ML100420026
| ML100420026 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 02/11/2010 |
| From: | Ryan Lantz NRC/RGN-IV/DRP/RPB-D |
| To: | Ridenoure R Southern California Edison Co |
| References | |
| FOIA/PA-2011-0221, FOIA/PA-2011-0157 IR-09-005 | |
| Download: ML100420026 (97) | |
See also: IR 05000361/2009005
Text
UNITED STATES
NUC LE AR RE G UL AT O RY C O M M I S S I O N
R E GI ON I V
612 EAST LAMAR BLVD , SU I TE 400
AR LI N GTON , TEXAS 76011-4125
February 11, 2010
Mr. Ross T. Ridenoure
Senior Vice President and
Chief Nuclear Officer
Southern California Edison Company
San Onofre Nuclear Generating Station
P.O. Box 128
San Clemente, CA 92674-0128
SUBJECT: SAN ONOFRE NUCLEAR GENERATING STATION - NRC INTEGRATED
INSPECTION REPORT 05000361/2009005 and 05000362/2009005
Dear Mr. Ridenoure:
On December 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your San Onofre Nuclear Generating Station, Units 2 and 3 facilities. The
enclosed integrated inspection report documents the inspection findings, which were discussed
on January 13, 2010, 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.
This report documents nine NRC identified findings and one self-revealing finding of very low
safety significance (Green). Eight of these findings were determined to involve violations of
NRC requirements. Additionally, three licensee-identified violations, which were determined to
be of very low safety significance, are listed in this report. However, because of the very low
safety significance and because they are entered into your corrective action program, the NRC
is treating these findings as noncited violations, consistent with Section VI.A.1 of the NRC
Enforcement Policy. If you contest the violations or the significance of the noncited violations,
you should provide a response within 30 days of the date of this inspection report, with the basis
for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear
Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas,
76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,
Washington, D.C. 20555-0001; and the NRC Resident Inspector at the San Onofre Nuclear
Generating Station facility. In addition, if you disagree with the characterization of any finding 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 San Onofre Nuclear Generating Station. The information you provide will
be considered in accordance with Inspection Manual Chapter 0305.
Southern California Edison Company -2-
In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, and its
enclosure, will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records component of NRCs document system (ADAMS).
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the
Public Electronic Reading Room).
Sincerely,
/RA/
Ryan E. Lantz, Chief
Project Branch D
Division of Reactor Projects
Docket Nos. 50-361
50-362
License Nos. NPF-10 NPF-15
Enclosure:
NRC Inspection Report 05000361/2009005 and 05000362/2009005
w/Attachment: Supplemental Information
Distribution:
See next page
Southern California Edison Company -3-
cc w/Enclosure: James D. Boyd, Commissioner
Chairman, Board of Supervisors California Energy Commission
County of San Diego 1516 Ninth Street (MS 34)
1600 Pacific Highway, Room 335 Sacramento, CA 95814
San Diego, CA 92101
Douglas K. Porter, Esq.
Gary L. Nolff Southern California Edison Company
Assistant Director-Resources 2244 Walnut Grove Avenue
City of Riverside Rosemead, CA 91770
3900 Main Street
Riverside, CA 92522 Albert R. Hochevar
Southern California Edison Company
Mark L. Parsons San Onofre Nuclear Generating Station
Deputy City Attorney P.O. Box 128
City of Riverside San Clemente, CA 92675
3900 Main Street
Riverside, CA 92522 Steve Hsu
Department of Health Services
Gary H. Yamamoto, P.E., Chief Radiologic Health Branch
Division of Drinking Water and MS 7610, P.O. Box 997414
Environmental Management Sacramento, CA 95899-7414
1616 Capitol Avenue, MS 7400
P.O. Box 997377 R. St. Onge
Sacramento, CA 95899-7377 Southern California Edison Company
San Onofre Nuclear Generating Station
Michael J. DeMarco P.O. Box 128
San Onofre Liaison San Clemente, CA 92674-0128
San Diego Gas & Electric Company
8315 Century Park Ct. CP21C Chief, Technological Hazards Branch
San Diego, CA 92123-1548 FEMA Region IX
1111 Broadway, Suite 1200
Director, Radiological Health Branch Oakland, CA 94607-4052
State Department of Health Services
P.O. Box 997414 (MS 7610) Chairperson, Radiological Assistance
Sacramento, CA 95899-7414 Committee
Region IX
Mayor Federal Emergency Management Agency
City of San Clemente Department of Homeland Security
100 Avenida Presidio 1111 Broadway, Suite 1200
San Clemente, CA 92672 Oakland, CA 94607-4052
Southern California Edison Company -4-
Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov)
Deputy Regional Administrator (Chuck.Casto@nrc.gov)
DRP Director (Dwight.Chamberlain@nrc.gov)
DRP Deputy Director (Anton.Vegel@nrc.gov)
DRS Director (Roy.Caniano@nrc.gov)
DRS Deputy Director (Troy.Pruett@nrc.gov)
Senior Resident Inspector (Greg.Warnick@nrc.gov)
Resident Inspector (John.Reynoso@nrc.gov)
Branch Chief, DRP/D (Ryan.Lantz@nrc.gov)
Senior Project Engineer, DRP/D (Don.Allen@nrc.gov)
SONGS Administrative Assistant (Heather.Hutchinson@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Branch Chief, DRS/TSB (Michael.Hay@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
OEMail Resource
ROPreports
DRS/TSB STA (Dale.Powers@nrc.gov)
OEDO RIV Coordinator (Leigh.Trocine@nrc.gov)
Regional State Liaison Officer (Bill.Maier@nrc.gov)
NSIR/DPR/EP (Eric.Schrader@nrc.gov)
NSIR/DPR/EP (Steve.LaVie@nrc.gov)
File located: R:\Reactors\Songs\SO2009005-RP-GGW.doc ADAMS ML
SUNSI Rev Compl. ; Yes No ADAMS ; Yes No Reviewer Initials RL
Publicly Avail ; Yes No Sensitive Yes ; No Sens. Type Initials RL
C:DRS/EB2 C:DRS/PSB2 C:DRS/EB1 C:DRS/OB C:DRS/PSB1
NO'Keefe GWerner TFarnholtz MHaire MShannon
/RA/ /RA/ /RA/ /RA/ /RA/
2/1/10 2/1/10 1/29/10 1/28/10 2/1/10
C:DRP SRI:Songs
RLantz GWarnick
/RA/ /RA/
2/10/10 2/10/10
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 50-361, 50-362
Report: 05000361/2009005 and 05000362/2009005
Licensee: Southern California Edison Co. (SCE)
Facility: San Onofre Nuclear Generating Station, Units 2 and 3
Location: 5000 S. Pacific Coast Hwy
San Clemente, California
Dates: September 24, 2009 through December 31, 2009
Inspectors: J. Adams, Reactor Inspector
M. Bloodgood, Reactor Inspector
P. Elkmann, Senior Emergency Preparedness Inspector
A. Fairbanks, Reactor Inspector
G. Guerra, CHP, Emergency Preparedness Inspector
C. Osterholtz, Senior Operations Engineer
C. Proctor, General Scientist
J. Reynoso, Resident Inspector
L. Ricketson, Senior Health Physicist
R. Schmitt, Emergency Preparedness Specialist
G. Warnick, Senior Resident Inspector
Approved By: Ryan Lantz, Chief,
Project Branch D
Division of Reactor Projects
-1- Enclosure
SUMMARY OF FINDINGS
IR 05000361/2009005, 05000362/2009005; 09/24/2009 - 12/31/2009; San Onofre Nuclear
Generating Station, Units 2 & 3, Integrated Resident and Regional Report; Flood Prot. Meas.,
Maint. Effect., Operability Evaluations, Event Follow-up, & Other Activities.
The report covered a 3-month period of inspection by resident inspectors and announced
baseline inspections by regional based inspectors. Eight noncited violations and two findings of
significance were identified. The significance of most findings is indicated by their color (Green,
White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination
Process. 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 finding for the failure of maintenance
personnel to use the standards described in Procedure SO23-XV-2,
Troubleshooting Plant Equipment and Systems, in developing procedures and
work plans to adequately perform, test, and communicate maintenance activities
on Unit 2 circulating water gate 5. Specifically, from September 5 through
September 13, 2009, maintenance personnel did not have adequate procedures
in place to perform corrective maintenance on Unit 2 circulating water gate 5.
The attempts to repair gate 5 were repeatedly unsuccessful due to inadequate
planning, execution, postmaintenance testing, and communication. This finding
was entered into the licensees corrective action program as Nuclear Notifications
NNs 200580999 and 200718204.
