ML17223A116
ML17223A116 | |
Person / Time | |
---|---|
Site: | Comanche Peak |
Issue date: | 08/10/2017 |
From: | Mark Haire NRC/RGN-IV/DRP/RPB-A |
To: | Peters K Vistra Operations Company |
Mark Haire | |
References | |
IR 2017002 | |
Download: ML17223A116 (58) | |
See also: IR 05000445/2017002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 E. LAMAR BLVD
ARLINGTON, TX 76011-4511
August 10, 2017
Ken J. Peters, Senior Vice President
and Chief Nuclear Officer
Vistra Operations Company LLC
P.O. Box 1002
Glen Rose, TX 76043
SUBJECT: COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED
INSPECTION REPORT 05000445/2017002 and 05000446/2017002
Dear Mr. Peters:
On June 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Comanche Peak Nuclear Power Plant, Units 1 and 2. On July 11, 2017, the NRC
inspectors discussed the results of this inspection with you and other members of your staff.
Inspectors documented the results of this inspection in the enclosed inspection report.
NRC inspectors documented five findings of very low safety significance (Green) in this report.
All of these findings involved violations of NRC requirements. Further, inspectors documented a
licensee-identified violation which was 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 NRC Enforcement Policy.
If you contest the 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, DC 20555-0001; with
copies to the Regional Administrator, Region IV; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident
inspector at the Comanche Peak Nuclear Power 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 IV; and the NRC resident inspector at the
Comanche Peak Nuclear Power Plant.
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your
response (if any) will be made available electronically for public inspection in the NRCs Public
Document Room or the NRC's Agencywide Documents Access and Management System
(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html.
K. Peters 2
To the extent possible, your response, if any, should not include any personal privacy,
proprietary, or safeguards information so that it can be made available to the public without
redaction.
Sincerely,
/RA/
Mark S. Haire, Chief
Project Branch A
Division of Reactor Projects
Docket Nos. 5000445 and 5000446
License Nos. NPF-87 and NPF-89
Enclosure:
Inspection Report 05000445/2017002 and
w/ Attachments:
1.) Supplemental Information
2.) Document Request
3.) Licensee Event Report
Detailed Risk Evaluation
K. Peters 3
COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT
05000445/2017002 and 05000446/2017002 - DATED AUGUST 10, 2017
DISTRIBUTION
KKennedy, RA
SMorris, DRA
TPruett, DRP
AVegel, DRS
JClark, DRS
RLantz, DRP
JJosey, DRP
RKumana, DRP
MHaire, DRP
RAlexander, DRP
MKirk, DRP
TSullivan, DRP
SJanicki, DRP
DLackey, DRP
JBowen, RIV/OEDO
KFuller, RC
VDricks, ORA
JWeil, OCA
MWatford, NRR
AMoreno, RIV/OCA
BMaier, RSLO
THipschman, IPAT
EUribe, IPAT
MHerrera, DRMA
RIV ACES
ROP Reports
Electronic Distribution for Comanche Peak Nuclear Power Plant
ADAMS ACCESSION NUMBER: ML17223A116
SUNSI Review ADAMS Non-Sensitive Publicly Available
By: MHaire/dll Yes No Sensitive Non-Publicly Available
OFFICE SRI:DRP/A RI:DRP/A SPE:DRP/A BC:EB1 BC:EB2 BC:OB
NAME JJosey RKumana RAlexander TFarnholtz GWerner VGaddy
SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/ /RA/
JMateychick
for
DATE 08/07/2017 08/04/2017 08/03/17 8/7/2017 08/08/2017 8/4/17
OFFICE BC:PSB2 TL-IPAT BC:DRP/A
NAME HGepford THipschman MHaire
SIGNATURE /RA/ /RA/ /RA/
DATE 08/04/2017 08/03/2017 8/9/17
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 05000445, 05000446
Report: 05000445/2017002 and 05000446/2017002
Licensee: Vistra Operations Company, LLC
Facility: Comanche Peak Nuclear Power Plant, Units 1 and 2
Location: 6322 N. FM-56, Glen Rose, Texas
Dates: April 1 through June 30, 2017
Inspectors: J. Josey, Senior Resident Inspector
R. Kumana, Resident Inspector
S. Janicki, Project Engineer
M. Chambers, Physical Security Inspector
L. Carson II, Sr. Health Physicist
J. ODonnell, CHP, Health Physicist
K. Clayton, Senior Operations Engineer
I. Anchondo, Reactor Inspector
Approved Mark S. Haire
By: Chief, Project Branch A
Division of Reactor Projects
Enclosure
SUMMARY
IR 05000445/2017002; 05000446/2017002; 04/01/2017 - 06/30/2017; Comanche Peak Nuclear
Power Plant; Fire Protection; Fire Protection; Inservice Inspection Activities; Maintenance
Effectiveness; Maintenance Risk Assessments and Emergent Work Control; Follow-up of
Events and Notices of Enforcement Discretion
The inspection activities described in this report were performed between April 1 and
June 30, 2017, by the resident inspectors on site and inspectors from the NRCs Region IV
office. Five findings of very low safety significance (Green) are documented in this report. All of
these findings involved violations of NRC requirements. The significance of inspection findings
is indicated by their color (Green, White, Yellow, or Red), which is determined using Inspection
Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are
determined using Inspection Manual Chapter 0310, Aspects within the Cross-Cutting Areas.
Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement
Policy. The NRCs program for overseeing the safe operation of commercial nuclear power
reactors is described in NUREG-1649, Reactor Oversight Process.
Cornerstone: Mitigating Systems
- Green. The inspectors identified a non-cited violation of Operating Licenses NPF-87 and
NPF-89, License Condition 2.G, Fire Protection Program, for the failure to control transient
combustibles in accordance with the stations fire protection report. Specifically, Fire
Protection Report, Revision 29, Section 5.3.8, Fire Area EO - Control Room, includes
Deviation 3c-1, Control Room Missile Door, which requires, in part, that since the control
room missile door in the west wall is not a 3-hour rated fire door, the area of the turbine deck
within 100 feet of the door is to be void of combustibles. Contrary to this, the licensee
allowed storage of combustible materials in this area without required compensatory
measures. This issue does not represent an immediate safety concern because the
licensee removed the combustible materials upon identification. The licensee entered this
issue into corrective action program as Condition Report CR-2017-5564.
The failure to control transient combustible material in accordance with the approved fire
protection report is a performance deficiency. The performance deficiency was more than
minor and therefore a finding because it was associated with the protection against external
factors attribute of the Mitigating System Cornerstone and adversely affected the
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Specifically, the
introduction of transient combustible materials decreased the external event mitigation for
fire prevention. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial
Characterization of Findings, June 19, 2012, the inspectors determined that the finding
pertained to a failure to adequately implement fire prevention and administrative controls for
transient combustible materials. As a result, the inspectors were directed to Inspection
Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process,
September 20, 2013. The inspectors evaluated the finding through Appendix F,
Attachment 1, Fire Protection Significance Determination Process Worksheet,
September 20, 2013, and determined that the finding was of very low safety consequence
(Green) because the Fire Prevention and Administrative Controls finding would not prevent
the reactor from reaching and maintaining a safe shutdown condition. The finding has a
problem identification and resolution cross-cutting aspect associated with resolution, in that,
the licensee failed to take effective corrective actions to address issues in a timely manner.
2
Specifically, the licensee had previously identified this issue in Condition Report
CR-2014010224 but had failed to take corrective actions to address it [P.3]. (Section 1R05)
- Green. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, that occurred when the licensee failed
on two occasions to perform an adequate operability determination associated with multiple
safety-related pipe supports. Specifically, the operability determination of multiple carbon
steel pipe support clamps exposed to boric acid and a bent sway strut pipe restraint lacked
the engineering rigor necessary to provide a high degree of confidence to support the
operability of the components. Subsequently, the inspectors concluded that the licensee
established reasonable expectation for operability once engineering provided the control
room with further analysis on the degraded conditions, and the new information was
reviewed and accepted. This issue was entered into the licensees corrective action
program as Condition Report CR-2017-05418.
The licensee's failure to perform adequate operability determinations per plant procedures
was a performance deficiency. The performance deficiency was more than minor, and
therefore a finding, because it was associated with the equipment performance attribute of
the Mitigating System cornerstone and adversely affected the cornerstone objective of
ensuring the availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences. Specifically, the licensee: (1) failed to perform the
required corrosion evaluation for a comparison of material wastage against design
dimensions of the pipe support clamps; (2) failed to perform a visual inspection of the
material condition of the pipe support clamps as required by the work order; (3) used
non-seismic design tolerances for the qualification of a seismically qualified strut in the
immediate operability determination; and (4) failed to consider that the bent condition of the
strut occurred after the previously accepted visual examinations on the same pipe support.
All these issues could have resulted in safety-related components failing to perform their
specified safety function during accident conditions. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated October 7, 2016, and
Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for
Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors
determined the finding was of very low safety significance (Green) because the finding: (1) it
was not a design deficiency; (2) did not represent a loss of system and/or function; (3) did
not represent an actual loss of function of at least a single train for longer than its technical
specification allowed outage time; (4) and did not result in the loss of a high safety-
significant non-technical specification train. This finding had a cross-cutting aspect in the
area of problem identification and resolution associated with resolution because the licensee
failed to adequately assess the degraded condition of the pipe supports in a complete and
accurate manner to support a reasonable expectation of operability [P.1]. (Section 1R08)
- Green. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, associated with the licensees failure to assure that design
changes were subject to design control measures commensurate with those applied to the
original design. Specifically, the licensee changed internal components for safety-related,
steam generator atmospheric relief valve booster relays but failed to verify that these new
components could withstand the environment created during a high energy line break. This
issue does not represent an immediate safety concern because the licensee performed an
operability determination which established a reasonable expectation for operability, and
implemented corrective actions to replace the relays with qualified relays. The licensee
3
entered this issue into the corrective action program for resolution as Condition Report CR-
2017-006236.
The failure to ensure that changes to the facility were subject to design control measures
commensurate with those applied to the original design was a performance deficiency. The
performance deficiency was more than minor, and therefore a finding, because it was
associated with the equipment performance attribute of the Mitigating Systems Cornerstone
and affected the associated objective to ensure availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. Using
Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated
October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance
Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening
Questions, the inspectors determined the finding was of very low safety significance
(Green) because the finding: (1) was not a deficiency affecting the design and qualification
of a mitigating structure, system, or component, and did not result in a loss of operability or
functionality, (2) did not represent a loss of system and/or function, (3) did not represent an
actual loss of function of at least a single train for longer than its allowed outage time, or two
separate safety systems out-of-service for longer than their technical specification allowed
outage time, and (4) does not represent an actual loss of function of one or more non-
technical specification trains of equipment designated as high safety-significant for greater
than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in accordance with the licensees maintenance rule program. The inspectors
did not assign a cross-cutting aspect because the performance deficiency was not reflective
of present performance. (Section 1R12)
- Green. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, associated with the licensees failure to assure that applicable
regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified
in the license application, for those structure, systems and components to which this
appendix applies, were correctly translated into specifications, drawings, procedures, and
instructions. Specifically, from initial construction through March 2017, the licensee failed to
fully incorporate applicable moderate energy line break design requirements for fire
protection piping located in the vicinity of the station service water pumps, the latter which
are needed to ensure the capability to shut down the reactor and maintain it in a safe
shutdown condition following a moderate energy line break. This issue does not represent
an immediate safety concern because when the lines were identified the licensee took
prompt action to isolate and depressurize them, and the licensee has implemented plant
modifications. The licensee entered this issue into the corrective action program as
Condition Report CR-2016-008147.
The failure to incorporate applicable design requirements into specifications for moderate
energy line break protection was a performance deficiency. The performance deficiency
was more than minor, and therefore a finding, because it was associated with the design
control attribute of the Mitigating Systems cornerstone and affected the cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Specifically, from initial construction
through March 2017, the licensee failed to fully incorporate applicable design requirements
for components needed to ensure the capability to shut down the reactor and maintain it in a
safe shutdown condition following a moderate energy line break. Using Inspection Manual
Chapter 0609, Attachment 04, Initial Characterization of Findings, dated July 1, 2012, and
Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for
Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated
4
October 7, 2016, the inspectors determined the finding required a detailed risk evaluation
because the finding involved a deficiency affecting the design and qualification of a
mitigating structure, system, or component, and resulted in a loss of operability, and
represented an actual loss of function of at least a single train for longer than its allowed
outage time. A senior reactor analysts from Region IV performed a detailed risk evaluation
and determined that the bounding increase in core damage frequency for this issue was
5.1E-8/year for Unit 1 and 2.9E-10/year for Unit 2, and was therefore of very low safety
significance (Green). The inspectors did not assign a cross-cutting aspect because the
performance deficiency was not reflective of present performance. (Section 4OA3)
Cornerstone: Barrier Integrity
- Green. The inspectors identified a non-cited violation of 10 CFR 50.65(a)(4), Requirements
for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees
failure to adequately assess risk and implement required risk management actions for a
planned maintenance activity. Specifically, the licensee failed to evaluate the risk and
implement required risk management actions associated with disabling a hazard barrier and
breeching the control room envelope when blocking open door E-40A. This issue did not
represent an immediate safety concern because, at the time of identification, the licensee
stopped the activity and secured the door. The licensee entered this issue into the corrective
action program for resolution as Condition Report CR-2017-006019.
