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{{#Wiki_filter:UNITED STATES
{{#Wiki_filter:UNITED STATES  
                                  NUCLEAR REGULATORY COMMISSION
NUCLEAR REGULATORY COMMISSION  
                                              REGION II
REGION II  
                              245 PEACHTREE CENTER AVENUE NE, SUITE 1200
245 PEACHTREE CENTER AVENUE NE, SUITE 1200  
                                      ATLANTA, GEORGIA 30303-1257
ATLANTA, GEORGIA 30303-1257  
                                        November 22, 2017
Mr. Joseph W. Shea
Vice President, Nuclear Licensing
November 22, 2017  
Tennessee Valley Authority
1101 Market Street, LP 3D-C
Mr. Joseph W. Shea  
Chattanooga, TN 37402-2801
Vice President, Nuclear Licensing  
SUBJECT: WATTS BAR NUCLEAR PLANT - NUCLEAR REGULATORY COMMISSION
              INTEGRATED INSPECTION REPORT 05000390/2017003, 05000391/2017003
Tennessee Valley Authority  
Dear Mr. Shea:
1101 Market Street, LP 3D-C  
On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an
Chattanooga, TN 37402-2801  
inspection at your Watts Bar Nuclear Plant, Unit 1 and Unit 2. On October 25, 2017, the NRC
inspectors discussed the results of this inspection with Mr. Tom Marshall and other members of
SUBJECT: WATTS BAR NUCLEAR PLANT - NUCLEAR REGULATORY COMMISSION  
your staff. A re-exit was conducted on November 8, 2017, with Ms. Kim Hulvey. The results of
INTEGRATED INSPECTION REPORT 05000390/2017003, 05000391/2017003  
this inspection are documented in the enclosed inspection report.
The NRC inspectors documented three findings of very low safety significance (Green) in this
Dear Mr. Shea:  
report which also involved violations of NRC requirements. Additionally, inspectors documented
six licensee-identified violations which were determined to be of very low safety significance in
On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an  
this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with
inspection at your Watts Bar Nuclear Plant, Unit 1 and Unit 2. On October 25, 2017, the NRC  
Section 2.3.2.a of the Enforcement Policy. If you contest these violations or significance of
inspectors discussed the results of this inspection with Mr. Tom Marshall and other members of  
these NCVs, you should provide a response within 30 days of the date of this inspection report,
your staff. A re-exit was conducted on November 8, 2017, with Ms. Kim Hulvey. The results of  
with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document
this inspection are documented in the enclosed inspection report.  
Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region
II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C.
The NRC inspectors documented three findings of very low safety significance (Green) in this  
20555-0001; and the NRC Resident Inspector at the Watts Bar Nuclear Plant.
report which also involved violations of NRC requirements. Additionally, inspectors documented  
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
six licensee-identified violations which were determined to be of very low safety significance in  
response within 30 days of the date of this inspection report, with the basis for your
this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with  
disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the
Section 2.3.2.a of the Enforcement Policy. If you contest these violations or significance of  
Watts Bar Nuclear Plant.
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, D.C. 20555-0001; with copies to the Regional Administrator, Region  
II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C.  
20555-0001; and the NRC Resident Inspector at the Watts Bar Nuclear Plant.
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  
Watts Bar Nuclear Plant.  


J. Shea                                     2
J. Shea  
This letter, its enclosure, and your response (if any) will be available for public inspection and
2  
copying at http://www.nrc.gov/reading-rm/adams.html and in the NRC Public Document Room
in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections,
Exemptions, Requests for Withholding.
This letter, its enclosure, and your response (if any) will be available for public inspection and  
                                              Sincerely,
copying at http://www.nrc.gov/reading-rm/adams.html and in the NRC Public Document Room  
                                              /RA/
in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections,  
                                              Alan Blamey, Chief
Exemptions, Requests for Withholding.  
                                              Reactor Projects Branch 6
                                              Division of Reactor Projects
Docket Nos.: 50-390, 50-391
License Nos.: NPF-90, 96
Enclosure:
IR 05000390/2017003, 05000391/2017003
  w/Attachment: Supplemental Information
cc Distribution via ListServ
Sincerely,  
/RA/  
Alan Blamey, Chief
Reactor Projects Branch 6  
Division of Reactor Projects  
Docket Nos.:   50-390, 50-391
License Nos.: NPF-90, 96  
Enclosure:  
IR 05000390/2017003, 05000391/2017003  
  w/Attachment: Supplemental Information  
cc Distribution via ListServ  




  ML17326A222
  ML17326A222
OFFICE         RII: DRP     RII: DRP         RII: DRP     RII: DRP   RII: DRP     RII: DRP
OFFICE  
NAME           RTaylor     BDavis           GCrespo     BBishop   JEargle     ELea
RII: DRP  
DATE           10/31/2017   11/8/2017       10/31/2017   10/31/2017 11/6/2017   11/6/2017
RII: DRP  
OFFICE         RII: DRP     RII: DRP         RII: DRP     R:II DRP   NCP Approver
RII: DRP  
NAME           JHamman     JJandovitz       ABlamey     JNadel     MFranke
RII: DRP  
DATE           10/31/2017   11/3/2017       11/21/2017   11/7/2017 11/22/2017
RII: DRP  
                                     
RII: DRP  
              U.S. NUCLEAR REGULATORY COMMISSION
NAME  
                                REGION II
RTaylor  
Docket Nos.:      50-390, 50-391
BDavis  
License Nos.:      NPF-90, NPF-96
GCrespo  
Report No.:        05000390/2017003, 05000391/2017003
BBishop  
Licensee:          Tennessee Valley Authority (TVA)
JEargle  
Facility:          Watts Bar Nuclear Plant, Units 1 and 2
ELea  
Location:          Spring City, TN 37381
DATE  
Dates:            July 1 through September 30, 2017
10/31/2017  
Inspectors:        J. Nadel, Senior Resident Inspector
11/8/2017  
                  J. Hamman, Resident Inspector
10/31/2017  
                  J. Jandovitz, Senior Resident Inspector
10/31/2017  
                  E. Lea, Regional Government Liaison Officer
11/6/2017  
                  S. Freeman, Senior Reactor Analyst
11/6/2017  
                  J. Eargle, Senior Construction Inspector
OFFICE  
                  B. Bishop, Project Engineer
RII: DRP  
                  G. Crespo, Senior Construction Inspector
RII: DRP  
                  C. Rapp, Senior Project Engineer
RII: DRP  
                  R. Taylor, Senior Project Inspector
R:II DRP  
                  B. Davis, Senior Construction Inspector
NCP Approver  
Approved by:      Alan Blamey, Chief
                  Reactor Projects Branch 6
NAME  
                  Division of Reactor Projects
JHamman  
                                                              Enclosure
JJandovitz  
ABlamey  
JNadel  
MFranke  
DATE  
10/31/2017  
11/3/2017  
11/21/2017  
11/7/2017  
11/22/2017  


                                            SUMMARY
IR 05000390/2017-003; 05000391/2017-003; July 1, 2017 - September 30, 2017; Watts Bar
Enclosure
Nuclear Plant; Operability Evaluations, Surveillance Testing.
U.S. NUCLEAR REGULATORY COMMISSION
The report covered a three-month period of inspection by the resident inspectors. Three Green
non-cited violations (NCV) were identified. The significance of most findings is indicated by their
REGION II
color (i.e., Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC)
0609, "Significance Determination Process," (SDP) dated April 29, 2015. Cross-cutting aspects
are determined using IMC 0310, Aspects Within Cross-Cutting Areas, dated
Docket Nos.: 
December 04, 2014. All violations of NRC requirements are dispositioned in accordance with
the NRCs Enforcement Policy, dated November 1, 2016. The NRCs program for overseeing
50-390, 50-391
the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process, Revision 6. Documents reviewed by the inspectors not identified in the
Report Details are listed in the Attachment.
License Nos.: 
Cornerstone: Mitigating Systems
*  Green. An NRC-identified NCV was identified for the failure to maintain written procedures
NPF-90, NPF-96
    for emergencies. Emergency procedure 1-E-1, Revision 7 and 2-E-1 Revision 0, both titled
    Loss of Reactor or Secondary Coolant, were updated to include steps directing
    inappropriate actions that would have affected emergency raw cooling water (ERCW) supply
Report No.:
    flow during an accident. The immediate corrective action was to remove the inappropriate
    steps. This violation was documented in the licensees corrective action program (CAP) as
    CR 1331422.
05000390/2017003, 05000391/2017003
    The performance deficiency was more than minor because it affected the Mitigating
    Systems Cornerstone attribute of Procedure Quality and adversely affected the cornerstone
    objective in that the reduced ERCW flow caused by the inappropriate steps affects the heat
Licensee:
    removal capability of the ERCW and component cooling systems (CCS) during a loss of
    coolant accident (LOCA). The finding was determined to require a detailed risk evaluation
    because it represented an actual loss of function of at least a single train for greater than its
Tennessee Valley Authority (TVA)  
    TS allowed outage time. The result was less than 1E-6 for each unit which would be a
    finding of very low significance (Green). The risk was mitigated because the performance
    deficiency would affect operation only when a LOCA occurred and simultaneous loss of two
Facility:
    shutdown boards. The finding has a cross-cutting aspect in the documentation attribute of
    the Human Performance area because the licensee did not maintain the accuracy of 1-E-1
    through its revisions and did not maintain procedure 2-E-1 accurate at its creation. (H.7)
Watts Bar Nuclear Plant, Units 1 and 2
    (Section 1R15)
*  Green. An NRC-identified NCV of Technical Specification (TS) 5.7.1.1.a, Procedures, was
    identified for the failure to maintain TVA procedures 1-GO-6 and 2-GO-6, both titled Unit
Location:
    Shutdown from Hot Standby to Cold Shutdown. The licensee failed to update the
    procedures prior to commencing dual unit operation to include steps that would shut down
    the running motor driven auxiliary feedwater pump prior to starting a third ERCW pump
Spring City, TN 37381
    during the time period where the opposite unit has been shut down less than 48 hours. The
    licensees immediate corrective actions included revising both procedures to add the
    required steps. This violation was documented in the licensees CAP as CR 1318176.
Dates:
July 1 through September 30, 2017
Inspectors:
J. Nadel, Senior Resident Inspector
J. Hamman, Resident Inspector
J. Jandovitz, Senior Resident Inspector
E. Lea, Regional Government Liaison Officer
S. Freeman, Senior Reactor Analyst
J. Eargle, Senior Construction Inspector
B. Bishop, Project Engineer
G. Crespo, Senior Construction Inspector
C. Rapp, Senior Project Engineer
R. Taylor, Senior Project Inspector
B. Davis, Senior Construction Inspector
Approved by: 
Alan Blamey, Chief 
Reactor Projects Branch 6
Division of Reactor Projects


                                                  3
    The performance deficiency was more than minor because it affected the Mitigating
    Systems Cornerstone attribute of Equipment Performance and adversely affected the
SUMMARY
    cornerstone objective in that failure to maintain the procedures resulted in a situation where
    the emergency diesel generator would have been rendered inoperable during a design basis
IR 05000390/2017-003; 05000391/2017-003; July 1, 2017 - September 30, 2017; Watts Bar
    event. The inspectors determined the finding was of very low safety significance (Green)
Nuclear Plant; Operability Evaluations, Surveillance Testing.
    because the finding did not represent an actual loss of function of a single train for greater
    than its TS allowed outage time. The finding had a cross-cutting aspect in the Avoid
The report covered a three-month period of inspection by the resident inspectors.  Three Green
    Complacency attribute of the Human Performance area because engineering missed a
non-cited violations (NCV) were identified. The significance of most findings is indicated by their
    critical aspect of the required procedure changes associated with design change notice
color (i.e., Green, White, Yellow, Red)  and determined using Inspection Manual Chapter (IMC)  
    62151 when performing the prompt determination of operability and the review process was
0609, "Significance Determination Process," (SDP) dated April 29, 2015. Cross-cutting aspects
    unsuccessful at identifying the error [H.12]. (Section 1R15)
are determined using IMC 0310, Aspects Within Cross-Cutting Areas, dated             
Cornerstone: Initiating Events
December 04, 2014.  All violations of NRC requirements are dispositioned in accordance with
*   Green. A self-revealed NCV of (TS) 5.7.1.1.a, Procedures, was identified for the failure to
the NRCs Enforcement Policy, dated November 1, 2016.  The NRCs program for overseeing
    follow TVA procedure 2-SI-68-86, 18 month Channel Calibration of Remote Shutdown
the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
    Monitoring Narrow Range Pressurizer Pressure Loop 2-LPP-68-337C, revision 4. The
Oversight Process, Revision 6.  Documents reviewed by the inspectors not identified in the  
    licensee failed to properly follow step 6.2.6 [1.3], which resulted in the inadvertent lifting of a
Report Details are listed in the Attachment.  
    pressurizer power operated relief valve (PORV). The licensees immediate corrective
    actions included revising the procedure. This violation was documented in the licensees
Cornerstone: Mitigating Systems
    CAP as CR 1309345.
    The performance deficiency was more than minor because it affected the Initiating Events
*  
    Cornerstone attribute of Human Performance and adversely affected the cornerstone
Green. An NRC-identified NCV was identified for the failure to maintain written procedures
    objective in that failing to follow procedure 2-SI-68-86 caused a depressurization of the plant
for emergencies.  Emergency procedure 1-E-1, Revision 7 and 2-E-1 Revision 0, both titled
    that had to be stopped by operator action. The finding was determined to be very low safety
Loss of Reactor or Secondary Coolant, were updated to include steps directing
    significance (Green) because the resultant leakage from the open PORV would be
inappropriate actions that would have affected emergency raw cooling water (ERCW) supply
    self-limiting such that it would stop before impacting the operating method of decay heat
flow during an accident. The immediate corrective action was to remove the inappropriate
    removal. The finding had a cross-cutting aspect in the Challenge the Unknown component
steps. This violation was documented in the licensees corrective action program (CAP) as  
    of the Human Performance area as defined in NRC IMC 0310, because the technicians
CR 1331422.  
    failed to recognize that the output was already set to 0, but proceeded anyway to toggle the
    output which resulted in setting it to 1 [H.11]. (Section 1R22)
The performance deficiency was more than minor because it affected the Mitigating
Six violations of very low safety significance, identified by the licensee, have been reviewed by
Systems Cornerstone attribute of Procedure Quality and adversely affected the cornerstone  
the NRC. Corrective actions taken or planned by the licensee have been entered into the
objective in that the reduced ERCW flow caused by the inappropriate steps affects the heat
licensees CAP. These violations and the corrective action tracking numbers are listed in
removal capability of the ERCW and component cooling systems (CCS) during a loss of  
Section 4OA7 of this report.
coolant accident (LOCA). The finding was determined to require a detailed risk evaluation
because it represented an actual loss of function of at least a single train for greater than its
TS allowed outage time.  The result was less than 1E-6 for each unit which would be a
finding of very low significance (Green).  The risk was mitigated because the performance
deficiency would affect operation only when a LOCA occurred and simultaneous loss of two
shutdown boards. The finding has a cross-cutting aspect in the documentation attribute of
the Human Performance area because the licensee did not maintain the accuracy of 1-E-1
through its revisions and did not maintain procedure 2-E-1 accurate at its creation. (H.7)
(Section 1R15)  
*
Green.  An NRC-identified NCV of Technical Specification (TS) 5.7.1.1.a, Procedures, was
identified for the failure to maintain TVA procedures 1-GO-6 and 2-GO-6, both titled Unit
Shutdown from Hot Standby to Cold Shutdown.  The licensee failed to update the
procedures prior to commencing dual unit operation to include steps that would shut down
the running motor driven auxiliary feedwater pump prior to starting a third ERCW pump
during the time period where the opposite unit has been shut down less than 48 hours. The
licensees immediate corrective actions included revising both procedures to add the  
required steps.  This violation was documented in the licensees CAP as CR 1318176.


                                        REPORT DETAILS
3
Summary of Plant Status
Unit 1 operated at 100 percent rated thermal power (RTP) for the entire reporting period.
Unit 2 began the reporting period shutdown for repairs to the main condenser. The unit was
The performance deficiency was more than minor because it affected the Mitigating
started up on July 23, 2017, but was shutdown to hot standby later that day due to equipment
Systems Cornerstone attribute of Equipment Performance and adversely affected the  
problems. On July 25, 2017, startup resumed, but the reactor was tripped before criticality due
cornerstone objective in that failure to maintain the procedures resulted in a situation where
to rod position indication problems during the startup. Startup commenced again on
the emergency diesel generator would have been rendered inoperable during a design basis
July 27, 2017, but was stopped due to additional rod position indication problems. Unit 2 started
event. The inspectors determined the finding was of very low safety significance (Green)
up after rod position indication repairs on July 30, 2017, and achieved 29 percent RTP on
because the finding did not represent an actual loss of function of a single train for greater
August 2, 2017. The unit remained at that power until August 8, 2017, when the turbine was
than its TS allowed outage time. The finding had a cross-cutting aspect in the Avoid
tripped due to a steam leak on a turbine drain line. The unit stabilized at 8 percent RTP and
Complacency attribute of the Human Performance area because engineering missed a
remained there until power ascension resumed after drain line repairs. Unit 2 reached
critical aspect of the required procedure changes associated with design change notice
100 percent RTP on August 8, 2017, and remained there for the remainder of the reporting
62151 when performing the prompt determination of operability and the review process was  
period.
unsuccessful at identifying the error [H.12]. (Section 1R15)
1.     REACTOR SAFETY
        Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
Cornerstone:  Initiating Events
1R01 Adverse Weather Protection (71111.01)
        External Flood Protection Inspection
*
  a.   Inspection Scope
Green.  A self-revealed NCV of (TS) 5.7.1.1.a, Procedures, was identified for the failure to  
        The inspectors reviewed the licensees readiness to cope with external flooding.
follow TVA procedure 2-SI-68-86, 18 month Channel Calibration of Remote Shutdown
        External flooding from a probable maximum precipitation (PMP) or design basis flood
Monitoring Narrow Range Pressurizer Pressure Loop 2-LPP-68-337C, revision 4. The  
        (DBF) had the potential for internal flooding of a portion of a number of the plant
licensee failed to properly follow step 6.2.6 [1.3], which resulted in the inadvertent lifting of a
        structures. The inspectors reviewed the feasibility of the licensees flooding mitigation
pressurizer power operated relief valve (PORV). The licensees immediate corrective
        plans and design features and verified that they were consistent with the licensees
actions included revising the procedure. This violation was documented in the licensees  
        design requirements and the risk analysis assumptions for coping with this type of
CAP as CR 1309345.  
        event. The inspectors performed walkdowns of selected areas to observe grading, yard
        drains, and curbs in the vicinity of the south valve vault rooms. The inspectors also
The performance deficiency was more than minor because it affected the Initiating Events
        checked status of the flood mode boat. The inspectors reviewed external flood
Cornerstone attribute of Human Performance and adversely affected the cornerstone
        protection features at the intake pumping station and condition of the strainer room sump
objective in that failing to follow procedure 2-SI-68-86 caused a depressurization of the plant  
        pumps. Additionally, the inspectors reviewed the licensees related corrective action
that had to be stopped by operator action. The finding was determined to be very low safety
        documents (condition reports) to ensure any non-conforming conditions related to
significance (Green) because the resultant leakage from the open PORV would be         
        potential flooding were properly addressed. The inspection was performed prior to the
self-limiting such that it would stop before impacting the operating method of decay heat
        expected rainfall from Hurricane Irma. This activity constituted one Adverse Weather
removal. The finding had a cross-cutting aspect in the Challenge the Unknown component
        Protection inspection sample, as defined in Inspection Procedure (IP) 71111.01.
of the Human Performance area as defined in NRC IMC 0310, because the technicians
  b.    Findings
failed to recognize that the output was already set to 0, but proceeded anyway to toggle the  
        No findings were identified.
output which resulted in setting it to 1 [H.11].  (Section 1R22)
Six violations of very low safety significance, identified by the licensee, have been reviewed by
the NRC. Corrective actions taken or planned by the licensee have been entered into the  
licensees CAP. These violations and the corrective action tracking numbers are listed in  
Section 4OA7 of this report.  


                                                5
1R04 Equipment Alignment (71111.04)
    Partial System Walkdowns
  a. Inspection Scope
REPORT DETAILS
    The inspectors conducted the equipment alignment partial walkdowns listed below to
   
    evaluate the operability of selected redundant trains or backup systems prior to unit
Summary of Plant Status
    transition into the mode of applicability for the systems. This also included that
   
    redundant trains were returned to service properly. The inspectors reviewed the
Unit 1 operated at 100 percent rated thermal power (RTP) for the entire reporting period.
    functional system descriptions, the Updated Final Safety Analysis Report (UFSAR),
    system operating procedures, and TS to determine correct system lineups for the current
Unit 2 began the reporting period shutdown for repairs to the main condenser. The unit was
    plant conditions. The inspectors performed walkdowns of the systems to verify that
started up on July 23, 2017, but was shutdown to hot standby later that day due to equipment
    critical components were properly aligned and to identify any discrepancies which could
problems.  On July 25, 2017, startup resumed, but the reactor was tripped before criticality due
    affect operability of the redundant train or backup system. This activity constituted six
to rod position indication problems during the startup. Startup commenced again on             
    inspection samples, as defined in IP 71111.04.
July 27, 2017, but was stopped due to additional rod position indication problems.  Unit 2 started
    *    2A and 2B train of motor-driven auxiliary feedwater and Unit 2 turbine-driven
up after rod position indication repairs on July 30, 2017, and achieved 29 percent RTP on   
           auxiliary feedwater prior to mode change
August 2, 2017. The unit remained at that power until August 8, 2017, when the turbine was
    *    2A and 2B train of safety injection prior to mode change
tripped due to a steam leak on a turbine drain line. The unit stabilized at 8 percent RTP and
    *    2A train of containment spray prior to mode change
remained there until power ascension resumed after drain line repairs. Unit 2 reached            
    *    2B train of containment spray prior to mode change
100 percent RTP on August 8, 2017, and remained there for the remainder of the reporting
    *    2A-A emergency diesel generator prior to mode change
period.
    *    2B-B emergency diesel generator prior to mode change
  b. Findings
1.
    No findings were identified.
REACTOR SAFETY
1R05 Fire Protection (71111.05AQ)
    Fire Protection Tours
   
  a. Inspection Scope
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
    The inspectors conducted tours of the areas important to reactor safety listed below to
    verify the licensees implementation of fire protection requirements as described in: the
1R01 Adverse Weather Protection (71111.01)  
    Fire Protection Program, Nuclear Power Group Standard Programs and Processes
    (NPG-SPP)-18.4.6, Control of Fire Protection Impairments; NPG-SPP-18.4.7, Control of
    Transient Combustibles; and NPG-SPP-18.4.8, Control of Ignition Sources (Hot Work).
External Flood Protection Inspection
    The inspectors evaluated, as appropriate, conditions related to: 1) licensee control of
   
    transient combustibles and ignition sources; 2) the material condition, operational status,
a.  
    and operational lineup of fire protection systems, equipment, and features; and 3) the
Inspection Scope  
    fire barriers used to prevent fire damage or fire propagation.
The inspectors reviewed the licensees readiness to cope with external flooding. 
External flooding from a probable maximum precipitation (PMP) or design basis flood
(DBF) had the potential for internal flooding of a portion of a number of the plant
structures.  The inspectors reviewed the feasibility of the licensees flooding mitigation
plans and design features and verified that they were consistent with the licensees  
design requirements and the risk analysis assumptions for coping with this type of
event.  The inspectors performed walkdowns of selected areas to observe grading, yard
drains, and curbs in the vicinity of the south valve vault rooms. The inspectors also
checked status of the flood mode boat. The inspectors reviewed external flood
protection features at the intake pumping station and condition of the strainer room sump
pumps. Additionally, the inspectors reviewed the licensees related corrective action
documents (condition reports) to ensure any non-conforming conditions related to  
potential flooding were properly addressed.  The inspection was performed prior to the  
expected rainfall from Hurricane Irma.  This activity constituted one Adverse Weather
Protection inspection sample, as defined in Inspection Procedure (IP) 71111.01.
b.
Findings
No findings were identified.  


