ML13310C184
| ML13310C184 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 11/06/2013 |
| From: | Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A |
| To: | Flores R Luminant Generation Co |
| References | |
| IR-13-004 | |
| Download: ML13310C184 (47) | |
See also: IR 05000445/2013004
Text
November 6, 2013
Rafael Flores, Senior Vice President
and Chief Nuclear Officer
Luminant Generation Company, LLC
Comanche Peak Nuclear Power Plant
P.O. Box 1002
Glen Rose, TX 76043
Subject: COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION
REPORT 05000445/2013004 AND 05000446/2013004
Dear Mr. Flores:
On September 25, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Comanche Peak Nuclear Power Plant, Units 1 and 2. On October 2, 2013,
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.
Three 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 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, Units 1 and 2.
If you disagree with a cross-cutting aspect assignment or a finding not associated with a
regulatory requirement 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,
Units 1 and 2.
UNITED STATES
NUCLEAR REGULATORY COMMISSION
RE G IO N I V
1600 EAST LAMAR BLVD
ARLINGTON, TEXAS 76011-4511
R. Flores
- 2 -
In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections,
Exemptions, Requests for Withholding, of the NRC's Rules of Practice, a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in the
NRCs Public Document Room or from the Publicly Available Records (PARS) component of the
NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is
accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public
Electronic Reading Room).
Sincerely,
/RA/
Wayne C. Walker, Branch Chief
Project Branch A
Division of Reactor Projects
Docket Nos.: 50-445, 50-446
Enclosure:
Inspection Report 05000445/2013004 and 05000446/2013004
w/Attachments:
1. Supplemental Information
2. Request for Information for the Temporary Instruction 2515-182,
Review of Implementation of the Industry Initiative to Control
Degradation of Underground Piping and Tanks Inspection
cc w/encl: Electronic Distribution for Comanche Peak
R. Flores
- 3 -
Electronic distribution by RIV:
Regional Administrator (Marc.Dapas@nrc.gov)
Deputy Regional Administrator (Steven.Reynolds@nrc.gov)
DRP Director (Kriss.Kennedy@nrc.gov)
DRP Deputy Director (Troy.Pruett@nrc.gov)
DRS Director (Tom.Blount@nrc.gov)
DRS Deputy Director (Jeff.Clark@nrc.gov)
Senior Resident Inspector (John.Kramer@nrc.gov)
Resident Inspector (Rayomand.Kumana@nrc.gov)
Branch Chief, DRP/A (Wayne.Walker@nrc.gov)
Senior Project Engineer, DRP/A (Ryan.Alexander@nrc.gov)
Project Engineer, DRP/A (Jason.Dykert@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Project Manager (Balwant.Singal@nrc.gov)
Branch Chief, DRS/TSB (Ray.Kellar@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
ACES (R4Enforcement.Resource@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Technical Support Assistant (Loretta.Williams@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
RIV/ETA: OEDO (Daniel.Rich@nrc.gov)
ROPreports
File located:R:\\_REACTORS\\CP2013004-RP-JGK.pdf
ADAMS Accession Number: ML13310C184
SUNSI Rev Compl.
Yes No
Yes No
Reviewer Initials
WW
Publicly Avail
Yes No
Sensitive
Yes No
Sens. Type Initials
WW
SRI:DRP/A
RI:DRP/A
SPE:DRP/A
C:/DRS/TSB
C:DRS/OB
JKramer
RKumana
RAlexander
RKellar
VGaddy
/RA/ E-Walker
/RA/ RDA for
/RA/
/RA/
/RA/
10/30/13
11/1/13
10/30/13
10/31/13
11/1/13
C:DRS/PSB1
C:DRS/PSB2
C:DRS/EB1
C:DRS/EB2
C:DRP/A
MHaire
JDrake
TFarnholtz
GMiller
WWalker
/RA/
/RA/
/RA/
/RA/
/RA/
11/4/13
10/31/13
11/1/13
11/1/13
11/6/13
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
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Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
50-445, 50-446
License:
Report:
05000445/2013004 and 05000446/2013004
Licensee:
Luminant Generation Company LLC
Facility:
Comanche Peak Nuclear Power Plant, Units 1 and 2
Location:
Dates:
June 27 through September 25, 2013
Inspectors:
J. Kramer, Senior Resident Inspector
R. Kumana, Resident Inspector
S. Alferink, Reactor Inspector
I. Anchondo, Senior Reactor Inspector
S. Graves, Senior Reactor Inspector
D. Proulx, Senior Project Engineer
M. Williams, Reactor Inspector
Approved By:
Wayne Walker, Chief, Project Branch A
Division of Reactor Projects
- 2 -
SUMMARY OF FINDINGS
IR 05000445/2013004, 05000446/2013004; 6/27/2013 - 9/25/2013; Comanche Peak Nuclear
Power Plant, Units 1 and 2 Integrated Resident and Regional Report; Equipment Alignments,
Maintenance Effectiveness, Operability Evaluations and Functionality Assessments, Plant
Modifications, Post-Maintenance Testing
The report covered a 3-month period of inspection by resident inspectors and announced
baseline inspections by region-based inspectors. Three Green non-cited violations and two
Green findings were identified. The significance of most findings is indicated by their color
(Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance
Determination Process. The cross-cutting aspect is determined using Inspection Manual
Chapter 0310, Components Within the Cross-Cutting Areas. Findings for which the
significance determination process does not apply may be Green or be assigned a severity level
after NRC management review. The NRC's program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 4, dated December 2006.
A.
NRC-Identified Findings and Self-Revealing Findings
Cornerstone: Initiating Events
Green. The inspectors reviewed a self-revealing finding for operations
personnel failure to follow instructions for the removal of the dissimilar metal
elbow when installing a pipe cap. As a result, the elbow eventually leaked,
reactor coolant system leakage increased, and a Unit 1 shutdown was needed to
correct the issue. The licensee entered the finding into the corrective action
program as Condition Report CR-2013-006795.
The finding was more than minor because it was associated with the human
performance attribute of the Initiating Events cornerstone and adversely affected
the cornerstone objective to limit the likelihood of those events that upset plant
stability and challenge critical safety functions during shutdown as well as power
operations. Using Inspection Manual Chapter 0609, Appendix A, The
Significance Determination Process for Findings At-Power, the finding was
determined to be of very low safety significance (Green) because the finding
could not result in exceeding the reactor coolant system leak rate for a small loss
of coolant accident and the finding would not have affected other systems used
to mitigate a loss of coolant accident resulting in a total loss of their function. The
finding had a human performance cross-cutting aspect associated with resources
because the environmental conditions impacted the ability of the operators to
correctly install the pipe cap H.3(a). (Section 1R15)
Green. The inspectors reviewed a self-revealing finding for the licensees failure
to ensure the heat exchanger tube plugging procedure was adequate. As a
result, auxiliary condenser plugs were improperly inserted and caused a tube
to leak. This caused high sodium levels in the steam generators and a Unit 2
power reduction from 100 percent to less than 50 percent power. The
licensee entered the finding into the corrective action program as Condition
Report CR-2012-011805.
- 3 -
The finding was more than minor because it was associated with the equipment
performance attribute of the Initiating Events cornerstone and adversely affected
the cornerstone objective, in that, it increased the likelihood of those events that
upset plant stability and challenge critical safety functions during power
operations. Using Inspection Manual Chapter 0609, Appendix A, The
Significance Determination Process for Findings At-Power, the finding was
determined to be of very low safety significance (Green) because the finding did
not cause a reactor trip and the loss of mitigation equipment. The finding has a
human performance cross-cutting aspect associated with work practices in that
the licensee supervision failed to provide appropriate oversight to the tube
plugging procedure and plugging activity H.4(c). (Section 1R18)
Cornerstone: Mitigating Systems
Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure
to follow instructions and remove cables from containment as part of a
modification. As a result, portions of 12 cables totaling approximately 100 feet
in length wrapped with tape on the ends remained in containment and could
have been transported to the emergency sumps during an accident. The
licensee entered the finding into the corrective action program as Condition
Report CR-2013-009443.
The finding was more than minor because it was associated with the equipment
performance attribute of the mitigating systems cornerstone and adversely
affected the cornerstone objective to ensure the availability, reliability, and
capability of the emergency sumps. Using NRC Manual Chapter 0609,
Significance Determination Process, Appendix G, Shutdown Operations
Significance Determination Process, Attachment 1, Checklist 2, the finding was
determined to be of very low safety significance because the licensee maintained
adequate mitigation capability for the current plant state and the finding was not
characterized as a loss of control event. The finding has a human performance
cross-cutting aspect associated with work practices in that the maintenance
personnel did not involve supervision when they had questions concerning the
removal of the cables and proceeded in the face of uncertainty H.4(a).
(Section 1R04)
Green. The inspectors identified a non-cited violation of 10 CFR 50.65(a)(1) for
the licensees failure to establish performance goals and perform monitoring to
ensure the Unit 1 auxiliary feedwater system was capable of performing its
intended function. The licensee entered the finding into the corrective action
program as Condition Report CR-2013-010024.
This finding was more than minor because it was associated with the equipment
performance attribute of the Mitigating Systems cornerstone and adversely
affected the cornerstone objective to ensure the availability and reliability of
systems that respond to initiating events to prevent undesirable consequences.
Using Inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process for Findings At-Power, the finding was determined to be
of very low safety significance (Green) because the finding was not a design or
qualification deficiency; did not represent an actual loss of safety function of a
system or train; and did not represent an actual loss of a technical specification
- 4 -
train for greater than its allowed outage time. The finding had a human
performance cross-cutting aspect associated with decision-making, in that, the
licensee failed to demonstrate that nuclear safety is the overriding priority by not
obtaining adequate interdisciplinary input when determining the auxiliary
feedwater maintenance rule status H.1(a). (Section 1R12)
Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure
to follow procedures that require initiating a condition report for degradation to
safety-related equipment. During a surveillance activity, maintenance personnel
discovered that a reactor coolant pump under frequency relay was outside the
as-found setpoint tolerance for pick-up frequency and failed to enter the condition
into the corrective action program. As a result, the cause and effect of the
degraded condition was not evaluated and the relay again drifted outside the
setpoint tolerance. The licensee entered the finding into the corrective action
program as Condition Report CR-2013-010078.
