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{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303-1257 | {{#Wiki_filter: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 | Vice President, Nuclear Licensing | ||
Tennessee Valley Authority | Tennessee Valley Authority | ||
1101 Market Street, LP 3D-C | 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 | 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 | 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 | 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. | 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 | |||
The NRC inspectors documented three findings of very low safety significance (Green) in this report which also involved violations of NRC requ | |||
irements. 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, | 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 | 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 | 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. | 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 | 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 | disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the | ||
Watts Bar Nuclear Plant. | 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." | 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, | Sincerely, | ||
/RA/ | /RA/ | ||
Alan Blamey, Chief | Alan Blamey, Chief | ||
Reactor Projects Branch 6 | Reactor Projects Branch 6 | ||
Division of Reactor Projects | Division of Reactor Projects | ||
Docket Nos.: 50-390, 50-391 License Nos.: NPF-90, 96 | |||
Docket Nos.: 50-390, 50-391 | |||
License Nos.: NPF-90, 96 | |||
Enclosure: | Enclosure: | ||
IR 05000390/2017003, 05000391/2017003 w/Attachment: Supplemental Information | IR 05000390/2017003, 05000391/2017003 | ||
w/Attachment: Supplemental Information | |||
cc Distribution via ListServ | 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 | 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 | Enclosure U.S. NUCLEAR REGULATORY COMMISSION | ||
REGION II | |||
Docket Nos.: 50-390, 50-391 | Docket Nos.: 50-390, 50-391 | ||
License Nos.: NPF-90, NPF-96 | License Nos.: NPF-90, NPF-96 | ||
Report No.: 05000390/2017003, 05000391/2017003 | Report No.: 05000390/2017003, 05000391/2017003 | ||
Licensee: Tennessee Valley Authority (TVA) | |||
Facility: Watts Bar Nuclear Plant, Units 1 and 2 | Facility: Watts Bar Nuclear Plant, Units 1 and 2 | ||
Location: Spring City, TN 37381 | Location: Spring City, TN 37381 | ||
Dates: July 1 through September 30, 2017 | Dates: July 1 through September 30, 2017 | ||
Inspectors: J. Nadel, Senior Resident Inspector | Inspectors: J. Nadel, Senior Resident Inspector | ||
J. Hamman, Resident Inspector | J. Hamman, Resident Inspector | ||
Line 71: | Line 103: | ||
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 | 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 | C. Rapp, Senior Project Engineer | ||
R. Taylor, Senior Project Inspector B. Davis, Senior Construction Inspector | 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 | 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) | 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 | 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 NRC's Enforcement Policy, dated November 1, 2016. The NRC's program for overseeing | the NRC's Enforcement Policy, dated November 1, 2016. The NRC's 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 | 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. | ||
steps. This violation was documented in the licensee's 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 | |||
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 licensee's 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 | removal capability of the ERCW and component cooling systems (CCS) during a loss of | ||
coolant accident (LOCA). The finding was | coolant accident (LOCA). The finding was det | ||
ermined 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 | 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 | 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 | 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 licensee's immediate corrective actions included revising both procedures to add the | 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 licensee's immediate corrective actions included revising both procedures to add the | ||
required steps. This violation was documented in the licensee's CAP as CR 1318176. | required steps. This violation was documented in the licensee's 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) | 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 | 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 | 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 | 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) | critical aspect of the required procedure changes associated with design change notice | ||
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 | 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 licensee's immediate corrective | pressurizer power operated relief valve (PORV). The licensee's immediate corrective | ||
actions included revising the procedure. This violation was documented in the licensee's | actions included revising the procedure. This violation was documented in the licensee's | ||
CAP as CR 1309345. The performance deficiency was more than minor because it affected the Initiating Events | 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 | 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 | objective in that failing to follow procedure 2-SI-68-86 caused a depressurization of the plant | ||
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of the Human Performance area as defined in NRC IMC 0310, because the technicians | 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 | 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 | 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 pl | |||
anned by the licensee hav | |||
e been entered into the licensee's CAP. These violations and the corrective action tracking numbers are listed in | |||
Section 4OA7 of this report. | Section 4OA7 of this report. | ||
REPORT DETAILS Summary of Plant Status | REPORT DETAILS | ||
Summary of Plant Status | |||
Unit 1 operated at 100 percent rated thermal power (RTP) for the entire reporting period. | 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 | 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 | ||
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remained there until power ascension resumed after drain line repairs. Unit 2 reached | 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 | 100 percent RTP on August 8, 2017, and remained there for the remainder of the reporting | ||
period. 1. REACTOR SAFETY | period. 1. REACTOR SAFETY | ||
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity | Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity | ||
