ML13042A373
| ML13042A373 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 02/11/2013 |
| From: | David Proulx NRC/RGN-IV/DRP/RPB-C |
| To: | Kevin Mulligan Entergy Operations |
| Proulx D | |
| References | |
| Download: ML13042A373 (97) | |
See also: IR 05000416/2012005
Text
February 11, 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 NUMBER 05000416/2012005
Dear Mr. Mulligan:
On December 31, 2012, 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 January 17, 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.
Four 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. Further, a licensee-identified violation, which was determined
to be of very low safety significance is listed in this report. The NRC is treating these violations
as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.
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
NUC LEAR RE GULATOR Y C OM MI S SI ON
R E G IO N I V
1600 EAST LAMAR BLVD
AR L INGTON , TEXAS 76011- 4511
K. Mulligan
- 2 -
NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is
accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public
Electronic Reading Room).
Sincerely,
/RA/
David Proulx, Acting Branch Chief
Project Branch C
Division of Reactor Projects
Docket No.: 50-416
License No: NPF-29
Enclosure:
Inspection Report 05000416/2012005
w/ Attachments
1: Supplemental Information
2: Request for Information for ALARA Planning & Controls Inspection
cc w/ encl:
Electronic Distribution for Grand Gulf Nuclear Station
K. Mulligan
- 3 -
DISTRIBUTION:
Regional Administrator (Elmo.Collins@nrc.gov)
Acting Deputy Regional Administrator (Steven.Reynolds@nrc.gov)
DRP Director (Kriss.Kennedy@nrc.gov)
Acting DRP Deputy Director (Michael.Scott@nrc.gov)
Acting DRS Director (Tom.Blount@nrc.gov)
Acting DRS Deputy Director (Jeff.Clark@nrc.gov)
Senior Resident Inspector (Rich.Smith@nrc.gov)
Resident Inspector (Blake.Rice@nrc.gov)
Acting Branch Chief, DRP/C (David.Proulx@nrc.gov
Senior Project Engineer, DRP/C (Bob.Hagar@nrc.gov)
Project Engineer, DRP/C (Rayomand.Kumana@nrc.gov)
GG Administrative Assistant (Alley.Farrell@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Project Manager (Alan.Wang@nrc.gov)
Branch Chief, DRS/TSB (Ray.Kellar@nrc.gov)
TSB Assistant (Loretta.Williams@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
OEMail Resource
RIV/ETA: OEDO (John.Cassidy@nrc.gov)
Regional State Liaison Officer (Bill.Maier@nrc.gov)
NSIR/DPR/EP (Eric.Schrader@nrc.gov)
DOCUMENT NAME: R:\\_REACTORS\\_GG\\2012\\GG 2012005- RP-RLS 130205.docx
SUNSI Rev Compl.
Yes No
Yes No
Reviewer Initials
DP
Publicly Avail.
Yes No
Sensitive
Yes No
Sens. Type Initials
DP
SRI:DRP/C
RI:DRP/C
SPE:DRP/C
C:DRS/EB1
C:DRS/EB2
C:DRS/OB
RLSmith
BBRice
BHagar
TRFarnholtz
GMiller
VGaddy
/E-Proulx/
E-Proulx/
/RA/
/RA/
/RA/
/RA/
2/11/13
2/11/13
2/6/13
1/31/13
2/4/13
2/4/13
C:DRS/PSB1
C:DRS/PSB2
C:DRS/TSB
BC:DRP/C
MHaire
GEWerner
RKellar
DProulx
/RA/
/RA/
/RA/
/RA/
2/4/13
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2/11/13
OFFICIAL RECORD COPY
- 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:
September 22 through December 31, 2012
Inspectors: R. Smith, Senior Resident Inspector
B. Rice, Resident Inspector
S. Achen, Reactor Inspector NSPDP
L. Carson II, Senior Health Physicist
G. George, Senior Reactor Inspector
R. Kumana, Project Engineer
S. Makor, Reactor Inspector
J. Laughlin, Emergency Preparedness Inspector, NSIR
N. Okonkwo, Reactor Inspector
Approved
By:
David Proulx, Acting Chief
Reactor Projects Branch C
Division of Reactor Projects
- 2 -
SUMMARY OF FINDINGS
IR 05000416/2012005; 09/22/2012 - 12/31/2012; GRAND GULF NUCLEAR STATION, UNIT 1,
Integrated Resident and Regional Report; Maintenance Effectiveness, Refueling and Other
Outage Activities, Occupational ALARA Planning and Controls, and Followup of Events and
Notices of Enforcement Discretion.
The report covered a 3-month period of inspection by resident inspectors and an announced
baseline inspections by region-based inspectors. Six Green non-cited violations and one Green
finding 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 identified a non-cited violation of 10 CFR 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, involving the licensees
failure to follow procedure EN-LI-118, Root Cause Evaluation Process,
Revision 18, in that they failed to evaluate the risk significances and develop
action plans to address equipment identified during their extent-of-condition
review for a post-scram root cause analysis. The licensee entered this issue into
their corrective action program as Condition Report CR-GGN-2012-11950. The
immediate corrective actions included assigning corrective actions for operations
personnel to properly evaluate the risk significance of the identified components
and perform appropriate corrective actions to correct the degraded conditions.
The licensees failure to properly determine risk significance and associated
action plans to correct degraded equipment that could challenge safe plant
operation is a performance deficiency. The 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, the failure to
take corrective actions to correct degraded equipment has the potential to lead to
initiating events resulting in plant transients. 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 the
finding did not cause a reactor trip or the loss of mitigation equipment relied upon
to transition the plant from the onset of the trip to a stable shutdown condition.
- 3 -
The inspectors determined that the apparent cause of this finding was that when
operations management directed operators to identify the degraded equipment,
they did not encourage those operators to comply with Procedure EN-LI-118.
Therefore, the finding has a cross-cutting aspect in the human performance area,
work practices component because the licensee did not define and effectively
communicate expectations regarding procedural compliance. H.4(b) (Section
4OA3).
Cornerstone: Mitigating Systems
Green. The inspectors reviewed a self-revealing non-cited violation of 10 CFR
50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the
licensees failure to complete preventive maintenance tasks on the high pressure
core spray division III diesel generator output breaker in accordance with the
corresponding preventive maintenance task template. The licensee entered this
issue in their corrective action program as Condition Report CR-GGN-2012-
07992. The immediate corrective actions included replacing the failed control
relay and restoring operability to the division III diesel generator. The long term
corrective actions included revising breaker refurbishment/replacement
procedure with directions to replace the control relay and change the procedure
frequency to every 10 years versus every 12 years.
The inspectors determined that this performance deficiency was more than minor
and is therefore a finding because it is associated with the equipment
performance attribute of the Mitigating Systems Cornerstone and adversely
affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Specifically, this failed control relay caused the subject breaker
to fail to close during the division III diesel generator monthly surveillance on
June 5, 2012. The inspectors used NRC Inspection Manual Chapter 0609,
Attachment 4, "Initial Characterization of Findings," to determine that the issue
affected the Mitigating System Cornerstone. Because the finding pertained only
to a degraded condition while the plant was shutdown, the inspectors used
Manual Chapter 0609, Appendix G, Shutdown Operations Significance
Determination Process, Checklist 8, Cold Shutdown or Refueling Operation -
Time to Boil > 2 Hours: RCS Level < 23 Above Top of Flange, to determine that
the finding was of very low safety significance because it did not increase the
likelihood of a loss of reactor coolant system inventory; did not degrade the
licensees ability to terminate a leak path or add RCS inventory when needed; did
not significantly degrade the licensees ability to recover decay heat removal if
lost; and did not affect the safety/relief valves (Green). The inspectors
determined that the cause of this finding was a latent issue that is not reflective
of current performance, therefore no cross-cutting aspect was identified. (Section
1R20.b).
Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,
Criterion III, Design Control, for the licensees failure to establish the gain
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settings used on the power range neutron monitoring system in accordance with
design requirements. The licensee entered this issue into their corrective action
program as Condition Report CR-GGN-2013-00177. The immediate corrective
actions included adjusting gain settings for their average power range monitor
(APRM) instruments to indicate actual core thermal power as determined by the
heat balance. In additioin, the licensee revised their neutron monitoring
procedure to set the initial gains for the average power range monitor to the
maximum value to maintain conservative power indication during future startups.
They also changed their local power range monitor replacement procedure to
use the vendor specified initial gain setting of 3.692 prior to startup.
The finding was more than minor because it affected the design control attribute
of the Mitigating Systems Cornerstone and impacted the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Specifically, the incorrect
gain settings caused a violation of technical specification 3.0.4 by rendering the
APRM Neutron Flux High - Setdown scram function and the Neutron Flux -
Upscale, Startup control rod block function inoperable prior to entry into Mode 2.
In accordance with 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 very low safety
significance (Green) because although the finding affected a single reactor
protection system trip signal to initiate a reactor scram, it did not affect the
function of other redundant trips or diverse methods of reactor shutdown, did not
involve control manipulations that unintentionally added positive reactivity, and
did not result in a mismanagement of reactivity by operators. Because the
performance deficiency occurred in the past and is not reflective of current
licensee performance, this finding was not assigned a cross-cutting aspect.
(Section 4OA3).
Cornerstone: Barrier Integrity
Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,
Criterion XVI, Corrective Action, involving the failure to correct a condition
adverse to quality in a timely manner. Specifically, the licensee failed to correct
multiple degraded conditions associated with the auxiliary building water intrusion
barrier. The licensee entered this issue into their corrective action program as
Condition Report CR-GGN-2012-10314. Corrective actions included generating
Work Order 318398 and delegating funds to repair the water intrusion barrier at
the next available opportunity.
The finding is more than minor because if left uncorrected, the condition of a
degraded auxiliary building water intrusion barrier could lead to a more significant
safety concern. Specifically, continued degradation of the water intrusion barrier
could lead to the auxiliary building (secondary containment) being degraded such
that the standby gas treatment system would not be able to achieve and maintain
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the design negative pressure of 1/4 inch water column within 120 seconds. Using
Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of
Findings, the inspectors determined that the finding affected the Barrier Integrity
Cornerstone. In accordance with Inspection Manual Chapter 0609, Appendix A,
The Significance Determination Process (SDP) for Findings at Power, the
inspectors determined that the finding had very low safety significance (Green)
because the finding only represents a degradation of the radiological barrier
function provided for the auxiliary building and standby gas treatment system.
The inspectors determined that the apparent cause of this finding was that the
licensee had failed to classify the degraded water intrusion barrier as a condition
adverse to quality that warranted correction in a timely manner. Therefore, the
finding has a cross-cutting aspect in the problem identification and resolution
area, corrective action program component because the licensee failed to
properly classify conditions adverse to quality P.1(c)(Section 1R12).
Green. The inspectors identified a non-cited violation of 10 CFR 50.65(a)(2), for
the failure to monitor the performance of the auxiliary building water intrusion
barrier. The licensee entered this issue into their corrective action program as
Condition Report CR-GGN-2012-11740. Corrective actions included initiating
Condition Report CR-GGN-2012-12286, in which the licensee concluded the
degraded water intrusion barrier had experienced a Maintenance Rule Functional
Failure and required further evaluation to determine if the barrier should be
classified in 10 CFR 50.65 (a)(1).
The finding is more than minor because if left uncorrected, the failure to monitor
the performance of the auxiliary building water intrusion barrier in accordance
with the maintenance rule program could lead to a more significant safety
concern. Specifically, continued unmonitored degradation of the water intrusion
barrier could compromise the integrity of the secondary containment function of
the auxiliary building. Using Inspection Manual Chapter 0609, Attachment 4,
Initial Characterization of Findings, the inspectors determined that the finding
affected the Barrier Integrity Cornerstone. In accordance with Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings at Power, the inspectors determined that the finding had a very low
safety significance (Green) because the finding only represents a degradation of
the radiological barrier function provided for the auxiliary building and standby
gas treatment system. The inspectors determined that the apparent cause of this
finding was the licensee failed to recognize that the auxiliary building water
intrusion barrier was scoped into their Maintenance Rule program with the
monitoring criteria of zero occurrences of water intrusion barrier degradation.
Therefore, the finding had a cross-cutting aspect in the human performance area,
work practices component because the licensee failed to follow maintenance rule
program procedures H.4(b)(Section 1R12).
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Cornerstone: Occupational Radiation Safety
Green. The inspector reviewed a self-revealing finding of very low safety
significance because during the refueling outage 18 extended power upgrade,
the licensee did not adequately plan and control work activities for the design and
replacement of the new fuel pool cooling heat exchangers. Specifically, outage
personnel did not perform adequate pre-outage walkdowns, which resulted in
significant unplanned collective exposure. Actual collective dose and hours for
Radiation Work Permit 2012-1086, Fuel Pool Cooling & Cleanup Heat
Exchanger Replacement, was 23.9 person-rem and 12,237 RWP-hours,
respectively. This is compared to the initial planned estimate of 3.74 person-rem
and 1,905 RWP-hours. This finding and procedural concern was entered into the
corrective action program as Condition Reports CR-GGNS-2012-09011 and
CR-GGNS-2012-12398.
The failure to appropriately use ALARA planning and controls procedures to
prevent unplanned and unintended collective doses was a performance
deficiency. This performance deficiency was more than minor because it
affected the Occupational Radiation Safety Cornerstone attribute of Program and
Process in that the failure to adequately implement ALARA procedures caused
the collective radiation dose for the job activity to exceed the planned dose by
more than 50 percent. In addition, this type of issue is addressed in Example 6.j
of IMC 0612, Appendix E, Examples of Minor Issues. Using the Occupational
Radiation Safety Significance Determination Process, the inspector determined
this performance deficiency to be a finding of very low safety significance
because although it involved ALARA planning and controls, the licensees latest
rolling three-year average does not exceed 240 person-rem. This finding has a
cross-cutting aspect in the human performance area, work control component,
because the licensee failed to evaluate the impact of work scope change on
human performance and interdepartmental communication and coordination prior
to commencing work activities. Specifically, there was inappropriate coordination
and communication of work activities between work groups
H.3(b)(Section 2RS02).
Green. The inspectors reviewed a self-revealing non-cited violation of Technical
Specification 5.4.1 for failure to comply with radiological exposure controls
specified in Radiation Work Permit 2012-1402, Refuel Floor High Water
Activities. Specifically, radiation exposure controls in the RWP required the
licensee to verify that fuel pool cleanup (demineralizers) was in-service, and if
dose rates increased by more than 0.2 millirem/hour, change the resins. During
reactor cavity operations, both fuel pool demineralizer trains were inoperable at
least 25 days. In addition, the dryer separator pool and reactor cavity were
isolated from the fuel pool clean up system. Consequently, general area
radiation levels on the reactor cavity floor increased from 0.4 millirem/hour to
6.0 millirem/hour. The actual collective dose and hours for the work activity was
8.24 person-rem and 9,000 RWP-hours, respectively. This is compared to the
planned initial estimate of 4.60 person-rem and 6,987 RWP-hours. This
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Radiation Work Permint and procedure violation was documented in the
licensees corrective action program as Condition Reports CR-GGNS-2012-
04288 and CR-GGNS-2012-12401.
The licensees failure to comply with the RWP to prevent unplanned and
unintended collective doses was a performance deficiency. This performance
deficiency was more than minor because it affected the Occupational Radiation
Safety Cornerstone attribute of Program and Process in that the failure to
adequately implement ALARA procedures caused the collective radiation dose
for the job activity to exceed the planned dose by more than 50 percent. In
addition, this type of issue is addressed in Example 6.i of IMC 0612, Appendix E,
Examples of Minor Issues. Using the Occupational Radiation Safety
Significance Determination Process, the inspector determined this performance
deficiency to be a non-cited violation of very low safety significance because
although it involved ALARA planning and controls, the licensees latest rolling
three-year average does not exceed 240 person-rem. The violation involved a
cross-cutting aspect in the human performance area, work control component,
because the licensee did not appropriately coordinate work activities by
incorporating actions to address the need for work groups to communicate and
coordinate with each other during activities in which interdepartmental
coordination was necessary to assure human performance
H.3(b)(Section 2RS02).
B.
Licensee-Identified Violations
One violation of very low safety significance, which was identified by the licensee has
been reviewed by the inspector. Corrective actions taken or planned by the licensee
have been entered into the licensees corrective action program. This violation and
corrective action tracking number is listed in Section 4OA7.