The finding was more than minor because if the licensee continues to fail to
document degraded safety-related equipment in the corrective action database,
there is a potential that this could lead to a more significant safety concern, in
that the cause of the degradation will not be evaluated and corrected. Using
Inspection Manual Chapter 0609, Appendix A, The Significance Determination
Process for Findings At-Power, the finding was determined to be of very low
safety significance (Green) because the finding was not a design or qualification
deficiency; did not represent an actual loss of safety function of a system or train;
and did not represent an actual loss of a technical specification train for greater
than its allowed outage time. The finding has a human performance
cross-cutting aspect associated with resources in that the licensee failed to
provide adequate training to personnel performing maintenance H.2(b).
(Section 1R19)
B.
Licensee-Identified Violations
A violation of very low safety significance was identified by the licensee and has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees corrective action program. The violation and corrective
action tracking numbers are listed in Section 4OA7.
- 5 -
Plant Status
Unit 1 began the inspection period at approximately 100 percent power. On July 26, 2013, the
operators initiated a shutdown of Unit 1 to Mode 3 for a scheduled maintenance outage to repair
a leak associated with a seal injection drain line. The unit returned to service the following day
when the main generator output breakers were closed. On July 28, 2013, the unit returned to
approximately 100 percent power and operated at that power level for the remainder of the
inspection period.
Unit 2 began the inspection period at approximately 100 percent power and operated at that
power level for the remainder of the inspection period.
REPORT DETAILS
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1
Summer Readiness for Offsite and Alternate-AC Power Systems
a.
Inspection Scope
The inspectors reviewed the licensees preparations for seasonal high grid loading. The
inspectors reviewed the licensees procedures and communications protocols to ensure
that they included measures to monitor and maintain availability and reliability of both the
off-site and alternate-ac power systems. The inspectors performed a walkdown of the
switchyard to observe the material condition of off-site power sources.
The inspectors also reviewed corrective action program items to verify that the licensee
was identifying summer readiness issues at an appropriate threshold and entering them
into its corrective action program for resolution.
These activities constitute completion of one summer readiness for off-site and
alternate-ac power systems sample as defined in Inspection Procedure 71111.01-05.
b.
Findings
No findings were identified.
.2
Readiness to Cope with External Flooding
a.
Inspection Scope
The inspectors performed a review of the Final Safety Analysis Report, the recent Safe
Shutdown Impoundment Dam Report, updated list of external flooding protection and
mitigation equipment, updated flooding walkdown issues list, and the latest revision of
the Post-Fukushima Flooding Reevaluation Report.
The inspectors also reviewed the corrective action program to determine if licensee
personnel identified and corrected flooding problems. The inspectors reviews focused
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specifically on the turbine building doors below the probable maximum flood level, and
adjacent water intake and discharge structures.
These activities constitute completion of one readiness to cope with external flooding
sample as defined in Inspection Procedure 71111.01-05.
b.
Findings
No findings were identified.
1R04 Equipment Alignments (71111.04)
a.
Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
April 19, 2013, Unit 1, containment lower level for debris transport to the
containment sumps following the refueling outage
July 23, 2013, Unit 2, residual heat removal pump 2-01 when residual heat
removal pump 2-02 was unavailable for maintenance
September 10, 2013, the switchyard, Unit 2 diesel generators, and Units 1 and 2
turbine driven auxiliary feedwater pumps when transformer XST2 was
unavailable for maintenance
The inspectors selected these systems based on their risk-significance relative to the
reactor safety cornerstones at the time they were inspected. The inspectors focused on
discrepancies that could affect the function of the system, and, therefore, potentially
increase risk. The inspectors reviewed applicable operating procedures, system
diagrams, Final Safety Analysis Report, technical specification requirements,
outstanding work orders, condition reports, and the impact of ongoing work activities on
redundant trains of equipment in order to identify conditions that could have rendered
the systems incapable of performing their intended functions. The inspectors also
walked down accessible portions of the systems to verify system components and
support equipment were aligned correctly and operable. The inspectors examined the
material condition of the components and observed operating parameters of equipment
to verify that there were no obvious deficiencies. The inspectors also verified that the
licensee had properly identified and resolved equipment alignment problems that could
cause initiating events or impact the capability of mitigating systems or barriers and
entered them into the corrective action program with the appropriate significance
characterization.
These activities constitute completion of three partial system walkdown samples as
defined in Inspection Procedure 71111.04-05.
- 7 -
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to
follow instructions and remove cables from containment as part of a modification. As a
result, portions of 12 cables totaling approximately 100 feet in length wrapped with tape
on the ends remained in containment and could have been transported to the
emergency sumps during an accident.
Description. On April 19, 2013, the inspectors performed a walkdown of the Unit 1
containment to look for debris and other materials that could be transported to the
emergency sumps during an accident. The inspectors observed portions of cables with
cut ends wrapped in tape in the lower loop rooms. The inspectors informed the licensee
of the observation. The licensee determined that the cables should have been removed
as part of a design modification and that maintenance personnel did not follow the work
order instructions when removing the cables. The licensee initiated another work order
and removed the cables.
The inspectors determined, through discussion with licensee personnel, that the
personnel performing the maintenance activity did not involve supervision when they had
questions concerning the removal of the cables and proceeded in the face of uncertainty.
Analysis. The failure of the maintenance personnel to follow work order instructions and
remove materials from containment was a performance deficiency which resulted in
debris remaining in containment. The finding was more than minor because it was
associated with the equipment performance attribute of the mitigating systems
cornerstone and adversely affected the cornerstone objective to ensure the availability,
reliability, and capability of the emergency sumps. Using NRC Manual Chapter 0609,
Significance Determination Process, Appendix G, Shutdown Operations Significance
Determination Process, Attachment 1, Checklist 2, the finding was determined to be of
very low safety significance because the licensee maintained adequate mitigation
capability for the current plant state and the finding was not characterized as a loss of
control event. The finding has a human performance cross-cutting aspect associated
with work practices in that the maintenance personnel did not involve supervision when
they had questions concerning the removal of the cables and proceeded in the face of
uncertainty H.4(a).
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions of a type appropriate to the circumstances and shall be
accomplished in accordance with these instructions. Work Order 4575654 implemented
a design change to remove cables from containment and Step 4, required, in part, to
remove the cable and insulating material from containment. Contrary to the above, on
April 10, 2013, maintenance personnel failed to follow documented instructions.
Specifically, the maintenance personnel failed to properly disconnect the cables and
remove them from containment. The licensee removed the materials before
returning the unit to service. Since the violation was of very low safety significance
and was documented in the licensees corrective action program as Condition
Report CR-2013-009443, it is being treated as a non-cited violation, consistent with
Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000445/2013004-01,
Failure to Remove Cable Material from Inside Containment.
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1R05 Fire Protection (71111.05AQ)
.1
Quarterly Fire Inspection Tours (71111.05Q)
a.
Inspection Scope
The inspectors conducted fire protection walkdowns in the following risk-significant plant
areas:
August 26, 2013, fire zone WB104a, service water intake structure
September 18, 2013, fire zone SD9, Unit 1 train A switchgear room
September 19, 2013, fire zone 2SD9, Unit 2 train A switchgear room
September 25, 2013, fire zone EC51, Unit 1 train B inverter room
September 25, 2013, fire zone EC50, Unit 2 train B inverter room
The inspectors reviewed areas to assess if licensee personnel had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant; effectively maintained fire detection and suppression capability; maintained
passive fire protection features in good material condition; and had implemented
adequate compensatory measures for out of service, degraded or inoperable fire
protection equipment, systems, or features, in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk
as documented in the plants individual plant examination of external events or their
potential to affect equipment that could initiate or mitigate a plant transient. The
inspectors verified that fire hoses and extinguishers were in their designated locations
and available for immediate use; that fire detectors and sprinklers were unobstructed;
that transient material loading was within the analyzed limits; and fire doors, dampers,
and penetration seals appeared to be in satisfactory condition.
These activities constitute completion of five quarterly fire-protection inspection samples
as defined in Inspection Procedure 71111.05-05.
b.
Findings
No findings were identified.
.2
Annual Fire Protection Drill Observation (71111.05A)
a.
Inspection Scope
On September 10, 2013, the inspectors observed a fire brigade drill for a simulated fire
in Unit 2 centrifugal charging pump 2-02 room. The observation evaluated the readiness
of the plant fire brigade and control room staff to fight fires. The inspectors verified that
the licensee staff identified deficiencies; openly discussed them in a self-critical manner
at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated
were: (1) proper wearing of turnout gear and self-contained breathing apparatus;
(2) proper use and layout of fire hoses; (3) employment of appropriate firefighting
techniques; (4) sufficient firefighting equipment brought to the scene; (5) effectiveness of
fire brigade leader communications, command, and control; (6) search for victims and
propagation of the fire into other plant areas; (7) utilization of preplanned strategies; and
(8) adherence to the preplanned drill scenario.
- 9 -
These activities constitute completion of one annual fire protection drill observation
sample as defined by Inspection Procedure 71111.05-05.
b.
Findings
No findings were identified.
1R06 Flood Protection Measures (71111.06)
a.
Inspection Scope
The inspectors reviewed the Final Safety Analysis Report, the flooding analysis, and
plant procedures to assess susceptibilities involving internal flooding; reviewed the
corrective action program to determine if licensee personnel identified and corrected
flooding problems; inspected spaces needing compensatory actions in order to protect
against internal flooding in cases where the circulating water system lake levels exceed
the 778 foot elevation; and verified that operator actions for coping with flooding can
reasonably achieve the desired outcomes. The inspectors also checked the floor and
wall penetration seals, watertight door seals, common drain lines and sumps, sump
pumps, level alarms, and control circuits that are integral to the internal flooding
mitigation strategy. The inspectors evaluated the following areas:
July 18, 2013, pathway from the circulating water discharge structure via
circulating water tunnels to turbine building and lower level of the electrical and
control building
July 18, 2013, recycle hold up tanks, laundry and hot shower tank, waste holdup
tank, and floor drain tanks in the auxiliary building
These activities constitute completion of two flood protection measures samples as
defined in Inspection Procedure 71111.06-05.
b.
Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
(71111.11)
.1
Quarterly Inspection of Licensed Operator Requalification Program (71111.11Q)
a.
Inspection Scope
On August 12, 2013, the inspectors observed a crew of licensed operators in the plants
simulator during requalification training. The inspectors assessed the following areas:
Licensed operator performance
The ability of the licensee to administer the evaluations and training
The modeling and performance of the control room simulator
The quality of post-scenario critiques
Follow-up actions taken by the licensee for identified discrepancies
- 10 -
These activities constitute completion of one quarterly inspection of licensed operator
requalification program sample as defined in Inspection Procedure 71111.11-05.
b.