1R01 Adverse Weather Protection (71111.01) | |||
External Flood Protection Inspection | |||
External Flood Protection Inspection a. Inspection Scope The inspectors reviewed the licensee's readiness to cope with external flooding. External flooding from a probable maximum precipitation (PMP) or design basis flood | a. Inspection Scope | ||
The inspectors reviewed the licensee's 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 | (DBF) had the potential for internal flooding of a portion of a number of the plant | ||
structures. The inspectors reviewed the feasibility of the licensee's flooding mitigation | structures. The inspectors reviewed the feasibility of the licensee's flooding mitigation | ||
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expected rainfall from Hurricane Irma. This activity constituted one Adverse Weather | expected rainfall from Hurricane Irma. This activity constituted one Adverse Weather | ||
Protection inspection sample, as defined in Inspection Procedure (IP) 71111.01. | Protection inspection sample, as defined in Inspection Procedure (IP) 71111.01. | ||
b. Findings | |||
b. Findings | |||
No findings were identified. | No findings were identified. | ||
5 1R04 Equipment Alignment (71111.04) Partial System Walkdowns a. Inspection Scope | 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 | 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 | redundant trains were returned to service properly. The inspectors reviewed the | ||
Line 138: | Line 204: | ||
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 | 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 | 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 | inspection samples, as defined in IP 71111.04. | ||
1R05 Fire Protection (71111.05AQ) Fire Protection Tours a. Inspection Scope | * 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 | The inspectors conducted tours of the areas important to reactor safety listed below to | ||
verify the licensee's implementation of fire protection requirements as described in: the Fire Protection Program, Nuclear Power Group Standard Programs and Processes | verify the licensee's 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, | (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 | and operational lineup of fire protection sy | ||
stems, 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. | 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. | 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 | 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 | 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 | 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 | evaluators, and to verify that licensee-identified issues were comparable to issues | ||
identified by the inspector. This activity constituted one Observation of Requalification | 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 | Activity inspection sample, as defined in IP 71111.11. | ||
b. Findings | |||
No findings were identified | |||
7 .2 Observation of Operator Performance a. Inspection Scope | 7 .2 Observation of Operator Performance | ||
a. Inspection Scope | |||
Inspectors observed and assessed licensed operator performance in the plant and main | 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 | control room, particularly during periods of heightened activity or risk and where the | ||
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post-maintenance testing, surveillance testing and refueling, and other outage activities | post-maintenance testing, surveillance testing and refueling, and other outage activities | ||
to focus on the following conduct of operations as appropriate. This activity constituted | 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. | one Observation of Operator Performance inspection sample, as defined in IP 71111.11. | ||
1R12 Maintenance Effectiveness (71111.12) a. Inspection Scope The inspectors reviewed the performance-based problem listed below. A review was | * 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 | 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 | 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 | ||
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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 | 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 | 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. | 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: | * Condition Report (CR) 1316520, Unit 2 function 063-B Train A (2A safety injection pump) exceeded performance criteria | ||
1) the effectiveness of the risk | 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 assessm | |||
ents 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 | 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 | 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; | 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 | 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 | Plant Risk Matrix. This activity constituted four Maintenance Risk Assessment inspection samples, as defined in IP 71111.13. | ||
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. | * 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 | 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 | 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 | 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 | ||
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accordance with the significant determination process (SDP). The inspectors verified | 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. | 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 | * 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 | 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 | potentially impacted the operability of the A train header of ERCW and CCS for both | ||
units. | units. | ||
Description. During an NRC review of a | Description. During an NRC review of a lic | ||
ensee-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 | 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 | or B train power. This procedural action would be implemented during a loss of coolant | ||
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December 28, 2015. The licensee removed the inappropriate steps in both procedures. | 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 | 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. | 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 | 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 | 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 | ||
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Chapter 0609, Attachment 4, "Initial Characterization of Findings." Using Appendix A, | 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. | 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 | 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). | 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 | 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 | 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 | ||