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REPORT DETAILS
Summary of Plant Status
Grand Gulf Nuclear Station (GGNS) began the inspection period at 100 percent rated thermal
power.
On October 21, 2012, the operators reduced power to approximately 87 percent rated
thermal power for a planned control rod testing and returned to 100 percent rated
thermal power the same day.
On November 8, 2012, the operators reduced power to approximately 93 percent rated
thermal power due to a moisture intrusion into the main lube oil and hydrogen seal oil
systems that resulted in a clogging of the hydrogen seal oil filters and a procedurally
required power reduction due to decrease in seal oil pressure. The licensee changed
out the seal oil filters, de-watered the oil systems, and returned to 100 percent rated
thermal power on November 9, 2012.
On November 20, 2012, the operators reduced power to approximately 57 percent rated
thermal power due to an oil leak on the B reactor feedwater pump. The licensee
repaired the leak and returned to 100 percent rated thermal power on November 22,
2012.
On December 8, 2012, the operators began to shutdown and cool down the plant to
perform planned outage 19-01 to fix some long standing balance of plant issues,
including air in leakage to the condenser and a failed open second stage moisture
separator drain valve. The licensee commenced plant startup on December 14, 2012,
and achieved 100 percent rated thermal power after final control rod pattern was
achieved on December 21, 2012.
On December 29, 2012, at 12:18 a.m., the reactor scrammed from 100 percent rated
thermal power due to 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 December 31, 2012.
The plant continued startup activities through the end of the quarter.
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1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignment (71111.04)
.1
Partial Walkdown
a.
Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
Division I diesel generator during division II allowed outage time
Division I standby service water during division II allowed outage time
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.
These activities constitute completion of two partial system walkdown samples as
defined in Inspection Procedure 71111.04-05.
b.
Findings
No findings were identified.
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.2
Complete Walkdown
a.
Inspection Scope
On October 28, 2012, the inspectors performed a complete system alignment inspection
of the residual heat removal 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 Procedure 71111.04-05.
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:
Upper control room
Division I diesel generator room
Division I standby service water pump and valve rooms
Reactor core isolation cooling pump room
The inspectors reviewed areas to assess if licensee personnel had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant; effectively maintained fire detection and suppression capability; maintained
passive fire protection features in good material condition; and had implemented
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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 four quarterly fire-protection inspection samples
as defined in Inspection Procedure 71111.05-05.
b.
Findings
No findings were identified.
1R06 Flood Protection Measures (71111.06)
a.
Inspection Scope
The inspectors reviewed the updated safety analysis report, the flooding analysis, and
plant procedures to assess susceptibilities involving internal flooding. Additionally, the
inspectors verified that operator actions for coping with internal flooding can reasonably
achieve the desired outcomes. The inspectors also inspected the areas listed below to
verify the adequacy of equipment seals located below the flood line, floor and wall
penetration seals, watertight door seals, common drain lines and sumps, sump pumps,
level alarms, and control circuits, and temporary or removable flood barriers. Specific
documents reviewed during this inspection are listed in the attachment.
November 14-15, 2012, Turbine Building, elevations 93-0, 111-0; Auxiliary
Building, elevation 103-0; Control Building, elevation 93-0. Inspection of
Unresolved Item 05000416/2012008-07, Potential Internal Flooding Caused by
Circulation Water System Failure.
These activities constitute completion of one flood protection measures inspection
sample as defined in Inspection Procedure 71111.06-05.
b.
Findings
No findings were identified.
- 12 -
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
(71111.11)
.1
Quarterly Review of Licensed Operator Requalification Program
a.
Inspection Scope
On October 15, 2012, the inspectors observed a crew of licensed operators in the plants
simulator during a 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.
.2
Quarterly Observation of Licensed Operator Performance
a.
Inspection Scope
On November 20, 2012, 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 an unplanned downpower from 100 percent to
57 percent for an emergent repair of an oil leak on the B reactor feedwater pump. The
inspectors observed the operators performance of the following activities:
Pre-job brief
Reactivity management brief
Power reduction via recirculation pump flow reduction
Power reduction via control rod manipulations
- 13 -
In addition, the inspectors assessed the operators adherence to plant procedures,
including EN-OP-115, Revision 12, Conduct of Operations, and other operations
department policies.
As part of this inspection activity, the inspectors also observed the operators use of the
power-to-flow map and the operators awareness of the plants location on the power-to-
flow map to ensure that the plant was operated within the analyzed region. The
inspector also independently verified that the plant was operated within the analyzed
region of the power-to-flow map as the power was being reduced from 100 percent to 57
percent. This inspection activity constitutes the completion of one Operating Experience
Smart Sample (OpESS) FY2007-004, BWR Core Power/ Flow Map - Supplemental
Inspection Guidance for MC 2515D.
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:
Auxiliary building (T10)
Residual heat removal system (E12)
Suppression pool makeup system (E30)
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
- 14 -
Trending key parameters for condition monitoring
Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)
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 three quarterly maintenance effectiveness
samples as defined in Inspection Procedure 71111.12-05.
b.
Findings
(1) Failure to Make Timely Corrective Actions to Repair the Degraded Auxiliary Building
Water Intrusion Barrier
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action, involving the failure to promptly correct a
condition adverse to quality. Specifically, the auxiliary building water-intrusion barrier
has been in a degraded condition since April 2004.
Description. The seismic category 1 containment structures incorporated into the design
of Grand Gulf Nuclear Station are the containment building (primary containment),
auxiliary building (secondary containment), and enclosure building. The auxiliary
building completely encircles the containment building from base mat to mid height and
houses normal and safety related equipment. The auxiliary building, in conjunction with
the standby gas treatment system, is designed to limit the thyroid dose and whole body
dose to within the guidelines of 10 CFR Part 100 by reaching and maintaining a negative
pressure of 1/4 inch water column within 120 seconds. The enclosure building is a limited
leakage, steel framed, seismic category 1 structure that completely encloses the
portions of the containment building above the auxiliary building roof levels and is
designed to limit the leakage of radioactive material into the environment during a loss of
coolant accident. To maintain the required leakage limits, a water intrusion barrier, in
the form of a flexible seal, is provided around the entire periphery of the
enclosure/auxiliary building interface. The occurrence of water intrusion into the
auxiliary building is evidence that the water intrusion barrier is degraded. Although the
standby gas treatment system has passed its surveillance requirements of achieving and
- 15 -
maintaining the designed negative pressure, continued degradation of the flexible seal
could challenge the standby gas treatment systems ability to meet its surveillance
requirements.
On October 1, 2012, the inspectors reviewed Condition Report CR-GGN-2012-10314,
which described water leaking into the auxiliary building following a heavy rain storm.
The inspectors performed a detailed historical review of water intrusion into the auxiliary
building and found 18 condition reports had been written between April 2004 and August
2012 identifying occurrences of water leaking into the auxiliary building. The inspectors
also found that the majority of the condition reports written were closed to Work Order
60875, which has been in the Plan status since 2005.
The licensee entered this issue in their corrective action program as Condition Report
CR-GGN-2012-10314. Corrective actions included generating Work Order 318398 and
delegating funds to repair the water intrusion barrier at the next available opportunity.
Analysis. The failure to promptly correct a condition adverse to quality is a performance
deficiency. The inspectors used Inspection Manual Chapter 0612, Appendix B, to
determine that the finding is more than minor because if left uncorrected, the condition of
a degraded auxiliary building water intrusion barrier could lead to a more significant
safety concern. Specifically, continued degradation of the water intrusion barrier could
lead to the auxiliary building (secondary containment) being degraded in that the
standby gas treatment system would not be able to achieve and maintain the design
negative pressure of 1/4 inch water column within 120 seconds. Using Inspection
Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors
determined that the finding affected the Barrier Integrity Cornerstone. In accordance
with Inspection Manual Chapter 0609, Appendix A, The Significance Determination
Process (SDP) for Findings at Power, the inspectors determined that the finding had
very low safety significance (Green) because the finding only represents a degradation
of the radiological barrier function provided for the auxiliary building and standby gas
treatment system. The inspectors determined that the apparent cause of this finding
was the licensee had failed to classify the degraded water intrusion barrier as a condition
adverse to quality that warranted prompt correction. Therefore, the finding had a cross-
cutting aspect in the problem identification and resolution area, corrective action
program component because the licensee failed to properly classify conditions adverse
to quality P.1(c).
Enforcement. 10 CFR 50, Appendix B, Criterion 16, Corrective Action, states in part,
measures shall be established to assure that conditions adverse to quality, are promptly
identified and corrected. Contrary to the above, measures establish by the licensee did
not assure that conditions adverse to quality, were promptly identified and corrected.
Specifically, the licensee initiated 18 condition reports from April 2004 through August
2012 identifying auxiliary building water intrusion barrier degradation as evidenced by
water in-leakage and failed to implement corrective actions to address the degraded
barrier. As an immediate corrective action, the licensee generated Work Order 318398
and delegated funds to repair the water-intrusion barrier at the next available
opportunity. This violation is being treated as a non-cited violation (NCV), consistent
- 16 -
with Section 2.3.2 of the Enforcement Policy because it was of very low safety
significance (Green) and it was entered into the licensees corrective action program as
CR-GGN-2012-10314 to address recurrence: NCV 05000416/2012005-01, Failure to
Make Timely Corrective Actions to Repair the Degraded Auxiliary Building Water
Intrusion Barrier.
(2) Failure to Adequately Monitor the Condition of the Auxiliary Building Water Intrusion
Barrier
Introduction. The inspectors identified a Green non-cited violation of 10 CFR
50.65(a)(1), involving the failure to adequately monitor the performance of the auxiliary
building water intrusion barrier.
Description. On October 1, 2012, the inspectors reviewed Condition Report CR-GGN-
2012-10323, which described water leaking into the auxiliary building following a heavy
rain storm. During the review, the inspectors determined the auxiliary building roof
system, which includes a water intrusion barrier, was scoped in the licensees
maintenance rule program with the monitoring criteria of zero occurrences of water
intrusion barrier degradation. The inspectors performed a detailed historical review of
water intrusion into the auxiliary building and found 18 condition reports had been written
between April 2004 and August 2012 identifying the occurrence of auxiliary building
water intrusion barrier degradation as evidenced by water leaking into the auxiliary
building. The inspectors also found that the licensee had not performed any evaluation
of the water-intrusion barrier against the monitoring criteria established in the licensees
When the inspectors brought this concern to the licensees attention, the licensee
entered this issue in their corrective action program as Condition Report CR-GGN-2012-
11740. Corrective actions included initiating Condition Report CR-GGN-2012-12286, in
which the licensee concluded the degraded water-intrusion barrier was a Maintenance
Rule Functional Failure and required further evaluation to determine if the barrier should
be classified a(1).
Analysis. The failure to monitor the performance of the auxiliary building water intrusion
barrier in accordance with the maintenance rule program is a performance deficiency.
The inspectors used Inspection Manual Chapter 0612, Appendix B, to determine that the
finding is more than minor because if left uncorrected, the failure to monitor the
performance of the auxiliary building water intrusion barrier in accordance with the
maintenance rule program could lead to a more significant safety concern. Specifically,
continued unmonitored degradation of the water intrusion barrier could compromise the
integrity of the secondary containment function of the auxiliary building. Using
Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the
inspectors determined that the finding affected the Barrier Integrity Cornerstone. In
accordance with Inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process (SDP) for Findings at Power, the inspectors determined that the
finding had a very low safety significance (Green) because the finding only represents a
degradation of the radiological barrier function provided for the auxiliary building and
- 17 -
standby gas treatment system. The inspectors determined that the apparent cause of
this finding was the licensee had failed to recognize that the auxiliary building water
intrusion barrier was scoped into their Maintenance Rule program with the monitoring
criteria of zero occurrences of water intrusion barrier degradation. Therefore, the finding
had a cross-cutting aspect in the human performance area, work practices component
because the licensee did not follow maintenance rule program procedures H.4(b).
Enforcement. 10 CFR 50.65 (a)(1), requires, in part, that the holders of an operating
license shall monitor the performance or condition of structures, within the scope of the
rule as defined by 10 CFR 50.65 (b), against licensee-established goals, in a manner
sufficient to provide reasonable assurance that such structures are capable of fulfilling
their intended functions. 10 CFR 50.65 (a)(2) states, in part, that monitoring as specified
in 10 CFR 50.65 (a)(1) is not required where it has been demonstrated that the
performance or condition of an SSC is being effectively controlled through the
performance of appropriate preventive maintenance, such that the SSC remains capable
of performing its intended function.
Contrary to the above, the licensee did not monitor the performance or condition of a
structure within the scope of the rule as defined by 10 CFR 50.65 (b), against licensee-
established goals, in a manner sufficient to provide reasonable assurance that the
structure is capable of fulfilling its intended functions. Specifically, although the auxiliary
building water-intrusion barrier is within the scope of the rule and the licensee had
established a performance goal of zero water leakage for that barrier, between April,
2004, and August, 2012, the licensee documented 18 instances of water leakage
through that barrier, but did not evaluate the barrier in accordance with their
maintenance rule program. This violation is being treated as a non-cited violation
(NCV), consistent with Section 2.3.2 of the Enforcement Policy because it was of very
low safety significance (Green), and it was entered into the licensees corrective action
program as CR-GGN-2012-11740 to address recurrence: NCV 05000416/2012005-02,
Failure to Adequately Monitor the Condition of the Auxiliary Building Water Intrusion
Barrier.
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:
Week of October 28, 2012, during the division II allowed outage time, resulting in
the site being in an increased yellow risk profile during the outage
Week of November 19, 2012, during the unplanned down power to repair an oil
leak on the B reactor feedwater pump, resulting in the site being in a increased
risk profile
- 18 -
Week of December 9, 2012, during the planned outage PO-19-01, resulting in
the licensee entering offline yellow risk for decay heat removal and containment
control
The inspectors selected these activities based on potential risk significance relative to
the reactor safety cornerstones. As applicable for each activity, the inspectors verified
that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)
and that the assessments were accurate and complete. When licensee personnel
performed emergent work, the inspectors verified that the licensee personnel promptly
assessed and managed plant risk. The inspectors reviewed the scope of maintenance
work, discussed the results of the assessment with the licensee's probabilistic risk
analyst or shift technical advisor, and verified plant conditions were consistent with the
risk assessment. The inspectors also reviewed the technical specification requirements
and inspected portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of three maintenance risk assessments and
emergent work control inspection samples as defined in Inspection
Procedure 71111.13-05.
b.
Findings
No findings were identified.
1R15 Operability Evaluations and Functionality Assessments (71111.15)
a.
Inspection Scope
The inspectors reviewed the following assessments:
Division II diesel generator time delay relay failure (CR-GGN-2012-12133)
Residual heat removal-fuel pool cooling assist suction valve over thrust (CR-
Division II diesel generator jacket water tube wall thinning (CR-GGN-2012-
12060)
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
- 19 -
operability and design criteria in the appropriate sections of the technical specifications
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 four operability evaluations inspection samples
as defined in Inspection Procedure 71111.15-05.
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:
Standby service water pump B following motor replacement
Division II diesel generator following maintenance activities
Residual heat removal pump B following maintenance activities
Residual heat removal shutdown cooling suction valve E12-F006B and standby
service water blow down valve P41-F016B following maintenance activities
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
- 20 -
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 four 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 planned
outage, started on December 8, 2012, 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 planned outage, the inspectors observed portions of the shutdown and
cooldown processes and monitored licensee controls over the outage activities listed
below.
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.
Status and configuration of electrical systems to ensure that technical
specifications and outage safety-plan requirements were met.
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.
- 21 -
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
Introduction. The inspectors reviewed a self-revealing non-cited violation of 10 CFR 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees
failure to complete preventive maintenance tasks on the high pressure core spray
division III diesel generator output breaker in accordance with the corresponding
preventive maintenance task template.
Description On June 5, 2012, the high pressure core spray division III diesel generator
output breaker (152-1701) failed to close during a surveillance test. Troubleshooting
revealed that the breaker had failed to close because of intermittent high resistance on
the current relay contacts. Through the subsequent evaluation documented in Condition
Report CR-GGN-2012-07922, the licensee determined that the apparent cause of the
relay failure was age-related and/or cycle-related degradation due to a lack of an
appropriate preventive-maintenance task for the relay. More specifically, although the
licensee had set a recurring preventive-maintenance task to refurbish/replace the
breaker (using preventive maintenance task PMRQ 50018212-02) every 12 +/- 25%
years, and had last completed that task in 1996 such that it was next due on November
2, 2008 (or November 2, 2011 with a 25% extension), the licensee did not complete that
task when it was due. Instead, the licensee deferred that task until September, 2012.