Findings
No findings were identified.
.2
Quarterly Observation of Licensed Operator Performance (71111.11Q)
a.
Inspection Scope
The inspectors observed the performance of on-shift licensed operators in the plants
main control room. At the time of the observations, the plant was in a period of
heightened activity. The inspectors assessed the operators adherence to plant
procedures and other operations department policies. The inspectors observed the
operators performance of the following activities:
July 8, 2013, Unit 1, reactivity management during the swapping from a
centrifugal charging pump to the positive displacement pump
July 27, 2013, Unit 1, down-power and manual reactor trip for planned
maintenance outage
These activities constitute completion of one quarterly observation of licensed-operator
performance sample as defined in Inspection Procedure 71111.11-05.
b.
Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12)
a.
Inspection Scope
The inspectors evaluated the following risk-significant systems, components, and
degraded performance issues:
Unit 1, auxiliary feedwater system
The inspectors reviewed events where ineffective equipment maintenance had resulted
in failures and independently verified the licensee's actions to address system
performance or condition problems in terms of the following:
Implementing appropriate work practices
Identifying and addressing common cause failures
Scoping of systems in accordance with 10 CFR 50.65(b)
Characterizing system reliability issues for performance
Charging unavailability for performance
Trending key parameters for condition monitoring
Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or (a)(2)
- 11 -
The inspectors verified appropriate performance criteria for structures, systems, and
components classified as having an adequate demonstration of performance through
preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the
establishment of appropriate and adequate goals and corrective actions for systems
classified as not having adequate performance, as described in 10 CFR 50.65(a)(1).
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the corrective action program with the appropriate
significance characterization. Specific documents reviewed during this inspection are
listed in the attachment.
These activities constituted completion of two maintenance effectiveness samples as
defined in Inspection Procedure 71111.12-05.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50.65(a)(1)
for the licensees failure to establish performance goals and perform monitoring to
ensure the Unit 1 auxiliary feedwater system was capable of performing its intended
function.
Description. On August 29, 2013, the inspectors attended a maintenance rule review
panel meeting. As part of the meeting, a system engineer presented two events that
had caused the auxiliary feedwater system to exceed its performance criteria of two
functional failures in a two year period for the Unit 1 motor driven auxiliary feedwater
pumps. The first functional failure, associated with Condition Report CR-2012-011913,
documented air blowing from the motor driven auxiliary feedwater pump 1-01 to the
condensate recirculation flow valve regulator gauge, 1-FV-2456. The second functional
failure, associated with Condition Report CR-2012-013430, documented a failure of the
motor driven auxiliary feedwater pump 1-01 flow controller to steam generator 1-01,
1-FK-2453C, at the remote shutdown panel. The engineer presented to the panel an
approved and documented evaluation that concluded the cause was known and
eliminated and thus, monitoring against goals was unnecessary. The panel agreed with
the engineers presentation and voted to place the system in a maintenance rule (a)(2)
status.
The inspectors disagreed with the maintenance rule review panels determination of the
status of the Unit 1 auxiliary feedwater system. The inspectors informed the panel that
they had failed to consider a third functional failure of the system. The inspectors
described the functional failure, associated with Condition Report CR-2013-003358,
where air was blowing from the motor driven auxiliary feedwater pump 1-02 to the
condensate recirculation flow valve regulator gauge, 1-FV-2457. Based on the
inspectors comments, the maintenance rule review panel determined the Unit 1 auxiliary
feedwater system should remain in an (a)(1) status and goals need to be established.
The inspectors discussed the cause of the event with the licensee. The inspectors
determined that the licensee failed to obtain adequate interdisciplinary input when
determining the auxiliary feedwater maintenance rule status.
Analysis. The failure to establish goals and monitor the performance of the auxiliary
feedwater system was a performance deficiency. This finding was more than minor
because it was associated with the equipment performance attribute of the Mitigating
- 12 -
Systems cornerstone and adversely affected the cornerstone objective to ensure the
availability and reliability of systems that respond to initiating events to prevent
undesirable consequences. Using Inspection Manual Chapter 0609, Appendix A, The
Significance Determination Process for Findings At-Power, the finding was determined
to be of very low safety significance (Green) because the finding was not a design or
qualification deficiency; did not represent an actual loss of safety function of a system or
train; did not represent an actual loss of a technical specification train for greater than its
allowed outage time; and did not result in the loss of one or more trains of non-technical
specification trains of equipment. The finding had a human performance cross-cutting
aspect associated with decision-making, in that, the licensee failed to demonstrate that
nuclear safety is the overriding priority by not obtaining adequate interdisciplinary input
when determining the auxiliary feedwater maintenance rule status H.1(a).
Enforcement. Title 10 CFR 50.65(a)(1) requires, in part, that the licensee shall monitor
the performance or condition of structures, systems, or components within the scope of
the rule against licensee-established goals in a manner sufficient to provide reasonable
assurance that such structures, systems, or components are capable of fulfilling their
intended safety functions. Title 10 CFR 50.65(a)(2) requires, in part, that monitoring
specified in paragraph (a)(1) is not required where it has been demonstrated the
performance or condition of a system, structure, and component is being effectively
controlled through appropriate preventive maintenance, such that the structure, system,
or component remains capable of performing its intended function. Contrary to the
above, on February 28, 2013, the licensee failed to monitor the performance or condition
of structures, systems, or components within the scope of the rule against
licensee-established goals in a manner sufficient to provide reasonable assurance that
such structures, systems, or components are capable of fulfilling their intended safety
functions. Specifically, the licensee failed to demonstrate that the performance or
condition of the Unit 1 auxiliary feedwater system had been effectively controlled
through the performance of appropriate preventive maintenance and did not monitor the
system against licensee-established goals. Since the violation was of very low safety
significance and was documented in the licensees corrective action program as
Condition Report CR-2013-010024, it is being treated as a non-cited violation, consistent
with Section 2.3.2.a of the Enforcement Policy: NCV 05000445/2013004-02, Failure to
Establish Goals and Monitor the Performance of the Auxiliary Feedwater System.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
The inspectors reviewed the licensees evaluation and management of plant risk for the
maintenance and emergent work activities affecting risk-significant and safety-related
equipment listed below to verify that the appropriate risk assessments were performed
prior to removing equipment for work:
July 12, 2013, Unit 1, risk assessment associated with the planned unit outage to
repair the seal injection leak
July 25, 2013, Unit 2, service water pump 2-01 out of service for unplanned
corrective maintenance on the breaker secondary stab
July 30, 2013, Unit 2, component cooling water pump 2-02 out of service during
testing of service water pump 2-02
- 13 -
August 8, 2013, Unit 2, emergent switchyard work to repair a failed relay in the
345kV subsystem
September 10, 2013, Units 1 and 2, transformer XST2 out of service for planned
maintenance
September 18, 2013, Unit 1, diesel generator 1-02 out of service for planned
maintenance
The inspectors selected these activities based on potential risk-significance relative to
the reactor safety cornerstones. As applicable for each activity, the inspectors verified
that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)
and that the assessments were accurate and complete. When licensee personnel
performed emergent work, the inspectors verified that the licensee personnel promptly
assessed and managed plant risk. The inspectors reviewed the scope of maintenance
work, discussed the results of the assessment with the licensee's probabilistic risk
analyst or shift technical advisor, and verified plant conditions were consistent with the
risk assessment. The inspectors also reviewed the technical specification requirements
and inspected portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met.
These activities constitute completion of six maintenance risk assessments and
emergent work control inspection samples as defined in Inspection
Procedure 71111.13-05.
b.
Findings
No findings were identified.
1R15 Operability Evaluations and Functionality Assessments (71111.15)
a.
Inspection Scope
The inspectors reviewed the following issues:
CR-2013-001446, Unit 1, inverter IV1PC4 board X40 solder connections
CR-2013-005376, Unit 1, void in residual heat removal piping
CR-2013-006795, Unit 1, increased reactor coolant system leak rate
CR-2013-008323, Unit 1, failure of diesel generator 1-01 starting air
compressor 1-01 relief valve
CR-2013-008552, Unit 2, leak from auxiliary feedwater to service water
cross-connect drain line
The inspectors selected these operability issues based on the risk-significance of the
associated components and systems. The inspectors evaluated the technical adequacy
of the evaluations to ensure that technical specification operability was properly justified
and the subject component or system remained available such that no unrecognized
increase in risk occurred. The inspectors compared the operability and design criteria in
the appropriate sections of the technical specifications and Final Safety Analysis Report
- 14 -
to the licensees evaluations to determine whether the components or systems were
operable. Where compensatory measures were required to maintain operability, the
inspectors determined whether the measures in place would function as intended and
were properly controlled. The inspectors determined, where appropriate, compliance
with bounding limitations associated with the evaluations. Additionally, the inspectors
reviewed a sampling of corrective action documents to verify that the licensee was
identifying and correcting any deficiencies associated with operability evaluations.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of five operability evaluation inspection samples
as defined in Inspection Procedure 71111.15-05.
b.
Findings
Introduction. The inspectors reviewed a Green self-revealing finding for operations
personnel failure to follow instructions for the removal of the dissimilar metal elbow when
installing a pipe cap. As a result, the elbow eventually leaked, reactor coolant system
leakage increased, and a Unit 1 shutdown was needed to correct the issue.
Description. On June 27, 2013, the licensee observed that a 3/4 inch threaded
connection downstream of reactor coolant pump 1-02 seal injection line drain valve
1CS-8364B was leaking. The leak was coming from a threaded connection on a carbon
steel elbow that was threaded onto the stainless steel pipe nipple with a stainless steel
cap on the elbow. The correct setup for the components was a stainless cap on the
stainless steel nipple. The licensee determined the incorrect component configuration
occurred near the end of the refueling outage in April 2013.
The inspectors reviewed the licensees cause evaluation for the event. The inspectors
noted that Procedure OWI-404, Operations Vent and Drain Guidelines, Revision 8,
Step 6.4.1, in part, prohibits the use of dissimilar metals fittings inside containment. The
licensees evaluation indicated that operators understood the requirement. The
inspectors reviewed training records and concluded that the operators were trained on
the Procedure OWI-404 requirements.
The inspectors discussed the finding with the licensee and reviewed the cause analysis.
The inspectors determined that the component was in a hot, dark, and hard to reach
location, with interferences present. The poor environmental conditions were the likely
cause of the leaving the carbon steel elbow on the pipe.
