder of a license under Part 50

shall follow and maintain the effectiveness of the emergency plan that meets the

planning standards of 10 CFR 50.47. 10 CFR 50.47(b)(2) states, in part, that adequate

staffing to provide initial facility accident response in key functional areas is maintained

at all times. NP-REP, Tennessee Valley Authority Nuclear Power Radiological

Emergency Plan, of Appendix A, Figure A-1, Site Emergency Organization, Browns

Ferry Nuclear Plant, defined the emergency plan staffing requirements for key functional

areas including the staffing of a Shift Technical Advisor and Incident Commander.

From May 21, 2007, through October 30, 2013, the licensee failed to follow and maintain

the effectiveness of an emergency plan that met the planning standards of 10 CFR

50.47 when the licensee did not ensure adequate staffing to provide initial facility

accident response in key functional areas was maintained at all times. Specifically, the

licensees process for maintaining minimum emergency response shift staffing failed to

ensure continuous staffing of emergency response roles as defined in NP-REP,

Tennessee Valley Authority Nuclear Power Radiological Emergency Plan as evidenced

by the following examples:

  • Failure to continuously staff the STA position beginning May 21, 2007
  • Failure to continuously staff the Incident Commander position beginning

December 21, 2012

The licensee augmented on-shift staffing levels on October 30, 2013, and entered this

issue into the corrective action program (CAP) as PERs 790092 and 801057. Pending

determination of the findings final safety significance, this finding is identified as AV

05000259, 260, 296/2013005-02, Failure to Maintain Emergency Response Staffing

Levels.

(2) Inaccurate Information Provided Concerning Onsite Emergency Response Organization

Staffing Requirements

Introduction: Two examples of an NRC-identified apparent violation of 10 CFR 50.9,

Completeness and accuracy of information, were identified for the licensees apparent

failure to provide complete and accurate information associated with emergency

response on-shift staffing requirements. Specifically, on two occasions the licensee

apparently provided inaccurate information to the NRC concerning onsite emergency

response organization minimum staffing requirements.

Description: On November 15, 2006, TVA submitted license amendment requests

(LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) Units 1, 2 and 3, respectively.

The LARs were submitted as part of the restart effort associated with Unit 1. In part, the

LARs identified the minimum staffing levels necessary to ensure that safe shutdown can

be achieved on the three operating units during an Appendix R fire. The LARs stated

Enclosure

15

that the minimum staffing levels were one Shift Manager (SM), four Unit Supervisors

(US), six Reactor Operators (ROs), eight Assistant Unit Operators (AUOs), and one Shift

Technical Advisor. The LARs indicated that the stated staffing levels were required once

Unit 1 achieved Mode 2 of reactor operations, which occurred on May 21, 2007.

On January 10, 2007, the licensee issued revision 7 of OPDP-1, Conduct of Operations,

which identified the required on-shift staffing levels to be one SM, three US, six ROs,

eight AUOs and one STA with the STA function allowed to be filled by one of the on-shift

US. This change decreased the required staffing levels for on-shift Unit Supervisors

from 4 to 3, and allowed the STA position to be filled by one of the on-shift US. This was

not sufficient to meet the required staffing levels submitted in the LARs required prior to

reaching Mode 2 on Unit 1.

In the safety evaluation dated April 25, 2007 (ADAMS Accession Number ML 071160431), the NRC documented that the licensee conveyed to NRC staff that the

appropriate procedures had been revised to reflect the increase in staffing levels

contained in the LARs. On April 25, 2007, the NRC approved the LARs for all three

units.

On February 17, 2010, the licensee determined that the guidance provided in OPDP-1

for minimum on-shift staffing did not meet the staffing levels submitted in LARs 271, 300,

and 259. On May 13, 2010, the licensee notified the Region II Regional Administrator

(RA), via a conference call, of the issue and in a follow-up letter dated June 29, 2010,

the licensee informed the RA that they did not meet the requirements of their licensing

basis. However, the licensee also stated that they had completed a staffing assessment

and determined that the current minimum staffing levels contained in OPDP-1 (i.e., three

US with one US filling the STA function) were adequate for successful implementation of

all safe shutdown actions for the bounding Appendix R fire scenario. On November 30,

2011, the licensee submitted in Summary Report for 10 CFR 50.59 Evaluations, Fire

Protection Report Technical Specification Bases Changes, Technical Requirements

Manual Changes, and NRC Commitment Revision to change to the staffing level

requirements in which they again provided information of their assessment and change

to their required staffing levels.

On September 06, 2013, the licensee initiated a self-assessment entitled Operations

Department Staffing Levels. The assessment evaluated three different scenarios:

1) Loss of Coolant Accident (LOCA) with a simultaneous Loss of Offsite Power (LOOP);

2) Fire in the Control Bay (Fire Area 16) that requires entry into the Safe Shutdown

Instructions (SSIs), specifically 0-SSI-16; and 3) a Beyond Design Basis External Event

postulated in response to the Fukushima Daiichi accident. The assessment assumed

that shift staffing levels were at the minimum required by OPDP-1, revision 7. The self-

assessment concluded that the current minimum staffing levels would not be sufficient to

perform all the required actions in the event of a fire in the Control Bay (Event 2). The

assessment contained a simplified time motion study that indicated the STA function

could not be staffed during this event.

Enclosure

16

On November 6, 2013, and in follow-up letter dated December 6, 2013, the licensee

informed the Region II RA in accordance with 10 CFR 50.9(b), that TVA had inaccurately

reported information regarding the required shift staffing for three-unit operation as

originally submitted in LARs 271, 300, and 259. The inspectors determined that on

multiple occasions the information provided to the NRC detailing required staffing levels

was not complete and accurate in all material respects.

Analysis: The inspectors determined that the licensees apparent failure to provide

complete and accurate information to the NRC were apparent violations of the

requirements of 10 CFR 50.9, Completeness and Accuracy of Information. These

apparent violations had the potential to impede or impact the regulatory process, and

therefore are subject to traditional enforcement as described in the NRC Enforcement

Policy, dated July 9, 2013. A cross-cutting aspect was not assigned because these

violations were dispositioned using traditional enforcement.

Enforcement: 10 CFR 50.9(a) requires, in part, that information provided to the

Commission by a licensee or information required by the statute or by the Commissions

regulations, orders or license conditions to be maintained by the licensee shall be

complete and accurate in all material respects.

TVA apparently provided information to the Commission that was not complete and

accurate in all material respects as evidenced by the following examples:

  • In a letter dated June 29, 2010, TVA apparently provided inaccurate information to

the NRC indicating that the minimum staffing levels stated in their licensing basis

were not required to achieve safe shutdown on the three-unit site during an Appendix

R fire event.

TVA has assessed the number of operators required to carry out the SSIs. The

most demanding staffing is required by 0-SSI-16, "Control Building Fire EL 593

Through EL 617." The evaluation concludes that the minimum staffing of three USs,

six ROs, and eight AUOs is adequate for successful implementation of this SSI.

  • In a letter dated November 30, 2011, TVA apparently provided inaccurate

information to the NRC indicating that the minimum staffing levels stated in their

licensing basis were not required to achieve safe shutdown on the three-unit site

during an Appendix R fire event.

Total staffing level is one Shift Manager (SM), three Unit Supervisors (US), Six

ROs, and eight AUOs. One of the US may be the STA

The licensee augmented on-shift staffing levels on October 30, 2013, and entered these

issues into the corrective action program as PERs 790109, 790092, and 801057. These

issues were preliminarily determined to be an apparent violation of 10 CFR 50.9 and

pending final determination, this issue is identified as AV 05000259, 260, 296/2013005-

03; Inaccurate Information Provided Concerning Onsite Emergency Response

Organization Staffing Requirements.