The finding is greater than minor because the performance deficiency was a
precursor to a significant event (reactor trip). Using the Manual Chapter 0609,
Significance Determination Process, Phase 1 Worksheets, the finding is
determined to have very low safety significance because the finding did not
contribute to both the likelihood of a reactor trip and the likelihood that mitigation
equipment or functions would not be available. The finding has a crosscutting
aspect in the area of human performance associated with work control because
maintenance personnel failed to incorporate actions to address the need for work
groups to communicate, coordinate, and cooperate with each other during
activities in which interdepartmental coordination is necessary to assure plant
and human performance H.3(b) (Section 4OA3).
- Green. The inspectors identified a finding for the failure of operations personnel
to perform an adequate pre-job brief in accordance with procedural requirements
for a planned Unit 2 heat treat evolution. Specifically, on September 13, 2009,
operations personnel failed to provide a thorough pre-job brief in preparation for
the performance of the heat treat evolution which contributed to a delay in
operator actions which ultimately resulted in a turbine and reactor trip on low
condenser vacuum due to escalated circulating water temperatures. This finding
-2- Enclosure
was entered into the licensees corrective action program as Nuclear Notification
NN 200580999.
The finding is greater than minor because the performance deficiency was a
precursor to a significant event (reactor trip). Using the Manual Chapter 0609,
Significance Determination Process, Phase 1 Worksheets, the finding is
determined to have very low safety significance because the finding did not
contribute to both the likelihood of a reactor trip and the likelihood that mitigation
equipment or functions would not be available. The finding has a crosscutting
aspect in the area of human performance associated with resources because the
licensee failed to provide adequate procedural guidance to ensure that
operations personnel could safely perform plant evolutions H.2(c)
(Section 4OA3).
- Green. Three examples of a self-revealing noncited violation of Technical
Specification 5.5.1.1.d, was identified for the failure of contractor personnel to
properly implement the requirements of a fire protection procedure for the control
of hot work activities. Specifically, between September 1 and 29, 2009, three
examples were identified where contractor personnel failed to properly implement
the requirements of Procedure SO123-XV-1.41, Steps 6.1.1 and 6.4.1.3, in that,
combustible materials were not covered or stored at a distance of 35 feet from
the ignition source or flame, and no evaluation was performed. This finding was
entered into the licensees corrective action program as Nuclear Notification NN
200604378.
The finding is greater than minor because it is associated with the protection
against external factors (fires) attribute of the Initiating Events Cornerstone and
affects the cornerstone objective to limit the likelihood of those events that upset
plant stability and challenge critical safety functions during shutdown as well as
power operations. Additionally, if left uncorrected, the practice of conducting hot
work in a manner that results in unintended combustion of nearby materials
would have the potential to lead to a more significant safety concern in that it
could result in a fire in or near risk significant equipment. Manual Chapter 0609,
Appendix M, Significance Determination Process Using Qualitative Criteria, was
used since Appendix F, Fire Protection Significance Determination Process,
does not address the potential risk significance of shutdown fire protection
findings, and Appendix G, Shutdown Operations Significance Determination
Process, does not address fire protection findings. The NRC management
review was performed by using the Manual Chapter 0609, Appendix F, Phase 1
Worksheet, to establish a bounding analysis. Using the bounding analysis, the
finding is determined to have very low safety significance because the finding
represented a low degradation rating, in that, it did not have any significant effect
on the likelihood that a fire might occur, or that a fire which does occur might not
be promptly suppressed. This finding has a crosscutting aspect in the area of
human performance associated with work practices because the licensee failed
to ensure supervisory and management oversight of work activities, including
contractors, such that nuclear safety was supported H.4(c) (Section 4OA3).
Cornerstone: Mitigating Systems
-3- Enclosure
- Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, Drawings, for the failure of
operations personnel to initiate a nuclear notification within the required
timeframe. Specifically, on September 27, 2009, operations personnel failed to
write a nuclear notification to document the problem with a flooded auxiliary
feedwater vault prior to the end of their shift. This finding was entered into the
licensees corrective action program as Nuclear Notifications NN 200615922.
The finding is greater than minor because the failure to follow procedures for
writing nuclear notifications, if left uncorrected, would have the potential to lead to
a more significant safety concern. The finding is associated with the equipment
performance attribute of the Mitigating Systems Cornerstone and affects the
cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences.
Using the Manual Chapter 0609, Significance Determination Process, Phase 1
Worksheets, the finding is determined to have very low safety significance
because the finding did not result in an actual loss of safety function, and did not
screen as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. This finding has a crosscutting aspect in the area of problem
identification and resolution associated with corrective action program since the
licensee failed to implement the corrective action program with an appropriate
threshold for identified issues P.1(a) (Section 1R06).
- Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for failure of engineering
personnel to adequately identify for correction conditions adverse to quality
between November 10 and December 1, 2009. Specifically, the inspection of
potential degradation associated with the support welds and embedded wall
plates for safety related seismic pipe restraints for emergency core cooling piping
was inadequate, in that, standing water and corrosion product interference was
not removed to enable an adequate inspection and evaluation of the structural
material. This finding was entered into the licensees corrective action program
as Nuclear Notification NN 200743417.
The finding is greater than minor because the failure to adequately identify for
correction conditions adverse to quality on safety related equipment, if left
uncorrected, would have the potential to lead to a more significant safety
concern. Additionally, the finding is associated with the equipment performance
attribute of the Mitigating Systems Cornerstone and affects the cornerstone
objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Using the
Manual Chapter 0609, Significance Determination Process, Phase 1
Worksheets, the finding is determined to have very low safety significance
because it did not represent an actual loss of safety function, and did not screen
as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. The finding has a crosscutting aspect in the area of human
performance associated with decision making because engineering personnel
failed to use conservative assumptions for operability decision making when
inspecting degraded and nonconforming conditions H.1(b) (Section 1R06).
-4- Enclosure
- Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensee's failure to take
adequate corrective actions for conditions adverse to quality associated with
Unit 3 emergency diesel generator train B. Specifically, in May 2009, corrective
actions were inadequate following an unexpected fuse failure in the emergency
diesel generator train B annunciator system. These inadequate corrective
actions enabled the pre-existing ground condition to continue until it ultimately
rendered the emergency diesel generator train B inoperable on December 11,
2009. This finding was entered into the licensees corrective action program as
Nuclear Notification NN 200722170.
The finding is greater than minor because the failure to correct conditions
adverse to quality for the emergency diesel generators is associated with the
equipment performance attribute of the Mitigating Systems Cornerstone and
affects the associated cornerstone objective to ensure the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences. Using the Manual Chapter 0609, Significance Determination
Process, Phase 1 Worksheets, the finding is determined to have very low safety
significance because it did not represent an actual loss of safety function, and did
not screen as potentially risk significant due to a seismic, flooding, or severe
weather initiating event. This finding has a crosscutting aspect in the area of
problem identification and resolution associated with corrective action program
since the licensee failed to thoroughly evaluate problems such that the
resolutions address the causes and extent of conditions P.1(c) (Section 1R12).
- Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensee's failure to take
adequate corrective actions for conditions adverse to quality associated with
Unit 3 emergency diesel generator train A. Specifically, on June 13, 2009,
following an emergency diesel generator failure on June 6, 2009, immediate
corrective actions were inadequately implemented when improperly configured
annunciator power supplies were installed in the emergency diesel generator
train A annunciator system. This configuration problem contributed to rapid
capacitor degradation as a result of the increased heat from a resistor, which
ultimately caused the emergency diesel generator failure to start on
December 12, 2009. This finding was entered into the licensees corrective
action program as Nuclear Notification NN 200756001.
The finding is greater than minor because the failure to correct conditions
adverse to quality for the emergency diesel generators is associated with the
equipment performance attribute of the Mitigating Systems Cornerstone and
affects the associated cornerstone objective to ensure the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences. Using the Manual Chapter 0609, Significance Determination
Process, Phase 1 Worksheets, the inspectors determined that this finding
represented an actual loss of safety function of emergency diesel generator train
for greater than the technical specification allowed outage time. This required
that a Phase 2 estimation be completed. Because the Phase 2 analysis
concluded that the finding was potentially greater than green, a Phase 3 analysis
was completed by a regional senior reactor analyst. The San Onofre SPAR
model indicated that the delta core damage frequency for emergency diesel
-5- Enclosure
generator train A being non-functional was 2.0E-6/yr. For an exposure time of
7 days, this resulted in an incremental core damage frequency of 3.8E-8 for this
finding, considering internal events only. The dominant sequence was a station
blackout sequence with failure of the diesels, failure to cross-tie power from the
other unit, failure to recover either onsite or offsite power, failure of batteries at
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and a failure to manually control the turbine-driven auxiliary feedwater
pump after battery depletion. The senior reactor analyst determined qualitatively
that the contribution of external events would not significantly add to this result;
therefore, the finding is determined to be of very low safety significance. This
finding has a crosscutting aspect in the area of human performance associated
with resources because the licensee failed to provide adequate instructions to
perform activities affecting quality H.2(c) (Section 1R12).