                                                6
5
    This activity constituted three inspection samples, as defined in IP 71111.05AQ.
    *   Auxiliary building elevation 713
    *   Auxiliary building elevation 676
1R04 Equipment Alignment (71111.04)
    *   Control building elevation 729 and 741 (cable spreading room)
  b. Findings
    No findings were identified.
Partial System Walkdowns
1R11 Licensed Operator Requalification and Performance (71111.11)
.1  Licensed Operator Requalification Review
a.
  a. Inspection Scope
Inspection Scope 
    On September 12, 2017, the inspectors observed licensed operator training
    examinations on the simulator per scenario 3-OT-SRE-1017, revision 7. The scenario
    included a feedwater line break and subsequent loss of all main and auxiliary feed
The inspectors conducted the equipment alignment partial walkdowns listed below to
    capability. The inspectors specifically evaluated the following attributes related to the
evaluate the operability of selected redundant trains or backup systems prior to unit
    operating crews performance:
transition into the mode of applicability for the systems.  This also included that
    *  Clarity and formality of communication
redundant trains were returned to service properly.  The inspectors reviewed the
    *  Ability to take timely action to safely control the unit
functional system descriptions, the Updated Final Safety Analysis Report (UFSAR),
    *  Prioritization, interpretation, and verification of alarms
system operating procedures, and TS to determine correct system lineups for the current
    *  Correct use and implementation of abnormal operating instructions and emergency
plant conditions.  The inspectors performed walkdowns of the systems to verify that
        operating instructions
critical components were properly aligned and to identify any discrepancies which could
    *  Timely and appropriate Emergency Action Level declarations per emergency plan
affect operability of the redundant train or backup system.  This activity constituted six
        implementing procedures
inspection samples, as defined in IP 71111.04.  
    *  Control board operation and manipulation, including high-risk operator actions
    *  Command and Control provided by the unit supervisor and shift manager
*  
    The inspectors also attended the critique to assess the effectiveness of the licensee
2A and 2B train of motor-driven auxiliary feedwater and Unit 2 turbine-driven
    evaluators, and to verify that licensee-identified issues were comparable to issues
auxiliary feedwater prior to mode change
    identified by the inspector. This activity constituted one Observation of Requalification
*  
    Activity inspection sample, as defined in IP 71111.11.
2A and 2B train of safety injection prior to mode change
  b. Findings
*  
    No findings were identified
2A train of containment spray prior to mode change
*
2B train of containment spray prior to mode change
*
2A-A emergency diesel generator prior to mode change
*
2B-B emergency diesel generator prior to mode change 
b.  
Findings  
No findings were identified.  
1R05 Fire Protection (71111.05AQ)  
Fire Protection Tours
a.  
Inspection Scope  
The inspectors conducted tours of the areas important to reactor safety listed below to
verify the licensees implementation of fire protection requirements as described in: the
Fire Protection Program, Nuclear Power Group Standard Programs and Processes
(NPG-SPP)-18.4.6, Control of Fire Protection Impairments; NPG-SPP-18.4.7, Control of
Transient Combustibles; and NPG-SPP-18.4.8, Control of Ignition Sources (Hot Work). 
The inspectors evaluated, as appropriate, conditions related to: 1) licensee control of
transient combustibles and ignition sources; 2) the material condition, operational status,  
and operational lineup of fire protection systems, equipment, and features; and 3) the  
fire barriers used to prevent fire damage or fire propagation.  


                                                7
6
.2  Observation of Operator Performance
   a. Inspection Scope
    Inspectors observed and assessed licensed operator performance in the plant and main
This activity constituted three inspection samples, as defined in IP 71111.05AQ. 
    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 such as procedures OPDP-1, Conduct of Operations; NPG-SPP-10.0, Plant
Auxiliary building elevation 713
    Operations; and GO-4, Normal Power Operation. Inspectors used activities such as
*
    post-maintenance testing, surveillance testing and refueling, and other outage activities
Auxiliary building elevation 676
    to focus on the following conduct of operations as appropriate. This activity constituted
*
    one Observation of Operator Performance inspection sample, as defined in IP 71111.11.
Control building elevation 729 and 741 (cable spreading room)
    *   Operator compliance and use of procedures
    *   Control board manipulations
b.
    *   Communication between crew members
Findings
    *  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
No findings were identified.  
    *   Pre-job briefs
  b. Findings
1R11 Licensed Operator Requalification and Performance (71111.11)
    No findings were identified.
1R12 Maintenance Effectiveness (71111.12)
.1    
  a. Inspection Scope
Licensed Operator Requalification Review
    The inspectors reviewed the performance-based problem listed below. A review was
    performed to assess the effectiveness of maintenance efforts that apply to scoped
a.  
    structures, systems, or components (SSCs) and to verify that the licensee was following
Inspection Scope  
    the requirements of TI-119, Maintenance Rule Performance Indicator Monitoring,
    Trending, and Reporting - 10 CFR 50.65, and NPG-SPP-03.4, Maintenance Rule
On September 12, 2017, the inspectors observed licensed operator training
    Performance Indicator Monitoring, Trending, and Reporting - 10 CFR 50.65. Reviews
examinations on the simulator per scenario 3-OT-SRE-1017, revision 7. The scenario
    focused, as appropriate, on: 1) appropriate work practices; 2) identification and
included a feedwater line break and subsequent loss of all main and auxiliary feed
    resolution of common cause failures; 3) scoping in accordance with 10 CFR 50.65;
capability.  The inspectors specifically evaluated the following attributes related to the  
    4) characterizing reliability issues for performance monitoring; 5) tracking unavailability
operating crews performance:
    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
Clarity and formality of communication
*  
Ability to take timely action to safely control the unit
*  
Prioritization, interpretation, and verification of alarms  
*  
Correct use and implementation of abnormal operating instructions and emergency
operating instructions 
*  
Timely and appropriate Emergency Action Level declarations per emergency plan
implementing procedures
*  
Control board operation and manipulation, including high-risk operator actions
*  
Command and Control provided by the unit supervisor and shift manager
The inspectors also attended the critique to assess the effectiveness of the licensee
evaluators, and to verify that licensee-identified issues were comparable to issues
identified by the inspector.  This activity constituted one Observation of Requalification
Activity inspection sample, as defined in IP 71111.11.  
b.  
Findings
No findings were identified


                                                8
7
    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. This activity constituted
    one Maintenance Effectiveness inspection sample, as defined in IP 71111.12.
.2 
    *   Condition Report (CR) 1316520, Unit 2 function 063-B Train A (2A safety injection
Observation of Operator Performance
        pump) exceeded performance criteria
  b.  Findings
a.
    No findings were identified.
Inspection Scope
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
  a. Inspection Scope
Inspectors observed and assessed licensed operator performance in the plant and main
    The inspectors evaluated, as appropriate, for the work activities listed below:
control room, particularly during periods of heightened activity or risk and where the
    1) the effectiveness of the risk assessments performed before maintenance activities
activities could affect plant safety.  Inspectors reviewed various licensee policies and
    were conducted; 2) the management of risk; 3) that, upon identification of an unforeseen
procedures such as procedures OPDP-1, Conduct of Operations; NPG-SPP-10.0, Plant
    situation, necessary steps were taken to plan and control the resulting emergent work
Operations; and GO-4, Normal Power Operation.  Inspectors used activities such as
    activities; and 4) that maintenance risk assessments and emergent work problems were
post-maintenance testing, surveillance testing and refueling, and other outage activities
    adequately identified and resolved. The inspectors verified that the licensee was
to focus on the following conduct of operations as appropriate. This activity constituted  
    complying with the requirements of 10 CFR 50.65 (a)(4); NPG-SPP-07.0, Work Control
one Observation of Operator Performance inspection sample, as defined in IP 71111.11.  
    and Outage Management; NPG-SPP-07.1, On Line Work Management;
    NPG-SPP-09.11.1, Equipment Out of Service Management; and TI-124, Equipment to
*  
    Plant Risk Matrix. This activity constituted four Maintenance Risk Assessment
Operator compliance and use of procedures
    inspection samples, as defined in IP 71111.13.
*
    *  Risk assessment for August 11, 2017, with the 1A emergency diesel generator
Control board manipulations
        (EDG) out of service (OOS) for an extended planned maintenance outage and
*
        applicability of TS 3.8.1.B.5 for the extended limiting condition for operation time
Communication between crew members
        period based on FLEX EDG availability
*
    *  Risk assessment for August 4, 2017, with 1B-B auxiliary feedwater train OOS and
Use and interpretation of plant instruments, indications and alarms
        replacement main transformer movement under dedicated offsite power lines
*
    *  Risk assessment for August 29, 2017, with both sources of offsite power inoperable
Use of human error prevention techniques
        due to a disqualified grid
*
    *  Risk assessment for work week 0905 with 1A-A motor driven auxiliary feedwater,
Documentation of activities, including initials and sign-offs in procedures
        1A-A component cooling system pump OOS for maintenance and high risk work on
*
        Unit 1 turbine electrohydraulic controls, and A main control room chiller OOS
Supervision of activities, including risk and reactivity management
  b. Findings
*
    No findings were identified.
Pre-job briefs
   
b.  
Findings
   
No findings were identified.  
1R12 Maintenance Effectiveness (71111.12)  
   
a.  
Inspection Scope  
The inspectors reviewed the performance-based problem listed below.  A review was
performed to assess the effectiveness of maintenance efforts that apply to scoped
structures, systems, or components (SSCs) and to verify that the licensee was following
the requirements of TI-119, Maintenance Rule Performance Indicator Monitoring,
Trending, and Reporting - 10 CFR 50.65, and NPG-SPP-03.4, Maintenance Rule
Performance Indicator Monitoring, Trending, and Reporting - 10 CFR 50.65. Reviews
focused, as appropriate, on:  1) appropriate work practices; 2) identification and  
resolution of common cause failures; 3) scoping in accordance with 10 CFR 50.65; 
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 
   
   


                                                9
8
1R15 Operability Evaluations (71111.15)
  a. Inspection Scope
    The inspectors reviewed the operability evaluations affecting risk-significant mitigating
in accordance with 10 CFR 50.65(a)(2); and 10) appropriateness and adequacy of     
    systems listed below, to assess, as appropriate: 1) the technical adequacy of the
10 CFR 50.65 (a)(1) goals, monitoring and corrective actions.  This activity constituted
    evaluations; 2) whether continued system operability was warranted; 3) whether the
one Maintenance Effectiveness inspection sample, as defined in IP 71111.12.
    compensatory measures, if involved, were in place, would work as intended, and were
    appropriately controlled; 4) where continued operability was considered unjustified, the
*
    impact on TS Limiting Conditions for Operation (LCO) and the risk-significance in
Condition Report (CR) 1316520, Unit 2 function 063-B Train A (2A safety injection
    accordance with the significant determination process (SDP). The inspectors verified
pump) exceeded performance criteria
    that the operability evaluations were performed in accordance with NPG-SPP-03.1,
    CAP. Additional documents reviewed are listed in the Attachment. This activity
b.
    constituted seven Operability Evaluation inspection samples, as defined in IP 71111.15.
Findings
    *   Immediate determination of operability (IDO) for CR 1320214, momentary indication
        of Unit 2 reactor rod control bank A rod L5 fully inserted
    *  Prompt determination of operability (PDO) for CR 1320012, Unit 2 intermittent solid
No findings were identified.
        state protection system (SSPS) train B general warning alarm
    *  Past operability evaluation (POE) for CR 1303309, Unit 1 steam generator 1 and 2
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)  
        power operated relief valve nitrogen supply found isolated
    *  PDO for CR 1322853, 2B1 emergency diesel generator engine lube oil circulating
a.  
        pump shaft shear
Inspection Scope  
    *   PDO for CR 1316395, ERCW system design bases and procedural errors potentially
        impacting system function
The inspectors evaluated, as appropriate, for the work activities listed below:  
    *   POE for CR 1316395, ERCW system design bases and procedural errors potentially
1) the effectiveness of the risk assessments performed before maintenance activities
        impacting system function
were conducted; 2) the management of risk; 3) that, upon identification of an unforeseen
    *  Review of CR 1333550, emergency diesel generator 2B inoperable due to low
situation, necessary steps were taken to plan and control the resulting emergent work  
        crankcase oil level
activities; and 4) that maintenance risk assessments and emergent work problems were
  b. Findings
adequately identified and resolved.  The inspectors verified that the licensee was
.1  Failure to Maintain Procedures for Response to a Loss of Coolant Accident
complying with the requirements of 10 CFR 50.65 (a)(4); NPG-SPP-07.0, Work Control
    Introduction. An NRC-identified Green NCV (NCV) was identified for the failure to
and Outage Management; NPG-SPP-07.1, On Line Work Management;                 
    maintain written procedures as required by TS 5.7.1.1.a. Emergency procedures 1-E-1,
NPG-SPP-09.11.1, Equipment Out of Service Management; and TI-124, Equipment to
    revision 7, and 2-E-1 revision 0, both titled Loss of Reactor or Secondary Coolant,
Plant Risk Matrix. This activity constituted four Maintenance Risk Assessment
    contained steps that would have reduced ERCW flow to the A and B CCS HXs and
inspection samples, as defined in IP 71111.13.  
    potentially impacted the operability of the A train header of ERCW and CCS for both
    units.
*  
    Description. During an NRC review of a licensee-identified issue regarding the CCS
Risk assessment for August 11, 2017, with the 1A emergency diesel generator
    heat exchanger (HX) ERCW outlet and outlet bypass valves, the inspectors found that
(EDG) out of service (OOS) for an extended planned maintenance outage and  
    emergency procedures 1-E-1and 2-E-1 both included a step that directed opening valve
applicability of  TS 3.8.1.B.5 for the extended limiting condition for operation time
    1-FCV-67-458, CCS HX A supply from ERCW header 1B, during a loss of either A train
period based on FLEX EDG availability
    or B train power. This procedural action would be implemented during a loss of coolant
*  
    accident (LOCA) on one unit with a coincident single active failure causing a loss of train
Risk assessment for August 4, 2017, with 1B-B auxiliary feedwater train OOS and  
replacement main transformer movement under dedicated offsite power lines
*  
Risk assessment for August 29, 2017, with both sources of offsite power inoperable  
due to a disqualified grid
*
Risk assessment for work week 0905 with 1A-A motor driven auxiliary feedwater, 
1A-A component cooling system pump OOS for maintenance and high risk work on
Unit 1 turbine electrohydraulic controls, and A main control room chiller OOS
b.  
Findings
No findings were identified.  


                                          10
9
(A or B) power while the other unit was using the residual heat removal (RHR) system
for decay heat cooling. These conditions were incorporated into the design bases for
Unit 2 during plant licensing. Procedure 2-E-1 was created with the inappropriate steps
1R15 Operability Evaluations (71111.15)  
on October 8, 2015. Procedure 1-E-1 was updated with identical steps on
December 28, 2015. The licensee removed the inappropriate steps in both procedures.
a.
The licensee evaluated the past operability of the ERCW system for the time period
Inspection Scope
where the steps were incorporated into the procedure and determined that the condition
resulted in the A train of ERCW/CCS being inoperable for Unit 2 for 11 days.
The inspectors reviewed the operability evaluations affecting risk-significant mitigating
Analysis. The failure to maintain written procedures for emergencies as required by TS
systems listed below, to assess, as appropriate:  1) the technical adequacy of the  
5.7.1.1.a was a performance deficiency. The performance deficiency was more than
evaluations; 2) whether continued system operability was warranted; 3) whether the  
minor because it affected the Mitigating Systems Cornerstone attribute of Procedure
compensatory measures, if involved, were in place, would work as intended, and were
Quality and adversely affected the cornerstone objective in that reduced ERCW flow
appropriately controlled; 4) where continued operability was considered unjustified, the  
caused by the inappropriate steps resulted in the Unit 2A train of ERCW/CCS being
impact on TS Limiting Conditions for Operation (LCO) and the risk-significance in
inoperable for 11 days. This finding was assessed using NRC inspection Manual
accordance with the significant determination process (SDP).  The inspectors verified
Chapter 0609, Attachment 4, Initial Characterization of Findings. Using Appendix A,
that the operability evaluations were performed in accordance with NPG-SPP-03.1,
Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to
CAP.  Additional documents reviewed are listed in the Attachment. This activity
require a detailed risk evaluation because it represented an actual loss of function of at
constituted seven Operability Evaluation inspection samples, as defined in IP 71111.15.  
least a single train for greater than its TS allowed outage time when the 2A train of
ERCW/CCS was inoperable for 11 days. A regional SRA performed the detailed risk
*
evaluation using SAPHIRE Version 8.1.6 and Version 8.50 of the SPAR Model for both
Immediate determination of operability (IDO) for CR 1320214, momentary indication
units combined. The SRA modified the fault trees for the ERCW 1B & 2A Supply
of Unit 2 reactor rod control bank A rod L5 fully inserted
Headers to reflect the inappropriate steps for opening Valve 1-FCV-67-458 given a
*
power loss of either A or B train power, assumed the affected header would fail if the
Prompt determination of operability (PDO) for CR 1320012, Unit 2 intermittent solid
valve were opened, and used an exposure time of one year. The result was less than
state protection system (SSPS) train B general warning alarm
1E-6 for each unit which would be a finding of very low significance (Green). For Unit 1,
*
the dominant sequences were related to loss of offsite power where the performance
Past operability evaluation (POE) for CR 1303309, Unit 1 steam generator 1 and 2
deficiency fails ERCW Header 2A leading to loss of seal cooling. For Unit 2, the
power operated relief valve nitrogen supply found isolated
dominant sequences were similar with the performance deficiency failing ERCW Header
*
1B. The risk was mitigated because the performance deficiency would affect operation
PDO for CR 1322853, 2B1 emergency diesel generator engine lube oil circulating
only when a LOCA occurred with the simultaneous loss of two shutdown boards.
pump shaft shear 
The finding had a cross-cutting aspect in the Documentation attribute of the Human
*
Performance area because the licensee did not maintain the accuracy of 1-E-1 through
PDO for CR 1316395, ERCW system design bases and procedural errors potentially
its revisions and did not maintain procedure 2-E-1 accurate at its creation. (H.7).
impacting system function
Enforcement. TS 5.7.1.1.a, Procedures, required, in part, that written procedures be
*
established, implemented, and maintained covering activities related to procedures
POE for CR 1316395, ERCW system design bases and procedural errors potentially
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory
impacting system function
Guide 1.33, revision 2, Appendix A, Section 6, Procedures for Combating Emergencies
*
and Other Significant Events recommends procedures for loss of coolant. Contrary to
Review of CR 1333550, emergency diesel generator 2B inoperable due to low  
the above, since October 8, 2015, 2-E-1, revision 0, was not properly established when
crankcase oil level
a procedural step directing opening of valve 1-FCV-67-458 was included. Also, since
December 28, 2015, procedure 1-E-1, revision 7, was not maintained when the same
b.  
procedural step was added. This violation was entered in to the licensees CAP as
Findings
CR 1331422 and procedures 1-E-1 and 2-E-1 have been revised to remove this step.
.1
Failure to Maintain Procedures for Response to a Loss of Coolant Accident
Introduction.  An NRC-identified Green NCV (NCV) was identified for the failure to
maintain written procedures as required by TS 5.7.1.1.a.  Emergency procedures 1-E-1,  
revision 7, and 2-E-1 revision 0, both titled Loss of Reactor or Secondary Coolant,  
contained steps that would have reduced ERCW flow to the A and B CCS HXs and
potentially impacted the operability of the A train header of ERCW and CCS for both
units.  
Description.  During an NRC review of a licensee-identified issue regarding the CCS
heat exchanger (HX) ERCW outlet and outlet bypass valves, the inspectors found that
emergency procedures 1-E-1and 2-E-1 both included a step that directed opening valve  
1-FCV-67-458, CCS HX A supply from ERCW header 1B, during a loss of either A train
or B train power. This procedural action would be implemented during a loss of coolant
accident (LOCA) on one unit with a coincident single active failure causing a loss of train


                                            11
10
  This violation is being treated as an NCV consistent with Section 2.3.2 of the NRC
  Enforcement Policy and is identified as NCV 05000390, 391/2017003-01, Failure to
  Maintain Procedures for Response to a Loss of Coolant Accident.
(A or B) power while the other unit was using the residual heat removal (RHR) system
.2 Inadequate Procedure for Unit Cooldown from Hot Standby to Cold Shutdown
for decay heat cooling. These conditions were incorporated into the design bases for
  Introduction: An NRC-identified finding of very low safety significance (Green) and
Unit 2 during plant licensing. Procedure 2-E-1 was created with the inappropriate steps
  associated NCV of TS 5.7.1.1.a, Procedures, was identified for the failure to maintain
on October 8, 2015.  Procedure 1-E-1 was updated with identical steps on     
  TVA procedures 1-GO-6 and 2-GO-6, both entitled Unit Shutdown from Hot Standby to
December 28, 2015. The licensee removed the inappropriate steps in both procedures. 
  Cold Shutdown. The licensee failed to update the procedures based on a PDO to
The licensee evaluated the past operability of the ERCW system for the time period  
  include steps that would shutdown the running motor driven auxiliary feedwarer pump
where the steps were incorporated into the procedure and determined that the condition
  (MDAFW) prior to starting a third ERCW pump during the period where the opposite unit
resulted in the A train of ERCW/CCS being inoperable for Unit 2 for 11 days.
  has been shutdown less than 48 hours.
  Discussion: TVA design change notification (DCN) 62151 was issued to ensure the dual
Analysis. The failure to maintain written procedures for emergencies as required by TS
  unit system alignment and flow settings for the ERCW system would support operability
5.7.1.1.a was a performance deficiency. The performance deficiency was more than
  and conform to the design bases for both units as Unit 2 transitioned from construction
minor because it affected the Mitigating Systems Cornerstone attribute of Procedure
  to full commercial operation. The DCN identified procedural changes necessary to
Quality and adversely affected the cornerstone objective in that reduced ERCW flow
  comply with Unit 1 license amendment 104, which added TSs 3.7.16, Component
caused by the inappropriate steps resulted in the Unit 2A train of ERCW/CCS being
  Cooling System - Shutdown, and 3.7.17, Essential Raw Cooling Water System -
inoperable for 11 days. This finding was assessed using NRC inspection Manual
  Shutdown, and the Unit 2 operating license. TS 3.7.16 and 3.7.17 required additional
Chapter 0609, Attachment 4, Initial Characterization of Findings. Using Appendix A,  
  CCS and ERCW pumps to be operable within 48 hours of a unit shutdown. One of the
Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to
  procedure changes discussed in DCN 62151 was necessary to ensure the ERCW
require a detailed risk evaluation because it represented an actual loss of function of at
  system was able to meet the limiting design bases event discussed in Unit 1 license
least a single train for greater than its TS allowed outage time when the 2A train of
  amendment 104 and the Unit 2 operating license which consisted of a design bases
ERCW/CCS was inoperable for 11 days. A regional SRA performed the detailed risk
  LOCA on one unit coincident with a dual unit LOOP, while the other (non-accident) unit
evaluation using SAPHIRE Version 8.1.6 and Version 8.50 of the SPAR Model for both
  is on RHR shutdown cooling within 48 hours after shutdown and experiences a single
units combined.  The SRA modified the fault trees for the ERCW 1B & 2A Supply
  active failure in the form of a loss of power to one train. The changes consisted of
Headers to reflect the inappropriate steps for opening Valve 1-FCV-67-458 given a
  procedure revisions to require starting a third ERCW pump and having provisions to load
power loss of either A or B train power, assumed the affected header would fail if the
  it as the second ERCW pump on a single diesel generator (EDG) during the limiting
valve were opened, and used an exposure time of one year.  The result was less than
  design basis event. It was recognized, during the license amendment process, that the
1E-6 for each unit which would be a finding of very low significance (Green).  For Unit 1,
  diesel generator loading analysis assumed the MDAFW pump was not running on the
the dominant sequences were related to loss of offsite power where the performance
  non-accident unit. However, the limiting design bases event assumes a dual unit LOOP
deficiency fails ERCW Header 2A leading to loss of seal cooling. For Unit 2, the
  where MDAFW pumps would be automatically loaded onto the non-accident units
dominant sequences were similar with the performance deficiency failing ERCW Header
  EDGs. As a result, DCN 62151 required the emergency procedures be revised to direct
1B.  The risk was mitigated because the performance deficiency would affect operation
  the MDAFW pumps for the non-accident unit be stopped and placed in pull to lock and
only when a LOCA occurred with the simultaneous loss of two shutdown boards.
  then activate the applicable ERCW pump interlock bypass switch.
  On July 12, 2017, the licensee identified that a previously unknown and unanalyzed
The finding had a cross-cutting aspect in the Documentation attribute of the Human
  failure mode may be more limiting than the limiting design bases event. As part of this
Performance area because the licensee did not maintain the accuracy of 1-E-1 through
  discovery the licensee realized the procedural changes in DCN 62151 had not been
its revisions and did not maintain procedure 2-E-1 accurate at its creation. (H.7).  
  implemented despite Unit 2 starting commercial operation in September of 2016. As a
  result, several emergency procedures did not reflect the required ECRW valve position
Enforcement.  TS 5.7.1.1.a, Procedures, required, in part, that written procedures be  
  and flow requirements to properly mitigate a limiting design bases accident on Unit 2.
established, implemented, and maintained covering activities related to procedures
  The licensee completed a PDO on July 16, 2017. The PDO identified four
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory
  compensatory actions necessary to restore operability. The four actions were all
Guide 1.33, revision 2, Appendix A, Section 6, Procedures for Combating Emergencies
  associated with Unit 1 and Unit 2 emergency and general operating procedure changes.
and Other Significant Events recommends procedures for loss of coolant. Contrary to
the above, since October 8, 2015, 2-E-1, revision 0, was not properly established when
a procedural step directing opening of valve 1-FCV-67-458 was included. Also, since
December 28, 2015, procedure 1-E-1, revision 7, was not maintained when the same
procedural step was added. This violation was entered in to the licensees CAP as   
CR 1331422 and procedures 1-E-1 and 2-E-1 have been revised to remove this step.  