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December 28, 2015, procedure 1-E-1, revision 7, was not maintained when the same | 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 licensee's CAP as CR 1331422 and procedures 1-E-1 and 2-E-1 have been revised to remove this step. | procedural step was added. This violation was entered in to the licensee's 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. | 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 | |||
.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 | 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 hours. | 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 hours. | ||
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 | |||
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 ident | |||
ified procedural changes necessary to comply with Unit 1 license amendmen | |||
t 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 | 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 hours of a unit shutdown. One of the | CCS and ERCW pumps to be operable within 48 hours 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 | 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 | LOCA on one unit coincident with a dual unit LOOP, while the other (non-accident) unit | ||
is on RHR shutdown cooling within 48 hours after shutdown and experiences a single | is on RHR shutdown cooling within 48 hours 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 | 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 | 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 | 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 unit's 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 | where MDAFW pumps would be automatically loaded onto the non-accident unit's 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. | 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 | 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 | 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. | 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 | 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 | ||
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MDAFW pump were required and they revised the PDO on July 17, 2017, to include the | MDAFW pump were required and they revised the PDO on July 17, 2017, to include the | ||
necessary procedure changes. | necessary procedure changes. | ||
Analysis: The licensee's 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 | Analysis: The licensee's 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 | Equipment Performance and affected the cornerstone objective in that failure to maintain | ||
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determined that this finding was of very low safety significance (Green) because the | 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 | finding did not represent an actual loss of function of a single train for greater than its TS | ||
allowed outage time. | allowed outage time. | ||
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]. | 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 | Enforcement: TS 5.7.1.1.a, "Procedures," required, in part, that written procedures be established, implemented, and maintained covering activities related to procedures | ||
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the required steps. This violation was entered into the CAP as CR 1318176 and is being | 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 | 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. | 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, | |||
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 | (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 | whether: 1) the effect of testing on the plant had been adequately addressed by control | ||
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NPG-SPP-07.1, On Line Work Management. This activity constituted five Post | NPG-SPP-07.1, On Line Work Management. This activity constituted five Post | ||
Maintenance Testing inspection samples, as defined in IP 71111.19. | 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 | * 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 | 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) | 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 | 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 | repairs. Unit 2 reached 100 percent RTP on August 8, 2017, and remained there for the | ||
remainder of the reporting period. | remainder of the reporting period. | ||
The inspectors observed the licensee's mode changes and startups in order to verify that they were performed in accordance with station procedures and TSs. The inspectors | The inspectors observed the licensee's 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 | 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 | 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. | 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. | ||
1R22 Surveillance Testing (71111.22) a. Inspection Scope The inspectors witnessed the surveillance tests and/or reviewed test data of selected | 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 | 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; | 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 | 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. | 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 | 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 | 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 | 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). | 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 | 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 | 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 | ||
Line 303: | Line 511: | ||
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 | 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, | 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. | |||
properly diagnosed the inadvertent PORV opening, and shut the associated PORV block | |||
valve stopping the pressure decrease. | |||
Analysis: The licensee's 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 | Analysis: The licensee's 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 | the cornerstone objective in that failing to follow procedure 2-SI-68-86 resulted in a | ||
Line 310: | Line 521: | ||
3. The resultant leakage from the open PORV would not have caused the current decay | 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 | 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 | 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 | 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 | 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 | 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 | 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 | Guide 1.33, Section 8, "Procedures for Control of Measuring and Test Equipment and for | ||