Enclosure

17

(3) Inappropriate Amendment of License Conditions

Introduction: The NRC identified an apparent violation (AV) of 10 CFR 50.90,

Application for Amendment of License, Construction Permit, or Early Site Permit for the

licensee apparent failure to submit an application requesting an amendment to their

operating license concerning on-shift staffing levels.

Description: On November 15, 2006, the licensee submitted license amendment

requests (LARs) 271, 300, and 259 for Browns Ferry Nuclear (BFN) units 1, 2 and 3,

respectively. The LARs were submitted as part of the restart effort associated with Unit

1. The LARs identified that the minimum staffing levels necessary to ensure safe

shutdown could be achieved on the three operating units during an Appendix R fire,

were 1 Shift Manager (SM), 4 Unit Supervisors (US), 6 Reactor Operators (ROs), 8

Assistant Unit Operators (AUOs), and 1 Shift Technical Advisor. The LARs indicated

that the stated staffing levels were required once Unit 1 achieved Mode 2 of reactor

operations, which occurred on May 21, 2007. On January 10, 2007, the licensee issued

revision 7 of OPDP-1, Conduct of Operations, which decreased the required staffing

levels for on-shift Unit Supervisors to 3, and allowed the STA position to be filled by one

of the on-shift US. In the safety evaluation dated April 25, 2007 (ADAMS Accession

No.ML 071160431), the NRC documented that the licensee conveyed to the NRC staff

that the appropriate procedures had been revised to reflect the increase in staffing levels

contained in the LARs. In addition, the staffs safety evaluation dated April 25, 2007 was

referenced in the BFN Units 1, 2, and 3 licenses regarding the approved Fire Protection

Program.

On May 13, 2010, the licensee notified the Region II Regional Administrator (RA) via a

conference call, that the staffing levels provided in OPDP-1 for minimum on-shift staffing

did not meet the staffing levels submitted in LARs 271, 300, and 259. In a follow-up 10

CFR 50.9 letter dated June 29, 2010, the licensee informed the RA that they did not

meet the requirements of their licensing basis. The licensee also stated that they had

completed a staffing assessment and determined that the current minimum staffing

levels contained in OPDP-1 (i.e., three US with one US filling the STA function) were

adequate for successful implementation of all safe shutdown actions for the bounding

Appendix R fire scenario. However, rather than apply for a license amendment, the

licensee initiated a change to the staffing level requirements using NPG-SPP-03.3, NRC

Commitment Management. TVA evaluated the staffing change as a regulatory

commitment change and determined that NRC approval was not needed and this

change should be reported to the NRC in a biennial report for the commitment changes

TVA reported the required staffing change to the NRC in Summary Report for 10 CFR

50.59 Evaluations, Fire Protection Report Technical Specification Bases Changes,

Technical Requirements Manual Changes, and NRC Commitment Revision, (ADAMS

Accession No. ML 11343A051) dated November 30, 2011. This decision by the licensee

prevented the NRC from reviewing this change to the operating license prior to the

licensee implementing the change.

Analysis: The inspectors determined that the licensees apparent failure to apply for a

license amendment from the NRC was an apparent violation of 10 CFR 50.90. Had

NRC reviewers been provided the correct information it would have impacted the

Enclosure

18

regulatory decision making process. In addition, the NRC staffs reiteration of the

staffing requirements from the November 15, 2006, LARs indicated the staffs reliance

on this specific information in making their technical judgment. This apparent violation of

10 CFR 50.90 had the potential to impede or impact the regulatory process, and

therefore was subject to traditional enforcement as described in the NRC Enforcement

Policy, dated July 9, 2013. A cross-cutting aspect was not assigned since the violation

was dispositioned using traditional enforcement.

Enforcement: Title 10 CFR 50.90 requires, in part, that whenever a holder of an

operating license under this part, desires to amend the license or permit, application for

an amendment must be filed with the Commission, as specified in section 50.4 of this

chapter, as applicable, fully describing the changes desired, and following as far as

applicable, the form prescribed for original applications.

From June 29, 2010, through October 30, 2013, the licensee in effect, apparently

amended their operating license without filing an application for an amendment as

specified in 10 CFR 50.90. Specifically, the licensee inappropriately amended the

requirements for site staffing incorporated as part of license amendments 271, 300, and

259, without submission of a license amendment request. The licensees decision to

amend the staffing levels via a commitment change resulted in bypassing the review and

approval that would occur as part of the licensing amendment process.

The licensee augmented on-shift staffing levels on October 30, 2013, and entered this

issue into the corrective action program as PERs 790109 and 801057. The failure to

apply for a license amendment was preliminarily determined to be an apparent violation

of 10 CFR 50.90 and, pending final determination, this issue is identified as AV

05000259, 260, 296/2013005-04; Inappropriate Amendment of License Conditions.

.3 Annual Licensed Operator Requalification Review

a. Inspection Scope

Annual Review of Licensee Requalification Examination Results: On December 31,

2013, the licensee completed the annual requalification operating examinations required

to be administered to all licensed operators in accordance with Title 10 of the Code of

Federal Regulations 55.59(a)(2), Requalification requirements, of the NRCs

Operators Licenses. The inspector performed an in-office review of the overall

pass/fail results of the individual operating examinations and the crew simulator

operating examinations in accordance with Inspection Procedure (IP) 71111.11,

Licensed Operator Requalification Program and Licensed Operator Performance. The

results were compared to the thresholds established in Section 3.02, Requalification

Examination Results, of IP 71111.11.

b. Findings

No findings were identified.

Enclosure

19

1R12 Maintenance Effectiveness

.1 Routine

a. Inspection Scope

The inspectors reviewed the specific structures, systems and components (SSCs) within

the scope of the Maintenance Rule (MR) (10 CFR 50.65) 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) Tracking

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 10 CFR 50.65(a)(1) goals, monitoring and corrective actions (i.e., Ten

Point Plan). The inspectors also compared the licensees performance against site

procedures. The inspectors also reviewed, as applicable, WOs, SRs, 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.

This activity constituted three Maintenance Effectiveness inspection samples.

Documents reviewed are listed in the Attachment.

  • Unit 1, 2, and 3 control air system shift to (a)(1) status

Heat Exchanger Asiatic Clam fouling

  • Unit 1, 2, and 3 Control Bay Chillers and associated (a)(1) plan effectiveness

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

For planned online work and/or emergent work that affected the combinations of risk

significant systems listed below, the inspectors examined four on-line 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 (RMAs) were conducted as required by 10 CFR 50.65(a)(4)

applicable plant procedures. Furthermore, as applicable, the inspectors verified the

actual in-plant configurations to ensure accuracy of the licensees risk assessments and

adequacy of RMA implementations. This activity constituted four Maintenance Risk

Assessment inspection samples. Documents reviewed are listed in the Attachment.