- Green. The inspectors identified three examples of a noncited violation of
10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and
Drawings, for the failure of operations and engineering personnel to follow
procedures and adequately evaluate degraded conditions to support operability
decision making. Specifically, on October 29, 2009, engineering personnel failed
to adequately evaluate the operability of the Unit 3 containment emergency sump
when an unanalyzed styrofoam material was identified, which had not been
previously analyzed for impact to the containment emergency sump.
Additionally, on November 17 and December 18, 2009, operations and
engineering personnel failed to adequately evaluate the operability of emergency
diesel generator train B when a lube oil leak was identified on a flexible hose for
the dc auxiliary turbo pump. And finally, on December 19, 2009, operations and
engineering personnel inappropriately applied Code Case N-513-2 to justify the
operability of the emergency core cooling system train A, in that, the flaw
geometry was only assumed and not characterized by volumetric inspection
methods or by physical measurements. This finding was entered into the
licensees corrective action program as Nuclear Notifications NNs 200673198,
200699833, and 200718673.
The finding is greater than minor because the failure to perform timely and
adequate evaluations of degraded, nonconforming, and unanalyzed conditions
for operability, if left uncorrected, would have the potential to lead to a more
significant safety concern. The finding is associated with the equipment
performance attribute of the Mitigating Systems Cornerstone and affects the
associated cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Using the Manual Chapter 0609, Significance Determination
Process, Phase 1 Worksheets, the finding is determined to have very low safety
significance because the finding did not result in a loss of safety function for
greater than the technical specification allowed outage time, and did not screen
as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. This finding has a crosscutting aspect in the area of problem
identification and resolution associated with corrective action program because
operations and engineering personnel failed to thoroughly evaluate problems
such that the resolutions addressed the cause and extent of condition. This
includes properly classifying, prioritizing, and evaluating for operability conditions
adverse to quality P.1(c) (Section 1R15).
-6- Enclosure
- Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure
of operations personnel to follow procedures and adequately implement identified
compensatory measures. Specifically, on November 25 and 28, 2009,
operations personnel did not follow requirements to establish a compensatory
measure to substitute manual operator actions for automatic actions to support
the operability of the functions provided by the refueling water storage tank to
charging pump suction piping. This finding was entered into the licensees
corrective action program as Nuclear Notification NN 200689450.
The finding is greater than minor because the inadequate implementation of
compensatory measures, if left uncorrected, would have the potential to lead to a
more significant safety concern. The finding is associated with the procedure
quality attribute of the Mitigating Systems Cornerstone and affects the associated
cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences.
Using the Manual Chapter 0609, Significance Determination Process, Phase 1
Worksheets, the finding is determined to have very low safety significance
because the finding did not result in an actual loss of safety function, and did not
screen as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. This finding has a crosscutting aspect in the area of human
performance associated with decision making because operations personnel
failed to make decisions using a systematic process, especially when faced with
uncertain or unexpected plant conditions, to ensure safety is maintained H.1(a)
(Section 1R15).
- Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, with thirteen examples that occurred
between June 2005 and July 2008, for the failure of the licensee to ensure that
appropriate measures were in place to assure that systems specified in the
design basis were maintained in a configuration which provided a reasonable
assurance of operability during design basis events. This finding was entered
into the licensees corrective action program as Action Requests ARs 050601315,
050601324, 060101159, 070200254, 200066209, and Nuclear Notifications NNs
200089167, 200058371, 200100730, and Corrective Action Order 800126624.
The finding is greater than minor because it is associated with the equipment
performance attribute of the Mitigating Systems Cornerstone and affects the
associated cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. In accordance with Manual Chapter 0609, Attachment 4,
Table 4a, Question 5, a Phase 3 analysis was required because the finding
screened as potentially risk significant due to a seismic, flooding, or severe
weather initiating event. In accordance with Inspection Manual Chapter 0609,
Appendix A, the analyst determined that the conditions documented in Table 1 of
this inspection report should be evaluated as a single inspection finding because
they resulted from a common cause. As a combined result of the evaluations
performed in the Phase 3 analysis, the analyst determined that this finding was of
very low safety significance. The finding has a crosscutting aspect in the area of
human performance associated with resources for the failure to maintain
-7- Enclosure
complete, accurate, and up-to-date design documentation, procedures, and work
packages H.2(c) (Section 4OA5).
B. Licensee-Identified Violations
Violations of very low safety significance, which were identified by the licensee, have
been reviewed by the inspectors. Corrective actions taken or planned by the licensee
have been entered into the licensees corrective action program. These violations and
their associated corrective action tracking numbers are listed in Section 4OA7.
-8- Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 2 began the inspection period at full power. On September 27, 2009, the unit was
shutdown for a scheduled refueling outage (U2C16) and steam generator replacement.
Unit 3 began the inspection period at full power. On October 24, 2009, the unit reduced power
to investigate an electrical ground on the high pressure intercept valves and during the
troubleshooting activities a valve (UV2200E) inadvertently closed resulting in a power reduction
to 88 percent. After repairs, the unit returned to full power on October 25, 2009. On
December 12, 2009, the unit commenced a technical specification required shutdown due to
both trains of emergency diesel generators being declared inoperable. The unit reduced power
to 40 percent before recovery of one train of emergency diesel generators allowed the unit to
exit the technical specification action and return to full power. The unit returned to full power on
December 13, 2009, and remained there for the duration of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of the licensees adverse weather procedures for
seasonal extremes (e.g., extreme high temperatures, extreme low temperatures, or
hurricane season preparations). The inspectors verified that weather-related equipment
deficiencies identified during the previous year were corrected prior to the onset of
seasonal extremes; and evaluated the implementation of the adverse weather
preparation procedures and compensatory measures for the affected conditions before
the onset of, and during, the adverse weather conditions.
During the inspection, the inspectors focused on plant-specific design features and the
licensees procedures used to mitigate or respond to adverse weather conditions.
Additionally, the inspectors reviewed the Updated Final Safety Analysis Report and
performance requirements for systems selected for inspection, and verified that operator
actions were appropriate as specified by plant-specific procedures. Specific documents
reviewed during this inspection are listed in the attachment. The inspectors also
reviewed corrective action program items to verify that the licensee was identifying
adverse weather issues at an appropriate threshold and entering them into their
corrective action program in accordance with station corrective action procedures. The
inspectors reviews focused specifically on the following plant systems:
- December 7-8, 2009, Units 2 and 3, the inspectors completed a review of the
licensee's readiness of the condensate storage tank and auxiliary feedwater
system for extreme low temperatures
These activities constitute completion of one readiness for seasonal adverse weather
sample as defined in IP 71111.01-05.
-9- Enclosure
b. Findings
No findings of significance were identified.
1R04 Equipment Alignments (71111.04)
.1 Partial Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
- December 8, 2009, Unit 3, Class 1E 4 kV bus (3A04 and 3A06) supply breakers
while emergency diesel generator train B was out of service for maintenance
- December 12, 2009, Unit 2, emergency diesel generator train A
- December 23, 2009, Unit 2, saltwater cooling system train B
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 walked down accessible
portions of the systems to verify system components and support equipment were
aligned correctly and operable. The inspectors examined the material condition of the
components and observed operating parameters of equipment to verify that there were
no obvious deficiencies. The inspectors also verified that the licensee had properly
identified and resolved equipment alignment problems that could cause initiating events
or impact the capability of mitigating systems or barriers and entered them into the
corrective action program with the appropriate significance characterization. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of three partial system walkdown samples as
defined by IP 71111.04-05.
b. Findings
No findings of significance were identified.
.2 Semi-Annual Complete Walkdown
a. Inspection Scope
On October 16, 2009, the inspectors performed a complete system alignment inspection
of the spent fuel pool cooling 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
- 10 - Enclosure
walked down 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 by IP 71111.04-05.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
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:
- October 1, 2009, Unit 2, containment building elevations 20 foot through 68 foot
- November 9, 2009, Unit 2, hot work activities in steam generator E088 cubicle
- December 4, 2009, Unit 2, saltwater cooling pump room and pipe tunnel
- December 8, 2009, Units 2 and 3, fire water pumps and storage tanks
- December 9-11, 2009, Units 2 and 3, auxiliary control building 9, 50, 70, and
85 feet elevations
The inspectors reviewed areas to assess if licensee personnel had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant; effectively maintained fire detection and suppression capability; maintained
passive fire protection features in good material condition; and had implemented
adequate compensatory measures for out of service, degraded or inoperable fire
protection equipment, systems, or features, in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk
as documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to affect equipment that could initiate or mitigate a plant
transient, or their impact on the plants ability to respond to a security event. Using the
documents listed in the attachment, the inspectors verified that fire hoses and
extinguishers were in their designated locations and available for immediate use; that
fire detectors and sprinklers were unobstructed, that transient material loading was
- 11 - Enclosure
within the analyzed limits; and fire doors, dampers, and penetration seals appeared to
be in satisfactory condition. The inspectors also verified that minor issues identified
during the inspection were entered into the licensees corrective action program.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of five quarterly fire-protection inspection samples
as defined by IP 71111.05-05.