                                              12
11
    The inspectors reviewed the PDO and determined that the need to stop a running
    MDAFW pump prior to loading an EDG with a second ERCW pump, to prevent
    overloading of the EDG, was not recognized as a required compensatory action to
This violation is being treated as an NCV consistent with Section 2.3.2 of the NRC
    restore operability. The licensee agreed that the procedure changes to stop the running
Enforcement Policy and is identified as NCV 05000390, 391/2017003-01, Failure to  
    MDAFW pump were required and they revised the PDO on July 17, 2017, to include the
Maintain Procedures for Response to a Loss of Coolant Accident.
    necessary procedure changes.
    Analysis: The licensees failure to maintain TVA procedures 1-GO-6, revision 8 and
.2
    2-GO-6, revision 6 was a performance deficiency. The performance deficiency was
Inadequate Procedure for Unit Cooldown from Hot Standby to Cold Shutdown
    more than minor because it affected the Mitigating Systems Cornerstone attribute of
    Equipment Performance and affected the cornerstone objective in that failure to maintain
Introduction:  An NRC-identified finding of very low safety significance (Green) and  
    the procedures resulted in a condition where the EDG would have been overloaded and
associated NCV of TS 5.7.1.1.a, Procedures, was identified for the failure to maintain  
    rendered inoperable in response to a design basis event. The inspectors evaluated the
TVA procedures 1-GO-6 and 2-GO-6, both entitled Unit Shutdown from Hot Standby to
    significance of this finding using IMC 0609, Attachment 4, Appendix A, Exhibit 2, and
Cold Shutdown. The licensee failed to update the procedures based on a PDO to
    determined that this finding was of very low safety significance (Green) because the
include steps that would shutdown the running motor driven auxiliary feedwarer pump
    finding did not represent an actual loss of function of a single train for greater than its TS
(MDAFW) prior to starting a third ERCW pump during the period where the opposite unit
    allowed outage time.
has been shutdown less than 48 hours.  
    The finding had a cross-cutting aspect in the Avoid Complacency component of the
    Human Performance area as defined in NRC IMC 0310 because the organization failed
Discussion:  TVA design change notification (DCN) 62151 was issued to ensure the dual
    to recognize the possibility of mistakes and use appropriate error reduction tools. [H.12].
unit system alignment and flow settings for the ERCW system would support operability
    Enforcement: TS 5.7.1.1.a, Procedures, required, in part, that written procedures be
and conform to the design bases for both units as Unit 2 transitioned from construction
    established, implemented, and maintained covering activities related to procedures
to full commercial operation. The DCN identified procedural changes necessary to
    recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory
comply with Unit 1 license amendment 104, which added TSs 3.7.16, Component
    Guide 1.33, Section 2(j), General Plant Operating Procedures, required procedures for
Cooling System - Shutdown, and 3.7.17, Essential Raw Cooling Water System -
    Hot Standby to Cold Shutdown. Contrary to the above, from July 16, 2017 to
Shutdown, and the Unit 2 operating license.  TS 3.7.16 and 3.7.17 required additional
    July 17, 2017, the licensee failed to maintain their procedures for unit shutdown from hot
CCS and ERCW pumps to be operable within 48 hours of a unit shutdown. One of the
    standby to cold shutdown, 1-GO-6, revision 8 and 2-GO-6, revision 6, because they did
procedure changes discussed in DCN 62151 was necessary to ensure the ERCW
    not include steps to prevent an EDG overload by stopping the running MDAFW pump.
system was able to meet the limiting design bases event discussed in Unit 1 license
    The licensees immediate corrective actions included revising both procedures to add
amendment 104 and the Unit 2 operating license which consisted of a design bases
    the required steps. This violation was entered into the CAP as CR 1318176 and is being
LOCA on one unit coincident with a dual unit LOOP, while the other (non-accident) unit  
    treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. It is
is on RHR shutdown cooling within 48 hours after shutdown and experiences a single
    identified as NCV 05000391, 390/2017003-02, Inadequate Procedure for Unit Cooldown
active failure in the form of a loss of power to one train. The changes consisted of
    from Hot Standby to Cold Shutdown.
procedure revisions to require starting a third ERCW pump and having provisions to load
1R19 Post-Maintenance Testing (71111.19)
it as the second ERCW pump on a single diesel generator (EDG) during the limiting
  a.  Inspection Scope
design basis event. It was recognized, during the license amendment process, that the
    The inspectors reviewed the post-maintenance test procedures and/or test activities,
diesel generator loading analysis assumed the MDAFW pump was not running on the
    (listed below) as appropriate, for selected risk-significant mitigating systems to assess
non-accident unit.  However, the limiting design bases event assumes a dual unit LOOP
    whether: 1) the effect of testing on the plant had been adequately addressed by control
where MDAFW pumps would be automatically loaded onto the non-accident units
    room and/or engineering personnel; 2) testing was adequate for the maintenance
EDGs.  As a result, DCN 62151 required the emergency procedures be revised to direct
    performed; 3) acceptance criteria were clear and adequately demonstrated operational
the MDAFW pumps for the non-accident unit be stopped and placed in pull to lock and  
    readiness consistent with design and licensing basis documents; 4) test instrumentation
then activate the applicable ERCW pump interlock bypass switch.
    had current calibrations, range, and accuracy consistent with the application; 5) tests
    were performed as written with applicable prerequisites satisfied; 6) jumpers installed or
On July 12, 2017, the licensee identified that a previously unknown and unanalyzed
failure mode may be more limiting than the limiting design bases event.  As part of this
discovery the licensee realized the procedural changes in DCN 62151 had not been  
implemented despite Unit 2 starting commercial operation in September of 2016.  As a
result, several emergency procedures did not reflect the required ECRW valve position
and flow requirements to properly mitigate a limiting design bases accident on Unit 2. 
The licensee completed a PDO on July 16, 2017.  The PDO identified four
compensatory actions necessary to restore operability.  The four actions were all
associated with Unit 1 and Unit 2 emergency and general operating procedure changes. 


                                                13
12
      leads lifted were properly controlled; 7) test equipment was removed following testing;
      and 8) equipment was returned to the status required to perform its safety function. The
      inspectors verified that these activities were performed in accordance with
The inspectors reviewed the PDO and determined that the need to stop a running
      NPG-SPP-06.9, Testing Programs; NPG-SPP-06.3, Pre-/Post-Maintenance Testing; and
MDAFW pump prior to loading an EDG with a second ERCW pump, to prevent
      NPG-SPP-07.1, On Line Work Management. This activity constituted five Post
overloading of the EDG, was not recognized as a required compensatory action to  
      Maintenance Testing inspection samples, as defined in IP 71111.19.
restore operability. The licensee agreed that the procedure changes to stop the running
      *  WO 118921021, 2-SI-68-120, 184 day channel operational test reactor coolant flow
MDAFW pump were required and they revised the PDO on July 17, 2017, to include the
          loop 3 channel III, loop 2-LPF-68-48D (F-436)
necessary procedure changes.  
      *  WO 118851496, 2-SI-99-10-B, 62 day functional test of SSPS train B and reactor trip
          breaker B following tester circuit board replacement
Analysis:  The licensees failure to maintain TVA procedures 1-GO-6, revision 8 and    
      *   WO 118921021, 2-SI-68-120, 184 day channel operational test reactor coolant flow
2-GO-6, revision 6 was a performance deficiency. The performance deficiency was
          loop 3, channel III, loop 2-LPF-68-48D (F436) following EAGLE 21 DFP circuit board
more than minor because it affected the Mitigating Systems Cornerstone attribute of
          replacement
Equipment Performance and affected the cornerstone objective in that failure to maintain
      *  WO 119010949, 1-SI-30-902-A, Valve full stroke exercising during plant operation
the procedures resulted in a condition where the EDG would have been overloaded and
          ventilation train A following replacement of quick exhaust valve on 1-FCV-30-40
rendered inoperable in response to a design basis event. The inspectors evaluated the
      *  WO 118985349, Post maintenance test following 2B2 EDG auxiliary lube oil pump
significance of this finding using IMC 0609, Attachment 4, Appendix A, Exhibit 2, and
          replacement
determined that this finding was of very low safety significance (Green) because the
  b. Findings
finding did not represent an actual loss of function of a single train for greater than its TS
      No findings were identified.
allowed outage time.    
  1R20 Refueling and Outage Activities (71111.20)
.1   Unit 2 Forced Outage (July 1, 2017 - August 8, 2017)
The finding had a cross-cutting aspect in the Avoid Complacency component of the
  a. Inspection Scope
Human Performance area as defined in NRC IMC 0310 because the organization failed
      The Unit 2 began a forced outage on March 23, 2017, due to a structural failure of the B
to recognize the possibility of mistakes and use appropriate error reduction tools.  [H.12].  
      condenser waterbox. On July 1, 2017, the unit was in mode 5 until the unit began to heat
      up in preparation for startup. The reactor became critical on July 23, 2017, but returned
Enforcement: TS 5.7.1.1.a, Procedures, required, in part, that written procedures be
      to hot standby (Mode 3) due to equipment problems with the main feed pumps. On
established, implemented, and maintained covering activities related to procedures
      July 25, 2017, startup resumed, but the reactor was tripped before criticality due to rod
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory
      position indication problems. Startup recommenced on July 27, 2017, but was stopped
Guide 1.33, Section 2(j), General Plant Operating Procedures, required procedures for
      due to additional rod position indication problems. On July 30, 2017, Unit 2 started up
Hot Standby to Cold Shutdown.  Contrary to the above, from July 16, 2017 to            
      after rod position indication repairs and achieved 29 percent rated thermal power (RTP)
July 17, 2017, the licensee failed to maintain their procedures for unit shutdown from hot
      on August 2, 2017. The unit remained at 29 percent RTP until August 3, 2017, when the
standby to cold shutdown, 1-GO-6, revision 8 and 2-GO-6, revision 6, because they did
      turbine was tripped due to a steam leak on a turbine drain line. The reactor stabilized at
not include steps to prevent an EDG overload by stopping the running MDAFW pump.
      8 percent RTP and remained there until power ascension resumed after drain line
The licensees immediate corrective actions included revising both procedures to add
      repairs. Unit 2 reached 100 percent RTP on August 8, 2017, and remained there for the
the required steps.  This violation was entered into the CAP as CR 1318176 and is being
      remainder of the reporting period.
treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.  It is
      The inspectors observed the licensees mode changes and startups in order to verify that
identified as NCV 05000391, 390/2017003-02, Inadequate Procedure for Unit Cooldown
      they were performed in accordance with station procedures and TSs. The inspectors
from Hot Standby to Cold Shutdown.
      made entry into containment prior to the unit restart to assess the material condition of
      SSCs, including the containment sump. The inspectors attended forced outage meetings
1R19 Post-Maintenance Testing (71111.19)
a.  
Inspection Scope
The inspectors reviewed the post-maintenance test procedures and/or test activities, 
(listed below) as appropriate, for selected risk-significant mitigating systems to assess  
whether:  1) the effect of testing on the plant had been adequately addressed by control
room and/or engineering personnel; 2) testing was adequate for the maintenance
performed; 3) acceptance criteria were clear and adequately demonstrated operational
readiness consistent with design and licensing basis documents; 4) test instrumentation
had current calibrations, range, and accuracy consistent with the application; 5) tests
were performed as written with applicable prerequisites satisfied; 6) jumpers installed or


                                              14
13
    and reviewed the daily risk assessments and condenser repair plans. The inspectors also
    observed the performance of some surveillance testing being performed while the unit was
   
    shutdown. This activity constituted one Refueling and Other Outage Activities sample, as
leads lifted were properly controlled; 7) test equipment was removed following testing;
    defined in IP 71111.20.
and 8) equipment was returned to the status required to perform its safety function.  The
b. Findings
inspectors verified that these activities were performed in accordance with             
    No findings were identified.
NPG-SPP-06.9, Testing Programs; NPG-SPP-06.3, Pre-/Post-Maintenance Testing; and  
1R22 Surveillance Testing (71111.22)
NPG-SPP-07.1, On Line Work Management. This activity constituted five Post
a.  Inspection Scope
Maintenance Testing inspection samples, as defined in IP 71111.19.  
    The inspectors witnessed the surveillance tests and/or reviewed test data of selected
    risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met the
*  
    requirements of the TS; the UFSAR; NPG-SPP-06.9, Testing Programs;
WO 118921021, 2-SI-68-120, 184 day channel operational test reactor coolant flow
    NPG-SPP-06.9.2, Surveillance Test Program; and NPG-SPP-09.1, ASME Section XI.
loop 3 channel III, loop 2-LPF-68-48D (F-436)  
    The inspectors also determined whether the testing effectively demonstrated that the
*  
    SSCs were operationally ready and capable of performing their intended safety
WO 118851496, 2-SI-99-10-B, 62 day functional test of SSPS train B and reactor trip
    functions. This activity constituted ten Surveillance Testing inspection samples; three
breaker B following tester circuit board replacement
    in-service and seven routine; as defined in IP 71111.22.
*  
    In-Service Test:
WO 118921021, 2-SI-68-120, 184 day channel operational test reactor coolant flow
    * WO 118371917, 1-SI-62-901-A, Centrifugal charging pump 1A-A quarterly
loop 3, channel III, loop 2-LPF-68-48D (F436) following EAGLE 21 DFP circuit board
        performance test
replacement
    * WO 118086192, 2-SI-67-908-B, Valve full stroke exercising and position indication
*  
        verification during cold shutdown - essential raw cooling water (train 2B)
WO 119010949, 1-SI-30-902-A, Valve full stroke exercising during plant operation
    * WO 118431243, 1-SI-74-901-A, Residual heat removal pump 1A quarterly
ventilation train A following replacement of quick exhaust valve on 1-FCV-30-40
        performance test
*
    Other Surveillances
WO 118985349, Post maintenance test following 2B2 EDG auxiliary lube oil pump
    * WO 118431170, 0-SI-82-12-A, Monthly diesel generator start and load test DG 2A-A
replacement
    * WO 118086055, 2-SI-0-710, Containment integrity: penetrations
    * WO 117823693, 2-SI-211-1-A, 18 month 6.9 KV shutdown board 2A-A automatic
b.
        and manual transfer tests
Findings
    * WO 118061393, 2-SI-211-1-B, 18 month 6.9 KV shutdown board 2B-B Automatic
        and Manual Transfer Tests
    * WO 117823686, 2-SI-211-3-A, 18 month functional test on 6900V SD BD 2A-A
No findings were identified.
        degraded and undervoltage relays
    * WO 117823687, 2-SI-211-3-B, 18 month functional test on 6900V SD BD 2B-B
1R20 Refueling and Outage Activities (71111.20)
        degraded and undervoltage relays
    * WO 117823601, 2-SI-68-86, 18 month channel calibration of remote shutdown
.1
        monitoring narrow range pressurizer pressure loop 2-LPP-68-337C
Unit 2 Forced Outage (July 1, 2017 - August 8, 2017)
a.  
Inspection Scope
The Unit 2 began a forced outage on March 23, 2017, due to a structural failure of the B  
condenser waterbox. On July 1, 2017, the unit was in mode 5 until the unit began to heat
up in preparation for startup.  The reactor became critical on July 23, 2017, but returned
to hot standby (Mode 3) due to equipment problems with the main feed pumps.  On     
July 25, 2017, startup resumed, but the reactor was tripped before criticality due to rod
position indication problems.  Startup recommenced on July 27, 2017, but was stopped
due to additional rod position indication problems.  On July 30, 2017, Unit 2 started up
after rod position indication repairs and achieved 29 percent rated thermal power (RTP)
on August 2, 2017.  The unit remained at 29 percent RTP until August 3, 2017, when the
turbine was tripped due to a steam leak on a turbine drain line.  The reactor stabilized at
8 percent RTP and remained there until power ascension resumed after drain line
repairs.  Unit 2 reached 100 percent RTP on August 8, 2017, and remained there for the
remainder of the reporting period.
The inspectors observed the licensees mode changes and startups in order to verify that
they were performed in accordance with station procedures and TSs.  The inspectors
made entry into containment prior to the unit restart to assess the material condition of  
SSCs, including the containment sump.  The inspectors attended forced outage meetings


                                              15
14
b. Findings
  Introduction: A self-revealed finding of very low safety significance (Green) and
  associated NCV of TS (TS) 5.7.1.1.a, Procedures, was identified for the failure to follow
and reviewed the daily risk assessments and condenser repair plans. The inspectors also
  TVA procedure 2-SI-68-86, 18 Month Channel Calibration of Remote Shutdown
observed the performance of some surveillance testing being performed while the unit was
  Monitoring Narrow Range Pressurizer Pressure Loop 2-LPP-68-337C, Revision 4. The
shutdown.  This activity constituted one Refueling and Other Outage Activities sample, as
  licensee failed to properly follow step 6.2.6 [1.3], which resulted in the inadvertent lifting
defined in IP 71111.20.  
  of a pressurizer power operated relief valve (PORV).
  Discussion: On June 21, 2017, instrumentation and control technicians were performing
b.  
  Surveillance 2-SI-68-86. The surveillance verified the function of the transfer switches
Findings
  for the PORV and its associated block valve to transfer power from the main control
  room to the auxiliary control room. Step 6.2.6 [1.3] of the procedure directed that the
  distributed control system (DCS) demand for the PORV be toggled to 0 (closed). When
No findings were identified.  
  the technicians came to this step, they toggled the output as directed in the beginning of
  the procedure step. However, they did not recognize that the DCS demand was at 0
1R22 Surveillance Testing (71111.22)
  and, therefore, toggled it to 1 (open). When the auxiliary transfer switch was operated,
  the PORV had an open signal present and opened. This resulted in a reactor coolant
a.  
  pressure drop from 335 psig to 310 psig. The main control room operators were alerted
Inspection Scope
  to this condition by an annunciator for high pressure in the pressurizer relief tank,
  properly diagnosed the inadvertent PORV opening, and shut the associated PORV block
The inspectors witnessed the surveillance tests and/or reviewed test data of selected
  valve stopping the pressure decrease.
risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met the  
  Analysis: The licensees failure to follow TVA procedure 2-SI-68-86, was a performance
requirements of the TS; the UFSAR; NPG-SPP-06.9, Testing Programs;                 
  deficiency. The performance deficiency was more than minor because it affected the
NPG-SPP-06.9.2, Surveillance Test Program; and NPG-SPP-09.1, ASME Section XI.
  Initiating Events Cornerstone attribute of Human Performance and adversely affected
The inspectors also determined whether the testing effectively demonstrated that the  
  the cornerstone objective in that failing to follow procedure 2-SI-68-86 resulted in a
SSCs were operationally ready and capable of performing their intended safety
  temporary lowering of reactor coolant pressure and inventory. The finding was screened
functions. This activity constituted ten Surveillance Testing inspection samples; three 
  in accordance with NRC IMC 0609, Attachment 4, Appendix G, Shutdown Operations
in-service and seven routine; as defined in IP 71111.22.  
  Significance determination process Phase 1 Initial Screening and Characterization of
  Findings. The finding was screened to Green based on the answers to questions 2 and
In-Service Test:
  3. The resultant leakage from the open PORV would not have caused the current decay
*
  heat removal method to fail if it went undetected and leakage would be self-limiting such
WO 118371917, 1-SI-62-901-A, Centrifugal charging pump 1A-A quarterly
  that it would stop before impacting the operating method of decay heat removal.
performance test
  The finding had a cross-cutting aspect in the Challenge the Unknown component of the
*
  Human Performance area as defined in NRC IMC 0310, because the technicians failed
WO 118086192, 2-SI-67-908-B, Valve full stroke exercising and position indication
  to recognize that the output was already set to 0, but proceeded anyways to toggle the
verification during cold shutdown - essential raw cooling water (train 2B)
  output which resulted in setting it to 1 [H.11].
*
  Enforcement: TS 5.7.1.1.a, Procedures, required, in part, that written procedures be
WO 118431243, 1-SI-74-901-A, Residual heat removal pump 1A quarterly
  established, implemented, and maintained covering activities related to procedures
performance test
  recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory
  Guide 1.33, Section 8, Procedures for Control of Measuring and Test Equipment and for
Other Surveillances
  Surveillance Tests, Procedures, and Calibrations requires procedures for surveillance
*
  tests. Contrary to the above, required surveillance procedure 2-SI-68-86, revision 4,
WO 118431170, 0-SI-82-12-A, Monthly diesel generator start and load test DG 2A-A
  was not implemented when step 6.2.6 [1.3] was not performed as written. Corrective
*
  actions taken or planned by the licensee include revisions to 2-SI-68-86 to clarify the
WO 118086055, 2-SI-0-710, Containment integrity: penetrations
*
WO 117823693, 2-SI-211-1-A, 18 month 6.9 KV shutdown board 2A-A automatic
and manual transfer tests
*
WO 118061393,  2-SI-211-1-B, 18 month 6.9 KV shutdown board 2B-B Automatic
and Manual Transfer Tests
*
WO 117823686, 2-SI-211-3-A, 18 month functional test on 6900V SD BD 2A-A  
degraded and undervoltage relays
*
WO 117823687, 2-SI-211-3-B, 18 month functional test on 6900V SD BD 2B-B
degraded and undervoltage relays
*
WO 117823601, 2-SI-68-86, 18 month channel calibration of remote shutdown
monitoring narrow range pressurizer pressure loop 2-LPP-68-337C


                                              16
15
    steps relating to toggling the DCS output, training for the craft, and management
    oversight of pre-job briefs. This violation was entered into the CAP as CR 1309345 and
    is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.
b.
    This violation is identified as NCV 05000391/2017003-03, Failure to Follow a
Findings
    Surveillance Procedure Led to an Inadvertent Lift of a Pressurizer Power Operated
    Relief Valve.
Introduction:  A self-revealed finding of very low safety significance (Green) and  
    Cornerstone: Emergency Preparedness
associated NCV of TS (TS) 5.7.1.1.a, Procedures, was identified for the failure to follow
1EP6 Drill Evaluation (71114.06)
TVA procedure 2-SI-68-86, 18 Month Channel Calibration of Remote Shutdown
  a. Inspection Scope
Monitoring Narrow Range Pressurizer Pressure Loop 2-LPP-68-337C, Revision 4. The
    On the dates listed below, the inspectors observed a licensee-evaluated emergency
licensee failed to properly follow step 6.2.6 [1.3], which resulted in the inadvertent lifting
    preparedness drill to verify that the emergency response organization was properly
of a pressurizer power operated relief valve (PORV).
    classifying the event in accordance with licensee procedure EPIP-1, Emergency Plan
    Classification Flowchart, and making accurate and timely notifications and protective
Discussion:  On June 21, 2017, instrumentation and control technicians were performing
    action recommendations in accordance with EPIP-2, Notification of Unusual Event;
Surveillance 2-SI-68-86.  The surveillance verified the function of the transfer switches
    EPIP-3, Alert; EIPIP-4, Site Area Emergency; EPIP-5, General Emergency; and the
for the PORV and its associated block valve to transfer power from the main control
    Radiological Emergency Plan. In addition, the inspectors verified that licensee
room to the auxiliary control room. Step 6.2.6 [1.3] of the procedure directed that the
    evaluators were identifying deficiencies and properly dispositioning performance against
distributed control system (DCS) demand for the PORV be toggled to 0 (closed). When
    the performance indicator criteria in Nuclear Energy Institute (NEI) 99-02, Regulatory
the technicians came to this step, they toggled the output as directed in the beginning of
    Assessment Performance Indicator Guideline. This activity constituted two EP drill
the procedure step.  However, they did not recognize that the DCS demand was at 0
    evaluation inspection samples.
and, therefore, toggled it to 1 (open).  When the auxiliary transfer switch was operated,
    *    EP drill on July 17, 2017
the PORV had an open signal present and opened.  This resulted in a reactor coolant
    *    EP drill on August 16, 2017
pressure drop from 335 psig to 310 psig.  The main control room operators were alerted
  b. Findings
to this condition by an annunciator for high pressure in the pressurizer relief tank,  
    No findings were identified.
properly diagnosed the inadvertent PORV opening, and shut the associated PORV block
4.   OTHER ACTIVITIES
valve stopping the pressure decrease.
4OA1 Performance Indicator (PI) Verification (71151)
.1  Cornerstone: Mitigating Systems
Analysis:  The licensees failure to follow TVA procedure 2-SI-68-86, was a performance
  a. Inspection Scope
deficiency. The performance deficiency was more than minor because it affected the  
    The inspectors sampled licensee submittals for the two PIs listed below. To verify the
Initiating Events Cornerstone attribute of Human Performance and adversely affected
    accuracy of the PI data reported from July 1, 2016 through June 30, 2017. PI definitions
the cornerstone objective in that failing to follow procedure 2-SI-68-86 resulted in a
    and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline,
temporary lowering of reactor coolant pressure and inventory. The finding was screened
    Revision 7, were used to verify the basis in reporting for each data element.
in accordance with NRC IMC 0609, Attachment 4, Appendix G, Shutdown Operations
    This activity constituted two performance indicator samples, as defined in IP 71151.
Significance determination process Phase 1 Initial Screening and Characterization of
Findings. The finding was screened to Green based on the answers to questions 2 and
3. The resultant leakage from the open PORV would not have caused the current decay
heat removal method to fail if it went undetected and leakage would be self-limiting such
that it would stop before impacting the operating method of decay heat removal.  
The finding had a cross-cutting aspect in the Challenge the Unknown component of the  
Human Performance area as defined in NRC IMC 0310, because the technicians failed
to recognize that the output was already set to 0, but proceeded anyways to toggle the  
output which resulted in setting it to 1 [H.11].
Enforcement:  TS 5.7.1.1.a, Procedures, required, in part, that written procedures be
established, implemented, and maintained covering activities related to procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory  
Guide 1.33, Section 8, Procedures for Control of Measuring and Test Equipment and for
Surveillance Tests, Procedures, and Calibrations requires procedures for surveillance
tests.  Contrary to the above, required surveillance procedure 2-SI-68-86, revision 4,
was not implemented when step 6.2.6 [1.3] was not performed as written. Corrective
actions taken or planned by the licensee include revisions to 2-SI-68-86 to clarify the


