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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 | | author name = Croteau R | ||
| author affiliation = NRC/RGN-II/DRP | | author affiliation = NRC/RGN-II/DRP | ||
| addressee name = Shea J | | 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: [[ | See also: [[see also::IR 05000259/2013005]] | ||
=Text= | =Text= | ||
{{#Wiki_filter: | {{#Wiki_filter: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 | |||
We intend to complete and issue our final safety significance determination within 90 days from the date of this letter. The | 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 | 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 | 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. | |||
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 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, | 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 | |||
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 | ||
_ 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 | |||
* 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 | |||
3 | |||
Cornerstone: Mitigating Systems | |||
* Green: The NRC-identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, | |||
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. | |||
* Green: | 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)] | 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 | |||
* TBD: | 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 | 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: | * TBD: The NRC identified two examples of an Apparent Violation of 10 CFR 50.9, | ||
* TBD: | 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. | staffing requirements. Specifically, on two occasions the licensee apparently provided | ||
* Severity Level IV: | 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 | |||
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 | |||
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 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 | |||
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: | |||
eight Assistant Unit Operators (AUOs), and one Shift Technical Advisor. The LARs indicated that the stated staffing levels were required once | |||
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 | |||
On September 06, 2013, the licensee initiated a self-assessment entitled | |||
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 | |||
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 | |||
* 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 | |||
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) | |||
* 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 | |||
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 | |||
(Section | (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 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 | |||
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 | |||
: NPG-SPP-09. | 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 | |||
: NPG-SPP-06.3, Pre-/Post-Maintenance Testing, Rev. 1 | 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 | |||
}} | }} |
Latest revision as of 09:09, 4 November 2019
ML14045A320 | |
Person / Time | |
---|---|
Site: | Browns Ferry ![]() |
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) | |
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
Mr. J.W. Shea
Vice President, Nuclear Licensing
Tennessee Valley Authority
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
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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
- 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
3
Cornerstone: Mitigating Systems
- Green: The NRC-identified a non-cited violation (NCV) of 10 CFR 50, Appendix B,
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
- 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
- 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 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
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
- 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
20
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
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
- 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
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
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 113206742
WO 114245152
WO 114687057
WO 114917994
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
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
RHRSW - residual heat removal service water
RTP - rated thermal power
RPS - reactor protection system
RWP - radiation work permit
SDP - significance determination process
SBGT - standby gas treatment
SNM - special nuclear material
SSC - structure, system, or component
TI - Temporary Instruction
TIP - transverse in-core probe
TRM - Technical Requirements Manual
TS - Technical Specification(s)
UFSAR - Updated Final Safety Analysis Report
URI - unresolved item
WO - work order
Attachment