ML13135A573
| ML13135A573 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 05/15/2013 |
| From: | David Proulx NRC/RGN-IV/DRP/RPB-C |
| To: | Kevin Mulligan Entergy Operations |
| Proulx D | |
| References | |
| IR-13-002 | |
| Download: ML13135A573 (86) | |
See also: IR 05000416/2013002
Text
May 15, 2013
Vice President Operations
Entergy Operations, Inc.
Grand Gulf Nuclear Station
P.O. Box 756
Port Gibson, MS 39150
SUBJECT:
GRAND GULF NUCLEAR STATION - NRC INTEGRATED INSPECTION
REPORT 05000416/2013002
Dear Mr. Mulligan:
On April 6, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Grand Gulf Nuclear Station, Unit 1. The enclosed inspection report documents the
inspection results, which were discussed on April 11, 2013, with you and other members of your
staff.
The inspections examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Five NRC-identified and three self-revealing findings of very low safety significance (Green)
were identified during this inspection. Six of these findings were determined to involve
violations of NRC requirements.
If you contest these non-cited violations, you should provide a response within 30 days of the
date of this inspection report, with the basis for your denial, to the Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the
Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at
Grand Gulf Nuclear Station.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at
Grand Gulf Nuclear Station.
In accordance with 10 CFR 2.390 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
NRC Public Document Room or from the Publicly Available Records (PARS) component of
NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 EAST LAMAR BLVD
ARLINGTON, TEXAS 76011-4511
K. Mulligan
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accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public
Electronic Reading Room).
Sincerely,
/RA/
David L. Proulx, Acting Chief
Project Branch C
Division of Reactor Projects
Docket No.: 50-416
License No.: NPF-29
Enclosure:
Inspection Report 05000416/2013002
w/ Attachment: Supplemental Information
cc w/ encl:
Electronic Distribution for Grand Gulf Nuclear Station
- 1 -
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
05000416
License:
Report:
Licensee:
Entergy Operations, Inc.
Facility:
Grand Gulf Nuclear Station, Unit 1
Location:
7003 Baldhill Road
Port Gibson, MS 39150
Dates:
January 1 through April 6, 2013
Inspectors: R. Smith, Senior Resident Inspector
B. Rice, Resident Inspector
S. Achen, Reactor Inspector
J. Braisted, Reactor Inspector
S. Hedger, Operations Engineer
J. Laughlin, Emergency Preparedness Inspector, NSIR
S. Makor, Reactor Inspector
Approved
By:
David L. Proulx, Acting Branch Chief
Reactor Projects Branch C
Division of Reactor Projects
- 2 -
SUMMARY OF FINDINGS
IR 05000416/2013002; 01/01/2013 - 04/06/2013; Grand Gulf Nuclear Station, Unit 1, Integrated
Resident and Regional Report; Flood Protection Measures, Maintenance Risk Assessments and
Emergent Work Control, Operability Evaluations and Functionality Assessments, Surveillance
Testing, Followup of Events and Notices of Enforcement Discretion.
The report covered a 3-month period of inspection by resident inspectors and announced
baseline inspections by region-based inspectors. Six Green non-cited violations and two Green
findings of significance 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 the failure to ensure
the current transformer structure, the neutral bus housing, and the associated
mounting hardware were installed with adequate clearance to accommodate
thermal expansion. This failure resulted in an automatic reactor scram on
December 29, 2012, and a subsequent scram on January 4, 2013. Following the
second scram on January 4, 2012, the licensee determined the cause of the
scram was a trip of the phase A unit differential relay because of a ground fault
on the A phase of the generator neutral current transformer, due to inadequate
clearances. Immediate corrective actions included removing the damaged
current transformer and modifying the neutral bus housing. The plant scrams
were entered into the corrective action program as Condition Reports CR-GGN-
2012-13290 and CR-GGN-2013-00083.
The failure to install micarta plate bolts in accordance with manufacturer
specifications and ensure that the current transformer structure, the neutral bus
housing, and the associated mounting hardware had adequate clearance is a
performance deficiency. This finding is more than minor because it is associated
with the Initiating Events Cornerstone attribute of human performance and
adversely affected the cornerstone objective to limit the likelihood of events that
upset plant stability and challenge critical safety functions during shutdown and
power operations. Using NRC Inspection Manual Chapter 0609, Attachment 4,
"Initial Characterization of Findings," the inspectors determined that the issue
affected the Initiating Events Cornerstone. In accordance with NRC Inspection
Manual Chapter 0609, Appendix A, The Significance Determination Process
(SDP) for Findings at Power, the inspectors determined that the issue has very
low safety significance (Green) because it caused only a reactor trip and did not
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cause a loss of mitigating equipment relied upon to transition the plant from the
onset of the trip to a stable shutdown condition. The finding has a cross-cutting
aspect in the human performance area associated with the resources component
because the licensee failed to provide adequate work instructions H.2(c)
(Section 4OA3).
- Green. The inspectors reviewed a self-revealing non-cited violation of 10 CFR
50 Appendix B Criterion V, for the failure to provide adequate instructions to
remove foreign material from the exhaust port of relief valve 1B21F047A. As a
result, the valve failed to close at its reset setpoint following a reactor scram on
December 29, 2012. The valve failed to close at its reset setpoint of 1013 psig
and remained open until pressure fell to approximately 675 psig. The immediate
corrective actions were to remove the foreign material exclusion plug from the
exhaust port of valve 1B21-F047A and to ensure no plug was installed in any
other safety relief valve. The licensee entered this issue into the corrective action
program as Condition Report CR-GGN-2013-00100.
The failure to provide adequate instructions to remove foreign material from the
exhaust port of relief valve 1B21F047A is a performance deficiency. This finding
is more than minor because it is associated with the Initiating Events
Cornerstone attribute of human performance and adversely affected the
cornerstone objective to limit the likelihood of events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations.
Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial
Characterization of Findings," the inspectors determined that the issue affected
the Initiating Events Cornerstone. In accordance with NRC Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings at Power, the inspectors determined that the issue has very low safety
significance (Green) because after a reasonable assessment of the degradation,
the finding could not result in exceeding the reactor coolant leak rate for a small
loss of coolant accident because the configuration of the safety relief valve was
such that it would close at approximately 675 psig. Also the finding did not affect
other systems used to mitigate a loss of coolant accident resulting in a total loss
of their function. The finding has a cross-cutting aspect in the area of human
performance associated with the decision-making component because the
licensee did not use a systematic process to make a safety-significant decision.
H.1(a) (Section 4OA3).
Green. The inspectors reviewed a self-revealing finding for the failure to identify
a degraded isophase bus duct view port window, which allowed water to intrude
into the duct and caused an automatic reactor scram on January 14, 2013. The
licensee took corrective action to stop the water intrusion into the isophase bus
duct and to electrically isolate the spare transformer from the energized
transformers. The licensee entered this issue into the corrective action program
as Condition Report CR-GGN-2013-00319.
The failure to identify a degraded isophase bus duct view port window is a
performance deficiency. The finding is more than minor because it is associated
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with the Initiating Events Cornerstone attribute of human performance and
adversely affected the associated cornerstone objective to limit the likelihood of
those events that upset plant stability and that challenge critical safety functions
during power operations. Using NRC Inspection Manual Chapter 0609,
Attachment 4, "Initial Characterization of Findings," the inspectors determined
that the issue affected the Initiating Events Cornerstone. In accordance with
NRC Inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process (SDP) for Findings at Power, the inspectors determined
that the issue has a very low safety significance (Green) because it caused only
a reactor trip and did not cause a loss of mitigating equipment relied on to
transition the plant from the onset of a trip to a stable shutdown condition. The
finding has a cross-cutting aspect in the area of human performance associated
with the decision-making component because the licensee did not use
conservative assumptions in decision-making H.1(b) (Section 4OA3).
Green. The inspectors identified a non-cited violation of Technical Specification
5.4.1.a, for the failure to revise the scram procedure after temporarily modifying
the division-2 circuits that sense first-stage turbine pressure. Specifically, after a
steam sensing line failed, the licensee had introduced a dummy signal into the
subject circuits to comply with technical specifications; however, they failed to
revise Procedure 05-1-02-I-1, Reactor Scram, Revision 117, to reflect this
temporary modification. This resulted in additional scrams during scram recovery
for the scrams on December 29, 2012, and January 4, 2013. Immediate
corrective actions included modifying the scram procedure to require the
operators to turn off the units that provide the dummy signal to the division-2
circuits that sense first-stage turbine pressure following a reactor scram, allowing
the operators to reset the full scram promptly. The licensee entered this issue
into the corrective action program as Condition Report CR-GGN-2013-001259.
The failure to revise Procedure 05-1-02-I-1 following a temporary modification to
the division-2 circuits that sense first-stage turbine pressure is a performance
deficiency. The finding is more than minor because it is associated with the
Initiating Events Cornerstone attribute of human performance and adversely
affected the cornerstone objective to limit the likelihood of events that upset plant
stability and challenge critical safety functions during shutdown as well as power
operations. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial
Characterization of Findings," the inspectors determined that the issue affected
the Initiating Events Cornerstone. In accordance with NRC Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings at Power, the inspectors determined that the issue has very low safety
significance (Green) because it only caused a reactor trip and did not cause the
loss of mitigating equipment relied upon to transition the plant from the onset of
the trip to a stable shutdown condition. The finding has a cross-cutting aspect in
the area of human performance associated with the work practices component
because licensee personnel failed to ensure that procedures impacted by a
temporary modification were properly revised to compensate for the installed
modification H.4(b) (Section 4OA3).
- 5 -
Cornerstone: Mitigating Systems
Green. The inspectors identified a non-cited violation of License Condition
2.C(41), Fire Protection Program, involving the failure to ensure that manhole
MH01 was properly sealed to prevent entry of flammable liquid. Specifically, on
February 20, 2013, four manhole covers had between one to three loose bolts
and evidence of water seepage. These vaults contain safety related cables for
standby service water trains A and B. Immediate corrective actions included
cleaning and tapping the bolt holes to ensure proper thread engagement, adding
work instructions to the preventative maintenance procedure to clean the
manhole bolt holes, and verifying that the other manholes containing safety-
related cables did not have similar issues with loose bolts on the manhole
covers. The licensee entered this issue in their corrective action program as
Condition Report CR-GGN-2013-01348.
This finding is more than minor because it is associated with the Mitigating
Systems Cornerstone attribute of protection against external factors and
adversely affected the cornerstone objective to ensure the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences. Using NRC Inspection Manual Chapter 0609, Attachment 4,
Initial Characterization of Findings, the inspectors determined that the issue
affected the Mitigating Systems Cornerstone and required the use of Inspection
Manual Chapter 0609, Attachment 4, Appendix F, Fire Protection Significance
Determination Process. However, an NRC senior reactor analyst determined
that the unique nature of this performance deficiency did not lend itself to
analysis by the methods provided in Appendix F. Therefore, a Phase 3 analysis
was performed. Based on a bounding analysis, the analyst determined that the
change in core damage frequency was approximately 1.5E-7/yr. The result was
low because of the relatively short periods of time that fuel was actually being
transferred, the low probability of transfer system failures, and the low likelihood
that a loss of normal service water initiator would occur following a fire in the
subject manholes. The finding has a cross-cutting aspect in the human
performance area associated with the resources component because the
licensee did not provide adequate work packages H.2(c) (Section 1R06).
Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,
Criterion V, for the licensees failure to monitor for ice accumulation on the
standby service water cooling towers in accordance with station procedures. On
January 17, 2013, the plant experienced a winter storm but operators did not
implement Standby Service Water System Operating Instruction, 04-1-01-P41-1,
Revision 137, Section 6.2, Cold Weather Operation, which directed the licensee
to monitor the standby service water cooling tower for ice accumulation when
weather conditions existed that could have resulted in icing of the cooling tower
fill material and missile grating. The licensee entered this issue into their
corrective action program as Condition Report CR-GGNS-2013-00426.
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The failure to monitor for ice accumulation in accordance with station procedures
is a performance deficiency. The finding is more than minor because if left
uncorrected, it could lead to a more significant safety concern. Specifically, the
occurrence of ice accumulation on the standby service water cooling towers, if
unmonitored, could cause damage to the fill material and/or the tower missile
gratings, which would render the standby service water system inoperable.
Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial
Characterization of Findings," the inspectors determined that the issue affected
the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings at Power, the inspectors determined that the issue had a very low
safety significance (Green) because it was not a deficiency affecting the design
or qualification of a mitigating system, structure or component, does not
represent a loss of system or function, does not represent a loss of function for
greater than its technical specification allow outage time, and does not represent
a loss of function as defined by the licensees Maintenance Rule program for
greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The finding has a cross-cutting aspect in the human
performance area associated with the work control component because the
licensee failed to appropriately plan work activities based on environmental
conditions that may impact plant structures, systems and components H.3(a)
(Section 1R13).
Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,
Criterion III, Design Control, for the failure of the licensee to maintain design
control, incorporate, verify, and check new instrument drift values, and translate
the design basis requirements for multiple allowable values and trip setpoints
described in the technical specifications into setpoint calculations. During the
review of condition reports associated with an operability review of the licensees
transition from an 18- to 24-month operating cycle in August 2012, inspectors
identified that the licensee failed to maintain design control of multiple setpoint
calculations. In response to NRC inspector questioning, a licensee review of the
calculations identified that three of the 14 calculations reviewed contained
calculated allowable values that differed from the values contained in the
Technical Specifications associated with Level 8 Narrow Range, Reactor Scram
on High SDVP Water Level, and HPCS & RCIC Pump Suction Transfer on High
Suppression Pool Level. An assessment of the calculations also determined that
one other calculation contained an error that was introduced during the
replacement of the high-pressure turbine rotor in a recent refueling outage, which
would require a license amendment request. The licensee entered this condition
in their corrective action program as CR-GGN-2013-00371.
The failure to maintain design control, incorporate, verify, and check new
instrument drift values, and translate the design basis requirements into multiple
allowable values and trip setpoints described in the technical specifications into
facility setpoint calculations is a performance deficiency. This finding is more
than minor because it is associated with the Mitigating Systems Cornerstone
attribute of design control and affected the cornerstone objective of ensuring the
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capability of the safety-related system to respond to initiating events to prevent
undesirable consequences. In accordance with NRC Inspection Manual Chapter
0609, Attachment 4, "Initial Characterization of Findings," the issue was
determined to affect the Mitigating Systems Cornerstone. Using Inspection
Manual Chapter 0609, Appendix A, The Significance Determination Process
(SDP) for Findings at Power, the inspectors determined the finding was of very
low safety significance (Green) because it was a design deficiency confirmed not
to result in a loss of the offsite power supply operability or functionality. This
finding has a cross-cutting aspect in the area of human performance decision-
making because the licensee did not use a systematic decision making process
and did not obtain interdisciplinary input on a risk significant decision H.1(a)
(Section 1R15).