Enclosure

20

  • October 2, 2013, Units 1/2 D EDG, Unit 2 RCIC, Unit Common C Emergency

Equipment Cooling Water Strainer, and 161kV Trinity Line Out of Service

  • October 23, 2013, Unit 3 Yellow Risk Status, 500kV Switchyard Maintenance (with

loss of offsite power multiplier input), Unit 2 Main Bank Battery (respective Unit 3

RMOV boards control power to alternate), B1 RHRSW Pump, and G Control Air

Compressor Out of Service

  • October 30, 2013, Unit 3, 3A EDG, 3A RHR pump and heat exchanger, RCIC,

common system A RHRSW header, A1 and A2 RHRSW pumps, and G Control

Air Compressor Out of Service

  • November 13, 2013, Unit 1, 1A Control Rod Drive pump replacement required a lift

over the Loop II CS subsystem. The Loop II CS was placed out of service as a

preventative measure for the lift. D1 and D2 RHRSW pumps, G Control Air

Compressor, 1A Component Cooling Water pump, and the C3 Emergency

Equipment Cooling Water pump strainer Out of Service; (This also constitutes a

Smart Sample per OpESS 2007-03 for the Control of Heavy Loads)

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the 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 procedures to ensure that

the licensees evaluation met procedure requirements. 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

reviewed PERs on a daily basis to verify that the licensee was identifying and correcting

any deficiencies associated with operability evaluations. This activity constituted five

Operability Evaluation inspection samples. Documents reviewed are listed in the

Attachment.

  • Unit 1/2, B 4kv shutdown board while B EDG feeder breaker was racked to test

with a wooden seismic device, (WO number 05-715371)

  • Unit 3, 3D EDG did not meet acceptance criteria for a pole drop test, (PER 732970)
  • RHRSW Pump Seismic Restraints (PERs 794671, 796311, 798502)
  • 3D EDG Heat Exchanger Fouling (PER 782689)
  • Average Power Range Monitor Voter Relay Logic Module failures under 10 CFR Part

21 (PER 818017)

Enclosure

21

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed the Design Change Notice (DCN) and completed work package

(WOs 113899709 and 113900042) for DCN 70752 to Eliminate Fault Propagation on

4kV Breakers, including related documents and procedures. The inspectors reviewed

licensee procedures NPG-SPP-09.3, Plant Modifications and Engineering Change

Control, and NPG-SPP-06.9.3, Post-Modification Testing, and observed part of the

licensees activities to implement this design change made while the unit was online.

The inspectors reviewed the associated 10 CFR 50.59 screening against the system

design bases documentation to verify that the modifications had not affected system

operability/availability. The inspectors reviewed selected ongoing and completed work

activities to verify that installation was consistent with the design control documents.

This activity constituted one Permanent Plant Modification sample. Documents

reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors witnessed and reviewed post-maintenance tests (PMTs) listed below to

verify that procedures and test activities confirmed SSC operability and functional

capability following the described 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

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 licensee procedural

requirements. Furthermore, the inspectors verified that problems associated with PMTs

were identified and entered into the CAP. This activity constituted four Post

Maintenance Test inspection samples. Documents reviewed are listed in the

Attachment.

Enclosure

22

  • October 16, 2013, CS, Division II Breaker Testing following DCN 70752 to Eliminate

Fault Propagation (WOs 113899709 and 113900042)

  • November 8, 2013, 3A EDG, 3-SR-3.8.1.1(3A), Monthly Operability Test Following

Lube Oil Modifications (WO 114395126)

  • November 13, 2013, Unit 2 RCIC digital flow controller test following replacement

(WO 115269495)

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

.1 Cornerstone: Initiating Events

a. Inspection Scope

The inspectors reviewed the licensees procedures and methods for compiling and

reporting the following Performance Indicators (PIs). The inspectors examined the

licensees PI data for the specific PIs listed below for the fourth quarter 2012 through

third quarter of 2013. The inspectors reviewed the licensees data and graphical

representations as reported to the NRC to verify that the data was correctly reported.

The inspectors also 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 verified that the PI data was appropriately captured, calculated correctly, and

discrepancies resolved. The inspectors used the Nuclear Energy Institute (NEI) 99-02,

Regulatory Assessment Performance Indicator Guideline, to ensure that industry

reporting guidelines were appropriately applied. This activity constituted nine

Performance Indicator inspection samples. Documents reviewed are listed in the

Attachment.

  • Unit 1, 2, and 3 Unplanned Scrams
  • Unit 1, 2, and 3 Unplanned Scrams with Complications

b. Findings

No findings were identified.

Enclosure

23

4OA2 Problem Identification and Resolution

.1 Review of items entered into the Corrective Action Program:

As required by Inspection Procedure 71152, Problem Identification and Resolution, 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 PER and SR reports,

and periodically attending Corrective Action Review Board (CARB) and PER Screening

Committee (PSC) meetings.

.2 Semi-annual Trend Review:

a. Inspection Scope

As required by Inspection Procedure 71152, the inspectors performed a review of the

licensees CAP and other associated programs and documents to identify trends that

could indicate the existence of a more significant safety issue. The inspectors review

was focused on repetitive equipment issues, but also included licensee trending efforts

and licensee human performance results. The inspectors review nominally considered

the six-month period of July through December 2013, although some examples

expanded beyond those dates when the scope of the trend warranted. The inspectors

reviewed licensee trend reports for the period in order to determine the existence of any

adverse trends that the licensee may not have previously identified. The inspectors

review also included the Integrated Trend Reports from April 1, 2013, to September 30,

2013. The inspectors verified that adverse or negative trends identified in the licensees

PERs, periodic reports, and trending efforts were entered into the CAP. This inspection

constituted one Semi-annual Trend Review inspection sample. Documents reviewed

are listed in the Attachment.

b. Observations and Findings

No findings were identified. In general, the licensee had identified trends and

appropriately addressed them in their CAP. The inspectors observed that the licensee

had performed a detailed review. The licensee routinely reviewed cause codes, involved

organizations, key words, and system links to identify potential trends in their data. The

inspectors compared the licensee process results with the results of the inspectors daily

screening. Trends that have been identified by the inspectors and reported to the

licensee were appropriately entered into the licensees trending program and the CAP.

These trends included the following:

  • Challenges to operability of the RHR heat exchangers due to Asiatic clam fouling
  • Secondary plant systems challenging continued operation at 100 percent power and

causing plant trips

  • Control of transient combustible material in safety-related areas of the plant

Enclosure

24

.3 Focused Annual Sample Review:

a. Inspection Scope

The inspectors conducted a review of licensee maintenance of floor drain systems in the

diesel buildings and reactor buildings with a focus on the preventative maintenance

practices and design of the drains with respect to impact on CO2 actuation on a fire.

This inspection constituted one Focused Annual Review inspection sample. Documents

reviewed are listed in the Attachment.

b. Observations and Findings

The inspectors noted that licensee preventative maintenance frequency for maintaining

plant drains was not identifying a trend of excessive debris on the as-found inspection.

Some plant areas did not have an assigned preventative maintenance task.

Additionally, the inspectors noted that the drains in the diesel rooms would allow CO2

concentrations to be diluted on any actuation into the adjacent corridors floor drain

sump.

Introduction: The NRC identified a Green NCV of 10 CFR 50, Appendix B, Criterion III,

Design Control, for the licensees failure to establish design control measures ensure the

capabilities of the B EDG room floor drains.

Description: On August 13, 2013, NRC inspectors identified significantly clogged floor

drains in the B EDG room. Per Browns Ferry Civil Design Criteria BFN-50-C-7105, Low

Energy Piping Evaluation Requirements, the two floor drains installed in the EDG room

were required to remove at least 135 gallons per minute (gpm) of water to sumps

outside the room. The Browns Ferry Engineering staff reviewed the condition and

concluded that the B EDG was inoperable as the drains were incapable of removing

flow. Subsequently, NRC inspectors observed licensee staff members dumping debris

and dirty water down the 3D EDG room drains. Despite observed fouling of the drains,

licensee staff failed to recognize this as a condition adverse to quality and initiate SRs to

address the condition. The inspectors determined that there were no preventative

maintenance tasks or periodic testing to ensure the drain capability for the eight EDG

rooms. Other plant rooms have a 26 week frequency preventative maintenance task to

ensure the design drain capabilities were maintained.