Analysis. The failure of the operations personnel to follow instructions for the removal of
the dissimilar metal elbow when installing a pipe cap was a performance deficiency. As
a result, the elbow leaked and caused a unit shutdown. The finding was more than
minor because it was associated with the human performance attribute of the Initiating
Events cornerstone and adversely affected the cornerstone objective to limit the
likelihood of those events that upset plant stability and challenge critical safety functions
during shutdown as well as power operations. Using Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process for Findings At-Power, the finding
was determined to be of very low safety significance (Green) because the finding could
not result in exceeding the reactor coolant system leak rate for a small loss of coolant
accident and the finding would not have affected other systems used to mitigate a loss of
coolant accident resulting in a total loss of their function. The finding had a human
- 15 -
performance cross-cutting aspect associated with resources because the environmental
conditions impacted the ability of the operators to correctly install the pipe cap H.3(a).
Enforcement. This finding does not involve enforcement action because no violation of a
regulatory requirement was identified. The licensee documented the finding in the
corrective action program as Condition Report CR-2013-006795. Because the finding
does not involve a violation and is of very low safety significance, it is being
characterized as a finding FIN 05000445/2013004-03, Improper Pipe Cap Installation
Results in a Unit Shutdown.
1R18 Plant Modifications (71111.18)
a.
Inspection Scope
The inspectors reviewed the plant modification associated with the plugging of the Unit 2
auxiliary condensers. The inspectors reviewed work instructions, and condition reports
associated with the modifications.
These activities constitute completion of one plant modification inspection sample as
defined in Inspection Procedure 71111.18-05.
b.
Findings
Introduction. The inspectors reviewed a Green self-revealing finding for the licensees
failure to ensure the heat exchanger tube plugging procedure was adequate. As a
result, auxiliary condenser plugs were improperly inserted and caused a tube to leak.
This caused high sodium levels in the steam generators and a unit power reduction from
100 percent to less than 50 percent power.
Description. On November 6, 2012, with Unit 2 operating at 100 percent power, a
condenser tube leak occurred in the main feedwater pump auxiliary condenser 2A. This
failure caused the sodium levels in all four steam generators to rise. In accordance with
plant procedures, the licensee reduced power to less than 50 percent until the sodium
levels improved. The licensees root cause analysis concluded that the plugs were
improperly installed during the recent refueling outage in October, 2012, as a result of
inadequate procedure guidance. The instructions did not consider the thickness of the
auxiliary condenser and resulted in the plugs being inserted too far into the tube sheet
and damaging the actual tube. On November 9, 2012, the licensee identified two tubes
that were damaged by improper plug insertion depth. The licensee replaced a total of
42 plugs in the condensers.
The licensee had several opportunities to prevent incorrect installation of the tube plugs.
In May 2011, licensee personnel in a heat exchanger lab training session recognized
that tubes were damaged when the plugs were inserted the length specified in
Procedure MSM-G0-5870, Heat Exchanger Tube Plugging, Revision 0. Condition
Report CR-2011-006610 was initiated to document that Procedure MSM-G0-5870
needed to be changed to prevent inserting tubes too far in a condenser tube sheet and
causing tube distortion or tube breakage. The condition report was reviewed by the
station ownership committee and the management review committee and was closed
the following day based on the initiation of a procedure change submittal. The
procedure change submittal classified the change as a procedure enhancement. The
change was not completed prior to use on the auxiliary condenser.
- 16 -
During the plugging evolution, a vendor that performed a portion of the tube plugging
activities recognized that the procedure was incorrect in the insertion location of the
plug. The vendor marked up the procedure to annotate the correct location of the plug
and inserted the plug in the correct location. The corrected location was discussed in
the post-job debrief, but the procedure was not revised and a condition report was not
initiated. In addition, the licensee did not change the incorrect plugging of the condenser
that was performed by licensee maintenance personnel a few days earlier.
The inspectors determined that MSM-G0-5870, Heat Exchanger Tube Plugging,
Revision 0 was revised in 2005 when the auxiliary condensers were added to the
procedure. Procedure STA-202, Nuclear Generation Procedure Change Process,
Revision 31, Step 6.3.8, requires, in part, that a technical review be performed when
changing a procedure. The instructions in Procedure MSM-G0-5870 were not changed
to account for the differences in tubesheet thickness when the auxiliary condenser was
added to the procedure and therefore the plugs were inserted in the wrong location. The
inspectors concluded that the licensee failed to follow Procedure STA-202 and failed to
perform an adequate technical review of Procedure MSM-G0-5870.
The inspectors discussed the finding with the licensee and reviewed the licensees root
cause analysis. Although Procedure MSM-G0-5870 was revised to incorporate the
auxiliary condenser in 2005, the inspectors concluded that the finding is indicative of
current plant performance. The inspectors determined that within 18 months prior to the
event, the licensee had identified several instances where Procedure MSM-G0-5870
was inadequate and missed all of the opportunities to correct the procedure and install
the plugs in the correct location before returning the condenser to service.
Analysis. The licensees failure to ensure the heat exchanger tube plugging procedure
was adequate was a performance deficiency. As a result, an auxiliary condenser tube
failed causing a high sodium level in the steam generators and a unit power reduction.
The finding was more than minor because it was associated with the equipment
performance attribute of the Initiating Events cornerstone and adversely affected the
cornerstone objective, in that, it increased the likelihood of those events that upset plant
stability and challenge critical safety functions during power operations. Using
Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process
for Findings At-Power, the finding was determined to be of very low safety significance
(Green) because the finding did not cause a reactor trip and the loss of mitigation
equipment. The finding has a human performance cross-cutting aspect associated with
work practices in that licensee supervision failed to provide appropriate oversight to the
tube plugging procedure and plugging activity H.4(c).
Enforcement. This finding does not involve enforcement action because no violation of a
regulatory requirement was identified. The licensee documented the finding in the
corrective action program as Condition Report CR-2012-011805. Because the finding
does not involve a violation and is of very low safety significance, it is being
characterized as a finding FIN 05000446/2013004-04, Failure to Properly Install
Auxiliary Condenser Tube Plugs Causes Steam Generator Chemistry Excursion and
Unit Power Reduction.
- 17 -
1R19 Post-Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors reviewed the following post-maintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
July 23, 2013, Unit 2, residual heat removal pump 2-02 testing following motor oil
change and breaker maintenance
August 26, 2013, Unit 2, reactor coolant pump under frequency relay testing
following under frequency relay replacement
September 12, 2013, Unit 1, turbine driven auxiliary feedwater pump
post-maintenance verification following governor valve stroke
September 18, 2013, Unit 1, diesel generator 1-02 testing following tachometer
and valve maintenance
September 19, 2013, Unit 2, motor driven auxiliary feedwater post-maintenance
testing following pressure gauge replacement.
September 20, 2013, Unit 1, containment spray pump 1-04 post-maintenance
testing following hand switch and light socket maintenance
The inspectors selected these activities based upon the structure, system, or
component's ability to affect risk. The inspectors evaluated these activities to ensure the
testing was adequate for the maintenance performed, the acceptance criteria were clear,
and the test ensured equipment operational readiness.
The inspectors evaluated the activities against technical specifications, the Final Safety
Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC
generic communications to ensure that the test results adequately ensured that the
equipment met the licensing basis and design requirements. In addition, the inspectors
reviewed corrective action documents associated with post-maintenance tests to
determine whether the licensee was identifying problems and entering them in the
corrective action program and that the problems were being corrected commensurate
with their importance to safety. Specific documents reviewed during this inspection are
listed in the attachment.
These activities constitute completion of six post-maintenance testing samples as
defined in Inspection Procedure 71111.19-05.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to
follow procedures that require initiating a condition report for degradation to
safety-related equipment. During a surveillance activity, maintenance personnel
discovered that a reactor coolant pump under frequency relay was outside the as-found
setpoint tolerance for pick-up frequency and failed to enter the condition into the
- 18 -
corrective action program. As a result, the cause and effect of the degraded condition
was not evaluated and the relay again drifted outside the setpoint tolerance.
Description. On November 2, 2012, maintenance personnel performed a calibration of
under frequency relay 81/2A2 in accordance with Procedure MSE-S2-0665X, Unit 2
RCP Under Frequency Relay TADOT and Channel Calibration Surveillance, Revision 4.
The inspectors reviewed the work order that documented the as-found setpoint criteria
out of tolerance for the reactor coolant pump under frequency relay. The maintenance
personnel adjusted and retested the relay. The relay as-left frequency was within the
calibration limits. The inspectors verified that the work order documentation for the
surveillance test was complete and had been signed by a work supervisor and
operations shift management. The inspectors noted that none of the personnel involved
in the testing of the relay or the review of the work order package initiated a condition
report for the relay being outside the as-found setpoint criteria as required by Procedure
STA-421, Initiation of Condition Reports, Revision 18.
The inspectors determined, through discussion with licensee personnel, that the
personnel involved with the performance of the maintenance activity were not
adequately trained in the management expectation and procedure requirement to initiate
condition reports for as-found setpoints outside the tolerance band, a degraded
condition.
Analysis. The licensees failure to follow procedure and initiate a condition report for
degraded safety-related equipment was a performance deficiency. The finding was
more than minor because if the licensee continues to fail to document degraded
safety-related equipment in the corrective action database, there is a potential that this
could lead to a more significant safety concern, in that the cause of the degradation will
not be evaluated and corrected. Using Inspection Manual Chapter 0609, Appendix A,
The Significance Determination Process for Findings At-Power, the finding was
determined to be of very low safety significance (Green) because the finding was not a
design or qualification deficiency; did not represent an actual loss of safety function of a
system or train; did not represent an actual loss of a technical specification train for
greater than its allowed outage time; and did not result in the loss of one or more trains
of non-technical specification trains of equipment. The finding has a human
performance cross-cutting aspect associated with resources in that the licensee failed to
provide adequate training to personnel performing maintenance H.2(b).
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions of a type appropriate to the circumstances and shall be
accomplished in accordance with these instructions. Procedure STA-421, Initiation of
Condition Reports, Revision 18, Attachment 8.A, Step 6.2 required, in part, that
equipment malfunctions, damage, or degradation, other than anticipated wear will be
documented in a condition report. Contrary to the above, on November 2, 2012, the
licensee performed an activity affecting quality and failed to accomplish the activity in
accordance with the instructions. Specifically, the licensee did not initiate a condition
report for an under frequency relay with an as-found setpoint outside the tolerance band.
Since the violation was of very low safety significance and was documented in the
licensees corrective action program as condition report CR-2013-010078, it is being
treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement
Policy: NCV 05000446/2013004-05, Failure to Initiate a Condition Report for a
Degraded Under Frequency Relay.