Green. The inspectors identified a non-cited violation of License Condition
2.C(41), Fire Protection Program, for the failure to identify and correct a
condition adverse to fire protection. Specifically, the licensee failed to ensure
that fire brigade members had sufficient access through a scaffold built in the
diesel generator building hallway into the division-1 diesel generator room. The
immediate corrective actions included removing the scaffold in the diesel
generator building hallway. The licensee documented this issue in their
corrective action program as Condition Report CR-GGN-2013-01679.
The failure to take prompt corrective action to ensure adequate access for fire
brigade members through installed scaffolding in the diesel generator building
hallway to the division-1 diesel generator room is a performance deficiency. The
finding is more than because if left uncorrected, it would have the potential to
lead to a more significant safety concern. Specifically, the inability for fire
brigade members to gain access to safety related equipment in timely manner
could result in preventing prompt extinguishing of fires. Using NRC Inspection
Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," the
inspectors determined that the issue affected the Mitigating Systems
Cornerstone. In accordance with NRC Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process (SDP) for Findings at
Power, the inspectors determined that the issue has very low safety significance
(Green) because the finding involved a risk-significant fire area that had an
automatic fire suppression system. The inspectors determined the apparent
cause of this finding was that the licensee did not implement the corrective action
program with a low threshold for identifying scaffolding that could impede fire
brigade member response during a fire. Therefore the finding had a cross-
cutting aspect in the problem identification and resolution area associated with
the corrective action program component because the licensee failed to identify
conditions adverse to fire protection P.1(a) (Section 1R22).
B.
Licensee-Identified Violations
None
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REPORT DETAILS
Summary of Plant Status
Grand Gulf Nuclear Station (GGNS) began the inspection period starting up from a reactor
scram on December 29, 2012. Subsequently:
On January 1, 2013, the licensees tied to the grid and proceeded with power accession.
On January 4, 2013, at 11:37 p.m., during power accession, the reactor scrammed from
94 percent rated thermal power due to a phase A unit differential signal resulting in a
main generator/turbine trip with a reactor scram. The licensee determined the apparent
cause of the scram and commenced startup activities on January 8, 2013, and reached
100 percent rated thermal power on January 11, 2013.
On January 14, 2013, at 6:05 p.m., the reactor scrammed from 100 percent rated
thermal power due to a turbine generator trip caused by a generator neutral time
overcurrent relay tripping. The licensee placed the plant in cold shutdown condition and
conducted an investigation of the event. The licensee determined the apparent cause of
the scram and commenced startup activities on January 27, 2013, and achieved 100
percent rated thermal power on February 6, 2013.
On April 5, 2013, the operators reduced power to 65 percent rated thermal power to
conduct rod pattern adjustment, control rod exercise, channel bow testing and turbine
testing. The operators returned the plant to 100 percent rated thermal power on April 6,
2013.
The plant remained at 100 percent rated thermal power for the remainder of the quarter.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1
Readiness for Seasonal Extreme Weather Conditions
a.
Inspection Scope
The inspectors performed a review of the adverse weather procedures for seasonal
extremes (e.g., extreme high temperatures, extreme low temperatures, or hurricane
season preparations). The inspectors verified that weather-related equipment
deficiencies identified during the previous year were corrected prior to the onset of
seasonal extremes and evaluated the implementation of the adverse weather
preparation procedures and compensatory measures for the affected conditions before
the onset of, and during, the adverse weather conditions.
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During the inspection, the inspectors focused on plant-specific design features and the
procedures used by plant personnel to mitigate or respond to adverse weather
conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis
Report and performance requirements for systems selected for inspection, and verified
that operator actions were appropriate as specified by plant-specific procedures.
Specific documents reviewed during this inspection are listed in the attachment. The
inspectors also reviewed corrective action program items to verify that plant personnel
were identifying adverse weather issues at an appropriate threshold and entering them
into their corrective action program in accordance with station corrective action
procedures. The inspectors reviews focused specifically on the following plant systems:
Standby service water pump house and valve nest rooms
Fire water pump house
Division 1, 2, and 3 diesel generator building breezeway
Plant service water system well switchgear room and plant service water pump
houses
These activities constitute completion of one readiness for seasonal adverse weather
sample as defined in Inspection Procedure 71111.01-05.
b.
Findings
No findings were identified.
.2
Readiness for Impending Adverse Weather Conditions
a.
Inspection Scope
Since thunderstorms with potential tornados and high winds were forecast in the vicinity
of the facility for January 10, 2013, the inspectors reviewed the plant personnels overall
preparations/protection for the expected weather conditions. On January 9, 2013, the
inspectors walked down the standby service water basins, the safety related
transformers, and emergency diesel generators because their safety-related functions
could be affected, or required, as a result of high winds, tornado-generated missiles, or
the loss of offsite power. The inspectors evaluated the plant staffs preparations against
the sites procedures and determined that the staffs actions were adequate. During the
inspection, the inspectors focused on plant-specific design features and the licensees
procedures used to respond to specified adverse weather conditions. The inspectors
also toured the plant grounds to look for any loose debris that could become missiles
during a tornado. The inspectors evaluated operator staffing and accessibility of
controls and indications for those systems required to control the plant. Additionally, the
inspectors reviewed the Updated Final Safety Analysis Report and performance
requirements for the systems selected for inspection, and verified that operator actions
were appropriate as specified by plant-specific procedures. The inspectors also
reviewed a sample of corrective action program items to verify that the licensee-
identified adverse weather issues at an appropriate threshold and dispositioned them
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through the corrective action program in accordance with station corrective action
procedures. Specific documents reviewed during this inspection are listed in the
attachment.
These activities constitute completion of one readiness for impending adverse weather
condition sample as defined in Inspection Procedure 71111.01-05.
b.
Findings
No findings were identified.
1R04 Equipment Alignment (71111.04)
.1
Partial Walkdown
a.
Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
Residual heat removal A following return from shutdown cooling after FO-19-04
Reactor core isolation cooling following surveillance
Low pressure core spray following a surveillance
Standby gas treatment A with B standby gas treatment out of service for
maintenance
Reactor protection system A with B reactor protection system out of service 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 attempted
to identify any discrepancies that could affect the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, Updated Final Safety Analysis Report, technical specification
requirements, administrative technical specifications, 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 inspected 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. Specific
documents reviewed during this inspection are listed in the attachment.
- 11 -
These activities constitute completion of five partial system walkdown samples as
defined in Inspection Procedure 71111.04-05.
c.
Findings
No findings were identified.
.2
Complete Walkdown
a. Inspection Scope
On April 2, 2013, the inspectors performed a complete system alignment inspection of
the low-pressure core spray system to verify the functional capability of the system. The
inspectors selected this system because it was considered both safety significant and
risk significant in the licensees probabilistic risk assessment. The inspectors inspected
the system to review mechanical and electrical equipment line ups, electrical power
availability, system pressure and temperature indications, as appropriate, component
labeling, component lubrication, component and equipment cooling, hangers and
supports, operability of support systems, and to ensure that ancillary equipment or
debris did not interfere with equipment operation. The inspectors reviewed a sample of
past and outstanding work orders to determine whether any deficiencies significantly
affected the system function. In addition, the inspectors reviewed the corrective action
program database to ensure that system equipment-alignment problems were being
identified and appropriately resolved. Specific documents reviewed during this
inspection are listed in the attachment.
These activities constitute completion of one complete system walkdown sample as
defined in Inspection Procedure71111.04-05.
b. Findings
No findings were identified.
1R05 Fire Protection (71111.05)
.1
Quarterly Fire Inspection Tours
a.
Inspection Scope
The inspectors conducted fire protection walkdowns that were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
Electrical penetration room 1A407, 166 foot elevation, auxiliary building
Equipment area 1A417, 166 foot elevation, auxiliary building
Equipment area 1A424, 1A428, 1A434, 166 foot elevation, auxiliary building
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Equipment area 1A403 & 1A420, 166 foot elevation, auxiliary building
Electrical penetration room 1A410, 166 foot elevation, auxiliary building
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 with later
additional insights, their potential to affect equipment that could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event. Using
the documents listed in the attachment, 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. The inspectors also verified that minor issues identified
during the inspection were entered into the licensees corrective action program.
Specific documents reviewed during this inspection are listed in the attachment.
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 February 12, 2013, the inspectors observed a fire brigade activation for a simulated
fire in a non-safety related motor control center on the 139 foot elevation of the auxiliary
building. The observation evaluated the readiness of the plant fire brigade 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 fire fighting 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) smoke
removal operations; (8) utilization of preplanned strategies; (9) adherence to the
preplanned drill scenario; and (10) drill objectives.
These activities constitute completion of one annual fire-protection inspection sample as
defined in Inspection Procedure 71111.05-05.
- 13 -
b.
Findings
No findings were identified.
1R06 Flood Protection Measures (71111.06)
a.
Inspection Scope
The inspectors reviewed the Updated 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 underground bunkers/manholes to verify the adequacy of
sump pumps, level alarm circuits, cable splices subject to submergence, and drainage
for bunkers/manholes; and verified that operator actions for coping with flooding can
reasonably achieve the desired outcomes. The inspectors also inspected the
manholes/vaults listed below. Specific documents reviewed during this inspection are
listed in the attachment.
January/February 2013, manholes/vaults 1, 2, 3, 20, and 21
These activities constitute completion of one bunker/manhole samples as defined in
Inspection Procedure 71111.06-05.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of License Condition
2.C(41), Fire Protection Program, involving the failure to properly seal manhole MH01
to prevent entry of flammable liquid.
Description. On February 20, 2013, during the manhole/vault inspection of manhole
MH01, the licensee inspected all four compartments associated with manhole MH01. At
the inspectors request, the licensee removed the three additional manhole covers that
are not normally removed for the monthly inspection. During the removal of the manhole
covers, the licensee and inspectors discovered that each manhole cover had between
one to three loose bolts. The inspectors noted evidence of water seepage past these
loose bolts, which was contrary to the requirements of Grand Gulf Nuclear Stations
license bases documents for manhole MH01. This manhole contains safety related
cables for standby service water trains A and B. In Section 9.A.5.59 of the Fire Hazard
Analysis for Fire Area 59, the yard area, it is required to seal manhole MH01 with
pressure type water-, gas-, and steam-tight bolted lids, with rubber gaskets, to prevent
the potential entry of any flammable liquid.
The licensee entered this issue in their corrective action program as Condition Report
CR-GGN-2013-01348. Immediate corrective actions included cleaning and tapping the
bolt holes to ensure proper thread engagement, adding work instructions to the
preventative maintenance procedure to clean the manhole bolt holes, and verifying that
the other manholes containing safety related cables did not have similar issues with
- 14 -
loose bolts on the manhole covers. Long term corrective actions include the licensee
adding instructions to their work order to check bolts for tightness for all safety related
manholes each month.
Analysis. The failure to properly seal safety-related manholes to prevent the introduction
of flammable liquid is a performance deficiency. The performance deficiency is more
than minor because it is associated with the Mitigating Systems Cornerstone attribute of
protection against external factors and adversely affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Using NRC Inspection Manual Chapter
0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that
the issue affected the Mitigating Systems Cornerstone and required the use of
Inspection Manual Chapter 0609, Attachment 4, Appendix F, Fire Protection
Significance Determination Process. However, an NRC senior reactor analyst
determined that the unique nature of this performance deficiency did not lend itself to
analysis by the methods provided in Appendix F. Therefore, a Phase 3 analysis was
performed. Based on a bounding analysis, the analyst determined that the change in
core damage frequency was approximately 1.5E-7/yr. The result was low because of
the relatively short periods of time that fuel was actually being transferred, the low
probability of transfer system failures, and the low likelihood that a loss of normal service
water initiator would occur following a fire in the subject manholes. The inspectors
determined the apparent cause of this finding was inadequate work instructions to
ensure manhole cover bolting is securely fastened. Therefore the finding has a cross-
cutting aspect in the human performance area associated with the resources component
because the licensee did not provide adequate work packages H.2(c).
Enforcement. License Condition 2.C(41), Fire Protection Program, states, in part, that
the plant shall implement and maintain in effect all provisions of the Fire Protection
Program as described in the Updated Final Safety Analysis Report. Updated Final
Safety Analysis Report Section 9A.5.59, Fire Area 59, Section 9A.5.59.3.a, required
that manhole MH01 be properly sealed with pressure type water-, gas-, and steam-tight
bolted lids, with rubber gaskets, to prevent the potential entry of any flammable liquid.
Contrary to this, on or before February 20, 2013, the licensee did not properly seal
manhole MH01 in accordance with the fire hazard analysis. The licensee restored
compliance by cleaning and tapping the bolt holes to ensure proper bolt thread
engagement. This violation is being treated as an NCV, consistent with Section 2.3.2.a
of the Enforcement Policy. The violation was entered into the licensees corrective
action program as Condition Report CR-GGN-2013-01348. (NCV 05000461/2013002-
01, Failure to Properly Seal Safety-related Manholes)
1R07 Heat Sink Performance (71111.07)
a.
Inspection Scope
The inspectors reviewed licensee programs to verify heat exchanger performance and
operability for the following heat exchangers:
Division 3 standby diesel generator jacket water coolers
- 15 -
Residual heat removal pump B seal cooler
Standby service water system pump B motor bearing oil cooler
The inspectors verified that testing, inspection, maintenance, and chemistry control
programs are adequate to ensure proper heat transfer. The inspectors verified that the
periodic testing and monitoring methods, as outlined in commitments to NRC Generic
Letter 89-13, utilized proper industry heat exchanger guidance. Additionally, the
inspectors verified that the licensees chemistry program ensured that biological fouling
was properly controlled between tests. The inspectors reviewed previous maintenance
records of the heat exchangers to verify that the licensees heat exchanger inspections
adequately addressed structural integrity and cleanliness of their tubes. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of three triennial heat sink inspection samples as
defined in Inspection Procedure 71111.07-05.
b.
Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
(71111.11)
.1
Annual Inspection [Licensed Operator Requalification (71111.11A)]
The licensed operator requalification program involves two training cycles that are
conducted over a 2-year period. In the first cycle, the annual cycle, the operators are
administered an operating test consisting of job performance measures and simulator
scenarios. In the second part of the training cycle, the biennial cycle, operators are
administered an operating test and a comprehensive written examination. For this
annual inspection requirement the licensee was in the first part of the training cycle.
a.
Inspection Scope
The inspector reviewed the results of the operating tests to satisfy the annual inspection
requirements.
On December 20, 2012, the licensee informed the lead inspector of the following results:
7 of 7 crews passed the simulator portion of the operating test
41 of 41 licensed operators passed the simulator portion of the operating test
40 of 41 licensed operators passed the Job Performance Measure portion of the
examination
- 16 -
The licensed operator that did not pass the Job Performance Measure portion of the
examination has been unable to complete this portion due to medical issues. When the
licensed operator returns from medical leave, then the examination will be completed.