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This violation is identified as NCV 05000391/2017003-03, Failure to Follow a | 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 | 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 | |||
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 | 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 | 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 Emer | |||
gency; 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 | evaluators were identifying deficiencies and properly dispositioning performance against | ||
the performance indicator criteria in Nuclear Energy Institute (NEI) 99-02, Regulatory | 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 | 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. | No findings were identified. | ||
4. OTHER ACTIVITIES | |||
4OA1 Performance Indicator (PI) Verification (71151) | 4. OTHER ACTIVITIES | ||
.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. | 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. | This activity constituted two performance indicator samples, as defined in IP 71151. | ||
17 * High Pressure Safety Injection MSPI * RCS leak rate b. Findings | 17 * High Pressure Safety Injection MSPI | ||
No findings were identified. | * RCS leak rate | ||
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 | b. Findings | ||
in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's CAP. This review was accomplished by reviewing daily 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 licensee's corrective | 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 licensee's 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 licensee's corrective | |||
actions intended to address operator performance concerns. The CR was written to | 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, | 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 | adequately considered extent of condition, generic implications, common cause, and | ||
previous occurrences, adequately identified root causes/apparent causes, and identified | previous occurrences, adequately identified root causes/apparent causes, and identified | ||
appropriate and timely corrective actions. The inspector reviewed processes contained in the licensee's 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 | appropriate and timely corrective actions. The inspector reviewed processes contained in the licensee's 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 licensee's HIT program with | with plant operations. The inspector discussed the licensee's HIT program with | ||
members of the licensee's training staff, operation's management, and licensee | members of the licensee's training staff, operation's 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. | 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 | 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 | crews and two crews of evaluators in a training environment. The inspector also | ||
observed classroom training and critiques following each simulator scenario. Many of | observed classroom training and critiques following each simulator scenario. Many of | ||
18 the training activities were also observed by a member of the licensee's corporate training staff, onsite operations management, a contract third party evaluator, and a peer evaluator from another utility. | 18 the training activities were also observed by a member of the licensee's 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 | The training sessions were found to be very intense and operational focused. The | ||
evaluators were extremely critical of | evaluators were extremely critical of cr | ||
ew 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 | Following each discussion, the simulator was reset to the desired point and reran. The | ||
discussions were very interactive. During the discussions, the evaluators constantly | 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 | 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 cr | ||
ew. The inspector also observed critiques following scenarios. | |||
From the inspector's 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 | From the inspector's 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 | ||
Line 364: | Line 612: | ||
controlling the plant. The HIT would also be expected to improve operators' | 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 | 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. | baseline inspection program. No findings were identified. | ||
.3 Semiannual Trend Review a. Inspection Scope | |||
.3 Semiannual Trend Review | |||
a. Inspection Scope | |||
The inspectors performed a review of the licensee's CAP and associated documents to | The inspectors performed a review of the licensee's CAP and associated documents to | ||
identify trends that could indicate the existence of a more significant safety issue. The | 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. | 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 | |||
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 | 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 | 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 | 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 | 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 | ||
Line 380: | Line 635: | ||
coolant system was either being borated or diluted. This required the operating crew to | 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 | 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. | 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 | 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 | 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 | 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 | 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. | 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 | 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 | inspection period that exhibited one of the following issues: inadequate documented | ||
condition details; inadequate screening of | condition details; inadequate screening of conditi | ||
period. The licensee has identified these issues in their CAP. | ons 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 | ||
4OA3 Event Followup (71153) | period. The licensee has identified these issues in their CAP. | ||
.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 | |||
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 | 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 | 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 | ||
Line 400: | Line 663: | ||
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 | 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. | 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 | 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 | |||