To review the bases for the preventive maintenance tasks performed using PMRQ
50018212-02, the inspectors noted that Preventive Maintenance Basis Template, EN-
Switchgear-Medium Voltage - 1 KV to 7KV, Revision 3, discusses switch and relay
contact failures and states, in part,
High contact resistance may develop over time although a trouble-free period of
10 years should be obtained under mild service conditions. Switch and relay
contact failure may be avoided by measuring the contact resistance at the
detailed inspection.
The inspectors therefore considered that the licensee likely would have prevented the
June 5, 2012, breaker failure if they had performed preventive maintenance task PMRQ
50018212-02 in 2011, and if they had measured the current relay contact resistance at
that time.
The licensee entered this issue in their corrective action program as Condition Report
CR-GGN-2012-07992. Their immediate corrective actions included replacing the failed
control relay and restoring operability to the division III diesel generator. The long-term
corrective actions included revising the breaker refurbishment/replacement procedure to
- 22 -
replace the current relay and changing the procedure frequency to once every 10 years
versus once every 12 years.
Analysis. The licensees failure to complete preventive maintenance tasks on the high
pressure core spray division III diesel generator output breaker in accordance with the
corresponding preventive maintenance task template was a performance deficiency.
Using NRC Inspection Manual Chapter 0612, Appendix B, Issue Screening, the
inspectors determined that this performance deficiency was more than minor and is
therefore a finding because it is associated with the equipment performance attribute of
the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of
ensuring the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Specifically, this failed control relay
caused the subject breaker to fail to close during the division III diesel generator monthly
surveillance on June 5, 2012.
The inspectors used NRC Inspection Manual Chapter 0609, Attachment 4, "Initial
Characterization of Findings," to determine that the issue affected the Mitigating System
Cornerstone. Because the finding pertained only to a degraded condition while the plant
was shutdown, the inspectors used Manual Chapter 0609, Appendix G, Shutdown
Operations Significance Determination Process, Checklist 8, Cold Shutdown or
Refueling Operation - Time to Boil > 2 Hours: RCS Level < 23 Above Top of Flange, to
determine that the finding was of very low safety significance because it did not increase
the likelihood of a loss of reactor coolant system inventory; did not degrade the
licensees ability to terminate a leak path or add RCS inventory when needed; did not
significantly degrade the licensees ability to recover decay heat removal if lost; and did
not affect the safety/relief valves (Green). The inspectors determined that the cause of
this finding was a latent issue that is not reflective of current performance, therefore no
cross-cutting aspect was identified.
Enforcement. 10 CFR 50, Appendix B, Criterion V, states in part, that activities affecting
quality shall be accomplished in accordance with procedures. Contrary to this
requirement, an activity affecting quality was not accomplished in accordance with
procedures. Specifically, preventive maintenance tasks on the high pressure core spray
division III diesel generator output breaker are prescribed by preventive maintenance
task PMRQ 50018212-02, on November 2, 2011. The licensee did not accomplish
preventive maintenance tasks on the high pressure core spray division III diesel
generator output breaker in accordance with PMRQ 50018212-02, in that PMRQ
50018212-02 required the licensee to refurbish/replace the breaker before November 2,
2011, and the licensee did not do so. As a result, on June 5, 2012, that breaker failed to
close due to high contact resistance on the breakers current relay contacts. As an
immediate corrective action, the licensee replaced the failed relay and restored
operability to the division III diesel generator. This violation is being treated as a non-
cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy because it
was of very low safety significance (Green), and it was entered into the licensees
corrective action program as CR-GGN-2012-07992 to address recurrence.
(NCV 05000416/2012005-03, Failure to Perform Preventive Maintenance on
GE Magne-Blast Circuit Breakers in Accordance With the Corresponding Preventive
Maintenance Task Template).
- 23 -
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
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
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.
November 15, 2012, automatic depressurization system electrical surveillance
November 29, 2012, turbine control valve fast closure functional test for channels
B and D
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of two surveillance testing inspection samples as
defined in Inspection Procedure 71111.22-05.
b.
Findings
No findings were identified.
- 24 -
Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes (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 number ML12265A082 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 one sample as defined in Inspection
Procedure 71114.04-05.
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 October
16, 2012, to identify any weaknesses and deficiencies in classification, notification, and
protective action recommendation development activities. The inspectors observed
emergency response operations in the Emergency Operating Facility (EOF) and the
Technical Support Center (TSC), 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.
- 25 -
b.
Findings
No findings were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational and Public Radiation Safety
2RS02 Occupational ALARA Planning and Controls (71124.02)
a.
Inspection Scope
This area was inspected to assess performance with respect to maintaining occupational
individual and collective radiation exposures as low as is reasonably achievable
(ALARA). The inspector used the requirements in 10 CFR Part 20, the technical
specifications, and the licensees procedures required by technical specifications as
criteria for determining compliance. During the inspection, the inspector interviewed
licensee personnel and reviewed the following items:
Site-specific ALARA procedures and collective exposure history, including the
current 3-year rolling average, site-specific trends in collective exposures, and
source-term measurements
ALARA work activity evaluations/post job reviews, exposure estimates, and
exposure mitigation requirements
The methodology for estimating work activity exposures, the intended dose
outcome, the accuracy of dose rate and man-hour estimates, and intended
versus actual work activity doses and the reasons for any inconsistencies
Records detailing the historical trends and current status of tracked plant source
terms and contingency plans for expected changes in the source term due to
changes in plant fuel performance issues or changes in plant primary chemistry
Radiation worker and radiation protection technician performance during work
activities in radiation areas, airborne radioactivity areas, or high radiation areas
Audits, self-assessments, and corrective action documents related to ALARA
planning and controls since the last inspection
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of the one required sample as defined in
Inspection Procedure 71124.02-05.
b.
Findings
- 26 -
(1) Failure to Adequately Plan and Control Work Activities to Maintain ALARA
Introduction. An inspector reviewed a self-revealing Green finding of very low safety
significance because during Refueling Outage 18, the licensee did not adequately plan
and control work activities for the design and replacement of the new fuel pool cooling
heat exchangers under Radiation Work Permit (RWP) 2012-1086.
Description. While reviewing the post ALARA review package for RWP 2012-1086 from
Refueling Outage 18, Extended Power Upgrade, the inspector identified that the
licensees ALARA planning and control program failed to prevent unplanned and
unintended collective doses related to the design and replacement of the new fuel pool
cooling heat exchangers. Specifically, outage personnel did not perform adequate pre-
outage walkdowns which resulted in significant unplanned collective exposure. The
actual collective dose and hours for the project was 23.9 person-rem and
12,237 RWP-hours, respectively. This is compared to the initial estimate of
3.74 person-rem and 1,905 RWP-hours. Initially, there were approximately 165 work
activities, almost equally split between 2 tasks on RWP 2012-1086, Revision 0.
However, RWP 2012-1086 was revised eight times during the fuel pool cooling heat
exchanger replacement project due to increased work scope. According to the post-job
ALARA review, the project began with only 40 percent of its work activities planned out
and developed on the outage schedule. An additional 60 percent of the project work
activities were added as increased scope after the outage began. The inspector noted
that 63 Engineering Change Notice (ECNs) were added to the fuel pool cooling heat
exchanger replacement project as increased scope. The implementation of the 63
ECNs caused the projected work hours to increase from 975 hours0.0113 days <br />0.271 hours <br />0.00161 weeks <br />3.709875e-4 months <br /> to 7,295 hours0.00341 days <br />0.0819 hours <br />4.877645e-4 weeks <br />1.122475e-4 months <br /> (a
748 percent increase). This increase in work scope was not fully understood nor
justified, and resulted in unintended collective dose. Some causes for the dose
overages were higher dose rates than expected, longer work durations than expected,
and more added work scope than expected. However, there was no documentation in
the ALARA package that justified the dose estimate increases resulting from changes in
the job scope, duration, and work area dose rates. The inspector determined that the
performance deficiency that led to the increased collective dose was not following the
written ALARA Program procedure EN-RP-110, Revision 7, for planning and work
controls and procedure EN-DC-115, Engineering Change Process, Revision 13.
EN-RP-110, Section 4.0.8, states, in part, that Planning and Outage Groups
Responsibilities include: Providing accurate work site person-hours and accurate
work locations for ALARA planning purposes. Provide detailed work plans to
allow for ALARA planning to designate adequate radiological controls.
EN-DC-115, Section 5.3.4(e), states, in part, that Radiation Protection / ALARA
considerations shall be identified early in the engineering change process (by
10 percent design milestone). Radiation Protection / ALARA considerations
should be addressed as an integral part of the design configuration, material
selection, and implementation plan.
Apparent Cause Evaluation (ACE) in CR-GGNS-2012-09011 evaluated why the outage
ALARA goal was exceeded by 114 person-rem. The ACE stated, in part, that the
- 27 -
milestone walkdowns of outage work packages and execution were not completed in a
timely manner and in accordance with procedure EN-FAP-OU-100, Refueling Outage
Preparation and Milestones, Revision 2.
Analysis. The failure to appropriately use the ALARA Planning and Controls procedure
to prevent unplanned and unintended collective doses was a performance deficiency.
This performance deficiency was more than minor because it affected the Occupational
Radiation Safety Cornerstone attribute of Program and Process in that the failure to
adequately implement ALARA procedures caused the collective radiation dose for the
job activity to exceed the planned dose by more than 50 percent. In addition, this type of
issue is addressed in Example 6.j of IMC 0612, Appendix E, Examples of Minor Issues.
Using the Occupational Radiation Safety Significance Determination Process, the
inspector determined this performance deficiency to be a finding of very low safety
significance because although it involved ALARA planning and controls, the licensees
latest rolling three-year average does not exceed 240 person-rem. This finding has a
cross-cutting aspect in the human performance area, work control component, because
the licensee failed to evaluate the impact of work scope change on human performance
and interdepartmental communication and coordination prior to commencing work
activities. Specifically, there was inappropriate coordination and communication of work
activities between work groups H.3(b).
Enforcement. No violation of regulatory requirements occurred. However, this
performance deficiency is directly related to the licensees failure to meet its expectation
to fully implement ALARA outage, planning, and control procedures. This finding and
the procedural concern were entered into the corrective action program as
CR-GGNS-2012-09011 and CR-GGNS-2012-12396: FIN 05000416/2012005-04,
Failure to Adequately Plan and Control Work Activities to Maintain ALARA.
(2) Failure To Follow Radiation Work Permit Requirements During Reactor Cavity High
Water Operations
Introduction. An inspector reviewed a self-revealing Green non-cited violation of
Technical Specification 5.4.1 for failure to comply with radiological exposure controls
specified in Radiation Work Permit (RWP) 2012-1402, Refuel Floor High Water
Activities.
Description. Radiation exposure controls in the RWP required the licensee to verify that
fuel pool cleanup (demineralizers) was inservice, and if dose rates increased by more
than 0.2 millirem/hour, change the resins. During reactor cavity operations, both fuel
pool demineralizer trains were inoperable at least 25 days. In addition, the dryer
separator pool and reactor cavity were isolated from the fuel pool clean up system.
Consequently, general area radiation levels on the reactor cavity floor increased from
0.4 millirem/hour to 6.0 millirem/hour. However, the resins were not changed as
required. The actual collective dose and hours for the work activity was 8.24 person-rem
and 9,000 RWP-hours, respectively. This is compared to the initial estimate of
4.60 person-rem and 6,987 RWP-hours.
- 28 -
Analysis. The licensees failure to implement radiological exposure controls in
accordance with the RWP was the performance deficiency that caused unplanned and
unintended collective doses. This performance deficiency was more than minor
because it affected the Occupational Radiation Safety Cornerstone attribute of Program
and Process in that the failure to adequately implement ALARA procedures caused the
collective radiation dose for the job activity to exceed the planned dose by more than
50 percent. In addition, this type of issue is addressed in Example 6.i of IMC 0612,
Appendix E, Examples of Minor Issues. Using the Occupational Radiation Safety
Significance Determination Process, the inspector determined this performance
deficiency to be a non-cited violation of very low safety significance because although it
involved ALARA planning and controls, the licensees latest rolling three-year average
does not exceed 240 person-rem. This violation involved a cross-cutting aspect in the
human performance area, work control component, because the licensee did not
appropriately coordinate work activities by incorporating actions to address the need for
work groups to communicate and coordinate with each other during activities in which
interdepartmental coordination was necessary to assure human performance H.3(b).
Enforcement. Technical Specification 5.4.1 states that written procedures shall be
established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Section 7.e(1).
Contrary to the above, during Refueling Outage 18, written procedures were not
established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Specifically,
Appendix A of Regulatory Guide 1.33 lists procedures for radiation exposure and
access controls;
licensee procedure EN-RP-100, Revision 7, Radiation Worker Expectations, is
a procedure for radiation exposure and access controls and requires, in part, that
individuals comply with all requirements of the procedure and radiation work
permit (RWP) instructions when performing radiological work;
RWP 2012-1402, Refuel Floor High Water Activities, required the licensee to
verify that fuel pool cleanup system demineralizers were in-service and to
change the resins if dose rates increased by more than 0.2 millirem/hour; and
from March 13 through April 10, 2012, fuel pool cleanup system demineralizers were not
in service. In addition, after dose rates increased by more than 0.2 millirem/hour, the
resins were not changed. Consequently, general area radiation levels on the reactor
cavity floor increased from 0.4 millirem/hour to 6.0 millirem/hour. This violation was
documented in the licensees corrective action program as condition reports CR-GGNS-
2012-04288 and CR-GGNS-2012-12401. This issue is being treated as a non-cited
violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV
05000416/2012005-05, Failure To Follow the Radiation Work Permit Requirements
During Reactor Cavity High Water Operations.
- 29 -
2RS04 Occupational Dose Assessment (71124.04)
a.
Inspection Scope
This area was inspected to: (1) determine the accuracy and operability of personal
monitoring equipment; (2) determine the accuracy and effectiveness of the licensees
methods for determining total effective dose equivalent; and (3) ensure occupational
dose is appropriately monitored. The inspector used the requirements in
10 CFR Part 20, the technical specifications, and the licensees procedures required by
technical specifications as criteria for determining compliance. During the inspection,
the inspector interviewed licensee personnel, performed walkdowns of various portions
of the plant, and reviewed the following items:
External dosimetry accreditation, storage, issue, use, and processing of active
and passive dosimeters
The technical competency and adequacy of the licensees internal dosimetry
program
Adequacy of the dosimetry program for special dosimetry situations such as
declared pregnant workers, multiple dosimetry placement, and neutron dose
assessment
Audits, self-assessments, and corrective action documents related to dose
assessment since the last inspection
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of the one required sample as defined in
Inspection Procedure 71124.04-05.
b.
Findings
No findings were identified.
- 30 -
4.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
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 third 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.
.2
Mitigating Systems Performance Index - Emergency ac Power System (MS06)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index - emergency ac power system performance indicator for the period from the fourth
quarter 2011 through third 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, mitigating systems performance index derivation reports, issue reports,
event reports, and NRC integrated inspection reports for the period of October 2011
through September 2012 to validate the accuracy of the submittals. The inspectors
reviewed the mitigating systems performance index component risk coefficient to
determine if it had changed by more than 25 percent in value since the previous
inspection, and if so, that the change was in accordance with applicable NEI guidance.
The inspectors also reviewed the licensees condition report database to determine if
any problems had been identified with the performance indicator data collected or
transmitted for this indicator and none were identified. Specific documents reviewed are
described in the attachment to this report.
These activities constitute completion of one mitigating systems performance index -
emergency ac power system sample as defined in Inspection Procedure 71151-05.
- 31 -
b.
Findings
No findings were identified.
.3
Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index - high pressure injection systems performance indicator for the period from the
fourth quarter 2011 through third 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, mitigating systems performance index derivation reports,
event reports, and NRC integrated inspection reports for the period of October 2011
through September 2012 to validate the accuracy of the submittals. The inspectors
reviewed the mitigating systems performance index component risk coefficient to
determine if it had changed by more than 25 percent in value since the previous
inspection, and if so, that the change was in accordance with applicable NEI guidance.
