ML17326A222
ML17326A222 | |
Person / Time | |
---|---|
Site: | Watts Bar |
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) | |
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
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
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
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.: 50-390, 50-391
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
Enclosure
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
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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
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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.
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- 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
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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.
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
Attachment
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
0-SI-82-2, 8 Hour Diesel Generator AC Power Source Operability Verification, Rev. 0025
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
2-IMI-99.100, EAGLE 21 Rack Diagnostics, Rev. 0002
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