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 | 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 | Monitor, and found the mode switch in the "DlFF" position, which was not expected. The | ||
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or condition prohibited by TS per 10 CFR 50.73(a)(2)(i)(B). During the time the monitor | 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 | 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 | indication, reactor coolant system inventory balance) remained available. This LER was | ||
reviewed by the inspectors. No additional fi | |||
ndings or violations of NRC requirements | |||
were identified. | |||
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being performed. Therefore, this condition was reported pursuant to | 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 | 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 | 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. | 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 | 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 | 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 | 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 | 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 | 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 | 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 | CCP was also inoperable. A NCV for this | ||
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 | 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 | 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 | on December 6, 2015, and had less than 100 days of operation since its overhaul. The | ||
Line 437: | Line 718: | ||
prohibited by TS for the 1B-B CCP being inoperable for greater than its allowed outage | 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 | 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 | requirements were identified. | ||
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 | 4OA5 .1 IP 93100 Safety-Conscious Work Environment Issue of Concern Follow Up | ||
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 | 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 empl | |||
oyees 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 | 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 | 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. | 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. | 4OA6 Meetings, including Exit | ||
4OA7 Licensee-Identified Violations The following licensee-identified violations of NRC requirements were determined to be | 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 | of very low safety significance and met the NRC Enforcement Policy criteria for being | ||
dispositioned as NCVs. | dispositioned as NCVs. | ||
* Technical Specification 5.7.1.1.a, "Procedures," required, in part, that written procedures be established, implemented, and maintained covering activities | * 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, | related to procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Regulatory Guide 1.33, Revision 2, Appendix A, Section 6, | ||
Line 458: | Line 751: | ||
result was less that 1E-6/year for Unit 2, which would be a finding of very low | 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 licensee's CAP as | significance (Green). This violation was entered in to the licensee's 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 | |||
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 | 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 | 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- | 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-IS | |||
IV-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 | 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. | 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 | 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 | |||
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 | 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. | 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, | 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 | |||
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 | 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 | 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 | 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, | 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 | 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. | 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 | 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 | 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 | 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 | within 30 days. If this 30 day requirement cannot be met, then the equipment be | ||
Line 483: | Line 792: | ||
surveillance on June 10, 2017, backdraft damper 0-BKD-31-592, equipment listed in | 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 | 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. | automatic suppression system on either side of the fire barrier. This violation was | ||
Attachment SUPPLEMENTARY INFORMATION KEY POINTS OF CONTACT Licensee Personnel | documented as CR 1316058. | ||
Attachment SUPPLEMENTARY INFORMATION | |||
KEY POINTS OF CONTACT | |||
Licensee Personnel | |||
G. Arent, Director, WBN Site Licensing | G. Arent, Director, WBN Site Licensing | ||
M. Casner, Director, Engineering L. Cross, Manager, Electrical Systems T. Detchemendy, Manager, Site Emergency Preparedness | M. Casner, Director, Engineering L. Cross, Manager, Electrical Systems T. Detchemendy, Manager, Site Emergency Preparedness | ||
Line 492: | Line 806: | ||
T. Marshall, Plant Manager | T. Marshall, Plant Manager | ||
C. Rice, Operations Superintendent | C. Rice, Operations Superintendent | ||
P. Simmons, Site Vice President A. White, Senior Manager, Site Quality Assurance | P. Simmons, Site Vice President | ||
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) | A. White, Senior Manager, Site Quality Assurance | ||
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 | LIST OF REPORT ITEMS | ||
Relief Valve (Section 1R22) Closed LER 05000390, 391/2016-010-00 Emergency Diesel Generator Crankcase Pressure Switches Not Analyzed to Withstand the Effects of | Opened and Closed NCV 05000390, 391/2017003-01 Failure to Maintain Procedures for Response to a Loss of Coolant Accident (Section 1R15.1) | ||
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) | NCV 05000391, 390/2017003-02 Inadequate Procedure for Unit Cooldown from Hot | ||
LER 05000390/2016-005-00 Both Trains of Unit 1 Emergency Gas Treatment System inoperable During Unit 2 Testing (Section 4OA3.3) | Standby to Cold Shutdown (Section 1R15.2) | ||
LER 05000390/2016-004-00 Automatic Reactor Trip Due to Actuation of Over Temperature Delta Temperature Bistables (Section | NCV 05000391/2017003-03 Failure to Follow a Surveillance Procedure Led to an Inadvertent Lift of a Pressurizer Power Operated | ||