The inspectors also reviewed the licensees condition report database to determine if
any problems had been identified with the performance indicator data collected or
transmitted for this indicator and none were identified. Specific documents reviewed are
described in the attachment to this report.
These activities constitute completion of one mitigating systems performance index -
high pressure injection system sample as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
.4
Mitigating Systems Performance Index - Heat Removal System (MS08)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index - heat removal system performance indicator for the period from the fourth quarter
2011 through third 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, mitigating systems performance index derivation reports,
and NRC integrated inspection reports for the period of October 2011 through
September 2012 to validate the accuracy of the submittals. The inspectors reviewed the
mitigating systems performance index component risk coefficient to determine if it had
changed by more than 25 percent in value since the previous inspection, and if so, that
the change was in accordance with applicable NEI guidance. The inspectors also
- 32 -
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 mitigating systems performance index -
heat removal system sample as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
.5
Mitigating Systems Performance Index - Residual Heat Removal System (MS09)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index - residual heat removal system performance indicator for the period from the fourth
quarter 2011 through third 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, mitigating systems performance index derivation reports,
event reports, and NRC integrated inspection reports for the period of October 2011
through September 2012 to validate the accuracy of the submittals. The inspectors
reviewed the mitigating systems performance index component risk coefficient to
determine if it had changed by more than 25 percent in value since the previous
inspection, and if so, that the change was in accordance with applicable NEI guidance.
The inspectors also reviewed the licensees condition report database to determine if
any problems had been identified with the performance indicator data collected or
transmitted for this indicator and none were identified. Specific documents reviewed are
described in the attachment to this report.
These activities constitute completion of one mitigating systems performance index -
residual heat removal system sample as defined in Inspection Procedure 71151-05.
b.
Findings
No findings were identified.
.6
Mitigating Systems Performance Index - Cooling Water Systems (MS10)
a.
Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index - cooling water systems performance indicator for the period from the fourth
quarter 2011 through third quarter 2012. To determine the accuracy of the performance
indicator data reported during those periods, the inspectors used definitions and
- 33 -
guidance contained in NEI Document 99-02, Regulatory Assessment Performance
Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator
narrative logs, issue reports, mitigating systems performance index derivation reports,
event reports, and NRC integrated inspection reports for the period of October 2011
through September 2012 to validate the accuracy of the submittals. The inspectors
reviewed the mitigating systems performance index component risk coefficient to
determine if it had changed by more than 25 percent in value since the previous
inspection, and if so, that the change was in accordance with applicable NEI guidance.
The inspectors also reviewed the licensees condition report database to determine if
any problems had been identified with the performance indicator data collected or
transmitted for this indicator and none were identified. Specific documents reviewed are
described in the attachment to this report.
These activities constitute completion of one mitigating systems performance index -
cooling water system 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.
b.
Findings
No findings were identified.
- 34 -
.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.
.3
Semi-Annual Trend Review
a.
Inspection Scope
The inspectors performed a review of the licensees corrective action program and
associated documents to identify trends that could indicate the existence of a more
significant safety issue. The inspectors focused their review on repetitive equipment
issues, but also considered the results of daily corrective action item screening
discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human
performance results. The inspectors nominally considered the 6-month period of May
20, 2012, through November 20, 2012, although some examples expanded beyond
those dates where the scope of the trend warranted.
The inspectors also included issues documented outside the normal corrective action
program in major equipment problem lists, repetitive and/or rework maintenance lists,
departmental problem/challenges lists, system health reports, quality assurance
audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.
The inspectors compared and contrasted their results with the results contained in the
licensees corrective action program trending reports. Corrective actions associated with
a sample of the issues identified in the licensees trending reports were reviewed for
adequacy.
These activities constitute completion of one single semi-annual trend inspection sample
as defined in Inspection Procedure 71152-05.
b.
Findings and Observations
No findings were identified.
The inspectors identified an increasing trend in condition reports identifying issues within
the work management process. The specific items documented in the condition reports
- 35 -
were reviewed by the inspectors, and it was determined that all were minor in nature.
The inspectors determined that the licensee had properly identified deficiencies in tagout
reviews, emergent work requests, work order impact statements and entered each issue
in the corrective action process. The work management issues have resulted in various
plant impacts, most notably an impact on resources due to repreforming work orders and
tagout reviews. The inspectors determined that although there was an abnormal
increase in work management issues, the licensee did appropriately address the issues
in the corrective action program.
.4
Selected Issue Follow-up Inspection: 4160 Vac Preventative Maintenance Procedures
a.
Inspection Scope
The inspectors chose to review Condition Reports CR-GGN-2012-08885,
CR-GGN-2012-9035, and CR-GGN-2012-09111, which addressed programmatic
conditions associated with 4160 Vac breaker testing described as The associated PM,
07-S-12-61, Inspection of GE Magna Blast Circuit Breaker, does not have any specific
steps that would clean or inspect auxiliary contacts though section 7.1.4 requires a
general inspection for any physical damage. The inspectors reviewed the associated
corrective actions for CR-GGN-2011-08885, CR-GGN-2012-9035, and CR-GGN-2012-
09111. The inspectors also reviewed associated procedures and interviewed several
members of the involved licensee staff. Documents reviewed are listed in the
attachment.
These activities constitute completion of one in-depth problem identification and
resolution sample as defined in Inspection Procedure 71152-05.
b.
Findings
No findings were identified.
.5
In-depth Review of Operator Workarounds
a.
Inspection Scope
The inspectors evaluated the licensees implementation of their process used to identify,
document, track, and resolve operational challenges. Inspection activities included, but
were not limited to, a review of the cumulative effects of the operator workarounds,
operator burdens, control deficiencies, control room alarms and long standing danger
and caution tags on system availability and the potential for improper operation of the
system, for potential impacts on multiple systems, and on the ability of operators to
respond to plant transients or accidents. The inspectors performed a review of the
cumulative effects of operator workarounds, operator burdens, control deficiencies,
control room alarms and long standing danger and caution tags. The documents listed
in the attachment were reviewed to accomplish the objectives of the inspection
procedure. The inspectors reviewed current operational challenge records to determine
whether the licensee was identifying operator challenges at an appropriate threshold,
had entered them into their corrective action program, and had proposed or
- 36 -
implemented appropriate and timely corrective actions, which addressed each issue.
Reviews were conducted to determine if any operator challenge could increase the
possibility of an initiating event, if the challenge was contrary to training, required a
change from long-standing operational practices, or if it created the potential for
inappropriate compensatory actions. Additionally, the inspectors review two licensee
assessments of their process to determine if they were properly assessing the issues
and determining long term corrective actions to reduce the operator challenges. Daily
plant and equipment status logs, degraded instrument logs, and operator aids or tools
being used to compensate for material deficiencies were also assessed to identify any
potential sources of unidentified operator workarounds.
These activities constitute completion of one operator workarounds annual inspection
sample as defined in Inspection Procedure 71152.
b.
Findings
No findings were identified.
4OA3 Followup of Events and Notices of Enforcement Discretion (71153)
.1
(Closed) Licensee Event Report 05000416/2012-001-00: Surveillance Test Procedure
Inadequate to Meet the Requirements of Technical Specifications
a.
Inspection Scope
On November 19, 2009, the licensee failed to ensure that Technical Specification (TS)
Surveillance Requirement (SR) 3.5.3.1 was met. The 2009 NRC Problem Identification
and Resolution (PI&R) Inspection identified a concern that the surveillance procedure
used to verify the reactor core isolation cooling (RCIC) system piping is filled with water
from the pump discharge valve to the injection valve was inadequate, in that it did not
have a basis (calculation) for the two-minute venting criterion and that there was no
visual means of confirming water flow through the vent line when performing venting of
the RCIC system. The 2009 PI&R inspection team documented the concern as a non-
cited violation in section 4OA2.5a of report 2009008. During the 2011 PI&R inspection,
the team reviewed the non-cited violation identified by the 2009 PI&R inspection and
determined that corrective actions were not taken in a timely enough manner to meet the
requirements of TS (SR) 3.5.3.1, which resulted in the RCIC system being inoperable for
a period of time in excess of TS allowance, which resulted in a condition prohibited by
TS. The licensee confirmed full compliance with TS SR 3.5.3.1 by performing ultrasonic
testing on February 5, 2010, which verified the piping was full of water.
The cause of the occurrence was an inadequate surveillance procedure acceptance
criterion, which resulted in the requirements of SR 3.5.3.1 not being met. The
contributing cause was the lack of technical rigor in evaluation of a potential inadequate
surveillance procedure. Corrective actions included using ultra sonic testing to verify the
RCIC system piping was full of water and revising RCIC surveillance procedures to
incorporate ultra sonic testing to verify the piping is full of water. Documents reviewed
as part of this inspection are listed in the attachment. The enforcement aspects of this
- 37 -
finding were discussed in NRC Inspection Report 05000416/2011006 in Section
4OA2.5a. This LER is closed.
b.
Findings
No findings were identified.
.2
(Closed) Licensee Event Report 05000416/2012-002-00: Manual Reactor Scram Due to
a Steam Supply Motor Operated Valve Failure that Resulted in the Inability to Maintain
Reactor Water Level
a.
Inspection Scope
On February 19, 2012, at 7:04 p.m., Grand Gulf Nuclear Station (GGNS) was in Mode 1
operating at approximately 22 percent power during a planned plant shutdown with the
reactor feed pump A secured when a manual reactor scram was initiated due to
decreasing reactor pressure vessel (RPV) water level. The cause of the event was a
combination of the isolating steam valve to the reactor feed pump B being out of
position, 90 percent closed, which isolates the main steam header from reactor feed
pump B and a planned power reduction. The power reduction resulted in the turbine
bypass valves (TBPV) opening as designed, then when the TBPVs reached 16 percent
open, reactor feed pump B began to decrease in speed. This resulted in a decreasing
level in the RPV. As level decreased, the control room supervisor directed a manual
scram be inserted prior to reaching the low level scram set point (+11.4 inches narrow
range). After the scram, reactor core isolation cooling (RCIC) was manually started to
inject water into the RPV and reactor feed pump A was restarted to restore and maintain
reactor water level. The appropriate off-normal event procedures were entered to
mitigate the transient with all systems responding as designed. All control rods inserted
to shut down the reactor.
The cause of the event was that equipment deficiencies preventing the high pressure
steam inlet valve to B RFPT from fully opening. Corrective actions included reactor water
level was restored and the plant was placed in a stable condition. The licensee
conducted troubleshooting of the steam supply valve and repaired it during the refueling
outage. Other contributing causes were evaluated and corrective actions were develop
to address these process issues. Documents reviewed as part of this inspection are
listed in the attachment. The enforcement aspects of this finding were discussed in NRC
Inspection Report 05000416/2012002 in Section 4OA3 and documented below. This
LER is closed.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, involving the
licensees failure to follow Procedure EN-LI-118, Root Cause Evaluation Process,
Revision 18, in that they failed to evaluate the risk significances and develop action
plans to address equipment identified during their extent-of-condition review for a post-
scram root-cause analysis.
- 38 -
Description. The inspectors reviewed Licensee Event Report 2012-002-00, Manual
Reactor Scram Due to a Steam Supply Motor Operated Valve Failure that Resulted in
the Inability to Maintain Reactor Water Level. The inspectors identified that the licensee
performed a root-cause analysis under Condition Report CR-GGN-2012-1842. In their
review of the root cause and associated corrective actions, the inspectors noted that
operations were directed by Corrective Actions 34 and 35 to perform an extent-of-
condition review of other systems to identify hidden or longstanding equipment issues
that pose a challenge to the safe operation of the plant. Although the operations
personnel identified numerous components such as valves and pumps in degraded state
that could affect safe plant operations, they did not properly perform Procedure
EN-LI-118, Attachment 9.7, in that they completed step one of evaluating and identifying
the similar components that were a cause of the original scram, but did not perform the
second step of determining the risk significance of these identified components and did
not develop action plans to resolve the degraded conditions.
The inspectors brought this to the attention of the licensee management, and they
reviewed the root cause and corrective actions from the condition report and came to the
same conclusions as the inspectors.
The licensee entered this issue in their corrective action program as Condition Report
CR-GGN-2012-11950. Their immediate corrective actions included assigning corrective
actions for operations personnel to properly evaluate the risk significance of the
identified components and perform appropriate corrective actions to correct the
degraded conditions.
Analysis. The licensees failure to properly determine risk significance and associated
action plans to correct degraded equipment that could challenge safe plant operation is
a performance deficiency. The 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, the failure to take corrective actions to
correct degraded equipment has the potential to lead to initiating events resulting in plant
transients. 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 the finding did not cause a reactor trip or the loss of mitigation
equipment relied upon to transition the plant from the onset of the trip to a stable
shutdown condition. The inspectors determined that the apparent cause of this finding
was that when operations management directed operators to identify the degraded
equipment, they did not encourage those operators to comply with Procedure EN-LI-118.
Therefore, the finding has a cross-cutting aspect in the human performance area, work
practices component because the licensee did not define and effectively communicate
expectations regarding procedural compliance. H.4(b)
- 39 -
Enforcement. 10 CFR 50, Appendix B, Criterion V, states, in part, that activities affecting
quality shall be prescribed by and accomplished in accordance with documented
instructions, procedures, or drawings, of a type appropriate to the circumstances.
Procedure EN-LI-118, Root Cause Evaluation Process, Revision 18, Attachment 9.7,
requires the licensee to evaluate the previous problem for similar issues and determine
risk significances and associated action plans to resolve the degraded components
identified. Contrary to the above, on or before October 9, 2012, the licensee did not
evaluate a previous problem for similar issues and determine risk significances and
associated action plans. Specifically, although the licensee did properly evaluate and
identify similar components such as valves and pumps in a degraded condition, they did
not determine the risk significance of what they identified or develop action plans to
resolve the degraded components identified. As an immediate corrective action, the
licensee assigned corrective actions to operations personnel to properly evaluate the
risk significance of the identified components and develop action plans to correct the
degraded components. This violation is being treated as a non-cited violation (NCV),
consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety
significance (Green) with no actual safety consequence, and it was entered into the
licensees corrective action program as CR-GGN-2012-11950 to address recurrence:
NCV 05000416/2012005-06, Failure to Evaluate the Risk Significances and Develop
Action Plans to Address Equipment Identified During Extent of Condition Review for a
Post Scram Root Cause Analysis.
.3
(Closed) Licensee Event Report 05000416/2012-003-00: ESF Actuation Due to Division
III Bus Undervoltage following a Lighting Strike
a.
Inspection Scope
On April 2, 2012, at 3:11 p.m. central daylight time (CDT) Grand Gulf Nuclear Station
was in mode 5 when a valid engineered safety feature (ESF) actuation for emergency
alternating current power to the division III 4160 volt bus occurred due to degraded
voltage. One of the two offsite 500 kilovolt offsite feeder breakers tripped open causing
a drop in grid voltage that resulted in a trip of normal ESF feeder for division III 4160 volt
bus. The high pressure core spray diesel generator automatically started and energized
the bus. The high pressure core spray system was not running at the time and no
emergency core cooling initiation occurred during this event. The technical specification
required power sources remained operable and in service during this event. The 500
kilovolt feeder was restored by the dispatcher at approximately 3:15 p.m. CDT.
The cause of the event was a lighting strike on the Franklin 500 kilovolt line. Entergy
transmission operation center reported at approximately 3:12 p.m., the Franklin extra
high voltage to Grand Gulf 500 kilovolt line tripped and locked out. The Franklin line in
one of three offsite power sources available to Grand Gulf. The fault was sensed by the
Grand Gulf line realying equipment and the fault was cleared by the dispatcher. Grand
Gulf personnel investigated the event and determined that all onsite equipment
performed as expected. Documents reviewed as part of this inspection are listed in the
attachment. This LER is closed.
- 40 -
b.
Findings
No findings were identified.
.4
(Closed) Licensee Event Report 05000416/2012-004-00: Weld Defect Indication Found
in Residual Heat Removal System to Reactor Pressure Vessel Boundary Nozzle
a.
Inspection Scope
On April 28, 2012, while the plant was in mode 4, shutdown for refueling outage 18,
ultrasonic testing was being performed on the nozzle weld N6B-KB, residual heat
removal/low pressure coolant injection nozzle to safe end weld. The ultrasonic
examination revealed an indication indicative of intergranular stress corrosion cracking.