The Browns Ferry EDG room internal flood mitigation strategy is to have the outside

sump level alarm alert operators once the sump becomes full. The sump pumps are

maintained in an off condition at the Browns Ferry plant. With the floor drains clogged,

operator action would be delayed because the sump could not receive 135 gpm flood

water through the drain piping. The licensee re-evaluated the B EDG drain conditions

one month later and determined the drains were only 90 percent and 45 percent clogged

on August 13, 2013. This would have allowed the drain water to slowly fill the sump.

Based on sufficient operator response time, the B EDG was determined to remain

operable. The licensees immediate corrective action was to clean all the drains in all

the EDG rooms.

Enclosure

25

Analysis: The inspectors determined that the licensees failure to establish measures to

assure the regulatory requirements and design basis of structures, systems, and

components were correctly translated into procedures and instructions in accordance

with 10 CFR 50, Appendix B, Criterion III, Design Control, was a performance deficiency

that was reasonably within TVAs ability to foresee and prevent. Specifically, no

measures were established to ensure the EDG floor drains maintained capability of

performing their intended functions as described in the design basis. The finding was

more than minor because, if left uncorrected, the performance deficiency would have the

potential to lead to a more significant safety concern. Specifically, the EDG room floor

drains could become sufficiently clogged such that internal flooding would cause the

affected EDG to be unable to perform its safety function. The inspectors performed a

Phase 1 screening in accordance with IMC 0609, Significance Determination Process,

Appendix A, Exhibit 1, Initiating Event screening question E, and determined the finding

was of very low safety significance (Green) because it did not impact the frequency of an

internal flooding event. This finding has a cross-cutting aspect in the area of Problem

Identification and Resolution, Corrective Action Program Component, because TVA did

not identify issues completely, accurately, and in a timely manner commensurate with

their safety significance. Specifically, TVA did not identify that workers were challenging

the drains design feature by routinely dumping dirty water and debris into the floor drains

without a mechanism to verify the resultant capability of the drains. P.1(a)

Enforcement: 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part,

that measures shall be established to assure the regulatory requirements and design

basis of structures, systems, and components are correctly translated into procedures

and instructions. Contrary to the above, prior to August 13, 2013, the Tennessee Valley

Authority (TVA) did not correctly translate the design basis of the EDG floor drains into

procedures and instructions and therefore no measures were established to ensure the

EDG floor drains maintained capability of performing their intended function as described

in their design basis. The licensees immediate corrective action was to clean all the

drains in all the EDG rooms thus verifying capability of the drains. This violation is being

treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The

violation was entered into the licensees corrective action program as PER 765575.

(NCV 05000259/2013005-05, Failure to Maintain Emergency Diesel Room Floor Drains)

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report (LER) 05000259/2009-002-01, Unexpected Logic

Lockout of the Loop II Residual Heat Removal (RHR) System Pumps

a. Inspection Scope

The inspectors reviewed LER 05000259/2009-002-01 dated September 27, 2013. The

licensee event report was reviewed based on the changes that were made to the original

report. The changes documented concurrent inoperability of systems described in other

LERs. These systems included the Loop II of the RHR system (due to the failure of

1-FCV-74-66) and the RHR pump 1C (due to a rotor/shaft bow). All the other system

Enclosure

26

operability issues were previously adjudicated in Browns Ferry inspection report

05000259, 260, 296/2010002 (ADAMS Accession No. ML101200508). This LER is

closed.

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report (LER) 05000259/2009-004-01, High Pressure Core

Injection Found Inoperable During Condensate Header Level Switch Calibration and

Functional Test

a. Inspection Scope

The inspectors reviewed LER 05000259/2009-004-01 dated September 27, 2013. The

licensee event report was reviewed based on the changes that were made to the

previous report. The changes documented concurrent inoperability of systems

described in other LERs. These systems included the Loop II of the RHR system (due

to the failure of 1-FCV-74-66) and the RHR pump 1C (due to a rotor/shaft bow). All the

other system operability issues were previously addressed in Browns Ferry inspection

report 05000259, 260, 296/2009005 (ADAMS Accession No. ML100331517). This LER

is closed.

b. Findings

No findings were identified.

.3 (Closed) Licensee Event Report (LER) 05000259/2010-003-03, Failure of a Low

Pressure Coolant Injection Flow Control Valve

a. Inspection Scope

The inspectors reviewed LER 05000259/2010-003-03 dated September 30, 2013. The

licensee event report was reviewed based on the changes that were made to the

previous reports. The changes documented concurrent inoperability of systems

described in other LERs and systems that were inoperable due to maintenance for

periods of time less than the allowed limit. All system operability issues were previously

addressed in Browns Ferry inspection reports 05000259/2011008 (ADAMS Accession

No. ML111290500) and 05000259, 260, 296/2012002 (ADAMS Accession No.

ML12121A507). This LER is closed.

b. Findings

No findings were identified.

Enclosure

27

.4 (Closed) Licensee Event Report (LER) 05000259, 260, 296/2011-003-02, Loss of Safety

Function (SDC) Resulting from Emergency Diesel Generator Output Breaker Trip

a. Inspection Scope

The inspectors reviewed LER 05000259, 260, 296/2011-003-02 dated September 30,

2013, and all previous revisions. The licensee event report was reviewed based on the

changes that were made to the previous reports. The key change was the

documentation of the inoperability of the Diesel Generator based on the failure of the

Overspeed Trip Limit Switch (OTLS). The previous revision did not include the total

inoperability time. This issue was previously addressed in Browns Ferry Inspection

reports 05000259, 260, 296/2011004 (ADAMS Accession No. ML113180503) and

05000259, 260, 296/2011005 (ADAMS Accession No. ML12045A063). This LER is

closed.

b. Findings

No findings were identified.

.5 (Closed) Licensee Event Report (LER) 05000259/2011-009-03, As-Found Undervoltage

Trip for the Reactor Protection System 1A1 Relay that Did Not Meet Acceptance Criteria

During Several Surveillances

a. Inspection Scope

The inspectors reviewed LER 05000259/2011-009-03 dated July 29, 2013. The licensee

event report was reviewed based on the changes that were made to the previous

reports. The changes documented additional similar failures and a change to the causal

factors. Standing order 174 was issued to establish Operations department

expectations when as-found data is found outside of acceptable regulatory guidelines.

The RPS 1A1 relay and 3C1 relay were replaced. This issue was previously addressed

in Browns Ferry Inspection reports 05000259, 260, 296/2012002 (ADAMS Accession

No. ML12121A507) and 05000259, 260, 296/2012003 (ADAMS Accession No.

ML12227A711). Section 4OA7 of Inspection Report 2012-002 addressed the associated

licensee identified violation. No additional findings were identified. This LER is closed.

b. Findings

No findings were identified.

.6 (Closed) Licensee Event Report (LER) 05000296/2013-001-00 and 01, Inoperable

Emergency Diesel Generator due to Failed Electric Generator Casing Fan Bearing

a. Inspection Scope

The inspectors reviewed the LER, dated March 11, 2013, and May 10, 2013, and the

associated PER 665217, including the root cause analysis, operability determinations,

Enclosure

28

and corrective action plans. On January 9, 2013, while performing operator rounds near

the Unit 3, 3D Emergency Diesel Generator (EDG), the licensee discovered metal

residue and grease around the generator blower shaft. The licensee determined the

generator blower inboard bearing (coupling side) had failed during a previous post

maintenance test, as verified by licensee vibration data, rendering the 3D EDG

inoperable. Following return to service of the 3D EDG and extent-of-condition

inspections, the licensee determined that two additional Unit 3 EDGs had blower

bearings that were degraded but not failed, and were also determined to be inoperable.