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures (71111.06)
a. Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, the flooding analysis,
and plant procedures to assess seasonal susceptibilities involving internal flooding;
reviewed the Updated Final Safety Analysis Report and corrective action program to
determine if licensee personnel identified and corrected flooding problems; inspected
underground bunkers/manholes to verify the adequacy of sump pumps, level alarm
circuits, cable splices subject to submergence, and drainage for bunkers/manholes;
verified that operator actions for coping with flooding can reasonably achieve the desired
outcomes; and walked down 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.
- September 29, 2009, Units 2 and 3, auxiliary feedwater pump room lower vault
room inspections
- November 11, 2009, Unit 2, auxiliary feedwater piping room tunnel to the safety
equipment building
- December 9-11, 2009, Units 2 and 3, walkdown of emergency diesel generators
and safety related equipment in the auxiliary control building
These activities constitute completion of one internal flooding and one review of cables
located in underground bunkers/manholes inspection samples as defined by
IP 71111.06-05.
b. Findings
1. Timely Initiation for Nuclear Notifications
Introduction. The inspectors identified a Green noncited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, Drawings, for the failure of
operations personnel to initiate a nuclear notification within the required timeframe.
Description. On September 29, 2009, when Unit 2 was in Mode 5, the inspectors
identified three inches of standing water in an electrical vault located on the southeast
- 12 - Enclosure
side of the auxiliary feedwater building. The inspectors observed the vault contained
underground electrical conduit to safety related auxiliary feedwater pump 2P504.
Operations control room personnel were immediately notified of the condition and
Nuclear Notification NN 200602405 was initiated. Operations personnel identified that
the flooded condition was identified two days earlier on September 27, 2009, by an
equipment operator. However, no nuclear notification had been initiated as required by
Procedure SO123-XV-50.CAP-1, Writing Nuclear Notification for Problem Identification
and Resolution, Revision 2. Procedure SO123-XV-50.CAP-1, Section 6.3, stated that
all personnel identifying problems that have the potential to affect the ability of a
structure, system, or component to perform its specified function will immediately notify
the shift manager or designee, and write a nuclear notification prior to the end of their
shift.
Engineering personnel inspected the vault and surrounding areas on September 29-30,
2009, to determine the source of the flooding. Adjacent to the auxiliary feedwater
building, water was located in the berm surrounding the nuclear service water tanks and
pumps. The reported source of the water was from a drain valve connected to the floor
drain from the condensate storage tank T121 room. The water in the nuclear service
water berm was found to be entering a degraded underground electrical conduit for a
nuclear service water pump. The water entered into the conduit and traveled down to
the cable tray located in the auxiliary feedwater vault.
The inspectors determined this degraded condition was not promptly entered into the
correction action program until identified by the inspectors. The safety related
equipment components associated with the vault were not immediately evaluated for
operability when the condition was entered into the corrective action program on
September 29, 2009, because the auxiliary feedwater system was not required to be
operable in Mode 5. The inspectors concluded that, because of the failure to follow
Procedure SO123-XV-50.CAP-1, an appropriate immediate operability determination of
safety related equipment was not done, while in the applicable mode, since the
degraded or flooded condition of the auxiliary feedwater vault was first discovered on
September 27, 2009, while the unit was still in Mode 3.
Based on the inspectors prompting on October 8, 2009, the licensee initiated Nuclear
Notification NN 200615922 to document the failure to write a nuclear notification for a
degraded condition which required an immediate operability determination.
The inspectors reviewed an additional example identified by the licensee (See
Section 4OA7.3) that occurred on November 20, 2009, when engineering personnel
observed a white deposit on Unit 2 pipe S21219ML057, T006 RWST Gravity Feed
Outlet, during an inspection of the auxiliary feedwater line tunnel. The engineer initially
thought that the pipe was part of the condensate system and did not warrant an
immediate nuclear notification. The engineer noted the deficiency and took a picture
which included the date and time.
On November 23, 2009, the original engineer showed the picture to another system
engineer for evaluation. The second engineer routinely performed inspection for boric
acid and discussed the possibility of the white substance as being boric acid with the
original engineer. The discussion concluded that the substance was probably boric acid
from an external source and that the piping was suspected to be part of the condensate
system. Neither of the engineers identified the need to initiate a nuclear notification in
- 13 - Enclosure
accordance Procedure SO123-XV-50.CAP-1. Further, the engineers failed to recognize
the condition as a problem that warranted a nuclear notification as required by
Procedure SO23-XV-85, Boric Acid Corrosion Control Program (BACCP), Revision 4.
Procedure SO23-XV-85 stated that, all boric acid leaks, including minor amounts of
residue, require a nuclear notification be initiated. At this time the engineers arranged
for another walk down which did not occur until November 25, 2009.
On November 25, 2009, both of the engineers performed an additional inspection of the
auxiliary feedwater tunnel to identify the source of the white deposit. Due to suspecting
that the substance was boric acid, prior to the inspection the engineers arranged for a
sample of the white substance to be obtained and analyzed. Additionally, the engineers
identified that the piping was associated with the refueling water storage tank and
determined that the deposit was likely boric acid. Following the additional inspection, the
engineers reported the condition to their supervisor who appropriately directed the
engineers to immediately notify the operations shift manager and initiate a nuclear
notification. The condition was documented on Nuclear Notification NN 200682817.
During the discussion, the engineering supervisor was not informed that the boric acid
leak was initially identified on November 20, 2009, which was five days earlier.
Following shift manager notification, an extent of condition review was performed on
Unit 3 which identified three additional boric acid leaks on similar piping, which resulted
in the entry into a one hour technical specification shutdown action statement.
On November 27, 2009, the engineering supervisor observed the picture of the boric
acid leak and noted that the picture was dated November 20, 2009. Noting the
discrepancy between the time that the condition was identified and the time that the
condition was entered into the corrective action program, the engineering supervisor
identified that the requirements of Procedure SO123-XV-50.CAP-1 were not followed.
The engineering supervisor initiated Nuclear Notification NN 200683697 to document the
failure to promptly initiate a nuclear notification.
Analysis. The failure to initiate a nuclear notification in a timely manner following the
identification of an equipment problem was a performance deficiency. The finding is
greater than minor because the failure to follow procedures for writing nuclear
notifications, if left uncorrected, would have the potential to lead to a more significant
safety concern. The finding is associated with the equipment performance attribute of
the Mitigating Systems Cornerstone and affects the cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Using the Manual Chapter 0609, Significance
Determination Process, Phase 1 Worksheets, the finding is determined to have very low
safety significance because the finding did not result in an actual loss of safety function,
and did not screen as potentially risk significant due to a seismic, flooding, or severe
weather initiating event. This finding has a crosscutting aspect in the area of problem
identification and resolution associated with corrective action program since the licensee
failed to implement the corrective action program with an appropriate threshold for
identified issues P.1(a).
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities
affecting quality shall be prescribed by documented instructions, procedures, or
drawings, of a type appropriate to the circumstances and shall be accomplished in
accordance with these instructions, procedures, or drawings. Procedure SO123-XV-
- 14 - Enclosure
50.CAP-1, Writing Nuclear Notifications for Problem Identification and Resolution,
Revision 2, stated that all personnel identifying problems that have the potential to affect
the ability of a structure, system, or component to perform its specified function will
immediately notify the shift manager or designee, and write a nuclear notification prior to
the end of their shift. Contrary to the above, on September 27, 2009, operations
personnel failed to write a nuclear notification to document the problem with a flooded
auxiliary feedwater vault prior to the end of their shift. As a result, an immediate
operability determination, as required by Procedure SO123-XV-52, Functionality
Assessment and Operability Determinations, Revision 13, was not completed in a timely
manner. Because this violation is of very low safety significance and has been entered
into the licensee's corrective action program as Nuclear Notification NN 200615922, this
violation is being treated as a noncited violation, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000361/2009005-01, Failure to Initiate a Notification in a
Timely Manner.
2. Pipe Support Material Degradation
Introduction. The inspectors identified a Green noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for failure of engineering personnel to
adequately identify for correction conditions adverse to quality between November 10
and December 1, 2009. Specifically, engineering personnel did not adequately inspect
degraded safety related seismic pipe supports exposed to ground water in the Unit 2
auxiliary feedwater tunnel to identify all actions necessary to evaluate and correct the
condition.