The failure to adequately assess the risk and implement required risk management actions
for proposed maintenance activities was a performance deficiency. This performance
deficiency was more than minor, and therefore a finding, because it was associated with the
configuration control attribute of the Barrier Integrity Cornerstone and affected the
associated objective to ensure physical design barriers protect the public from radionuclide
releases caused by accidents or events. Using Inspection Manual Chapter 0609,
Appendix K, Maintenance Risk Assessment and Risk Management Significance
Determination Process, dated May 19, 2005, Flowchart 2, Assessment of Risk
Management Actions, the inspectors determined the need to calculate the risk deficit to
determine the significance of this issue. A senior reactor analyst determined the finding to
have very low safety significance (Green) based on combining the effects of the degradation
of the radiological barrier and tornado missile barrier functions. The analyst performed a
qualitative review of the screening criteria in Manual Chapter 0609, Appendix A, The
Significance Determination Process for Findings At-Power, for the degradation of the
radiological barrier function for the control room and considered the short exposure time
(2.9E-5 years) and the Comanche Peak specific high winds frequency (3.0E-4/year) for the
tornado missile barrier function of the control room to determine that the incremental core
damage probability deficit and the incremental large early release probability deficit were
less than 1E-6 and 1E-7, respectively. The finding has a human performance cross-cutting
aspect associated with procedure adherence, in that operations personnel failed to follow
procedures when allowing door E-40A to be opened. (Section 1R13)
5
PLANT STATUS
Unit 1 began the inspection period at approximately 100 percent power. On May 20, 2017,
unit 1 reduced power to 68 percent for main turbine testing and returned to full power the same
day. Unit 1 operated at full power for the rest of the inspection period.
Unit 2 began the inspection period at approximately 98 percent power. On April 2, 2017, Unit 2
was shut down for a planned refueling outage. Unit 2 returned to full power on May 10, 2017.
On June 2, 2017, unit 2 lowered power to 73 percent due to high turbine generator
temperatures. On June 5, unit 2 was shut down to repair the turbine generator and remained
shut down for the rest of the inspection period.
REPORT DETAILS
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Summer Readiness for Offsite and Alternate AC Power Systems
a. Inspection Scope
On June 26, 2017, the inspectors completed an inspection of the stations off-site and
alternate-ac power systems. The inspectors inspected the material condition of these
systems, including transformers and other switchyard equipment to verify that plant
features and procedures were appropriate for operation and continued availability of off-
site and alternate-ac power systems. The inspectors reviewed outstanding work orders
and open condition reports for these systems. The inspectors walked down the
switchyard to observe the material condition of equipment providing off-site power
sources.
These activities constituted one sample of summer readiness of off-site and alternate-ac
power systems, as defined in Inspection Procedure 71111.01.
b. Findings
No findings were identified.
1R04 Equipment Alignment (71111.04)
.1 Partial Walk-Down
a. Inspection Scope
The inspectors performed partial system walk-downs of the following risk-significant
systems:
- April 25, 2017, Unit 2, component cooling water heat exchanger 2-01
- May 19, 2017, Unit 2, containment spray train B
6
- June 14, 2017, Unit 1, turbine driven auxiliary feedwater pump 1-01
The inspectors reviewed the licensees procedures and system design information to
determine the correct lineup for the systems. They visually verified that critical portions
of the systems or trains were correctly aligned for the existing plant configuration.
These activities constituted three partial system walk-down samples as defined in
Inspection Procedure 71111.04.
b. Findings
No findings were identified.
1R05 Fire Protection (71111.05)
.1 Quarterly Inspection
a. Inspection Scope
The inspectors evaluated the licensees fire protection program for operational status
and material condition. The inspectors focused their inspection on five plant areas
important to safety:
- April 5, 2017, Fire Area SG10a, Unit 1, emergency diesel generator (EDG) room
train A
- April 24, 2017, Fire area EO65, Unit 1 and 2, control room
- April 25, 2017, Fire area TB105g, Unit 1, turbine deck
- April 25, 2017, Fire area TB205g, Unit 2, turbine deck
- May 1, 2017, Fire areas AA26, AA27, AE32, AF33, Unit 1 and 2, component
cooling water pump rooms
For each area, the inspectors evaluated the fire plan against defined hazards and
defense-in-depth features in the licensees fire protection program. The inspectors
evaluated control of transient combustibles and ignition sources, fire detection and
suppression systems, manual firefighting equipment and capability, passive fire
protection features, and compensatory measures for degraded conditions.
These activities constituted five quarterly inspection samples, as defined in Inspection
Procedure 71111.05.
b. Findings
Introduction. The inspectors identified a Green, non-cited violation of Operating
Licenses NPF-87 and NPF-89, License Condition 2.G, Fire Protection Program, for the
failure to control transient combustibles in accordance with the stations fire protection
report.
7
Description. On April 24, 2017, while touring the turbine deck, the inspectors noted a
large amount of combustible material stored within the 100 foot combustible material
exclusion area of door E-40A, control room to turbine deck. The inspectors determined
that the licensee had performed and evaluation of this condition under
EV-TR-2017-003925-1 and determined it to be acceptable. Inspectors questioned this
evaluation because the stations Fire Protection Report, Revision 29, Section 5.3.8, Fire
Area EO - Control Room, contains Deviation 3c-1, Control Room Missile Door, which
requires, in part, that since the control room missile door in the west wall is not a 3-hour
rated fire door, the area of the turbine deck within 100 feet of the door is to be void of
combustibles.
The inspectors reviewed EV-TR-2017-003925-1 and noted that this evaluation
documented that the combustible material exclusion area was created because a fire
rating for door E-40A could not be found (Condition Report CR-2014-010224) and
referenced Calculation 0210-063-0043, Maximum Permissible Fire Loading/Non-Rated
Features Analysis, Revision 14, as a basis for a 3-hour fire rating for the door.
Inspectors reviewed Condition Report CR-2014-010224 and noted that it had been
generated because combustible materials had been stored within 100 feet of door E-40A
without proper controls. Furthermore, this condition report identified that Deviation 3c-1
requires the area of the turbine deck within 100 feet of the door is to be void of
combustible material since door E-40A is not a 3-hour rated fire door. Inspectors also
reviewed Calculation 0210-063-0043 and determined that this calculation was not a
design analyses and used judgement as a basis for a 3-hour fire rating on door E-40A,
which was non-conservative.
Inspectors determined that the licensee had failed to implement the requirements of the
stations approved Fire Protection Report when storing combustible materials within the
combustible material exclusion zone without proper controls. Inspectors informed the
licensee of their concern and the licensee initiated Condition Report CR-2017-005564 to
capture this issue in the stations corrective action program. The licensee also removed
all combustible material from the exclusion area.
During subsequent reviews inspectors noted that the licensee had also initiated
Condition Report CR-2016-004166 because Nuclear Oversight had determined that the
corrective actions for Condition Report CR-2014-010224 were not fully effective.
Condition Report CR-2016-004166 was subsequently closed with no actions taken.
Analyses. The failure to control transient combustible material in accordance with the
approved fire protection report is a performance deficiency. The performance deficiency
was more than minor and therefore a finding because it was associated with the
protection against external factors attribute of the Mitigating System Cornerstone and
adversely affected the cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Specifically, the introduction of transient combustible materials
decreased the external event mitigation for fire prevention. Using NRC Inspection
Manual Chapter 0609, Attachment 4, Initial Characterization of Findings,
June 19, 2012, the inspectors determined that the finding pertained to a failure to
adequately implement fire prevention and administrative controls for transient
combustible materials. As a result, the inspectors were directed to Inspection Manual
Chapter 0609, Appendix F, Fire Protection Significance Determination Process,
September 20, 2013. The inspectors evaluated the finding through Appendix F,
8
Attachment 1, Fire Protection Significance Determination Process Worksheet,
September 20, 2013, and determined that the finding was of very low safety
consequence (Green) because the Fire Prevention and Administrative Controls finding
would not prevent the reactor from reaching and maintaining a safe shutdown condition.
The finding has a problem identification and resolution cross-cutting aspect associated
with resolution, in that, the licensee failed to take effective corrective actions to address
issues in a timely manner. Specifically, the licensee had previously identified this issue
in Condition Report CR-2014-010224 but had failed to take corrective actions to address
it [P.3].
Enforcement. Comanche Peak Unit 1, Operating License NPF-87, Condition 2.G,
Fire Protection, requires, in part, that the licensee implement and maintain in effect all
provisions of the approved fire protection program as described in the Final Safety
Analysis Report through Amendment 78 and as approved in the Safety Evaluation
Report and its supplements through Supplement 24.
Comanche Peak Unit 2, Operating License NPF-89, Condition 2.G, Fire Protection,
requires, in part, that the licensee implement and maintain in effect all provisions of the
approved fire protection program as described in the Final Safety Analysis Report
through Amendment 87 and as approved in the Safety Evaluation Report and its
supplements through Supplement 27.
The stations approved fire protection program includes Fire Protection Report,
Revision 29, Section 5.3.8, Fire Area EO - Control Room, which contains
Deviation 3c-1, Control Room Missile Door, which requires, in part, that since the
control room missile door in the west wall is not a 3-hour rated fire door, the area of the
turbine deck within 100 feet of the door is to be void of combustibles. Contrary to the
above, on April 24, 2017, the licensee failed to maintain the area around the control
room missile door void of combustibles. Specifically, the licensee allowed storage of
combustible materials within 100 feet of the control room missile door in the west wall
without required compensatory measures for the deviation from the Fire Protection
Report. This issue does not represent an immediate safety concern because upon
identification, the licensee removed the combustible materials from the 100 foot
exclusion area. Since this violation was of very low safety significance (Green) and has
been entered into the corrective action program as Condition Report CR-2017-005564,
this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of
the NRC Enforcement Policy. (NCV 05000445/2017002-01; 05000446/2017002-01,
Failure to Control Transient Combustible Material in Accordance with a Fire Protection
Procedure)
1R08 Inservice Inspection Activities (71111.08)
The activities described in subsections 1 through 4 below constitute completion of one
inservice inspection sample, as defined in Inspection Procedure 71111.08.
.1 Non-destructive Examination Activities and Welding Activities
a. Inspection Scope
The inspector directly observed the following nondestructive examinations:
9
EXAMINATION
SYSTEM COMPONENT IDENTIFICATION
TYPE
Reactor Coolant Pressurizer Upper Heat-to-Shell Ultrasonic
(TCX-1-2100-5)
Reactor Coolant Pressurizer Spay Nozzle to Vessel Ultrasonic
(TCX-1-2100-12)
Reactor Coolant Pressurizer Safety Nozzle to Vessel Ultrasonic
(TCX-1-2100-13)
Reactor Vessel Control Rod Drive Mechanism Ultrasonic
Head Penetrations 75, 76, 77, 78
The inspector reviewed records for the following nondestructive examinations:
EXAMINATION
SYSTEM COMPONENT IDENTIFICATION
TYPE
Reactor Coolant Pressurizer Longitude Weld Ultrasonic
(TCX-1-2100-9)
Reactor Coolant Pressurizer Safety Nozzle to Vessel Ultrasonic
(TCX-1-2100-14, TCX-1-2100-15,
TCX-1-2100-16)
Service Water SW-1-132-046-A43R (Strut) Visual (VT-3)
(SW-1-AB-001-H1 during refueling outage
RF5, RF12, and RF14)
During the review and observation of each examination, the inspector observed whether
activities were performed in accordance with the ASME Code requirements and
applicable procedures. The inspector reviewed one indication that was previously
examined, and observed that the licensee evaluated and accepted the indication in
accordance with the ASME Code and/or an NRC approved alternative. The inspector
also reviewed the qualifications of all nondestructive examination technicians performing
the inspections to determine whether they were current.
b. Findings
No findings were identified.
.2 Vessel Upper Head Penetration Inspection Activities
a. Inspection Scope
The inspector reviewed the results of the licensees volumetric inspection of the reactor
vessel head to determine whether the inspection met ASME Code Case N-729-1. The
inspector also reviewed whether the required inspection coverage was achieved and
whether limitations were properly recorded. The inspector reviewed whether the
personnel performing the inspection were certified examiners to their respective
nondestructive examination method.
10
b. Findings
No findings were identified.
.3 Boric Acid Corrosion Control Inspection Activities
a. Inspection Scope
The inspector reviewed implementation of the boric acid corrosion control program for
monitoring degradation of those systems that could be adversely affected by boric acid
corrosion. The inspector reviewed the documentation associated with boric acid
corrosion control walk downs, as specified in Procedure STA-737, Boric Acid Corrosion
Detection and Evaluation, Revision 8. The inspector reviewed whether the visual
inspections emphasized locations where boric acid leaks could cause degradation of
safety-significant components, whether engineering evaluations used corrosion rates
applicable to the affected components and whether engineering properly assessed the
effects of corrosion induced wastage on structural or pressure boundary integrity. The
inspector observed whether corrective actions taken were consistent with the ASME
Code, 10 CFR 50, and Appendix B requirements.
b. Findings
No findings were identified.
.4 Steam Generator Tube Inspection Activities
a. Inspection Scope
The inspector reviewed the steam generator tube eddy current examination scope and
expansion criteria to determine whether these criteria met technical specification
requirements, EPRI guidelines, and commitments made to the NRC. The inspector also
reviewed whether the eddy current examination inspection scope included areas of
degradations that were known to represent potential eddy current test challenges such
as the top of tube sheet, tube support plates, and U-bends. The inspector confirmed
that no repairs were required at the time of the inspection.