The inspector completed one inspection sample of the annual licensed operator
requalification program.
b.
Findings
No findings were identified.
.2
Quarterly Review of Licensed Operator Requalification Program
a.
Inspection Scope
On March 11, 2013, the inspectors observed a crew of licensed operators in the plants
simulator during requalification as found evaluation. The inspectors assessed the
following areas:
Licensed operator performance
The ability of the licensee to administer the evaluations
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
These activities constitute completion of one quarterly licensed operator requalification
program sample as defined in Inspection Procedure 71111.11.
b.
Findings
No findings were identified.
.3
Quarterly Observation of Licensed Operator Performance
a.
Inspection Scope
On January 2, 2013, 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 due to resuming power ascension following the reactor
scram on December 29, 2012. The inspectors observed the operators performance of
the following activities:
Pre-job brief
- 17 -
Increasing power by withdrawing control rods
Procedural compliance in responding to control room alarms
Technical specifications compliance while moving a control rod that had
previously been by-passed
In addition, the inspectors assessed the operators adherence to plant procedures,
including conduct of operations procedure and other operations department policies.
These activities constitute completion of one quarterly licensed-operator performance
sample as defined in Inspection Procedure 71111.11.
b.
Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12)
a.
Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant systems:
High pressure core spray diesel generator (P81)
Condenser air removal and offgas systems (N62/N64)
The inspectors reviewed events such as where ineffective equipment maintenance has
resulted in valid or invalid automatic actuations of engineered safeguards systems 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)
- 18 -
Verifying 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 constitute completion of two quarterly maintenance effectiveness
samples as defined in Inspection Procedure 71111.12-05.
b.
Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
The inspectors reviewed licensee personnel's 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:
The week of January 7, 2013, during emergent severe weather in the area
The weeks of January 14 and 21, 2013, an assessment of outage risk during
shutdown for FO-19-04
The week of February 4, 2013, during service transformer 11 outage
The week of February 11, 2013, during service transformer 11 outage and
emergent severe weather in the area requiring the licensee to enter orange risk
The week of March 18, 2013, during emergent severe weather in the area
requiring the licensee to enter yellow risk
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
- 19 -
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. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of five maintenance risk assessments and
emergent work control inspection samples as defined in Inspection
Procedure 71111.13-05.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion V, for the licensees failure to monitor for ice accumulation on the
standby service water cooling towers in accordance with station procedures.
Description. On January 17, 2013, the plant experienced a winter storm in which frozen
precipitation was observed in the area. Standby Service Water System Operating
Instruction, 04-1-01-P41-1, Revision 137, Section 6.2, Cold Weather Operation,
directed the licensee to monitor the standby service water cooling tower fill material and
missile grating for ice accumulation when weather conditions exist that could result in
icing of the cooling tower fill material and missile grating. Ice formation on fan blades,
fan shafts, and missile gratings during periods of frozen precipitation could result in fan
blade/shaft damage or destruction and/or blockage of the fan discharge flow path. On
January 18, 2013, the inspectors asked about the results of the monitoring effort and
whether any actions were necessary to mitigate ice accumulation. During discussions
with the shift manager, the inspectors learned that the operations department had
directed the outage control center to perform the procedurally required inspections, but
the inspections were not performed.
The licensee entered this issue into their corrective action program as Condition Report
CR-GGNS-2013-00426. Because the inspectors questions occurred after the ambient
temperature had risen well above freezing, there were no immediate safety concerns.
Analysis. The failure to monitor for ice accumulation in accordance with station
procedures is a performance deficiency. The performance deficiency is more than minor
and therefore a finding because if left uncorrected, it could lead to a more significant
safety concern. Specifically, the occurrence of ice accumulation on the standby service
water cooling towers, if unmonitored, could cause damage to the fill material and/or the
tower missile gratings, which would render the standby service water system inoperable.
Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of
Findings," the inspectors determined that the issue affected the Mitigating Systems
Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix A,
The Significance Determination Process (SDP) for Findings at Power, the inspectors
determined that the issue had a very low safety significance (Green) because it was not
a deficiency affecting the design or qualification of a mitigating system, structure or
component, does not represent a loss of system or function, does not represent a loss of
function for greater than its technical specification allow outage time, and does not
- 20 -
represent a loss of function as defined by the licensees Maintenance Rule program for
greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The finding had a cross-cutting aspect in the human performance
area associated with the work control component because the licensee failed to
appropriately plan work activities based on environmental conditions that may impact
plant structures, systems and components H.3(a).
Enforcement. Title 10 CFR 50, Appendix B, Criterion V states, in part, that activities
affecting quality shall be accomplished in accordance with procedures. Contrary to the
above, an activity affecting quality was not accomplished in accordance with procedures.
Specifically, Procedure 04-1-01-P41-1, Standby Service Water System, Revision 137,
required the licensee to monitor the standby service water cooling tower for icing when
conditions existed that could have resulted in icing of standby service water cooling
tower missile grating and fill material. Contrary to the above, on January 17, 2013, the
licensee failed to monitor for icing on the standby service water cooling tower when
conditions existed that could have resulted in icing of the standby service water cooling
tower fans and fill material. This issue is not an immediate safety concern because the
ambient temperatures rapidly rose above freezing that same day. This violation is being
treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The
violation was entered into the licensees corrective action program as Condition Report
CR-GGN-2013-00426. (NCV 05000416/2013002-02, Failure to Monitor for Ice on
Standby Service Water Towers)
1R15 Operability Evaluations and Functionality Assessments (71111.15)
a.
Inspection Scope
The inspectors reviewed the following assessments:
Safety relief valve did not close following the December 29, 2012, reactor scram,
Standby service water pump house temperature, CR-GGN-2013-00220
Division 3 emergency diesel generator air start system, CR-GGN-2013-00318
Division 1 and 2 diesel generator lube oil pressure low, CR-GGN-2013-00810
Standby service water heat removal, CR-GGN-2013-000957
Emergency safety features room cooler evaluation for the operability of standby
service water system train B and division 2 diesel generator
Non-conservative Tech Spec allowable values, CR-GGN-2012-09971
The inspectors selected these operability and functionality assessments based on the
risk significance of the associated components and systems. The inspectors evaluated
the technical adequacy of the evaluations to ensure technical specification operability
was properly justified and to verify 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
- 21 -
and Updated Final Safety Analysis Report 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. 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 six operability evaluations inspection samples
as defined in Inspection Procedure 71111.15-05. The seventh bulleted item was counted
in Grand Gulf Nuclear Stations 2012005 quarterly inspection report, but the finding is
documented in this inspection report.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion III, Design Control, for the failure to maintain design control,
incorporate, verify, and check new instrument drift values, and translate the design basis
requirements for multiple allowable values and trip setpoints described in the technical
specifications into setpoint calculations.
Description. During the review of condition reports associated with an operability review
of the licensees transition from an 18- to 24-month operating cycle in August 2012,
inspectors identified that the licensee failed to maintain design control of multiple
setpoint calculations. The inspectors questioned whether the licensee had incorporated
all of the existing outstanding calculation changes and numerous allowable values and
trip setpoints described in the GGNS technical specifications. Inspectors also
questioned whether the calculations and values were supported by the plant design. In
response, the licensee investigated and identified the following:
1. CR-GGN-2004-00021 originally identified that the technical specification allowable
value was non-conservative and the analytical limit was protected for nine instrument
setpoint calculations. The licensee also indicated that at that time it was possible to
revise the calculations to show that the existing allowable values are conservative.
2. April 2003, the licensee cancelled the procedure EDP-32 that supported these
particular calculations, but failed to update the affected calculations to reflect this
change that was still referenced in other calculations.
3. CR-GGN-2012-11939 stated that No open CR has been found that tracks the need
to revise these calculations and the associated procedures to correct the problems
originally identified in CR-2004-00021.
Additionally, the licensee performed an investigation that assessed each calculation
of concern to determine if the current Nominal Trip Setpoint value(s) and/or
Allowable Value(s) specified in their Technical Specifications were conservative with
respect to the associated calculations.
- 22 -
4. During the review of the calculations, the licensee identified that three of the 14
calculations reviewed contained calculated Allowable Values that differed from the
values contained in the Technical Specifications. Specifically:
JC-Q1B21-N683-1, Rev. 0, Level 8 Narrow Range
JC-Q1C11-N601-1, Rev. 1, Instrument Uncertainty and Setpoint Determination
for System C71 Loop N601 - Scram Reactor on High SDVP Water Level
JC-Q1E22-N655-1, Rev. 1, Instrument Uncertainty and Setpoint Determination
for Instrument Loops 1E22-N655, 1E22-N636-HPCS & RCIC Pump Suction
Transfer on High Suppression Pool Level
The licensee determined that safety functions associated with the affected Allowable
Values remained Operable due to conservatisms in the Nominal Trip Setpoints and
that current Technical Specification values were conservative with respect to the new
calculated values. The licensee re-performed the calculations to reflect available
margin improvement and captured the identified conditions in their corrective action
program.
5. The licensees assessment of the calculations also determined that one calculation
JC-Q1E31-N685, Revision 0, contained an error. The error was determined to have
been introduced during the replacement of the high-pressure turbine rotor in a recent
refueling outage. The licensee determined that the current Nominal Trip Setpoint
value and allowable value were conservative relative to the new calculated Nominal
Trip Setpoint.
The licensee has submitted a License Amendment Request to the NRC to revise the
allowable value associated with this calculation.
6. The inspectors also reviewed the procedure EN-DC-166, Key Calculation
Identification and Improvement Program, dated July 5, 2012, which identifies a
group of key calculations that will be reviewed by the licensee for accuracy and
consistency with station design and maintained at a higher priority than other site
calculations. Since the condition is associated with non-conservative technical
specification Allowable Values, it also required that an engineering evaluation be
performed. At this time, the licensees engineering change and associated 50.59 is
still in process.
The inspectors reviewed all fourteen calculations that were of concern, as well as the
new calculations for the four calculations that were determined to have
discrepancies. The inspectors also assessed how the licensee ensured the new
conservative Allowable Values were protected and reviewed the spurious trip
avoidance methodology that was used. The inspectors determined that the
available margin between the original calculations and the revised calculations for
the three calculations was maintained within limits specified in procedures.
- 23 -
The licensee entered this issue into their corrective action program as Condition Report
CR-GGN-2013-00371. The immediate corrective actions were that the licensee
determined that safety functions associated with the affected Allowable Values remained
Operable due to conservatisms in the Nominal Trip Setpoints and that current Technical
Specification values were conservative with respect to the new calculated values. The
licensee re-performed the calculations to reflect available margin improvement and
captured the identified conditions in their corrective action program.
Analysis. The failure to maintain design control, incorporate, verify, and check new
instrument drift values, and translate the design basis requirements into multiple
allowable values and trip setpoints described in the technical specifications into facility
setpoint calculations is a performance deficiency. Using Inspection Manual Chapter
0612, the inspectors determined this finding is more than minor because it was
associated with the Mitigating Systems Cornerstone attribute of design control and
affected the cornerstone objective of ensuring the capability of the safety-related system
to respond to initiating events to prevent undesirable consequences. In accordance with
NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of
Findings," the issue was determined to affect the Mitigating Systems Cornerstone. In
accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process (SDP) for Findings at Power, the inspectors determined the
finding was of very low safety significance (Green) because it was a design deficiency
confirmed not to result in a loss of the offsite power supply operability or functionality.
This finding has a cross-cutting aspect in the area of human performance decision-
making because the licensee did not use a systematic decision-making process and did
not obtain interdisciplinary input on a risk significant decision H.1(a).
Enforcement. Title 10 CFR 50, Appendix B, Criterion III, Design Control, the design
basis for structures, systems, and components will be translated into specifications,
drawings, procedures, and instructions and design control measures shall provide for
verifying or checking the adequacy of design, such as by the performance of design
reviews, by the use of simplified methods, or by performance of a suitable testing
program. Contrary to the above, from April 2003 to October 2012, the licensee failed to
adequately translate design basis information into specifications, drawings, procedures,
and instructions, and verify the adequacy of the design by the performance of design
reviews. Specifically, the licensee failed to maintain design control for Calculations JC-
Q1B21-N683-1, JC-Q1C11-N60101, JC-Q1E22-N655-1 that differed from the values
contained in the Technical Specifications, and Calculation JC-Q1E31-N685 contained an
error introduced by the replacement of the high-pressure turbine rotor. This violation is
being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The
violation was entered into the licensees corrective action program as Condition Report
CR-GGN-2013-0037. (NCV 05000416/2013002-03 Failure to Maintain Design Control
of Setpoint Calculations)
- 24 -
1R18 Plant Modifications (71111.18)
.1
a. Inspection Scope
The inspectors reviewed key affected parameters associated with energy needs,
materials, replacement components, timing, heat removal, control signals, equipment
protection from hazards, operations, flow paths, pressure boundary, ventilation
boundary, structural, process medium properties, licensing basis, and failure modes for
the permanent modification listed below.
EC-41836 - A Phase Unit Differential Neutral CT Swap with A Phase
Generator Differential CT
The inspectors verified that modification preparation, staging, and implementation did
not impair emergency/abnormal operating procedure actions, key safety functions, or
operator response to loss of key safety functions; post-modification testing will maintain
the plant in a safe configuration during testing by verifying that unintended system
interactions will not occur; systems, structures and components performance
characteristics still meet the design basis; the modification design assumptions were
appropriate; the modification test acceptance criteria will be met; and licensee personnel
identified and implemented appropriate corrective actions associated with permanent
plant modifications. Specific documents reviewed during this inspection are listed in the
attachment.
This activity constitutes completion of one sample for temporary modification review as
defined in Inspection Procedure 71111.18-05.
b. Findings
No findings were identified.
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:
Source range monitor B following corrective maintenance
Intermediate range monitor E following corrective maintenance
Source range monitors E and F following corrective maintenance
Reactor water cleanup containment isolation valve 1G33-F028 following
corrective maintenance
- 25 -
Reactor core isolation cooling exhaust check valve following corrective
maintenance
Service transformer 11 following periodic maintenance
Engineered safety features transformer 11 following periodic maintenance
Division 2 diesel generator following corrective maintenance
Reactor protection system B following corrective maintenance
The inspectors selected these activities based upon the structure, system, or
component's ability to affect risk. The inspectors evaluated these activities for the
following (as applicable):
The effect of testing on the plant had been adequately addressed; testing was
adequate for the maintenance performed
Acceptance criteria were clear and demonstrated operational readiness; test
instrumentation was appropriate
The inspectors evaluated the activities against the technical specifications, the Updated
Final Safety Analysis Report, 10 CFR 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 nine post-maintenance testing inspection
samples as defined in Inspection Procedure 71111.19-05.
b.
Findings
No findings were identified.
1R20 Refueling and Other Outage Activities (71111.20)
a.