                                              17
16
    *  High Pressure Safety Injection MSPI
    *  RCS leak rate
  b. Findings
steps relating to toggling the DCS output, training for the craft, and management
    No findings were identified.
oversight of pre-job briefs. This violation was entered into the CAP as CR 1309345 and
4OA2 Problem Identification and Resolution (71152)
is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. 
.1  Review of Items Entered into the CAP
This violation is identified as NCV 05000391/2017003-03, Failure to Follow a  
    As required by Inspection Procedure 71152, Problem Identification and Resolution, and
Surveillance Procedure Led to an Inadvertent Lift of a Pressurizer Power Operated
    in order to help identify repetitive equipment failures or specific human performance
Relief Valve.  
    issues for follow-up, the inspectors performed a daily screening of items entered into the
    licensees CAP. This review was accomplished by reviewing daily condition report (CR)
Cornerstone:  Emergency Preparedness
    summary reports and attending daily CR review meetings
.2  Annual Sample: Review of CR 129727, Watts Bar Elevation Letter - Operations
1EP6 Drill Evaluation (71114.06)
    Leadership Formality and Rigor
  a. Inspection Scope
a.  
    The inspectors reviewed CR 1297271, WBN Elevation Letter - Operations Leadership
Inspection Scope  
    Formality and Rigor, in detail to evaluate the effectiveness of the licensees corrective
    actions intended to address operator performance concerns. The CR was written to
On the dates listed below, the inspectors observed a licensee-evaluated emergency
    address the continued lack of formality, rigor, and discipline by operators in monitoring
preparedness drill to verify that the emergency response organization was properly
    and controlling the plant. The inspectors assessed whether issues were properly
classifying the event in accordance with licensee procedure EPIP-1, Emergency Plan
    identified, documented accurately and completely, properly classified and prioritized,
Classification Flowchart, and making accurate and timely notifications and protective
    adequately considered extent of condition, generic implications, common cause, and
action recommendations in accordance with EPIP-2, Notification of Unusual Event;
    previous occurrences, adequately identified root causes/apparent causes, and identified
EPIP-3, Alert; EIPIP-4, Site Area Emergency; EPIP-5, General Emergency; and the
    appropriate and timely corrective actions. The inspector reviewed processes contained in
Radiological Emergency Plan.  In addition, the inspectors verified that licensee
    the licensees Conduct of Operations procedure (OPDP-1) and CAP (NPG-SPP-22.300).
evaluators were identifying deficiencies and properly dispositioning performance against
    This activity constituted one sample of in-depth review as defined in IP 71152.
the performance indicator criteria in Nuclear Energy Institute (NEI) 99-02, Regulatory
  b. Observations and Findings
Assessment Performance Indicator Guideline. This activity constituted two EP drill
    To address the concerns identified in CR 1297217, the licensee developed a High
evaluation inspection samples.  
    Intensity Training (HIT) program. The training was developed to refocus training
    personnel and license operators of standards, behaviors and expectations associated
*
    with plant operations. The inspector discussed the licensees HIT program with
EP drill on July 17, 2017
    members of the licensees training staff, operations management, and licensee
*
    operators during a four day period. During the discussions, the inspector was able to
EP drill on August 16, 2017
    obtain a clear understanding of why and how HIT was developed.
    During the four days of observing HIT activities, the inspectors observed two operating
b.  
    crews and two crews of evaluators in a training environment. The inspector also
Findings  
    observed classroom training and critiques following each simulator scenario. Many of
No findings were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification (71151)
.1
Cornerstone:  Mitigating Systems
a.  
Inspection Scope
The inspectors sampled licensee submittals for the two PIs listed below.  To verify the  
accuracy of the PI data reported from July 1, 2016 through June 30, 2017.  PI definitions
and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline,
Revision 7, were used to verify the basis in reporting for each data element. 
This activity constituted two performance indicator samples, as defined in IP 71151.  


                                                18
17
    the training activities were also observed by a member of the licensees corporate
    training staff, onsite operations management, a contract third party evaluator, and a peer
    evaluator from another utility.
    The training sessions were found to be very intense and operational focused. The
*
    evaluators were extremely critical of crew performance. The evaluators took every
High Pressure Safety Injection MSPI
    opportunity to identify and address concerns. Whenever a concern/issue was identified,
*
    the scenario was stopped and the issues was discussed with the crew. Stopping the
RCS leak rate
    scenario and holding discussions occurred numerous times throughout each scenario.
    Following each discussion, the simulator was reset to the desired point and reran. The
b.  
    discussions were very interactive. During the discussions, the evaluators constantly
Findings
    focused on procedural requirement and licensee expectations. The evaluators were
    often challenged/questioned by crew members. The evaluators adequately addressed
    each question or concern identified by the crew. The inspector also observed critiques
No findings were identified.
    following scenarios.
    From the inspectors observation it was clear that HIT was designed to address
4OA2 Problem Identification and Resolution (71152)
    operational performance issues identified in the CR. The effectiveness of HIT can only
    be evaluated by observing operator and plant performance over time. The inspectors
.1
    concluded that the training provided during HIT, if embraced, should decrease lack of
Review of Items Entered into the CAP
    formality, increase rigor, and improve discipline by operators in monitoring and
    controlling the plant. The HIT would also be expected to improve operators
As required by Inspection Procedure 71152, Problem Identification and Resolution, and
    implementation of standards outlined in OPDP-1, Conduct of Operations. The
in order to help identify repetitive equipment failures or specific human performance
    inspectors will continue to monitor operator and plant performance in the control room,
issues for follow-up, the inspectors performed a daily screening of items entered into the  
    during actual plant events and in licensed operator simulator training, as required by the
licensees CAP. This review was accomplished by reviewing daily condition report (CR)
    baseline inspection program. No findings were identified.
summary reports and attending daily CR review meetings 
.3  Semiannual Trend Review
  a. Inspection Scope
.2
    The inspectors performed a review of the licensees CAP and associated documents to
Annual Sample:  Review of CR 129727, Watts Bar Elevation Letter - Operations
    identify trends that could indicate the existence of a more significant safety issue. The
Leadership Formality and Rigor
    review was focused on trends in risk management, long-standing minor equipment
    deficiencies, housekeeping, TS compliance, corrective action screening and condition
a.  
    adverse to quality documentation.
Inspection Scope
  b. Observations and Findings
    No findings were identified. The inspectors had several observations regarding the
    trends listed above. Regarding risk management, the inspectors noted that the
The inspectors reviewed CR 1297271, WBN Elevation Letter - Operations Leadership
    environmental factor for the equipment out of service computer program (EOOS) was
Formality and Rigor, in detail to evaluate the effectiveness of the licensees corrective
    not consistently adjusted per procedure to reflect activities in the plant switchyard. This
actions intended to address operator performance concerns. The CR was written to
    was initially identified to the licensee in 2016. The condition report written at that time
address the continued lack of formality, rigor, and discipline by operators in monitoring  
    documented the issue as an NRC question, rather than a failure to follow the EOOS
and controlling the plant. The inspectors assessed whether issues were properly
    procedure, and the corrective action was to respond to the NRC to ensure that their
identified, documented accurately and completely, properly classified and prioritized,  
    question was answered, rather than address procedure non-compliance. The inspectors
adequately considered extent of condition, generic implications, common cause, and  
    re-visited this with the licensee when they observed switchyard work in progress without
previous occurrences, adequately identified root causes/apparent causes, and identified  
appropriate and timely corrective actions. The inspector reviewed processes contained in
the licensees Conduct of Operations procedure (OPDP-1) and CAP (NPG-SPP-22.300). 
This activity constituted one sample of in-depth review as defined in IP 71152.
b.  
Observations and Findings
To address the concerns identified in CR 1297217, the licensee developed a High
Intensity Training (HIT) program.  The training was developed to refocus training
personnel and license operators of standards, behaviors and expectations associated
with plant operations. The inspector discussed the licensees HIT program with
members of the licensees training staff, operations management, and licensee  
operators during a four day period.  During the discussions, the inspector was able to  
obtain a clear understanding of why and how HIT was developed. 
During the four days of observing HIT activities, the inspectors observed two operating
crews and two crews of evaluators in a training environment. The inspector also
observed classroom training and critiques following each simulator scenario.  Many of


                                                19
18
    the environmental factor setting in EOOS being per procedure. This time the licensee
    properly characterized the issue as procedure non-compliance in their CAP. The
    inspectors used the EOOS test module and verified that risk remained GREEN during
the training activities were also observed by a member of the licensees corporate
    instances when the environmental factor adjustment was not properly set. The
training staff, onsite operations management, a contract third party evaluator, and a peer
    inspectors noted that, for the work performed when the environmental factor was not
evaluator from another utility.
    properly set, the licensee did implement physical risk mitigation controls at the work sites
    that were in accordance with the appropriate work management procedures.
The training sessions were found to be very intense and operational focused.  The
    The inspectors also noted a trend in long-standing equipment issues eventually
evaluators were extremely critical of crew performance. The evaluators took every
    becoming either operator distractions or worse conditions. In one instance valve leakby
opportunity to identify and address concerns.  Whenever a concern/issue was identified,  
    in the chemical volume and control system gave erroneous indication that the reactor
the scenario was stopped and the issues was discussed with the crew.  Stopping the
    coolant system was either being borated or diluted. This required the operating crew to
scenario and holding discussions occurred numerous times throughout each scenario. 
    enter procedures to then verify that the RCS truly was neither borated nor diluted. In
Following each discussion, the simulator was reset to the desired point and reran.  The
    another instance, known leakage on the 1A high pressure fire pump shaft seal worsened
discussions were very interactive.  During the discussions, the evaluators constantly
    to the point that protective measures had to be taken to shield water spray from the
focused on procedural requirement and licensee expectations. The evaluators were
    power supply conduit of the pump.
often challenged/questioned by crew members.  The evaluators adequately addressed
    Since the completion of Unit 2 construction, the inspectors noted a reduction in the
each question or concern identified by the crew.  The inspector also observed critiques
    amount of temporary equipment stored in the plant auxiliary building and general
following scenarios.
    housekeeping improvements in the auxiliary building. CAP review during the first and
    second quarter of 2017 showed a more aggressive approach by the license in improving
From the inspectors observation it was clear that HIT was designed to address
    housekeeping and removing lingering temporary equipment. Documents reviewed show
operational performance issues identified in the CR.  The effectiveness of HIT can only
    that the licensee accomplished this through frequent health and safety walkdowns and
be evaluated by observing operator and plant performance over time. The inspectors
    challenging temporary equipment tags that were out of date. The inspectors observed
concluded that the training provided during HIT, if embraced, should decrease lack of
    the results of these efforts in their routine walkdowns of risk-significant areas.
formality, increase rigor, and improve discipline by operators in monitoring and
    Specifically, in regards to a large scaffold storage area near the Unit 2 713 level
controlling the plant.  The HIT would also be expected to improve operators
    penetration. Although temporary equipment tags were present and up to date, the area
implementation of standards outlined in OPDP-1, Conduct of Operations. The
    appeared to have become a convenient location to temporarily store a wide variety of
inspectors will continue to monitor operator and plant performance in the control room,
    items beyond scaffolding. The licensee identified this in their CAP and then completely
during actual plant events and in licensed operator simulator training, as required by the  
    removed all of the items stored in the area.
baseline inspection program.  No findings were identified.  
    The inspectors also identified negative trends in the treatment of C-level CRs in the CAP
    and with TS compliance issues. Inspectors identified multiple C-level CRs during the
.3
    inspection period that exhibited one of the following issues: inadequate documented
Semiannual Trend Review
    condition details; inadequate screening of conditions adverse to quality (CAQs) to
    non-CAQ status; and failure to promptly identify CAQs. Inspectors also noted several
a.
    examples of issues with TS compliance and proper TS application during the inspection
Inspection Scope
    period. The licensee has identified these issues in their CAP.
4OA3 Event Followup (71153)
The inspectors performed a review of the licensees CAP and associated documents to
.1  (Closed) Licensee Event Report (LER) 05000390, 391/2016-010-00, Emergency Diesel
identify trends that could indicate the existence of a more significant safety issue. The  
    Generator Crankcase Pressure Switches Not Analyzed to Withstand the Effects of a
review was focused on trends in risk management, long-standing minor equipment
    Tornado
deficiencies, housekeeping, TS compliance, corrective action screening and condition
    A condition involving the potential impact of a tornado on the EDGs was identified during
adverse to quality documentation.
    an NRC Component Design Basis lnspection at the Sequoyah Nuclear Plant. The EDGs
    were designed with a crankcase pressure trip setpoint of approximately one inch of
b.  
    water which is bypassed during an emergency start. A tornado could potentially induce
Observations and Findings
No findings were identified. The inspectors had several observations regarding the  
trends listed above. Regarding risk management, the inspectors noted that the  
environmental factor for the equipment out of service computer program (EOOS) was
not consistently adjusted per procedure to reflect activities in the plant switchyard. This
was initially identified to the licensee in 2016. The condition report written at that time
documented the issue as an NRC question, rather than a failure to follow the EOOS
procedure, and the corrective action was to respond to the NRC to ensure that their
question was answered, rather than address procedure non-compliance. The inspectors
re-visited this with the licensee when they observed switchyard work in progress without


                                                20
19
    a pressure spike which could cause actuation of the crankcase pressure trip due to
    different vent paths between the EDG room and the EDG crankcase. Actuation of the
    crankcase pressure trip would energize the shutdown relay causing an EDG lockout
the environmental factor setting in EOOS being per procedure. This time the licensee
    condition. The EDG lockout condition would prevent all EDG starts until operators
properly characterized the issue as procedure non-compliance in their CAP. The  
    manually reset the lockout condition. Because the EDGs at Watts Bar were essentially
inspectors used the EOOS test module and verified that risk remained GREEN during
    identical designs, this condition was reviewed for applicability to Watts Bar. The
instances when the environmental factor adjustment was not properly set. The  
    licensee determined this condition placed both units in an unanalyzed condition that
inspectors noted that, for the work performed when the environmental factor was not
    could have potentially affected all four EDGs simultaneously. This was a legacy EDG
properly set, the licensee did implement physical risk mitigation controls at the work sites
    protective logic circuitry design that did not anticipate the interaction between the
that were in accordance with the appropriate work management procedures.    
    crankcase pressure trip and the outside atmospheric pressure spike during a tornado.
The inspectors also noted a trend in long-standing equipment issues eventually
    This condition was documented in the licensee CAP as CR 1179264. A compensatory
becoming either operator distractions or worse conditions. In one instance valve leakby
    action was established of starting the EDGs in the emergency mode when notified of a
in the chemical volume and control system gave erroneous indication that the reactor
    Tornado Warning and ran while the Tornado Warning was in effect ensuring the EDGs
coolant system was either being borated or diluted.  This required the operating crew to
    would be available to perform their required safety function. The licensee also
enter procedures to then verify that the RCS truly was neither borated nor diluted. In
    implemented DCN 66376 to remove the sealin function of the crankcase differential
another instance, known leakage on the 1A high pressure fire pump shaft seal worsened
    pressure switches and retain the alarm function of the switches for all four EDGs. This
to the point that protective measures had to be taken to shield water spray from the  
    LER was reviewed by the inspectors. A licensee-identified violation is documented in
power supply conduit of the pump.  
    Section 4OA7.
.2  (Closed) LER 05000390/2016-001-00, Channel Mode Switch in Incorrect Position
Since the completion of Unit 2 construction, the inspectors noted a reduction in the
    Renders Lower Containment Atmosphere Particulate Radiation Monitor Inoperable.
amount of temporary equipment stored in the plant auxiliary building and general
  a. Inspection Scope
housekeeping improvements in the auxiliary building. CAP review during the first and
    On January 12, 2016, at 1645 Eastern Standard Time (EST), Watts Bar Nuclear Plant
second quarter of 2017 showed a more aggressive approach by the license in improving
    (WBN) Maintenance personnel were performing a 92 day channel operational test for
housekeeping and removing lingering temporary equipment. Documents reviewed show
    radiation monitor 1-RM-90-1064, Lower Containment Atmosphere Particulate Radiation
that the licensee accomplished this through frequent health and safety walkdowns and
    Monitor, and found the mode switch in the "DlFF" position, which was not expected. The
challenging temporary equipment tags that were out of date.  The inspectors observed
    surveillance was stopped and an investigation was conducted. It was determined that
the results of these efforts in their routine walkdowns of risk-significant areas. 
    the design required the mode switch to be in the "lNT" position to be operable. The
Specifically, in regards to a large scaffold storage area near the Unit 2 713 level
    mode selector switch was placed in the "lNT" position and the surveillance was
penetration.  Although temporary equipment tags were present and up to date, the area
    completed. The radiation monitor was restored to OPERABLE status at 1743 EST on
appeared to have become a convenient location to temporarily store a wide variety of
    January 12, 2016. Placing the mode selector switch in the "DlFF" position resulted in 1-
items beyond scaffolding. The licensee identified this in their CAP and then completely
    RM-90-1064 being INOPERABLE due to the loss of alarm function of the monitor.
removed all of the items stored in the area.  
    Investigation determined that the switch had been repositioned on December 8, 2015.
    Because the containment particulate radiation monitor was inoperable for a period of
    time greater than permitted by TS 3.4.15, this condition was reportable as an operation
The inspectors also identified negative trends in the treatment of C-level CRs in the CAP
    or condition prohibited by TS per 10 CFR 50.73(a)(2)(i)(B). During the time the monitor
and with TS compliance issues.  Inspectors identified multiple C-level CRs during the  
    was inoperable, other means of leak detection (e.g., containment pocket sump level
inspection period that exhibited one of the following issues: inadequate documented
    indication, reactor coolant system inventory balance) remained available. This LER was
condition details; inadequate screening of conditions adverse to quality (CAQs) to   
    reviewed by the inspectors. No additional findings or violations of NRC requirements
non-CAQ status; and failure to promptly identify CAQs. Inspectors also noted several
    were identified.
examples of issues with TS compliance and proper TS application during the inspection
.3  (Closed) LER 05000390/2016-005-00, Both Trains of Unit 1 Emergency Gas Treatment
period. The licensee has identified these issues in their CAP.  
    System Inoperable During Unit 2 Testing
4OA3 Event Followup (71153)  
.1
(Closed) Licensee Event Report (LER) 05000390, 391/2016-010-00, Emergency Diesel
Generator Crankcase Pressure Switches Not Analyzed to Withstand the Effects of a
Tornado
A condition involving the potential impact of a tornado on the EDGs was identified during
an NRC Component Design Basis lnspection at the Sequoyah Nuclear Plant.  The EDGs
were designed with a crankcase pressure trip setpoint of approximately one inch of  
water which is bypassed during an emergency start.  A tornado could potentially induce


                                                  21
20
    On March 14, 2016, Watts Bar Nuclear Plant (WBN) Unit 1 determined through
    engineering analysis that both trains of emergency gas treatment system (EGTS) were
    inoperable for 8 minutes, 10 seconds during preoperational testing of Unit 2 EGTS. The
a pressure spike which could cause actuation of the crankcase pressure trip due to
    inoperability of A and B trains of Unit 1 EGTS took place on October 22, 2015, while
different vent paths between the EDG room and the EDG crankcase.  Actuation of the
    Unit 1 was in Mode 1 and two trains of EGTS were required to be operable in
crankcase pressure trip would energize the shutdown relay causing an EDG lockout
    accordance with TS LCO 3.6.9, "Emergency Gas Treatment System (EGTS). At the
condition. The EDG lockout condition would prevent all EDG starts until operators
    time of the event, Unit 2 was in "no mode," prior to initial fuel loading. With both trains of
manually reset the lockout condition.  Because the EDGs at Watts Bar were essentially
    EGTS inoperable, the specified safety functions of Unit 1 EGTS were not capable of
identical designs, this condition was reviewed for applicability to Watts Bar.  The
    being performed. Therefore, this condition was reported pursuant to
licensee determined this condition placed both units in an unanalyzed condition that
    10 CFR 50.73(a)(2)(v)(C) and 10 CFR 50.73(a)(2)(v)(D), "Event or Condition That Could
could have potentially affected all four EDGs simultaneously. This was a legacy EDG
    Have Prevented Fulfilment of a Safety Function." This LER was reviewed by the
protective logic circuitry design that did not anticipate the interaction between the
    inspectors. No additional findings or violations of NRC requirements were identified.
crankcase pressure trip and the outside atmospheric pressure spike during a tornado.
.4  (Closed) LER 05000390/2016-004-00, Automatic Reactor Trip Due to Actuation of Over
This condition was documented in the licensee CAP as CR 1179264. A compensatory
    Temperature Delta Temperature Bistables
action was established of starting the EDGs in the emergency mode when notified of a
    On March 22, 2016, at 1131, Watts Bar Nuclear Plant Unit 1 experienced an automatic
Tornado Warning and ran while the Tornado Warning was in effect ensuring the EDGs
    reactor trip. The initiating reactor trip first out received was 76-C Over-temperature Delta
would be available to perform their required safety function.  The licensee also
    T. The turbine trip first out received was 73-C Rx Trip Breakers RTA and BYA Open.
implemented DCN 66376 to remove the sealin function of the crankcase differential
    Prior to the unit trip, Unit 1 was in Mode 1 at 100 percent power. Concurrent with the
pressure switches and retain the alarm function of the switches for all four EDGs. This  
    reactor trip, the auxiliary feedwater system actuated. All control rods inserted upon the
LER was reviewed by the inspectors. A licensee-identified violation is documented in
    reactor trip and safety systems functioned as expected. This LER was reviewed by the
Section 4OA7.  
    inspectors. No additional findings or violations of NRC requirements were identified.
  .5 (Closed) LER 05000390/2016-006-00, Undersized Room Cooler Fan Shaft Results in
.2
    Loss of Centrifugal Charging Pump
(Closed) LER 05000390/2016-001-00, Channel Mode Switch in Incorrect Position
    On May 13, 2016, Watts Bar Unit 1 determined that a condition prohibited by TSs had
Renders Lower Containment Atmosphere Particulate Radiation Monitor Inoperable.
    previously occurred. During the Fall 2015 outage, maintenance performed on the 1B-B
    centrifugal charging pump (CCP) room cooling fan introduced a condition that resulted in
a.
    a subsequent bearing failure of the room cooling fan. This condition would have
Inspection Scope
    prevented the 1B-B CCP pump from performing its function for its designed mission
    time. Based on the reduced reliability of the fan, the 1B-B CCP was considered to be
On January 12, 2016, at 1645 Eastern Standard Time (EST), Watts Bar Nuclear Plant  
    inoperable from October 7, 2015, until the fan was repaired and returned to service on
(WBN) Maintenance personnel were performing a 92 day channel operational test for
    December 6, 2015. During this time, there were several short periods when the 1A-A
radiation monitor 1-RM-90-1064, Lower Containment Atmosphere Particulate Radiation
    CCP was also inoperable. A NCV for this condition was documented in NRC Inspection
Monitor, and found the mode switch in the "DlFF" position, which was not expected. The  
    Report 05000390, 391/2016002-02. The LER was reviewed by the inspectors. No
surveillance was stopped and an investigation was conducted. It was determined that
    additional findings or violations of NRC requirements were identified.
the design required the mode switch to be in the "lNT" position to be operable.  The
.6  (Closed) LER 05000390/2016-011-00, Loss of Centrifugal Charging Pump Due to
mode selector switch was placed in the "lNT" position and the surveillance was
    Repeat Failure of Associated Room Cooler
completed. The radiation monitor was restored to OPERABLE status at 1743 EST on
    On August 3, 2016, Wafts Bar Nuclear Plant Unit 1 (WBN1) determined that a condition
January 12, 2016. Placing the mode selector switch in the "DlFF" position resulted in 1-
    prohibited by TS had previously occurred. During maintenance of the 1B-B CCP room
RM-90-1064 being INOPERABLE due to the loss of alarm function of the monitor.
    cooler, the bearing was found in a degraded condition requiring repair. This fan was
Investigation determined that the switch had been repositioned on December 8, 2015. 
    required to support Operability of the 1B-B CCP. The fan had been previously repaired
Because the containment particulate radiation monitor was inoperable for a period of
    on December 6, 2015, and had less than 100 days of operation since its overhaul. The
time greater than permitted by TS 3.4.15, this condition was reportable as an operation
or condition prohibited by TS per 10 CFR 50.73(a)(2)(i)(B). During the time the monitor
was inoperable, other means of leak detection (e.g., containment pocket sump level
indication, reactor coolant system inventory balance) remained available. This LER was  
reviewed by the inspectors. No additional findings or violations of NRC requirements  
were identified.  
.3
(Closed) LER 05000390/2016-005-00, Both Trains of Unit 1 Emergency Gas Treatment
System Inoperable During Unit 2 Testing