Steam Generator Inspection
- The inspector verified that the number and sizes of steam generator tube
flaws/degradation identified were consistent with the licensees previous outage
operational assessment predictions.
- The inspector verified that steam generator eddy current examination scope and
expansion criteria met technical specification requirements.
- The inspector verified that eddy current probes and equipment configurations
used to acquire data from the steam generator tubes were qualified to detect the
known/expected types of steam generator tube degradation in accordance with
Appendix H, Performance Demonstration for Eddy Current Examination of
EPRI Document 1013706.
11
The inspector reviewed the licensees identification of the following tube degradation
mechanisms:
- circumferential primary water stress corrosion cracking (PWSCC) at bulge/over-
expansion locations with the hot leg (HL) tubesheet
- circumferential PWSCC at the HL tubesheet expansion transition
- tube wear at anti-vibration bars, preheater baffle plates, and quatrefoil tube
support plates
- tube wear due to loose parts
The inspector verified that the licensees eddy current examination scope included the
new degradation mechanism, fully enveloped the problem, and has taken appropriate
corrective actions before plant start up. The licensee will now include circumferential
primary water stress corrosion cracking as a new degradation mechanism at the multiple
locations specified above.
b. Findings
No findings were identified.
.5 Identification and Resolution of Problems
a. Inspection Scope
The inspector reviewed 14 condition reports concerning inservice inspection activities to
evaluate whether the licensee implemented appropriate corrective actions for inservice
inspection issues. From this review the inspector concluded that the licensee has an
appropriate threshold for entering inservice inspection issues into the corrective action
program and has procedures that direct a root cause evaluation when necessary. The
licensee also has an effective program for applying industry inservice inspection
operating experience. Specific documents reviewed during this inspection are listed in
the attachment.
b. Findings
Green. The inspector identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, that occurred when the licensee
failed on two occasions to perform an adequate operability determination associated
with safety-related pipe supports. Specifically, the operability determination of multiple
carbon steel pipe support clamps exposed to boric acid and a bent sway strut pipe
restraint, lacked the engineering rigor to provide a high degree of confidence to support
the components operability.
Description. Procedure STI-422.01, Operability Determination and Functionality
Assessment Program, institutes a definition for reasonable expectation of operability in
Section 4.18. In particular, this definition establishes that the supporting basis for the
reasonable expectation of Technical Specification System, Structure, and Component
(SSC) operability should provide a high degree of confidence that the SSC remains
12
operable. This requirement is applicable during both immediate and prompt operability
determinations per procedure Section 6.2.1, and 6.2.2, respectively.
On April 27, 2016, the licensee performed a visual inspection on an ASME Code,
Class 3, sway strut pipe restraint in the service water system. The examination
documented a slight bend along the strut resulting in a failed visual examination. The
immediate operability determination in Condition Report CR-2016-03811, documented
that a slightly bent or bowed strut was acceptable per Site Specification CPES-P-1079,
Specification Field Fabrication and Erection of Pipe Supports. An evaluation under the
prompt operability determination documented that the bent condition was within the
design calculation tolerances and that the strut restraint remained operable. Further
discussions at the time of the inspection established that the licensee believed that the
bent strut was part of the original construction of the pipe support.
The immediate operability determination referenced Step 4.1.2.9 of Site
Specification CPES-P-1079, and established that a slight bend on the strut restraint was
an acceptable condition for operation without further evaluation. Step 4.1.2.9 states:
Seismic Category None supports shall be installed within +/- 5 degrees from the
angle indicated on the Design Drawing. Support rods shall be installed such that
they do not exhibit slack. Slightly bent or bowed rods are acceptable provided
they support the dead load of the pipe.
The inspector determined that Seismic Category None is a designation for
nonsafety-related components that are not seismically qualified and are not required
to have a quality assurance inspection. These requirements are specified in
Table 5.1.1.1, Pipe Support Design Document Classification Matrix, of Site
Specification CPES-P-1079. However, the inspector verified that the strut was classified
as safety-related and was seismically qualified per design documents. Furthermore, the
inspector determined that the prior two visual examinations on the same strut that were
performed as part of the ASME Section XI program had not identified an unacceptable
condition such as a slight bend on the component. Therefore, the inspector determined
that the bent condition did not exist prior to the failed visual examination and that the
licensee had failed to consider these facts in their operability determination.
Consequently, the licensee failed to establish a reasonable expectation of operability.
On May 4, 2016, the licensee identified rust particles under the insulation of the
discharge line to the reactor coolant system in the Chemical and Volume Control
System. Upon removal of the insulation, the affected components exhibited excessive
discoloration in the form of corrosion products and dry boric acid. These components
included three ASME Code, Class 3, carbon steel pipe support clamps. The licensee
proceeded to clean the affected components under Work Order 5268838. A step
included in the work order directed the licensee to perform a material condition
inspection to look for obvious degradation such as pitting or corrosion. As a conclusion,
the licensee determined that the pipe support clamps remained operable because the
cross-sectional properties of the clamps with respect to membrane or bending strength
remain unaffected.
The inspector questioned the level of technical details and assumptions provided in the
operability determination evaluations. Specifically, the inspector noted that statements
such as, the inspected surfaces exhibited minor boric acid staining and material loss,
13
and with minimal material lost given the amount of corrosion product, the corrosion was
of an intermittent nature, were provided without quantifying the condition of the clamps.
The inspector determined that the boric acid evaluation performed per the boric acid
corrosion control program had failed to take into account corrosion rates as required by
Procedure STA-737.01, Boric Acid Corrosion Detection and Evaluation, Rev 0.
Furthermore, the inspector concluded that the visual inspection per Work Order 5268838
had not been performed, but rather signed off by engineering per teleconference
referencing the evaluation provided as part of the operability evaluation. The inspector
concluded that the licensee had not provided the technical rigor required to demonstrate
a reasonable expectation of operability as required by Section 6.2.1 and 6.2.2 of
Procedure STI-422.01.
Analysis. The licensee's failure to perform adequate operability determinations per plant
procedures was a performance deficiency. The performance deficiency was more than
minor, and therefore a finding, because it was associated with the equipment
performance attribute of the Mitigating System cornerstone and adversely affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Specifically, the
licensee: (1) failed to perform the required corrosion evaluation for a comparison of
material wastage against design dimensions of the pipe support clamps; (2) failed to
perform a visual inspection of the material condition of the pipe support clamps as
required by the work order; (3) used non-seismic design tolerances for the qualification
of a seismically qualified strut in the immediate operability determination; and (4) failed
to consider that the bent condition of the strut occurred after the previously accepted
visual examinations on the same pipe support. All these issues could have resulted in
safety-related components failing to perform their specified safety function during
accident conditions. Using Inspection Manual Chapter 0609, Attachment 04, Initial
Characterization of Findings, dated October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power, Exhibit
2, Mitigating Systems Screening Questions, the inspectors determined the finding was
of very low safety significance (Green) because the finding: (1) it was not a design
deficiency; (2) did not represent a loss of system and/or function; (3) did not represent
an actual loss of function of at least a single train for longer than its technical
specification allowed outage time; and (4) did not result in the loss of a high safety-
significant non-technical specification train. This finding had a cross-cutting aspect in
the area of problem identification and resolution associated with resolution because the
licensee failed to adequately assess the degraded condition of both pipe supports in a
complete and accurate manner to support a reasonable expectation of operability [P.1].
Enforcement. Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that activities affecting quality shall be accomplished in
accordance with these instructions, procedures, or drawings. Procedure STI-422.01,
Operability Determination and Functionality Assessment Program, Section 4.18
institutes a definition for reasonable expectation of operability. In particular, this
definition establishes that, the supporting basis for the reasonable expectation of
Technical Specification System, Structure, and Component (SSC) operability should
provide a high degree of confidence that the SSC remains operable. Contrary to the
above, on April 27 and May 4, 2017, the licensee failed to accomplish activities affecting
quality in accordance with the applicable procedure. Specifically, the licensee
discovered multiple degraded conditions of safety-related pipe supports but failed to
14
implement adequate actions that provided a reasonable expectation of operability as
required by Procedure STI-422.01. Since the affected components were located in the
operating Unit, the inspector concluded that the licensee had established reasonable
expectation for operability once engineering had provided the control room with further
analysis on the degraded conditions and the new information was reviewed and
accepted. Because the violation was of very low safety significance and it was entered
into the corrective action program as Condition Report CR-2017-005418, this violation is
being treated as a non-cited violation consistent with Section 2.3.2 of the NRC
Enforcement Policy. (NCV 05000446/2017002-02, Inadequate Operability Evaluation for
Safety Related Pipe Supports)
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
(71111.11)
.1 Review of Licensed Operator Requalification
a. Inspection Scope
On May 31, 2017, the inspectors observed an evaluated simulator scenario performed
by an operating crew. The inspectors assessed the performance of the operators and
the evaluators critique of their performance.
These activities constituted completion of one quarterly licensed operator requalification
program sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
.2 Review of Licensed Operator Performance
a. Inspection Scope
On April 2, 2017, the inspectors observed the performance of on-shift licensed operators
in the Unit 2 main control room. At the time of the observations, the unit was in a period
of heightened activity due to performing a planned shutdown for refueling. The
inspectors observed the operators performance of the unit shutdown, and transition to
In addition, the inspectors assessed the operators adherence to plant procedures,
including the conduct of operations procedure and other operations department policies.
These activities constituted completion of one quarterly licensed operator performance
sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
.3 Biennial Review
The licensed operator requalification program involves two training cycles that are
15
conducted over a 2-year period. In the first cycle, the annual cycle, the operators are
administered an operating test consisting of job performance measures and simulator
scenarios. In the second part of the training cycle, the biennial cycle, operators are
administered an operating test and a comprehensive written examination. For this cycle,
the licensee is completing the second, or biennial cycle, which ends March 31, 2017.
The licensee completed the operating tests in December 2016 and the inspectors
documented the results of the operating test performance and content reviews in
inspection report(s) 05000445/2016004 and 05000446/2016004.
On April 17, 2017, the licensee informed the inspectors of the completed biennial cycle
results for Units 1 and 2 for both the written examinations and the operating tests:
- 11 of 13 crews passed the simulator portion of the operating test
- The 2 crews that were evaluated as unsatisfactory consisted of twelve operators
and one individual failed the simulator scenarios as an individual (not tied to crew
performance)
- 74 of 74 licensed operators passed the job performance measure portion of the
operating test
- Out of 74 operators, 2 retired from the company in December 2016, and 71 of the
remaining 72 licensed operators passed the written examination
The final failure count on any portion of the biennial exams was 14 operators. Using
74 operators as the total number of operators that took any portion of the exam, this
resulted in an 18.9 percent failure rate. This is below the threshold for a finding
(greater than 20 percent failure is a green finding) as described in Inspection Manual
Chapter 0609, "Significance Determination Process," Appendix I, "Licensed Operator
Requalification Significance Determination Process."
The inspectors also reviewed the written examinations for content quality, overlap, and
remediation packages. The individuals that failed any portions of their operating tests
and/or written examinations were remediated, retested, and passed their retake
operating tests and/or written examinations prior to returning to shift.
The inspectors completed one inspection sample of the biennial licensed operator
requalification program.
a. Inspection Scope
b. Findings
No findings were identified.
16
1R12 Maintenance Effectiveness (71111.12)
.1 Routine Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed one instance of degraded performance or condition of safety-
significant structures, systems, and components (SSCs):
- June 8, 2017, Unit 2 component cooling water system
The inspectors reviewed the extent of condition of possible common cause SSC failures
and evaluated the adequacy of the licensees corrective actions. The inspectors
reviewed the licensees work practices to evaluate whether these may have played a
role in the degradation of the SSCs. The inspectors assessed the licensees
characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance
Rule), and verified that the licensee was appropriately tracking degraded performance
and conditions in accordance with the Maintenance Rule.
These activities constituted completion of one maintenance effectiveness sample, as
defined in Inspection Procedure 71111.12.
b. Findings
No findings were identified.
.2 Quality Control
a. Inspection Scope
On April 25, 2017, the inspectors reviewed the licensees quality control activities
through a review of parts installed in the steam generator atmospheric relief valves that
were purchased as commercial-grade parts but were dedicated prior to installation in a
quality-grade application.
These activities constituted completion of one quality control sample, as defined in
Inspection Procedure 71111.12.
b. Findings
Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix
B, Criterion III, Design Control, associated with the licensees failure to assure that
design changes were subject to design control measures commensurate with those
applied to the original design. Specifically, the licensee changed internal components for
safety-related booster relays but failed to verify that these new components could
withstand the environment created during a high energy line break.
Description. While reviewing a commercial grade dedication package for steam
generator atmospheric relief valve booster relays inspectors noted that Condition Report
CR-2017-004594 was written because of identified discrepancies with the currently
installed relay. Specifically, the licensee had determined that in 2005 a design change
had been performed which allowed new relay models to be installed in the plant, and
17
these new model contained elastomers that were not qualified for the environmental
conditions the relays could be exposed to under accident conditions. Inspectors
determined that these changes to the facility were design changes that should have
been subject to design control measures commensurate with those applied to the
original design, but were not.