Description. Between November 10 and December 1, 2009, inspectors performed
walkdowns of Unit 2 auxiliary feedwater piping underground tunnel. Degraded piping
penetrations between the safety equipment building room and auxiliary feedwater tunnel
areas was identified as a long standing issue by NRC inspectors (NCV
05000361/2009004-01). The degraded seal allowed ground water to leak into the safety
equipment building for several years. Two trains of the emergency core cooling system
piping pass through the auxiliary feedwater piping tunnel into the safety equipment
building. The inspectors were informed that repairs to the penetration seals on the
safety equipment building side had been completed. In order to verify the condition of
the piping penetration on both sides, inspectors requested entry to the auxiliary
feedwater piping tunnel. This was necessary to evaluate the general condition of the
piping penetration seals in the tunnel and determine the impact water leakage had on
safety related equipment in the auxiliary feedwater tunnel. Access was restricted to the
piping tunnel by a locked door and required a radiation exposure permit before entry.
The inspectors noted that water was discovered in the tunnel by a health physics
technician during a routine health physics survey on November 8, 2009. The technician
generated Nuclear Notification NN 200659260, and according to the description, water
was present in the tunnel during the previous surveillance and needed to be pumped
down. The inspectors questioned the licensee regarding how often water had been
found in the tunnel since the last health physic survey, but no recent documented
occurrences were identified in the corrective action program.
During the piping tunnel inspection, the inspectors observed that the flooding was due to
leaking seals from degraded wall penetrations between the safety equipment building
and the auxiliary feedwater tunnel. The inspectors observed that the groundwater had
- 15 - Enclosure
affected emergency core cooling system pipe supports trains A and B as evidenced by
heavy rust at the base of the supports. On November 17, 2009, the licensee
documented the inspectors observations in Nuclear Notification NN 200670710, which
included the pipe support degradation concerns.
Since the piping supports are embedded in the tunnel floor, they have been repeatedly
exposed to standing water for extended periods of time. On November 18, 2009,
engineering personnel inspected the piping support welds and embedded wall plates for
corrosion, to identify potential material degradation, as directed per Nuclear Notification
NN 200670710. Engineering personnel concluded that the corrosion on the supports
and welds appeared to be minor surface corrosion, such that the structural material was
not impacted. Therefore, it was concluded that no further evaluation was required since
the corrosion did not impact structural integrity of the supports. The corrective action
identified was to clean and repaint the corroded pipe support areas to prevent further
degradation.
On December 1, 2009, inspectors returned to the piping tunnel with engineering
personnel and observed that the corroded pipe supports appeared to be in the same
condition that was observed during their previous inspection. Further, the inspectors
were informed that the pipe support inspection was performed by visual examination of
the conditions that the inspectors observed. The inspectors questioned engineering
personnel how an adequate inspection of the condition was performed without the
removal of standing water and corrosion, since the interference would obstruct an
adequate view of the material surface that needed to be evaluated. In response to the
inspectors question, engineering personnel initiated action for additional pipe support
inspections that would require removal of interference to adequately inspect the pipe
support structural materials.
On December 18, 2009, the results of the additional inspection and evaluation were
presented to the inspectors. The results confirmed the inspectors concerns that some
of the pipe support welds had sustained material degradation, which was more than
minor surface corrosion. The engineering analyses to justify the degradation showed a
loss of margin in various piping welds but the support strength remained within allowable
design limits.
Analysis. The failure to adequately identify for correction conditions adverse to quality
was a performance deficiency. The finding is greater than minor because the failure to
adequately identify for correction conditions adverse to quality on safety related
equipment, if left uncorrected, would have the potential to lead to a more significant
safety concern. Additionally, the finding is associated with the equipment performance
attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Using the Manual Chapter 0609,
Significance Determination Process, Phase 1 Worksheets, the finding is determined to
have very low safety significance because it did not represent an actual loss of safety
function, and did not screen as potentially risk significant due to a seismic, flooding, or
severe weather initiating event. The finding has a crosscutting aspect in the area of
human performance associated with decision making because engineering personnel
failed to use conservative assumptions for operability decision making when inspecting
degraded and nonconforming conditions H.1(b).
- 16 - Enclosure
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion XVI, Corrective Action, requires, in part, that measures shall be established to
assure that conditions adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and nonconformances are promptly
identified and corrected. Contrary to the above, between November 10 and
December 1, 2009, engineering personnel failed to adequately identify for correction a
condition adverse to quality. Specifically, the inspection of potential degradation
associated with the support welds and embedded wall plates for safety related seismic
pipe restraints for emergency core cooling piping was inadequate, in that, standing water
and corrosion product interference was not removed to enable an adequate inspection
and evaluation of the structural material. Adequate inspection and evaluation is
necessary, such that, the identified resolution addresses the causes and extent of
conditions. Because this finding is of very low safety significance and has been entered
into the licensees corrective action program as Nuclear Notification NN 200743417, this
violation is being treated as a noncited violation, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000361/2009005-02, Failure to Adequately Identify
Problems in Corrective Action Program.
1R08 In-service Inspection Activities (71111.08)
.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water
Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control
(71111.08-02.01)
a. Inspection Scope
The inspector reviewed two types of nondestructive examination activities and two welds
on the reactor coolant system pressure boundary. The inspector did not review
examinations with relevant indications that had been accepted by licensee personnel for
continued service because there were none.
The inspector directly observed the following nondestructive examinations:
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Reactor Coolant 02-008-002 Ultrasonic Testing
System
Safety Injection 02-020-088 Penetrant Testing
System
The inspector reviewed records for the following nondestructive examinations:
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Reactor Coolant 02-006-010 Ultrasonic Testing
System
High Pressure 02-068-950 Penetrant Testing
- 17 - Enclosure
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Safety Injection
High Pressure 02-068-970 Penetrant Testing
Safety Injection
Low Pressure 02-071-1510 Penetrant Testing
Safety Injection
Low Pressure 02-071-1530 Penetrant Testing
Safety Injection
High Pressure 02-06-3640 Penetrant Testing
Safety Injection)
Low Pressure 02-071-1700 Penetrant Testing
Safety Injection
High Pressure 02-070-2710 Penetrant Testing
Safety Injection
High Pressure 02-068-990 Penetrant Testing
Safety Injection
High Pressure 02-070-2860 Penetrant Testing
Safety Injection
High Pressure 02-070-2370 Penetrant Testing
Safety Injection
Low Pressure 02-062-031-01 Penetrant Testing
Safety Injection
Low Pressure 02-072-137 Penetrant Testing
Safety Injection
Shutdown 02-075-042 Penetrant Testing
Cooling
During the review and observation of each examination, the inspector verified that
activities were performed in accordance with the ASME Code requirements and
applicable procedures. The inspector also verified that the qualifications of all
nondestructive examination technicians performing the inspections were current.
- 18 - Enclosure
The inspector observed performance of one ASME Code,Section XI, repair and
replacement weld and performed a record review of one additional weld. The weld that
was observed was:
SYSTEM IDENTIFICATION ACTIVITY
High Pressure Safety S21204MU021 Weld installation
Injection
The weld for which a record review was performed was:
SYSTEM IDENTIFICATION ACTIVITY
Chemical Volume Control 2TSH9205 Weld installation
System
The inspector verified, by review, that the welding procedure specifications and the
welders had been properly qualified in accordance with ASME Code,Section IX,
requirements. The inspector also verified, through observation and record review, that
essential variables for the welding process were identified, recorded in the procedure
qualification record, and formed the bases for qualification of the welding procedure
specifications. Specific documents reviewed during this inspection are listed in the
attachment.
These actions constitute completion of the requirements for Section 02.01.
b. Findings
No findings of significance were identified.
.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)
a. Inspection Scope
The inspector reviewed the results of licensee personnels volumetric inspection of
pressure-retaining components above the reactor pressure vessel head to verify that
there were no flaws in the welds associated with these penetrations. The inspector
observed data acquisition and/or analysis of five penetrations. The inspector verified
that the personnel performing the inspections were current in their certification as Level
II or Level III ultrasonic testing examiners. Specific documents reviewed during this
inspection are listed in the attachment.
These actions constitute completion of the requirements for Section 02.02.
b. Findings
No findings of significance were identified.
- 19 - Enclosure
.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)
a. Inspection Scope
The inspector evaluated the implementation of the licensees boric acid corrosion control
program for monitoring degradation of those systems that could be adversely affected by
boric acid corrosion. The inspector reviewed the documentation associated with the
licensees boric acid corrosion control walkdown as specified by Procedure SO23-XV-
85, Boric Acid Corrosion Control Program, Revision 4. The inspector also reviewed the
visual records of the components and equipment. The inspector verified that the visual
inspections emphasized locations where boric acid leaks could cause degradation of
safety-significant components. The inspector also verified that the engineering
evaluations for those components where boric acid was identified gave assurance that
the ASME Code wall thickness limits were properly maintained. The inspector confirmed
that the corrective actions performed for evidence of boric acid leaks were consistent
with requirements of the ASME Code. Specific documents reviewed during this
inspection are listed in the attachment.