The indication was evaluated by personnel and confirmed to be a weld defect. Inservice
Inspection relief request (RR-ISI-17; ML12124A245) to repair the weld was submitted to,
and approved by, the NRC (reference GTC 2012-00011). A full structural weld overlay
repair to the weld in accordance with ASME code requirements was completed on May
14, 2012. A post-weld ultrasonic test was completed satisfactorily on May 16, 2012.
The cause of the weld defect was determined to be the weld and butter were fabricated
with material that is susceptible to IGSCC type cracking. Actions were taken to mitigate
this condition through the stress relieving process of Induction Heating Stress
Improvement (IHSI). A contributing cause for the identification of this condition in 2012
(versus earlier) is the development and use of improved ultrasonic examination
procedures, techniques and training. Documents reviewed as part of this inspection are
listed in the attachment. This LER is closed.
b.
Findings
No findings were identified.
.5
(Closed) Licensee Event Report 05000416/2012-005-00: Average Power Range
Monitors Inoperable in Excess of Technical Specification Allowances in Mode 2
a.
Inspection Scope
On June 13, 2012, during startup activities for Unit 1 with the reactor in Mode 1
operating at approximately 12 -15 percent (%) power, the Average Power Range Monitor
(APRMs) were indicating a reactor power level lower than expected for the plant
condition. The licensee determined that during Refueling Outage 18 (RF18) the APRMs
were set to indicate flux lower than the actual power level. This resulted in the system
being inoperable during Mode 2 due to the APRM Neutron Flux High - Setdown scram
setpoint being outside of Technical Specification (TS) 3.3.1.1 Reactor Protection System
(RPS) Instrumentation limits. This condition existed when Mode 2 was initially entered
on June 6, 2012 until Mode 1 was entered on June 13, 2012. This condition was limited
to the Power Range Neutron Monitoring (PRNM) system. During startup in Mode 2, the
intermediate range monitors (IRM) and the high reactor pressure trip functions were
operable. Therefore, reactor power transients would have been mitigated by these
- 41 -
functions. The APRM Neutron Flux High - Setdown function is not directly credited in any
safety analyses, and this event did not adversely affect plant safety or the health and
safety of the public.
The apparent cause of this condition was a failure to identify differing operating
characteristics between the old system and the new system during the engineering
change process. The licensee had been entering the minimum gain for the old APRM
instruments, and did not evaluate this practice as part of the engineering change
process. The old instruments indicated much higher than actual power at low power
levels while the new instruments indicated closer to actual levels. As a result, when the
licensee continued to use the minimum gain setting, the new instruments indicated lower
than actual power. The licensee conducted an apparent cause evaluation and identified
other contributing causes and corrective actions. Documents reviewed as part of this
inspection are listed in the attachment. The enforcement aspects of this finding are
documented below. This LER is closed.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion III, Design Control, involving the licensees failure to establish the
gain settings used on the power range neutron monitoring (PRNM) system in
accordance with design requirements. Specifically, prior to June 13, 2012, the licensee
used non-conservative gain settings on the average power range monitors (APRMs) and
local power range monitors (LPRMs) causing them to indicate flux lower than the actual
power level, which resulted in violations of Technical Specifications 3.0.4, 3.3.1.1, and
3.3.2.1.
Description. On June 13, 2012, during a reactor startup, the licensee discovered that
reactor power as indicated by the APRM neutron flux was significantly lower than the
apparent power as determined by the heat balance and other indications. The licensee
determined that actual power was approximately 12-15 percent while the APRMs
indicated 6.5 percent. The licensee immediately validated the heat balance inputs and
adjusted APRM and LPRM gains to correct the discrepancy. The licensee reported this
event in License Event Report (LER) 05000416/2012-005-00 as a violation of Technical
Specification 3.3.1.1 Reactor Protection System Instrumentation due to the APRM
Neutron Flux High - Setdown scram function being inoperable. The inspectors reviewed
the LER and concluded that the licensee also violated Technical Specification 3.0.4
because they entered Mode 2 with the required function inoperable and did not meet any
of the allowable exceptions. Furthermore, the inspectors noted that the Neutron Flux -
Upscale, Startup function of Technical Specification 3.3.2.1 Control Rod Block
Instrumentation was also inoperable.
The cause of the technical specification violations was that the licensee had entered
incorrect, non-conservative gains into the APRM and LPRM instruments. During
Refueling Outage 18, the licensee upgraded the PRNM system to a digital General
Electric Hitachi designed Nuclear Measurement and Control System (NUMAC) as part of
the extended power uprate (EPU). This involved replacing all of the APRM instruments
with a new design. The licensee also replaced forty LPRM detectors.
- 42 -
The licensee procedure for initial APRM gain setting directed setting the gain to the
minimum possible before instrument calibration, which is performed between 18 percent
and 21.8 percent reactor power. The apparent reason for this was that the old
instruments did not effectively discriminate gamma flux at low power, and therefore
indicated higher than actual values. The licensee used the minimum gain value to
prevent a rod withdrawal block prior to calibrating the instruments. The new instruments
are more effective at gamma discrimination at low power, and therefore indicate closer
to actual flux. The licensee had never established a basis for determining the initial gain
settings, did not re-evaluate the continued use of these settings during the design
change process, and did not modify the procedures to set a more conservative initial
gain setting. The licensee also discovered during their apparent cause evaluation that
the initial gain setting they used for the replacement LPRM detectors was incorrect. The
licensee had been using 3.000 as the default initial gain setting for uncalibrated LPRMs.
However, the vendor recommended default setting was 3.692. Therefore the forty
replaced LPRMs were providing a non-conservative signal to the APRMs. As a result of
the failure to use conservative gain settings on the LPRMs and APRMs, all APRMs
indicated approximately 40-50 percent of actual thermal power when the error was
discovered.
The APRMs are designed to indicate within tolerances and ensure protective functions
specified in the plant design documents. The inspectors determined that the licensee
had been using initial gain settings for both the LPRMs and APRMs that had not been
evaluated or analyzed to ensure these design requirements were being met. The
licensee carried over this practice when implementing their design change for the new
system instead of evaluating the settings for the new system.
The licensee entered this issue into their corrective action program as Condition Report
CR-GGN-2013-00177. The immediate corrective actions included adjusting gain settings
for their APRM instruments so they indicated actual core thermal power as determined
by the heat balance. The licensee also revised their neutron monitoring procedure to set
the initial gains for the APRMs to the maximum value to maintain conservative power
indication during future startups and changed their LPRM replacement procedure to use
the vendor specified initial gain setting of 3.692 prior to startup.
Analysis. The failure to ensure that the design basis was correctly translated into
specifications, drawings, procedures, and instructions was a performance deficiency.
The performance deficiency was more than minor because it affected the design control
attribute of the Mitigating Systems Cornerstone and impacted the cornerstone objective
to ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Specifically, the incorrect gain settings led
to a violation of technical specification 3.0.4 by rendering the APRM Neutron Flux High -
Setdown scram function and the Neutron Flux - Upscale, Startup control rod block
function inoperable prior to entry into Mode 2. 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 issue was determined to have very low safety
significance (Green) because although the finding affected a single reactor protection
- 43 -
system (RPS) trip signal to initiate a reactor scram, it did not affect the function of other
redundant trips or diverse methods of reactor shutdown, did not involve control
manipulations that unintentionally added positive reactivity, and did not result in a
mismanagement of reactivity by operators. This finding was not assigned a cross-cutting
aspect because the performance deficiency occurred in the past and is not reflective of
current licensee performance.
Enforcement. 10 CFR 50, Appendix B, Criterion III, requires, in part, that measures
shall be established to assure that the design basis is correctly translated into
procedures. Contrary to the above, prior to June 13, 2012, measures established by
the licensee did not assure that the design basis was correctly translated into
procedures. Specifically, those measure did not assure that the bases for the APRM
and LPRM gain settings were correctly translated into the licensees maintenance and
operating procedures. The licensees immediate actions were to set appropriate gain
settings for their APRM instruments and submit an LER for the violation of technical
specifications. This violation is being treated as an NCV, consistent with Section 2.3.2 of
the Enforcement Policy, because it was of very low safety significance (Green) and was
entered into the licensees corrective action program as CR-GGN-2013-00177 to
address recurrence NCV 05000416/2012005-07, Failure to Establish Gain Settings on
APRM and LPRM Instruments in Accordance with Design Requirements.
.6
(Closed) Licensee Event Report 05000416/2012-006-00: Special Nuclear Material
Inventory Discrepancy
a.
Inspection Scope
On July 25, 2012, at 3:34 p.m. the licensee determined that a source range monitor
detector was not in its expected storage location. This met the reporting criteria in 10
CFR 72.74 and 10 CFR 74.11 as a loss of special nuclear material. The Source Range
Monitor (SRM) detector contained an estimated maximum activity of 0.187 microcuries,
which is equivalent to 0.00292 grams of all Special Nuclear Material (SNM) isotopes,
including U-235. This also met the reporting criteria in 10 CFR 20.2201 (a) (1) (ii) as a
loss of licensed material of a quantity greater than ten times that specified in Appendix C
to 10 CFR Part 20. According to special nuclear material (SNM) inventory sheets, the
SRM detector was expected to be stored in an SNM Item Control Area (ICA) on the 208
foot elevation of the Auxiliary building. However, during performance of the annual
physical inventory of SNM, the SRM detector could not be located. Subsequent
investigations concluded that the SRM was removed from the 208 foot elevation of the
Auxiliary building SNM ICA during clean up at the end of Refueling Outage 18, along
with other material that was stored in the area, and discarded as radioactive waste.
The inspector reviewed the licensee event report, NRC Event Notification 48133, and
the licensees corrective action reports, which documented this event and its causes.
The inspectors verified that the cause of the event was identified, radiological
consequences were assessed, and that corrective actions were reasonable. The
enforcement aspects of this violation are discussed in Section 4OA7 of this report. This
licensee event report is closed.
- 44 -
.7
(Closed) Licensee Event Report 05000416/2012-007-00: Standby Service Water
System Administratively Inoperable For A Period Longer Than Allowed By Technical
Specifications
a.
Inspection Scope
On August 18, 1987, a 10 CFR 50.59 safety evaluation was performed for a change to
the Final Safety Analysis Report (FSAR) to relax methodology for single passive failures
of standby service water components. On July 19, 2012, with the plant in mode 1 at
approximately 100 percent power, during the inspectors reviewed FSAR change
NPEFSAR 87/0067 and determined prior NRC approval of the change was required.
This resulted in SSW being administratively inoperable for a period longer than allowed
by technical specifications due to relaxation of the passive failure methodology without
prior NRC approval. The licensee determined that the event posed no threat to public
health and safety as there had been no passive failures that had challenged operability.
The licensee implemented compensatory measures and they have submitted a request
to revise the SSW passive failure methodology to the NRC. Procedures are in place to
prevent recurrence.
The apparent cause for this issue is misapplication of industry documents that were
used for justification in the 10 CFR 50.59 safety evaluation due to lack of understanding
their applicability. The NUREG-0138 document did not specifically address single
passive failures for systems such as the standby service water system. These
documents were based on single passive failures of emergency core cooling systems.
Therefore, the licensee should have responded with a "YES" answer to questions 1 and
2 in the safety evaluation, which would have required prior NRC approval before these
changes were made to the GGNS FSAR. As stated above the licensee has submitted a
request to the NRC seeking approval of changes to the standby passive failure
methodology and has implement compensatory measures as an interim actions.
Documents reviewed as part of this inspection are listed in the attachment. The
enforcement aspects of this finding were discussed in NRC Inspection Report
05000416/2012008 in Section 1R21.2.3. This LER is closed.
b.
Findings
No findings were identified.
.8
Reactor Scram Following a Phase A Unit Differential Relay Trip
a.
Inspection Scope
On December 29, 2012 at approximately 12:18 a.m, the plant scrammed from 100
percent power. Upon responding to the site at 2:30 a.m., the inspectors learned that the
initial cause of the scram appeared to be the phase A unit differential relay tripping,
causing a generator lockout relay to trip, which resulted in a turbine trip and reactor
scram due to power being greater than 40 percent. The inspectors verified that all the
control rods were inserted and settled at position 00, and that reactor water level
- 45 -
lowered to approximately +7 inches narrow range (approximately 174 inches above top
of active fuel) and being maintained with reactor feedwater pump turbine A at
approximately +36 inches using startup level control. Reactor vessel pressure increased
on the trip from its nominal value of approximately 1035 psig to approximately 1116 psig,
and this caused the low-low level set to initiate as expected.
Additionally, the valve B21-F047A (automatic depressurization system safety relief
valve) lifted (normal mechanical lift pressure is 1113 psig), but the valve did not close
when it should have, and lowered reactor pressure vessel pressure to approximately 675
psig. The licensee entered their procedures to shut the valve, and when they took the
control switch to close, the valve closed. They also removed the fuses for this valve.
The licensee determined that the mechanical relief function for the valve was inoperable
but the safety relief function and automatic depressurization function were still operable.
The licensees maintained the plant in a hot shutdown condition until restart. The
inspectors reviewed the force outage list with plant staff and monitored troubleshooting
of plant issues. The licensee could not duplicate the condition with the phase A unit
differential relay through testing but elected to replace this relay prior to restart.
Additionally the licensee placed recording equipment on the various relays to monitor
response during startup.
Specific documents reviewed during this event follow-up are listed in the attachment.
These activities constitute completion of one event follow-up as defined in Inspection
Procedure 71153-05.
b.
Findings
No findings were identified.
4OA5 Other Activities
.1
Power Uprate Related Inspection Activities: Licensee Actions for New or More Likely
a. Inspection Scope
During the inspection period, the inspectors verified that the licensee has taken all
required actions to address the effects of new or more probable initiating events as
stated in the license amendment, licensee commitments, or in the safety evaluation
report. The inspectors verified that the applicable Off-Normal Event Procedures,
Emergency Procedures, and Severe Accident Procedures had been revised to
incorporate the operational changes made due to the extended power uprate.
These activities constitute the completion of one inspection sample as defined in
Inspection Procedure 71004, Section 2.01.
- 46 -
b. Findings
No findings were identified.
.2
Power Uprate Related Inspection Activities: Completion of the Grand Gulf Nuclear
Station Extended Power Uprate Inspection Plan (IP 71004)
a. Inspection Scope
Inspection Procedure 71004, Power Uprate, requires that several samples be selected
for inspection. The samples selected were risk-informed and focused on items
concerning new integrated plant response characteristics, new operator procedures, and
plant safety during any required tests. The inspection effort is summarized below in
which each sample, applicable inspection procedure used and report number in which
the results were documented are provided.
Report No.: 05000416/2012002
Sample Description
Procedure
Standby service water siphon line
extension modification
Standby liquid control system (Boron-10
enrichment change) modification
Steam dryer assembly welding processes
and examinations
Review of Anticipated Transient Without a
Scram Safety Evaluation
Flow Accelerated Corrosion monitoring and
maintenance program
71004
Report No.: 05000416/2012003
Sample Description
Procedure
Power Range Neutron Monitoring
modification
Replacement steam dryer 10CFR50.59
Evaluation for current operating power limit
(3898 MWth)
Post modification test for ultimate heat sink
siphon piping replacement and extension
Power Range Neutron Monitoring system
post maintenance test after installation
- 47 -
Operator training and requalification
program
Power Range Neutron Monitoring system
functional test prior to startup
Report No.: 05000416/2012004
Sample Description
Procedure
Power ascension testing as described in
Appendix 9 of the EPU license amendment
71004
Power Range Neutron Monitoring system
calibration at EPU power (4408 MWth)
Operator actions during integrated plant
evolutions
71004
Operator training at EPU power (4408
MWth)
Report No.: 05000416/2012005
Sample Description
Procedure
Verify licensee has taken all necessary
actions to address the effects of new or
more likely initiating events as stated in the
license amendment, licensee
commitments, or the safety evaluation
71004
.3
Licensee Strike Contingency Plans (92709)
a. Inspection Scope
On October 1, 2012, Grand Gulf Nuclear Station initiated a lockout of bargaining unit
security officers due to their vote against the ratification of the contract that expired
September 30, 2012. In accordance with Inspection Procedure 92709, Licensee Strike
Contingency Plans, the resident inspectors monitored the need for compensatory
measures on a daily basis and reported adverse conditions to regional management and
security specialists for assessment. The residents also verified support from the local
authorities were adequate to ensure that personnel had unimpeded access to the plant,
delivery of support goods and offsite shipment of radioactive materials were
unencumbered, unimpeded access to medical care and ambulance services, and
unimpeded access to the local fire department to supplement the site fire fighting unit.