The inspectors reviewed the licensees evaluation documented in Condition Report
CR-2017-004594. While this evaluation identified that the relays were not qualified for
the environment it focused only on procuring replacement relays. Based on this
inspectors determined that the licensees evaluation was inadequate. Specifically, the
inspectors noted that (1) the operability evaluation performed by the licensee failed to
establish a reasonable expectation of operability for all of the relays, and the licensee
had not initiated a past operability to address the inoperable relay, (2) the licensee had
no actions to correct the identified condition adverse to quality of a design change
implemented without appropriate controls, and (3) the licensee had no actions in place to
ensure that the inadequate relays were controlled as blocked stock to ensure they were
not subsequently re-installed in the facility.
The inspectors informed the licensee of their concerns, and the licensee subsequently
added actions to Condition Report CR-2017-004594 to address these issues. The
additional actions included a revised operability evaluation completed by the licensee
which adequately established a reasonable expectation for operability while the licensee
procured and installed replacement booster relays which fully met the required
environmental qualifications.
Analysis. The failure to ensure that changes to the facility were subject to design control
measures commensurate with those applied to the original design was a performance
deficiency. The performance deficiency was more than minor, and therefore a finding,
because it was associated with the equipment performance attribute of the Mitigating
Systems Cornerstone and affected the associated objective to ensure availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Using Inspection Manual Chapter 0609, Attachment 04,
Initial Characterization of Findings, dated October 7, 2016, and Inspection Manual
Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power,
Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the
finding was of very low safety significance (Green) because the finding: (1) was not a
deficiency affecting the design and qualification of a mitigating structure, system, or
component, and did not result in a loss of operability or functionality, (2) did not
represent a loss of system and/or function, (3) did not represent an actual loss of
function of at least a single train for longer than its allowed outage time, or two separate
safety systems out-of-service for longer than their technical specification allowed outage
time, and (4) does not represent an actual loss of function of one or more non-technical
specification trains of equipment designated as high safety-significant for greater than 24
hours in accordance with the licensees maintenance rule program. The inspectors did
not assign a cross-cutting aspect because the performance deficiency was not reflective
of present performance (i.e., the design change was completed in 2005).
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in
part, that, design changes, including field changes, shall be subject to design control
measures commensurate with those applied to the original design. Contrary to the
above, the volume booster relays in the Unit 1 and Unit 2 atmospheric relief valves,
18
items that are safety-related and to which Appendix B requirements apply, did not have
design changes subject to the same design control measures commensurate with those
applied to the original design. Specifically, between August 2005 and April 25, 2017, the
licensee implemented changes to the relays and failed to control critical materials inside
of the relays. This issue does not represent an immediate safety concern because the
licensee performed an operability determination which established a reasonable
expectation for operability, and implemented corrective actions to replace the relays with
qualified relays. Because this finding is of very low safety significance, and has been
documented in the corrective action program as CR-2017-006236, this violation is being
treated as an NCV consistent with Section 2.3.2.a of the NRC Enforcement Policy.
(05000445/2017002-03; 05000446/2017002-03, Relays not Environmentally Qualified)
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed five risk assessments performed by the licensee prior to
changes in plant configuration and the risk management actions taken by the licensee in
response to elevated risk:
- March 27, 2017, Unit 2, refueling outage 2RF16 defense in depth plan
- April 17, 2017, Unit 2, equipment train A controls during orange risk window due
to train B outage
- May 4, 2017, Unit 1 and Unit 2, controls in place when opening hazard barrier
door E-40A
- May 31, 2017, Unit 2, sequencer maintenance during main turbine automatic
voltage regulator testing
- June 26, 2017, Unit 1, risk management actions during containment spray
maintenance window
The inspectors verified that these risk assessments were performed timely and in
accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant
procedures. The inspectors reviewed the accuracy and completeness of the licensees
risk assessments and verified that the licensee implemented appropriate risk
management actions based on the result of the assessments.
The inspectors also observed portions of the unit 2 polar crane troubleshooting during a
reactor vessel head lift on April 8 and 9, 2017, an emergent work activity that had the
potential to cause an initiating event.
The inspectors verified that the licensee appropriately developed and followed a work
plan for this activity. The inspectors verified that the licensee took precautions to
minimize the impact of the work activity on SSCs.
These activities constituted completion of six maintenance risk assessments and
emergent work control inspection samples, as defined in Inspection Procedure 71111.13.
19
b. Findings
Introduction. The inspectors identified a non-cited violation of 10 CFR 50.65(a)(4),
Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power
Plants, for the licensees failure to adequately assess risk and implement required risk
management actions for a planned maintenance activity. Specifically, the licensee failed
to evaluate the risk and implement required risk management actions associated with
disabling a hazard barrier and breeching the control room envelope when blocking open
door E-40A.
Description. While touring the turbine deck on May 4, 2017, inspectors noted that door
E-40A was blocked open by a pallet jack with no workers in the immediate area of the
door. Inspectors questioned this because this door is a tornado missile boundary and
part of the control room pressure boundary. Inspectors noted that site procedure
ODA-308, LCO Tracking Program, Revision 16, section 13.7.39, Tornado Missile
Shields, contains a preplanned risk assessment and required risk management actions
associated with disabling this barrier. Specifically, for routine entry and exit, the person
opening/closing the door is in administrative control of the door and for all other activities
a dedicated individual stationed at the door in continuous communication with the control
room who could rapidly shut the door is required.
Inspectors went to the control room and engaged the shift manager with their concerns
about the current configuration of door E-40A. During their discussion they determined
that the shift manager had authorized the opening of the door, but had not reviewed and
implemented the required risk management actions specified in the risk assessment
documented in procedure ODA-308. The shift manager subsequently directed that the
activity be stopped, and door E-40A be shut. Condition Report CR-2017-006019 was
generated to capture this issue in the stations corrective action program.
Analysis. The failure to adequately assess the risk and implement required risk
management actions for proposed maintenance activities was a performance deficiency.
This performance deficiency was more than minor, and therefore a finding, because it
was associated with the configuration control attribute of the Barrier Integrity
Cornerstone and affected the associated objective to ensure physical design barriers
protect the public from radionuclide releases caused by accidents or events. Using
Inspection Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk
Management Significance Determination Process, dated May 19, 2005, Flowchart 2,
Assessment of Risk Management Actions, the inspectors determined the need to
calculate the risk deficit to determine the significance of this issue. A senior reactor
analyst determined the finding to have very low safety significance (Green) based on
combining the effects of the degradation of the radiological barrier and tornado missile
barrier functions. The analyst performed a qualitative review of the screening criteria in
Manual Chapter 0609, Appendix A, The Significance Determination Process for
Findings At-Power, for the degradation of the radiological barrier function for the control
room and considered the short exposure time (2.9E-5 years) and the Comanche Peak
specific high winds frequency (3.0E-4/year) for the tornado missile barrier function of the
control room to determine that the incremental core damage probability deficit and the
incremental large early release probability deficit were less than 1E-6 and 1E-7,
respectively. The finding has a human performance cross-cutting aspect associated
with procedure adherence, in that operations personnel failed to follow procedures when
allowing door E-40A to be opened [H.8].
20
Enforcement. Title 10 CFR 50.65(a)(4) states, in part, Before performing maintenance
activities (including, but not limited to surveillance, post-maintenance testing, and
corrective and preventive maintenance), the licensee shall assess and manage the
increase in risk that may result from proposed maintenance activities. Contrary to the
above, prior to performing maintenance activities, the licensee failed to manage the
associated increase in risk from the proposed maintenance activity. Specifically, on
May 4, 2017, the licensee failed to implement required risk management actions
associated with disabling a hazard barrier and breeching the control room envelope
when blocking open door E-40A. This issue did not represent an immediate safety
concern because, at the time of identification, the licensee stopped the activity and
secured the door. Since this violation was of very low safety significance (Green) and
has been entered into the corrective action program as Condition Report CR-2017-
006019, this violation is being treated as a non-cited violation consistent with Section
2.3.2.a of the NRC Enforcement Policy. (NCV 05000445/2017002-04;
05000446/2017002-04, Failure to Adequately Assess Risk and Implement Risk
Management Actions for Proposed Maintenance.)
1R15 Operability Determinations and Functionality Assessments (71111.15)
a. Inspection Scope
The inspectors reviewed seven operability determinations that the licensee performed
for degraded or nonconforming SSCs:
- April 7, 2017, Unit 2, CR-2017-004391 negative pressure boundary door
degraded window
- April 13, 2017, Unit 2, CR-2017-004737 2-02 reactor coolant pump bolting issue
- April 20, 2017, Unit 1 and Unit 2, CR-2017-004594 steam generator atmospheric
relief valve booster relays contain unqualified material for environmental
qualification
- April 28, 2017, Unit 2, CR 2017-005384, residual heat removal pump
comprehensive operability test flow oscillations
- May 4, 2017, Unit 2, CR-2017-005101, EDG turbocharger wall thickness below
design minimum
- May 5, 2017, Unit 2, IR-2017-006042 turbine driven auxiliary feedwater pump
exceeded response time acceptance criteria in surveillance procedure
- May 18, 2017, Unit 2, IR-2017-006454 oil leak on chiller X-05
The inspectors reviewed the timeliness and technical adequacy of the licensees
evaluations. Where the licensee determined the degraded SSC to be operable or
functional, the inspectors verified that the licensees compensatory measures were
appropriate to provide reasonable assurance of operability or functionality. The
inspectors verified that the licensee had considered the effect of other degraded
conditions on the operability or functionality of the degraded SSC.
21
These activities constituted completion of seven operability and functionality review
samples as defined in Inspection Procedure 71111.15.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed five post-maintenance testing activities that affected risk-
significant SSCs:
- May 8, 2017, Unit 2, train A main steam line isolation and response time testing
following valve actuator adjustment
- May 9, 2017, Unit 2, train A slave relay testing
- May 11, 2017, Unit 2, turbine driven auxiliary feedwater pump run following
maintenance
- May 19, 2017, Unit 2, diesel generator 2-01 post maintenance re-torques
- June 15, 2017, Unit 1, turbine driven auxiliary feedwater pump following
replacement of sentinel valve
The inspectors reviewed licensing- and design-basis documents for the SSCs and the
maintenance and post-maintenance test procedures. The inspectors observed the
performance of the post-maintenance tests to verify that the licensee performed the tests
in accordance with approved procedures, satisfied the established acceptance criteria,
and restored the operability of the affected SSCs.
These activities constituted completion of five post-maintenance testing inspection
samples, as defined in Inspection Procedure 71111.19.
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities (71111.20)
a. Inspection Scope
During the stations refueling outage that concluded on May 8, 2017, the inspectors
evaluated the licensees outage activities. The inspectors verified that the licensee
considered risk in developing and implementing the outage plan, appropriately managed
personnel fatigue, and developed mitigation strategies for losses of key safety functions.
This verification included the following:
22
- Review of the licensees outage plan prior to the outage
- Review and verification of the licensees fatigue management activities
- Monitoring of shut-down and cool-down activities
- Verification that the licensee maintained defense-in-depth during outage activities
- Observation and review of reduced-inventory and mid-loop activities
- Observation and review of fuel handling activities
- Monitoring of heat-up and startup activities
These activities constituted completion of one refueling outage sample, as defined in
Inspection Procedure 71111.20.
b. Findings
No findings were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors observed seven risk-significant surveillance tests and reviewed test
results to verify that these tests adequately demonstrated that the SSCs were capable of
performing their safety functions:
In-service tests:
- April 17, 2017, Unit 2, residual heat removal pump 2-02 testing
Containment isolation valve surveillance tests:
- May 8, 2017, Unit 2, train A main steam line isolation and response time testing
Other surveillance tests:
- April 12, 2017, Unit 2, train B integrated test sequence testing
- April 18, 2017, Unit 2, reactor coolant pump flow transmitter testing
- April 19, 2017, Unit 2, turbine driven auxiliary feedwater pump testing
- May 19, 2017, Unit 2, train A containment spray pump testing
- May 22, 2017, Unit 2, train B reactor trip breaker testing
The inspectors verified that these tests met technical specification requirements, that the
licensee performed the tests in accordance with their procedures, and that the results of
the test satisfied appropriate acceptance criteria. The inspectors verified that the
licensee restored the operability of the affected SSCs following testing.
23
These activities constituted completion of seven surveillance testing inspection samples,
as defined in Inspection Procedure 71111.22.
b. Findings
No findings were identified.
2. RADIATION SAFETY
Cornerstones: Public Radiation Safety and Occupational Radiation Safety
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)
a. Inspection Scope
The inspectors evaluated the licensees performance in assessing the radiological
hazards in the workplace associated with licensed activities. The inspectors assessed
the licensees implementation of appropriate radiation monitoring and exposure control
measures for both individual and collective exposures. During the inspection, the
inspectors interviewed licensee personnel, walked down various areas in the plant,
performed independent radiation dose rate measurements, and observed postings and
physical controls. The inspectors reviewed licensee performance in the following areas:
- Radiological hazard assessment, including a review of the plants radiological
source terms and associated radiological hazards. The inspectors also reviewed
the licensees radiological survey program to determine whether radiological
hazards were properly identified for routine and non-routine activities and
assessed for changes in plant operations.
- Instructions to workers including radiation work permit requirements and
restrictions, actions for electronic dosimeter alarms, changing radiological
conditions, and radioactive material container labeling.