Inspection Scope
The inspectors reviewed the outage safety plan and contingency plans for the forced
outage, conducted January 14, 2013 through January 27, 2013, to confirm that licensee
personnel had appropriately considered risk, industry experience, and previous site-
specific problems in developing and implementing a plan that assured maintenance of
defense in depth. During the forced outage, the inspectors observed post scram actions
and monitored licensee controls over the outage activities listed below.
- 26 -
Configuration management, including maintenance of defense in depth, is
commensurate with the outage safety plan for key safety functions and
compliance with the applicable technical specifications when taking equipment
out of service.
Clearance activities, including confirmation that tags were properly hung and
equipment appropriately configured to safely support the work or testing.
Status and configuration of electrical systems to ensure that technical
specifications and outage safety-plan requirements were met, and controls over
switchyard activities.
Monitoring of decay heat removal processes, systems, and components.
Verification that outage work was not impacting the ability of the operators to
operate the spent fuel pool cooling system.
Reactor water inventory controls, including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss.
Controls over activities that could affect reactivity.
Maintenance of secondary containment as required by the technical
specifications.
Startup and ascension to full power operation, tracking of startup prerequisites.
Licensee identification and resolution of problems related to forced outage
activities.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one other outage inspection sample as defined
in Inspection Procedure 71111.20-05.
b.
Findings
No findings were identified.
1R22 Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, procedure
requirements, and technical specifications to ensure that the surveillance activities listed
below demonstrated that the systems, structures, and/or components tested were
capable of performing their intended safety functions. The inspectors either witnessed
or reviewed test data to verify that the significant surveillance test attributes were
adequate to address the following:
Preconditioning
- 27 -
Evaluation of testing impact on the plant
Acceptance criteria
Test equipment
Procedures
Jumper/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
Engineering evaluations, root causes, and bases for returning tested systems,
structures, and components not meeting the test acceptance criteria were correct
Reference setting data
Annunciators and alarms setpoints
The inspectors also verified that licensee personnel identified and implemented any
needed corrective actions associated with the surveillance testing.
January 3, 2013, division 3 diesel generator 24-hour run and quick restart
January 14, 2013, reactor coolant system leakage surveillance
January 30, 2013, reactor core isolation cooling inservice testing
February 16, 2013, engineers safety features transformer 11 full flow sprinkler
test
February 26, 2013, division 2 diesel generator surveillance
February 27, 2013, local leak rate test for isolation valve 1E12-F406
March 6, 2013, division 1 emergency diesel generator 24-hour run and quick
March 20, 2013, average power range monitor flow bias calibration
April 6, 2013, channel bow testing
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of nine surveillance testing inspection samples as
defined in Inspection Procedure 71111.22-05.
- 28 -
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of License Condition
2.C(41), Fire Protection Program, for the failure to correct a condition adverse to quality
with respect to fire protection. Specifically, after the licensee installed a scaffold in the
hallway near the doorway into the division-1 diesel generator room that interfered with
access into that room, the licensee failed to correct that condition for approximately 2
months.
Description. During January, 2013, the licensee installed a scaffold in the diesel
generator building, to enable workers to access a component for scheduled
maintenance. On March 6, 2013, during a surveillance inspection of the 24-hour run of
the division-1 diesel generator, the inspectors noted that the licensee had placed the
scaffold in the hallway near the access door for the division-1 diesel generator. They
also experienced difficulty transiting through the scaffolding poles to reach the door of
the generator room. After the inspectors told the control room supervisor of this issue,
the licensee determined that the scaffold would adversely affect response of fire brigade
members to a fire in the division-1 diesel generator room, and immediately removed the
scaffold. Through an extent-of-condition review, the licensee determined that two other
scaffolds in the auxiliary building south stairwell above and below the 166 foot elevation
were also blocking fire brigade access. The licensee established alternate routes for the
fire brigade to access areas blocked by these scaffolds. On March 11, 2013, the
licensee removed one scaffold from the south stairwell and modified the other to allow
fire brigade access.
The licensee documented this issue in their corrective action program as Condition
Report CR-GGN-2013-01679. The short-term corrective actions included removing the
scaffold in the diesel generator building hallway. The licensee also removed a scaffold
and modified an additional scaffold in the auxiliary building south stairwell. The
maintenance support superintendent told the inspectors that he had directed scaffolding
personnel to maintain a minimum 36-inch spacing for future scaffolds constructed on
site, and that he plans to work with his fleet peers to implement a change to the fleet
procedure to ensure scaffolds are properly constructed with respect to fire brigade
access.
Analysis. The failure to take prompt corrective action to ensure adequate access for fire
brigade members through installed scaffolding in the diesel generator building hallway to
the division-1 diesel generator room is a performance deficiency. This performance
deficiency is more than minor and is therefore a finding because if left uncorrected, it
would have the potential to lead to a more significant safety concern. Specifically,
continued inability for fire brigade members to gain access to safety related equipment in
timely manner could result in preventing promptly extinguishing fires. Using NRC
Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," the
inspectors determined that the issue affected the Mitigating Systems Cornerstone. In
accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process (SDP) for Findings at Power, the inspectors determined that the
issue has very low safety significance (Green) because the finding involved a
- 29 -
risk-significant fire area that had an automatic fire suppression system. The inspectors
determined the apparent cause of this finding was that the licensee did not implement
the corrective action program with a low threshold for identifying scaffolding that could
impede fire brigade member response during a fire. Therefore the finding had a cross-
cutting aspect in the problem identification and resolution area associated with the
corrective action program component because the licensee failed to identify conditions
adverse to fire protection P.1(a).
Enforcement. License Condition 2.C(41), Fire Protection Program, states, in part, that
the plant shall implement and maintain in effect all provisions of the Fire Protection
Program as described in the Updated Final Safety Analysis Report. Updated Final
Safety Analysis Report Section 9B.2.1.9.c required, in part, that prompt and effective
corrective actions are taken to correct conditions adverse to the Fire Protection Program.
Contrary to this, on or before March 6, 2013, the licensee did not take prompt and
effective actions to correct a condition adverse to the Fire Protection Program.
Specifically, during January, 2013, the licensee installed a scaffold in a diesel generator
building hallway that interfered with fire-brigade access into the diesel generator room,
the licensee did not take action to correct that condition until the inspectors questioned
the scaffold configuration on March 6, 2013. As an immediate corrective action, the
licensee removed the scaffold in the diesel generator building hallway on March 6. This
violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement
Policy. The violation was entered into the licensees corrective action program as
Condition Report CR-GGN-2013-01679. (NCV 05000416/2013002-04, Failure to
Correct a Scaffold Affecting Fire Brigade Access)
Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)
a.
Inspection Scope
The NSIR headquarters staff performed an in-office review of the latest revisions of
various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan
located under ADAMS accession numbers ML12345A425, ML12355A106 and
ML130230023 as listed in the Attachment.
The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in
the revisions resulted in no reduction in the effectiveness of the Plan, and that the
revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to
10 CFR 50. The NRC review was not documented in a safety evaluation report and did
not constitute approval of licensee-generated changes; therefore, this revision is subject
to future inspection. The specific documents reviewed during this inspection are listed in
the Attachment.
These activities constitute completion of three samples as defined in Inspection
Procedure 71114.04-05.
- 30 -
b.
Findings
No findings were identified.
1EP6 Drill Evaluation (71114.06)
.1
Emergency Preparedness Drill Observation
a.
Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on March 5,
2013, to identify any weaknesses and deficiencies in classification, notification, and
protective action recommendation development activities. The inspectors observed
emergency response operations in the simulator control room and the emergency offsite
facility to determine whether the event classification, notifications, and protective action
recommendations were performed in accordance with procedures. The inspectors also
attended the licensee drill critique to compare 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. As part of the inspection, the inspectors reviewed the drill
package and other documents listed in the attachment.
These activities constitute completion of one sample as defined in Inspection
Procedure 71114.06-05.
b.
Findings
No findings were identified.
4OA1 Performance Indicator Verification (71151)
.1
Data Submission Issue
a.
Inspection Scope
The inspectors performed a review of the performance indicator data submitted by the
licensee for the fourth quarter 2012 performance indicators for any obvious
inconsistencies prior to its public release in accordance with 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.
b.
Findings
No findings were identified.
- 31 -
.2
Unplanned Scrams per 7000 Critical Hours (IE01)
a.
Inspection Scope
The inspectors sampled licensee submittals for the unplanned scrams per 7000 critical
hours performance indicator for the period from the first quarter 2012 through the fourth
quarter 2012. To determine the accuracy of the performance indicator data reported
during those periods, the inspectors used definitions and guidance contained in NEI
Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6.
The inspectors reviewed the licensees operator narrative logs, issue reports, event
reports, and NRC integrated inspection reports for the period of January 2012 through
December 2012, 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. Specific documents reviewed are described in the attachment
to this report.
These activities constitute completion of one unplanned scrams per 7000 critical hours
sample as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
.3
Unplanned Power Changes per 7000 Critical Hours (IE03)
a.
Inspection Scope
The inspectors sampled licensee submittals for the unplanned power changes per 7000
critical hours performance indicator for the period from the first quarter 2012 through the
fourth quarter 2012. To determine the accuracy of the performance indicator data
reported during those periods, the inspectors used definitions and guidance contained in
NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 6. The inspectors reviewed the licensees operator narrative logs, issue
reports, maintenance rule records, event reports, and NRC integrated inspection reports
for the period of January 2012 through December 2012, 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. Specific documents
reviewed are described in the attachment to this report.
These activities constitute completion of one unplanned transients per 7000 critical
hours sample as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
- 32 -
.4
Unplanned Scrams with Complications (IE04)
a.
Inspection Scope
The inspectors sampled licensee submittals for the unplanned scrams with
complications performance indicator for the period from the first quarter 2012 through
the fourth quarter 2012. To determine the accuracy of the performance indicator data
reported during those periods, the inspectors used definitions and guidance contained in
NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 6. The inspectors reviewed the licensees operator narrative logs, issue
reports, event reports, and NRC integrated inspection reports for the period of January
2012 through December 2012, 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. Specific documents reviewed are
described in the attachment to this report.
These activities constitute completion of one unplanned scrams with complications
sample 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.
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.
- 33 -
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 and, as such, did not constitute any separate inspection samples.
b.
Findings
No findings were identified.
4OA3 Followup of Events and Notices of Enforcement Discretion (71153)
.1
Reactor Scram Due to Unit Differential Relay Trip
a.
Inspection Scope
On January 4, 2013, Grand Gulf Nuclear Station experienced and unexpected reactor
scram from 94 percent rated thermal power the scram was due to a phase A unit
differential relay tripping, causing the generator lockouts to trip, resulting in a turbine trip
and reactor scram due to being greater than 35 percent power. The inspectors
responded to the plant and verified the site systems responded as designed and that the
operators stabilized the plant in accordance with station procedures. The licensee
determined a ground condition had occurred on the A phase of the generator neutral
current transformer. The ground condition was caused by inadequate spacing between
the current transformer and support bolts. During power operations, thermal expansion
and relative vibration allow the support bolts to make contact with the current
transformer and damage the insulation and cause a ground condition resulting in a main
generator trip and plant scram. The licensee took corrective action to remove the
damaged current transformer and corrected any other bolting issues prior to startup.
These activities constitute completion of one event follow-up as defined in Inspection
Procedure 71153-05.
b. Findings
1. Automatic Reactor Scram Caused by Ground Condition on the A Phase Neutral Current
Transformer
- 34 -
Introduction. The inspectors reviewed a Green self-revealing finding for the failure to
ensure the current transformer structure, the neutral bus housing, and the associated
mounting hardware were installed with adequate clearance to accommodate thermal
expansion. This failure resulted in an automatic reactor scram on December 29, 2012,
and a subsequent scram on January 4, 2013.
Description. On December 29, 2012, while operating at 100 percent rated thermal
power, the plant experienced an automatic reactor scram. Site personnel determined
the scram was caused by a trip of the phase A unit differential relay, which caused the
generator lockouts to trip and resulted in a turbine trip and reactor scram.
The licensee determined that the potential causes of the phase A unit differential relay
trip were either a spurious actuation of the differential relay, a fault in the current
transformer relay circuitry, or an internal fault of a current transformer (CT). Because the
licenses testing and inspection activities did not identify a definite failure mode, the
licensee determined that an intermittent failure of the phase A unit differential relay was
the most-likely cause of the relay trip. The licensee replaced the unit differential relays
for all three phases (A, B, and C), and returned the plant to online operations on
January 1, 2013. The licensee had installed monitoring equipment prior to restart, and
the monitoring equipment did not detect a phase-differential fault while the licensee
brought the generator online.
On January 4, 2012, while operating at 94 percent rated thermal power, the plant
experienced an automatic reactor scram. The licensee determined the cause of the
scram was a trip of the phase A unit differential relay, which caused the generator
lockouts to trip and resulted in a turbine trip and reactor scram. The monitoring
equipment installed following the initial scram indicated a ground condition occurred on
the A phase of the generator neutral CT. The licensee assembled a failure modes
analysis team to inspect the non-accessible areas of the main generator A phase neutral
CT. This team used a boroscope to identify the source of the ground condition. The
boroscope inspection showed that micarta plate bolts on the isophase bus transition box
below the CTs had not been installed according to manufacturer specifications. As a
result, clearance within the bus transition box was not adequate to accommodate the
thermal expansion of the CT structure, the neutral bus housing, and the associated
mounting hardware. Thus, during power operations, thermal expansion and relative
vibration between these components allowed a micarta plate bolt to make contact with
the A phase neutral CT, damage the insulation, and cause a ground condition. The
result was a main generator trip and plant scram.
The licensee entered the plant scrams into their corrective action process as Condition
Reports CR-GGN-2012-13290 and CR-GGN-2013-00083. Immediate corrective actions
included removing the damaged CT and modifying the micarta plate bolts to conform to
manufacturer specifications. The licensee also performed a root-cause analysis to
address recurrence.
Analysis. The failure to install micarta plate bolts in accordance with manufacturer
specifications and ensure that the current transformer structure, the neutral bus housing,
and the associated mounting hardware had adequate clearance is a performance
- 35 -
deficiency. The performance deficiency is more than minor and therefore is a finding
because it is associated with the Initiating Events Cornerstone attribute of human
performance and adversely affected the cornerstone objective to limit the likelihood of
events that upset plant stability and challenge critical safety functions during shutdown
and power operations. Using NRC Inspection Manual Chapter 0609, Attachment 4,
"Initial Characterization of Findings," the inspectors determined that the issue affected
the Initiating Events Cornerstone. In accordance with NRC Inspection Manual Chapter
0609, Appendix A, The Significance Determination Process (SDP) for Findings at
Power, the inspectors determined that the issue has very low safety significance
(Green) because it caused only a reactor trip and did not cause a loss of mitigating
equipment relied upon to transition the plant from the onset of the trip to a stable
shutdown condition. Therefore the finding has a cross-cutting aspect in the human
performance area associated with the resources component because the licensee failed
to provide adequate work instructions H.2(c).