These actions constitute completion of the requirements for Section 02.03.
b. Findings
No findings of significance were identified.
.4 Steam Generator Tube Inspection Activities (71111.08-02.04)
a. Inspection Scope
The licensee did not perform steam generator inspection activities this refueling outage.
Consequently, the inspector did not perform any inspections in this area.
These actions constitute completion of the requirements of Section 02.04.
b. Findings
No findings of significance were identified.
.5 Identification and Resolution of Problems (71111.08-02.05)
a. Inspection scope
The inspector reviewed nine condition reports which dealt with inservice inspection
activities and found the corrective actions were appropriate. The specific condition
reports reviewed are listed in the documents reviewed section. From this review the
inspector concluded that the licensee has an appropriate threshold for entering issues
into the corrective action program and has procedures that direct a root cause evaluation
when necessary. The licensee also has an effective program for applying industry
operating experience. Specific documents reviewed during this inspection are listed in
the attachment.
These actions constitute completion of the requirements of Section 02.05.
- 20 - Enclosure
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
.1 Annual Inspection
The licensed operator requalification program involves two training cycles that are
conducted over a two year period. In the first cycle, the annual cycle, the operators are
administered an operating test consisting of job performance measures and simulator
scenarios. In the second part of the training cycle, the biennial cycle, operators are
administered an operating test and a comprehensive written examination.
a. Inspection Scope
The inspector conducted an in-office review of the annual requalification training
program operating test results for 2009. The licensee examined 87 operators
(41 reactor operators and 46 senior reactor operators) during this requalification cycle.
In addition, 15 operating crews were examined on the facility's simulator. Thirteen of the
operating crews passed the simulator scenarios and 84 operators passed the operating
tests.
b. Findings
No findings of significance were identified.
.2 Quarterly Inspection
a. Inspection Scope
On December 17, 2009, the inspectors observed a crew of licensed operators in the
plants simulator during licensed operator requalification training to verify that operator
performance was adequate, evaluators were identifying and documenting crew
performance problems, and training was being conducted in accordance with licensee
procedures. The inspectors evaluated the following areas:
- Licensed operator performance
- Crews clarity and formality of communications
- Crews ability to take timely actions in the conservative direction
- Crews prioritization, interpretation, and verification of annunciator alarms
- Crews correct use and implementation of abnormal and emergency procedures
- Control board manipulations
- Oversight and direction from supervisors
- Crews ability to identify and implement appropriate technical specification
actions and emergency plan actions and notifications
- 21 - Enclosure
The inspectors compared the crews performance in these areas to pre-established
operator action expectations and successful critical task completion requirements.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one quarterly licensed-operator requalification
program sample as defined in IP 71111.11.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant systems:
- November 17, 2009, Units 2 and 3, review of the noise spikes on emergency
diesel generator dc power bus
- December 8, 2009, Unit 3, emergency diesel generator train B
- December 12, 2009, Unit 3, emergency diesel generator train A annunciator
power supply problems
The inspectors reviewed events such as where ineffective equipment maintenance has
resulted in valid or invalid automatic actuations of engineered safeguards systems and
independently verified the licensee's actions to address system performance or condition
problems in terms of the following:
- Implementing appropriate work practices
- Identifying and addressing common cause failures
- Scoping of systems in accordance with 10 CFR 50.65(b)
- Characterizing system reliability issues for performance
- Charging unavailability for performance
- Trending key parameters for condition monitoring
- Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or (a)(2)
- 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
- 22 - Enclosure
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 IP 71111.12-05.
b. Findings
The inspectors reviewed the events, and associated maintenance effectiveness that led
to the periods of emergency diesel generator inoperability described in Section 4OA3.1,
and identified two findings where the licensee failed to take adequate corrective actions
for conditions adverse to quality associated with the Unit 3 emergency diesel generators.
The inspectors determined that the underlying performance deficiencies that resulted in
the emergency diesel generator inoperability declarations were a failure to implement
corrective actions commensurate with the safety significance of the emergency diesel
generators.
1. Emergency Diesel Generator Train B
Introduction. The inspectors identified a Green noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensee's failure to take adequate
corrective actions for a condition adverse to quality associated with Unit 3 emergency
diesel generator train B.
Description. The inspectors reviewed the licensees prompt investigation into the
December 11, 2009, inadvertent grounding of a wire by a maintenance technician. The
inadvertent grounding blew the emergency diesel generator train B annunciator system
fuse. This investigation report was documented in Nuclear Notification NN 200704617
and indicated that a similar event caused the same fuse to blow in May 2009 during
scheduled maintenance on emergency diesel generator train B per Maintenance Order
MO 800295645. Following the event on December 11, engineering personnel
determined that the annunciator system must have had a preexisting ground in order for
the fuse to have been blown by either of these accidental groundings. The inspectors
questioned maintenance personnel familiar with the May 2009 event and identified that
the only corrective action taken at the time was to replace the blown fuse. The
inspectors concluded the licensee failed to take adequate corrective actions to perform
an evaluation of the failure, including the potential impact on operability and the need for
further corrective actions. These inadequate corrective actions enabled the pre-existing
ground condition to continue until it ultimately rendered the emergency diesel generator
train B inoperable on December 11, 2009.
Analysis. The failure to take adequate corrective actions for conditions adverse to
quality was a performance deficiency. The finding is greater than minor because the
failure to correct conditions adverse to quality for the emergency diesel generators is
associated with the equipment performance attribute of the Mitigating Systems
Cornerstone and affects the associated cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Using the Manual Chapter 0609, Significance
Determination Process, Phase 1 Worksheets, the finding is determined to have very low
- 23 - Enclosure
safety significance because it did not represent an actual loss of safety function, and did
not screen as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. This finding has a crosscutting aspect in the area of problem
identification and resolution associated with corrective action program since the licensee
failed to thoroughly evaluate problems such that the resolutions address the causes and
extent of conditions P.1(c).
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion XVI, Corrective Action, requires, in part, that measures shall be established to
assure that conditions adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and nonconformances are promptly
identified and corrected. Contrary to the above, in May 2009, the licensee failed to take
adequate corrective actions for conditions adverse to quality associated with emergency
diesel generator train B. Specifically, corrective actions were inadequate following an
unexpected fuse failure in the emergency diesel generator train B annunciator system.
Because this finding was of very low safety significance and has been entered into the
licensees corrective action program as Nuclear Notification NN 200722170, this
violation is being treated as a noncited violation, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000362/2009005-03, Failure to Correct Problems with
Emergency Diesel Generator Train B.
2. Emergency Diesel Generator Train A
Introduction. The inspectors identified a Green noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensee's failure to take adequate
corrective actions for a condition adverse to quality associated with Unit 3 emergency
diesel generator train A.
Description. On June 6, 2009, the emergency diesel generator train A was declared
inoperable after it failed to start during a monthly surveillance test. The cause was
determined to be voltage noise from the annunciator power supplies that incorrectly
closed contacts in the speed switch circuitry. As part of the immediate corrective actions,
the licensee modified the annunciator power supply circuit boards obtained from the
warehouse by replacing the capacitors with new capacitors, installed the power supplies
on June 13, 2009, and initiated an apparent cause evaluation.
Following the emergency diesel generator train A failure on December 12, the licensee
determined that the cause was the same cause as the failure on June 6, 2009. Further,
the licensees failure analysis concluded that both annunciator power supply circuit
boards (replaced on June 13, 2009), had configuration problems, in that, a capacitor was
in contact with an adjacent resistor. This configuration problem contributed to rapid
capacitor degradation as a result of the increased heat from the resistor, which ultimately
caused the emergency diesel generator failure to start on December 12. Emergency
diesel generator train A was successfully started, and completed a surveillance test on
November 23, 2009, then continued in a standby condition until the failure to start
occurred on December 12, 2009.