- Contamination and radioactive material control, including release of potentially
contaminated material from the radiologically controlled area, radiological survey
performance, radiation instrument sensitivities, material control and release
criteria, and control and accountability of sealed radioactive sources.
- Radiological hazards control and work coverage. During walk-downs of the
facility and job performance observations, the inspectors evaluated ambient
radiological conditions, radiological postings, adequacy of radiological controls,
radiation protection job coverage, and contamination controls. The inspectors
also evaluated dosimetry selection and placement as well as the use of
dosimetry in areas with significant dose rate gradients. The inspectors examined
the licensees controls for items stored in the spent fuel pool and evaluated
airborne radioactivity controls and monitoring.
- High radiation area and very high radiation area controls. During plant walk-
downs, the inspectors verified the adequacy of posting and physical controls,
including areas of the plant with the potential to become risk-significant high
radiation areas.
24
- Radiation worker performance and radiation protection technician proficiency
with respect to radiation protection work requirements. The inspectors
determined if workers were aware of significant radiological conditions in their
workplace, radiation work permit controls/limits in place, and electronic dosimeter
dose and dose rate set points. The inspectors observed radiation protection
technician job performance, including the performance of radiation surveys.
- Problem identification and resolution for radiological hazard assessment and
exposure controls. The inspectors reviewed audits, self-assessments, and
corrective action program documents to verify problems were being identified
and properly addressed for resolution.
These activities constituted completion of the seven required samples of radiological
hazard assessment and exposure control program, as defined in Inspection
Procedure 71124.01.
b. Findings
No findings were identified.
2RS3 In-Plant Airborne Radioactivity Control and Mitigation (71124.03)
a. Inspection Scope
The inspectors evaluated whether the licensee controlled in-plant airborne radioactivity
concentrations consistent with as low as reasonably achievable principles and that the
use of respiratory protection devices did not pose an undue risk to the wearer. During
the inspection, the inspectors interviewed licensee personnel, walked down various
areas in the plant, and reviewed licensee performance in the following areas:
- Engineering controls, including the use of permanent and temporary ventilation
systems to control airborne radioactivity. The inspectors evaluated installed
ventilation systems, including review of procedural guidance, verification of
systems used during high-risk activities, and verification of airflow capacity, flow
path, and filter/charcoal unit efficiencies. The inspectors also reviewed the use of
temporary ventilation systems used to support work in contaminated areas, such
as high-efficiency particulate air/charcoal negative pressure units. Additionally,
the inspectors evaluated the licensees airborne monitoring protocols, including
verification that alarms and set points were appropriate.
- Use of respiratory protection devices, including an evaluation of the licensees
respiratory protection program for use, storage, maintenance, and quality
assurance of National Institute for Occupational Safety and Health-certified
equipment, air quality and quantity for supplied-air devices and self-contained
breathing apparatus (SCBA) bottles, qualification and training of personnel, and
user performance.
- Self-contained breathing apparatus for emergency use, including the licensees
capability for refilling and transporting SCBA bottles to and from the control room
and operations support center during emergency conditions, hydrostatic testing
25
of SCBA bottles, status of SCBA staged and ready for use in the plant including
vision correction, mask sizes, etc., SCBA surveillance and maintenance records,
and personnel qualification, training, and readiness.
- Problem identification and resolution for airborne radioactivity control and
mitigation. The inspectors reviewed audits, self-assessments, and corrective
action documents to verify problems were being identified and properly
addressed for resolution.
These activities constituted completion of the four required samples of in-plant
airborne radioactivity control and mitigation program, as defined in Inspection
Procedure 71124.03.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
Security
4OA1 Performance Indicator Verification (71151)
.1 Safety System Functional Failures (MS05)
a. Inspection Scope
For the period of April 1, 2016, through March 31, 2017, the inspectors reviewed
licensee event reports (LERs), maintenance rule evaluations, and other records that
could indicate whether safety system functional failures had occurred. The inspectors
used definitions and guidance contained in Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-
1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to determine
the accuracy of the data reported.
These activities constituted verification of the safety system functional failures
performance indicator for units 1 and 2, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.2 Reactor Coolant System Specific Activity (BI01)
a. Inspection Scope
The inspectors reviewed the licensees reactor coolant system chemistry sample
analyses for the period of April 1, 2016, through March 31, 2017, to verify the accuracy
and completeness of the reported data. The inspectors used definitions and guidance
contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment
26
Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported
data.
These activities constituted verification of the reactor coolant system specific activity
performance indicator for units 1 and 2, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.3 Reactor Coolant System Total Leakage (BI02)
a. Inspection Scope
The inspectors reviewed the licensees records of reactor coolant system total leakage
for the period of April 1, 2016, through March 31, 2017, to verify the accuracy and
completeness of the reported data. The inspectors used definitions and guidance
contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported
data.
These activities constituted verification of the reactor coolant system leakage
performance indicator for units 1 and 2, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.4 Occupational Exposure Control Effectiveness (OR01)
a. Inspection Scope
The inspectors verified that there were no unplanned exposures or losses of radiological
control over locked high radiation areas and very high radiation areas during the period
of June 1, 2016, to March 31, 2017. The inspectors reviewed a sample of radiologically
controlled area exit transactions showing exposures greater than 100 mrem. The
inspectors used definitions and guidance contained in Nuclear Energy Institute
Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7,
to determine the accuracy of the reported data.
These activities constituted verification of the occupational exposure control
effectiveness performance indicator as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
27
.5 Radiological Effluent Technical Specifications (RETS)/Offsite Dose Calculation Manual
(ODCM) Radiological Effluent Occurrences (PR01)
a. Inspection Scope
The inspectors reviewed corrective action program records for liquid or gaseous effluent
releases that occurred between June 1, 2016, and March 31, 2017, and were reported to
the NRC to verify the performance indicator data. The inspectors used definitions and
guidance contained in Nuclear Energy Institute Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of
the reported data.
These activities constituted verification of the RETS/ODCM radiological effluent
occurrences performance indicator as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution (71152)
.1 Routine Review
a. Inspection Scope
Throughout the inspection period, the inspectors performed daily reviews of items
entered into the licensees corrective action program and periodically attended the
licensees condition report screening meetings. The inspectors verified that licensee
personnel were identifying problems at an appropriate threshold and entering these
problems into the corrective action program for resolution. The inspectors verified that
the licensee developed and implemented corrective actions commensurate with the
significance of the problems identified. The inspectors also reviewed the licensees
problem identification and resolution activities during the performance of the other
inspection activities documented in this report.
b. Findings
No findings were identified.
.2 Annual Follow-up of Selected Issues
a. Inspection Scope
The inspectors selected one issue for an in-depth follow-up:
- The inspectors reviewed the licensees corrective action program and associated
documents to identify trends that could indicate the existence of a more
significant safety issue. The inspectors focused on an issue associated with
ambient air temperature limits for starting the stations risk significant alternate
power diesel generators documented in Condition Reports CR-2016-001817 and
CR-2017-002072. The inspectors assessed the licensees problem identification
28
threshold, cause analyses, extent of condition reviews and compensatory
actions. The inspectors verified that the licensee appropriately prioritized the
planned corrective actions and that these actions were adequate to correct the
condition.
These activities constituted completion of one annual follow-up sample as defined in
b. Findings
No findings were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
.1 (Closed) Licensee Event Report 05000445/2016-001-01, Unanalyzed Condition
Involving Potential Moderate Energy Line Break
a. Inspection Scope
On September 13, 2016, based on initial observations by NRC inspectors, the licensee
determined that pressurized fire protection piping in the service water intake structure
was not properly shielded for moderate energy line break protection of service water
components which resulted in inoperability of one train of service water for both Unit 1
and Unit 2.
During extent of condition walk downs conducted on October 6, 2016, October 10, 2016,
November 17, 2016, December 5, 2016, and December 22, 2016, additional piping in
the Unit 1 and Unit 2 safeguards and auxiliary buildings was found to not be shielded
correctly as well, resulting in inoperability of one train of various safety related equipment
for both units. The licensee determined the most likely cause of this event was that the
methodology used to conduct the initial moderate energy line break walk downs was
flawed and allowed some threats to be missed. The licensees corrective actions include
shielding the affected piping, performing a 100 percent walk down of rooms containing
moderate energy line break piping identified for shielding, and revising the systems
interaction program maintenance procedure.
These activities constituted completion of one event follow-up sample, as defined in
b. Findings
Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, associated with the licensees failure to
assure that applicable regulatory requirements and the design bases, as defined in 10
CFR 50.2 and as specified in the license application, for those structure, systems and
components to which this appendix applies, were correctly translated into specifications,
drawings, procedures, and instructions. Specifically, from initial construction through
March 2017, the licensee failed to fully incorporate applicable design requirements for
components needed to ensure the capability to shut down the reactor and maintain it in
a safe shutdown condition following a moderate energy line break.
29
Description. On September 13, 2016, inspectors performed walkdowns in the service
water intake structure and identified a vertical run of unshielded, pressurized fire
protection piping that appeared to pose a moderate energy line break threat to the
service water pumps. Inspectors determined that in the event of a moderate energy line
break crack along any portion of the unshielded piping, the resultant spray had the
potential to impact the function of any one of the four service water pumps. However,
only one train would have been affected during the event due to the physical
configuration/separation relative to the source line and target pumps and/or associated
motor control centers that support pump operation. Inspectors informed the licensee of
their concern.
Engineering personnel performed a subsequent walkdown of the intake structure and
determined that the identified piping was not correctly shielded and operability of the
service water pumps was in question. The licensee took immediate action to isolate and
depressurize the fire protection line in question which addressed the operability concern.
The licensee entered this issue into the station corrective action program as Condition
Report CR-2016-008147 for resolution.
Part of the licensees actions was to perform extent of condition walkdowns for
unshielded moderate energy piping in the safeguards building for Unit 1 and 2. During
the extent of condition walk downs conducted on October 6, 2016, October 10, 2016,
November 17, 2016, December 5, 2016, and December 22, 2016, additional piping in
the Unit 1 and Unit 2 safeguards and auxiliary buildings was found to not be
appropriately shielded against a moderate energy line break, resulting in the inoperability
of various safety related equipment for both units.
- Unit 2 Train B 480 VAC motor control center 2EB2-1 (Unit 2 Train B emergency
core cooling, battery charger, containment spray, and containment isolation valve
equipment)
(Unit 1 Train B safety-related pumps, panels, sequencer, and transformers)
- Unit 1 Train B 480V MCC 1 EB4-1 (Unit 1 Train B safety-related pumps, valves,
fans, battery chargers, and transformers)
fans, battery chargers, and transformer)
fans, battery chargers, and transformers)
In each of these instances the licensee took prompt action to isolate and depressurize
the identified moderate energy piping pending modification. The licensee subsequently
determined that the most probable cause of the issue was the use of a flawed
methodology during the initial moderate energy piping walkdowns conducted in 1989.
The licensee reported this issue to NRC in Event Report 52239, and Licensee Event
Report 16-002-00.
30
Analyses. The failure to incorporate applicable design requirements into specifications
for moderate energy line break protection was a performance deficiency. The
performance deficiency was more than minor, and therefore a finding, because it was
associated with the design control attribute of the Mitigating Systems cornerstone and
affected the cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences.
Specifically, from initial construction through March 2017, the licensee failed to fully
incorporate applicable design requirements for components needed to ensure the
capability to shut down the reactor and maintain it in a safe shutdown condition following
a moderate energy line break. Using Inspection Manual Chapter 0609, Attachment 04,
Initial Characterization of Findings, dated July 1, 2012, and Inspection Manual
Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power,
Exhibit 2, Mitigating Systems Screening Questions, dated October 7, 2016, the
inspectors determined the finding required a detailed risk evaluation because the finding
involved a deficiency affecting the design and qualification of a mitigating structure,
system, or component, and resulted in a loss of operability, and represented an actual
loss of function of at least a single train for longer than its allowed outage time. A senior
reactor analysts from Region IV performed a detailed risk evaluation and determined
that the bounding increase in core damage frequency for this issue was 5.1E-8/year for
Unit 1 and 2.9E-10/year for Unit 2, and was therefore of very low safety significance
(Green). Additional information is included in the detailed risk evaluation in
Attachment 3 of this report. The inspectors did not assign a cross-cutting aspect
because the performance deficiency was not reflective of present performance.
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in
part, that, measures shall be established to assure that applicable regulatory
requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the
license application, for those structures, systems, and components to which this
appendix applies, are correctly translated into specifications, drawings, procedures, and
instructions. Contrary to the above, measures established by the licensee did not
assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those structures, systems, and
components to which this appendix applies, were correctly translated into specifications,
drawings, procedures, and instructions. Specifically, from initial construction through
March 2017, the licensee failed to fully incorporate applicable design requirements for
components needed to ensure the capability to shut down the reactor and maintain it in
a safe shutdown condition following a moderate energy line break. This issue does not
represent an immediate safety concern because when the lines were identified the
licensee took prompt action to isolate and depressurize them, and the licensee has
implemented plant modifications. Since this violation was of very low safety significance
(Green) and has been entered into the corrective action program as Condition Report
CR-2016-008147, this violation is being treated as a non-cited violation consistent with
Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000445/2017002-05;
05000446/2017002-05, Failure to Translate Design Requirements Into the As Built
Facility)
31
4OA6 Meetings, Including Exit
Exit Meeting Summary
On April 14, 2017, the inspectors presented the radiation safety inspection results to
Mr. T. McCool, Site Vice President, and other members of the licensee staff. The licensee
acknowledged the issues presented. The licensee confirmed that any proprietary information
reviewed by the inspectors had been returned or destroyed.