Enforcement. This finding does not involve enforcement action because no violation of a
regulatory requirement was identified. This finding was entered into the licensees
corrective action program as Condition Reports CR-GGN-2012-13290 and CR-GGN-
2013-00083. Because this finding does not involve a violation and is of very low safety
significance, it is identified as a finding (FIN 05000416/2013002-06, Reactor Scram Due
to Ground Fault)
2. Failure to Provide Instructions to Remove Foreign Material from Safety Relief Valve
1B21-F047A Exhaust Port Resulting in the Valve Failing Open Beyond its Reset
Setpoint
Introduction. The inspectors reviewed a Green self-revealing non-cited violation of
10 CFR 50 Appendix B Criterion V, for the failure to provide instructions to remove a
foreign material exclusion plug from the exhaust port of safety relief valve 1B21-F047A,
which resulted in the valves failure to close at its reset setpoint following a reactor scram
on December 29, 2012.
Description. On December 29, 2012, while operating at 100 percent rated thermal
power, the plant experienced an automatic reactor scram due to a turbine trip. Following
the turbine trip/reactor scram and in response to the resulting pressure transient, 11
safety relief valves opened. Those valves opened on their mechanical relief setpoint,
which requires air to open the valves against spring pressure. The valves normally close
when the reset pressure is reached by exhausting air pressure off the valve and allowing
spring pressure to shut the valve. However, on December 29, safety relief valve 1B21-
F047A failed to close at its reset setpoint of 1013 psig, and remained open until steam
pressure dropped to approximately 675 psig. The licensee determined that the valve
was still operable for its safety relief function and its alternate depressurization function,
but inoperable for its mechanical relief function. Based on analysis that the valve was
operable for its safety functions, the licensee left the valve switch in the closed position
instead of the auto position for plant startup. After the plant scrammed again on
January 4, 2013, the licensee made a drywell/containment entry and determined by
physical examination of the valve, that a foreign material exclusion (FME) plug had been
left in the exhaust port of valve 1B21-F047A.
- 36 -
Through an extent-of-condition review, the licensee verified that no FME plug was
inserted into the exhaust port of any other safety relief valve. Through an investigation,
they determined that a lack of work instructions directing the removal of FME plugs was
the reason why the FME plug had been left in the exhaust port of valve 1B21-F047A .
Further review determined that although the licensee had refurbished safety relief valves
themselves in the past, the licensee had recently sent valve 1B21-F047A and several
other valves to a vendor for refurbishment and testing. Further review also revealed that
the vendors processes for completing this work differed from the licensees processes in
at least one noteworthy way: while the licensee had used tape to provide FME covers
over exhaust ports, the vendor installed FME plugs into those ports. The inspectors
considered that when the licensee made the decision to use a vendor to refurbish the
subject valves, they apparently did not recognize this difference, and consequently did
not develop instructions to remove the subject plugs.
The licensee documented this issue in their corrective action program as Condition
Report CR-GGN-2013-00100. The immediate corrective actions were to remove the
FME plug from the exhaust port of valve 1B21-F047A and ensure no other safety relief
valves had FME plugs installed. The licensee has developed long-term corrective
actions to establish detailed work instructions to ensure that no FME plug is left in any
Analysis. The failure to provide instructions to remove a foreign material exclusion plug
from the exhaust port of relief valve 1B21F047A is a performance deficiency. The
performance deficiency is more than minor and therefore, a finding because it is
associated with the Initiating Events Cornerstone attribute of human performance and
adversely affected the cornerstone objective to limit the likelihood of events that upset
plant stability and challenge critical safety functions during shutdown as well as power
operations. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial
Characterization of Findings," the inspectors determined that the issue affected the
Initiating Events Cornerstone. In accordance with NRC Inspection Manual Chapter
0609, Appendix A, The Significance Determination Process (SDP) for Findings at
Power, the inspectors determined that the issue has very low safety significance
(Green) because after a reasonable assessment of the degradation, the finding could
not result in exceeding the reactor coolant leak rate for a small loss of coolant accident
because the configuration of the safety relief valve was such that it would close at
approximately 675 psig. Also the finding did not affect other systems used to mitigate a
loss of coolant accident resulting in a total loss of their function. The licensee
determined that the apparent cause of the finding was that when they decided to ask a
vendor to refurbish safety-relief valves, they did not realize that the vendor would install
FME plugs into the valves exhaust ports, and therefore did not develop instructions to
remove those plugs. Because that decision affected the mechanical relief function of a
safety relief valve, the inspectors considered that decision to be safety-significant.
Therefore, this finding had a cross-cutting aspect in the area of human performance
associated with the decision-making component because the licensee did not use a
systematic process to make a safety-significant decision. H.1(a)
- 37 -
Enforcement. Title 10 CFR 50, Appendix B, Criterion V, states, in part that activities
affecting quality shall be prescribed by procedures appropriate to the circumstances.
Contrary to this requirement, on or before April 18, 2012, an activity affecting quality was
not prescribed by procedures appropriate to the circumstances. Specifically, Procedure
07-S-15-4,Main Steam Safety/Relief Valve Removal and Installation, Revision 16,
Step 7.15, did not include instructions to remove FME plugs from the exhaust port air
control block of safety relief valves. The licensee has developed corrective actions to
establish detailed work instructions to ensure that no FME plug is left in any safety relief
valve. This violation is being treated as an NCV, consistent with Section 2.3.2.a of the
Enforcement Policy. The violation was entered into the licensees corrective action
program as Condition Report CR-GGN-2013-00100. (NCV 05000416/2013002-06,
Inadequate Procedure for Removal of a Foreign Material Exclusion Plug)
.2
Reactor Scram Due to Neutral Time Overcurrent Relay Trip
a.
Inspection Scope
On January 14, 2013, the plant experienced an automatic reactor scram from 100
percent rated thermal power. The scram was due to a neutral time overcurrent relay
tripping, causing a generator lockouts to trip, resulting in a turbine trip and reactor scram
due to being greater than 35 percent power. The inspectors responded to the site and
verified the plant systems responded as designed, and that the operators stabilized the
plant in accordance with station procedures. The licensee determined that the ground
that was detected on the bus was caused by water intruding the isophase bus duct
through a degraded viewing port on top of the isophase bus duct and accumulating in
the vertical sections of the duct, collecting on a seal-off bushing which served as a
barrier in bus ducts to re-direct air flow to the spare transformer. The collection of water
on the seal-off bushings resulted in grounding of the main conductor to the duct wall that
in turn resulted in the neutral time overcurrent relay to pick up, which resulted in the
turbine generator trip. The licensee took corrective measures to stop the water intrusion
into the isophase bus duct and to electrically isolate the spare transformer from the
energized transformers prior to startup.
b.
Findings
1. Failure to Identify a Degraded Isophase Bus Duct Resulting in Automatic Reactor Scram
Introduction. The inspectors reviewed a Green self-revealing finding for the failure to
identify a degraded isophase bus duct view port window which allowed water to intrude
into the isophase bus duct, and caused an automatic reactor scram on January 14,
2013.
Description. On October 2, 2012, the licensee generated condition report CR-GGN-
2012-11250 documenting cracked isophase bus duct viewing port windows. They
closed this condition report to condition report CR-GGN-2012-11188, in which they were
performing an apparent cause evaluation (ACE) for a degraded viewing-port window.
Procedure EN-LI-119, Apparent Cause Evaluation Process, Revision 16, requires that
the extent-of-condition review identify the total population of items that have or may have
- 38 -
the same problem as the one being evaluated. However, for the CR-GGN-2012-11188
ACE, the licensee limited the extent-of-condition review to only those viewing ports that
they could see from the ground. The licensee specifically did not identify the view ports
on top of the bus ducts as being susceptible to the same issues identified in the two
condition reports. This resulted in missing an opportunity to identify degraded viewing
ports on top of the isophase bus ducting.
On January 14, 2013, at 6:05 p.m., while operating at 100 percent rated thermal power,
the plant experienced an automatic reactor scram. Site personnel determined that the
scram was caused by a turbine generator trip resulting from tripping a generator neutral
time overcurrent relay. Their investigation detected a ground on the bus. They
determined that the cause of the grounded condition was water entering the isophase
bus duct through a degraded viewing port on top of the isophase bus duct. This water
accumulated in the vertical sections of the duct and collected on a seal-off bushing,
which served as a barrier in the bus ducts to re-direct air flow to the spare transformer.
The collection of water on the seal-off bushings resulted in the grounding of the main
conductor to the duct wall. This then resulted in the neutral time overcurrent relay picking
up and caused the turbine generator trip. The licensee took corrective measures to stop
the water intrusion into the isophase bus duct and to electrically isolate the spare
transformer from the energized transformers.
The licensee documented this issue in their corrective action program as Condition
Report CR-GGN-2013-00319. The corrective actions included adding a design change
to stop water intrusion into the isophase bus duct by replacing the viewing ports on top
of the duct with bolted down metal plates and gaskets. The licensee also performed a
root-cause analysis to address recurrence.
Analysis. The failure to identify a degraded isophase bus duct view port window is a
performance deficiency. This performance deficiency is more than minor and therefore
is a finding because it is associated with the Initiating Events Cornerstone attribute of
human performance and adversely affected the associated cornerstone objective to limit
the likelihood of those events that upset plant stability and that challenge critical safety
functions during power operations. Using NRC Inspection Manual Chapter 0609,
Attachment 4, "Initial Characterization of Findings," the inspectors determined that the
issue affected the Initiating Events Cornerstone. In accordance with NRC Inspection
Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings at Power, the inspectors determined that the issue has a very low safety
significance (Green) because it only caused a reactor trip and did not cause a loss of
mitigating equipment relied on to transition the plant from the onset of a trip to a stable
shutdown condition. The most-significant contributing cause to the performance
deficiency was that the licensee had decided to not inspect the viewing ports on the top
side of the isophase bus duct because they had assumed that those ports were not
degraded. Therefore, the finding has a cross-cutting aspect in the area of human
performance associated with the decision-making component because the licensee did
not use conservative assumptions in decision-making H.1(b).
Enforcement. This finding does not involve enforcement action because no violation of a
regulatory requirement was identified. This finding was entered into the licensees
- 39 -
corrective action program as Condition Report CR-GGN-2013-00319. Because this
finding does not involve a violation and is of very low safety significance, it is identified
as a finding. (FIN 05000416/2013002-07, Reactor Scram Due to Moisture in Isophase
Bus Duct )
2. Failure to Revise the Scram Procedure After Temporarily Modifying the Division-2
Circuits that Sense First-Stage Turbine Pressure
Introduction. The inspectors identified a Green non-cited violation of Technical
Specification 5.4.1.a, for the failure to revise the scram procedure after temporarily
modifying the division-2 circuits that sense first-stage turbine pressure. Specifically, due
to a failed steam sensing line, the licensee had introduced a dummy signal into the
subject circuits to comply with technical specifications; however, they had failed to revise
the scram procedure to reflect this temporary modification. This resulted in additional
scrams during scram recovery for the scrams on December 29, 2012, and January 4,
2013.
Description. On February 16, 2013, during follow up interviews for reactor scrams that
occurred on December 29, 2012, January 4, 2013, and January 14, 2013, the inspectors
questioned the cause of the repeat scrams following the original scrams, and discussed
issues with controlling reactor water level. The operators referenced Procedure 05-1-02-
I-1, Reactor Scram, Revision 117, that allowed them to reset the scram and then insert
the intermediate-range power detectors into the core one channel at a time to avoid a full
scram. However, with dummy signals applied to the division-2 circuits that sense first-
stage turbine pressure, they could reset only the division-1 side of the scram. The
licensee had temporarily installed this dummy signal to ensure that a reactor scram
circuit would actuate a reactor scram following a turbine trip with reactor power greater
than 35 percent rated thermal power. However, with power below 35 percent rated
thermal power and the signal applied, the dummy signal would not allow operators to
reset the half-scram on the division 2 side. Consequently, when the operators complied
with the scram procedure and inserted the intermediate-range power detectors into the
core on the division-1 side, they received intermittent spikes on division-1 instruments,
resulting in full scrams. Also, with the inability to reset the scram due to this alignment of
the first stage sensing circuits on the division 2 side, control rod drive system injection
added water to the reactor vessel, which complicated reactor water level control.
The licensee documented this issue in their corrective action program as Condition
Report CR-GGN-2013-001259. The short-term corrective actions included modifying the
scram procedure to require the operators to turn off the units that provide the dummy
signal to the division-2 circuits that sense first-stage turbine pressure following a reactor
scram, allowing the operators to reset the full scram promptly.
Analysis. The failure to revise Procedure 05-1-02-I-1 following a temporary modification
to the division-2 circuits that sense first-stage turbine pressure is a performance
deficiency. This performance deficiency is more than minor and therefore, a finding
because it is associated with the Initiating Events Cornerstone attribute of human
performance and adversely affected the cornerstone objective to limit the likelihood of
events that upset plant stability and challenge critical safety functions during shutdown
- 40 -
as well as power operations. Using NRC Inspection Manual Chapter 0609, Attachment
4, "Initial Characterization of Findings," the inspectors determined that the issue affected
the Initiating Events Cornerstone. In accordance with NRC Inspection Manual Chapter
0609, Appendix A, The Significance Determination Process (SDP) for Findings at
Power, the inspectors determined that the issue has very low safety significance
(Green) because it only caused a reactor trip and did not cause the loss of mitigating
equipment relied upon to transition the plant from the onset of the trip to a stable
shutdown condition. The finding had a cross-cutting aspect in the area of human
performance associated with the work practices component because licensee personnel
failed to ensure that procedures impacted by a temporary modification were properly
revised to compensate for the installed modification H.4(b).
Enforcement. Technical Specification 5.4.1.a requires that written procedures be
established, implemented, and maintained as recommended by NRC Regulatory Guide
1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A,
Section 1j recommends procedures for Bypass of Safety Functions and Jumper
Control. Procedure EN-DC-136, Temporary Modifications, Revision 8, Step 4.4[1],
implements this requirement and states, in part, that the operations manager, Ensures
development of new or revision of existing Operations procedures required to reflect the
configuration as affected by the Temporary Modification Package. Contrary to the
above, a procedure recommended by Regulatory Guide 1.33 was not implemented.