Analysis. The failure to take adequate corrective actions for conditions adverse to
quality was a performance deficiency. The finding is greater than minor because the
failure to correct conditions adverse to quality for the emergency diesel generators is
associated with the equipment performance attribute of the Mitigating Systems
Cornerstone and affects the associated cornerstone objective to ensure the availability,
- 24 - Enclosure
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Using the Manual Chapter 0609, Significance
Determination Process, Phase 1 Worksheets, the inspectors determined that this
finding represented an actual loss of safety function of an emergency diesel generator
train for greater than the technical specification allowed outage time. This required that
a Phase 2 estimation be completed. Because the Phase 2 analysis concluded that the
finding was potentially greater than green, a Phase 3 analysis was completed by a
regional senior reactor analyst. The San Onofre SPAR model indicated that the delta-
core damage frequency for emergency diesel generator train A being non-functional was
2.0E-6/yr. For an exposure time of 7 days, this resulted in an incremental core damage
frequency of 3.8E-8 for this finding, considering internal events only. The dominant
sequence was a station blackout sequence with failure of the diesels, failure to cross-tie
power from the other unit, failure to recover either onsite or offsite power, failure of
batteries at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and a failure to manually control the turbine-driven auxiliary
feedwater pump after battery depletion. The senior reactor analyst determined
qualitatively that the contribution of external events would not significantly add to this
result; therefore, the finding is determined to be of very low safety significance (Green).
This finding has a crosscutting aspect in the area of human performance associated with
resources because the licensee failed to provide adequate instructions to perform
activities affecting quality H.2(c).
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion XVI, Corrective Action, requires, in part, that measures shall be established to
assure that conditions adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and nonconformances are promptly
identified and corrected. Contrary to the above, on June 13, 2009, the licensee failed to
take adequate corrective actions for conditions adverse to quality associated with the
emergency diesel generator train A. Specifically, the immediate corrective actions were
inadequately implemented when improperly configured annunciator power supplies were
installed in the emergency diesel generator train A annunciator system. Because this
finding was of very low safety significance and has been entered into the licensees
corrective action program as Nuclear Notification NN 200756001, this violation is being
treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement
Policy: NCV 05000362/2009005-04, Failure to Correct Problems with Emergency Diesel
Generator Train A.
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:
- October 6, 2009, Unit 2, reactor vessel head removal and storage
- October 22-26, 2009, Unit 2, steam generator replacement impacts to operating
unit risk assessment
- 25 - Enclosure
- October 23 through November 30, 2009, Unit 2, steam generator E088
temporary lift modifications to facilitate steam generator replacement
- November 2-3, 2009, Units 2 and 3, emergent work activities associated with
atmospheric dump valves found with loose jam nut
- November 12-24, 2009, Unit 2, fire damper engineering change package on
emergency cooling train A
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 five maintenance risk assessments and
emergent work control inspection samples as defined by IP 71111.13-05.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed the following issues:
- November 10, 2009, Units 2 and 3, styrofoam material in containment impact to
containment emergency sump
- December 3, 2009, Unit 2, through wall leak identified on piping from refueling
water storage tank to charging pump suction
- December 3, 2009, Unit 3, through wall leaks identified on piping from refueling
water storage tank to charging pump suction
- December 7, 2009, Unit 3, S32420MY719, flexible hose for the dc auxiliary turbo
pump P496 on emergency diesel generator train B
- December 9, 2009, Units 2 and 3, operability impact of cracks identified on
mounting flanges for bushings associated with Class 1E 4.16 kV breakers
- December 14, 2009, Unit 3, impact on operability of emergency diesel generator
train B following annunciator power supply problems identified in train A
- 26 - Enclosure
- December 22, 2009, Unit 3, boric acid deposits discovered on emergency core
cooling system train A suction piping
The inspectors selected these potential operability issues based on the risk-significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that technical specification operability was
properly justified and the subject component or system remained available such that no
unrecognized increase in risk occurred. The inspectors compared the operability and
design criteria in the appropriate sections of the technical specifications and Updated
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. The inspectors determined, where
appropriate, compliance with bounding limitations associated with the evaluations.
Additionally, the inspectors also 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 seven operability evaluations inspection
samples as defined in IP 71111.15-05.
b. Findings
1. Operability Determination Adequacy
Introduction. The inspectors identified three examples of a Green noncited violation of
10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for
the failure of operations and engineering personnel to follow procedures and adequately
evaluate degraded conditions to support operability decision making.
Description. The first example is associated with issues discovered on October 27,
2009, when a fire was reported inside the Unit 2 containment at the 63 foot elevation.
The fire started while workers were using an acetylene torch to remove a vertical floor
support I-beam column, which was being removed to support steam generator
replacement activities. Hot slag from the torching activity burned into caulking around
the I-beam and ignited styrofoam material enclosed by the caulking. The styrofoam
spacer and caulking were used during original construction and are an integral part of
the containment floor design. The licensee documented this event in Nuclear
Notification NN 200643134.
The inspectors reviewed the event on October 28, 2009, and became aware that
engineering personnel were assigned tasks to determine the impact that styrofoam
material had on the containment emergency sump. Further, the inspectors were
informed the styrofoam material had not been analyzed as part of the licensee response
to NRC Generic Letter (GL) 2004-02, Potential Impact of Debris Blockage on
Emergency Sump Recirculation at Pressurized Water Reactors (PWRs).
On October 29, 2009, the inspectors questioned engineering personnel regarding the
status of the operability evaluation for Unit 3 and were told that there had been no task
assigned in the nuclear notification. Additional questions determined that engineering
personnel were only continuing their analysis of the impact that styrofoam material had
- 27 - Enclosure
on the containment emergency sump for Unit 2 as assigned by Nuclear Notification NN
200643134. Since this material was discovered in Unit 2, and was likely to exist in
Unit 3 as well, the inspectors asked if the condition was being evaluated for operability
since Unit 3 was in Mode 1. Specifically, the inspectors questioned whether an
evaluation of the specific Unit 3 conditions needed to be assessed through the
operability determination process as prescribed in Procedure SO123-XV-52,
Functionality Assessments and Operability Determinations, Revision 13. In addition,
the inspectors questioned whether an evaluation was necessary to review the impact of
the styrofoam on the fire loading analysis. Engineering personnel generated Nuclear
Notification NN 200645996, as a result of the inspectors questions, to perform an
operability determination for the Unit 3 emergency containment sump.
On November 3, 2009, the immediate operability and prompt operability determinations
were completed for Unit 3. The licensee determined that Unit 3 had a reasonable
expectation of operability based on three factors: 1) material discovered in the
containment was situated such that it was unlikely to become dislodged and free to
become entrained in a flow of water; 2) material was of low density and would float and
not likely to cause blockage at the emergency sump; and 3) material was not likely to be
affected by temperatures expected during any anticipated operational occurrences.
On November 4, 2009, fire protection engineers completed a functional assessment for
Unit 3, that evaluated styrofoam impact on the fire protection analysis. The evaluation
concluded that the styrofoam material was isolated from other combustibles and ignition
sources and therefore not an impact to safety related equipment inside containment.
The inspectors reviewed the operability determinations and functional assessments, and
concluded that they were adequate.
The second example was associated with equipment issues first identified on
November 17, 2009, when the licensee identified a lube oil leak from the Unit 3
emergency diesel generator train B. The leak was identified to be from the flexible hose
for the dc auxiliary turbo pump P496 and leaking at a rate of seven drops per minute.
The licensee initiated Nuclear Notification NN 200669151 to place the problems
associated with the leaking hose into the corrective action program. Subsequently, the
licensee, in accordance with Procedure SO123-XV-52, Functionality Assessments and
Operability Determinations, Revision 14, performed an immediate operability
determination to ensure that the leak would not challenge the minimum required lube oil
level stated in Technical Specification 3.8.3, Diesel Lube Oil, Fuel Oil and Starting Air,
and therefore meet the design basis seven day operation. The licensee determined,
using engineering judgment, that the diesel generator would still remain operable due to
the small leak rate. The licensee then performed a prompt operability determination,
based on the use of engineering judgment in the immediate operability determination,
which assumed that the leak rate would be proportional to the increase in pressure
during generator operation and reach a limit of ten drops per minute. The resulting
calculation determined that a total volume of oil that would be lost during the required
seven day operation would be only 1.33 gallons. This calculation did not include any
other unidentified leakage, which did not challenge the available ten percent margin
(16.46 gallons) built into the seven day oil consumption value for the diesel generator.
The licensee, due to the failure mechanism of the flex hose being unknown, commenced
periodic inspection of the leak location and leak rate estimations to ensure that further
degradation did not impact the 7 day mission time of the emergency diesel generator.
- 28 - Enclosure
The licensee did not identify an upper limit for leakage in which the 7 day mission time
would be challenged as part of the operability determination to provide guidance for the
engineers inspecting the leak.
On December 8, 2009, during operation of emergency diesel generator train B, a leak
was identified at a leak rate of 140 drops per minute from the degraded hose identified
on November 17, 2009, in Nuclear Notification NN 200669151. The licensee declared
emergency diesel generator train B inoperable following the identification of the lube oil
leak due to the increased leak rate and potential future degradation of the flexible hose.