On April 21, 2017, the inspector presented the inservice inspection activities inspection results
to Mr. S. Sewell, Director of Engineering and Regulatory Affairs, and other members of the
licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that
any proprietary information reviewed by the inspector had been returned or destroyed.
On May 4, 2017, the inspectors presented the licensed operator requalification program
inspection results to Mr. J. Ruby, Exam Lead, Licensed Operator Requalification Training, and
other members of the licensee staff. The licensee representatives acknowledged the findings
presented. The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was identified.
On March 27, 2017, the inspectors presented the resident inspector quarterly inspection results
to Mr. K. Peters, Senior Vice President and Chief Nuclear Officer, and other members of the
licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that
any proprietary information reviewed by the inspectors had been returned or destroyed.
32
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
J. Barnette, Consultant, Licensing Technologist
A. Birdett, Engineer, Steam Generator
S. Dixon, Consulting License Analyst, Regulatory Affairs
J. Goodrich, Supervisor, Radiation Protection.
J. Gumnick, Manager, Radiation Protection
R. Knapp, Supervisor, Radiation Protection
T. Hope, Manager, Regulatory Affairs
J. Howard, Engineering, Inservice Inspection
T. McCool, Site Vice President
E. McGurk, Supervisor, Radiation Protection
K. Peters, Senior Vice President and Chief Nuclear Officer
J. Ruby, Exam Lead, Licensed Operator Requalification Training
S. Sewell, Director, Engineering and Regulatory Affairs
J. Taylor, Director, Site Engineering
C. Tran, Manager, Engineering Programs
G. Woods, Supervisor, Radiation Protection
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000445/2017002-01 Failure to Control Transient Combustible Material in Accordance
NCV 05000446/2017002-01 with a Fire Protection Procedure (Section 1R05)
Inadequate Operability Evaluation for Safety-related Pipe
Supports (Section 1R08)05000445/2017002-03
NCV Relays not Environmentally Qualified (Section 1R12)05000446/2017002-03
05000445/2017002-04 Failure to Adequately Assess Risk and Implement Risk
NCV 05000446/2017002-04 Management Actions for Proposed Maintenance (Section 1R13)05000445/2017002-05 Failure to Translate Design Requirements Into the As Built Facility
NCV 05000446/2017002-05 (Section 4OA3)
Closed
05000445-2016-001- Unanalyzed Condition Involving Potential Moderate Energy Line
LER
01 Break (Section 4OA3)
Attachment 1
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
Procedures
Number Title Revision
STA-634 Extreme Temperature Equipment Protection Program 6
Section 1R04: Equipment Alignment
Miscellaneous Documents
Number Title
Guarded Equipment Management Sign Posting Log
Section 1R05: Fire Protection
Calculations
Number Title Revision
0210-063-0043 Maximum Permissible Fire Loading/Non-Rated Features 14
Analysis
Condition Reports
CR-2017-003925 CR-2014-010224 CR-2016-004166 CR-2016-004167
Procedures
Number Title Revision
FPI-403 Fire Preplan Instruction Manual 5
STA-729 Control of Transient Combustibles, Ignition Sources and Fire 11
Watches
Miscellaneous Documents
Number Title
DBD-ME-002
Section 1R08: Inservice Inspection Activities
Procedures
Number Title Revision/
Date
SG-SGMP-17-8 Comanche Peak 2RF16 (April 2017) Steam Generator 0
Degradation Assessment
A1-2
Procedures
Number Title Revision/
Date
STI-422.01 Operability Determination and Functionality Assessment 4
Program
SG-CDME-08-28 Steam Generator Condition Monitoring and Operational July 17,
Assessment for Comanche Peak Unit 2, April 2008 (2RF10) 2008
MRS-SSP-3393 Eddy Current Data Analysis Guidelines for Comanche Peak 0
Unit 2 D5 steam generators
STA-737 Boric Acid Corrosion Detection and Evaluation 8
MRS-TRC-2317 Use of Appendix H and I Qualified Techniques at Comanche 0
Peak 2RF16 Steam Generator Inspection
SG-SGMP-14-9 Steam Generator Condition Monitoring and Operational 0
Assessment for Comanche Peak Unit 2, April 2014 Outage
(2RF14)
WDI-PJF- Reactor Vessel Head Examination Final Report April 2017 0
1316984-FSR-
001
DBD-CS-018 Design Criteria for Pipe Stress and Pipe Supports 11
WDI-SSP-1326 Reactor Vessel Head Penetration Inspection Service 0
Procedure for Comanche Peak Unit 2
WDI-STD-1040 Procedure for Ultrasonic Examination of Reactor Vessel 14
Head Penetrations
TX-ISI-302 Ultrasonic Examination of Austenitic Piping Welds 5
TX-ISI-210 Ultrasonic Examination Procedure of Welds in Ferritic Steel 9
Vessel
TX-ISI-8 VT-1 and VT-3 Visual Examination Procedure 9
CPES-P-1079 Specification Field Fabrication and Erection of Pipe 11
Supports
Reactor Vessel Closure Head Visual Examination 5
Drawings
Number Title Revision
MS-2-001-402- Large Bore Piping Support CP-4
C72S
BRHL-SW-1-AB- Station Service Water CP-5
001
BRP-SW-1-AB- Station Service Water CP-1
001
A1-3
Condition Reports
CR-2017-005066 CR-2017-005109 CR-2017-005222 CR-2016-004050 CR-2016-003811
CR-2016-005566 CR-2016-005600 CR-2016-007429 CR-2015-008795 CR-2015-009112
CR-2015-009115 CR-2015-009180 CR-2015-009181 CR-2015-009272
Work Orders
5264718 5171029 5268838
Section 1R11: Licensed Operator Requalification Program and Licensed Operator
Performance
Miscellaneous Documents
Number/Type Title Date
Written Exams 2017 Exam -Weeks 1-6 April 2017
Sample Plans 2017 Exam -Weeks 1-6 April 2017
ES-601-1 NRC Exam Security Agreement Form March 2017
Condition Reports
IR-2017-003933 TR-2017-003859 TR-2017-002923 TR-2017-001656
TR-2017-000548 TR-2016-010799 TR-2016-000851 TR-2017-001568
Section 1R12: Maintenance Effectiveness
Miscellaneous Documents
Number Title Revision/
Date
Technical Evaluation 94-00367-00-00 March 17,
1994
CJ7239-1 Dedication Plan for Fisher Volume Booster Fischer (CW) 1
P/N CW2625-12-HT
Q1717.0 Nuclear Environmental Test Procedure for Fischer Volume 1
Booster
Condition Reports
CR-2017-004594 CR-2005-000085 CR-2005-003263
A1-4
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Condition Reports
CR-2017-006354 CR-2014-004903 CR-2011-010090 CR-2009-008296
Drawings
Number Title Revision
M2-0249 Flow Diagram Generator Primary Water 18
Miscellaneous Documents
Number Title
EV-IR-2017- Unit 2 ODMI for Primary Water Pump 5 line to vent line
006354-1 weld crack
EV-IR-2017- Evaluation to install temporary tieback support for Primary
006354-2 Water
EV-IR-2017- Maximum crack size before shutdown
006354-3
Work Orders
5444458
Section 1R15: Operability Determinations and Functionality Assessments
Drawings
Number
E2-0064 S2-0910-2-8010A
Procedures
Number Title Revision
OPT-214A Diesel Generator operability test 22
STI-422.01 Operability determinations and functionality assessment 2
program
STA-707 10CFR50.59 and 10CFR72.48 reviews 21
MSM-C0-3346 Emergency Diesel Engine Turbocharger Maintenance 6
INC-214 Installation of electrical conductor seal assemblies 0
A1-5
Miscellaneous Documents
Number Title Revision/
Date
59SC-2017- 50.59 Screening - EDG G90 Elliot Turbocharger - Thin Wall April 17,
000057-01-00 Turbine Casing 2017
VDRT-5427168 Diesel Generator Turbocharger Casing Minimal Wall April 19,
Thickness 2017
EVAL-2005- Evaluation of EDG 2-01 Turbocharger wall thinning April 7, 2005
001433-01-00
VL-04-000971 Vendor Letter - G90 Elliot Turbocharger Thin Wall Turbine April 6, 2004
Case
FDA-2017- U1/U2 Generic use-as-is disposition to address EDG 0
000057-01 Turbocharger wall thinning
Work Orders
5174039 5429766
Section 1R19: Post-Maintenance Testing
Calculations
Number Title Revision
ME-CA- Residual Heat Removal design performance limit for 0
00005476 Inservice Testing
Condition Reports
CR-2017-005384
Procedures
Number Title Revision
OPT-203B Residual Heat Removal System 14
OPT-206B AFW System 22
Miscellaneous Documents
Number Title Date
EV-CR-2017- RHR pump comprehensive pump test flow band evaluation April 21,
005384-1 2017
Work Orders
5171407
A1-6
Section 1R20: Refueling and Other Outage Activities
Condition Reports
CR-2017-004725 CR-2017-004789 CR-2017-004811
Procedures
Number Title Revision
OPT-203B Residual Heat Removal System 14
IPO-002B Plant Startup from Hot Standby 10
NUC-301 Low power physics testing 21
Work Orders
5174286
Section 1R22: Surveillance Testing
Procedures
Number Title Revision
STA-601 Authority for Equipment Operation 17
Section 2RS1: Radiological Hazard Assessment and Exposure Controls
Procedures
Number Title Revision
RPI-115 Alarm Response 9
RPI-212 Radioactive Source Control 13
RPI-213 Survey and Release of Material and Personnel 26
RPI-400 Decontamination Program 21
RPI-509 Personnel Dosimetry Program 16
RPI-602 Radiological Surveillance and Posting 58
RPI-606 Radiation Work and General Access Permits 37
RPI-623 Radiological Briefings 10
RPI-626 Alpha Monitoring Program 8
RPI-700 Sealed Source Leak Testing 13
RPI-802 Performance of Source Checks 23
STA-650 General Health Physics Plan 8
STA-655 Exposure Monitoring Program 22
A1-7
Procedures
Number Title Revision
STA-656 Radiation Work Control 22
STA-660 Control of High Radiation Areas 17
Audits and Self-Assessments
Number Title Date
CR-2016- CPNPP Strategic Self-Assessment Report October
005928 16, 2016
CR-2016- CPNPP Targeted Self-Assessment Report September
005929 15, 2016
Condition Reports
CR-2016-003921 CR-2016-004059 CR-2016-004387 CR-2016-004390 CR-2016-004806
CR-2016-004879 CR-2016-005048 CR-2016-006813 CR-2016-006813 CR-2017-000761
CR-2017-004224 CR-2017-004307 CR-2017-004787
Radiation Work Permits
Number Title Revision
20172100 2RF16 RP Support in Containment 0
20172214 2RF16 Reactor Vessel Annulus BMI, Seal Table Activities, 0
Eddy Current Testing and Containment Close-Out
20172300 2RF16 Secondary Side Steam Generator Activities 0
20172400 2RF16 Primary Side Steam Generator Activities 1
20172600 2RF16 Westinghouse (WEC) Refueling Activities 2
Radiation Surveys
Number Title Date
U-2 RB 825 S/G Platform #s 1, 2, & 3 April 13, 2017
U-2 RB 825 S/G Channel Head Survey Points (EPRI) April 13, 2017
Generator #s 1, 2, 3, & 4.
M-20161101-10 U-2 RB 808 All Rooms 2-154 November 1,
Quarterly Comprehensive 2016
M-20170125-11 U-2 RB 808 All Rooms 2-154 January 25,
Quarterly Comprehensive 2017
M-20170215-17 Aux 842 Valve & Pipe Gallery X-230 February 15,
Trending Routine 2017
M-20170225-1 Aux 832 Piping Area X-213 February 25,
Bi-Weekly 2017
A1-8
Procedures
Number Title Revision
M-20170329-13 Aux 832 Piping Area X-213 March 29, 2017
Post Resin Transfer Flush Survey
M-20170330-19 Aux 842 Valve & Pipe Gallery X-230 March 30, 2017
Post 24 Hour Resin Transfer
Air Sampling Results
Number Title Date
12-Apr-2017- U2 Equipment Hatch 832 April 12, 2017
0005
12-Apr-2017- Unit 2 LTDN HX A/S April 12, 2017
0037
13-Apr-2017- Platform 1 Iodine April 13, 2017
0006
13-Apr-2017- Platform 1 Particulate April 13, 2017
0007
Section 2RS3: In-plant Airborne Radioactivity Control and Mitigation
Procedures
Number Title Revision
ODA-102 Conduct of Operations 27
RPI-888 Calibration of Air Sampling Equipment 4
RPI-902 Issue and Control of Respiratory Protection 17
RPI-903 Cleaning, Decontamination, & Disinfecting of Respiratory 14
Protection Equipment
RPI-904 Accountability & Inspection of Respiratory Protection 13
Equipment (Maintenance & Repair)
SOP-817A Safeguards Ventilation Systems 10
SOP-816 Primary Plant Ventilation Systems 13
SOP-801A Containment Ventilation 14
SOP-802 Control Room Ventilation 13
STA-659 Respiratory Protection Program 17
STI-659.1 Use of Respiratory Protection 0
STI-704.1 Processing Respiratory Health Screens 1
STA-704 Respiratory Health Screen Program 17
A1-9
Procedures
Number Title Revision
TRA-103 Respiratory Protection Training 11
Audits and Self-Assessments
Number Title Date
CR-2016- CPNPP Strategic Self-Assessment Report October 16,
005928 2016
CR-2016- CPNPP Targeted Self-Assessment Report September 15,
005929 2016
AI-TR-2017- 1 CRE habitability targeted self-assessment January 27,
000435 2017
Condition Reports
CR-2016-007561 CR-2016-010369 CR-2016-008843 CR-2016-002439 CR-2017-001125
CR-2016-006015
Miscellaneous Documents
Title Date
SCBA Qualification Records March 31, 2017
SCBA Qualification Records Ops & Fire Brigade March 13, 2017
SCBA Inspection Records December 16,
2016
SCBA Inspection Records October 15, 2016
CPNPP Respirator Model Types March 13, 2017
Section 4OA2: Problem Identification and Resolution
Condition Reports
CR-2016-001817 CR-2017-002072
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Condition Reports
CR-2016-008147
A1-10
The following items are requested for the
Occupational Radiation Safety Inspection
Comanche Peak Nuclear Power Plant
Inspection Dates April 10 - 17, 2017
Integrated Report 2017002
Inspection areas are listed in the attachments below.