The licensee concluded that the direct cause of the 3D EDG bearing failure was the

absence of lubrication to the internal parts of the EDG blower bearing due to age related

breakdown of the grease. The licensee determined two root causes to be inadequate

component level assessment of the blower shielded bearings for failure modes and

impacts and ineffective industry vibration monitoring standards. All four Unit 3 EDG

generator blower bearings were replaced.

b. Findings

The enforcement aspects of this finding are discussed in Section 4OA7. This LER and

its revision are closed.

.7 (Closed) Licensee Event Report (LER) 05000259/2013-006-00, 1B Standby Liquid

Control Pump Inoperable for Longer than Allowed by Technical Specifications

a. Inspection Scope

The inspectors reviewed LER 05000259/2013-006-00 dated December 3, 2013. A

licensee past operability review determined that 1B Standby Liquid Control pump was

inoperable from December 1, 2012, to February 14, 2013, due to a piece of the motor

breakers arc chute that had become dislodged and re-located to between the breaker

contacts. This LER is closed.

b. Findings

Introduction. A Severity Level IV Non-Cited violation of 10 CFR 50.73(a)(2)(i)(B) was

identified by the inspectors for the licensees failure to submit a License Event Report

(LER) within 60 days of a reportable event .

Description. On September 26, 2013, in response to NRC inspector questioning, the

licensee reevaluated the past operability results of the failure of the 1B Standby Liquid

Control (SLC) pump which occurred on Feb 13, 2013. Following the reevaluation, a

revision to the PER 618667 past operability evaluation was made which concluded the

1B SLC pump would not have been able to meet its mission time from December 1,

2012 to February 14, 2013 (74 days). The licensing staff also identified that 1A SLC

pump had been out of service for accumulator repairs during the time period that 1B

SLC pump was inoperable. Thus the failure was reportable as both a condition

prohibited by technical specifications and a loss of system safety function. PER 796578

was initiated with an immediate corrective action to generate a LER. LER 50-259 2013-

006-00 was submitted on December 3, 2013.

Enclosure

29

Analysis. The inspectors determined that the failure to submit a License Event Report

(LER) within 60 days of a reportable event was a violation of the requirements of 10 CFR

50.73(a)(2)(i)(B). This violation had the potential to impede or impact the regulatory

process, and therefore subject to traditional enforcement as described in the NRC

Enforcement Policy, dated July 9, 2013. The inspectors used the examples provided in

Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required

Report, of the NRC Enforcement Policy to determine the severity level (SL). Based on

the wording of example 9 under the examples for SL IV violations, the inspectors

determined that this violation should be characterized as a SL IV violation. Example 9

states A licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73. A

cross-cutting aspect was not assigned because the violation was dispositioned using

traditional enforcement.

Enforcement. 10 CFR 50.73(a)(2)(i)(B) required, in part, that licensees report any

conditions prohibited by plant technical specifications within 60 days via a License Event

Report. Contrary to the above, from April 14, 2013, through December 3, 2013, the

licensee did not report within 60 days the failure to comply with Condition A of Technical

Specification 3.1.7 after the February 13, 2013, 1B SLC pump breaker failure. This

issue was documented in the licensees corrective action program as Problem

Evaluation Reports 796578 and 817510. Corrective actions included reporting the

conditions in LER 050000- 259/2013-06-00. This violation is being treated as an NCV,

consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into

the licensees corrective action program as PER 796578. (NCV 05000259/2013005-06,

[Failure to report a condition prohibited by Technical Specifications.])

.8 (Closed) Licensee Event Report (LER) 050000260/2012-006-01, Automatic Reactor Scram Due to Loss of Power to the Reactor Protection System

a. Inspection Scope

On December 22, 2012, Unit 2 automatically scrammed from approximately 100 percent

power due to loss of power to both RPS buses. The 4kV Shutdown Board D had

de-energized during testing of the emergency diesel generators which resulted in a loss

of the RPS Bus 2B. While attempting to re-energize the RPS Bus 2B, a procedural error

resulted in de-energizing the RPS Bus 2A which resulted in a reactor scram and closure

of the main steam isolation valves.

The original LER 05000260/2012-006-00, dated February 20, 2013, and applicable PER

660862, were reviewed by the inspectors and documented in Section 4OA3.3 of NRC IR 05000260/2013002 (ADAMS Accession No. ML13134A237), where a self-revealing

apparent violation (AV) of Technical Specification 5.4.1 was identified for the licensees

failure to properly implement procedure 2-OI-99, Reactor Protection System. The

finding was determined to have a low to moderate safety significance (white) and a

notice of violation was issued to Browns Ferry for this event in NRC IR 05000260/2013013 (ADAMS Accession No. ML13235A058).

Enclosure

30

The inspectors reviewed Revision 1 of the LER dated December 6, 2013, and applicable

PER 740259, including the revised cause determination and corrective action plans.

This revised LER was submitted to provide the results of the licensees completed

investigation and revised causal analysis. The inspectors verified that the supplemental

information provided in the revised LER was complete and accurate. No additional

licensee significant performance deficiencies were identified by the inspectors. This

LER is closed

b. Findings

No additional findings were identified..

4OA5 Other Activities

.1 Operation of an Independent Spent Fuel Storage Installation (ISFSI) (60855)

a. Inspection Scope

Under the guidance of IP 60855.1, the inspectors observed operations involving spent

fuel transfer and storage for dry cask campaign number seven. Inspectors interviewed

personnel and reviewed the licensees documentation regarding storing spent fuel to

verify that these independent spent fuel storage installation (ISFSI) related programs

and procedures fulfill the commitments and requirements specified in the Safety Analysis

Report (SAR), Certificate of Compliance (CoC), 10 CFR Part 72, and the Technical

Specifications. Specifically one year of related 10 CFR 72.48 evaluations, 10 CFR

72.212(b) evaluations, and lid welding records associated with multi-purpose canisters

(MPC) S/N 0326 and S/N 0330 were reviewed. The inspectors conducted independent

ISFSI related activities to ensure that the licensee performed spent fuel loading and

transport in a safe manner. Inspectors performed focused operational reviews on new

methodologies concerning forced helium dehydration and supplemental cooling.

Inspectors attended briefings and observed operations in the field including overall

supervisory involvement, coordination, and oversight of ISFSI-related work activities.

The inspectors reviewed the fuel loading plan for MPC-0326 and verified that the fuel

assemblies were properly selected and loaded in accordance with characterization

documents and approved procedures. The inspectors verified that selected individuals

had received the necessary training in accordance with approved procedures for their

ISFSI-related job duties.

The inspectors reviewed work orders, completed procedures, logs, welding records,

inspection records, qualification records, and overall guidelines for MPC-0326 ISFSI

activities. The inspectors determined that the licensee had established, maintained, and

implemented adequate control of dry cask processing operations, including loading,

transportation, and storage per approved procedures and technical specification

requirements. Records of spent fuel stored at the facility were properly maintained.

Enclosure

31

b. Findings and Observations

No findings were identified.

.2 (Closed) Temporary Instruction 2515/182 - Review of the Industry Initiative to Control

Degradation of Underground Piping and Tanks

a. Inspection Scope

The inspectors conducted a review of records and procedures related to the licensees

program for buried piping and underground piping and tanks in accordance with Phase

II of temporary instruction (TI) 2515-182 to confirm that the licensees program

contained attributes consistent with Sections 3.3.A and 3.3.B of Nuclear Energy

Institute (NEI) 09-14, Guideline for the Management of Buried Piping Integrity,

Revision 3, and to confirm that these attributes were scheduled and/or completed by

the NEI 09-14 Revision 3 deadlines. The inspectors interviewed licensee staff

responsible for the buried piping program and reviewed activities related to the buried

piping program to determine if the program was managed in a manner consistent with

the industrys buried piping initiative.