- 19 -
1R22 Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors reviewed the Final Safety Analysis Report, procedure requirements,
technical specifications, and corrective action documents to ensure that the surveillance
activities listed below demonstrated that the systems, structures, and components tested
were capable of performing their intended safety functions.
Pump or Valve Inservice Test
July 30, 2013, Unit 2, service water pump 2-02 testing in accordance with
Procedure OPT-207B, Service Water System, Revision 14
Routine Surveillance Testing
August 6, 2013, Unit 1, residual heat removal and safety injection train A testing
in accordance with Procedure OPT-512A, RHR and SI Subsystem Valve Test,
Revision 10
September 5, 2013, Unit 2, steam generator 2-03 wide range level calibration in
accordance with Procedure INC-7412B, Channel Calibration Steam Generator 3
Wide Level, Protection Set II, Channel 0503, Revision 2
September 5, 2013, Unit 2, containment pressure calibration in accordance with
Procedure INC-7856B, Channel Operability Test and Channel Calibration
Containment Channel 0935, Protection Set III, Revision 5
September 11, 2013, Unit 2, diesel generator 2-01 testing in accordance with
Procedure OPT-214B, Diesel Generator Operability Test, Revision 16
September 18, 2013, off-site power sources verification in accordance with
Procedure OPT-215, Class 1E Electrical Systems Operability, Revision 15
The inspectors either witnessed or reviewed test data to verify that the significant
surveillance test attributes were adequate to address the following:
Preconditioning
Evaluation of testing impact on the plant
Acceptance criteria
Test equipment
Procedures
Jumper and lifted lead controls
Test data
Testing frequency and method demonstrated technical specification operability
Test equipment removal
Restoration of plant systems
Fulfillment of ASME code requirements
Updating of performance indicator data
Reference setting data
Annunciators and alarms setpoints
- 20 -
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of six surveillance testing inspection samples (one
pump or valve inservice test, and five routine surveillance testing samples) as defined in
Inspection Procedure 71111.22-05.
b.
Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (71114.06)
a.
Inspection Scope
On July 31, 2013, the inspectors evaluated the conduct of licensee emergency drills to
identify any weaknesses and deficiencies in classification, notification, and protective
action recommendation development activities. The inspectors observed emergency
response operations in the simulator and the emergency operations facility to determine
whether the event classification, notifications, and protective action recommendations
were performed in accordance with procedures. The inspectors also compared any
inspector-observed weakness with those identified by the licensee staff in order to
evaluate the critique and to verify whether the licensee staff was properly identifying
weaknesses and entering them into the corrective action program.
These activities constituted completion of one drill and/or training evolution sample as
defined in Inspection Procedure 71114.06-06.
b.
Findings
No findings were identified.
4.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, and Occupational Radiation Safety
4OA1 Performance Indicator Verification (71151)
.1
Data Submission Issue
a.
Inspection Scope
The inspectors performed a review of the data submitted by the licensee for the second
quarter 2013 performance indicators for any obvious inconsistencies prior to its public
release in accordance with NRC Inspection Manual Chapter 0608, Performance
Indicator Program.
This review was performed as part of the inspectors normal plant status activities and,
as such, did not constitute a separate inspection sample.
- 21 -
b.
Findings
No findings were identified.
.2
Reactor Coolant System Specific Activity (BI01)
a.
Inspection Scope
The inspectors sampled licensee submittals for the reactor coolant system specific
activity performance indicator for Units 1 and 2 for the period from the second
quarter 2012 through the first quarter 2013. To determine the accuracy of the
performance indicator data reported during those periods, performance indicator
definitions and guidance contained in Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The
inspectors reviewed the licensees reactor coolant system chemistry samples, technical
specification requirements, condition reports, and NRC integrated inspection reports to
validate the accuracy of the submittals. The inspectors also reviewed the licensees
condition report database to determine if any problems had been identified with the
performance indicator data collected or transmitted for this indicator and none were
identified.
These activities constitute completion of two reactor coolant system specific activity
samples as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
.3
Reactor Coolant System Leakage (BI02)
a.
Inspection Scope
The inspectors sampled licensee submittals for the reactor coolant system leakage
performance indicator for Units 1 and 2 for the period from the second quarter 2012
through the first quarter 2013. To determine the accuracy of the performance indicator
data reported during those periods, performance indicator definitions and guidance
contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the
licensees operator logs, reactor coolant system leakage tracking data, condition reports,
and NRC integrated inspection reports to validate the accuracy of the submittals. The
inspectors also reviewed the licensees condition report database to determine if any
problems had been identified with the performance indicator data collected or
transmitted for this indicator.
These activities constitute completion of two reactor coolant system leakage samples as
defined by Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
- 22 -
.4
Mitigating Systems Performance Index - Emergency ac Power System (MS06)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index emergency-ac power system performance indicator for Units 1 and 2 for the period
from the third quarter 2012 through the second quarter 2013. To determine the accuracy
of the performance indicator data reported during those periods, the inspectors used
definitions and guidance contained in Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors
reviewed the licensees operator narrative logs, mitigating systems performance index
derivation reports, condition reports, and NRC integrated inspection reports to validate
the accuracy of the submittals. The inspectors reviewed the mitigating systems
performance index component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable Nuclear Energy Institute guidance. The inspectors also
reviewed the licensees condition report database to determine if any problems had been
identified with the performance indicator data collected or transmitted for this indicator
and none were identified.
These activities constitute completion of two mitigating systems performance index
emergency-ac power system samples as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
.5
Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index high pressure injection systems performance indicator for Units 1 and 2 for the
period from the third quarter 2012 through the second quarter 2013. To determine the
accuracy of the performance indicator data reported during those periods, the inspectors
used definitions and guidance contained in Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors
reviewed the licensees operator narrative logs, condition reports, mitigating systems
performance index derivation reports, and NRC integrated inspection reports to validate
the accuracy of the submittals. The inspectors reviewed the mitigating systems
performance index component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable Nuclear Energy Institute guidance. The inspectors also
reviewed the licensees condition report database to determine if any problems had been
identified with the performance indicator data collected or transmitted for this indicator
and none were identified.
These activities constitute completion of two mitigating systems performance index high
pressure injection system samples as defined in Inspection Procedure 71151-05.
- 23 -
b.
Findings
No findings were identified.
.6
Mitigating Systems Performance Index - Heat Removal System (MS08)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index heat removal system performance indicator for Units 1 and 2 for the period from
the third quarter 2012 through the second quarter 2013. To determine the accuracy of
the performance indicator data reported during those periods, the inspectors used
definitions and guidance contained in Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors
reviewed the licensees operator narrative logs, condition reports, mitigating systems
performance index derivation reports, and NRC integrated inspection reports to validate
the accuracy of the submittals. The inspectors reviewed the mitigating systems
performance index component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable Nuclear Energy Institute guidance. The inspectors also
reviewed the licensees condition report database to determine if any problems had been
identified with the performance indicator data collected or transmitted for this indicator
and none were identified.
These activities constitute completion of two mitigating systems performance index heat
removal system samples as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
4OA2 Problem Identification and Resolution (71152)
.1
Routine Review of Identification and Resolution of Problems
a.
Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensees
corrective action program at an appropriate threshold, that adequate attention was being
given to timely corrective actions, and that adverse trends were identified and
addressed. The inspectors reviewed attributes that included the complete and accurate
identification of the problem; the timely correction, commensurate with the safety
significance; the evaluation and disposition of performance issues, generic implications,
common causes, contributing factors, root causes, extent of condition reviews, and
previous occurrences reviews; and the classification, prioritization, focus, and timeliness
of corrective actions. Minor issues entered into the licensees corrective action program
because of the inspectors observations are included in the attached list of documents
reviewed.
- 24 -
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples. Instead, by procedure, they were considered an
integral part of the inspections performed during the quarter and documented in
Section 1 of this report.
b.
Findings
No findings were identified.
.2
Daily Corrective Action Program Reviews
a.
Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees corrective action program. The inspectors
accomplished this through review of the stations daily corrective action documents.
The inspectors performed these daily reviews as part of their daily plant status
monitoring activities, so these reviews did not constitute any separate inspection
samples.
b.
Findings
No findings were identified.
.3
Semi-Annual Trend Review
Inspection Scope
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 the corrective action program and maintenance
backlogs. The inspectors reviewed documents and interviewed personnel to determine
if the licensee completely and accurately identified problems in a timely manner
commensurate with its significance, evaluated and dispositioned operability issues,
considered the extent of condition, prioritized the problem commensurate with its safety
significance, identified appropriate corrective actions, and completed corrective actions
in a timely manner commensurate with the safety significance of the issue.
These activities constitute completion of one semi-annual trend review inspection
sample as defined in Inspection Procedure 71152-05.
b.
Findings
No findings were identified.
.4
Selected Issue Follow-up Inspection
a.
Inspection Scope
The inspectors reviewed the licensees long-term corrective actions taken and planned
to resolve fire protection program noncompliances associated with unapproved operator
manual actions and multiple spurious operations. The licensees long-term corrective
- 25 -
actions spanned several outages and involved modifications designed to prevent or
mitigate adverse impacts to plant equipment identified as necessary to safely shutdown
the reactor in the event of fire. These corrective actions included a regulatory
commitment to complete the operator manual action and multiple spurious operations
implementation plan by the end of the first quarter of 2015.
The inspectors reviewed the licensees modification plans, schedules, and
documentation; revised training program for the licensee staff and contractors involved
with the modifications; compensatory measures associated with the planned corrective
actions; and justification for exceeding the period of enforcement discretion provided in
Enforcement Guidance Memorandum 09-002, Enforcement Discretion for Fire Induced
Circuit Faults, dated May 14, 2009. The inspectors walked down a sample of the plant
modifications that were in progress and a sample of the plant modifications that were
completed.
The inspectors interviewed the managers, engineers, and contractor personnel
responsible for developing and managing the schedule for the planned modifications.
The inspectors ensured the proposed schedule was achievable and discussed potential
actions if adverse impacts affected the timely completion of the modifications. The
inspectors assessed the timeliness of the planned corrective actions in accordance with
the guidance in Regulatory Issue Summary 2005-20, Operability Determinations &
Functionality Assessments for Resolution of Degraded or Nonconforming Conditions
Adverse to Quality or Safety.