Specifically, on June 21, 2012, the operations manager did not ensure the development
of a new or revisions of existing operations procedures required to reflect the
configuration as affected by the Temporary Modification Package. Specifically, on June
21, 2012, after the licensee implemented a temporary modification that inserted a
dummy signal into the division-2 circuits that sense first-stage turbine pressure due to a
failed steam sensing line to comply with technical specifications, but the operations
manager did not ensure that Procedure 05-1-02-I-1, Reactor Scram, Revision 117 was
revised to reflect the temporary modification. As an immediate corrective action, the
licensee revised that procedure to require the operators to turn off the units that provide
the dummy signal to the subject circuits following a reactor scram. This violation is being
treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The
violation was entered into the licensees corrective action program as Condition Report
CR-GGN-2013-01259. (NCV 05000416/2013002-08, Failure to Revise the Scram
Procedure After Temporary Modification)
4OA5 Other Activities
.1
Temporary Instruction 2515/182 - Review of the Implementation of the Industry Initiative
to Control Degradation of Underground Piping and Tanks
a. Inspection Scope
The inspectors reviewed the licensees programs for buried pipe and underground piping
and tanks to ensure that the attributes recommended in NEI 09-14 Rev. 1 are contained
in the licensees program. These attributes are listed in sections 3.3 A and 3.3 B of NEI
09-14 Rev. 1. The inspectors also reviewed the licensees programs for buried piping
- 41 -
and tanks to ensure the completion dates recommended by NEI 09-14 Rev. 1 are
contained in the licensees program. Furthermore, the inspectors reviewed the
licensees program to ensure that activities which correspond to specified completion
dates which have passed, have been completed.
The licensees buried piping and underground piping and tanks program was inspected
in accordance with paragraphs 03.01.a through 03.01.c (Phase 1) of the TI and was
found to meet all applicable aspects of NEI 09-14 Rev. 1, as set forth in Table 1 of the TI.
b. Findings
No findings were identified.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On January 16, 2012, the inspector presented inspection results to Mr. B. Ford, Senior
Licensing Manager (Corporate), and other members of the licensees staff. The licensee
acknowledged the issues presented. The inspector asked the licensee whether any materials
examined during the inspection should be considered proprietary. Any proprietary
documentation that was reviewed during the inspection was returned to the licensee or
disposed of appropriately.
The lead inspector obtained the final annual examination results and telephonically exited with
Mr. R. Collins, Superintendent, Simulator Support and Training, on February 6, 2013. The
inspector did not review any proprietary information during this inspection.
On March 1, 2013, the inspectors presented the final inspection results for the tri-annual heat
exchanger inspection, to Jay Miller, General Manager, Plant Operations, and other members of
the licensee staff. The licensee acknowledged the issues presented. The inspector asked the
licensee whether any materials examined during the inspection should be considered
proprietary. No proprietary information was identified.
On April 11, 2013, the inspectors presented the inspection results to Kevin Mulligan, Site Vice
President of Operations, and other members of the licensee staff. The licensee acknowledged
the issues presented. The inspector asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary information was identified.
4OA7 Licensee-Identified Violations
None.
A-1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
W. Barlow, Heat Exchanger System Engineer
M. Causey, Senior Lead Technical Specialist
D. Chipley, Electrical Design Engineer
R. Collins, Superintendent, Simulator Support and Training
J. Dorsey, Security Manager
W. Drinkard, RHR System Engineer
H. Farris, Assistant Operations Manager
J. Gerard, Interim Operations Manager
J. Giles, Manager, Training
D. Jones, Chief Engineer
C. Justiss, Licensing
V. Kirk, SSW System Engineer
C. Lewis, Manager, Emergency Preparedness
J. Miller, General Plant Manager
R. Miller, Manager, Radiation Protection
K. Mulligan, Site Vice President Operations
L. Patterson, Manager, Program Engineering
C. Perino, Director, Nuclear Safety Assurance
R. Scarbrough, Specialist and Lead Offsite Liaison, Licensing
J. Seiter, Licensing
J. Shaw, Manager, System Engineering
T. Thurmon, Supervisor, Design Engineering-Mechanical
D. Wiles, Engineering Director
A-2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed 05000416/2013002-01 NCV Failure to Properly Seal Safety-related Manholes (Section 1R06.b)05000416/2013002-02 NCV Failure to Monitor for Ice on Standby Service Water Towers
(Section 1R13.b)05000416/2013002-03 NCV Failure to Maintain Design Control for Setpoint Calculations
(Section 1R15.b)05000416/2013002-04 NCV Failure to Correct a Scaffold Affecting Fire Brigade Access
(Section 1R22.b)05000416/2013002-05 FIN
Automatic Reactor Scram Caused by Ground Condition on the A
Phase Neutral Current Transformer (Section 4OA3.1.b)05000416/2013002-06 NCV Inadequate Procedure for Removal of a Foreign Material Exclusion
Plug (Section 4OA3.1.b)05000416/2013002-07 FIN
Reactor Scram Due to Moisture in Isophase Bus Duct
(Section 4OA3.2.b)05000416/2013002-08 NCV Failure to Revise the Scram Procedure After Temporary
Modification (Section 4OA3.2.b)
Discussed
Temporary Instruction
2515/182
TI
Review of the Implementation of the Industry Initiative to Control
Degradation of Underground Piping and Tanks
A-3
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
PROCEDURES
NUMBER
TITLE
REVISION
04-1-01-N71-3
System Operating Instruction Auxiliary Cooling Tower
System
19
Emergency Evacuation
3
06-TE-1000-V-
0001
Culvert No. 1 Embankment Stability Inspection/Survey
100
05-1-02-VI-2
Off Normal Event Procedure Hurricanes, Tornados, and
Severe Weather
120
04-1-03-A30-1
Equipment Performance Instruction, Cold Weather
Protection
23
04-1-01-P41-1
Standby Service Water System
136
OTHER DOCUMENTS
NUMBER
TITLE
REVISION
96/1022-00
Engineering Request Form, GGCR 1996-0553-00, GNRI
97/00074
2
CONDITION REPORTS
A-4
WORK ORDERS
WO 52377825 01
Section 1R04: Equipment Alignment
PROCEDURES
NUMBER
TITLE
REVISION
04-1-01-E51-1
System Operating Instruction, Reactor Core Isolation
Cooling
131
04-1-01-E12-1
System Operating Instruction, Residual Heat Removal A
142
Housekeeping/Facility and Grounds Maintenance
3
01-S-07-9
Industrial Safety and Housekeeping Inspections
29
04-1-01-T48-1
System Operating Instruction: Standby Gas Treatment
34
04-1-01-E21-1
System Operating Instruction: Low Pressure Core Spray
38
01-S-07-43
Control of Loose Items, Temporary Electrical Power, and
Access to Equipment
6
General Industrial Safety Requirements
12
Control of Scaffolding
9
04-1-01-C71-1
System Operating Instruction: Reactor Protector System
33
OTHER DOCUMENTS
NUMBER
TITLE
REVISION
System Health Report: E21- Low Pressure Core Spray
April 3, 2013
GLP-OPS-E2100 Operator Training: Low Pressure Core Spray (LPCS)
System - E21
10
GFIG-OPS-
E2100
Figure 4, LPCS Pump and Valve Control Logic
GFIG-OPS-
E2100
Figure 1, Low Pressure Core Spray (LPCS) System
E21 Low Pressure Core Spray System Power Point
Presentation
A-5
CONDITION REPORTS
A-6
ENGINEERING CHANGES
EC No.: 26182, Rev 0
EC No.: 28897, Rev 0
EC No.: 25801, Rev 0
WORK ORDERS
WO 00284166 01
Section 1R05: Fire Protection
PROCEDURES
NUMBER
TITLE
REVISION
06-OP-SP64-M-
0047
Unit I Fire Hose Station and Fire Extinguisher Maintenance
115
Fire Pre-Plan A-
Set Down Are Passage - 1A424, Spent Fuel Cask Handling
1
A-7
Section 1R05: Fire Protection
PROCEDURES
NUMBER
TITLE
REVISION
35
Area - 1A427, Set Down Area Passage - 1A428, Water
Sampling Station - 1A429, Set Down Area Passage - 1A434
Fire Pre-Plan A-
31
Misc Equip Area Passages 1A403 & 1A420 Area 7 Elevation
166
0
Fire Pre-Plan A-
33
Motor Control Center Room 1A410 Area 7 Elevation 166
0
Fire Pre-Plan A-
32
Motor Control Center Room 1A407 Area 8 Elevation 166
0
Fire Pre-Plan A-
29
Passage Area - 1A401, Misc Equip Area - 1A417, Area
Elevation 166
1
Fire Brigade Drills, February 12, 2013
1
DRAWINGS
NUMBER
TITLE
REVISION
M-7103
Hose Station and Fire EXT. Locations Auxiliary Building and
Containment Plan at Elevation 161-10 and 166-0 Unit 1
1
CONDITION REPORTS
Section 1R06: Flood Protection Measures
OTHER DOCUMENTS
NUMBER
TITLE
9645-E-029.0
Technical Specification for 9,000-volt Power Cable
CONDITION REPORTS
A-8
WORK ORDERS
WO 52425152 01
WO 52425153 01
WO 52462227 01
WO 52463541 01
WO 52464573 01
WO 00322812 01
WO 00308173 01
WO 00307759 01
WO 00303319 01
WO 00342828 01
WO 00342829 01
WO 00264016 01
Section 1R07: Heat Sink Performance
PROCEDURES
NUMBER
TITLE
REVISION
04-1-03-P41-2
SSW B Chemical Addition Run
6
04-1-03-P41-3
SSW C Chemical Addition Run
2
06-OP-1P41-M-0001
HPCS Service Water Operability Check
101
06-OP-1P41-M-0004
Standby Service Water (SSW) Loop A Operability
Check
109
06-OP-1P41-M-0005
Standby Service Water (SSW) Loop B Operability
Check
112
06-OP-1P41-Q-0004
Standby Service Water Loop A Valve and Pump
Operability Test
121
06-OP-1P41-Q-0006
HPCS Service Water System Valve and Pump
Operability Test
113
08-S-03-10
Chemistry Sampling Program
49
A-9
Section 1R07: Heat Sink Performance
PROCEDURES
NUMBER
TITLE
REVISION
17-S-03-29
GL-89-13 Thermal Performance Data Collection and
Analysis
6
17-S-06-22
SSW A Performance
12
Heat Exchanger Performance and Condition
Monitoring
4
Component Performance Monitoring
7
EN-EP-S-039-G
Testing Standard for Safety-Related Heat
Exchangers Cooled by Standby Service Water
2
CALCULATIONS
NUMBER
TITLE
REVISION
8.9.2-N
Alternate Shutdown Cooling
1
MC-Q1P41-09008 Tornado, Seismic and Thermal Performance Analysis of the
Stainless Steel Fill Replacement for SSW Cooling Towers
0
MC-Q1P41-11001 GGNS Standby Service Water Ultimate Heat Sink Thirty
Day Performance at EPU
0
MC-Q1P41-86007 Standby Service Water Ultimate Heat Sink Performance
0
MC-Q1P41-97020 Determination of Minimum Allowable SSW Flows (LOCA
Lineup) to Safety Related Heat Exchangers
9
MC-Q1P81-97034 Division 3 Engine Heat Rejection Rate
0
A-10
DRAWINGS
NUMBER
TITLE
REVISION
105D5106
Interface Control Pump & Motor First Made for Residual
Heat Removal System
5-046-12-102-004 Engine Jacket Water Cooler #12102 CPK
1
M-087.0-
Q1P41C001A-A-
1.1-004
Outline Induction Motor
0
M-92200
CCW Heat Exchanger
6
VPF-KA3636-013 Heat Exchanger Specification Sheet - Jacket Water
Cooler
A
OTHER DOCUMENTS
NUMBER
TITLE
REVISION/
DATE
1E12C002B - RHR B Seal Cooler Flow Rate
February 22,
2013
1P41C001B - SSW B Pump Motor Cooler Flow Rate
February 22,
2013
Heat Exchanger Program Health Report
February 5, 2013
List of Generic Letter 89-13 Heat Exchanger Baseline
Eddy Current Testing Dates and Work Orders
February 28,
2013
PM Basis for Heat Exchangers
2
Service Water System Health Report
February 5, 2013
A-11
OTHER DOCUMENTS
NUMBER
TITLE
REVISION/
DATE
Response to Generic Letter 89-13; Service Water
System Problems Affecting Safety-Related Equipment
January 29, 1990
Attachment to Spec.