The licensees buried piping and underground piping and tanks program was inspected

in accordance with paragraph 03.02.a of the TI and it was confirmed that activities

which correspond to completion dates specified in the program which have passed

since the Phase 1 inspection was conducted, have been completed. The licensees

buried piping and underground piping and tanks program was inspected in accordance

with paragraph 03.02.b of the TI and responses to specific questions found in

http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-

2011-11-16.pdf were submitted to the NRC headquarters staff.

b. Findings

No findings were identified. Based upon the scope of the review described above,

Phase II of TI-2515/182 was completed.

.3 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.

Enclosure

32

b. Findings

No findings were identified

4OA6 Meetings, Including Exit

On January 10, and 21, 2014, the resident inspectors presented the quarterly inspection

results to Mr. Steve Bono, Plant Manager, and other members of the licensees staff,

who acknowledged the findings. The inspectors verified that all proprietary information

was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the

licensee and is a violation of NRC requirements which meets the criteria of the NRC

Enforcement Policy, for being dispositioned as a Non-Cited Violation.

Unit 3 Technical Specification 3.3.8.1, AC Sources - Operating, required EDGs to be

operable in Modes 1, 2, and 3, and with multiple EDGs inoperable, required all but one

EDG be returned to service in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in 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 this, between December 22, 2012, and January 9, 2013,

the licensee determined that multiple EDGs were inoperable as a result of failed 3D

EDG and degraded 3A and 3B EDG generator blower bearings. This TS violation was

entered into the licensees CAP as PERs 665217, 675339, and 675952. This finding

represented an actual loss of function of the 3D EDG for greater than the TS allowed

outage time, and therefore, required a detailed risk evaluation. Because of the short

exposure time related to the performance deficiency, the finding was determined to be of

very low safety significance (Green).

Enclosure

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee

E. Bates, Licensing Engineer

D. Campbell, Assistant Ops Superintendent

P. Campbell, System Engineer

S. Christman, Ops Shift Manager

D. Drummonds, Underground and Buried Piping Program Owner

J. Emens, Nuclear Site Licensing Manager

D. Green, Licensing Engineer

R. Guthrie, System Engineer

L. Hughes, Manager Operations

E. Johnson, System Engineer

J. Lacasse, System Engineer

J. McCormack, System Engineer

M. Oliver, Licensing Engineer

J. Paul, Nuclear Site Licensing Manager

K. Polson, Site Vice President

M. Roy, Maintenance Rule Coordinator

S. Samaras, Civil Design Engineer

T. Scott, Performance Improvement Manager

M. Webb, Site Licensing

A. Yarborough, System Engineer

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened

05000259, 260, 296/2013005-02 AV Failure to Maintain Emergency Response

Staffing Levels (Section 1R11.2)

05000259, 260, 296/2013005-03 AV Inaccurate Information Provided Concerning

Onsite Emergency Response Organization

Staffing Requirements (Section 1R11.2)

05000259, 260, 296/2013005-04 AV Inappropriate Amendment of License

Conditions (Section 1R11.2)

Opened and Closed

05000259, 260, 296/2013005-01 NCV Failure to Document Service Water Freeze

Protection Deficiencies (Section 1R01)

Attachment

2

05000259, 260, 296/2013005-05 NCV Failure to Maintain Emergency Diesel Room

Floor Drains (Section 4OA2.3)05000260/2013005-06 SL-IV Failure to report a condition prohibited by

Technical Specifications (Section 4OA3.7)

Closed

05000259/2009-002-01 LER Unexpected Logic Lockout of the Loop II

Residual Heat Removal System Pumps

(Section 4OA3.1)

05000259/2009-004-01 LER High Pressure Core Injection Found Inoperable

During Condensate Header Level Switch

Calibration and Functional Test (Section

4OA3.2)

05000259/2010-003-03 LER Failure of a Low Pressure Coolant Injection

Flow Control Valve (Section 4OA3.3)

05000259, 260, 296/2011-003-02 LER Loss of Safety Function (SDC) Resulting from

Emergency Diesel Generator Output Breaker

Trip (Section 4OA3.4)

05000259/2011-009-03 LER As-Found Undervoltage Trip for the Reactor

Protection System 1A1 Relay that Did Not

Meet Acceptance Criteria During Several

Surveillances (Section 4OA3.5)

05000259/2013-006-00 LER 1B Standby Liquid Control Pump Inoperable for

Longer than Allowed by Technical

Specifications (Section 4OA3.7)

05000260/2012-006-01 LER Automatic Reactor Scram Due to Loss of Power

to the Reactor Protection System (Section

4OA3.8)

05000296/2013-001-00 LER Inoperable Emergency Diesel Generator due to

Failed Electric Generator Casing Fan Bearing

(Section 4OA3.6)

05000296/2013-001-01 LER Inoperable Emergency Diesel Generator due to

Failed Electric Generator Casing Fan Bearing

(Section 4OA3.6)

2515/182 TI Review of the Industry Initiative to Control

Degradation of Underground Piping and Tanks,

Phase II (Section 4OA5.2)

Attachment

3

Discussed

None

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

0-GOI-200-1, Freeze Protection Inspection, Rev. 76

EPI-0-000-FRZ001, Freeze Protection Program for RHRSW pump rooms and Diesel Generator

Building, Rev. 19

PER 8000190

PER 821246, Prompt Determination of Operability

SR 821249

System Code FZ Discrepancy WO List, dated December 16, 2013

Section 1R04: Equipment Alignment

3-OI-71/ATT-3 RCIC Electrical Lineup Checklist, Rev. 50

3-OI-71/ATT-1 Reactor Core Isolation Cooling (RCIC) Valve Lineup Checklist, Rev. 50

Browns Ferry Electrical Distribution drawing

Browns Ferry Plan of the Day, 10-15-2013

DWG 2-47E814-1, Flow Diagram Core Spray System, Rev. 52

FSAR Section 4.7, RCIC

Load Dispatcher switching order for opening MOD 5240

NEDP-27, Past Operability Evaluations, Rev. 0

PER 696780, Frequency change required on SLC pump breakers

PER 681667, 1B SLC pump tripped

SR 791672, Unit 3 RCIC Steam flow indication reads 10,000 lbm/hr at zero flow

SR 791254, Unit 2 RCIC deferral of rupture disk replacement

System Health Reports, Standby Liquid Control, 2-1-13 to 5-31-13

System Health Reports, Standby Liquid Control, 6-1-13 to 9-30-13

Unit 2 Core Spray Fragnet Update dated 10-15-2013

Section 1R05: Fire Protection

Browns Ferry Nuclear Plant Fire Protection Report, Volume 1, Rev. 16

Browns Ferry Nuclear Plant Fire Protection Report, Volume 1A, Rev 16

Browns Ferry Nuclear Plant Fire Protection Report, Volume 2, Rev. 51

Section 1R11: Licensed Operator Requalification

NP-REP, Tennessee Valley Authority Nuclear Power Radiological Emergency Plan, Rev. 100

Training Focus Areas for Cycle 5, 2013

Unit 2 Simulator Exercise Guide (SEG) OPL173.R227, Anticipated Transient without Scram