The inspectors also discussed the guidance for alternative compensatory measures
contained in Information Notice 97-48, Inadequate or Inappropriate Interim Fire
Protection Compensatory Measures; Regulatory Issue Summary 2005-07,
Compensatory Measures to Satisfy the Fire Protection Program Requirements; and
Inspection Procedure 71111.05T, Fire Protection (Triennial).
These activities constitute completion of one in-depth problem identification and
resolution sample, as defined in Inspection Procedure 71152-05.
b.
Findings
Introduction. The inspectors identified an unresolved item associated with fire-induced
single spurious operations. The inspectors were concerned that a single hot short could
cause the spurious operation of motor-operated valves and bypass their torque/limit
switch, resulting in damage to the pressure boundary.
Description. On February 28, 1992, the NRC issued Information Notice 92-18, Potential
for Loss of Remote Shutdown Capability During a Control Room Fire, to alert licensees
of conditions that could result in the loss of capability to maintain the reactor in a safe
shutdown condition in the event that a control room fire forced operators to evacuate the
control room (i.e., alternative shutdown scenarios).
Information Notice 92-18 was primarily concerned with the loss of control of valves
required for alternative shutdown. Specifically, the Information Notice was concerned
with the potential for hot shorts to cause the spurious operation of these motor-operated
valves and bypass their torque/limit switch, potentially damaging the valves before
operators could transfer control to the remote shutdown panel. In this situation, the
valves may not be able to be operated manually or from the remote shutdown panel.
- 26 -
The licensee evaluated this issue in Engineering Report ER-ME-089, Resolution of
NRC Information Notice 92-18, Potential Loss of Remote Shutdown Capability Following
Control Room Fire, Revision 0, dated December 29, 1993. The licensee evaluated the
population of motor-operated valves that were required to be operated manually or
remotely from the remote shutdown panel for alternative shutdown scenarios. This
population consisted of 86 motor-operated valves. The licensee made modifications as
necessary to ensure that these valves could be operated manually or remotely from the
remote shutdown panel for all alternative shutdown scenarios.
In 2010, the licensee began their evaluation of multiple spurious operations in
accordance with Nuclear Energy Institute Document NEI 00-01, Guidance for Post-Fire
Safe-Shutdown Circuit Analysis, Revision 2. Appendix G to NEI 00-01 contained the
generic list of multiple spurious operations scenarios applicable to pressurized water
reactors. This appendix contained a scenario (MSO-55) that considered valve failure
due to a spurious motor-operated valve operation in conjunction with a short that
bypassed the torque/limit switch. This scenario was described as follows:
General scenario is that fire damage to motor-operated valve circuitry causes
spurious operation. If the same fire causes wire-to-wire short(s) such that the
valve torque and limit switches are bypassed, then the valve motor may stall at
the end of the valve cycle. This can cause excess current in the valve motor
windings as well as valve mechanical damage. This mechanical damage may be
sufficient to prevent manual operation of the valve.
Scenario only applies to motor-operated valves. Note this generic issue may
have already been addressed during disposition of the NRC Information
Notice 92-18. This disposition should be reviewed in the context of multiple
spurious operations and multiple hot shorts.
The licensee formed a multiple spurious operations expert panel, which met in
March 2010, to review the generic list of multiple spurious operations contained in
NEI 00-01. The multiple spurious operations expert panel meeting results were
documented in Engineering Report ER-ME-130, Summary of Expert Panel Activities
Related to Postulation of Multiple Spurious Operations for the CPNPP Fire Safe
Shutdown Analysis, Revision 0, dated April 2010. The licensee initially concluded that
scenario MSO-55 was already addressed in the fire safe shutdown analysis.
On August 17, 2010, the licensee convened a supplemental meeting of the multiple
spurious operations expert panel. The expert panel reconsidered multiple spurious
operations scenario MSO-55 and concluded that a nonconformance existed.
Specifically, the expert panel concluded that the licensee had addressed the concerns
raised in Information Notice 92-18 for alternative shutdown scenarios, but did not
address the concerns for scenarios where operators did not need to evacuate the control
room.
The licensee subsequently evaluated the larger population of motor-operated valves that
are used or must remain intact for post-fire safe shutdown. The licensee concluded that
modifications were needed for 57 valves. Ten of the valves required a mechanical
modification, while the remaining 47 valves required an electrical modification.
- 27 -
The licensee entered this issue into their corrective action program as Condition Report
CR-2010-007806 and implemented compensatory measures. The inspectors identified
an issue of concern with the potential for single spurious operations to damage the
pressure boundary. The inspectors determined that additional inspection is required to
determine if a performance deficiency exists. This issue of concern is being treated as
an unresolved item URI 05000445/2013004-06; 05000446/2013004-06, Potential
Motor-Operated Valve Single Spurious Operation Vulnerability.
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
(Closed) Licensee Event Report 05000445/2011-003-00, Unsuitable Material on
Containment Airlock
The inspectors reviewed the licensee event report that documented several aluminum
components in the personnel and emergency airlocks, which were not compatible with
the post-accident environment in containment. The containment design specifications
limited the use of exposed aluminum and prohibited the use of aluminum in pressure
gauges. However, the containment airlock system included one aluminum body
hydraulic valve and two aluminum pressure gauges in each unit. The use of aluminum
in containment was restricted to limit the potential for chemical reaction with the sodium
hydroxide that would be present during post-accident conditions, which could impact the
physical integrity of the affected components. The inspectors examined maintenance
work orders, written procedures, condition reports, and the licensees root cause
analysis of the event. The licensee removed the affected pressure gauges and replaced
the hydraulic valves. The enforcement aspects of this finding are discussed in
Section 4OA7. This licensee event report is closed.
These activities constitute completion of one follow-up of events and notices of
enforcement discretion sample as defined in Inspection Procedure 71153-05.
4OA5 Other Activities
(Closed) NRC Temporary Instruction 2515/182, Review of the Implementation of the
Industry Initiative to Control Degradation of Underground Piping and Tanks
Leakage from buried and underground pipes has resulted in groundwater contamination
incidents with associated heightened NRC and public interest. The industry issued a
guidance document, Nuclear Energy Institute 09-14, Guideline for the Management of
Buried Piping Integrity, (ADAMS Accession No. ML1030901420) to describe the goals
and required actions (commitments made by the licensee) resulting from this
underground piping and tank initiative. On December 31, 2010, Nuclear Energy Institute
issued Revision 1 to Nuclear Energy Institute 09-14, Guidance for the Management of
Underground Piping and Tank Integrity, (ADAMS Accession No. ML110700122) with an
expanded scope of components which included underground piping that was not in
direct contact with the soil and underground tanks. Nuclear Energy Institute later issued
Nuclear Energy Institute 09-14, Revision 2 in November 2012 (ADAMS Accession No.
ML13086A086 and ML13086A089) and Revision 3 in April 2013 (ADAMS Accession No.
ML13130A322). On November 17, 2011, the NRC issued Temporary Instruction
2515/182, Review of the Implementation of Industry Initiative to Control Degradation of
Underground Piping and Tanks, to gather information related to the industrys
implementation of this initiative.
- 28 -
a.
Inspection Scope
The licensees buried piping and underground piping and tanks program was inspected
in accordance with paragraph 03.02.a of the temporary instruction and it was confirmed
that activities which correspond to completion dates specified in the program which have
passed since the Phase 1 inspection was conducted, have been completed.
Additionally, the licensees buried piping and underground piping and tanks program was
inspected in accordance with paragraph 03.02.b of the temporary instruction and
responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-
experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to the NRC
headquarters staff. Based upon the scope of the review described above, Temporary
Instruction 2515/182 was completed and will be closed.
b.
Findings
No findings were identified.
4OA6 Meetings
Exit Meeting Summary
On September 12, 2013, the inspectors presented the multiple spurious operations
inspection results to Mr. K. Peters, Site Vice President, and other members of the
licensee staff. The licensee acknowledged the issues presented. The inspectors
confirmed that some of the materials examined during the inspection were considered
proprietary. The inspectors verified that no proprietary information was retained by the
inspectors or documented in this report.
On September 12, 2013, the inspectors presented the Temporary Instruction 2515/182
inspection results to Mr. K. Peters, Site Vice President, and other members of the
licensee staff. The licensee acknowledged the issues presented. No proprietary
information was reviewed during the inspection.
On October 2, 2013, the inspectors presented the resident inspection results to
Mr. R. Flores, Senior Vice President and Chief Nuclear Officer, and other members of
the licensee staff. The licensee acknowledged the issues presented. The inspectors
acknowledged review of proprietary material during the inspection. No proprietary
information was documented in the report.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which meet the criteria of the NRC
Enforcement Policy for being dispositioned as a non-cited violation.
Title 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that design
control measures shall assure that appropriate quality standards are specified and that
deviations from such standards are controlled. Contrary to the above, from initial plant
operation until October 2011, the licensee failed to control deviations from standards of
material applications inside containment. Specifically, the licensee failed to identify and
prevent the use of aluminum in multiple containment airlock valve bodies and pressure
gauges in containment. The finding was more than minor because it was associated
- 29 -
with the containment configuration control attribute of the Barrier Integrity cornerstone
and adversely affected the associated cornerstone objective to provide reasonable
assurance that physical design barriers protect the public from radionuclide releases
caused by accidents or events. Using Inspection Manual Chapter 0609, Appendix A,
The Significance Determination Process (SDP) For Findings At-Power, the inspector
determined that the violation is of very low safety significance (Green) because the
finding did not represent an actual open pathway in the physical integrity of reactor
containment. The violation was entered into the licensees corrective action program as
Condition Report CR-2011-005686. The licensee subsequently removed the affected
pressure gauges and replaced the hydraulic valves. This is the enforcement aspect of
the licensee event report discussed in Section 4OA3.