Security inspectors from the regional office provided oversight for the turn-over of the
bargaining security force to the contingency security force. The bargaining unit security
force voted to ratify a new contract on November 16, 2012. The resident inspectors
- 48 -
interviewed security management and along with regional security inspectors reviewed
the sites reintegration plan to ensure adequate security coverage would be maintained
during the reintegration process. Documents reviewed are listed in the attachments.
b. Findings
No findings were identified.
.4
(Closed) URI 05000416/2012008-07, Potential Internal Flooding Caused by Circulation
Water System Failure
a. Inspection Scope
On October 9, 2012, the NRC issued NRC Inspection Report 05000416/2012008, which
documented the results of an component design bases inspection conducted from
June 25, 2012, to September 10, 2012. In this inspection report, the NRC issued
Unresolved Item 05000416/2012008-07, Potential Internal Flooding Caused by
Circulation Water System Failure. This unresolved item was related to the licensees
evaluation of internal flooding events resulting from the postulated failure of circulating
water system components in the turbine building Calculation M6.3.051, Circulating
Water System-Calculate Revised Plant Flooding Elevations Due to Aux Cooling Tower,
Revision B. Specifically, the licensees design basis flooding analysis was based on a
steady state comparison of the volume of the circulating water system to the available
volume in the unit 1 turbine building, the canceled unit 2 turbine building, the radwaste
building, and control building. The inspectors determined this analysis failed to consider
the effects of large sliding doors, which are not watertight when closed, between the
unit 1 turbine building and the unit 2 turbine building and between the unit 1 turbine
building and radwaste building. It also failed to consider closed nonwatertight doors
between unit 1 turbine building and the control building. Additionally, it failed to include
the contribution of makeup flow from plant service water. With the assumption that the
doors are closed and wont fail, the inspectors questioned whether the flood level in the
unit 1 turbine building could increase to levels that would affect adjacent auxiliary
building and control building rooms that contain safety-related equipment.
During the component design bases inspection, the licensee performed
Calculation M6.3.051-001, Circulating Water Systems - Calculate Revised
Unit 1 Turbine Building and Unit 1 Control Building Flooding Elevations,
Revision 0, to correct deficiencies with the original internal flood analysis
(Condition Report CR-GGN-2012-09424). This analysis concluded that, with closed
doors and contribution of plant service water, the water level in the unit 1 turbine building
would increase, but the increase would not affect safety-related equipment in the
adjacent auxiliary and control building rooms. Although the analysis concluded that
plant protection from internal floods would not be adversely affected, the inspectors
disagreed with the assumption for flowrate from a postulated expansion joint failure in
the circulating water system. The calculation used the methodology of NRC Branch
Technical Position MEB 3-1 to predict the maximum flow from a failed circulating water
system expansion joint. Applying the MEB 3-1 methodology to the 10-foot diameter
expansion joint resulted in a postulated crack of 5-feet long and 1-inch wide. This crack
- 49 -
resulted in a calculated leak rate of approximately 15,500 gallons per minute. The
inspectors questioned the applicability of NRC Branch Technical Position MEB 3-1 to
nonsafety-related expansion joints and whether the crack leak rate should be
significantly higher if a gross failure was assumed in the updated final safety analysis
report. The inspectors discussed this design and licensing basis issue with NRC staff in
the Office of Nuclear Reactor Regulation. Due to complexity of establishing the
appropriate design and licensing bases for this issue, this item was considered
unresolved pending further NRC review to determine if a finding existed.
On November 15, 2012, the inspectors completed an internal flooding inspection, as
documented in Section 1R06 of this report. During the inspection, the inspectors toured
the circulating water system, including the circulating water pumps, from the cooling
tower to the unit 1 condenser. The inspection included a visual inspection of the doors
connecting the unit 1 turbine building to adjacent buildings, including complete
inspection of the flood barriers connecting the unit 1 turbine building to the auxiliary
building.
Additionally, during this inspection, the inspector requested the licensee perform an
internal flood analysis assuming the expansion joint failure leak rate was
290,000 gallons per minute. This represented a complete failure of the expansion joint
and runout flow of the circulating water system pumps. This analysis concluded that the
water level in the unit 1 turbine building would increase, but the increase would not affect
safety-related equipment in the adjacent auxiliary and control building rooms.
From the review, the inspectors determined that the auxiliary building flood barriers
would mitigate affects of an internal flood. Additionally, the inspectors determined that it
is very unlikely that a failure of the expansion joint would discharge the entire volume of
water of the circulating water system assumed in the internal flood analysis based on the
configuration and operation of the circulating water system. That is, the circulating water
system is an open system; when the system loses vacuum, the deep draft pumps would
shut down leaving a large water volume in the circulating water system basin and only
contents in the circulating water system pipe would drain through the failed expansion
joint.
Since the inspectors confirmed that safety-related equipment would not be affected,
assuming the maximum expansion joint failure leak rate and flood barriers would protect
the auxiliary building, the inspectors did not identify a finding. Therefore, Unresolved
Item 05000416/2012008-07, Potential Internal Flooding Caused by Circulation Water
System Failure, is closed.
b. Findings
No findings were identified.
.5
Temporary Instruction 2515/187 - Inspection Near Term Task Force Recommendation
2.3 Flooding Walkdowns
- 50 -
a. Inspection Scope
Inspectors verified that the licensees walkdown packages, WP1, WP2, WP6, and WP7
contained the elements as specified in NEI 12-07 Walkdown Guidance document. The
inspectors accompanied the licensee on their walkdown of the plant yard topography
inside the protected area and the safety related switchgear room on the 111 ft. elevation
in the control building and verified that the licensee confirmed the following flood
protection features:
Visual inspection of the flood protection feature was performed if the flood
protection feature was relevant. External visual inspection for indications of
degradation that would prevent its credited function from being performed was
performed
Critical SSC dimensions
Available physical margin, where applicable, was determined
Flood protection feature functionality was determined using either visual
observation or by review of other documents
The inspectors independently performed their walkdown and verified that the following
flood protection features were in place:
Plant yard grade at the 133 ft. elevation of the control building was such that
water would be shed away from the building
Staged sandbags were properly stored and in good material condition
Reasonable simulation building sandbag flood barrier
The inspectors verified that noncompliances with current licensing requirements and
issues identified in accordance with the 10 CFR 50.54(f) letter, Item 2.g of Enclosure 4,
were entered into the licensees corrective action program. In addition, issues identified
in response to Item 2.g that could challenge risk significant equipment and the licensees
ability to mitigate the consequences will be subject to additional NRC evaluation.
b. Findings
No NRC-identified or self-revealing findings were identified.
.6
Temporary Instruction 2515/188 - Inspection of Near-Term Task Force
Recommendation 2.3 Seismic Walkdowns
The inspectors accompanied the licensee on their seismic walkdowns of the following
areas and equipment:
- 51 -
Date
Building
Elevation
Area
Equipment
09/18/2012 Diesel Generator
Building
136 ft
1D308
Control Panel H13P401
10/05/2012 Auxiliary Building
93 ft
1A106
E12B002B
10/09/2012 Control Building
189 ft
OC703
Control Panel H13P669
10/09/2012 Control Building
189 ft
OC703
E51N602A
The inspectors verified that the licensee confirmed that the following seismic features
associated with listed equipment were free of potential adverse seismic conditions such
as:
Anchorage was free of bent, broken, missing, or loose hardware
Anchorage was free of corrosion that is more than mild surface oxidation
Anchorage was free of visible cracks in the concrete near the anchors
Anchorage configuration was consistent with plant documentation
SSCs will not be damaged from impact by nearby equipment of structures
Overhead equipment, distribution systems, ceiling tiles and lighting, and masonry
block walls are secure and not likely to collapse onto the equipment
Attached lines have adequate flexibility to avoid damage
The area appears to be free of potentially adverse seismic interactions that could
cause a fire in the area
The area appears to be free of potentially adverse seismic interactions
associated with housekeeping practices, storage of portable equipment, and
temporary installations (e.g. scaffolding, lead shielding)
The inspectors independently performed their walkdown and verified that the equipment
and areas listed in Table 2 were free of potential adverse seismic conditions as
described above.
- 52 -
Date
Building
Elevation Area
Equipment
10/18/2012
SSW Pump Building 133 ft
2M110
Y47N005B
11/28/2012
Auxiliary Building
93 ft
1A104
E51F046
Observations made during the walkdown that could not be determined to be acceptable
were entered into the licensees corrective action program for evaluation.
Additionally, inspectors verified that items that could allow the spent fuel pool to drain
down rapidly were added to the SWEL and these items were walked down by the
licensee.
b. Findings
No NRC-identified findings or self-revealing findings were identified.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On January 17, 2013, the inspectors presented the inspection results to Mr. 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.
On December 3, 2012, the inspector presented the results of the radiation safety inspection to
Ms. C. Perino, Director of Nuclear Safety Assurance, 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
The following violation of very low security significance (Green) was identified by the licensee
and is a violation of NRC requirements which met the criteria of NRC Enforcement Policy for
being dispositioned as a non-cited violation.
10 CFR 74.19 requires, in part, that each licensee keep records of inventory including location,
transfer, and disposal of all special nuclear material and conduct an annual physical inventory of
all special nuclear material in its possession. Contrary to the above, before July 25, 2012, the
licensee did not keep records of inventory including location, transfer, and disposal of all special
nuclear material, in that on that date and after completing an inventory and records review of
SNM pursuant to the material control and accounting program, licensee reactor engineers
declared a source range monitor (SRM) detector lost. Specifically, SRM with serial number
1OF007J5 was not in its expected storage location. Using Manual Chapter 0609, Appendix D,
- 53 -
Public Radiation Safety Significance Determination Process, the inspectors determined that
this finding had very low safety significance (Green) because it resulted in no dose to a member
of the public in the restricted area, controlled area or the unrestricted area.
A1-1
Attachment
Attachment 1: SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
J. Dorsey, Security Manager
H. Farris, Assistant Operations Manager
J. Gerard, Interim Operations Manager
J. Giles, Manager, Training
M. Krupa, Director, Major Projects
C. Justiss, Licensing
C. Lewis, Manager, Emergency Preparedness
E. Mason, Auditor, Quality Assurance
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
J. Richardson, Director, Power Upgrade Project
R. Scarbrough, Specialist and Lead Offsite Liaison, Licensing
J. Seiter, Acting Manager, Licensing
J. Shaw, Manager, System Engineering
T. Thurmon, Supervisor, Design Engineering-Mechanical
T. Trichell, Manager, Radiation Protection
D. Wiles, Engineering Director
E. Wright, Supervisor, ALARA
NRC Personnel
None
A1-2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed 05000416/2012005-01 NCV Failure to Make Timely Corrective Actions to Repair the Degraded
Auxiliary Building Water Intrusion Barrier (Section 1R12.b.1)05000416/2012005-02 NCV Failure to Adequately Monitor the Condition of the Auxiliary
Building Water Intrusion Barrier (Section (1R12.b.2)05000416/2012005-03 NCV Failure to Implement Adequate Procedure Instructions to Perform
Preventive Maintenance Requiring the Periodic Replacement of
the Control Relays in GE Magne Blast Circuit Breakers (Section
1R20.b)05000416/2012005-04 FIN Failure to Adequately Plan and Control Work Activities to Maintain
ALARA (Section 2RS02.b.1)05000416/2012005-05 NCV Failure To Follow the Radiation Work Permit Requirements During
Reactor Cavity High Water Operations (Section 2RS02.b.2)05000416/2012005-06 NCV Failure to Evaluate the Risk Significances and Develop Action
Plans to Address Equipment Identified During Extent of Condition
Review for a Post Scram Root Cause Analysis (Section 4A03.2.b)05000416/2012005-07 NCV Failure to Establish Gain Settings on APRM and LPRM
Instruments in Accordance with Design Requirements (Section
4A03.5.b)
Inspection Near Term Task Force Recommendation 2.3 Flooding
Walkdowns (Section 4OA5.5)
Inspection of Near-Term Task Force Recommendation 2.3
Seismic Walkdowns (Section 4OA5.6)
Closed 05000416/2012008-07
URI Potential Internal Flooding Caused by Circulation Water System
Failure (Section 4OA5.4)
05000416/2012-001-00 LER Surveillance Test Procedure Inadequate to Meet the
Requirements of Technical Specifications (Section 4OA3.1)
05000416/2012-002-00 LER Manual Reactor Scram Due to a Steam Supply Motor Operated
Valve Failure that Resulted in the Inability to Maintain Reactor
Water Level (Section 4OA3.2)
05000416/2012-003-00 LER ESF Actuation Due to Division III Bus Undervoltage following a
Lighting Strike (Section 4OA3.3)
05000416/2012-004-00 LER Weld Defect Indication Found in Residual Heat Removal System
to Reactor Pressure Vessel Boundary Nozzle (Section 4OA3.4)
A1-3
Closed
05000416/2012-005-00 LER Average Power Range Monitors Inoperable in Excess of
Technical Specification Allowances in Mode 2 (Section 4OA3.5)
05000416/2012-006-00 LER Special Nuclear Material Inventory Discrepancy (Section
4OA3.6)
05000416/2012-007-00 LER Standby Service Water System Administratively Inoperable For A
Period Longer Than Allowed By Technical Specifications
(Section 4OA3.7)
A1-4
LIST OF DOCUMENTS REVIEWED
Section 1R04: Equipment Alignment
PROCEDURE
NUMBER
TITLE
REVISION
04-1-01-P75-1
Standby Diesel Generator System
96
04-1-01-P41-1
Standby Service Water System
136
04-1-01-E12-1
System Operating Instruction, Residual Heat Removal
System
142
DRAWINGS
NUMBER
TITLE
REVISION
M-1085D
Residual Heat Removal System
4
OTHER DOCUMENTS
NUMBER
TITLE
DATE
System Health Report E12 Residual Heat Removal
November
16, 2012
CONDITION REPORTS
A1-5
CONDITION REPORTS
Section 1R05: Fire Protection
PROCEDURES
NUMBER
TITLE
REVISION
Fire Pre Plan C-
17
Upper Relay Room - Unit 1 Area 25A
A1-6
Section 1R05: Fire Protection
PROCEDURES
NUMBER
TITLE
REVISION
04-1-01-P64-3
Fire Protection Cardox System
26
GGNS MS-55
GGNS Mechanical Standard GGNS TRM Required Fire
Rated Floor, Walls & Ceilings
0
Fire Pre-Plan
SSW-01
SSW Pump House and Valve Room, Room 1M110-SSW A
Pump House Room 1M112-SSW A Valve Room
1
Fire Pre-Plan
DG-02
DIV I Diesel Generator Room 1D302, Area 12, Elevation 133
5
Fire Pre-Plan A-
03
RCIC Pump Room - 1A104
1
OTHER DOCUMENTS
NUMBER
TITLE
DATE
2012-08
Transient Combustible Evaluation
9A.5.64
9A.5.60.1
Chemetron Fire Systems Manual
January 8,
1979
9A.5.2.4
Fire Zone 1A104: RCIC Room, Elev. 93 0
DRAWINGS
NUMBER
TITLE
REVISION
A-629
Unit I and Common Buildings Fire Protection Misc. Notes and
Details
0
E-0965
Raceway Plan Water Treatment Building El. 1330 and
STDBY Water Pump HS Basin A & B Fire and Smoke
Detection System Units I & II
7
CALCULATION
NUMBER
TITLE
DATE
MC-QSP64-
86058
Fire Zone Yard/Fire Area 59
June 13,
2001
A1-7
CONDITION REPORTS
Section 1R06: Flood Protection Measures
PROCEDURES
NUMBER
TITLE
REVISION
05-1-02-VI-1
Off-Normal Event Procedure Flooding
109
04-1-02-1H13-P680-
Alarm Response Instruction, Turbine Building E
Floor Drain Sump Level Hi-Hi
100
04-1-02-1H13-P680-
Alarm Response Instruction, Turbine Building W
Equipment Drain Sump Level Hi-Hi
100
04-1-02-1H13-P680-
Alarm Response Instruction, Turbine Building E
Equipment Drain Sump Level Hi-Hi
100
04-1-02-1H13-P680-
Alarm Response Instruction, Turbine Building W
Floor Drain Sump Level Hi-Hi
100
04-1-02-1H13-P870-
Alarm Response Instruction, Circulating Water
Expansion Joint Seal Level Hi
113
CALCULATIONS
NUMBER
TITLE
REVISION
M6.3.051
Circulating Water System - Calculate Revised Plant Flooding
Elevations Due to the Aux Cooling Tower
B
M6.3.043
Circulating Water System - Calculate Water Volume of
C
A1-8
CALCULATIONS
NUMBER
TITLE
REVISION
M6.3.051-001
Circulating Water Systems - Calculate Revised Unit 1
Turbine Building and Unit 1 Control Building Flooding
Elevations
0
DRAWINGS
NUMBER
TITLE
REVISION
C-1706C
Unit 1 & 2 Circulating Water System Circulating Water
Piping Sections and Details
11
M154.0-
N1N71G521A-
1.2-006
Garlock Style 204 & 204HP Expansion Joints
1
M-1059A
P&I Diagram, Circulation Water System
41
M-1059B
P&I Diagram, Circulating Water System, Unit 1
18
SFD-1059
System Flow Diagram, Circulating Water System, Unit 1
2
A-0010
Units 1 & 2 General Floor Plan, Fl. Plan at El. 93-0 &
103-0
10
A-0011
Units 1 & 2 Gen. Fl. Plan. - Fl. Plan at El. 111-0, 113-
0, 118-0, & 119-0
8
E-1152-033
Schematic Diagram, Circulating Water System, Main
Control Room Annunciation, Unit 1
14
ENGINEERING CHANGES
NUMBER
TITLE
REVISION
A1-9
ENGINEERING CHANGES
NUMBER
TITLE
REVISION
Calculate Revised Unit 1 Turbine Building and Unit 1
Control Building Flooding Elevations
0
VENDOR DOCUMENTS
NUMBER
TITLE
REVISION
9645-A-021.0
Bechtel Material Requisition - Watertight Doors
8
WORK ORDERS
WO 52306120 01
WO 52323476 01
WO 52323703 01
CONDITION REPORTS
Section 1R11: Licensed Operator Requalification Program
PROCEDURES
NUMBER
TITLE
REVISION
03-1-01-2
Integrated Operating Instruction Power Operations
152
Reactivity Maneuver Plan (BWR)
1
Reactivity Maneuver Plan
1
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
2012 Cycle 6 Licensed Operator Requal Simulator Training
Plan Simulator Differences
GSMS-LOR-
WEX17
LOR Training APRM Downscale/Loss of Condenser
Vacuum/LOCA/Degraded ECCS (EP-2, EP-3)
18
A1-10
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
Grand Gulf Cycle
19
Periodic Log
November
20, 2012
Section 1R12: Maintenance Effectiveness
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
GGNS-C-399.0
Maintenance Rule Inspection of Structures, Tanks, and
Transformers Inspections
9
Maintenance Rule Scope and Basis
2
Condition Monitoring of Maintenance Rule Structures
2
1
Maintenance Rule Monitoring
4
Maintenance Rule (a)(1) Process
1
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
EQ04.10
9kV Power Cable
1
ER-GG-2005-
0144-000
Evaluate Water Inleakage into the Enclosure Bldg.