No. 9645-M-072.0
Heat Exchanger Data Sheet - Component Cooling
Water Heat Exchangers
5
CCE-2006-002
Allow for all Water-to-Water Heat Exchangers to be
Maintained through the Preventive Maintenance
Program
May 2, 2006
EPRI NP-7552
Heat Exchanger Performance Monitoring
December 1991
EPRI TR-108009
Balance-of-Plant Heat Exchanger Condition
Assessment and Inspection Guide
December 1999
EPRI TR-108923
Recommended Cleaning Practices for Service Water
Systems
December 1997
GNRI-95/00044
Issuance of Amendment No. 120 to Facility Operating
License No. NPF-29 - Grand Gulf Nuclear Station,
Unit 1 (TAC No. M88101)
February 21,
1995
NDEN-0250-000-
2011
Diesel Jacket Water Cooler - P81B00A - Final Report
January 24, 2012
UFSAR 15.2.6
Loss of AC Power
10
UFSAR 15.6.5
Loss-of-Coolant Accidents (Resulting from Spectrum
of Postulated Piping Breaks Within the Reactor
Coolant Pressure Boundary - Inside Containment)
LDC 03059
UFSAR 9.2.2
Component Cooling Water System
0
UFSAR 9.5.5
Diesel Generator Cooling Water System
0
A-12
OTHER DOCUMENTS
NUMBER
TITLE
REVISION/
DATE
UFSAR Figure 9.2-
10
Component Cooling Water System
LDC 03009
UFSAR Figure 9.2-9 Component Cooling Water System
LBDCR 11028
UFSAR Figure 9.5-
15
Jacket Water System w/ Heat Exchanger
LDC 03009
UFSAR Table 9.2-4 Standby Service Water System Component
Description
LDC 02022
UFSAR Table 9.2-7 Component Cooling Water System Component
Description
LDC 01039
UFSAR Table 9.5-3 Diesel Generator Cooling Water System Component
Data
LDC 97085
VENDOR DOCUMENTS
NUMBER
TITLE
REVISION
21A9236
Engine-Generator for High Pressure Core Spray
System
5
21A9236AN
Engine-Generator for High Pressure Core Spray
System
2
CONDITION REPORTS
A-13
WORK ORDERS
Section 1R11: Licensed Operator Requalification Program
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
List of Modifications that need to be made on TREX Load per
Control Room Walkdown
January 10,
2013
A-14
Section 1R11: Licensed Operator Requalification Program
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
2013 Cycle 8 Licensed Operator Requal Simulator Training
Plan Simulator Differences
1
Operating Test Results
December
20, 2012
Modifications that need to be made to the TREX load for
simulator training cycle 9, 2013 per Control Room walkdown
February 25,
2013
2013 Cycle 9 Licensed Operator Requal Simulator Training
Plan Simulator Differences
0
GSMS-LOR-
WEX17
APRM Downscale/Loss of Condenser
Vacuum/LOCA/Degraded ECCS (EP-2, EP-3)
19
GIN 2013/00050
Simulator Evaluation on March 11, 2013 D Shift
March 11,
2013
Section 1R12: Maintenance Effectiveness
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
Attachment 9.1
Maintenance Rule Functional Failure Evaluation Template,
December 1,
2011
Maintenance Rule Scope and Basis
2
Condition Monitoring of Maintenance Rule Structures
2
Maintenance Rule Monitoring
4
ER-GG-2002-
0466-000
Evaluate Division I and II Diesel Generators (P75) to
determine if the governor setup complies with Reg. Guide 1
0
A-15
CALCULATIONS
NUMBER
TITLE
REVISION
MC-Q1P75-
98030
Standby Diesel Jacket Water Operating Parameters
1
MC-Q1111-01005 Determination of Component Design Minimum Wall
Thickness for Internal Erosion/Corrosion Program Plan
(GGNS-MS-41) and Components Inspected per CR-GGN-
2001-0955, CA-006 and 009
1
OTHER DOCUMENTS
NUMBER
TITLE
REVISION
MS-38
Document Revision Notice,06-566
2
SDC-P75
Document Revision Notice, 05-1803
1
SEP-ISI-102
Program Section for ASME Section XI, Division 1 Inservice
Inspection Program
1
ENGINEERING CHANGES
CONDITION REPORTS
A-16
A-17
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
Attachment 9.1
Online Emergent Work Add/Delete Approval form for the
week of January 7, 2013
9
05-1-02-VI-2
Hurricanes, Tornados and Severe Weather, February 10,
2013 Entry
120
01-S-07-43
Control of Loose Items, Temporary Electrical Power, and
Access to Equipment
6
Severe Weather Response
0
Severe Weather Recovery
0
General Industrial Safety Requirements
12
Electrical Safety
9
A-18
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
Material Handling Programs
15
On Line Risk Assessment
7
07-S-05-300
Control and use of Cranes and Hoists
113
06-TE-1000-V-
0001
Culvert No. 1 Embankment Stability Inspection\\Survey
100
05-1-02-VI-2
Hurricanes, Tornados and Severe Weather, February 12,
2013 Entry
120
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52462497-01
February 7,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52447574-01
February 6,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52369078
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52363905
February 7,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 338638-03
February 6,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52462496
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO Ops SOI
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52449563
February 7,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 340986
February 7,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52323348 01
February 5,
2013
A-19
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52362522
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO Dry Tube Strong Back
Shipment
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52370068-01, 00340429-
01, 52457198-01, 52457199-01
February 15,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52370068-01, 00340429-
01, 52457198-01, 52457199-01, 52457197-01, 52455988-01,
52455987-01
February 15,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52421734-01
February 14,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52452186-01, 52452186-
02, 52452186-03, 52452186-04
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52461116-01
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52456138, 52453953,
52453954
February 14,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52459533
February 7,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52340213
February 7,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52453952-01, 52456129-
01, 52456130-01
February 14,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52366069
February 13,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 298667
February 13,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
February 13,
A-20
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
Description and Justification, WO 341597-01, 341598-01,
298713
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 263365
February 11,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 336528
February 5,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, Component ID P41C003C and
D
February 12,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 324771
February 13,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52455992, 52456139
February 12,
2013
05-1-02-VI-2
Hurricanes, Tornados and Severe Weather, February 10,
2013 Entry
120
05-1-02-VI-2
Hurricanes, Tornados and Severe Weather, February 21,
2013 Entry
120
05-1-02-VI-2
Hurricanes, Tornados and Severe Weather, February 25,
2013 Entry
120
05-1-02-VI-2
Hurricanes, Tornados and Severe Weather, March 18-19,
2013 Entry
120
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 345315
March 19,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, Various Work Orders
March 19,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 302233
March 19,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52341331
March 20,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 263743
March 20,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
March 20,
A-21
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
Description and Justification, WO 341060 and 341071
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 51662321-01
March 20,
2013
Online Emergent Work Add/Delete Approval Form, Section A-
Description and Justification, WO 52472683, 52474315,
52453420-01, 52472679-01, 52472679-02, 52453420-02
March 20,
2013
05-1-02-VI-2
Hurricanes, Tornados and Severe Weather, March 23, 2013
Entry
120
01-S-02-3
Temporary Change Notice, Directive # 01-S-18-6
June 28,
2012
02-S-01-17
Control of Limiting Conditions for Operation
124
01-S-18-6
Qualitative Risk Considerations for External Events, Level 2
SSCs, SSCs not in EOOS, & SSCs not Modeled
Appropriately
011
05-1-02-VI-2
Hurricanes, Tornados, and Severe Weather
122
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Shutdown Condition 1, Time to 200 degrees F, .25 hour2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />s:
Day 12.5
January 27,
2013, 11:05 am
Shutdown Condition 1, Time to 200 degrees F, .5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />s:
Day 12
January 27,
2013, 5:30 am
Shutdown Condition 1, Time to 200 degrees F, .85 hour9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br />s:
Day 12
January 26,
2013, 7:15pm
Shutdown Condition 1, Time to 200 degrees F, .85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br />
January 26,
2013, 1:27 am
Shutdown Condition 1, Time to 200 degrees F, .8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />s:
Day 11
January 25,
2013, 7:05 pm
Shutdown Condition 1, Time to 200 degrees F, .75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />
January 24,
2013, 7:42 am
Shutdown Condition 1, Time to 200 degrees F, .75 hour8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />s:
Day 9
January 24,
2013, 2:10 am
A-22
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Shutdown Condition 1, Time to 200 degrees F, .7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />
January 23,
2013, 2:58 pm
Shutdown Condition 1, Time to 200 degrees F, .7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />
January 23,
2013, 2:20 am
Shutdown Condition 1, Time to 200 degrees F, .7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />
January 22,
2013, 4:43 pm
Shutdown Condition 1, Time to 200 degrees F, .65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br />
January 22,
2013, 1:00 am
Shutdown Condition 1, Time to 200 degrees F, .65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br />
January 21,
2013, 1:45 am
Shutdown Condition 1, Time to 200 degrees F, .65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br />
January 21,
2013, 12:00 pm
Shutdown Condition 1, Time to 200 degrees F, .6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s:
Day 5
January 20,
2013, 4:00 pm
Shutdown Condition 1, Time to 200 degrees F, .6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
January 20,
2013, 4:30 am
Shutdown Condition 1, Time to 200 degrees F, .5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />s:
Day 3
January 18,
2013, 7:00 am
Shutdown Condition 1, Time to 200 degrees F, .45 hour5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />s:
Day 3
January 17,
2013, 5:00 pm
Shutdown Condition 1, Time to 200 degrees F, .4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
January 17,
2013, 5:30 am
Shutdown Condition 1, Time to 200 degrees F, .3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />s:
Day 2
January 16,
2013, 10:00 am
Shutdown Condition 1, Time to 200 degrees F, .5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />
January 15,
2013, 8:30 pm
Shutdown Condition 1, Time to 200 degrees F, .25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />
January 15,
2013, 9:50 am
CONDITION REPORTS
A-23
Section 1R15: Operability Evaluations
PROCEDURES
NUMBER
TITLE
REVISION
Operability Determination Process, April 12, 2012
6
06-IC-1B21-Q-
1003
REACTOR VESSEL LOW/HIGH WATER LEVEL (RPS)
CALIBRATION SAFETY RELATED
106
06-IC-1B21-R-
0002
REACTOR VESSEL LOW/HIGH WATER LEVEL
CALIBRATION SAFETY RELATED
107
06-IC-1B21-R-
0003
SAFETY/RELIEF VALVE HIGH PRESSURE TRIP/LOW LOW
RELIEF/ECCS VESSEL PRESSURE INJECTION
PERMISSIVE CALIBRATION SAFETY RELATED
107
06-IC-1B21-R-
0008
CALIBRATION (ECCS}
SAFETY RELATED
107
06-IC-1821-R-
0011
REACTOR VESSEL WATER LEVEL (ADS) (RCIC)
CALIBRATION
SAFETY RELATED
101
06-IC-1B21-R-
2005
REACTOR VESSEL WATER LEVEL (LEVELS 1 AND 2)
CALIBRATION
SAFETY RELATED
105
06-IC-1B21-R-
2012
REACTOR VESSEL WATER LEVEL (HPCS)
CALIBRATION SAFETY RELATED
104
06-IC-1C11-R-
2001
SCRAM DISCHARGE VOLUME HIGH WATER LEVEL (RPS)
CALIBRATION SAFETY RELATED
105
06-IC-1E22-R-
0003
SUPPRESSION POOL HIGH WATER LEVEL CALIBRATION
(HPCS) SAFETY RELATED
102
06-IC-1E22-R-
0004
HPCS SYSTEM FLOW RATE LOW (BYPASS)
CALIBRATION
SAFETY RELATED
104
06-IC-1E31-R-
0023
RCIC/RHR AND RCIC STEAM LINE HIGH FLOW (RCIC
ISOL)
CALIBRATION SAFETY RELATED
104
06-IC-1E31-R-
1016
RCIC STEAM SUPPLY LOW PRBSSURE CALIBRATION
SAFETY RELATED
103
06*IC-1E51-R-
0003
SUPPRESSION POOL HIGH WATER LEVEL (RCIC)
CALIBRATION SAFETY RELATED
101
A-24
DRAWINGS
NUMBER
TITLE
169C9489
Purchase Part Relay
CALCULATIONS
NUMBER
TITLE
REVISION
MC-Q1P75-91119 Maximum Allowable Leakage From Division I and II
Generators Starting Air Storage Tanks
1
3.8.23-0
Standby Service Water Valve Room
0
MC-Q1P75-
90194
Lube Oil Requirements for the Division I and II Diesel
Generators
1
MC-Q1Y47-09011 SSW Pump House Temperature for Normal and Recirculation
Flows
0
MC-Q1Y47-
09002
SSW Pump House Temperature During Station Blackout
(SBO)
0
MC-Q1T46-95018 Calculations Sheet
2
MC-Q1T46-96037 ESF Switchgear Room Temperatures with the Room Coolers
Out of Service
0
JC-Q1B21-N616-
1
SAFETY RELIEF LOW/LOW SET SETPOINT
CALCULATION
0
JC-Q1B21-N674-
1
LEVEL 8 WIDE RANGE HPCS INJECTION VALVE
CLOSURE
0
JC-Q1B21-N680-
1
LEVEL 3 SETPOINT CALCULATION
0
JC-Q1B21-N681-
1
Level 1 Setpoint Calculation (Safety Related Tech. Spec.)
0
JC-Q1B21-N682-
1
LEVEL 2, SAFETY RELATED. TECH. SPEC., SETPOINT
CALCULATION
0
JC-Q1B21-N683-
1
LEVEL 8 NARROW RANGE
0
JC-Q1B21-N683-
1
LEVEL 8 NARROW RANGE
1
JC-Q1B21-N693-
1
LEVEL 8 NARROW RANGE RCIC TRIP
0
A-25
CALCULATIONS
NUMBER
TITLE
REVISION
JC-Q1B21-N697-
1
LOW PRESSURE ECCS PRESSURE PERMISSIVE
SETPOINT CALCULATION
0
JC-Q1C11-N601-
1
INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM C71 LOOP N601 SCRAM
REACTOR ON HIGH SDVP WATER LEVEL
1
JC-Q1C11-N601-
1
INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM C71 LOOP N601 SCRAM
REACTOR ON HIGH SDVP WATER LEVEL
2
JC-Q1E12-N655-
1
INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM E12 LOOPS N655 AND
N656 RHR PUMP DISCHARGE PRESSURE PERMISSIVE
FOR ADS
1
JC-Q1E12-N655-
1
INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM E12 LOOPS N655 AND
N656 RHR PUMP DISCHARGE PRESSURE PERMISSIVE
FOR ADS
2
JC-Q1E22-N651-
2
INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM lE22 LOOP N65l
HPCS PUMP MINIMUM FLOW BYPASS VALVE HI
PRESSURE INTERLOCK
1
JC-Q1E22-N655-
1
INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR INSTRUMENT LOOPS 1E22-N655,
1E51-N636 HPCS & RCIC PUMP SUCTION
TRANSFER ON HI SUPPRESSION POOL LEVEL
1
JC-01E31-N685-1 INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM EJl LOOP N685
RCIC TURBINE ISOLATION ON LOW INLET STEAM
PRESSURE
0
JC-01E31-N685-1 INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM EJl LOOP N685
RCIC TURBINE ISOLATION ON LOW INLET STEAM
PRESSURE
1
JC-Q1E51-N655-
1
INSTRUMENT LOOP UNCERTAINTY AND SETPOINT
DETERMINATION FOR SYSTEM E51 LOOP N655
RCIC TURBINE ISOLATION ON EXHAUST DIAPHRAGM
FAILURE
0
MC-Q1E22-
12001
LEVEL 8 TRIP FOR HPCS AND RCIC
0
A-26
CALCULATIONS
NUMBER
TITLE
REVISION
EC-Q1111-88002 Thermal Life of Agastat Relays
1
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
ER No. GGNS-
96-0005
Safety Relief Valves Safety Function Lift Setpoint Tolerance
Relaxation Summary Report
0
GGNS-SDC-B21 System Design Criteria Nuclear Boiler System
3
460000026
Instructions for Installation and Maintenance Safety Relief
Valves for Steam Service
QDR 0308-90
Quality Deficiency Report form
April 30, 1991
9645-M-616.3
Material Requisition: Electric Unit Heaters
11
GGNS-SDC-Y47 Standby Service Water Pump House Ventilation System
(Y47)
1
GGNS-SDC-P75 Standby Diesel Generator System (P75)
1
460000444
Chromalox Forced Air Heater
Model DSRV-16-4
Diesel
Engine/Generator
Associated Publications Manual Volume III, Book 1
10 CFR 50.59
Evaluation Form
9
GGNS-NE-11-
00007
Review of IRM AL Basis for 24 Month Fuel Cycle
0
GGNS-NE-11-
00006
Review of B21-N679-1 and B21-N697-1 Setpoint Basis
for 24 Month Fuel Cycle
0
GGNS-NE-11-
00008
Review of E21-N652-1 Setpoint Basis for 24 Month Fuel
Cycle
0
GGNS-NE-11-
00009
Review of RWCU Differential Flow
0
GGNS-NE-11-
00010
Review of E31-N684-1 Setpoint Basis for 24 Month Fuel
Cycle
0
GGNS-NE-11-
00011
RCIC Turbine Exhaust Vent Line Trip and Low Steam
Pressure Trip and Isolation AL Bases for 24 Month Fuel Cycle
0
A-27
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
SCN.98-001
STANDARD/SPECIFICATION CHANGE NOTICE: GGNS-
JS-09 Methodology for the Generation of Instrument Loop
Uncertainty & Setpoint Calculations
0
GEXI2012-00050 Grand Gulf Cycle 19 - Level 8 Setpoint Analytical Limit
Sensitivity
GNRO-
2012/00132
License Amendment Request for Revision of Technical
Specification Allowable Value for Primary Containment and
Drywell isolation Instrumentation Function 3.c RCIC Steam
Supply Line Pressure - Low.