A1-1
Attachment 1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
R. Flores, Senior Vice President and Chief Nuclear Officer
K. Peters, Site Vice President
S. Bradley, Manager, Radiation Protection
D. Goodwin, Director, Work Management
T. Hope, Manager, Regulatory Affairs
B. Kidwell, Manager, Emergency Preparedness
F. Madden, Director, External Affairs
B. Mays, Vice President, Engineering
T. McCool, Vice President, Station Support
D. McGaughey, Director, Performance Improvement
B. Moore, Director, Nuclear Training
K. Nickerson, Director, Engineering Support
B. Patrick, Director, Maintenance
B. Reppa, Director, Site Engineering
S. Sewell, Plant Manager
M. Smith, Director, Nuclear Operations
S. Smith, Plant Manager
K. Tate, Manager, Security
D. Wilder, Director, Plant Support
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed 05000445/2013004-01
Failure to Remove Cable Material from Inside Containment
(Section 1R04)05000445/2013004-02
Failure to Establish Goals and Monitor the Performance of
the Auxiliary Feedwater System (Section 1R12)05000445/2013004-03
Improper Pipe Cap Installation Results in a Unit Shutdown
(Section 1R15)05000446/2013004-04
Failure to Properly Install Auxiliary Condenser Tube Plugs
Causes Steam Generator Chemistry Excursion and Unit
Power Reduction (Section 1R18)05000446/2013004-05
Failure to Initiate a Condition Report for a Degraded Under
Frequency Relay (Section 1R19)
Opened 05000445/2013004-06
Potential Motor-Operated Valve Single Spurious Operation
Vulnerability (Section 4OA2)
A1-2
Closed
05000445/2011-003-00
LER
Unsuitable Material on Containment Airlock (Section 4OA3)
2515/182
TI
Review of the Implementation of the Industry Initiative to
Control Degradation of Underground Piping and Tanks
(Section 4OA5)
LIST OF DOCUMENTS REVIEWED
Section 1R05: Fire Protection
PROCEDURES
NUMBER
TITLE
REVISION
ABN-805B
Response to Fire in the Auxiliary Building or the Fuel
Building
6
FPI-403
Auxiliary Building Elevation 810-6
4
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION
Fire Protection Report
29
M1-1921
Fire Hazard Analysis - Unit 1 Containment and
Safeguards Buildings
Section 1R06: Flood Protection Measures
CONDITION REPORT
2013-007696
Section 1R11: Licensed Operator Requalification Program and Licensed Operator
Performance
PROCEDURE
NUMBER
TITLE
REVISION
ABN-601
Response to a 138/345 KV System Malfunction
12
Section 1R12: Maintenance Effectiveness
CONDITION REPORT
2012-009694
A1-3
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
PROCEDURES
NUMBER
TITLE
REVISION
STA-629
Switchyard Control and Transmission Grid Interface
7
WCI-202
Maintenance Risk Assessment
0
WCI-203
Weekly Surveillance / Work Scheduling
27
STI-600.01
Guarded Equipment Management Program
0
CONDITION REPORT
2013-009613
Section 1R15: Operability Evaluations and Functionality Assessments
PROCEDURE
NUMBER
TITLE
REVISION
SOP-108A
Reactor Coolant Pump
12
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION/DATE
EVAL-2008-
000640-09-00
Discharge Piping Acceptance Criteria for Allowable Void
Fraction
August 31, 2008
2323-MS-24
Specification; Diesel Generator Sets
5
DBD-ME-011
Design Basis Document; Diesel Generator Sets
35
DO-2-S008
Pipe Stress/Pipe Support Final Reconciliation Report
1
M1-0215
Flow Diagram Starting Air Piping CP1-MEDGEE-01
554
Starting Air Receivers DeLaval Part No. 76001-125
7
CONDITION REPORTS
2013-008323
2013-008325
2013-008384
2011-007105
2013-008552
2013-004502
2013-005376
2013-008070
2013-006795
A1-4
Section 1R19: Post-Maintenance Testing
PROCEDURES
NUMBER
TITLE
REVISION
OPT-602B
Train B Motor Driven Auxiliary Feedwater Accumulator
Check Valve Leak Test
4
OPT-206B
Auxiliary Feedwater System
21
OPT-214B
Diesel Generator Operability Test
17
WORK ORDERS
4636007
4469522
4356139
4356150
4645979
CONDITION REPORT
2013-005723
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION
M2-0206
Flow Diagram Auxiliary Feedwater
M2-2206
Instrumentation & Control Diagram Auxiliary Feedwater
System Channel 2455/2458
Section 1R22: Surveillance Testing
PROCEDURES
NUMBER
TITLE
REVISION
OPT-512A
RHR and SI Subsystem Valve Test
10
MSM-P0-3374
Emergency Diesel Generator Monthly Run Related
Inspections
3
INC-7412B
Channel Calibration Steam Generator 3 Wide Level,
Protection Set II, Channel 0503
2
INC-7856B
Channel Operability Test and Channel Calibration
Containment, Channel 0935, Protection Set III
5
WORK ORDERS
4464533
4528096
4575548
4638141
3751148
4050269
3438649
4364545
4386207
4385158
A1-5
MISCELLANEOUS DOCUMENT
TITLE
REVISION
Inservice Test Plan for Pumps and Valves
12
Section 1EP6: Drill Evaluation
PROCEDURES
NUMBER
TITLE
REVISION
ABN-915
Security Events
14
EPP-201
Assessment of Emergency Action Level Emergency
Classification and Plan Activation
12
CONDITION REPORT
CR-2013-008383
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION/DATE
Comanche Peak Emergency Plan
39
Exercise Final Report
EPP-201
Emergency Action Level Technical Basis Document
November 4, 2010
Section 4OA1: Performance Indicator Verification
CONDITION REPORTS
2013-004387
2013-007278
Section 4OA2: Problem Identification and Resolution
DRAWINGS
NUMBER
TITLE
REVISION
SK-0001-10-
000172-03-00
Motor Operated Valve 1-8351A Seal Water Injection
Isolation
0
SK-0001-10-
000172-48-00
Motor Operated Valve 1-8716A Residual Heat Removal
Cross Connect
0
SK-0006-10-
000172-48-00
Motor Operated Valve 1-8804A Residual Heat Removal
Pump-1 to Charging Pumps Schematic Diagram
0
SK-0010-10-
000172-48-00
Motor Operated Valve 1-8809A Residual Heat Removal
System to Cold Leg Isolation Valve
0
A1-6
DRAWINGS
NUMBER
TITLE
REVISION
SK-0012-10-
000172-48-00
Motor Operated Valve 1-8811A Sump to Number 1
Residual Heat Removal Pump Schematic/Ext Conn
Diagram
0
SK-0015-10-
000172-48-00
Motor Operated Valve 1-8812A Refueling Water Storage
Tank to RHR Pump 1 Isolation Schematic/Ext Conn
Diagram
0
ENGINEERING REPORTS
NUMBER
TITLE
REVISION
ER-ME-089
Resolution of the NRC Information Notice IN-92-18,
Potential Loss of Remote Shutdown Capability Following
Control Room Fire
0
ER-ME-129
Identification of Fire Safe Shutdown Manual Action
Resolution Requirements on the Protected Shutdown
Train
3
ER-ME-130
Summary of Expert Panel Activities Related to Postulation
of Multiple Spurious Operations for the CPNPP Fire Safe
Shutdown Analysis
0
MODIFICATIONS
NUMBER
TITLE
REVISION
FDA-2010-
000172-48
MSO-55 (3C) - Mechanical Damage to Pressure
Boundary MOVs
4
PROCEDURES
NUMBER
TITLE
REVISION/DATE
MSG-1060
Electrical Terminations (Wire Sizes 26 AWG thru 10
AWG)
2
NMP-16-40-02
CB&I Nuclear Maintenance Procedure Conduct of
Electrical Work
July 30, 2013
STA-729
Control of Transient Combustibles, Ignition Sources, and
Fire Watches
10
VENDOR DOCUMENTS
NUMBER
TITLE
DATE
WPT-17595
Motor Operated Valve Hot Short Evaluations
April 26, 2012
LTR-SEE-III-11-
320
Comanche Peak 1 & 2 Hot Short Evaluation Results -
Phase 2 Westinghouse Valves
December 21,
2011
A1-7
VENDOR DOCUMENTS
NUMBER
TITLE
DATE
LTR-SEE-III-12-51 Comanche Peak 1 & 2 Hot Short Evaluation Results -
Phase 4 Westinghouse and Copes-Vulcan Valves
April 25, 2012
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
DATE
Initial Notification of 10CFR Part 21 Defect/Failure to
Comply; RSCC Wire & Cable, LLC
May 30, 2012
OMA/MSO Implementation Plan
August 6, 2013
Presentation: Condition Report Stand-down
September 10,
2013
Spreadsheet for 2RF14 Mod Team Design Modifications
Training Presentation: Fire Safe Shutdown Analysis -
Multiple Spurious Operations Issues for OPS
Nov 2012
Training Presentation: Print and Schematic Reading -
Initial Training
N/A
Report
Westinghouse Reactor Coolant Pump Shutdown Seal
Deficiencies
July 26, 2013
CP-201201332
Letter from Luminant Power to NRC, Subject: Comanche
Peak Nuclear Power Plant (CPNPP) Docket Nos. 50-445
and 50-446 Request for Extension of Enforcement
Discretion for Multiple Spurious Operation Circuit
Interactions Resolution
November 8, 2012
EM13.GEL.EW4
Training Presentation: Terminations and Splices, Wire
Size 26 AWG - 10 AWG
N/A
Letter from M. Evans, Director Division of Operating
Reactor Licensing, Office of Nuclear Reactor Regulation
to Mr. R. Flores, Senior Vice President and Chief Nuclear
Officer, Luminant Generation Company; Subject:
Comanche Peak Nuclear Power Plant, Units 1 And 2 -
Denial of Request for Extension of Enforcement
Discretion for Multiple Spurious Operation Circuit
Interactions Resolution (TAC Nos. MF0303 and MF0304)
February 22, 2013
SM06.JPM.ELE
Training Material: JPM-Maintenance Service/Mods
Electrician (Qual Card)
April 23, 2013
CONDITION REPORTS
2010-007806
2012-005653
2013-004082
2013-007901
2013-009429
2011-002717
2013-000140
2013-004125
2013-008463
2013-009439
A1-8
CONDITION REPORTS
2011-002807
2013-002903
2013-005186
2013-009265
2012-003193
2013-003971
2013-006721
2013-009408
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
DRAWINGS
NUMBER
TITLE
REVISION
M2-0245
Flow Diagram Personnel Air Lock
M1-0245
Flow Diagram Airlocks
PROCEDURES
NUMBER
TITLE
REVISION
SOP-907A
Containment Personnel Airlocks
15
SOP-907B
Containment Personnel Airlocks
10
ECE-5.01-08
Electronic Design Change Process
19
ECE-5.01
Design Control Program
23
STA-602
Temporary Modifications and Transient Equipment
Placements
17
STI-422.02
Compensatory Actions and Transient Equipment
Placements
1
WORK ORDERS
4271384
4269660
4271392
4271397
4457537
4164122
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION/DATE
FDA-2012-
000230-01-01
Replace the IRC PAL and EAL Pressure Gauges
June 3, 2013
18.18056.12.204 Evaluation of Pressure Boundary Integrity of 1BS-0053
August 2, 2013
2323-SS-15
Containment Personnel Air Lock, Equipment Hatch, and
Emergency Air Lock
3
2323-MS-614
Pressure Gauges
1
DBD-CS-074
Containment Liner and Penetration
8
DBD-ME-008
Containment Analysis
1
A1-9
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION/DATE
CS-CA-0000-3032 Supplemental Calculation for the Personnel Air Lock
4
CONDITION REPORTS
2011-011952
2013-008349
2011-010804
2013-008947
2013-008412
2013-005162
2013-007660
2013-010275
Section 4OA5: Other Activities
PROCEDURES
NUMBER
TITLE
REVISION/DATE
EPG-9.03
Underground Pipe and Tank Program
4
STA-753
Control of Site Excavation Underground Pipe and Tank
Program Plan
1
0900484.00
Comanche Peak Nuclear Power Plant APEC Survey
1
0900520.401
Site Specific Risk Implementation Analysis
0
MSE-P0-1327
Monthly Cathodic Protection Inspection
6
MSE-P0-1328
Cathodic Protection Annual Survey
1
STA-654
Groundwater Protection Program
9
TS521572
Technical Service Laboratory Report
May 10, 2013
0900514
Soil Analysis for Comanche Peak Nuclear Power Plant
(CPNPP)
1
1016456
Recommendation for an Effective Program to Control the
Degradation of Buried and Underground Piping and
Tanks
1
SA-2009-017
Buried Pipe Program
April 6, 2007
NDE 4.02
ASME Section XI Visual Examination VT-2
6
DRAWINGS
NUMBER
TITLE
REVISION
SK-0024-12-
000027-01-02
General Layout for New Cathodic Protection System
2
D-2722.02-01
Cathodic Protection-Plan & Elevation
6
ISI-M1-0215
Flow Diagram Diesel Fuel Oil Piping CP1-MEDGEE-02
A1-10
CONDITION REPORTS
2011-12305
2012-12465
2010-07291
2009-02371
2009-02370
2009-02702
2010-01386
2012-02877
2013-02211
2012-13332
2013-01875
2013-09396
WORK ORDERS
3894928
4313504
3667839
3953450
3975749
4047802
4509630
4509638
4509694
4075264
A2-1
Attachment 2
Request for Information - Temporary Instruction 2515-182, Review of Implementation of
the Industry Initiative to Control Degradation of Underground Piping and Tanks
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 August 30, 2013, to facilitate
the preparation for the onsite inspection week. Please provide requested documentation
electronically if possible. If requested documents are large and only hard copy formats are
available, please inform the inspectors, 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 at (817) 200-1152.