0
GGNS-96-0075
Assessment of Grand Gulf Compliance with the Guidelines of
NEI 96-03, Rev. D and the Maintenance Rule for Monitoring
the Condition of Structures
2
Attachment 9.1
Maintenance Rule Functional Failure Evaluation, CR-GGN-
2012-08921 CA 00051
October 5,
2012
CONDITION REPORTS
A1-11
CONDITION REPORTS
A1-12
CONDITION REPORTS
A1-13
CONDITION REPORTS
WORK ORDERS
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
02-S-01-17
Control of Limiting Conditions for Operation
123
Online Emergent Work Add/Delete Approval Form
November 1,
2012
07-S-02-300
Fuel and Core Component Movement Control
125
07-S-05-300
Control and Use of Cranes and Hoists
113
Material Handling Program
13
05-1-02-V-12
Off-Normal Event Procedure, Condensate/Reactor Water
High Conductivity
25
Attachment 9.1 Online Emergent Work Add/Delete Approval
Form, WO 52313215
9
01-S-18-6,
Attachment VI
Risk Assessment of Maintenance Activities
119
02-S-01-41
On Line Risk Assessment
7
A1-14
OTHER DOCUMENTS
NUMBER
TITLE
DATE
LCOTR No.:1-TS-12-0290
LCOTR No.:1-TS-12-0228
LCOTR No.:1-TS-12-0261
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December 9,
2012
9:34 pm
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
10, 2012
7 am
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
10, 2012
10:56 am
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
10, 2012
3:45 pm
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
10, 2012
7:50 pm
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
11, 2012
7:20 pm
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
12, 2012
8:07 pm
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
12, 2012
10 pm
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
13, 2012
1:02 am
Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel
Status: Fueled
December
13, 2012
1:35 am
CONDITION REPORTS
A1-15
WORK ORDERS
ENGINEERING CHANGES
Section 1R15: Operability Evaluations
PROCEDURE
NUMBER
TITLE
REVISION
Operability Determination Process: CR-GGN-2012-12133
6
OTHER DOCUMENTS
NUMBER
TITLE
DATE
460000286
Limitorque Valve Controls
July 16, 2007
ASM Handbook, Volume 13A - Corrosion: Fundamentals,
Testing, and Protection
2003
Structural Analysis and design of Process Equipment, 2nd
Edition
1989
Eddie Current Test Data for Div II Emergency Diesel
Generator Jacket Water Heat Exchanger
November 1,
2012
March 2007
February
1977
DRAWINGS
NUMBER
TITLE
REVISION
E-1111-013
P75 Stand-by Diesel Generator SYS DIV II Train B Start
Circuit
16
E-1111-012
P75 Stand-by Diesel Generator SYS DIV II Train A Start and
Stop Circuit
13
A1-16
DRAWINGS
NUMBER
TITLE
REVISION
Figure 1
Boundary and Support Systems of Emergency Diesel
Generator Systems
4
CALCULATIONS
NUMBER
TITLE
REVISION /
DATE
MC-Q1P75-
98030
Standby Diesel Jacket Water Operating Parameters
1
CONDITION REPORTS
ENGINEERING CHANGES
Section 1R19: Post-Maintenance Testing
PROCEDURES
NUMBER
TITLE
REVISION
07-S-23-P75-2
Diesel Generator DIV I and DIV II Functional Check
Overspeed Trip Switch and Emergency Stop Switch
2
06-OP-1P41-Q-
005
Standby Service Water Loop B Valve and Pump Operability
Test
122
06-OP-1E12-Q-
0006
LPCI/RHR Subsystem B MOV Functional Test
111
06-OP-1E12-M-
0002
LPCI/RHR Subsystem B Monthly Functional Test
113
06-OP-1E12-Q-
0024
LPCI/RHR Subsystem B Quarterly Functional Test
118
0005
SSW Loop B Operability Check
112
06-OP-1P75-M-
0002, Attachment
Standby Diesel Generator 12 Functional Test
131
A1-17
Section 1R19: Post-Maintenance Testing
PROCEDURES
NUMBER
TITLE
REVISION
II
06-OP-1P75-M-
0002, Attachment
I
Standby Diesel Generator 12 Functional Test
131
04-1-03-P75-1
Div 2 Diesel Generator Unexcited Run
7
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Open Documents on LCOs for Diesel Generator 12
November 5,
2012
Analysis for Static Test of Gate and Globe Valves, Valve
1P41F016B
MOV Torque Switch Setpoint Methodology Set Point
Calculations, Valve No. 1P41F016B
MOV Torque Switch Setpoint Methodology Set Point
Calculations, Valve No. 1E12F006B
Preliminary Vibration Data on SSW B
41329
Stator Winding Test Report, Grand Gulf SSW Pump
GNRO-2012-
00007
Reply to Notice of Violation EA-2012-015
February 13,
2012
TR-110392
Eddy Current Testing of Service Water Heat Exchangers for
Engineers Guideline
February
1999
ASM Handbook, Vol. 13A-Corrosion: Fundamentals, Testing,
Protection
2003
WORK ORDERS
WO 00121405 01
WO 00282241 01
WO 00314300 01
WO 00319437 01
WO 00318398 01
WO 00320182 02
WO 52421359 01
WO 00272998 01
WO 00272998 04
WO 00082560 04
WO 00082560 01
WO 00082560 03
WO 00082560 08
WO 00332736 01
A1-18
CONDITION REPORTS
CR-GGN-2012-
Section 1R20: Refueling and Other Outage Activities
PROCEDURES
NUMBER
TITLE
REVISION
PO 19-01
Shutdown Operations Protection Plan: December 17, 2012
13
07-S-12-150
General Electric AM 4.16 KV Breaker Overhaul Instruction
0
07-S-12-61
Inspection of GE Magne Blast Circuit Breakers
3
07-S-12-61
Inspection of GE Magne Blast Circuit Breakers
4
07-S-12-150
General Electric AM 4.16 KV Breaker Overhaul Instruction
1
DRAWINGS
NUMBER
TITLE
REVISION
E-1188-018
Schematic Diagram, HPCS Power supply System Breaker
No.1
11
E-1009
One Line Meter & Relay Diagram 4.16KV E.S.F. System Bus
17AC
9
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
GG19-013
December Startup Power Profile
GG19-014
December Startup Power Profile
PO-19-01 Critical Path
December 9,
2012
PO-19-01 Critical Path
December
10, 2012
A1-19
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
PO-19-01 Critical Path
December
11, 2012
PO-19-01 Critical Path
December
12, 2012
GGNS PO-19-01 Planned Outage Daily Update
December
10, 2012
GGNS PO-19-01 Planned Outage Daily Update
December
11, 2012
GGNS PO-19-01 Planned Outage Daily Update
December
12, 2012
GGNS PO-19-01 Planned Outage Daily Update
December
13, 2012
LT-Apparent Cause Evaluation Report: Failure of the Division
III Diesel Generators Output Breaker to Close
June 27,
2012
GEK-7320F
Instruction, Magne Blast Circuit Breaker Types AM-4.16-350-
2C, AM-4.16-350-2H
F
PM Basis
Template
EN-Switchgear-Medium Voltage-1KV to 7KV
3
ACE Report CR-GGN-2012-07922 dated 06-27-2012
1000011
Guidance on Overhaul of Magne-Blast Circuit Breakers
December
2000
CONDITION REPORTS
Section 1R22: Surveillance Testing
PROCEDURE
NUMBER
TITLE
REVISION
06-EL-1B21-Q-
0001
ADS Timers Functional Test and Calibration
102
A1-20
Section 1R22: Surveillance Testing
PROCEDURE
NUMBER
TITLE
REVISION
06-IC-1C71-Q-
2003
Turbine Control Valve Fast Closure (RPS/EOC RPT)
Functional Test
104
WORK ORDERS
WO 52439342 01
WO 52439341 01
WO 52439340 01
Section 1EP6: Drill Evaluation
PROCEDURES
NUMBER
TITLE
REVISION
10-S-01-1
Activation of the Emergency Plan
121
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Emergency Notification Form, Message Number 1
October 16,
2012
GGNS-EP Group Drill, Emergency Facility Log
October 16,
2012
Attachment 2
Objectives/Evaluation Criteria, Performance Indicators
Attachment 3
PCRS Items, Lessons Learned
Repair and Corrective Actions-Admin Status Board
October 16,
2012
GGNS 2012 EP Drill (Blue Team)
October 16,
2012
CONDITION REPORTS
A1-21
Section 2RS02: Occupational ALARA Planning and Controls
PROCEDURES
NUMBER
TITLE
REVISION
BWR Shutdown and Startup Chemistry
0
EN-FAP-OU-100
Refueling Outage Preparation & Milestones
2
Conduct of Maintenance
3
Engineering Change Process
13
Radiation Worker Expectations
7
Access Control for Radiologically Controlled Areas
6
Radiological Control
3
Radiological Posting
11
ALARA Program
7
Source Control
9
Radiological Diving
2
Dosimetry Administration
3
Personnel Monitoring
8
Special Monitoring Requirements
6
Selection, Issue and Use of Respiratory Protection
5
AUDITS, SELF-ASSESSMENTS, AND SURVEILLANCES
NUMBER
TITLE
DATE
QA 14/15-2011
GGNS 2011 RP-RW Audit Report Final
November 30,
2011
CONDITION REPORTS
A1-22
RADIATION EXPOSURE PERMITS-ALARA POST-JOB REVIEWS
NUMBER
TITLE
REVISION
RWP-1086
Fuel Pool Cooling & Cleanup Modification
8
RWP-1402
Refuel Floor High Water
2
RWP-1403
Reactor Assembly/Disassembly
5
RWP-1406
Dryer/Separator Replacement
16
RWP-1505
Scaffold
2
RWP-1508
Under Vessel Activities
4
RWP-1511
General Drywell Maintenance
3
RWP-1516
In-Service Inspection
4
OTHER DOCUMENTS
NUMBER
TITLE
DATE
5-Year Exposure Reduction Plan 2012-2016
Grand Gulf Refuel Outage18 Report
Temporary Shielding Request 08-2
Temporary Shielding Request 12-47
Temporary Shielding Request 12-50
Refuel Outage18 Detailed Water Plan
A1-23
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Survey GG-1203-
3444
185 Auxiliary South Side Elevation
March 27, 2012
Survey GG-1202-
1383
208 Containment Auxiliary Platform
February 28,
2012
Survey GG-1202-
1329
208 Containment Refuel Bridge
February 27,
2012
Section 2RS04: Occupational Dose Assessment (71124.04)
PROCEDURES
NUMBER
TITLE
REVISION
Dosimetry Administration
3
Personnel Monitoring
8
Special Monitoring Requirements
6
Dosimeter of Legal Record
7
Selection, Issue and Use of Respiratory Protection
5
AUDITS, SELF-ASSESSMENTS, AND SURVEILLANCES
NUMBER
TITLE
DATE
QA 14/15-2011
GGNS 2011 RP-RW Audit Report Final
November 30,
2011
OTHER DOCUMENTS
NUMBER
TITLE
DATE
11-02
ANI Information Bulletin: Neutron Monitoring
July 2012
Dosimeter of Legal Record
November 26,
2012
CONDITION REPORT
A1-24
Section 4OA1: Performance Indicator Verification
PROCEDURE
NUMBER
TITLE
REVISION
Performance Indicator Process
6
OTHER DOCUMENTS
NUMBER
TITLE
DATE
NRC Performance Indicator Technique/Data Sheet, Heat
Removal (RCIC/EFW/AFW)
4th Quarter
2011
NRC Performance Indicator Technique/Data Sheet
1st Quarter
2012
NRC Performance Indicator Technique/Data Sheet
2nd Quarter
2012
NRC Performance Indicator Technique/Data Sheet
3rd Quarter
2012
NRC Resident Questions about E51-RCIC MSPI Data
4th Quarter
2011-3rd
Quarter 2012
Surveillance Tests for RCIC/E51 System
NRC Performance Indicator Technique/Data Sheet, Residual
Heat Removal (RHR)
4th Quarter
2011
NRC Performance Indicator Technique/Data Sheet
1st Quarter
2012
NRC Performance Indicator Technique/Data Sheet
2nd Quarter
2012
NRC Performance Indicator Technique/Data Sheet
3rd Quarter
2012
NRC Resident Questions about E12- Residual Heat Removal
4th Quarter
2011-3rd
Quarter 2012
4th Quarter
2011
A1-25
OTHER DOCUMENTS
NUMBER
TITLE
DATE
NRC Performance Indicator Technique/Data Sheet, High
Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI)
4th Quarter
2011
NRC Performance Indicator Technique/Data Sheet, High
Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI)
1st Quarter
2012
NRC Performance Indicator Technique/Data Sheet, High
Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI)
2nd Quarter
2012
NRC Performance Indicator Technique/Data Sheet, High
Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI)
3rd Quarter
2012
NRC Performance Indicator Technique/Data Sheet,
4th Quarter
2011
NRC Performance Indicator Technique/Data Sheet,
1st Quarter
2012
NRC Performance Indicator Technique/Data Sheet,
2nd Quarter
2012
NRC Performance Indicator Technique/Data Sheet,
3rd Quarter
2012
NRC Resident Questions about Division I and II Standby
Diesel Generators
4th Quarter
2011-3rd
Quarter 2012
NRC Resident Questions about E22 High Pressure Core
Spray
4th Quarter
2011-3rd
Quarter 2012
NRC Performance Indicator Technique/Data Sheet, Cooling
Water Support
4th Quarter
2011
NRC Performance Indicator Technique/Data Sheet, Cooling
Water Support
1st Quarter
2012
NRC Performance Indicator Technique/Data Sheet, Cooling
Water Support
2nd Quarter
2012
NRC Performance Indicator Technique/Data Sheet, Cooling
Water Support
3rd Quarter
2012
Operations Surveillances for Stand-by Service Water P41
System
A1-26
Section 4OA2: Identification and Resolution of Problems
PROCEDURES
NUMBER
TITLE
REVISION/
DATE
04-1-01-P44-1
Plant Service Water/Radial Well System
99
05-1-02-III-12
Off-Normal Event Procedure
0
Work Request Generation, Screening, and Classification
8
EN-FAP-OP-009 Tagging Performance Indicator Program
2
Entergy Trending Process
12
On-Line Work Management Process
9
Attachment 9.5
Operator Aggregate Assessment of Plant Deficiencies
April 2012
Operations Assessments
4
EN-FAP-OP-006 Operator Aggregate Impact Index Performance Indicator
0
Attachment 9.5
Operator Aggregate Assessment of Plant Deficiencies
November
2012
07-S-12-61
Inspection of GE MagnaBlast Circuit Breakers
110
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Standing Orders
October 14,
2012
Operator Compensatory Actions
October 2012
ODMIs In Effect
November 14,
2012
List of Inputs to Operation Aggregate Index
October 2012
Tagouts Older than 90 days Report
August 19,
2012
Caution Tagouts Older than 90 days Report
August 19,
2012
Items Affecting Operations Aggregate Index
March 1,
2012
Remaining Open Actions For Open GGN Crs with Operability
April 17, 2012
A1-27
OTHER DOCUMENTS
NUMBER