NEDC-31336P-A General Electric Instrument Setpoint Methodology
GIN 95-03473
Failure Rate of Agastat Relays
December 27,
1995
GGNS-89-0028
Engineering Report on Functionality under High Ambient
Conditions of Auxiliary Building ESF Switchgear Room
Equipment Important to Safety
2
1974
IEEE Standard for Qualifying Class IE Equipment for Nuclear
Power Generating Stations
1971
CONDITION REPORTS
ENGINEERING CHANGES
A-28
WORK ORDERS
WO 00345315 01
Section 1R18: Plant Modifications
DRAWINGS
NUMBER
TITLE
REVISION
E-1046
Main Generator and Main Transformer CT Connections
009
E-1040
Plant Protection Logic Diagram
011
E-1045
N41 Three Line Meter & Relay Diagram
026
E-1002
One Line Meter & Relay Diagram
016
CONDITION REPORTS
ENGINEERING CHANGES
Section 1R19: Post-Maintenance Testing
PROCEDURES
NUMBER
TITLE
REVISION
06-OP-1C51-V-
0001, Attachment I
SRM Channel Function Test
110
06-OP-1C51-V-
0001, Attachment II
SRM Channel Function Test
110
06-OP-1G33-Q-
0001, Attachment II
Reactor Water Cleanup System Valve Operability
108
06-OP-1M61-V-
0003
Local Leak Rate Test-Low Pressure Water
1
06-OP-1E51-Q-
0003
RCIC System Quarterly Pump Operability Verification
134
A-29
Section 1R19: Post-Maintenance Testing
PROCEDURES
NUMBER
TITLE
REVISION
06-OP-1C51-V-
0002, Attachment I
IRM Functional Test
107
06-OP-1C51-V-
0002, Attachment II
IRM Functional Test
107
04-S-04-2
Operation of Electrical Circuit Breakers
56
07-S-02-2
Special Guidance for the Performance of Electrical
Activities
5
DRAWINGS
NUMBER
TITLE
REVISION
M-242.0-Q1-1.2-
101
20 150 Pound Swing Check Valve Weld End with Outside
Lever and Weight
4
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
BWR Owners Group Valve Technical Resolution Group, Final
Report: Appendix J-Generic Letter 89-10 Correlation
April 30, 1996
0900596
Structural Integrity Associates, Baseline Risk Implementation
Analysis: Grand Gulf Nuclear Station
A
HVA TD Report Summary: ESF-11 Second Test
February 13,
2013
HVA TD Report Summary: ESF-11 Final Test
February 13,
2013
Two-winding Transformer, Service Transformer 11
February 6,
2013
Pre-Maintenance Service Transformer 11
March 9,
2009
Two-Winding Transformer Data Sheet
GEK 42296
GE Motor Generator Package Set, Model 6PA4326A103
1
A-30
CONDITION REPORTS
WORK ORDERS
WO 00338860 01
WO 00338860 04
WO 52306016 01
WO 00089947 01
WO 00237152 01
WO 00299863 01
WO 00340488 01
WO 00335727 01
WO 00317521 01
WO 00337745 01
WO 00337245 02
WO 52411201 01
WO 52411202 05
WO 00295355 01
WO 00295355 05
WO 00332005 01
WO 00332006 01
WO 52386967 01, 09, 11
WO 00341598 01
WO 00331994 01
WO 00316857 01
WO 52463180 01
WO 00345940 01, 02
WO 00341915 01
WO 00265232 01
WO 52323390 01
ENGINEERING CHANGES
A-31
Section 1R20: Refueling and Other Outage Activities
PROCEDURES
NUMBER
TITLE
REVISION
07-S-12-128
Isolated Phase BUS Attachment Sheet General Location,
Page 1
2
01-S-06-12
GGNS Surveillance Program
111
03-1-01-1
Cold Shutdown to Generator Carrying Minimum Load
154
Conduct of Operations
13
Reactivity Management Program
5
07-S-12-128
General Maintenance Instruction, Isolated Phase BUS
Attachment Sheet General Location
2
03-1-01-3
Integrated Operating Instruction Plant Shutdown
122
DRAWINGS
NUMBER
TITLE
REVISION
D-7208-11-A2
22KV, 25,600A, 125 KV B11 Existing BUS Layout With 1.P.B
Modifications
T-157102
Assembly of Flexible Disconnect Links & Housing-Links
Installed
Isophase Air Flow Diagram
Isophase Air Flow Simplified Diagram
E-1045
N41 Three Line Meter & Relay Diagram Generator and Main
Transformer
26
Trouble Shooting Plan, BUS Duct Side
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
DC HIPOT/MEGGER, ISO-PHASE BUS
January 24,
2013
Remaining Open Actions and Operability Information for CRs
with ODMI Flags
January 24,
2013
Unassigned CRs
January 24,
2013
A-32
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
Cycle 19 Outage,
FO-19-04
OPS Cold Shutdown surv review, By Performance (Yes or
No)
0
Remaining Open Actions for Open GGN CRs with
Operability Code: OPERABLE DNC or OPERABLE_COMP
MEAS
January 24,
2013
N21F010B Action Plan per 01-S-06-26 step 6.2.7
N36F012B Action Plan per 01-S-06-26 step 6.2.7, 6B
Feeder/Bleeder trip valve
Restart Evaluation for Scram 128
Failure Mode Analysis Worksheet Main Generator trip on
main generator neutral time over-current relay 1N41M705
(451N/UT11)
PO 19-01
Shutdown Operations Protection Plan
13
Forced Outage Cold FO-19-04- Critical Path
January 27,
2013
Forced Outage Cold FO-19-04- Critical Path
January 22,
2013
Forced Outage Cold FO-19-04- Critical Path
January 17,
2013
FO-19-04 Generator Trip Discovery Information
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 17,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 20,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 21,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 17,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 18,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 19,
2013
A-33
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 22,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 23,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 24,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 25,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 26,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 27,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 28,
2013
Grand Gulf Nuclear Station FO-19-04 Forced Outage Daily
Update
January 29,
2013
GGNS Action Plan for Recovery from FO-12-02
CONDITION REPORTS
WORK ORDERS
ENGINEERING CHANGES
A-34
Section 1R22: Surveillance Testing
PROCEDURES
NUMBER
TITLE
REVISION
06-OP-1P81-R-
0001
HPCS Diesel Generator 18 Month Functional Test- Test No.
3- 24 Hour Rated Load Test/DG Hot Start Test
121
06-OP-1P81-R-
0001
HPCS Diesel Generator 18 Month Functional Test-General
Instructions
121
06-OP-1E51-Q-
0003
RCIC System Quarterly Pump Operability Verification
134
07-S-24-P75-
Periodic Inspection and Adjustment of Hydraulic Valve Lifters
on the DSRV-16-4 Delaval Diesel Engine
10
06-OP-1P75-M-
0002, Attachment
II
Standby Diesel Generator 12 Functional Test: February 27,
2013, 3:30 am
132
06-OP-1P75-M-
0002, Attachment
II
Standby Diesel Generator 12 Functional Test: February 26,
2013, 5:34 pm
132
06-OP-1P75-M-
0002, Attachment
II
Standby Diesel Generator 12 Functional Test: February 26,
2013, 4:22 pm
132
04-1-05-E12-3
Residual Heat Removal Loop C and Pass Return Penetration
000
06-OP-1M61-V-
0003
Local Leak Rate Test, Low Pressure Water for 1E12F406
(Failure)
1
06-OP-1M61-V-
0003
Local Leak Rate Test, Low Pressure Water for 1E12F406
(Passed)
1
02-S-01-28
Diesel Generator Start Information Sheet, Diesel Generator
No: 11, Start No: 1397
4
06-IC-IC51-R-
0075
APRM Recirculation Flow Transmitter Calibration
104
17-S-02-4
Performance and System Engineering Instruction Post
Refueling Outage Data Collection and Analysis
14
Drywell Leakage
2
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 08-49
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 24-05
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 44-05
14
A-35
Section 1R22: Surveillance Testing
PROCEDURES
NUMBER
TITLE
REVISION
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 60-29
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 36-05
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 60-45
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 20-61
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 44-61
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 16-57
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 60-21
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 20-05
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 60-41
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 04-45
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 08-13
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 08-53
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 56-13
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 52-57
14
04-1-03-C11-7
Control Rod Settle and Insertion Test, Control Rod 56-53
14
CALCULATIONS
NUMBER
TITLE
DATE
M-1358H
Pipe Anchors Diesel Generator Building
July 19, 1982
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
1P81PT01
Air Start Reliability Test
1
1P75PT01
Air Storage Tank Capacity Test
1
E-236
Emergency Diesel Generator Qualification Test Summary
December
28, 1976
91/1006
Change System P75, Division I and II Low Pressure Lockout
Setpoint
0
A-36
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
Discussion of Solenoid Valves on Packing Leak-Off Lines
6.B.4
EDG Hydraulic Lifter Instruction Manual
GG USFAR
Appendix 9B Fire Protection Program
Attachment 9.5
Operability Evaluation CR-GGN-2013-01977
6
Reactivity Maneuver Plan
2
CONDITION REPORTS
WORK ORDERS
WO 52342314 01
WO 00321520 01
WO 52323349 02
WO 00345315 01
WO 00345315 01
WO 52348931 01
1EP4: Emergency Action Level and Emergency Plan Changes
NUMBER
TITLE
REVISION
10-S-01-1
Activation of the Emergency Plan
122
69
Evacuation Time Estimate Study Update
Section 1EP6: Drill Evaluation
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Emergency Notification Form, Message Number 1
March 5,
2013
A-37
Section 1EP6: Drill Evaluation
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Emergency Notification Form, Message Not Sent
March 5,
2013
Emergency Notification Form, Message Number 2
March 5,
2013
Emergency Notification Form, Message Number 3
March 5,
2013
Emergency Notification Form, Message Number 4
March 5,
2013
Emergency Notification Form, Message Number 5
March 5,
2013
Emergency Notification Form, Message Number 6
March 5,
2013
Emergency Notification Form, Message Number 7
March 5,
2013
Emergency Notification Form, Message Number 8
March 5,
2013
GGNS 2013 Green Team Drill, Emergency Facilitator Log
March 5,
2013
Attachment 2, Objectives/Evaluation Criteria
March 5,
2013
GGNS 2013 Green Team, Repair and Corrective Action-
Admin Status Board
March 5,
2013
GGNS 2013 Green Team, Emergency Notification (Display)
March 5,
2013
CONDITION REPORTS
A-38
Section 4OA1: Performance Indicator Verification
PROCEDURES
NUMBER
TITLE
REVISION
Performance Indicator Process, Unit 1, 1st Qtr 2012
5
Performance Indicator Process, Unit 1, 2nd Qtr 2012
5
Performance Indicator Process, Unit 1, 3rd Qtr 2012
5
Performance Indicator Process, Unit 1, 4 h Qtr 2012
6
Section 4OA3: Event Follow-Up
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
01-S-06-26
Post-Trip Analysis, GG Unit 1, Scram No. 127
20
Apparent Cause Evaluation (ACE) Process
16
EN-LI-118-08,
Attachment 9.2
Revised Failure Mode Analysis Worksheet CR-GGN000083
0
EN-LI-118-08,
Attachment 9.2
Revised Failure Mode Analysis Worksheet: Main Generator
trip on main generator time over-current relay 1N41M705
1
01-S-06-5
Reactor Plant Event Notification Worksheet, EN#48673
110
01-S-06-26
Post-Trip Analysis, GG Unit 1, Scram No. 128
20
01-S-06-26
Post Trip Analysis, Written Statements Format
20
05-1-02-I-1
Off-Normal Event Procedure, Reactor Scram
117
05-1-02-I-1
Off-Normal Event Procedure, Reactor Scram
119
01-S-02-3
Temporary Change Notice, Directive # 07-S-15-4
April 3, 2012
8
DRAWINGS
NUMBER
TITLE
REVISION
E-1002
One Line Meter & Relay Diagram Generator and Main
Transformer, Unit 1
16
E-1045
NA1 Three Line Meter & Relay Diagram Generator and Main
Transformer
26
A-39
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Reactor Operating Events: Event Notification 48652
January 5,
2013
Unit Differential Relay Information
January 4,
2013
Unit Differential Relay Information
January 7,
2013
Grand Gulf Nuclear Station FO-19-04 Daily Update
January 15,
2013
Grand Gulf Nuclear Station FO-19-04 Daily Update
January 16,
2013
Grand Gulf Nuclear Station FO-19-04 Initial Brief
Single Trend Point - C34N004A
January 14,
2013
Grand Gulf Operations Logs-Days
January 14,
2013
Grand Gulf Cycle 19, Sequence No 19, 3Dm
V6.59.01/P11E10
January 14,
2013
Sequence of Event Log
January 14,
2013
Investigation of Cause of the January 14, 2013, SCRAM and
Actions Taken to Correct
Failure Mode Analysis Worksheet: Main Generator trip on
main generator neutral time over-current relay 1N41M705
Attachment 9.11
Entergy Operations, Grand Gulf Nuclear Station, RCE for
Generator Trip and Reactor Scram, CR-GGN-2013-0319
February 15,
2013
NRC Requested Information for FO47A
CONDITION REPORTS
A-40
A-41
WORK ORDERS
WO 52285169 01
TI-182
PROCEDURES
NUMBER
TITLE
REVISION
Underground Piping and Tanks Inspection and Monitoring
Program
6
Configuration Management
3
Engineering Program Sections
4
OTHER DOCUMENTS
NUMBER
TITLE
REVISION
Guideline for the Management of Underground Piping and
Tank Integrity
1
0900596-2
Grand Gulf Nuclear Power Station Native and Interrupted
APEC Survey
1
CEP-UPT-0100
Underground Piping and Tanks Inspection and Monitoring
1
Electric Power Research Institute: BPIRD Data Submission
Template, January 14, 2013
0.1
SEP-UIP-GGN
Underground Components Inspection Plan
0
En-ES-S-002-
MULTI
Underground Piping and Tanks General Visual Inspection
1
SI Project
Number:
0900596
Structural Integrity Associates, Inc Technical Report for
Baseline Risk Implementation Analysis, Grand Gulf Nuclear
Station
A
A-42
OTHER DOCUMENTS
NUMBER
TITLE
REVISION
CEP-UPT-0100
Underground Piping and Tanks Inspection and Monitoring
2
ECH-EP-12-
00001
Guidelines for Management of Reasonable Assurance of
Integrity for Above and Underground SSCs Containing
Radioactive Material
0
FTK-ESPP-
G00121
Underground Piping/Tanks Program Owner
5
Documentation of Buried Pipe and Tanks / Sumps in the
GGNS Piping Program
0
CONDITION REPORTS