4OA3.4) LER 05000390/2016-006-00 Undersized Room Cooler Fan Shaft Results in Loss of Centrifugal Charging Pump (Section 4OA3.5) LER | |||
LIST OF DOCUMENTS REVIEWED Section 1R01: Adverse Weather Protection 0-MI-17.003, Flood Mode Preparation Storage Locations and Periodic Inventory, Rev. 0012 | 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 05000 | |||
390/2016-011-00 | |||
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 | 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 | |||
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-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 | |||
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 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-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-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 (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 | 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-0-692-01, Rev. 4 | ||
WBN-Prefire Plan, AUX-0-692-02, Rev. 3 | WBN-Prefire Plan, AUX-0-692-02, Rev. 3 | ||
Drawing 47A472-1 | Drawing 47A472-1 | ||
Drawing 47W866-11 Drawing 47W920-2 Drawing 47A381-20 | |||
Drawing 47W866-11 | |||
Drawing 47W920-2 | |||
Drawing 47A381-20 | |||
Drawing 47A381-127 | Drawing 47A381-127 | ||
WBN Prefire Plan AUX-0-713-01, Rev. 1 | 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-0-713-02, 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 | 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 | 4 Section 1R13: Maintenance Risk Assessments and Emergent Work Control | ||
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 | 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 | 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 | 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 | N3-67-4002, Essential Raw Cooling Water System | ||
1-E-1, Loss of Reactor or Secondary Coolant, Rev. 0009 | 1-E-1, Loss of Reactor or Secondary Coolant, Rev. 0009 | ||
Line 530: | Line 884: | ||
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 | 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 | 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 | |||
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 | 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 | |||
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 | Drawing 1-47W866-1, Rev. 68 | ||
5 Section 1R22: Surveillance Testing WOs 118628055, 116153069 CRs 1322136, 1276914, 1314124, 1314688, 1309892, 1309602, 1309207 | 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 | 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 Controller's 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 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, | - 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 Controller's 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 | dated: 2/11/2016 | ||
CR 11430756 Level 2 Evaluation Action 007 dated: 07/15/2016 | CR 11430756 Level 2 Evaluation Action 007 dated: 07/15/2016 | ||
Line 543: | Line 908: | ||
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. | 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 | 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 | |||
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 | |||
}} | }} |
Revision as of 09:10, 29 June 2018
ML17326A222 | |
Person / Time | |
---|---|
Site: | Watts Bar |
Issue date: | 11/22/2017 |
From: | Blamey A J Reactor Projects Region 2 Branch 6 |
To: | Shea J W 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 requ
irements. 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
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 NRC's Enforcement Policy, dated November 1, 2016. The NRC's 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 licensee's 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 det
ermined 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 licensee's immediate corrective actions included revising both procedures to add the
required steps. This violation was documented in the licensee's 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 licensee's immediate corrective
actions included revising the procedure. This violation was documented in the licensee's
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 pl
anned by the licensee hav
e been entered into the licensee's 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 licensee's 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 licensee's flooding mitigation
plans and design features and verified that they were consistent with the licensee's
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 licensee's 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 licensee's 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 sy
stems, 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 assessm
ents 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 lic
ensee-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 licensee's 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 ident
ified procedural changes necessary to comply with Unit 1 license amendmen
t 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 unit's 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 licensee's 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 licensee's 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 licensee's 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 licensee's 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 Emer
gency; 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 licensee's 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 licensee's 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 licensee's 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 licensee's HIT program with
members of the licensee's training staff, operation's 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 licensee's 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 cr
ew 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 cr
ew. The inspector also observed critiques following scenarios.
From the inspector's 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 licensee's 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 conditi
ons 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 fi
ndings 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 empl
oyees 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 licensee's 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 licensee's 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-IS
IV-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 05000
390/2016-011-00
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
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
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 Controller's 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