Please provide the requested information on or before April 3, 2017.
Please submit this information using the same lettering system as below. For example, all
contacts and phone numbers for Inspection Procedure 71124.01 should be in a file/folder titled
1- A, applicable organization charts in file/folder 1- B, etc.
If information is placed on ims.certrec.com, please ensure the inspection exit date entered is at
least 30 days later than the onsite inspection dates, so the inspectors will have access to the
information while writing the report.
In addition to the corrective action document lists provided for each inspection procedure listed
below, please provide updated lists of corrective action documents at the entrance meeting.
The dates for these lists should range from the end dates of the original lists to the day of the
entrance meeting.
If more than one inspection procedure is to be conducted and the information requests appear
to be redundant, there is no need to provide duplicate copies. Enter a note explaining in which
file the information can be found.
If you have any questions or comments, please contact Louis C. Carson II at (817) 200-1221
or Louis.Carson@nrc.gov.
PAPERWORK REDUCTION ACT STATEMENT
This letter does not contain new or amended information collection requirements subject
to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). Existing information
collection requirements were approved by the Office of Management and Budget,
control number 3150-0011.
Attachment 2
1. Radiological Hazard Assessment and Exposure Controls (71124.01) and
Performance Indicator Verification (71151)
Date of Last Inspection: May 13, 2016
A. List of contacts and telephone numbers for the Radiation Protection Organization Staff
and Technicians
B. Applicable organization charts
C. ALL radiation protection related licensee assessments and audits, all independent or
third party radiation protection related assessments and audits, all radiation protection
related self-assessments, and all radiation safety related LERs, including but not limited
to radiation monitoring instrumentation and radioactive effluents, releases and / or spills,
written since May 2016.
D. Procedure indexes for the radiation protection procedures
E. Please provide specific procedures related to the following areas noted below.
Additional Specific Procedures may be requested by number after the inspector reviews
the procedure indexes.
1. Radiation Protection Program Description
2. Radiation Protection Conduct of Operations
3. Personnel Dosimetry Program
4. Posting of Radiological Areas
5. High Radiation Area Controls
6. RCA Access Controls and Radiation Worker Instructions
7. Conduct of Radiological Surveys
8. Radioactive Source Inventory and Control
9. Declared Pregnant Worker Program
F. List of corrective action documents (including corporate and sub-tiered systems) since
May 2016.
a. Initiated by the radiation protection organization
b. Assigned to the radiation protection organization
NOTE: The lists should indicate the significance level of each issue and the search
criteria used. Please provide in document formats which are searchable so that
the inspector can perform word searches.
If not covered above, a summary of corrective action documents since May 2016
involving unmonitored releases, unplanned releases, or releases in which any dose limit
or administrative dose limit was exceeded (for Public Radiation Safety Performance
Indicator verification in accordance with IP 71151)
Additionally, a copy of ALL radiation protection AND chemistry department root cause
evaluations, apparent cause evaluation, and condition evaluations performed since May
2016.
G. List of radiologically significant work activities scheduled to be conducted during the
inspection period (If the inspection is scheduled during an outage, please also include a
list of work activities greater than 1 rem, scheduled during the outage with the dose
estimate for the work activity.)
H. List of active radiation work permits
A2-2
I. Radioactive source inventory list
a. All radioactive sources that are required to be leak tested
b. All radioactive sources that meet the 10 CFR Part 20, Appendix E, Category 2
and above threshold. Please indicate the radioisotope, initial and current activity
(w/assay date), and storage location for each applicable source.
J. The last two leak test results for the radioactive sources inventoried and required to be
leak tested. If applicable, specifically provide a list of all radioactive source(s) that have
failed its leak test within the last two years
K. A current listing of any non-fuel items stored within your pools, and if available, their
appropriate dose rates (Contact / @ 30cm)
L. Computer printout of radiological controlled area entries greater than 100 millirem since
the previous inspection to the current inspection entrance date. The printout should
include the date of entry, some form of worker identification, the radiation work permit
used by the worker, dose accrued by the worker, and the electronic dosimeter dose
alarm set-point used during the entry (for Occupational Radiation Safety Performance
Indicator verification in accordance with IP 71151).
3. In-Plant Airborne Radioactivity Control and Mitigation (71124.03)
Date of Last Inspection: October 2015
A. List of contacts and telephone numbers for the following areas:
1. Respiratory Protection Program
2. Self-contained breathing apparatus
B. Applicable organization charts
C. Copies of audits, self-assessments, vendor or NUPIC audits for contractor support
(SCBA), and LERs, written since date of last inspection related to:
1. Installed air filtration systems
2. Self-contained breathing apparatuses
D. Procedure index for:
1. Use and operation of continuous air monitors
2. Use and operation of temporary air filtration units
3. Respiratory protection
E. Please provide specific procedures related to the following areas noted below.
Additional Specific Procedures may be requested by number after the inspector reviews
the procedure indexes.
1. Respiratory protection program
2. Use of self-contained breathing apparatuses
3. Air quality testing for SCBAs
4. Use of installed plant systems, such as containment purge, spent fuel pool
ventilation, and auxiliary building ventilation
F. A summary list of corrective action documents (including corporate and sub-tiered
systems) written since date of last inspection, related to the Airborne Monitoring program
including since October 2015
A2-3
1. Continuous air monitors
2. Self-contained breathing apparatuses
3. Respiratory protection program
NOTE: The lists should indicate the significance level of each issue and the search
criteria used. Please provide in document formats which are searchable so that
the inspector can perform word searches.
G. List of SCBA qualified personnel - reactor operators and emergency response personnel
H. Inspection records for self-contained breathing apparatuses (SCBAs) staged in the plant
for use since date of last inspection: October 2015
I. SCBA training and qualification records for control room operators, shift supervisors,
STAs, and OSC personnel for the last year.
A selection of personnel may be asked to demonstrate proficiency in donning, doffing,
and performance of functionality check for respiratory devices
J. List of respirators (available for use) by type (APR, SCBA, PAPR, etc.), manufacturer,
and model.
A2-4
PAPERWORK REDUCTION ACT STATEMENT
This letter does not contain new or amended information collection requirements subject to
the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). Existing information
collection requirements were approved by the Office of Management and Budget, Control
Number 31500011. The NRC may not conduct or sponsor, and a person is not required to
respond to, a request for information or an information collection requirement unless the
requesting document displays a currently valid Office of Management and Budget control
number.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRCs
document system (ADAMS). ADAMS is accessible from the NRC web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Information Request
February 24, 2017
Notification of Inspection and Request for Information
Comanche Peak Unit 2
NRC Inspection Report 05000446/2017002
INSERVICE INSPECTION DOCUMENT REQUEST
Inspection Dates: April 10 - 21, 2017
Inspection Procedures: IP 71111.08 Inservice Inspection (ISI) Activities
Inspector: Isaac Anchondo
A. Information Requested for the In-Office Preparation Week
The following information should be sent to the Region IV office in hard copy or electronic
format (ims.certrec.com preferred), in care of Isaac Anchondo, by March 17, 2017, to facilitate
the selection of specific items that will be reviewed during the onsite inspection week. The
inspector will select specific items from the information requested below and then request from
your staff additional documents needed during the onsite inspection week (Section B of this
enclosure). We ask that the specific items selected from the lists be available and ready for
review on the first day of inspection. Please provide requested documentation electronically if
possible. If requested documents are large and only hard copy formats are available, please
inform the inspector(s), and provide subject documentation during the first day of the onsite
inspection.
If you have any questions regarding this information request, please call the inspector as soon
as possible.
Based on the current schedule, on April 10, 2017, reactor inspector from the Nuclear Regulatory
Commissions (NRC) Region IV office will perform the baseline inservice inspection at
Comanche Peak, Unit 2, using NRC Inspection Procedure 71111.08, Inservice Inspection
A2-5
Activities. Experience has shown that this inspection is a resource intensive inspection both for
the NRC inspector and your staff. The date of this inspection may change dependent on the
outage schedule you provide. In order to minimize the impact to your onsite resources and to
ensure a productive inspection, we have enclosed a request for documents needed for this
inspection. These documents have been divided into two groups. The first group (Section A of
the enclosure) identified information to be provided prior to the inspection to ensure that the
inspector are adequately prepared. The second group (Section B of the enclosure) identifies
the information the inspector will need upon arrival at the site. It is important that all of these
documents are up to date and complete in order to minimize the number of additional
documents requested during the preparation and/or the onsite portions of the inspection.
We have discussed the schedule for these inspection activities with your staff and understand
that our regulatory contact for this inspection will be Mr. James Barnette of your licensing
organization. The tentative inspection schedule is as follows:
Preparation week: April 3, 2017
Onsite weeks: April 10 - 21, 2017
Our inspection dates are subject to change based on your updated schedule of outage
activities. If there are any questions about this inspection or the material requested, please
contact the lead inspector Isaac Anchondo at (817) 200-1152 (isaac.anchondo@nrc.gov).
A.1 ISI/Welding Programs and Schedule Information
a) A detailed schedule (including preliminary dates) of:
i. Nondestructive examinations planned for ASME Code Class Components
performed as part of your ASME Section XI, risk informed (if applicable),
and augmented inservice inspection programs during the upcoming outage.
ii. Examinations planned for Alloy 82/182/600 components that are not
included in the Section XI scope (If applicable)
iii. Examinations planned as part of your boric acid corrosion control program
(Mode 3 walkdowns, bolted connection walkdowns, etc.)
iv. Welding activities that are scheduled to be completed during the upcoming
outage (ASME Class 1, 2, or 3 structures, systems, or components)
b) A copy of ASME Section XI Code Relief Requests and associated NRC safety
evaluations applicable to the examinations identified above.
i. A list of ASME Code Cases currently being used to include the system
and/or component the Code Case is being applied to.
c) A list of nondestructive examination reports which have identified recordable or
rejectable indications on any ASME Code Class components since the beginning of
the last refueling outage. This should include the previousSection XI pressure test(s)
conducted during start up and any evaluations associated with the results of the
pressure tests.
A2-6
d) A list including a brief description (e.g., system, code class, weld category,
nondestructive examination performed) associated with the repair/replacement
activities of any ASME Code Class component since the beginning of the last outage
and/or planned this refueling outage.
e) If reactor vessel weld examinations required by the ASME Code are scheduled to
occur during the upcoming outage, provide a detailed description of the welds to be
examined and the extent of the planned examination. Please also provide reference
numbers for applicable procedures that will be used to conduct these examinations.
f) Copy of any 10 CFR Part 21 reports applicable to structures, systems, or components
within the scope of Section XI of the ASME Code that have been identified since the
beginning of the last refueling outage.
g) A list of any temporary noncode repairs in service (e.g., pinhole leaks).
h) Please provide copies of the most recent self-assessments for the inservice
inspection, welding, and Alloy 600 programs
A.2 Reactor Pressure Vessel Head
Provide a detailed scope of the planned bare metal visual examinations (e.g., volume
coverage, limitations, etc.) of the vessel upper head penetrations and/or any nonvisual
nondestructive examination of the reactor vessel head including the examination
procedures to be used.
i. Provide the records recording the extent of inspection for each penetration
nozzle including documents which resolved interference or masking issues
that confirm that the extent of examination meets 10 CFR
50.55a(g)(6)(ii)(D).
ii. Provide records that demonstrate that a volumetric or surface leakage path
examination assessment was performed.
Copy of current calculations for EDY, and RIY as defined in Code Case N-729-1 that establish
the volumetric and visual inspection frequency for the reactor vessel head and J-groove welds.
A.3 Boric Acid Corrosion Control Program
a) Copy of the procedures that govern the scope, equipment and implementation of the
inspections required to identify boric acid leakage and the procedures for boric acid
leakage/corrosion evaluation.
b) Please provide a list of leaks (including code class of the components) that have been
identified since the last refueling outage and associated corrective action
documentation. If during the last cycle, the unit was shut down, please provide
documentation of containment walkdown inspections performed as part of the boric
acid corrosion control program.