Section 1R12: Maintenance Effectiveness

0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -

10 CFR 50.65, Rev. 46

0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -

10 CFR 50.65, Rev. 46, Attachment 11 (Control Air System)

CDE Record 1371, 2A RHR HX Inspection

Control Air Compressor Trips/Anomalies Report, dated 3/12/13

Attachment

4

Control Bay Chilled Water System 031-E a(1) Plan Rev 1, 1-10-2012

DWG 0-47E845-1

DWG 0-47E845-2

DWG 1-47E610-32-1

DWG 2-47E610-32-1

FSAR Chapter 10.14 Service and Control Air

NPG-SPP-03.4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting-

10 CFR 50.65, Rev. 2

PDO for PER 674502

PER 674502

PER 692613

PER 784085

PER 814796, Review the Maintenance Rule Performance Criteria Established in 0-TI-346

System Health Report for the Control Air System, dated 11/18/13

System Health Report, System 31, A/C, Heating and CREV, (6-1-2013 - 9-30-13)

U0 RHRSW, Functions 023-B, C, & D (a)(1) Plan, Rev. 4

WO 111456773

WO 113206742

WO 113632455

WO 114245152

WO 114245153

WO 114687057

WO 114731364

WO 114917994

WO 115045078

WO 115057307

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

NPG-SPP-09.11.1, Equipment Out of Service Management, Revs. 6, 7

Operations EOOS Desktop Users Guide, Effective Date: 4/27/2012

10/1-3/2013, Plan of the Day

10/1-3/2013, Operators Daily Logs and EOOS Profiles

10/23-25/2013, Plan of the Day

10/23-25/2013, Operators Daily Logs and EOOS Profiles

SR 797298, Expected EOOS Color Change Not Communicated to OPS Shift Crew

10/29-30/2013, Plan of the Day

10/29-30/2013, Operators Daily Logs and EOOS Profiles

11/13/2013, Plan of the Day

11/13/2013, Operators Daily Logs and EOOS Profiles

Operating Experience Smart Sample Guidance (OpESS) 2007-03, Crane and Heavy Lift

Inspection, Rev. 2

Nuclear Energy Institute (NEI) 08-05 Industry Initiative on the Control of Heavy Loads, Rev. 0

NRC Generic Letter 80-113 Control of Heavy Loads

MSI-0-000-LFT001, Lifting Instructions for the Control of Heavy Loads, Rev. 0064

Section 1R15: Operability Determinations and Functionality Assessments

0-GOI-300-2, Electrical General Operating Instruction

Calculation CD-Q0999-890268

Attachment

5

Calculation MDQ0082000016, Diesel Generator Jacket Water Cooler Capacity and Tube

Plugging, Rev. 2

Common cause failure evaluation for PER 728243

DWG 0-37W205-10, Mechanical Pumping Station & Water Treatment - Piping & Equipment,

Rev. 6

DWG 0-37W205-5, Mechanical Pumping Station & Water Treatment - Piping & Equipment,

Rev. 6

EWR13-BOP-023-202, Evaluation of Conservatism within EPRI document 1025271 and

Applicability of EPRI Guidelines at BFN, Rev. Original

Failure Analysis for PER 732970

IEEE-115 Code requirements for Pole Drop testing

Past Operability Evaluation for PER 782689

PDO for PER 732970

PER 401732, 3C Diesel Generator Shorted Rotor Pole

PER 728243, 3D Diesel Generator did not meet acceptance criteria for a pole drop test

PER 732970, The PDO for PER 728243 appeared inconclusive

PER 782689, Fouling Seen During Raw Water Inspection of 3D DG HEX

PER 794671, Missing Bolts Found on B3 EECW Pump Seismic Restraint

PER 796311, Missing and Deteriorated Hardware Discovery on A3 RHRSW Pump Restraint

PER 798502, Repairs Needed to C1 RHRSW Pump Seismic Restraint

Prompt Determination of Operability for PERs 794671, 796311, 798502

UFSAR, Appendix C, Structural Qualification Of Subsystems And Components, Amendment 25

UFSAR, Section 10.9, RHR Service Water System, Amendment 25

Unit 3 TS 3.8.1

WO 115052074, Heat Exchanger Visual Inspection and Evaluation Form

WO number 05-715371

Section 1R18: Plant Modifications

NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 1

NPG-SPP-06.9.3, Post-Modification Testing, Rev. 4

NPG-SPP-09.3, Plant Modifications and Engineering Change Control, Rev. 15

DCN 70752, Install Separate Fusing for Trip Circuits on 4KV Breakers to Eliminate Fault

Propagation issue, Rev. A

WO 113899709, DCN 70752 - Stage 16: Install ATM6 Fuse in 4kV Board Trip Circuit

WO 113900042, DCN 70752 - Stage 23: Install ATM6 Fuse in 4kV Board Trip Circuit

DCN 70752 - Stage 16, Testing Steps

DCN 70752 - Stage 23, Testing Steps

2-SR-3.5.1.6(CS II), Core Spray Flow Rate Loop II, Rev. 33

0-GOI-300-2, Electrical, Rev. 122

EII-0-000-BKR005, 4KV Horizontal Breaker 52STA Switch Test Linkage and Position Switch

Blocking and Tie-Up, Rev. 7

NRC Generic Letter No. 96-01: Testing Of Safety-Related Logic Circuits

Section 1R19: Post Maintenance Testing

0-GOI-300-2, Electrical, Rev. 122

0-SR-3.8.1.1(A), Diesel Generator A Monthly Operability Test, Rev. 50

2-OI-71 Reactor Core Isolation Cooling Operating Instruction, Rev. 0068

2-SR-3.5.1.6(CS II), Core Spray Flow Rate Loop II, Rev. 33

Attachment

6

3-SR-3.8.1.1(3A), Diesel Generator 3A Monthly Operability Test, Rev. 55

DCN 70752 - Stage 16, Testing Steps

DCN 70752 - Stage 23, Testing Steps

DCN 70752, Install Separate Fusing for Trip Circuits on 4KV Breakers to Eliminate Fault

Propagation issue

EII-0-000-BKR005, 4KV Horizontal Breaker 52STA Switch Test Linkage and Position Switch

Blocking and Tie-Up, Rev. 7

MMDP-1, Maintenance Management System, Rev. 27

NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 1

NPG-SPP-06.9.3, Post-Modification Testing, Rev. 4

NRC Generic Letter No. 96-01: Testing Of Safety-Related Logic Circuits

PER 786196, Oil on Floor beneath 3A D/G Platform

PER 806291, Diesel Generator 3A Control Circuit Ground Alarm Received

PER 807494, Fail light is illuminated on Unit 2 RCIC flow controller

PER 808811, PDO Request for PER 789196

WO 113899709, DCN 70752 - Stage 16: Install ATM6 Fuse in 4kV Board Trip Circuit

WO 113900042, DCN 70752 - Stage 23: Install ATM6 Fuse in 4kV Board Trip Circuit

WO 114395126, Diesel Generator 3A Monthly Operability Test

WO 114456082, Diesel Generator A Monthly Operability Test

WO 115263298, Attachment 1 to Task 10, BFN-3-ENG-082-0003A, Rev. 0

WO 115269495, Replacement of BFN-2-FIC-071-0036A (Digital Flow controller for Unit 2 RCIC)

WO 115302820, Re-Seal NPT Pipe Threads at Inlet to Check Valve

Section 4OA1: Performance Indicator (PI) Verification

Browns Ferry Daily Operator Logs, October 1, 2012, through September 30, 2013

Section 4OA2: Problem Identification and Resolution

Integrated Trend Report, Q3FY13

Integrated Trend Report, Q4FY13

NPG-SPP 22.303, PER Analysis, Actions, Closures, and Approvals, Rev. 0001

NPG-SPP 22.305, Apparent Cause Analysis, Rev. 0001

NPG-SPP 22.306, Root Cause Analysis, Rev. 0001

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

2-AOP-99-1, Loss of Power to One RPS Bus, Rev. 27 and Rev. 29

2-OI-99, Reactor Protection System, Rev. 79 and Rev. 80

LER 259, 260, 296/2011-003-02, Loss of Safety Function (SDC) Resulting from Emergency