                                                22
21
      mission time of the CCPs is specified in design documents as 100 days. Based on the
      inability of the CCP to meet its mission time, the 1B-B CCP was considered to be design
      inoperable since its overhaul on December 6, 2015. This represents a condition
      prohibited by TS for the 1B-B CCP being inoperable for greater than its allowed outage
On March 14, 2016, Watts Bar Nuclear Plant (WBN) Unit 1 determined through
      time. The LER was reviewed by the inspectors. No findings or violations of NRC
engineering analysis that both trains of emergency gas treatment system (EGTS) were
      requirements were identified.
inoperable for 8 minutes, 10 seconds during preoperational testing of Unit 2 EGTS.  The
4OA5
inoperability of A and B trains of Unit 1 EGTS took place on October 22, 2015, while 
  .1  IP 93100 Safety-Conscious Work Environment Issue of Concern Follow Up
Unit 1 was in Mode 1 and two trains of EGTS were required to be operable in  
  a. Inspection Scope
accordance with TS LCO 3.6.9, "Emergency Gas Treatment System (EGTS). At the  
      The inspectors assessed the TVA Nuclear corporate safety-conscious work
time of the event, Unit 2 was in "no mode," prior to initial fuel loading.  With both trains of
      environment (SCWE) by conducting safety culture interviews of individuals from the
EGTS inoperable, the specified safety functions of Unit 1 EGTS were not capable of
      engineering, licensing, and operations groups. Inspectors interviewed a total of 22
being performed. Therefore, this condition was reported pursuant to                           
      individuals to determine if indications of a chilled work environment exist, employees are
10 CFR 50.73(a)(2)(v)(C) and 10 CFR 50.73(a)(2)(v)(D), "Event or Condition That Could
      reluctant to raise safety and regulatory issues, and employees are being discouraged
Have Prevented Fulfilment of a Safety Function."  This LER was reviewed by the  
      from raising safety or regulatory issues. Information gathered during the interviews was
inspectors. No additional findings or violations of NRC requirements were identified.  
      used in aggregate to assess the work environment at TVA Nuclear corporate.
   
  b. Assessment
.4
      Based on the interviews conducted, the inspectors determined that licensee
(Closed) LER 05000390/2016-004-00, Automatic Reactor Trip Due to Actuation of Over
      management emphasized the need for all employees to identify and report problems
Temperature Delta Temperature Bistables
      using the appropriate methods established within the administrative programs, including
      the CAP and Employee Concerns Program. These methods were readily accessible to
On March 22, 2016, at 1131, Watts Bar Nuclear Plant Unit 1 experienced an automatic
      all employees. Based on discussions conducted with a sample of employees from
reactor trip.  The initiating reactor trip first out received was 76-C Over-temperature Delta
      various departments, the inspectors determined that employees felt free to raise safety
T. The turbine trip first out received was 73-C Rx Trip Breakers RTA and BYA Open.
      and regulatory issues, and that management encouraged employees to place issues into
Prior to the unit trip, Unit 1 was in Mode 1 at 100 percent power. Concurrent with the
      the CAP for resolution. The inspectors did not identify any reluctance on the part of the
reactor trip, the auxiliary feedwater system actuated. All control rods inserted upon the  
      licensee staff to report safety concerns.
reactor trip and safety systems functioned as expected.  This LER was reviewed by the  
4OA6 Meetings, including Exit
inspectors. No additional findings or violations of NRC requirements were identified.
      On October 25, 2017 and November 8, 2017, the resident inspectors presented the
      inspection results to members of the licensee staff. The inspectors confirmed that none
.5
      of the potential report input discussed was considered proprietary.
(Closed) LER 05000390/2016-006-00, Undersized Room Cooler Fan Shaft Results in
4OA7 Licensee-Identified Violations
Loss of Centrifugal Charging Pump
      The following licensee-identified violations of NRC requirements were determined to be
      of very low safety significance and met the NRC Enforcement Policy criteria for being
On May 13, 2016, Watts Bar Unit 1 determined that a condition prohibited by TSs had
      dispositioned as NCVs.
previously occurred.  During the Fall 2015 outage, maintenance performed on the 1B-B
      *    Technical Specification 5.7.1.1.a, Procedures, required, in part, that written
centrifugal charging pump (CCP) room cooling fan introduced a condition that resulted in
          procedures be established, implemented, and maintained covering activities
a subsequent bearing failure of the room cooling fan.  This condition would have
          related to procedures recommended in Regulatory Guide 1.33, Revision 2,
prevented the 1B-B CCP pump from performing its function for its designed mission
          Appendix A, 1978. Regulatory Guide 1.33, Revision 2, Appendix A, Section 6,
time. Based on the reduced reliability of the fan, the 1B-B CCP was considered to be
inoperable from October 7, 2015, until the fan was repaired and returned to service on
December 6, 2015.  During this time, there were several short periods when the 1A-A
CCP was also inoperable.  A NCV for this condition was documented in NRC Inspection
Report 05000390, 391/2016002-02. The LER was reviewed by the inspectors.  No
additional findings or violations of NRC requirements were identified.
.6
(Closed) LER 05000390/2016-011-00, Loss of Centrifugal Charging Pump Due to  
Repeat Failure of Associated Room Cooler 
On August 3, 2016, Wafts Bar Nuclear Plant Unit 1 (WBN1) determined that a condition
prohibited by TS had previously occurred.  During maintenance of the 1B-B CCP room
cooler, the bearing was found in a degraded condition requiring repair.  This fan was
required to support Operability of the 1B-B CCP. The fan had been previously repaired
on December 6, 2015, and had less than 100 days of operation since its overhaul. The


                                        23
22
  Procedures for Combating Emergencies and Other Significant Events requires
  procedures for a reactor trip. Contrary to the above, from May 23, 2016, until
  July 16, 2017, procedure 2-E-0, Revision 5, Reactor Trip and Safety Injection, was
mission time of the CCPs is specified in design documents as 100 days. Based on the  
  not maintained which resulted in a condition where CCS Heat Exchanger B
inability of the CCP to meet its mission time, the 1B-B CCP was considered to be design
  (ERCW/CCS Train 2A) would not have been able to remove sufficient heat during
inoperable since its overhaul on December 6, 2015.  This represents a condition  
  sump recirculation following a LOCA on Unit 2 for approximately 75 days. This
prohibited by TS for the 1B-B CCP being inoperable for greater than its allowed outage
  condition was caused by the licensees failure to implement ERCW system
time. The LER was reviewed by the inspectors.  No findings or violations of NRC
  DCN 62151 as written. A detailed risk evaluation was performed using SAPHIRE
requirements were identified.  
  Version 8.1.5 and Version 8.50 of the SPAR Model for both units combined. The
  result was less that 1E-6/year for Unit 2, which would be a finding of very low
4OA5 
  significance (Green). This violation was entered in to the licensees CAP as
.1  
  CR 1316395.
IP 93100 Safety-Conscious Work Environment Issue of Concern Follow Up
* Technical Specification 5.7.1.1.a stated, in part, that written procedures shall be
  established, implemented, and maintained covering the applicable procedures in
  a.  
  Regulatory Guide 1.33 Rev. 2, Appendix A, February 1978. Procedures for locking
Inspection Scope
  and tagging are applicable procedures under REG GUIDE 1.33 Appendix A, 1.c
  Equipment Control. Contrary to this requirement, Step 3.2.4.M of procedure
The inspectors assessed the TVA Nuclear corporate safety-conscious work
  NPG-SPP-10.2, Clearance Procedure to Safely Control Energy, Revision 18 was
environment (SCWE) by conducting safety culture interviews of individuals from the  
  not followed when nitrogen supply isolation valves 2-ISIV-1-408L and
engineering, licensing, and operations groups. Inspectors interviewed a total of 22
  2-ISIV-1-408M and isolation valves 2-ISIV-1-405L and 2-ISIV-1-405M were closed
individuals to determine if indications of a chilled work environment exist, employees are
  and tagged but not documented as tagged in the Electronic Shift Operations
reluctant to raise safety and regulatory issues, and employees are being discouraged
  Management System (eSOMS). As a result, the valves remained closed resulting
from raising safety or regulatory issues. Information gathered during the interviews was
  in the inability to operate the Unit 2 SG#1 and #2 PORVs using back-up nitrogen.
used in aggregate to assess the work environment at TVA Nuclear corporate.  
  The finding was determined to be Green because having the nitrogen supply to
  two out of four steam generator PORVs isolated only affects the ability to achieve
  b.  
  and maintain cold shutdown. The licensee documented this violation as
Assessment
  CR 1303309.
* Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control, required, in part, a
Based on the interviews conducted, the inspectors determined that licensee
  testing program to demonstrate that quality related SSCs will perform satisfactorily
management emphasized the need for all employees to identify and report problems
  in service and performed in accordance with written test procedures. Contrary to
using the appropriate methods established within the administrative programs, including
  the above, from at least 2010 until July 2017, various safety-related valves were
the CAP and Employee Concerns Program.  These methods were readily accessible to  
  unacceptably preconditioned prior to required as-found testing. This finding was of
all employees.  Based on discussions conducted with a sample of employees from
  very low safety significance (Green) because the finding did not represent an
various departments, the inspectors determined that employees felt free to raise safety
  actual loss of function of a single train for greater than its TS allowed outage time.
and regulatory issues, and that management encouraged employees to place issues into
  The licensee documented this violation as CRs 1276605, 1316712, 1319298,
the CAP for resolution. The inspectors did not identify any reluctance on the part of the
  1319304.
licensee staff to report safety concerns.
* 10 CFR Part 50, Appendix B, Criterion III, Design Control, stated, in part, that,
  measures shall be established for the selection and review for suitability of
4OA6 Meetings, including Exit
  application of materials, parts, equipment, and processes that are essential to the
  safety-related functions of SSCs. Contrary to the above, for at least the past
  twenty years, the licensee failed to assess the effects of a tornado on the
On October 25, 2017 and November 8, 2017, the resident inspectors presented the
  crankcase over-pressure trip which could prevent EDGs from fulfilling their
inspection results to members of the licensee staff.  The inspectors confirmed that none
  safety-related function. A regional senior reactor analyst performed a detailed risk
of the potential report input discussed was considered proprietary.  
  evaluation and determined the dominant accident sequences involved a
  weather-related loss of offsite power with all four EDGs failing due to the
4OA7 Licensee-Identified Violations
The following licensee-identified violations of NRC requirements were determined to be
of very low safety significance and met the NRC Enforcement Policy criteria for being
dispositioned as NCVs.
*  
Technical Specification 5.7.1.1.a, Procedures, required, in part, that written
procedures be established, implemented, and maintained covering activities
related to procedures recommended in Regulatory Guide 1.33, Revision 2,  
Appendix A, 1978.  Regulatory Guide 1.33, Revision 2, Appendix A, Section 6,


                                        24
23
  performance deficiency and the operators recovering one of the failed EDGs. The
  risk of this performance deficiency was not greater than Green due to the low
  frequency of tornados/high winds and the potential for operator recovery. The
Procedures for Combating Emergencies and Other Significant Events requires
  licensee documented this violation as CR 117926.
procedures for a reactor trip.  Contrary to the above, from May 23, 2016, until   
* Technical Specification LCO 3.6.3, Containment Isolation Valves, required that each
July 16, 2017, procedure 2-E-0, Revision 5, Reactor Trip and Safety Injection, was  
  containment isolation valve shall be operable in modes 1, 2, 3, and 4. TS Required
not maintained which resulted in a condition where CCS Heat Exchanger B
  Action statement A.1 required that the affected penetration flow path be isolated,
(ERCW/CCS Train 2A) would not have been able to remove sufficient heat during
  and Required Action A.2, directed that the penetration flow path is verified to be
sump recirculation following a LOCA on Unit 2 for approximately 75 days.  This
  isolated once per 31 days. Contrary to the above, on May 18, 2017, containment
condition was caused by the licensees failure to implement ERCW system     
  isolation valve 1-FCV-31-330 was tagged closed for maintenance; however no
DCN 62151 as written.  A detailed risk evaluation was performed using SAPHIRE
  verification that the flow path was isolated was performed until August 23, 2017.
Version 8.1.5 and Version 8.50 of the SPAR Model for both units combined. The  
  This finding was of very low safety-significance (Green) because it did not represent
result was less that 1E-6/year for Unit 2, which would be a finding of very low
  an actual open pathway in the physical integrity of reactor containment and was not
significance (Green).  This violation was entered in to the licensees CAP as      
  related to hydrogen ignitors. The licensee documented this violation as
CR 1316395.  
  CR 1331287.
* Unit 1 Operating License condition 2.F required, in part, that TVA shall implement
*  
  and maintain in effect all provisions of the approved Fire Protection Program. The
Technical Specification 5.7.1.1.a stated, in part, that written procedures shall be  
  Fire Protection Report was developed to ensure compliance with the requirements of
established, implemented, and maintained covering the applicable procedures in  
  this licensee condition. Fire Protection Report, Part II, is the Fire Protection Plan
Regulatory Guide 1.33 Rev. 2, Appendix A, February 1978.  Procedures for locking
  (FPP). FPP Subsection 14.10, Fire Safe Shutdown Equipment, required
and tagging are applicable procedures under REG GUIDE 1.33 Appendix A, 1.c
  nonfunctional equipment listed in Table 14.10 be restored to its functional status
Equipment Control. Contrary to this requirement, Step 3.2.4.M of procedure 
  within 30 days. If this 30 day requirement cannot be met, then the equipment be
NPG-SPP-10.2, Clearance Procedure to Safely Control Energy, Revision 18 was
  placed in its fire safe shutdown (FSSD) position. Contrary to the above, during a
not followed when nitrogen supply isolation valves 2-ISIV-1-408L and                 
  surveillance on June 10, 2017, backdraft damper 0-BKD-31-592, equipment listed in
2-ISIV-1-408M and isolation valves 2-ISIV-1-405L and 2-ISIV-1-405M were closed
  Table 14.10, was identified as not being able to achieve its FSSD position. However,
and tagged but not documented as tagged in the Electronic Shift Operations
  actions to place the damper in its FSSD position were not taken until July 11, 2017.
Management System (eSOMS).  As a result, the valves remained closed resulting
  This finding was of very low safety significance because there was a fully functional
in the inability to operate the Unit 2 SG#1 and #2 PORVs using back-up nitrogen. 
  automatic suppression system on either side of the fire barrier. This violation was
The finding was determined to be Green because having the nitrogen supply to
  documented as CR 1316058.
two out of four steam generator PORVs isolated only affects the ability to achieve
and maintain cold shutdown.  The licensee documented this violation as           
CR 1303309.
*
Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control, required, in part, a
testing program to demonstrate that quality related SSCs will perform satisfactorily
in service and performed in accordance with written test procedures.  Contrary to
the above, from at least 2010 until July 2017, various safety-related valves were
unacceptably preconditioned prior to required as-found testing. This finding was of  
very low safety significance (Green) because the finding did not represent an
actual loss of function of a single train for greater than its TS allowed outage time. 
The licensee documented this violation as CRs 1276605, 1316712, 1319298,
1319304.  
*  
10 CFR Part 50, Appendix B, Criterion III, Design Control, stated, in part, that,
measures shall be established for the selection and review for suitability of  
application of materials, parts, equipment, and processes that are essential to the  
safety-related functions of SSCs. Contrary to the above, for at least the past
twenty years, the licensee failed to assess the effects of a tornado on the
crankcase over-pressure trip which could prevent EDGs from fulfilling their   
safety-related function. A regional senior reactor analyst performed a detailed risk
evaluation and determined the dominant accident sequences involved a  
weather-related loss of offsite power with all four EDGs failing due to the  


                              SUPPLEMENTARY INFORMATION
24
                                KEY POINTS OF CONTACT
Licensee Personnel
G. Arent, Director, WBN Site Licensing
performance deficiency and the operators recovering one of the failed EDGs.  The
M. Casner, Director, Engineering
risk of this performance deficiency was not greater than Green due to the low
L. Cross, Manager, Electrical Systems
frequency of tornados/high winds and the potential for operator recovery. The
T. Detchemendy, Manager, Site Emergency Preparedness
licensee documented this violation as CR 117926.
E. Ellis, Senior Manager, Nuclear Site Security
D. Erb, Operations Director
*
K. Hulvey, Watts Bar Licensing Manager
Technical Specification LCO 3.6.3, Containment Isolation Valves, required that each
J. James, Director, Maintenance
containment isolation valve shall be operable in modes 1, 2, 3, and 4.  TS Required
B. Jenkins, Director, Plant Support
Action statement A.1 required that the affected penetration flow path be isolated,
T. Marshall, Plant Manager
and Required Action A.2, directed that the penetration flow path is verified to be
C. Rice, Operations Superintendent
isolated once per 31 days.  Contrary to the above, on May 18, 2017, containment
P. Simmons, Site Vice President
isolation valve 1-FCV-31-330 was tagged closed for maintenance; however no
verification that the flow path was isolated was performed until August 23, 2017. 
This finding was of very low safety-significance (Green) because it did not represent
an actual open pathway in the physical integrity of reactor containment and was not
related to hydrogen ignitors.  The licensee documented this violation as               
CR 1331287.
*
Unit 1 Operating License condition 2.F required, in part, that TVA shall implement
and maintain in effect all provisions of the approved Fire Protection Program.  The
Fire Protection Report was developed to ensure compliance with the requirements of
this licensee condition.  Fire Protection Report, Part II, is the Fire Protection Plan
(FPP).  FPP Subsection 14.10, Fire Safe Shutdown Equipment, required
nonfunctional equipment listed in Table 14.10 be restored to its functional status
within 30 days.  If this 30 day requirement cannot be met, then the equipment be
placed in its fire safe shutdown (FSSD) position.  Contrary to the above, during a
surveillance on June 10, 2017, backdraft damper 0-BKD-31-592, equipment listed in
Table 14.10, was identified as not being able to achieve its FSSD position.  However,
actions to place the damper in its FSSD position were not taken until July 11, 2017. 
This finding was of very low safety significance because there was a fully functional
automatic suppression system on either side of the fire barrier.  This violation was
documented as CR 1316058.
 
Attachment
SUPPLEMENTARY INFORMATION  
KEY POINTS OF CONTACT  
Licensee Personnel
G. Arent, Director, WBN Site Licensing  
M. Casner, Director, Engineering  
L. Cross, Manager, Electrical Systems  
T. Detchemendy, Manager, Site Emergency Preparedness  
E. Ellis, Senior Manager, Nuclear Site Security  
D. Erb, Operations Director  
K. Hulvey, Watts Bar Licensing Manager
J. James, Director, Maintenance  
B. Jenkins, Director, Plant Support  
T. Marshall, Plant Manager  
C. Rice, Operations Superintendent  
P. Simmons, Site Vice President  
A. White, Senior Manager, Site Quality Assurance
A. White, Senior Manager, Site Quality Assurance
                                                        Attachment


                              LIST OF REPORT ITEMS
Opened and Closed
NCV 05000390, 391/2017003-01         Failure to Maintain Procedures for Response to a
LIST OF REPORT ITEMS  
                                      Loss of Coolant Accident (Section 1R15.1)
NCV 05000391, 390/2017003-02         Inadequate Procedure for Unit Cooldown from Hot
Opened and Closed  
                                      Standby to Cold Shutdown (Section 1R15.2)
NCV 05000390, 391/2017003-01
NCV 05000391/2017003-03               Failure to Follow a Surveillance Procedure Led to
                                      an Inadvertent Lift of a Pressurizer Power Operated
Failure to Maintain Procedures for Response to a  
                                      Relief Valve (Section 1R22)
Loss of Coolant Accident (Section 1R15.1)  
Closed
LER 05000390, 391/2016-010-00         Emergency Diesel Generator Crankcase Pressure
NCV 05000391, 390/2017003-02
                                      Switches Not Analyzed to Withstand the Effects of
                                      a Tornado (Section 4OA3.1)
Inadequate Procedure for Unit Cooldown from Hot  
LER 05000390/2016-001-00             Channel Mode Switch in Incorrect Position Renders
Standby to Cold Shutdown (Section 1R15.2)  
                                      Lower Containment Atmosphere Particulate
                                      Radiation Monitor Inoperable (Section 4OA3.2)
NCV 05000391/2017003-03
LER 05000390/2016-005-00             Both Trains of Unit 1 Emergency Gas Treatment
                                      System inoperable During Unit 2 Testing (Section
                                      4OA3.3)
Failure to Follow a Surveillance Procedure Led to  
LER 05000390/2016-004-00             Automatic Reactor Trip Due to Actuation of Over
an Inadvertent Lift of a Pressurizer Power Operated  
                                      Temperature Delta Temperature Bistables (Section
Relief Valve (Section 1R22)  
                                      4OA3.4)
LER 05000390/2016-006-00             Undersized Room Cooler Fan Shaft Results in Loss
Closed  
                                      of Centrifugal Charging Pump (Section 4OA3.5)
LER 05000390, 391/2016-010-00  
LER 05000390/2016-011-00             Loss of Centrifugal Charging Pump Due to
Emergency Diesel Generator Crankcase Pressure  
                                      Repeat Failure of Associated Room Cooler
Switches Not Analyzed to Withstand the Effects of  
                                      (Section 4OA3.6)
a Tornado (Section 4OA3.1)  
LER 05000390/2016-001-00  
Channel Mode Switch in Incorrect Position Renders  
Lower Containment Atmosphere Particulate  
Radiation Monitor Inoperable (Section 4OA3.2)  
LER 05000390/2016-005-00  
Both Trains of Unit 1 Emergency Gas Treatment  
System inoperable During Unit 2 Testing (Section  
4OA3.3)  
LER 05000390/2016-004-00  
Automatic Reactor Trip Due to Actuation of Over  
Temperature Delta Temperature Bistables (Section  
4OA3.4)  
LER 05000390/2016-006-00
Undersized Room Cooler Fan Shaft Results in Loss  
of Centrifugal Charging Pump (Section 4OA3.5)  
LER 05000390/2016-011-00  
Loss of Centrifugal Charging Pump Due to  
Repeat Failure of Associated Room Cooler  
(Section 4OA3.6)


                              LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
0-MI-17.003, Flood Mode Preparation Storage Locations and Periodic Inventory, Rev. 0012
LIST OF DOCUMENTS REVIEWED  
0-TI-444, External Flood Protection Program, Rev. 0003
Section 1R04: Equipment Alignment
Section 1R01: Adverse Weather Protection  
Procedures
0-MI-17.003, Flood Mode Preparation Storage Locations and Periodic Inventory, Rev. 0012  
2-SI-63-8, ECCS Valve Alignment Verification, Rev. 0002
0-TI-444, External Flood Protection Program, Rev. 0003  
2-SI-3-130, AFW Valve Alignment Verification, Rev. 0004
2-SOI-63.01 ATT 1V, Safety Injection System, Rev. 0005
Section 1R04: Equipment Alignment  
2-SI-70-1, Component Cooling System, Safety-Related Valves: Alignment Verification, Rev.
Procedures  
    0004
2-SI-63-8, ECCS Valve Alignment Verification, Rev. 0002  
2-SOI-72.01, Containment Spray System, Rev. 0005
2-SI-3-130, AFW Valve Alignment Verification, Rev. 0004  
2-SOI-72.01 Containment Spray System Valve Checklist 2-71.01V, ATT 1V, Rev. 0001
2-SOI-63.01 ATT 1V, Safety Injection System, Rev. 0005  
0-SOI-82.03, Diesel Generator (DG) 2A-A, Rev. 0012
2-SI-70-1, Component Cooling System, Safety-Related Valves: Alignment Verification, Rev.  
0-SOI-82.03, Diesel Generator 2A-A Power Checklist 82.03-1P, ATT 1P, Rev. 0000
0004  
0-SOI-82.03, Diesel Generator 2A-A Valve Checklist 82.03-1V, ATT 1V, Rev. 0010
2-SOI-72.01, Containment Spray System, Rev. 0005  
0-SOI-67.01, Essential Raw Cooling Water System Supply Header 1A Valve Alignment
2-SOI-72.01 Containment Spray System Valve Checklist 2-71.01V, ATT 1V, Rev. 0001  
    Checklist 0-67.01-3V, ATT 3V, Rev. 0017
0-SOI-82.03, Diesel Generator (DG) 2A-A, Rev. 0012  
0-PI-OPS-17.0, 18 Month Locked Valve Verification, Rev. 0082
0-SOI-82.03, Diesel Generator 2A-A Power Checklist 82.03-1P, ATT 1P, Rev. 0000  
0-TI-31.08, Flow Balancing Valves Setpoint Positions, Rev. 0003
0-SOI-82.03, Diesel Generator 2A-A Valve Checklist 82.03-1V, ATT 1V, Rev. 0010  
0-SOI-82.04, Diesel Generator (DG) 2B-B, Rev. 0010
0-SOI-67.01, Essential Raw Cooling Water System Supply Header 1A Valve Alignment  
0-SOI-82.04. Diesel Generator 2B-B Power Checklist 82.04-1P, ATT 1P, Rev. 0000
Checklist 0-67.01-3V, ATT 3V, Rev. 0017  
0-SOI-82.04, Diesel Generator 2B-B Valve Checklist 82.04-1V, ATT 1V, Rev. 0010
0-PI-OPS-17.0, 18 Month Locked Valve Verification, Rev. 0082  
0-SOI-67.01, Essential Raw Cooling Water System Supply Header 1B Valve Alignment
0-TI-31.08, Flow Balancing Valves Setpoint Positions, Rev. 0003  
    Checklist 0-67.01-4V, ATT 4V, Rev. 0017
0-SOI-82.04, Diesel Generator (DG) 2B-B, Rev. 0010  
Section 1R05: Fire Protection
0-SOI-82.04. Diesel Generator 2B-B Power Checklist 82.04-1P, ATT 1P, Rev. 0000  
CRs 1262925, 1343002
0-SOI-82.04, Diesel Generator 2B-B Valve Checklist 82.04-1V, ATT 1V, Rev. 0010  
Fire Protection Report, Part VI - Fire Hazards Analysis, Rev. 52
0-SOI-67.01, Essential Raw Cooling Water System Supply Header 1B Valve Alignment  
WBN-Prefire Plan, AUX-0-692-01, Rev. 4
Checklist 0-67.01-4V, ATT 4V, Rev. 0017  
WBN-Prefire Plan, AUX-0-692-02, Rev. 3
Drawing 47A472-1
Section 1R05: Fire Protection  
Drawing 47W866-11
CRs 1262925, 1343002  
Drawing 47W920-2
Fire Protection Report, Part VI - Fire Hazards Analysis, Rev. 52  
Drawing 47A381-20
WBN-Prefire Plan, AUX-0-692-01, Rev. 4  
Drawing 47A381-127
WBN-Prefire Plan, AUX-0-692-02, Rev. 3  
WBN Prefire Plan AUX-0-713-01, Rev. 1
Drawing 47A472-1  
WBN Prefire Plan AUX-0-713-02, Rev. 3
Drawing 47W866-11  
WBN Prefire Plan AUX-0-713-03, Rev. 4
Drawing 47W920-2  
WBN Prefire Plan CON-0-729-01, Rev. 2
Drawing 47A381-20  
WBN Prefire Plan AUX-0-676-01, Rev. 3
Drawing 47A381-127  
WBN Prefire Plan AUX-0-713-01, Rev. 1  
WBN Prefire Plan AUX-0-713-02, Rev. 3  
WBN Prefire Plan AUX-0-713-03, Rev. 4  
WBN Prefire Plan CON-0-729-01, Rev. 2  
WBN Prefire Plan AUX-0-676-01, Rev. 3  