1.
Organization list of site individuals responsible for the sites underground piping and
tanks program.
2.
Copy of Site Underground Piping and Tanks program.
3.
Date completed and/or schedule for the completion of the following NEI 09-14 Revision1
attributes:
Buried Piping
Procedures and Oversight
Risk Ranking
Inspection Plan
Plan Implementation
Asset Management Plan
Underground Piping and Tanks
Procedures and Oversight
Prioritization
Condition Assessment Plan
Plan Implementation
Asset Management Plan
4.
Location maps of buried and underground piping and tanks identified by the inspectors
from the information requested for the preparation week.
5.
Copy of EPRI document Recommendations for an Effective Program to Control the
Degradation of Buried Pipe.
6.
Self or third party assessments of the Underground Piping and Tanks Program (if any
have been performed).
7.
For any of the NEI 09-14 Revision1 attributes identified below which have been
completed prior to the NRCs onsite inspection, provide written records that demonstrate
that the program attribute is complete:
A2-2
Buried Piping
Procedures and Oversight
Risk Ranking
Inspection Plan
Plan Implementation
Asset Management Plan
Underground Piping and Tanks
Procedures and Oversight
Prioritization
Condition Assessment Plan
Plan Implementation
Asset Management Plan
8.
Please review the attached Questions list and provide the response and/or document
requests. If requested documents are large and only hard copy formats are available,
please inform the inspectors, and provide subject documentation during the first day of
the onsite inspection.
Ques
Resp
Initiative Consistency
Has the licensee taken any deviations to either
of the initiatives?
Yes / No
If so, what deviations have been taken and
what is (are) the basis for these deviations?
Provide documentation of deviations and any
associated corrective action reports.
Does the licensee have an onsite buried piping
program manager (owner)? One or more
dedicated staff(s)?
Yes / No
How many buried piping program owners
have there been since January 1, 2010?
Provide documentation identifying individuals
responsible for the site buried piping program
since January 1, 2010.
How many other site programs are assigned to
the buried piping program owner?
List all site programs that are under the direct
responsibility of the sites buried piping
program owner.
Does the licensee have requirements to
capture program performance, such as system
health reports and performance indicators?
Provide copies of the last 3 systems health
reports (if applicable)
Are these requirements periodic or event
driven?
Periodic / Event Driven / None
Are there examples where these
requirements have been successfully used to
upgrade piping systems or to avert piping or
tank leaks?
Provide documentation related to examples if
applicable
Does the licensee have a program or
procedure to confirm the as-built location of
buried and underground piping and tanks at
the plant?
Yes / No
Has the licensee used this program?
Yes / No
A2-3
Was the program effective in identifying the
location of buried pipe?
Yes / No
For a sample of buried pipe and underground
piping and tanks (sample size at least 1 high
and 1 low risk/priority pipe or tank), did the
risk ranking and/or prioritization process
utilized by the licensee produce results in
accordance with the initiative guidelines, i.e.,
which emphasize the importance of
components which have a high likelihood and
consequence of failure and deemphasize the
importance of components which have a low
likelihood and consequence of failure?
Yes / No
Sample size examined
Provide copy of sites risk ranking documents
including documents pertaining to the actual
risk rankings and methodology used.
Provide documents/drawings and/or list which
identifies the risk ranking for each pipe
segment or tank in each system within the
scope of these programs.
Provide the documents which record/describe
how the risk methodology was applied to
determine the risk of pipe segments or tanks
as selected by the inspector during the
preparation week.
As part of its risk ranking process did the
licensee estimate/determine the total length
of buried/underground piping included in the
initiatives?
Yes / No
As part of its risk ranking process did the
licensee estimate/determine the total length
of high risk buried/underground piping
included in the initiatives?
Yes / No
Preventive Actions / System Maintenance
For buried steel, copper, or aluminum piping
or tanks which are not cathodically protected,
has the licensee developed a technical basis
for concluding that structural (e.g. ASME
Code minimum wall, if applicable) and leak
tight integrity of buried piping can be
maintained?
Yes / No / Not Applicable (no buried steel,
copper, or aluminum piping which is not
cathodically protected)
Is the technical basis provided as justification
by the licensee consistent with the initiative
(including its reference documents) or
industry standards (e.g. NACE SP0169)
Yes / No
Provide documented technical basis including
referencing documents.
For uncoated steel piping, has the licensee
developed a technical basis for concluding
that structural (e.g. ASME Code minimum
wall, if applicable) and leak tight integrity of
buried piping can be maintained?
Yes / No / Not Applicable (no uncoated
buried steel pipe)
Is the technical basis provided as justification
by the licensee consistent with the initiative
(including its reference documents) or
industry standards (e.g. NACE SP0169)?
Yes / No
Provide documented technical basis including
referencing documents.
A2-4
For licensees with cathodic protection
systems, does the licensee have procedures
for the maintenance, monitoring and surveys
of this equipment?
Yes / No / Not Applicable (no cathodic
protection systems)
Are the licensee procedures consistent with
the initiative (including its reference
documents) or industry standards (e.g.
NACE SP0169)?
Yes / No
Provide copy of procedures if applicable.
Is the cathodic protection system, including
the evaluation of test data, being operated
and maintained by personnel knowledgeable
of, or trained in, such activities?
Yes / No
Provide documentation of training or
qualification records of personnel
Is there a program to ensure chase and vault
areas which contain piping or tanks subject
to the underground piping and tanks initiative
are monitored for, or protected against,
accumulation of leakage from these pipes or
tanks?
Yes / No / N/A (No piping in chases or vaults)
Provide copy of program.
Inspection Activities / Corrective Actions
Has the licensee prepared an inspection plan
for its buried piping and underground piping
Yes / No
Does the plan specify dates and locations
where inspections are planned?
Yes / No
Provide copy of inspection plan and
associated implementation procedures
Have inspections, for which the planned
dates have passed, occurred as scheduled
or have a substantial number of inspections
been deferred?
Occurred as scheduled / Deferred
Has the licensee experienced leaks and/or
significant degradation in safety related
piping or piping carrying licensed material
since January 1, 2009?
Leaks Yes / No
Degradation Yes / No
If leakage or significant degradation did
occur, did the licensee determine the cause
of the leakage or degradation?
Yes / No
Based on a review of a sample of root cause
analyses for leaks from buried piping or
underground piping and tanks which are
safety related or contain licensed material,
did the licensee's corrective action taken as a
result of the incident include addressing the
cause of the degradation?
Yes / No / N/A (no leaks)
Provide root cause analyses of identified leaks
if applicable.
Did the corrective action include an
evaluation of extent of condition of the piping
or tanks and possible expansion of scope of
inspections? (Preference should be given to
high risk piping and significant leaks where
more information is likely to be available).
Yes / No / N/A (no leaks)
Provide corrective action documents
concerning leaks if applicable.
A2-5
Based on a review of a sample of NDE
activities which were either directly observed
or for which records were reviewed, were the
inspections conducted using a predetermined
set of licensee/contractor procedures?
Yes / No
Provide list of scheduled NDE activities
scheduled during onsite week and list of NDE
activities that have already been conducted.
Were these procedures sufficiently described
and recorded such that the inspection could be
reproduced at a later date?
Yes / No
Provide copies of NDE procedures for the
various NDE activities that have occurred or
are scheduled to occur.
Were the procedures appropriate to detect
the targeted degradation mechanism?
Yes / No
For quantitative inspections, were the
procedures used adequate to collect
Yes / No
Did the licensee disposition direct or indirect
NDE results in accordance with their
procedural requirements?
Yes / No
Provide sample of direct and/or indirect NDE
results and the subsequent evaluations of
these NDE results.
Based on a sample of piping segments, is
there evidence that licensees are
substantially meeting the pressure testing
requirements of ASME Section XI IWA-
5244?
Yes / No
Provide the completed records for the last
two required Section XI periodic
pressure/flow test on safety-related buried
pipe segments