Diesel Generator Output Breaker Trip

LER 259/2009-002-01, Unexpected Logic Lockout of the Loop II Residual Heat Removal (RHR)

System Pumps

LER 259/2009-004-01, High Pressure Core Injection found Inoperable during Condensate

Header Level Switch Calibration and Functional Test

LER 259/2010-003-03, Failure of a Low Pressure Coolant Injection Flow Control Valve

PER 660235, 3D EDG Units in Parallel with D EDG Failed PMTI

PER 660862, U2 Scram while restarting 2B RPS using 2B RPS MG Set

PER 740259, RPS Scram, White Finding

Unit 1 FSAR

Unit 1 Technical Specifications 3.5.1 and 3.8.1

Attachment

7

Section 4OA5: Other Activities

ISFSI Inspection

10 CFR 72.212, Report of Evaluations, Rev. 5, dated 6/11/2012

10 CFR 72.48 Screening Review, 0-GOI-100-3B, Manual Operation of the Refuel Platform

10 CFR 72.48 Screening Review, 0-SR-DCS3.1.2.1, High Storm Inspection log, attachment 1

10 CFR 72.48 Screening Review, DCN 64063A, Revised setpoint changes for radiation

monitors 2-R-90-142, 2-R-90-143, 3-R-90-142, 3-R-90-143

10 CFR 72.48 Screening Review, EDC 70586A, Use of HBF IAW Holtec CoC Amend. 5, Rev. 0

10 CFR 72.48 Screening Review, EDC 70586A, Use of HBF IAW Holtec CoC Amend. 5, Rev. 1

10 CFR 72.48 Screening Review, EPI-0-111-CRA009, Annual Inspection of Reactor Building

Crane, Rev. 000

10 CFR 72.48 Screening Review, MSI-0-079-DCS036, ISFSI Abnormal Conditions Procedure

10 CFR 72.48 Screening Review, MSI-0-079-DCS043, Dry Cask Campaign Review Program,

Rev. 1

10 CFR 72.48 Screening Review, MSI-0-079-DCS300.2, Alternate Cooling Water System

Operation, Rev. 3

10 CFR 72.48 Screening Review, MSI-0-079-DCS400.1, ISFSI Abnormal Conditions Procedure,

Placing the MPC in a Safe Condition

10 CFR 72.48 Screening Review, Work Order 1131655560

Certificate of Compliance No. 1014, Appendix B, Design Features for the HI-STORM 100 Cask

System, Section 3.6, Forced Helium Dehydration System, Amendment 5

Drawing 0-47E201, ISFSI Dry Storage Implementation Notes

Drawing 4838, Standard MPC Shell and Details for MPC24, 32, & 68

EDC 70586, Allow Use of the FHD and SCS to Enable the Storage of High Burnup Fuel in the

ISFSI, Rev. A

HOLTEC HI STORM 100 Cask System, Safety Evaluation Report, Amendment 1

MSI-0-079-DCS036, ISFSI Abnormal Conditions Procedure, Rev. 2

MSI-0-079-DCS200.1, Dry Cask Preparations and Start Up, Rev. 5

MSI-0-079-DCS200.2, MPC Loading and Transport Operations, Rev. 28

MSI-0-079-DCS300.10, Forced Helium Dehydration System Operation, Rev. 3

MSI-0-079-DCS300.11, Supplemental Cooling System Operation, Rev. 0

MSI-0-079-DCS300.2, Alternate Cooling Water System Operation, Rev. 3

MSI-0-079-DCS400.1, ISFSI Abnormal Conditions Procedure, Placing the MPC in a Safe

Condition, Rev. 3

MSI-0-079-DCS500.3, MPC Cooldown and Weld Removal, Rev. 3

MSI-0-079-DCS500.5, MPC Unloading Operations, Rev. 3

Work Order 1131655560

Corrective Action Documents Reviewed

PER 733056, UPTI Milestone Completion

PER 734268, UPTI Database Trending

PER 790632, Radwaste Discharge Pipe Leak Inspection

Corrective Action Documents Generated

SR 824118 Leaks

SR 824122 GPR

SR 824126 Programs

SR 824128 NACE SP0169

Attachment

8

SR 824132 Soil Analysis

SR 824136 Health Reporting

SR 824138 Pipe Location

SR 824140 BP Manager

SR 824142 SBGT Pipe Repair

Procedure

0-TI-364, ASME Section XI System Pressure Tests, Rev. 16

0-TI-561, Underground Piping and Tanks Integrity Program (UPTI), Rev. 14

0-TI-561, Underground Piping and Tanks Integrity Program (UPTI), Rev. 5

0-TI-561, Buried Piping Component Management Program (UPTI), Rev. 0

0-TI-623, Aging Management Program Basis Document for Buried Piping and Underground

Piping and Tanks, Rev. 0

2-SI-4.5.C.1(3), RHRSW Pump and Header Operability and Flow Test, Rev. 18

NPG-SPP-22.303, PER Analysis, Actions, Closures and Approvals, Rev. 1

NPG-SPP-09.15, Underground Piping and Tanks Integrity Program (UPTI), Rev. 6

NPG-SPP-09.16.1, System, Component and Program Health, Rev. 3

SI-GWT-100, Structural Integrity GWT Piping and Inspection General Procedure, Rev. 3

SI-GWT-103, Ultrasonic Thickness in Support of Guided Wave Testing (GWT), Rev. 1

Other Documents

Drawing # 0-17E300-8-23-13, Mechanical Isometric RHR Service Water Piping, Rev. 2

Drawing # 0-17E401-11, Mechanical Hardened Wetwell Vent Piping, Rev. 1

Drawing # 017W-9-67-1, Mechanical Isometric Emergency Equipment Cooling Water, Rev. 0

Drawing # 0-47E830-3-77-1, Flow Diagram Radwaste, Rev. 26

EPRI TR 1016456, Recommendations for an Effective Program to Control the Degradation of

Buried Pipe

Nuclear Energy Institute (NEI) 09-14, Guideline for the Management of Buried Piping Integrity,

Rev. 3

Program Health Report, 1/1/2013-6/30/2013

Program Health Report, 7/1/2012-12/31/2012

Report No. R06131219899, Radwaste Leak Inspection Report

Report No. R06121220058, Condition Assessment - Underground Piping and Tanks

Report No. R06131217892, Underground Piping and Tanks Inspection Plan, Rev. 5

Report No. BFN-ENG-F-10-002, Buried Piping Program Self-Assessment Report

Report No. 1200135.401, Structural Integrity Associates Report on GWT Excavation of

Radwaste Pipes

Report No. 04226.15, Underwater Construction Report on Condensate Storage Tank No. 1

Immersion Area In-Service Cleaning & Inspection

Report No. BFN-ENG-S-13-014, Self-Assessment of Buried Piping and Underground Piping

and Tanks

Report No. L2909128800, Benchmarking to Calloway Report

Report No. CRP-ENG-F-12-0002, TVA Fleet wide Piping and Tanks Inspection Program

Self-Assessment

Work Order No. 112816452, 2-SI-4.5.c.1(3) RHRSW Pump and Header Operability and Flow

Tests, 4/24/2012

Attachment

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

RHR - residual heat removal

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

SLC - standby liquid control

SNM - special nuclear material

SRV - safety relief valve

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

Attachment

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