                                          4
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
4  
0-TI-12.16, Diesel Generator Outage T/S or SR Contingency Actions, Rev. 0005
    WO 118934650
0-SI-82-2, 8 Hour Diesel Generator AC Power Source Operability Verification, Rev. 0025
Section 1R13: Maintenance Risk Assessments and Emergent Work Control  
    WO 118928550
0-TI-12.16, Diesel Generator Outage T/S or SR Contingency Actions, Rev. 0005  
CRs 1727208, 1327472
WO 118934650  
NPG-SPP-09.11.1, Equipment Out of Service Management, Rev. 0012
0-SI-82-2, 8 Hour Diesel Generator AC Power Source Operability Verification, Rev. 0025  
NPG-SPP-07.3, Work Activity Risk Management Process, Rev. 0021
WO 118928550  
PWR operational risk review - red sheet for WO 118819797, Hose replacement on Unit 1 main
CRs 1727208, 1327472  
    turbine electro-hydraulic control
NPG-SPP-09.11.1, Equipment Out of Service Management, Rev. 0012  
High risk management plan for WO 119013421, Freeze seal for isolation of valve, dated 9/7/17
NPG-SPP-07.3, Work Activity Risk Management Process, Rev. 0021  
Section 1R15: Operability Determinations and Functionality Assessments
PWR operational risk review - red sheet for WO 118819797, Hose replacement on Unit 1 main  
WOs 118882781, 113861046, 113860919, 118991891
turbine electro-hydraulic control  
WBN-SDD-N3-85-4003, Control Rod Drive System, Rev. 15
High risk management plan for WO 119013421, Freeze seal for isolation of valve, dated 9/7/17  
WBN-SDD-N3-99-4003, Reactor Protection System, Rev. 24
Drawings 1082H70-6, Rev. N; 1082H70, Rev. AK; 1082H70-17, Rev. AF
Section 1R15: Operability Determinations and Functionality Assessments  
Operational Decision-Making Issue Evaluation Document, dated July 22, 2017
WOs 118882781, 113861046, 113860919, 118991891  
    Drawing 2-47W880-4, Rev. 0
WBN-SDD-N3-85-4003, Control Rod Drive System, Rev. 15  
0-PI-OPS-17.0, 18 Month Locked Valve Verification, Rev. 0081
WBN-SDD-N3-99-4003, Reactor Protection System, Rev. 24  
N3-67-4002, Essential Raw Cooling Water System
Drawings 1082H70-6, Rev. N; 1082H70, Rev. AK; 1082H70-17, Rev. AF  
1-E-1, Loss of Reactor or Secondary Coolant, Rev. 0009
Operational Decision-Making Issue Evaluation Document, dated July 22, 2017  
WBN-SDD-N3-67-4002, Essential Raw Cooling Water System, System 67, Rev. 0035
Drawing 2-47W880-4, Rev. 0  
0-TI-31.08, Flow Balancing Valves Setpoint Positions, Rev. 0003
0-PI-OPS-17.0, 18 Month Locked Valve Verification, Rev. 0081  
0-TI-12.11, Emergency Operating Instruction (EOI) Control, Rev. 0001
N3-67-4002, Essential Raw Cooling Water System  
TI-78, Lubrication Program, Rev. 0011
1-E-1, Loss of Reactor or Secondary Coolant, Rev. 0009  
NPG-SPP-07.3, Work Activity Risk Management Process, Rev. 0009
WBN-SDD-N3-67-4002, Essential Raw Cooling Water System, System 67, Rev. 0035  
WB-DC-40-64, Design Basis Events Design Criteria
0-TI-31.08, Flow Balancing Valves Setpoint Positions, Rev. 0003  
Westinghouse STS, B 3.8.3, Diesel Fuel Oil, Lube Oil, and Starting Air, Rev. 4.0
0-TI-12.11, Emergency Operating Instruction (EOI) Control, Rev. 0001  
0-SOI-82.01, Diesel Generator (DG) 1A-A, Rev. 0009
TI-78, Lubrication Program, Rev. 0011  
WBN-VTD-P318-0020, Instructions for EMD Lubricating Oil System
NPG-SPP-07.3, Work Activity Risk Management Process, Rev. 0009  
Section 1R19: Post Maintenance Testing
WB-DC-40-64, Design Basis Events Design Criteria  
CR 1325844
Westinghouse STS, B 3.8.3, Diesel Fuel Oil, Lube Oil, and Starting Air, Rev. 4.0  
0-SOI-82.01, Diesel Generator (DG) 1A-A, Rev. 0009  
WBN-VTD-P318-0020, Instructions for EMD Lubricating Oil System  
Section 1R19: Post Maintenance Testing  
CR 1325844  
2-SI-68-114, 184 Day Channel Operational Test RCS Flow Loop 1 Channel III Loop 2-LPF-68-
2-SI-68-114, 184 Day Channel Operational Test RCS Flow Loop 1 Channel III Loop 2-LPF-68-
    6D (F-416), Rev. 0003
6D (F-416), Rev. 0003  
WO 118921021
WO 118921021  
2-IMI-99.100, EAGLE 21 Rack Diagnostics, Rev. 0002
2-IMI-99.100, EAGLE 21 Rack Diagnostics, Rev. 0002  
WO 117829913
WO 117829913  
1-SI-30-901-A, Valve Full Stroke Exercising During Plant Operation - Ventilation (Train A), Rev.
1-SI-30-901-A, Valve Full Stroke Exercising During Plant Operation - Ventilation (Train A), Rev.  
    0017
0017  
PM 600124762
PM 600124762  
Drawing 1-47W866-1, Rev. 68
Drawing 1-47W866-1, Rev. 68  


                                            5
Section 1R22: Surveillance Testing
5  
WOs 118628055, 116153069
CRs 1322136, 1276914, 1314124, 1314688, 1309892, 1309602, 1309207
0-SOI-82.03, Diesel Generator (DG) 2A-A, Rev. 0010
Section 1R22: Surveillance Testing  
2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD
WOs 118628055, 116153069  
  - ERCW (Train 2B), Rev. 0003
CRs 1322136, 1276914, 1314124, 1314688, 1309892, 1309602, 1309207  
2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD
0-SOI-82.03, Diesel Generator (DG) 2A-A, Rev. 0010  
  - ERCW (Train 2B), Rev. 0004
2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD  
2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD
- ERCW (Train 2B), Rev. 0003  
  - ERCW (Train 2B), Rev. 0005
2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD  
1EP6: EP Drill Evaluation
- ERCW (Train 2B), Rev. 0004  
Controllers package for July 17, 2017, training drill dated 7/17/17
2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD  
CRs 1319059, 1318956, 1318824, 1318834, 1319057, 1318822, 1318830, and 1318823
- ERCW (Train 2B), Rev. 0005  
Section 4OA3: Followup of Events and Notices of Enforcement Discretion
Documentation of Information Sharing - Title: Radiation Meter 1-RM-90-106A
1EP6: EP Drill Evaluation  
Design Change Notice #66212, Rev. A for Equipment: Various/System 65 (Emergency Gas
Controllers package for July 17, 2017, training drill dated 7/17/17  
Treatment System) to revise SDD N3-65-4001 to Incorporate Test Requirements,
CRs 1319059, 1318956, 1318824, 1318834, 1319057, 1318822, 1318830, and 1318823  
  dated: 2/11/2016
CR 11430756 Level 2 Evaluation Action 007 dated: 07/15/2016
Section 4OA3: Followup of Events and Notices of Enforcement Discretion  
Past Operability Evaluation Documentation for CR 1143076 signed on 3/10/2016.
Documentation of Information Sharing - Title: Radiation Meter 1-RM-90-106A  
Routine WO 117688915, Equipment Description: EH Fluid Display Subpanel, Unit 1 Reactor
Design Change Notice #66212, Rev. A for Equipment: Various/System 65 (Emergency Gas  
  Trip. Dated: 3/22/2016.
Treatment System) to revise SDD N3-65-4001 to Incorporate Test Requirements,  
Level 2 Evaluation - CR Number 1152462, Rev 0 dated 4/26/2016.
    dated: 2/11/2016  
NPG Technical Pre-Job Briefing Checklist AEC CR1152462 dated 3/31/2016
CR 11430756 Level 2 Evaluation Action 007 dated: 07/15/2016  
TVA Corrective Action 1152462-006 Completed 12/21/2016.
Past Operability Evaluation Documentation for CR 1143076 signed on 3/10/2016.
TVA Condition Report 1152462 draft: 03/22/2016 Unit 1 Reactor Trip
Routine WO 117688915, Equipment Description: EH Fluid Display Subpanel, Unit 1 Reactor
    Trip. Dated: 3/22/2016.  
Level 2 Evaluation - CR Number 1152462, Rev 0 dated 4/26/2016.  
NPG Technical Pre-Job Briefing Checklist AEC CR1152462 dated 3/31/2016  
TVA Corrective Action 1152462-006 Completed 12/21/2016.  
TVA Condition Report 1152462 draft: 03/22/2016 Unit 1 Reactor Trip  
Operations Log for 8/17/2017
Operations Log for 8/17/2017
}}
}}

Latest revision as of 15:22, 7 January 2025

Integrated Inspection Report 05000390/2017003, 05000391/2017003
ML17326A222
Person / Time
Site: Watts Bar  Tennessee Valley Authority icon.png
Issue date: 11/22/2017
From: Alan Blamey
Reactor Projects Region 2 Branch 6
To: James Shea
Tennessee Valley Authority
Shared Package
ML17326A219 List:
References
IR 2017003
Download: ML17326A222 (32)
v • d • e


See also: IR 05000390/2017003

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION II

245 PEACHTREE CENTER AVENUE NE, SUITE 1200

ATLANTA, GEORGIA 30303-1257

November 22, 2017

Mr. Joseph W. Shea

Vice President, Nuclear Licensing

Tennessee Valley Authority

1101 Market Street, LP 3D-C

Chattanooga, TN 37402-2801

SUBJECT: WATTS BAR NUCLEAR PLANT - NUCLEAR REGULATORY COMMISSION

INTEGRATED INSPECTION REPORT 05000390/2017003, 05000391/2017003

Dear Mr. Shea:

On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Watts Bar Nuclear Plant, Unit 1 and Unit 2. On October 25, 2017, the NRC

inspectors discussed the results of this inspection with Mr. Tom Marshall and other members of

your staff. A re-exit was conducted on November 8, 2017, with Ms. Kim Hulvey. The results of

this inspection are documented in the enclosed inspection report.

The NRC inspectors documented three findings of very low safety significance (Green) in this

report which also involved violations of NRC requirements. Additionally, inspectors documented

six licensee-identified violations which were determined to be of very low safety significance in

this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with

Section 2.3.2.a of the Enforcement Policy. If you contest these violations 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, D.C. 20555-0001; with copies to the Regional Administrator, Region

II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C.

20555-0001; and the NRC Resident Inspector at the Watts Bar Nuclear Plant.

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

Watts Bar Nuclear Plant.

J. Shea

2

This letter, its enclosure, and your response (if any) will be available for public inspection and

copying at http://www.nrc.gov/reading-rm/adams.html and in the NRC Public Document Room

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

Exemptions, Requests for Withholding.

Sincerely,

/RA/

Alan Blamey, Chief

Reactor Projects Branch 6

Division of Reactor Projects

Docket Nos.: 50-390, 50-391

License Nos.: NPF-90, 96

Enclosure:

IR 05000390/2017003, 05000391/2017003

w/Attachment: Supplemental Information

cc Distribution via ListServ

ML17326A222

OFFICE

RII: DRP

RII: DRP

RII: DRP

RII: DRP

RII: DRP

RII: DRP

NAME

RTaylor

BDavis

GCrespo

BBishop

JEargle

ELea

DATE

10/31/2017

11/8/2017

10/31/2017

10/31/2017

11/6/2017

11/6/2017

OFFICE

RII: DRP

RII: DRP

RII: DRP

R:II DRP

NCP Approver

NAME

JHamman

JJandovitz

ABlamey

JNadel

MFranke

DATE

10/31/2017

11/3/2017

11/21/2017

11/7/2017

11/22/2017

Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos.:

50-390, 50-391

License Nos.:

NPF-90, NPF-96

Report No.:

05000390/2017003, 05000391/2017003

Licensee:

Tennessee Valley Authority (TVA)

Facility:

Watts Bar Nuclear Plant, Units 1 and 2

Location:

Spring City, TN 37381

Dates:

July 1 through September 30, 2017

Inspectors:

J. Nadel, Senior Resident Inspector

J. Hamman, Resident Inspector

J. Jandovitz, Senior Resident Inspector

E. Lea, Regional Government Liaison Officer

S. Freeman, Senior Reactor Analyst

J. Eargle, Senior Construction Inspector

B. Bishop, Project Engineer

G. Crespo, Senior Construction Inspector

C. Rapp, Senior Project Engineer

R. Taylor, Senior Project Inspector

B. Davis, Senior Construction Inspector

Approved by:

Alan Blamey, Chief

Reactor Projects Branch 6

Division of Reactor Projects

SUMMARY

IR 05000390/2017-003; 05000391/2017-003; July 1, 2017 - September 30, 2017; Watts Bar

Nuclear Plant; Operability Evaluations, Surveillance Testing.

The report covered a three-month period of inspection by the resident inspectors. Three Green

non-cited violations (NCV) were identified. The significance of most findings is indicated by their

color (i.e., Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," (SDP) dated April 29, 2015. Cross-cutting aspects

are determined using IMC 0310, Aspects Within Cross-Cutting Areas, dated

December 04, 2014. All violations of NRC requirements are dispositioned in accordance with

the NRCs Enforcement Policy, dated November 1, 2016. The NRCs program for overseeing

the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor

Oversight Process, Revision 6. Documents reviewed by the inspectors not identified in the

Report Details are listed in the Attachment.

Cornerstone: Mitigating Systems

Green. An NRC-identified NCV was identified for the failure to maintain written procedures

for emergencies. Emergency procedure 1-E-1, Revision 7 and 2-E-1 Revision 0, both titled

Loss of Reactor or Secondary Coolant, were updated to include steps directing

inappropriate actions that would have affected emergency raw cooling water (ERCW) supply

flow during an accident. The immediate corrective action was to remove the inappropriate

steps. This violation was documented in the licensees corrective action program (CAP) as

CR 1331422.

The performance deficiency was more than minor because it affected the Mitigating

Systems Cornerstone attribute of Procedure Quality and adversely affected the cornerstone

objective in that the reduced ERCW flow caused by the inappropriate steps affects the heat

removal capability of the ERCW and component cooling systems (CCS) during a loss of

coolant accident (LOCA). The finding was determined to require a detailed risk evaluation

because it represented an actual loss of function of at least a single train for greater than its

TS allowed outage time. The result was less than 1E-6 for each unit which would be a

finding of very low significance (Green). The risk was mitigated because the performance

deficiency would affect operation only when a LOCA occurred and simultaneous loss of two

shutdown boards. The finding has a cross-cutting aspect in the documentation attribute of

the Human Performance area because the licensee did not maintain the accuracy of 1-E-1

through its revisions and did not maintain procedure 2-E-1 accurate at its creation. (H.7)

(Section 1R15)

Green. An NRC-identified NCV of Technical Specification (TS) 5.7.1.1.a, Procedures, was

identified for the failure to maintain TVA procedures 1-GO-6 and 2-GO-6, both titled Unit

Shutdown from Hot Standby to Cold Shutdown. The licensee failed to update the

procedures prior to commencing dual unit operation to include steps that would shut down

the running motor driven auxiliary feedwater pump prior to starting a third ERCW pump

during the time period where the opposite unit has been shut down less than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. The

licensees immediate corrective actions included revising both procedures to add the

required steps. This violation was documented in the licensees CAP as CR 1318176.

3

The performance deficiency was more than minor because it affected the Mitigating

Systems Cornerstone attribute of Equipment Performance and adversely affected the

cornerstone objective in that failure to maintain the procedures resulted in a situation where

the emergency diesel generator would have been rendered inoperable during a design basis

event. The inspectors determined the finding was of very low safety significance (Green)

because the finding did not represent an actual loss of function of a single train for greater

than its TS allowed outage time. The finding had a cross-cutting aspect in the Avoid

Complacency attribute of the Human Performance area because engineering missed a

critical aspect of the required procedure changes associated with design change notice

62151 when performing the prompt determination of operability and the review process was

unsuccessful at identifying the error [H.12]. (Section 1R15)

Cornerstone: Initiating Events

Green. A self-revealed NCV of (TS) 5.7.1.1.a, Procedures, was identified for the failure to

follow TVA procedure 2-SI-68-86, 18 month Channel Calibration of Remote Shutdown

Monitoring Narrow Range Pressurizer Pressure Loop 2-LPP-68-337C, revision 4. The

licensee failed to properly follow step 6.2.6 [1.3], which resulted in the inadvertent lifting of a

pressurizer power operated relief valve (PORV). The licensees immediate corrective

actions included revising the procedure. This violation was documented in the licensees

CAP as CR 1309345.

The performance deficiency was more than minor because it affected the Initiating Events

Cornerstone attribute of Human Performance and adversely affected the cornerstone

objective in that failing to follow procedure 2-SI-68-86 caused a depressurization of the plant

that had to be stopped by operator action. The finding was determined to be very low safety

significance (Green) because the resultant leakage from the open PORV would be

self-limiting such that it would stop before impacting the operating method of decay heat

removal. The finding had a cross-cutting aspect in the Challenge the Unknown component

of the Human Performance area as defined in NRC IMC 0310, because the technicians

failed to recognize that the output was already set to 0, but proceeded anyway to toggle the

output which resulted in setting it to 1 [H.11]. (Section 1R22)

Six violations of very low safety significance, identified by the licensee, have been reviewed by

the NRC. Corrective actions taken or planned by the licensee have been entered into the

licensees CAP. These violations and the corrective action tracking numbers are listed in

Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at 100 percent rated thermal power (RTP) for the entire reporting period.

Unit 2 began the reporting period shutdown for repairs to the main condenser. The unit was

started up on July 23, 2017, but was shutdown to hot standby later that day due to equipment

problems. On July 25, 2017, startup resumed, but the reactor was tripped before criticality due

to rod position indication problems during the startup. Startup commenced again on

July 27, 2017, but was stopped due to additional rod position indication problems. Unit 2 started

up after rod position indication repairs on July 30, 2017, and achieved 29 percent RTP on

August 2, 2017. The unit remained at that power until August 8, 2017, when the turbine was

tripped due to a steam leak on a turbine drain line. The unit stabilized at 8 percent RTP and

remained there until power ascension resumed after drain line repairs. Unit 2 reached

100 percent RTP on August 8, 2017, and remained there for the remainder of the reporting

period.

1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

External Flood Protection Inspection

a.

Inspection Scope

The inspectors reviewed the licensees readiness to cope with external flooding.

External flooding from a probable maximum precipitation (PMP) or design basis flood

(DBF) had the potential for internal flooding of a portion of a number of the plant

structures. The inspectors reviewed the feasibility of the licensees flooding mitigation

plans and design features and verified that they were consistent with the licensees

design requirements and the risk analysis assumptions for coping with this type of

event. The inspectors performed walkdowns of selected areas to observe grading, yard

drains, and curbs in the vicinity of the south valve vault rooms. The inspectors also

checked status of the flood mode boat. The inspectors reviewed external flood

protection features at the intake pumping station and condition of the strainer room sump

pumps. Additionally, the inspectors reviewed the licensees related corrective action

documents (condition reports) to ensure any non-conforming conditions related to

potential flooding were properly addressed. The inspection was performed prior to the

expected rainfall from Hurricane Irma. This activity constituted one Adverse Weather

Protection inspection sample, as defined in Inspection Procedure (IP) 71111.01.

b.

Findings

No findings were identified.

5

1R04 Equipment Alignment (71111.04)

Partial System Walkdowns

a.

Inspection Scope

The inspectors conducted the equipment alignment partial walkdowns listed below to

evaluate the operability of selected redundant trains or backup systems prior to unit

transition into the mode of applicability for the systems. This also included that

redundant trains were returned to service properly. The inspectors reviewed the

functional system descriptions, the Updated Final Safety Analysis Report (UFSAR),

system operating procedures, and 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 six

inspection samples, as defined in IP 71111.04.

2A and 2B train of motor-driven auxiliary feedwater and Unit 2 turbine-driven

auxiliary feedwater prior to mode change

2A and 2B train of safety injection prior to mode change

2A train of containment spray prior to mode change

2B train of containment spray prior to mode change

2A-A emergency diesel generator prior to mode change

2B-B emergency diesel generator prior to mode change

b.

Findings

No findings were identified.

1R05 Fire Protection (71111.05AQ)

Fire Protection Tours

a.

Inspection Scope

The inspectors conducted tours of the areas important to reactor safety listed below to

verify the licensees implementation of fire protection requirements as described in: the

Fire Protection Program, Nuclear Power Group Standard Programs and Processes

(NPG-SPP)-18.4.6, Control of Fire Protection Impairments; NPG-SPP-18.4.7, Control of

Transient Combustibles; and NPG-SPP-18.4.8, Control of Ignition Sources (Hot Work).

The inspectors evaluated, as appropriate, conditions related to: 1) licensee control of

transient combustibles and ignition sources; 2) the material condition, operational status,

and operational lineup of fire protection systems, equipment, and features; and 3) the

fire barriers used to prevent fire damage or fire propagation.

6

This activity constituted three inspection samples, as defined in IP 71111.05AQ.

Auxiliary building elevation 713

Auxiliary building elevation 676

Control building elevation 729 and 741 (cable spreading room)

b.

Findings

No findings were identified.

1R11 Licensed Operator Requalification and Performance (71111.11)

.1

Licensed Operator Requalification Review

a.

Inspection Scope

On September 12, 2017, the inspectors observed licensed operator training

examinations on the simulator per scenario 3-OT-SRE-1017, revision 7. The scenario

included a feedwater line break and subsequent loss of all main and auxiliary feed

capability. 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 abnormal operating instructions and emergency

operating instructions

Timely and appropriate Emergency Action Level declarations per emergency plan

implementing procedures

Control board operation and manipulation, including high-risk operator actions

Command and Control provided by the unit supervisor and shift manager

The inspectors also attended the critique to assess the effectiveness of the licensee

evaluators, and to verify that licensee-identified issues were comparable to issues

identified by the inspector. This activity constituted one Observation of Requalification

Activity inspection sample, as defined in IP 71111.11.

b.

Findings

No findings were identified

7

.2

Observation of Operator Performance

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 such as procedures OPDP-1, Conduct of Operations; NPG-SPP-10.0, Plant

Operations; and GO-4, Normal Power Operation. Inspectors used activities such as

post-maintenance testing, surveillance testing and refueling, and other outage activities

to focus on the following conduct of operations as appropriate. This activity constituted

one Observation of Operator Performance inspection sample, as defined in IP 71111.11.

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

b.

Findings

No findings were identified.

1R12 Maintenance Effectiveness (71111.12)

a.

Inspection Scope

The inspectors reviewed the performance-based problem listed below. A review was

performed to assess the effectiveness of maintenance efforts that apply to scoped

structures, systems, or components (SSCs) and to verify that the licensee was following

the requirements of TI-119, Maintenance Rule Performance Indicator Monitoring,

Trending, and Reporting - 10 CFR 50.65, and NPG-SPP-03.4, Maintenance Rule

Performance Indicator Monitoring, Trending, and Reporting - 10 CFR 50.65. Reviews

focused, as appropriate, on: 1) appropriate work practices; 2) identification and

resolution of common cause failures; 3) scoping in accordance with 10 CFR 50.65;

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

8

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. This activity constituted

one Maintenance Effectiveness inspection sample, as defined in IP 71111.12.