TITLE
DATE
GGNS Quarterly Trend Report 1st and 2nd Quarter 2012
October 3,
2012
Open ODMI Actions
March 2012
Remaining Open Actions For Open GGN Crs with Operability
Code: OPERABLE-COMP MEAS
April 17, 2012
Grand Gulf Operator Aggregate Impact Index
November
2011
Grand Gulf Operator Aggregate Impact Index
December
2011
Grand Gulf Operator Aggregate Impact Index
January 2012
Grand Gulf Operator Aggregate Impact Index
February
2012
Grand Gulf Operator Aggregate Impact Index
March 2012
Grand Gulf Operator Aggregate Impact Index
April 2012
Grand Gulf Operator Aggregate Impact Index
May 2012
Grand Gulf Operator Aggregate Impact Index
June 2012
Grand Gulf Operator Aggregate Impact Index
July 2012
Grand Gulf Operator Aggregate Impact Index
August 2012
Grand Gulf Operator Aggregate Impact Index
September
2012
Grand Gulf Operator Aggregate Impact Index
October 2012
Grand Gulf Operator Aggregate Impact Index
November
2012
Grand Gulf Operator Burdens (OB)
November
2011
Grand Gulf Operator Burdens (OB)
December
2011
Grand Gulf Operator Burdens (OB)
January 2012
Grand Gulf Operator Burdens (OB)
February
2012
A1-28
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Grand Gulf Operator Burdens (OB)
March 2012
Grand Gulf Operator Burdens (OB)
April 2012
Grand Gulf Operator Burdens (OB)
May 2012
Grand Gulf Operator Burdens (OB)
June 2012
Grand Gulf Operator Burdens (OB)
July 2012
Grand Gulf Operator Burdens (OB)
August 2012
Grand Gulf Operator Burdens (OB)
September
2012
Grand Gulf Operator Burdens (OB)
October 2012
Grand Gulf Operator Burdens (OB)
November
2012
Grand Gulf Operator Workarounds (OWA)
November
2011
Grand Gulf Operator Workarounds (OWA)
December
2011
Grand Gulf Operator Workarounds (OWA)
January 2012
Grand Gulf Operator Workarounds (OWA)
February
2012
Grand Gulf Operator Workarounds (OWA)
March 2012
Grand Gulf Operator Workarounds (OWA)
April 2012
Grand Gulf Operator Workarounds (OWA)
May 2012
Grand Gulf Operator Workarounds (OWA)
June 2012
Grand Gulf Operator Workarounds (OWA)
July 2012
A1-29
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Grand Gulf Operator Workarounds (OWA)
August 2012
Grand Gulf Operator Workarounds (OWA)
September
2012
Grand Gulf Operator Workarounds (OWA)
October 2012
Grand Gulf Operator Workarounds (OWA)
November
2012
Grand Gulf Control Room Deficiencies
November
2011
Grand Gulf Control Room Deficiencies
December
2011
Grand Gulf Control Room Deficiencies
January 2012
Grand Gulf Control Room Deficiencies
February
2012
Grand Gulf Control Room Deficiencies
March 2012
Grand Gulf Control Room Deficiencies
April 2012
Grand Gulf Control Room Deficiencies
May 2012
Grand Gulf Control Room Deficiencies
June 2012
Grand Gulf Control Room Deficiencies
July 2012
Grand Gulf Control Room Deficiencies
August 2012
Grand Gulf Control Room Deficiencies
September
2012
Grand Gulf Control Room Deficiencies
October 2012
Grand Gulf Control Room Deficiencies
November
2012
A1-30
OTHER DOCUMENTS
NUMBER
TITLE
DATE
Grand Gulf Control Room Alarm (CRA)
November
2011
Grand Gulf Control Room Alarm (CRA)
December
2011
Grand Gulf Control Room Alarm (CRA)
January 2012
Grand Gulf Control Room Alarm (CRA)
February
2012
Grand Gulf Control Room Alarm (CRA)
March 2012
Grand Gulf Control Room Alarm (CRA)
April 2012
Grand Gulf Control Room Alarm (CRA)
May 2012
Grand Gulf Control Room Alarm (CRA)
June 2012
Grand Gulf Control Room Alarm (CRA)
July 2012
Grand Gulf Control Room Alarm (CRA)
August 2012
Grand Gulf Control Room Alarm (CRA)
September
2012
Grand Gulf Control Room Alarm (CRA)
October 2012
Grand Gulf Control Room Alarm (CRA)
November
2012
Grand Gulf Caution Tags > 90 days
November
2011-
November
2012
Grand Gulf Tagouts > 90 days
November
2011-
November
2012
A1-31
CONDITION REPORTS
A1-32
CONDITION REPORTS
Section 4OA3: Event Follow-Up
PROCEDURES
NUMBER
TITLE
REVISION
Root Cause Evaluation Process
18
05-S-01-EP-1
Emergency/Severe Accident Procedure Support Documents
27
06-RE-1C51-O-
0001
Local Power Range Monitor Calibration
112
17-S-02-40
Bypassing and Unbypassing LRPMs
116
04-1-01-C51-1
Neutron Monitoring
28
04-1-02-1H13-
P680-5A-C9
LPRM DNSC
206
A1-33
Section 4OA3: Event Follow-Up
PROCEDURES
NUMBER
TITLE
REVISION
07-S-33-C51-2
LPRM Detector Removal/Installation
112
07-S-33-C51-2
LPRM Detector Removal/Installation
113
03-1-01-1
Cold Shutdown to Generator Carrying Minimum Load
154
06-RE-1C51-O-
0001
Local Power Range Monitor Calibration
112
06-RE-1C51-W-
0001
APRM Gain Adjustment
106
01-S-06-26
Post-Trip Analysis, Scram # 126, December 31, 2012
20
02-S-01-27
Operations Philosophy
49
01-S-06-5
Event Notification Worksheet EN#48637
110
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
00160640
Action Request Identification
October 22,
2012
CA 34 for CR-GGN-2012-1842
CA 35 for CR-GGN-2012-1842
CA 43 for CR-GGN-2012-1842
GNRO-2012-
00013
GGNS LER 2012-001-00 Surveillance Test Procedure
Inadequate to meet the Requirements of Technical
Specifications
March 13,
2012
GNRO-2012-
00028
GGNS LER 2012-002-00 Manual Reactor Scram Due to a
Steam Supply Motor Operated Valve Failure that Resulted in
the Inability to Maintain Reactor Water Level
April 19, 2012
A1-34
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
GNRO-2012-
00048
GGNS LER 2012-003-00 Actuation Due to Division III Bus
Undervoltage following a Lightening Strike
May 29, 2012
GNRO-2012-
00069
GGNS LER 2012-004-00 Weld Defect Indication Found in
Residual Heat Removal System to Reactor Pressure Vessel
Boundary Nozzle
June 27,
2012
GNRO-2012-
00084
GGNS LER 2012-005-00 Average Power Range Monitors
Inoperable in Excess of Technical Specifications Allowances
in Mode 2
August 13,
2012
GNRO-2012-
00090
Special Report 2012-006-00 Special Nuclear Inventory
Discrepancy
August 23,
2012
Root Cause Evaluation Report, Inability to Maintain Reactor
Water Lever, CR-GGN-2012-1842
July 11, 2012
Apparent Cause Evaluation Report PRNM Issues During
RF18 Power Ascension, CR-GGN-2012-8224
1
GNRO-
2012/00108
GGNS LER 2012-007-00 Standby Service Water System
Administratively Inoperable For A Period Longer Than
Allowed By Technical Specifications
September
14, 2012
Core Operating Limits Report
12034
22A3739AE
Neutron Monitoring System
6
SDC-C71
0
SDC-C51
Neutron Monitoring System
0
Chapter 7
Chapter 7
GG Technical Specifications and Bases
SCN No:
96/0001
Standard/Specific Change Notice
December
30, 2003
DRN No: 04-
1210
SDC-C51 Neutron Monitoring System
0
A1-35
OTHER DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
DRN No: 05-
1185
SDC-C71
0
Forced Outage Worklist
December
18, 2012
CONDITION REPORTS
ENGINEERING CHANGES
Section 4OA7: Licensee-Identified Violations
CONDITION REPORTS
CR-GGNS-2012-09405
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
07-S-14-310
Inspection of Mechanical Seals on Doors
10
Fukushima Near Term Task Force Recommendation 2.3
Flooding Walkdown Procedure
0
GGNS-CS-12-
0002
Flooding Walkdown Submittal Report for Resolution of
Fukushima Near-Term Task Force Recommendation 2.3:
Flooding
0
A1-36
Fukushima Near-Term Task Force Recommendation 2.3
Seismic Walk-down Procedure
0
05-1-02-VI-2
Hurricanes, Tornados, and Severe Weather
119
05-1-02-VI-1
Off-Normal Event Procedure Flooding
109
Severe Weather Response
0
DRAWINGS
NUMBER
TITLE
REVISION /
DATE
07-S-14-310
Inspection of Mechanical Seals on Doors
10
J-0133G
Installation detail-Seismic and Non Seismic Tubing Run-
STDBY. Diesel Generator
3
J-0157T
Area Temp. Element
6
Standby Service Water Pump House A and B Temperature
5
J-1512
Standby Service Water Pump House Basin A
8
J-1512- U2-C
Standby Service Water Pump House Basin A
A
J-KA1512
Standby Service Water Pump House Basin A
A
M-1026
Diesel Generator Building, Unit 1
15
M-1106A
D. Gen., ECCS., ESF. ELEC. SWGR., SSW. & CIRC. WTR.
PP. HSE. VENT. SYS. - Unit 1
12
9645-J-561.0-
Q1C61N403A-
1.1-0010
Thermo Electric Drawing 27620
OTHER
NUMBER
TITLE
REVISION /
DATE
Endorsement of Nuclear Energy Institute 12-07, Guidelines
for Performing Verification Walkdowns of Plant Flood
Protection Features
May 31, 2012
WP1
Yard Inside PA (North)
0
WP2
Yard Inside PA (South)
0
WP 3
Yard Outside PA (North)
0
WP4
Yard Outside PA (South)
0
A1-37
OTHER
NUMBER
TITLE
REVISION /
DATE
AWC-041
DG, El. 133, Room 1D308,DSL
AWC-050
SWEL1-084
H22P401, STBY DG Engine Control Panel
SWEL1-068
Y47N005B, Temperature Element (SSW Pump House B
Space)
SWEL Excel Sheet
September
17, 2012
US Army Corp of Engineers: Sandbagging Techniques
2004
ER-GG-2004-
0272-000
Acceptance of corrosion of conduit and electric boxes (CR-
July 1, 2004
PMP Site Drainage Modifications
1
GGNS-CS-12-
00003
GGNS Flooding Walkdown Submittal Report for Resolution of
Fukushima Near-Term Task Force Recommendation 2.3:
Flooding
0
GGNS-CS-12-
00002
GGNS Flooding Walkdown Submittal Report for Resolution of
Fukushima Near-Term Task Force Recommendation 2.3:
Seismic
0
GGNS-CS-12-
00004
GGNS Flooding Walkdown Submittal Report for Resolution of
Fukushima Near-Term Task Force Recommendation 2.3:
Flooding
0
CONDITION REPORTS
A1-38
CR-GGN02004-02612
A2-1
Attachment
Attachment 2: Request for Information for ALARA Planning & Controls Inspection
1. Items needed to support the ALARA Planning & Controls (71124.02) inspection to be
conducted by Louis C. Carson II are as follows:
Date of Last Inspection: February 18, 2011
A.
List of contacts and telephone numbers for ALARA program personnel
B.
Applicable organization charts
C.
Copies of audits, self-assessments, and LERs, written since date of last inspection,
focusing on ALARA
D.
Procedure index for ALARA Program
E.
Please provide specific procedures related to the following areas noted below.
Additional Specific Procedures may be requested by number after the inspector
reviews the procedure indexes.
1. ALARA Program
2. ALARA Committee
3. Radiation Work Permit Preparation
F.
A summary list of corrective action documents (including corporate and subtiered
systems) written since date of last inspection, related to the ALARA program. In
addition to ALARA, the summary should also address Radiation Work Permit
violations, Electronic Dosimeter Alarms, and RWP Dose Estimates
NOTE: The lists should indicate the significance level of each issue and the search
criteria used. Please provide documents which are searchable.
G.
List of work activities greater than 1 rem, since date of last inspection.
Include original dose estimate and actual dose.
H.
Site dose totals and 3-year rolling averages for the past 3 years (based on dose of
record)
I.
Outline of source term reduction strategy
J.
A major focus of this inspection will be the results of the power upgrade outage,
please provide the following:
Annual GGNS ALARA Report for 2011
Last post Refueling-Power- Outage Report
List of ALARA Package that Exceeded the Original Dose Projections
A2-2
Provide Written Justifications if Dose were Exceeded by 50% & 5 Person-Rem
2.
Occupational Dose Assessment (Inspection Procedure 71124.04) to be reviewed:
Date of Last Inspection: August 18, 2010
A
List of contacts and telephone numbers for the following areas:
1
Radiological effluent control
2
Engineered safety feature air cleaning systems
B
Applicable organization charts
C
Audits, self assessments, surveillances, vendor or NUPIC audits of contractor
support, and LERs written since September 2010 related to Occupational Dose
Assessment
D
Procedure indexes for Occupational Dose Assessment
E
Please provide specific procedures related to the following areas. Additional
Specific Procedures may be requested after the inspector reviews the procedure
indexes.
1. Radiation Protection Program
2. Radiation Protection Conduct of Operations
3. Personnel Dosimetry Program
4. Radiological Posting and Warning Devices
5. Air Sample Analysis
6. Performance of High Exposure Work
7. Declared Pregnant Worker
8. Bioassay Program
F
List of corrective action documents (including corporate and subtiered systems)
written since September 2010 associated with:
1. NVLAP accreditation
2. Dosimetry (TLD/OSL, etc.) problems
3. Electronic alarming dosimeters
4. Bioassays or internally deposited radionuclides or internal dose
A2-3
5. Neutron dose
NOTE; The lists should indicate the significance level of each issue and the
search criteria used.
G
List of positive whole body counts since, September 2010 names redacted if
desired
H
Part 61 analyses/scaling factors
I
The most recent National Voluntary Laboratory Accreditation Program (NVLAP)
accreditation report on the licensee or dosimetry vendor, as appropriate
Please provide this information to me by November 1, 2012; thank you in advance. If you have
any questions pertaining to the requested information or the upcoming inspection, my office
number is (817) 200-1221, or you can reach me by email at Louis.Carson@nrc.gov.