A2-7
A.4 Steam Generator Tube Inspections
a) A detailed schedule of:
i. Steam generator tube inspection, data analyses, and repair activities for
the upcoming outage (if occurring).
ii. Steam generator secondary side inspection activities for the upcoming
outage (if occurring).
b) Copy of SG history documentation given to vendors performing eddy current (ET)
testing of the SGs during the upcoming outage.
c) Copy of procedure containing screening criteria used for selecting tubes for in-situ
pressure testing and the procedure to be used for in-situ pressure testing.
d) Copy of previous outage SG tube operational assessment. Also include a copy of the
following documents as they become available:
i. Degradation assessment
ii. Condition monitoring assessment
e) Copy of the document defining the planned SG ET scope (e.g., 100 percent of
unrepaired tubes with bobbin probe and 20 percent sample of hot leg expansion
transition regions with rotating probe) and identify the scope expansion criteria, which
will be applied. Also identify and describe any deviations in this scope or expansion
criteria from the EPRI Guidelines.
f) Copy of the document describing the ET acquisition equipment to be applied including
ET probe types. Also identify the extent of planned tube examination coverage with
each probe type (e.g. rotating probe -0.080 inches, 0.115 inches pancake coils and
mid-range +point coil applied at the top-of-tube-sheet plus 3 inches to minus 12
inches).
g) Identify and quantify any SG tube leakage experienced during the previous operating
cycle. Also provide documentation identifying which SG was leaking and corrective
actions completed and planned for this condition.
h) Copy of steam generator eddy current data analyst guidelines and site validated eddy
current technique specification sheets. Additionally, please provide a copy of EPRI
Appendix H, Examination Technique Specification Sheets, qualification records.
i) Provide past history of the condition and issues pertaining to the secondary side of the
steam generators (including items such as loose parts, fouling, top of tube sheet
condition, crud removal amounts, etc.).
Indicate where the primary, secondary, and resolution analyses are scheduled to take place.
A.5 Additional Information Related to all Inservice Inspection Activities
A2-8
a) A list with a brief description of inservice inspection, and boric acid corrosion control
program related issues (e.g., Condition Reports) entered into your corrective action
program since the beginning of the last refueling outage. For example, a list based
upon data base searches using key words related to piping such as: inservice
inspection, ASME Code,Section XI, NDE, cracks, wear, thinning, leakage, rust,
corrosion, boric acid, or errors in piping examinations.
b) Provide training (e.g. Scaffolding, Fall Protection, FME, Confined Space) if they are
required for the activities described in A.1 through A.4.
c) Please provide names and phone numbers for the following program leads:
Inservice inspection (examination, planning)
Containment exams
Reactor pressure vessel head exams
Snubbers and supports
Repair and replacement program
Licensing
Site welding engineer
Boric acid corrosion control program
Steam generator inspection activities (site lead and vendor contact)
B. Information to be Provided Onsite to the Inspector(s) at the Entrance Meeting (April 6,
2017):
B.1 Inservice Inspection / Welding Programs and Schedule Information
a) Updated schedules for inservice inspection/nondestructive examination activities,
including planned welding activities, and schedule showing contingency repair plans, if
available.
b) For ASME Code Class welds selected by the inspector from the lists provided from
Section A of this enclosure, please provide copies of the following documentation for
each subject weld:
Weld data sheet (traveler).
Weld configuration and system location.
Applicable Code Edition and Addenda for weldment.
Applicable Code Edition and Addenda for welding procedures.
Applicable welding procedures used to fabricate the welds.
Copies of procedure qualification records (PQRs) supporting the weld
procedures from B.1.b.v.
Copies of welders performance qualification records (WPQ).
A2-9
Copies of the nonconformance reports for the selected welds (If
applicable).
Radiographs of the selected welds and access to equipment to allow
viewing radiographs (if radiographic testing was performed).
Copies of the preservice examination records for the selected welds.
Readily accessible copies of nondestructive examination personnel
qualifications records for reviewing.
c) For the inservice inspection related corrective action issues selected by the inspector
from Section A of this enclosure, provide a copy of the corrective actions and
supporting documentation.
d) For the nondestructive examination reports with relevant conditions on ASME Code
Class components selected by the inspector from Section A above, provide a copy of
the examination records, examiner qualification records, and associated corrective
action documents.
e) A copy of (or ready access to) most current revision of the inservice inspection
program manual and plan for the current interval.
f) For the nondestructive examinations selected by the inspector from Section A of this
enclosure, provide a copy of the nondestructive examination procedures used to
perform the examinations (including calibration and flaw characterization/sizing
procedures). For ultrasonic examination procedures qualified in accordance with
ASME Code,Section XI, Appendix VIII, provide documentation supporting the
procedure qualification (e.g. the EPRI performance demonstration qualification
summary sheets). Also, include qualification documentation of the specific equipment
to be used (e.g., ultrasonic unit, cables, and transducers including serial numbers) and
nondestructive examination personnel qualification records.
B.2 Reactor Pressure Vessel Head (RPVH)
a) Provide drawings showing the following (if performing any RPVH inspection activities):
i. RPVH and control rod drive mechanism nozzle configurations.
ii. RPVH insulation configuration.
Note: The drawings listed above should include fabrication drawings for the nozzle
attachment welds as applicable.
b) Copy of the documents which demonstrate that the procedures to be used for
volumetric examination of the reactor vessel head penetration J-groove welds were
qualified by a blind demonstration test in accordance with 10 CFR 50.55a(g)(6)(ii)(D).
c) Copy of volumetric, surface and visual examination records for the prior inspection of
the reactor vessel head and head penetration J-groove welds.
A2-10
B.3 Boric Acid Corrosion Control Program
a) Please provide boric acid walk down inspection results, an updated list of boric acid
leaks identified so far this outage, associated corrective action documentation, and
overall status of planned boric acid inspections.
b) Please provide any engineering evaluations completed for boric acid leaks identified
since the end of the last refueling outage. Please include a status of corrective actions
to repair and/or clean these boric acid leaks. Please identify specifically which known
leaks, if any, have remained in service or will remain in service as active leaks.
B.4 Steam Generator Tube Inspections
a) Copies of the Examination Technique Specification Sheets and associated justification
for any revisions.
b) Please provide a copy of the eddy current testing procedures used to perform the
steam generator tube inspections (specifically calibration and flaw
characterization/sizing procedures, etc.).
c) Copy of the guidance to be followed if a loose part or foreign material is identified in
the steam generators.
d) Identify the types of SG tube repair processes which will be implemented for defective
SG tubes (including any NRC reviews/evaluations/approvals of this repair process).
Provide the flaw depth sizing criteria to be applied for ET indications identified in the
SG tubes.
e) Copy of documents describing actions to be taken if a new SG tube degradation
mechanism is identified.
f) Provide procedures with guidance/instructions for identifying (e.g. physically locating
the tubes that require plugging) and plugging SG tubes.
g) List of corrective action documents generated by the vendor and/or site with respect to
steam generator inspection activities.
B.5 Codes and Standards
a) Ready access to (i.e., copies provided to the inspector(s) for use during the inspection
at the onsite inspection location, or room number and location where available):
i. Applicable Editions of the ASME Code (Sections V, IX, and XI) for the
inservice inspection program and the repair/replacement program.
b) Copy of the performance demonstration initiative (PDI) generic procedures with the
latest applicable revisions that support site qualified ultrasonic examinations of piping
welds and components (e.g., PDI-UT-1, PDI-UT-2, PDI-UT-3, PDI-UT-10, etc.).
Boric Acid Corrosion Guidebook Revision 1 - EPRI Technical Report 1000975.
A2-11
Comanche Peak Medium Energy Line Break Licensee Event Report
Detailed Risk Evaluation
Comanche Peak Nuclear Power Plant Licensee Event Report 16-002-01, Unanalyzed
Condition Involving Potential Moderate Energy Line Break, described six vulnerabilities in the
licensees equipment configurations for medium energy line breaks (MELB). Each of these
conditions is contained in the tables in this evaluation.
The length of piping which could cause the loss of the affected components by having a MELB
was estimated and the values are contained in the tables.
All MELBs were assumed to fail the affected components every time the piping would leak or
break. The pipe leak and/or break frequency was estimated by the use of system piping data
from the 2010 Component Reliability update for data from NUREG/CR-6928, Industry-Average
Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants.
The analyst assumed non-service water system piping and added the 2.53E-10 per hour per
foot for small leakage and 2.53E-11 per hour per foot for large leakage to estimate the MELB
hazard.
The MELB deficiencies were assumed to have existed since initial plant power operations
began. Exposure time was limited to one year per Section 2.0, Exposure Time Modeling, in the
Risk Assessment of Operational Events (RASP) Handbook.
The analyst assumed for condition number 1 in the tables below that each unit was vulnerable
to having a service water pump affected and therefore considered a loss of service water pump
for each unit in the estimate of increase in core damage frequency for each unit. The
Comanche Peak Plant Risk Information e-Book was used to determine that service water pump
1-1 was the most risk significant service pump for Unit 1; and service water pump 2-1 was the
most significant service water pump for Unit 2.
The analyst assumed for condition number 3 in the tables below that only one component could
be affected, therefore in the tables, only the most risk significant service water pump was
considered in the final estimated increase in core damage frequency.
The analyst first estimated the increase in core damage frequency due to the additional failure
probability of the components from a MELB event. The results are contained in the following
table:
Condition Number and Feet of Piping failure Nominal failure Revised Increase in core damage
Affected Component(s) piping probability probability failure frequency
probability Unit 1 Unit 2
1 Service Water Pump 1- 50 3.34E-7 1.57E-4 1.58E-4 2.44E-10 N/A
1
Service Water Pump 2- 50 3.34E-7 1.57E-4 1.58E-4 N/A 2.44E-10
1
2 Motor Control Center 5 3.34E-8 3.33E-5 3.34E-5 N/A Negligible
3 Switchgear 1EA2 20 1.34E-7 3.33E-5 3.34E-5 1.32E-10 N/A
Motor Control Center 20 1.34E-7 3.33E-5 3.34E-5 Negligible N/A
Distribution Panel 20 1.34E-7 6.50E-5 6.51E-5 Negligible N/A
A3-1 Attachment 3
Condition Number and Feet of Piping failure Nominal failure Revised Increase in core damage
Affected Component(s) piping probability probability failure frequency
probability Unit 1 Unit 2
4 Motor Control Center 5 3.34E-8 3.33E-5 3.333E-5 1.0E-11 N/A
5 Motor Control Center 5 3.34E-8 3.33E-5 3.34E-5 N/A 1.0E-11
6 Motor Control Center 10 6.68E-8 3.33E-5 3.34E-5 1.0E-11 N/A
Total Increase In Core Damage Frequency (per year) for each Unit 3.96E-10 2.54E-10
The analyst then estimated the increase in core damage frequency from each of the MELB
events by increasing the initiating event frequency for cases where there was a clear initiator
(e.g., loss of bus initiator, loss of service water initiator). If no initiator was modelled, the analyst
assumed the MELB caused a transient and applied the frequency of the MELB event to the
conditional core damage probability (CCDP) for a transient. The following table contains the
results:
Condition Number and Feet of Piping failure Nominal Revised Transient Increase in core damage
Affected Component(s) piping frequency initiating initiating CCDP frequency
(per year) event event Unit 1 Unit 2
frequency frequency
1 Service Water Pump 50 1.22E-4 5.74E-2 5.76E-2 N/A Negligible N/A
1-1
Service Water Pump 50 1.22E-4 5.74E-2 5.76E-2 N/A N/A Negligible
2-1
2 Motor Control 5 1.22E-5 6.90E-1 6.90E-1 9.33E-6 N/A 1.2E-10
Center 2EB2-1
3 Switchgear 1EA2* 20 4.88E-5 False 4.88E-5 N/A 4.55E-8 N/A
Motor Control 20 4.88E-5 6.90E-1 6.90E-1 5.35E-6 2.61E-10 N/A
Center 1EB4-2 (not used)
Distribution Panel 20 4.88E-5 7.37E-4 7.86E-4 N/A 3.52E-8 N/A
1ED2-2** (not used)
4 Motor Control 5 1.22E-5 6.90E-1 6.90E-1 2.22E-4 2.7E-9 N/A
Center 1EB4-1
5 Motor Control 5 1.22E-5 6.90E-1 6.90E-1 2.22E-4 N/A 2.7E-9
Center 2EB4-1
6 Motor Control 10 2.44E-5 6.90E-1 6.90E-1 2.22E-4 2.7E-9 N/A
Center 1EB4-1
Total Increase In Core Damage Frequency (per year) for each Unit 5.1E-8 2.8E-9
- The analyst assumed that an initiator for failure of bus 1EA2 could be modeled by increasing the failure probability of bus 1EA1 to
obtain representative results because the SPAR model did not contain an initiator of loss of bus 1EA2.
Adding the results of the two effects resulted in an estimated increase in core damage
frequency of 5.1E-8/year for Unit 1 and 2.9E-10/year for Unit 2. Based on these increases, the
finding was determined to be of very low safety significance (Green). The estimates were
obtained by use of Version 8.28 of the Comanche Peak SPAR model ran on SAPHIRE, Version
8.1.5. The dominant core damage sequences were losses of switchgear and losses of service
water. Offsite power and feed and bleed availability remained to mitigate the significance of
dominant initiators.
A3-2