Condition Report (CR) 1316520, Unit 2 function 063-B Train A (2A safety injection

pump) exceeded performance criteria

b.

Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

a.

Inspection Scope

The inspectors evaluated, as appropriate, for the work activities listed below:

1) the effectiveness of the risk assessments performed before maintenance activities

were conducted; 2) the management of risk; 3) that, upon identification of an unforeseen

situation, necessary steps were taken to plan and control the resulting emergent work

activities; and 4) that maintenance risk assessments and emergent work problems were

adequately identified and resolved. The inspectors verified that the licensee was

complying with the requirements of 10 CFR 50.65 (a)(4); NPG-SPP-07.0, Work Control

and Outage Management; NPG-SPP-07.1, On Line Work Management;

NPG-SPP-09.11.1, Equipment Out of Service Management; and TI-124, Equipment to

Plant Risk Matrix. This activity constituted four Maintenance Risk Assessment

inspection samples, as defined in IP 71111.13.

Risk assessment for August 11, 2017, with the 1A emergency diesel generator

(EDG) out of service (OOS) for an extended planned maintenance outage and

applicability of TS 3.8.1.B.5 for the extended limiting condition for operation time

period based on FLEX EDG availability

Risk assessment for August 4, 2017, with 1B-B auxiliary feedwater train OOS and

replacement main transformer movement under dedicated offsite power lines

Risk assessment for August 29, 2017, with both sources of offsite power inoperable

due to a disqualified grid

Risk assessment for work week 0905 with 1A-A motor driven auxiliary feedwater,

1A-A component cooling system pump OOS for maintenance and high risk work on

Unit 1 turbine electrohydraulic controls, and A main control room chiller OOS

b.

Findings

No findings were identified.

9

1R15 Operability Evaluations (71111.15)

a.

Inspection Scope

The inspectors reviewed the operability evaluations affecting risk-significant mitigating

systems listed below, to assess, as appropriate: 1) the technical adequacy of the

evaluations; 2) whether continued system operability was warranted; 3) whether the

compensatory measures, if involved, were in place, would work as intended, and were

appropriately controlled; 4) where continued operability was considered unjustified, the

impact on TS Limiting Conditions for Operation (LCO) and the risk-significance in

accordance with the significant determination process (SDP). The inspectors verified

that the operability evaluations were performed in accordance with NPG-SPP-03.1,

CAP. Additional documents reviewed are listed in the Attachment. This activity

constituted seven Operability Evaluation inspection samples, as defined in IP 71111.15.

Immediate determination of operability (IDO) for CR 1320214, momentary indication

of Unit 2 reactor rod control bank A rod L5 fully inserted

Prompt determination of operability (PDO) for CR 1320012, Unit 2 intermittent solid

state protection system (SSPS) train B general warning alarm

Past operability evaluation (POE) for CR 1303309, Unit 1 steam generator 1 and 2

power operated relief valve nitrogen supply found isolated

PDO for CR 1322853, 2B1 emergency diesel generator engine lube oil circulating

pump shaft shear

PDO for CR 1316395, ERCW system design bases and procedural errors potentially

impacting system function

POE for CR 1316395, ERCW system design bases and procedural errors potentially

impacting system function

Review of CR 1333550, emergency diesel generator 2B inoperable due to low

crankcase oil level

b.

Findings

.1

Failure to Maintain Procedures for Response to a Loss of Coolant Accident

Introduction. An NRC-identified Green NCV (NCV) was identified for the failure to

maintain written procedures as required by TS 5.7.1.1.a. Emergency procedures 1-E-1,

revision 7, and 2-E-1 revision 0, both titled Loss of Reactor or Secondary Coolant,

contained steps that would have reduced ERCW flow to the A and B CCS HXs and

potentially impacted the operability of the A train header of ERCW and CCS for both

units.

Description. During an NRC review of a licensee-identified issue regarding the CCS

heat exchanger (HX) ERCW outlet and outlet bypass valves, the inspectors found that

emergency procedures 1-E-1and 2-E-1 both included a step that directed opening valve

1-FCV-67-458, CCS HX A supply from ERCW header 1B, during a loss of either A train

or B train power. This procedural action would be implemented during a loss of coolant

accident (LOCA) on one unit with a coincident single active failure causing a loss of train

10

(A or B) power while the other unit was using the residual heat removal (RHR) system

for decay heat cooling. These conditions were incorporated into the design bases for

Unit 2 during plant licensing. Procedure 2-E-1 was created with the inappropriate steps

on October 8, 2015. Procedure 1-E-1 was updated with identical steps on

December 28, 2015. The licensee removed the inappropriate steps in both procedures.

The licensee evaluated the past operability of the ERCW system for the time period

where the steps were incorporated into the procedure and determined that the condition

resulted in the A train of ERCW/CCS being inoperable for Unit 2 for 11 days.

Analysis. The failure to maintain written procedures for emergencies as required by TS 5.7.1.1.a was a performance deficiency. The performance deficiency was more than

minor because it affected the Mitigating Systems Cornerstone attribute of Procedure

Quality and adversely affected the cornerstone objective in that reduced ERCW flow

caused by the inappropriate steps resulted in the Unit 2A train of ERCW/CCS being

inoperable for 11 days. This finding was assessed using NRC inspection Manual

Chapter 0609, Attachment 4, Initial Characterization of Findings. Using Appendix A,

Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to

require a detailed risk evaluation because it represented an actual loss of function of at

least a single train for greater than its TS allowed outage time when the 2A train of

ERCW/CCS was inoperable for 11 days. A regional SRA performed the detailed risk

evaluation using SAPHIRE Version 8.1.6 and Version 8.50 of the SPAR Model for both

units combined. The SRA modified the fault trees for the ERCW 1B & 2A Supply

Headers to reflect the inappropriate steps for opening Valve 1-FCV-67-458 given a

power loss of either A or B train power, assumed the affected header would fail if the

valve were opened, and used an exposure time of one year. The result was less than

1E-6 for each unit which would be a finding of very low significance (Green). For Unit 1,

the dominant sequences were related to loss of offsite power where the performance

deficiency fails ERCW Header 2A leading to loss of seal cooling. For Unit 2, the

dominant sequences were similar with the performance deficiency failing ERCW Header

1B. The risk was mitigated because the performance deficiency would affect operation

only when a LOCA occurred with the simultaneous loss of two shutdown boards.

The finding had a cross-cutting aspect in the Documentation attribute of the Human

Performance area because the licensee did not maintain the accuracy of 1-E-1 through

its revisions and did not maintain procedure 2-E-1 accurate at its creation. (H.7).

Enforcement. TS 5.7.1.1.a, Procedures, required, in part, that written procedures be

established, implemented, and maintained covering activities related to procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory

Guide 1.33, revision 2, Appendix A, Section 6, Procedures for Combating Emergencies

and Other Significant Events recommends procedures for loss of coolant. Contrary to

the above, since October 8, 2015, 2-E-1, revision 0, was not properly established when

a procedural step directing opening of valve 1-FCV-67-458 was included. Also, since

December 28, 2015, procedure 1-E-1, revision 7, was not maintained when the same

procedural step was added. This violation was entered in to the licensees CAP as

CR 1331422 and procedures 1-E-1 and 2-E-1 have been revised to remove this step.

11

This violation is being treated as an NCV consistent with Section 2.3.2 of the NRC

Enforcement Policy and is identified as NCV 05000390, 391/2017003-01, Failure to

Maintain Procedures for Response to a Loss of Coolant Accident.

.2

Inadequate Procedure for Unit Cooldown from Hot Standby to Cold Shutdown

Introduction: An NRC-identified finding of very low safety significance (Green) and

associated NCV of TS 5.7.1.1.a, Procedures, was identified for the failure to maintain

TVA procedures 1-GO-6 and 2-GO-6, both entitled Unit Shutdown from Hot Standby to

Cold Shutdown. The licensee failed to update the procedures based on a PDO to

include steps that would shutdown the running motor driven auxiliary feedwarer pump

(MDAFW) prior to starting a third ERCW pump during the period where the opposite unit

has been shutdown less than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

Discussion: TVA design change notification (DCN) 62151 was issued to ensure the dual

unit system alignment and flow settings for the ERCW system would support operability

and conform to the design bases for both units as Unit 2 transitioned from construction

to full commercial operation. The DCN identified procedural changes necessary to

comply with Unit 1 license amendment 104, which added TSs 3.7.16, Component

Cooling System - Shutdown, and 3.7.17, Essential Raw Cooling Water System -

Shutdown, and the Unit 2 operating license. TS 3.7.16 and 3.7.17 required additional

CCS and ERCW pumps to be operable within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of a unit shutdown. One of the

procedure changes discussed in DCN 62151 was necessary to ensure the ERCW

system was able to meet the limiting design bases event discussed in Unit 1 license

amendment 104 and the Unit 2 operating license which consisted of a design bases

LOCA on one unit coincident with a dual unit LOOP, while the other (non-accident) unit

is on RHR shutdown cooling within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after shutdown and experiences a single

active failure in the form of a loss of power to one train. The changes consisted of

procedure revisions to require starting a third ERCW pump and having provisions to load

it as the second ERCW pump on a single diesel generator (EDG) during the limiting

design basis event. It was recognized, during the license amendment process, that the

diesel generator loading analysis assumed the MDAFW pump was not running on the

non-accident unit. However, the limiting design bases event assumes a dual unit LOOP

where MDAFW pumps would be automatically loaded onto the non-accident units

EDGs. As a result, DCN 62151 required the emergency procedures be revised to direct

the MDAFW pumps for the non-accident unit be stopped and placed in pull to lock and

then activate the applicable ERCW pump interlock bypass switch.

On July 12, 2017, the licensee identified that a previously unknown and unanalyzed

failure mode may be more limiting than the limiting design bases event. As part of this

discovery the licensee realized the procedural changes in DCN 62151 had not been

implemented despite Unit 2 starting commercial operation in September of 2016. As a

result, several emergency procedures did not reflect the required ECRW valve position

and flow requirements to properly mitigate a limiting design bases accident on Unit 2.

The licensee completed a PDO on July 16, 2017. The PDO identified four

compensatory actions necessary to restore operability. The four actions were all

associated with Unit 1 and Unit 2 emergency and general operating procedure changes.

12

The inspectors reviewed the PDO and determined that the need to stop a running

MDAFW pump prior to loading an EDG with a second ERCW pump, to prevent

overloading of the EDG, was not recognized as a required compensatory action to

restore operability. The licensee agreed that the procedure changes to stop the running

MDAFW pump were required and they revised the PDO on July 17, 2017, to include the

necessary procedure changes.

Analysis: The licensees failure to maintain TVA procedures 1-GO-6, revision 8 and

2-GO-6, revision 6 was a performance deficiency. The performance deficiency was

more than minor because it affected the Mitigating Systems Cornerstone attribute of

Equipment Performance and affected the cornerstone objective in that failure to maintain

the procedures resulted in a condition where the EDG would have been overloaded and

rendered inoperable in response to a design basis event. The inspectors evaluated the

significance of this finding using IMC 0609, Attachment 4, Appendix A, Exhibit 2, and

determined that this finding was of very low safety significance (Green) because the

finding did not represent an actual loss of function of a single train for greater than its TS

allowed outage time.

The finding had a cross-cutting aspect in the Avoid Complacency component of the

Human Performance area as defined in NRC IMC 0310 because the organization failed

to recognize the possibility of mistakes and use appropriate error reduction tools. [H.12].

Enforcement: TS 5.7.1.1.a, Procedures, required, in part, that written procedures be

established, implemented, and maintained covering activities related to procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory

Guide 1.33, Section 2(j), General Plant Operating Procedures, required procedures for

Hot Standby to Cold Shutdown. Contrary to the above, from July 16, 2017 to

July 17, 2017, the licensee failed to maintain their procedures for unit shutdown from hot

standby to cold shutdown, 1-GO-6, revision 8 and 2-GO-6, revision 6, because they did

not include steps to prevent an EDG overload by stopping the running MDAFW pump.

The licensees immediate corrective actions included revising both procedures to add

the required steps. This violation was entered into the CAP as CR 1318176 and is being

treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. It is

identified as NCV 05000391, 390/2017003-02, Inadequate Procedure for Unit Cooldown

from Hot Standby to Cold Shutdown.

1R19 Post-Maintenance Testing (71111.19)

a.

Inspection Scope

The inspectors reviewed the post-maintenance test procedures and/or test activities,

(listed below) as appropriate, for selected risk-significant mitigating systems to assess

whether: 1) the effect of testing on the plant had been adequately addressed by control

room and/or engineering personnel; 2) testing was adequate for the maintenance

performed; 3) acceptance criteria were clear and adequately demonstrated operational

readiness consistent with design and licensing basis documents; 4) test instrumentation

had current calibrations, range, and accuracy consistent with the application; 5) tests

were performed as written with applicable prerequisites satisfied; 6) jumpers installed or

13

leads lifted were properly controlled; 7) test equipment was removed following testing;

and 8) equipment was returned to the status required to perform its safety function. The

inspectors verified that these activities were performed in accordance with

NPG-SPP-06.9, Testing Programs; NPG-SPP-06.3, Pre-/Post-Maintenance Testing; and

NPG-SPP-07.1, On Line Work Management. This activity constituted five Post

Maintenance Testing inspection samples, as defined in IP 71111.19.

WO 118921021, 2-SI-68-120, 184 day channel operational test reactor coolant flow

loop 3 channel III, loop 2-LPF-68-48D (F-436)

WO 118851496, 2-SI-99-10-B, 62 day functional test of SSPS train B and reactor trip

breaker B following tester circuit board replacement

WO 118921021, 2-SI-68-120, 184 day channel operational test reactor coolant flow

loop 3, channel III, loop 2-LPF-68-48D (F436) following EAGLE 21 DFP circuit board

replacement

WO 119010949, 1-SI-30-902-A, Valve full stroke exercising during plant operation

ventilation train A following replacement of quick exhaust valve on 1-FCV-30-40

WO 118985349, Post maintenance test following 2B2 EDG auxiliary lube oil pump

replacement

b.

Findings

No findings were identified.

1R20 Refueling and Outage Activities (71111.20)

.1

Unit 2 Forced Outage (July 1, 2017 - August 8, 2017)

a.

Inspection Scope

The Unit 2 began a forced outage on March 23, 2017, due to a structural failure of the B

condenser waterbox. On July 1, 2017, the unit was in mode 5 until the unit began to heat

up in preparation for startup. The reactor became critical on July 23, 2017, but returned

to hot standby (Mode 3) due to equipment problems with the main feed pumps. On

July 25, 2017, startup resumed, but the reactor was tripped before criticality due to rod

position indication problems. Startup recommenced on July 27, 2017, but was stopped

due to additional rod position indication problems. On July 30, 2017, Unit 2 started up

after rod position indication repairs and achieved 29 percent rated thermal power (RTP)

on August 2, 2017. The unit remained at 29 percent RTP until August 3, 2017, when the

turbine was tripped due to a steam leak on a turbine drain line. The reactor stabilized at

8 percent RTP and remained there until power ascension resumed after drain line

repairs. Unit 2 reached 100 percent RTP on August 8, 2017, and remained there for the

remainder of the reporting period.

The inspectors observed the licensees mode changes and startups in order to verify that

they were performed in accordance with station procedures and TSs. The inspectors

made entry into containment prior to the unit restart to assess the material condition of

SSCs, including the containment sump. The inspectors attended forced outage meetings

14

and reviewed the daily risk assessments and condenser repair plans. The inspectors also

observed the performance of some surveillance testing being performed while the unit was

shutdown. This activity constituted one Refueling and Other Outage Activities sample, as

defined in IP 71111.20.

b.

Findings

No findings were identified.

1R22 Surveillance Testing (71111.22)

a.

Inspection Scope

The inspectors witnessed the surveillance tests and/or reviewed test data of selected

risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met the

requirements of the TS; the UFSAR; NPG-SPP-06.9, Testing Programs;

NPG-SPP-06.9.2, Surveillance Test Program; and NPG-SPP-09.1, ASME Section XI.

The inspectors also determined whether the testing effectively demonstrated that the

SSCs were operationally ready and capable of performing their intended safety

functions. This activity constituted ten Surveillance Testing inspection samples; three

in-service and seven routine; as defined in IP 71111.22.

In-Service Test:

WO 118371917, 1-SI-62-901-A, Centrifugal charging pump 1A-A quarterly

performance test

WO 118086192, 2-SI-67-908-B, Valve full stroke exercising and position indication

verification during cold shutdown - essential raw cooling water (train 2B)

WO 118431243, 1-SI-74-901-A, Residual heat removal pump 1A quarterly

performance test

Other Surveillances

WO 118431170, 0-SI-82-12-A, Monthly diesel generator start and load test DG 2A-A

WO 118086055, 2-SI-0-710, Containment integrity: penetrations

WO 117823693, 2-SI-211-1-A, 18 month 6.9 KV shutdown board 2A-A automatic

and manual transfer tests

WO 118061393, 2-SI-211-1-B, 18 month 6.9 KV shutdown board 2B-B Automatic

and Manual Transfer Tests

WO 117823686, 2-SI-211-3-A, 18 month functional test on 6900V SD BD 2A-A

degraded and undervoltage relays

WO 117823687, 2-SI-211-3-B, 18 month functional test on 6900V SD BD 2B-B

degraded and undervoltage relays

WO 117823601, 2-SI-68-86, 18 month channel calibration of remote shutdown

monitoring narrow range pressurizer pressure loop 2-LPP-68-337C

15

b.

Findings

Introduction: A self-revealed finding of very low safety significance (Green) and

associated NCV of TS (TS) 5.7.1.1.a, Procedures, was identified for the failure to follow

TVA procedure 2-SI-68-86, 18 Month Channel Calibration of Remote Shutdown

Monitoring Narrow Range Pressurizer Pressure Loop 2-LPP-68-337C, Revision 4. The

licensee failed to properly follow step 6.2.6 [1.3], which resulted in the inadvertent lifting

of a pressurizer power operated relief valve (PORV).

Discussion: On June 21, 2017, instrumentation and control technicians were performing

Surveillance 2-SI-68-86. The surveillance verified the function of the transfer switches

for the PORV and its associated block valve to transfer power from the main control

room to the auxiliary control room. Step 6.2.6 [1.3] of the procedure directed that the

distributed control system (DCS) demand for the PORV be toggled to 0 (closed). When

the technicians came to this step, they toggled the output as directed in the beginning of

the procedure step. However, they did not recognize that the DCS demand was at 0

and, therefore, toggled it to 1 (open). When the auxiliary transfer switch was operated,

the PORV had an open signal present and opened. This resulted in a reactor coolant

pressure drop from 335 psig to 310 psig. The main control room operators were alerted

to this condition by an annunciator for high pressure in the pressurizer relief tank,

properly diagnosed the inadvertent PORV opening, and shut the associated PORV block

valve stopping the pressure decrease.

Analysis: The licensees failure to follow TVA procedure 2-SI-68-86, was a performance

deficiency. The performance deficiency was more than minor because it affected the

Initiating Events Cornerstone attribute of Human Performance and adversely affected

the cornerstone objective in that failing to follow procedure 2-SI-68-86 resulted in a

temporary lowering of reactor coolant pressure and inventory. The finding was screened

in accordance with NRC IMC 0609, Attachment 4, Appendix G, Shutdown Operations

Significance determination process Phase 1 Initial Screening and Characterization of

Findings. The finding was screened to Green based on the answers to questions 2 and

3. The resultant leakage from the open PORV would not have caused the current decay

heat removal method to fail if it went undetected and leakage would be self-limiting such

that it would stop before impacting the operating method of decay heat removal.

The finding had a cross-cutting aspect in the Challenge the Unknown component of the

Human Performance area as defined in NRC IMC 0310, because the technicians failed

to recognize that the output was already set to 0, but proceeded anyways to toggle the

output which resulted in setting it to 1 [H.11].

Enforcement: TS 5.7.1.1.a, Procedures, required, in part, that written procedures be

established, implemented, and maintained covering activities related to procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory

Guide 1.33, Section 8, Procedures for Control of Measuring and Test Equipment and for

Surveillance Tests, Procedures, and Calibrations requires procedures for surveillance

tests. Contrary to the above, required surveillance procedure 2-SI-68-86, revision 4,

was not implemented when step 6.2.6 [1.3] was not performed as written. Corrective

actions taken or planned by the licensee include revisions to 2-SI-68-86 to clarify the

16

steps relating to toggling the DCS output, training for the craft, and management

oversight of pre-job briefs. This violation was entered into the CAP as CR 1309345 and

is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.

This violation is identified as NCV 05000391/2017003-03, Failure to Follow a

Surveillance Procedure Led to an Inadvertent Lift of a Pressurizer Power Operated

Relief Valve.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06)

a.

Inspection Scope

On the dates listed below, the inspectors observed a licensee-evaluated emergency

preparedness drill to verify that the emergency response organization was properly

classifying the event in accordance with licensee procedure EPIP-1, Emergency Plan

Classification Flowchart, and making accurate and timely notifications and protective

action recommendations in accordance with EPIP-2, Notification of Unusual Event;

EPIP-3, Alert; EIPIP-4, Site Area Emergency; EPIP-5, General Emergency; and the

Radiological Emergency Plan. In addition, the inspectors verified that licensee

evaluators were identifying deficiencies and properly dispositioning performance against

the performance indicator criteria in Nuclear Energy Institute (NEI) 99-02, Regulatory

Assessment Performance Indicator Guideline. This activity constituted two EP drill

evaluation inspection samples.

EP drill on July 17, 2017

EP drill on August 16, 2017

b.

Findings

No findings were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification (71151)

.1

Cornerstone: Mitigating Systems

a.

Inspection Scope

The inspectors sampled licensee submittals for the two PIs listed below. To verify the

accuracy of the PI data reported from July 1, 2016 through June 30, 2017. PI definitions

and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline,

Revision 7, were used to verify the basis in reporting for each data element.

This activity constituted two performance indicator samples, as defined in IP 71151.

17

High Pressure Safety Injection MSPI

RCS leak rate

b.

Findings

No findings were identified.

4OA2 Problem Identification and Resolution (71152)

.1

Review of Items Entered into the CAP

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 condition report (CR)

summary reports and attending daily CR review meetings

.2

Annual Sample: Review of CR 129727, Watts Bar Elevation Letter - Operations

Leadership Formality and Rigor

a.

Inspection Scope

The inspectors reviewed CR 1297271, WBN Elevation Letter - Operations Leadership

Formality and Rigor, in detail to evaluate the effectiveness of the licensees corrective

actions intended to address operator performance concerns. The CR was written to

address the continued lack of formality, rigor, and discipline by operators in monitoring

and controlling the plant. The inspectors assessed whether issues were properly

identified, documented accurately and completely, properly classified and prioritized,

adequately considered extent of condition, generic implications, common cause, and

previous occurrences, adequately identified root causes/apparent causes, and identified

appropriate and timely corrective actions. The inspector reviewed processes contained in

the licensees Conduct of Operations procedure (OPDP-1) and CAP (NPG-SPP-22.300).

This activity constituted one sample of in-depth review as defined in IP 71152.

b.

Observations and Findings

To address the concerns identified in CR 1297217, the licensee developed a High

Intensity Training (HIT) program. The training was developed to refocus training

personnel and license operators of standards, behaviors and expectations associated

with plant operations. The inspector discussed the licensees HIT program with

members of the licensees training staff, operations management, and licensee

operators during a four day period. During the discussions, the inspector was able to

obtain a clear understanding of why and how HIT was developed.

During the four days of observing HIT activities, the inspectors observed two operating

crews and two crews of evaluators in a training environment. The inspector also

observed classroom training and critiques following each simulator scenario. Many of

18

the training activities were also observed by a member of the licensees corporate

training staff, onsite operations management, a contract third party evaluator, and a peer

evaluator from another utility.

The training sessions were found to be very intense and operational focused. The

evaluators were extremely critical of crew performance. The evaluators took every

opportunity to identify and address concerns. Whenever a concern/issue was identified,

the scenario was stopped and the issues was discussed with the crew. Stopping the

scenario and holding discussions occurred numerous times throughout each scenario.

Following each discussion, the simulator was reset to the desired point and reran. The

discussions were very interactive. During the discussions, the evaluators constantly

focused on procedural requirement and licensee expectations. The evaluators were

often challenged/questioned by crew members. The evaluators adequately addressed

each question or concern identified by the crew. The inspector also observed critiques

following scenarios.

From the inspectors observation it was clear that HIT was designed to address

operational performance issues identified in the CR. The effectiveness of HIT can only

be evaluated by observing operator and plant performance over time. The inspectors

concluded that the training provided during HIT, if embraced, should decrease lack of

formality, increase rigor, and improve discipline by operators in monitoring and

controlling the plant. The HIT would also be expected to improve operators

implementation of standards outlined in OPDP-1, Conduct of Operations. The

inspectors will continue to monitor operator and plant performance in the control room,

during actual plant events and in licensed operator simulator training, as required by the

baseline inspection program. No findings were identified.

.3

Semiannual Trend Review

a.

Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to

identify trends that could indicate the existence of a more significant safety issue. The

review was focused on trends in risk management, long-standing minor equipment

deficiencies, housekeeping, TS compliance, corrective action screening and condition

adverse to quality documentation.

b.

Observations and Findings

No findings were identified. The inspectors had several observations regarding the

trends listed above. Regarding risk management, the inspectors noted that the

environmental factor for the equipment out of service computer program (EOOS) was

not consistently adjusted per procedure to reflect activities in the plant switchyard. This

was initially identified to the licensee in 2016. The condition report written at that time

documented the issue as an NRC question, rather than a failure to follow the EOOS

procedure, and the corrective action was to respond to the NRC to ensure that their

question was answered, rather than address procedure non-compliance. The inspectors

re-visited this with the licensee when they observed switchyard work in progress without

19

the environmental factor setting in EOOS being per procedure. This time the licensee

properly characterized the issue as procedure non-compliance in their CAP. The

inspectors used the EOOS test module and verified that risk remained GREEN during

instances when the environmental factor adjustment was not properly set. The

inspectors noted that, for the work performed when the environmental factor was not

properly set, the licensee did implement physical risk mitigation controls at the work sites

that were in accordance with the appropriate work management procedures.

The inspectors also noted a trend in long-standing equipment issues eventually

becoming either operator distractions or worse conditions. In one instance valve leakby

in the chemical volume and control system gave erroneous indication that the reactor

coolant system was either being borated or diluted. This required the operating crew to

enter procedures to then verify that the RCS truly was neither borated nor diluted. In

another instance, known leakage on the 1A high pressure fire pump shaft seal worsened

to the point that protective measures had to be taken to shield water spray from the

power supply conduit of the pump.

Since the completion of Unit 2 construction, the inspectors noted a reduction in the

amount of temporary equipment stored in the plant auxiliary building and general

housekeeping improvements in the auxiliary building. CAP review during the first and

second quarter of 2017 showed a more aggressive approach by the license in improving

housekeeping and removing lingering temporary equipment. Documents reviewed show

that the licensee accomplished this through frequent health and safety walkdowns and

challenging temporary equipment tags that were out of date. The inspectors observed

the results of these efforts in their routine walkdowns of risk-significant areas.

Specifically, in regards to a large scaffold storage area near the Unit 2 713 level

penetration. Although temporary equipment tags were present and up to date, the area

appeared to have become a convenient location to temporarily store a wide variety of

items beyond scaffolding. The licensee identified this in their CAP and then completely

removed all of the items stored in the area.

The inspectors also identified negative trends in the treatment of C-level CRs in the CAP

and with TS compliance issues. Inspectors identified multiple C-level CRs during the

inspection period that exhibited one of the following issues: inadequate documented

condition details; inadequate screening of conditions adverse to quality (CAQs) to

non-CAQ status; and failure to promptly identify CAQs. Inspectors also noted several

examples of issues with TS compliance and proper TS application during the inspection

period. The licensee has identified these issues in their CAP.

4OA3 Event Followup (71153)

.1

(Closed) Licensee Event Report (LER) 05000390, 391/2016-010-00, Emergency Diesel

Generator Crankcase Pressure Switches Not Analyzed to Withstand the Effects of a

Tornado

A condition involving the potential impact of a tornado on the EDGs was identified during

an NRC Component Design Basis lnspection at the Sequoyah Nuclear Plant. The EDGs

were designed with a crankcase pressure trip setpoint of approximately one inch of

water which is bypassed during an emergency start. A tornado could potentially induce

20

a pressure spike which could cause actuation of the crankcase pressure trip due to

different vent paths between the EDG room and the EDG crankcase. Actuation of the

crankcase pressure trip would energize the shutdown relay causing an EDG lockout

condition. The EDG lockout condition would prevent all EDG starts until operators

manually reset the lockout condition. Because the EDGs at Watts Bar were essentially

identical designs, this condition was reviewed for applicability to Watts Bar. The

licensee determined this condition placed both units in an unanalyzed condition that

could have potentially affected all four EDGs simultaneously. This was a legacy EDG

protective logic circuitry design that did not anticipate the interaction between the

crankcase pressure trip and the outside atmospheric pressure spike during a tornado.

This condition was documented in the licensee CAP as CR 1179264. A compensatory

action was established of starting the EDGs in the emergency mode when notified of a

Tornado Warning and ran while the Tornado Warning was in effect ensuring the EDGs

would be available to perform their required safety function. The licensee also

implemented DCN 66376 to remove the sealin function of the crankcase differential

pressure switches and retain the alarm function of the switches for all four EDGs. This

LER was reviewed by the inspectors. A licensee-identified violation is documented in

Section 4OA7.

.2

(Closed) LER 05000390/2016-001-00, Channel Mode Switch in Incorrect Position

Renders Lower Containment Atmosphere Particulate Radiation Monitor Inoperable.

a.

Inspection Scope

On January 12, 2016, at 1645 Eastern Standard Time (EST), Watts Bar Nuclear Plant

(WBN) Maintenance personnel were performing a 92 day channel operational test for

radiation monitor 1-RM-90-1064, Lower Containment Atmosphere Particulate Radiation

Monitor, and found the mode switch in the "DlFF" position, which was not expected. The

surveillance was stopped and an investigation was conducted. It was determined that

the design required the mode switch to be in the "lNT" position to be operable. The

mode selector switch was placed in the "lNT" position and the surveillance was

completed. The radiation monitor was restored to OPERABLE status at 1743 EST on

January 12, 2016. Placing the mode selector switch in the "DlFF" position resulted in 1-

RM-90-1064 being INOPERABLE due to the loss of alarm function of the monitor.

Investigation determined that the switch had been repositioned on December 8, 2015.

Because the containment particulate radiation monitor was inoperable for a period of

time greater than permitted by TS 3.4.15, this condition was reportable as an operation

or condition prohibited by TS per 10 CFR 50.73(a)(2)(i)(B). During the time the monitor

was inoperable, other means of leak detection (e.g., containment pocket sump level

indication, reactor coolant system inventory balance) remained available. This LER was

reviewed by the inspectors. No additional findings or violations of NRC requirements

were identified.

.3

(Closed) LER 05000390/2016-005-00, Both Trains of Unit 1 Emergency Gas Treatment

System Inoperable During Unit 2 Testing

21

On March 14, 2016, Watts Bar Nuclear Plant (WBN) Unit 1 determined through

engineering analysis that both trains of emergency gas treatment system (EGTS) were

inoperable for 8 minutes, 10 seconds during preoperational testing of Unit 2 EGTS. The

inoperability of A and B trains of Unit 1 EGTS took place on October 22, 2015, while

Unit 1 was in Mode 1 and two trains of EGTS were required to be operable in

accordance with TS LCO 3.6.9, "Emergency Gas Treatment System (EGTS). At the

time of the event, Unit 2 was in "no mode," prior to initial fuel loading. With both trains of

EGTS inoperable, the specified safety functions of Unit 1 EGTS were not capable of

being performed. Therefore, this condition was reported pursuant to

10 CFR 50.73(a)(2)(v)(C) and 10 CFR 50.73(a)(2)(v)(D), "Event or Condition That Could

Have Prevented Fulfilment of a Safety Function." This LER was reviewed by the

inspectors. No additional findings or violations of NRC requirements were identified.

.4

(Closed) LER 05000390/2016-004-00, Automatic Reactor Trip Due to Actuation of Over

Temperature Delta Temperature Bistables

On March 22, 2016, at 1131, Watts Bar Nuclear Plant Unit 1 experienced an automatic reactor trip. The initiating reactor trip first out received was 76-C Over-temperature Delta

T. The turbine trip first out received was 73-C Rx Trip Breakers RTA and BYA Open.

Prior to the unit trip, Unit 1 was in Mode 1 at 100 percent power. Concurrent with the

reactor trip, the auxiliary feedwater system actuated. All control rods inserted upon the

reactor trip and safety systems functioned as expected. This LER was reviewed by the

inspectors. No additional findings or violations of NRC requirements were identified.

.5

(Closed) LER 05000390/2016-006-00, Undersized Room Cooler Fan Shaft Results in

Loss of Centrifugal Charging Pump

On May 13, 2016, Watts Bar Unit 1 determined that a condition prohibited by TSs had

previously occurred. During the Fall 2015 outage, maintenance performed on the 1B-B

centrifugal charging pump (CCP) room cooling fan introduced a condition that resulted in

a subsequent bearing failure of the room cooling fan. This condition would have

prevented the 1B-B CCP pump from performing its function for its designed mission

time. Based on the reduced reliability of the fan, the 1B-B CCP was considered to be

inoperable from October 7, 2015, until the fan was repaired and returned to service on

December 6, 2015. During this time, there were several short periods when the 1A-A

CCP was also inoperable. A NCV for this condition was documented in NRC Inspection

Report 05000390, 391/2016002-02. The LER was reviewed by the inspectors. No

additional findings or violations of NRC requirements were identified.

.6

(Closed) LER 05000390/2016-011-00, Loss of Centrifugal Charging Pump Due to

Repeat Failure of Associated Room Cooler

On August 3, 2016, Wafts Bar Nuclear Plant Unit 1 (WBN1) determined that a condition

prohibited by TS had previously occurred. During maintenance of the 1B-B CCP room

cooler, the bearing was found in a degraded condition requiring repair. This fan was

required to support Operability of the 1B-B CCP. The fan had been previously repaired

on December 6, 2015, and had less than 100 days of operation since its overhaul. The

22

mission time of the CCPs is specified in design documents as 100 days. Based on the

inability of the CCP to meet its mission time, the 1B-B CCP was considered to be design

inoperable since its overhaul on December 6, 2015. This represents a condition

prohibited by TS for the 1B-B CCP being inoperable for greater than its allowed outage

time. The LER was reviewed by the inspectors. No findings or violations of NRC

requirements were identified.

4OA5

.1

IP 93100 Safety-Conscious Work Environment Issue of Concern Follow Up

a.

Inspection Scope

The inspectors assessed the TVA Nuclear corporate safety-conscious work

environment (SCWE) by conducting safety culture interviews of individuals from the

engineering, licensing, and operations groups. Inspectors interviewed a total of 22

individuals to determine if indications of a chilled work environment exist, employees are

reluctant to raise safety and regulatory issues, and employees are being discouraged

from raising safety or regulatory issues. Information gathered during the interviews was

used in aggregate to assess the work environment at TVA Nuclear corporate.

b.

Assessment

Based on the interviews conducted, the inspectors determined that licensee

management emphasized the need for all employees to identify and report problems

using the appropriate methods established within the administrative programs, including

the CAP and Employee Concerns Program. These methods were readily accessible to

all employees. Based on discussions conducted with a sample of employees from

various departments, the inspectors determined that employees felt free to raise safety

and regulatory issues, and that management encouraged employees to place issues into

the CAP for resolution. The inspectors did not identify any reluctance on the part of the

licensee staff to report safety concerns.

4OA6 Meetings, including Exit

On October 25, 2017 and November 8, 2017, the resident inspectors presented the

inspection results to members of the licensee staff. The inspectors confirmed that none

of the potential report input discussed was considered proprietary.

4OA7 Licensee-Identified Violations

The following licensee-identified violations of NRC requirements were determined to be

of very low safety significance and met the NRC Enforcement Policy criteria for being

dispositioned as NCVs.

Technical Specification 5.7.1.1.a, Procedures, required, in part, that written

procedures be established, implemented, and maintained covering activities

related to procedures recommended in Regulatory Guide 1.33, Revision 2,

Appendix A, 1978. Regulatory Guide 1.33, Revision 2, Appendix A, Section 6,

23

Procedures for Combating Emergencies and Other Significant Events requires

procedures for a reactor trip. Contrary to the above, from May 23, 2016, until

July 16, 2017, procedure 2-E-0, Revision 5, Reactor Trip and Safety Injection, was

not maintained which resulted in a condition where CCS Heat Exchanger B

(ERCW/CCS Train 2A) would not have been able to remove sufficient heat during

sump recirculation following a LOCA on Unit 2 for approximately 75 days. This

condition was caused by the licensees failure to implement ERCW system

DCN 62151 as written. A detailed risk evaluation was performed using SAPHIRE

Version 8.1.5 and Version 8.50 of the SPAR Model for both units combined. The

result was less that 1E-6/year for Unit 2, which would be a finding of very low

significance (Green). This violation was entered in to the licensees CAP as

CR 1316395.

Technical Specification 5.7.1.1.a stated, in part, that written procedures shall be

established, implemented, and maintained covering the applicable procedures in

Regulatory Guide 1.33 Rev. 2, Appendix A, February 1978. Procedures for locking

and tagging are applicable procedures under REG GUIDE 1.33 Appendix A, 1.c

Equipment Control. Contrary to this requirement, Step 3.2.4.M of procedure

NPG-SPP-10.2, Clearance Procedure to Safely Control Energy, Revision 18 was

not followed when nitrogen supply isolation valves 2-ISIV-1-408L and

2-ISIV-1-408M and isolation valves 2-ISIV-1-405L and 2-ISIV-1-405M were closed

and tagged but not documented as tagged in the Electronic Shift Operations

Management System (eSOMS). As a result, the valves remained closed resulting

in the inability to operate the Unit 2 SG#1 and #2 PORVs using back-up nitrogen.

The finding was determined to be Green because having the nitrogen supply to

two out of four steam generator PORVs isolated only affects the ability to achieve

and maintain cold shutdown. The licensee documented this violation as

CR 1303309.

Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control, required, in part, a

testing program to demonstrate that quality related SSCs will perform satisfactorily

in service and performed in accordance with written test procedures. Contrary to

the above, from at least 2010 until July 2017, various safety-related valves were

unacceptably preconditioned prior to required as-found testing. This finding was of

very low safety significance (Green) because the finding did not represent an

actual loss of function of a single train for greater than its TS allowed outage time.

The licensee documented this violation as CRs 1276605, 1316712, 1319298,

1319304.

10 CFR Part 50, Appendix B, Criterion III, Design Control, stated, in part, that,

measures shall be established for the selection and review for suitability of

application of materials, parts, equipment, and processes that are essential to the

safety-related functions of SSCs. Contrary to the above, for at least the past

twenty years, the licensee failed to assess the effects of a tornado on the

crankcase over-pressure trip which could prevent EDGs from fulfilling their

safety-related function. A regional senior reactor analyst performed a detailed risk

evaluation and determined the dominant accident sequences involved a

weather-related loss of offsite power with all four EDGs failing due to the

24

performance deficiency and the operators recovering one of the failed EDGs. The

risk of this performance deficiency was not greater than Green due to the low

frequency of tornados/high winds and the potential for operator recovery. The

licensee documented this violation as CR 117926.

Technical Specification LCO 3.6.3, Containment Isolation Valves, required that each

containment isolation valve shall be operable in modes 1, 2, 3, and 4. TS Required

Action statement A.1 required that the affected penetration flow path be isolated,

and Required Action A.2, directed that the penetration flow path is verified to be

isolated once per 31 days. Contrary to the above, on May 18, 2017, containment

isolation valve 1-FCV-31-330 was tagged closed for maintenance; however no

verification that the flow path was isolated was performed until August 23, 2017.

This finding was of very low safety-significance (Green) because it did not represent

an actual open pathway in the physical integrity of reactor containment and was not

related to hydrogen ignitors. The licensee documented this violation as

CR 1331287.

Unit 1 Operating License condition 2.F required, in part, that TVA shall implement

and maintain in effect all provisions of the approved Fire Protection Program. The

Fire Protection Report was developed to ensure compliance with the requirements of

this licensee condition. Fire Protection Report, Part II, is the Fire Protection Plan

(FPP). FPP Subsection 14.10, Fire Safe Shutdown Equipment, required

nonfunctional equipment listed in Table 14.10 be restored to its functional status

within 30 days. If this 30 day requirement cannot be met, then the equipment be

placed in its fire safe shutdown (FSSD) position. Contrary to the above, during a

surveillance on June 10, 2017, backdraft damper 0-BKD-31-592, equipment listed in

Table 14.10, was identified as not being able to achieve its FSSD position. However,

actions to place the damper in its FSSD position were not taken until July 11, 2017.

This finding was of very low safety significance because there was a fully functional

automatic suppression system on either side of the fire barrier. This violation was

documented as CR 1316058.

Attachment

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Arent, Director, WBN Site Licensing

M. Casner, Director, Engineering

L. Cross, Manager, Electrical Systems

T. Detchemendy, Manager, Site Emergency Preparedness

E. Ellis, Senior Manager, Nuclear Site Security

D. Erb, Operations Director

K. Hulvey, Watts Bar Licensing Manager

J. James, Director, Maintenance

B. Jenkins, Director, Plant Support

T. Marshall, Plant Manager

C. Rice, Operations Superintendent

P. Simmons, Site Vice President

A. White, Senior Manager, Site Quality Assurance

LIST OF REPORT ITEMS

Opened and Closed

NCV 05000390, 391/2017003-01

Failure to Maintain Procedures for Response to a

Loss of Coolant Accident (Section 1R15.1)

NCV 05000391, 390/2017003-02

Inadequate Procedure for Unit Cooldown from Hot

Standby to Cold Shutdown (Section 1R15.2)

NCV 05000391/2017003-03

Failure to Follow a Surveillance Procedure Led to

an Inadvertent Lift of a Pressurizer Power Operated

Relief Valve (Section 1R22)

Closed

LER 05000390, 391/2016-010-00

Emergency Diesel Generator Crankcase Pressure

Switches Not Analyzed to Withstand the Effects of

a Tornado (Section 4OA3.1)

LER 05000390/2016-001-00

Channel Mode Switch in Incorrect Position Renders

Lower Containment Atmosphere Particulate

Radiation Monitor Inoperable (Section 4OA3.2)

LER 05000390/2016-005-00

Both Trains of Unit 1 Emergency Gas Treatment

System inoperable During Unit 2 Testing (Section

4OA3.3)

LER 05000390/2016-004-00

Automatic Reactor Trip Due to Actuation of Over

Temperature Delta Temperature Bistables (Section

4OA3.4)

LER 05000390/2016-006-00

Undersized Room Cooler Fan Shaft Results in Loss

of Centrifugal Charging Pump (Section 4OA3.5)

LER 05000390/2016-011-00

Loss of Centrifugal Charging Pump Due to

Repeat Failure of Associated Room Cooler

(Section 4OA3.6)

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

0-MI-17.003, Flood Mode Preparation Storage Locations and Periodic Inventory, Rev. 0012

0-TI-444, External Flood Protection Program, Rev. 0003

Section 1R04: Equipment Alignment

Procedures

2-SI-63-8, ECCS Valve Alignment Verification, Rev. 0002

2-SI-3-130, AFW Valve Alignment Verification, Rev. 0004

2-SOI-63.01 ATT 1V, Safety Injection System, Rev. 0005

2-SI-70-1, Component Cooling System, Safety-Related Valves: Alignment Verification, Rev.

0004

2-SOI-72.01, Containment Spray System, Rev. 0005

2-SOI-72.01 Containment Spray System Valve Checklist 2-71.01V, ATT 1V, Rev. 0001

0-SOI-82.03, Diesel Generator (DG) 2A-A, Rev. 0012

0-SOI-82.03, Diesel Generator 2A-A Power Checklist 82.03-1P, ATT 1P, Rev. 0000

0-SOI-82.03, Diesel Generator 2A-A Valve Checklist 82.03-1V, ATT 1V, Rev. 0010

0-SOI-67.01, Essential Raw Cooling Water System Supply Header 1A Valve Alignment

Checklist 0-67.01-3V, ATT 3V, Rev. 0017

0-PI-OPS-17.0, 18 Month Locked Valve Verification, Rev. 0082

0-TI-31.08, Flow Balancing Valves Setpoint Positions, Rev. 0003

0-SOI-82.04, Diesel Generator (DG) 2B-B, Rev. 0010

0-SOI-82.04. Diesel Generator 2B-B Power Checklist 82.04-1P, ATT 1P, Rev. 0000

0-SOI-82.04, Diesel Generator 2B-B Valve Checklist 82.04-1V, ATT 1V, Rev. 0010

0-SOI-67.01, Essential Raw Cooling Water System Supply Header 1B Valve Alignment

Checklist 0-67.01-4V, ATT 4V, Rev. 0017

Section 1R05: Fire Protection

CRs 1262925, 1343002

Fire Protection Report, Part VI - Fire Hazards Analysis, Rev. 52

WBN-Prefire Plan, AUX-0-692-01, Rev. 4

WBN-Prefire Plan, AUX-0-692-02, Rev. 3

Drawing 47A472-1

Drawing 47W866-11

Drawing 47W920-2

Drawing 47A381-20

Drawing 47A381-127

WBN Prefire Plan AUX-0-713-01, Rev. 1

WBN Prefire Plan AUX-0-713-02, Rev. 3

WBN Prefire Plan AUX-0-713-03, Rev. 4

WBN Prefire Plan CON-0-729-01, Rev. 2

WBN Prefire Plan AUX-0-676-01, Rev. 3

4

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

0-TI-12.16, Diesel Generator Outage T/S or SR Contingency Actions, Rev. 0005

WO 118934650

0-SI-82-2, 8 Hour Diesel Generator AC Power Source Operability Verification, Rev. 0025

WO 118928550

CRs 1727208, 1327472

NPG-SPP-09.11.1, Equipment Out of Service Management, Rev. 0012

NPG-SPP-07.3, Work Activity Risk Management Process, Rev. 0021

PWR operational risk review - red sheet for WO 118819797, Hose replacement on Unit 1 main

turbine electro-hydraulic control

High risk management plan for WO 119013421, Freeze seal for isolation of valve, dated 9/7/17

Section 1R15: Operability Determinations and Functionality Assessments

WOs 118882781, 113861046, 113860919, 118991891

WBN-SDD-N3-85-4003, Control Rod Drive System, Rev. 15

WBN-SDD-N3-99-4003, Reactor Protection System, Rev. 24

Drawings 1082H70-6, Rev. N; 1082H70, Rev. AK; 1082H70-17, Rev. AF

Operational Decision-Making Issue Evaluation Document, dated July 22, 2017

Drawing 2-47W880-4, Rev. 0

0-PI-OPS-17.0, 18 Month Locked Valve Verification, Rev. 0081

N3-67-4002, Essential Raw Cooling Water System

1-E-1, Loss of Reactor or Secondary Coolant, Rev. 0009

WBN-SDD-N3-67-4002, Essential Raw Cooling Water System, System 67, Rev. 0035

0-TI-31.08, Flow Balancing Valves Setpoint Positions, Rev. 0003

0-TI-12.11, Emergency Operating Instruction (EOI) Control, Rev. 0001

TI-78, Lubrication Program, Rev. 0011

NPG-SPP-07.3, Work Activity Risk Management Process, Rev. 0009

WB-DC-40-64, Design Basis Events Design Criteria

Westinghouse STS, B 3.8.3, Diesel Fuel Oil, Lube Oil, and Starting Air, Rev. 4.0

0-SOI-82.01, Diesel Generator (DG) 1A-A, Rev. 0009

WBN-VTD-P318-0020, Instructions for EMD Lubricating Oil System

Section 1R19: Post Maintenance Testing

CR 1325844

2-SI-68-114, 184 Day Channel Operational Test RCS Flow Loop 1 Channel III Loop 2-LPF-68-

6D (F-416), Rev. 0003

WO 118921021

2-IMI-99.100, EAGLE 21 Rack Diagnostics, Rev. 0002

WO 117829913

1-SI-30-901-A, Valve Full Stroke Exercising During Plant Operation - Ventilation (Train A), Rev.

0017

PM 600124762

Drawing 1-47W866-1, Rev. 68

5

Section 1R22: Surveillance Testing

WOs 118628055, 116153069

CRs 1322136, 1276914, 1314124, 1314688, 1309892, 1309602, 1309207

0-SOI-82.03, Diesel Generator (DG) 2A-A, Rev. 0010

2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD

- ERCW (Train 2B), Rev. 0003

2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD

- ERCW (Train 2B), Rev. 0004

2-SI-67-908-B, Valve Full Stroke Exercising and Position Indication Verification During Cold SD

- ERCW (Train 2B), Rev. 0005

1EP6: EP Drill Evaluation

Controllers package for July 17, 2017, training drill dated 7/17/17

CRs 1319059, 1318956, 1318824, 1318834, 1319057, 1318822, 1318830, and 1318823

Section 4OA3: Followup of Events and Notices of Enforcement Discretion

Documentation of Information Sharing - Title: Radiation Meter 1-RM-90-106A

Design Change Notice #66212, Rev. A for Equipment: Various/System 65 (Emergency Gas

Treatment System) to revise SDD N3-65-4001 to Incorporate Test Requirements,

dated: 2/11/2016

CR 11430756 Level 2 Evaluation Action 007 dated: 07/15/2016

Past Operability Evaluation Documentation for CR 1143076 signed on 3/10/2016.

Routine WO 117688915, Equipment Description: EH Fluid Display Subpanel, Unit 1 Reactor

Trip. Dated: 3/22/2016.

Level 2 Evaluation - CR Number 1152462, Rev 0 dated 4/26/2016.

NPG Technical Pre-Job Briefing Checklist AEC CR1152462 dated 3/31/2016

TVA Corrective Action 1152462-006 Completed 12/21/2016.

TVA Condition Report 1152462 draft: 03/22/2016 Unit 1 Reactor Trip

Operations Log for 8/17/2017

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