The flexible hose was replaced as part of Maintenance Order NMO 800410821. The
previous operability determination assumed a leak rate of 10 drops per minute during
generator operation. Based on the observed leak rate, operations personnel determined
that the operability of the generator should be reassessed and initiated Nuclear
Notification NN 200695875. The licensee performed another prompt operability
determination using values obtained from Procedure SO23-3-3.23, Diesel Generator
Monthly and Semiannual Testing, Attachment 11, and assumptions used in the previous
evaluation and concluded that the amount of available oil to cover the seven day loss
due to the flex hose leakage was 18.74 gallons. The licensee determined that the 140
drop per minute leak rate from the flex hose corresponded to 18.64 gallons over the
design basis required seven day operation which resulted in a margin of .1 gallons. This
assumed that margin, 16.64 gallons, calculated into the total 181.1 gallons of oil required
for the completion of the seven day mission time would be used by the current active
leak and did not take into account additional leakage. During the December 8, 2009,
diesel run, the licensee identified another lube oil leak and replaced two additional
flexible hoses that showed evidence of seepage not accounted for in this assumption.
The licensee determined, based on these assumptions, that the emergency diesel
generator could meet the seven day mission time.
Procedure SO123-XV-52, defined a component operable if the structure, system, or
component is capable of performing the functions specified by its design, within the
required range of physical design conditions. Based on this, the inspectors questioned
the adequacy of using the assumption that the leak rate was proportional to the change
in pressure and that it did not take into account the changes in temperature
(~100 degree change) and viscosity of the lube oil during diesel generator operations. In
addition, the inspectors questioned the methodology used for determining the available
oil and converting the drop per minute leak rate to total lube oil loss due to the licensee
using a standard water drop to cubic centimeter ratio. The use of the standard ratio for
water did not account for any differences in viscosity and temperature between oil and
water. Following the inspectors questioning, the licensee conducted testing to
determine the actual drop rate to cubic centimeter per hour corresponding to the diesel
generator lube oil. The licensee determined that the more conservative value of ten
drops per cubic centimeter should be used to calculate the amount of lube oil lost during
the seven day operation instead of the initial value of twenty drops per cubic centimeter.
This change in conversion factors resulted in a calculated loss of approximately
37 gallons of lube oil over a seven day period of operation instead of the 18.64 gallons
previously assumed.
Following the inspectors questions about the methodology used in determining the
amount of oil available and lost due to leakage, the licensee recalculated the amount of
oil available above the minimum technical specification required level. The licensee
- 29 - Enclosure
determined that the diesel generator had a volume of approximately 42 gallons of oil
between the technical specification minimum level and the Full Run mark.
The third example occurred on December 19, 2009, following the identification of boric
acid deposits on the Unit 3 emergency core cooling system train A suction piping. The
boric acid deposits were observed on the welds attaching a lug to the pipe at support
S3-SI-001-H-030. Based on the deposits observed, the licensee determined that the
boric acid leakage was from a through wall flaw located underneath the lug. Because of
the leak location, the licensee was unable to characterize the flaw geometry. Instead,
engineering personnel assumed the flaw characteristics based on operating experience
and a determination that the critical crack length was greater than the size of the lug.
Since the flaw was determined to be within the boundary of the lug, the licensee
concluded that the flaw was less than the critical crack length. Based on the assumed
characterization of the flaw, the licensee applied the provisions of Code Case N-513-2,
Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3
Piping, and determined that the emergency core cooling system train A suction piping
was operable.
On December, 22, 2009, the inspectors reviewed the operability determination
documented in Nuclear Notification NN 200714391 and Code Case N-513-2. The
inspectors reviewed Code Case N-513-2 and noted that it was only applicable when the
flaw geometry was characterized by volumetric inspection methods or by physical
measurements. The inspectors determined that the method used to characterize the
flaw to justify operability in the operability determination was not in accordance with the
code case, in that, the flaw geometry was only assumed and not characterized by
volumetric inspection methods or by physical measurements. Therefore, the inspectors
concluded that engineering and operations personnel inappropriately applied Code Case
N-513-2 to justify the operability of the emergency core cooling system train A.
The inspectors communicated their conclusion regarding the inadequate operability
determination to operations and engineering personnel. Since the operability
determination was inadequate, operations personnel declared the emergency core
cooling system train A suction piping, and refueling water storage tank inoperable and
entered applicable technical specifications and followed the requirements of the limiting
conditions for operability. Refueling water storage tank outlet isolation valve 3HV-9300
was closed to isolate the leak from the refueling water storage tank, which restored
operability of the tank. The emergency core cooling system train A remained inoperable.
The licensee removed the lugs necessary to complete the required inspections to
properly characterize the flaw geometry. Following flaw characterization, the licensee
appropriately applied Code Case N-513-2 to document an adequate basis for operability
of the piping in a revised operability determination, declared the emergency core cooling
system train A suction piping operable, and opened outlet isolation valve 3HV-9300 to
return the system to service.
Analysis. The failure to perform an adequate operability determination was a
performance deficiency. The finding is greater than minor because the failure to perform
timely and adequate evaluations of degraded, nonconforming, and unanalyzed
conditions for operability, if left uncorrected, would have the potential to lead to a more
significant safety concern. The finding is associated with the equipment performance
attribute of the Mitigating Systems Cornerstone and affects the associated cornerstone
- 30 - Enclosure
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Using the Manual Chapter 0609,
Significance Determination Process, Phase 1 Worksheets, the finding is determined to
have very low safety significance because the finding did not result in a loss of safety
function for greater than the technical specification allowed outage time, and did not
screen as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. This finding has a crosscutting aspect in the area of problem
identification and resolution associated with corrective action program because
operations and engineering personnel failed to thoroughly evaluate problems such that
the resolutions addressed the cause and extent of condition. This includes properly
classifying, prioritizing, and evaluating for operability conditions adverse to quality
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion V, Instructions, Procedures and Drawings, requires that activities affecting
quality shall be prescribed by instructions, procedures, or drawings and shall be
accomplished in accordance with those instructions, procedures, and drawings. The
assessment of operability of safety related equipment needed to mitigate accidents was
an activity affecting quality and was implemented by Procedure SO123-XV-52,
Functionality Assessments and Operability Determinations. Procedure SO123-XV-52,
Step 1.0, stated that the objective of the procedure was to provide guidelines and
instructions for evaluating the operability of a structure, system, or component when a
degraded, nonconforming, or unanalyzed condition was identified.
Contrary to the above, on October 29, 2009, engineering personnel failed to follow
Procedure SO123-XV-52, Revision 13, to adequately evaluate the operability of an
identified nonconforming and unanalyzed condition. Specifically, engineering personnel
failed to adequately evaluate the operability of the Unit 3 containment emergency sump
when an unanalyzed styrofoam material was identified, which had not been previously
analyzed for impact to the containment emergency sump.
Contrary to the above, on November 17 and December 8, 2009, operations and
engineering personnel failed to follow Procedure SO123-XV-52, Revision 14, to
adequately evaluate the operability of the Unit 3 emergency diesel generator train B.
Specifically, operations and engineering personnel failed to adequately evaluate the
operability of emergency diesel generator train B when a lube oil leak was identified on a
flexible hose for the dc auxiliary turbo pump.
Contrary to the above, on December 19, 2009, operations and engineering personnel
failed to follow Procedure SO123-XV-52, Revision 14, to adequately evaluate the
operability of the Unit 3 emergency core cooling system train A. Specifically, operations
and engineering personnel inappropriately applied Code Case N-513-2 to justify the
operability of the emergency core cooling system train A, in that, the flaw geometry was
only assumed and not characterized by volumetric inspection methods or by physical
measurements.
Because the finding is of very low safety significance and has been entered into the
licensees corrective action program as Nuclear Notifications NNs 200673198,
200699833, and 200718673, this violation is being treated as a noncited violation,
consistent with Section VI.A of the Enforcement Policy: NCV 05000362/2009005-05,
Failure to Follow the Operability Determination Process.
- 31 - Enclosure
2. Compensatory Measures
Introduction. The inspectors identified a Green noncited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure of
operations personnel to follow procedures and adequately implement identified
compensatory measures used to substitute manual operator actions for automatic
actions to perform a required function.
Description. On November 25, 2009, through wall leaks were identified on piping from
the refueling water storage tank to charging pump suction on Units 2 and 3. Unit 3
entered a one hour shutdown action per Technical Specification 3.5.4, Condition B, for
an inoperable refueling water storage tank. Unit 3 exited the one hour action statement
when block valves MU067 and MU054 were closed to isolate the leaks from the
refueling water storage tank. Unit 2 was defueled when the through wall leaks were
discovered. The Unit 2 shutdown defense in depth strategy credited the refueling water
storage tank to charging pump suction line as a makeup source to control spent fuel pool
inventory. Similar to actions taken in Unit 3, operations personnel in Unit 2 shut block
valve MU067 to isolate a leak from the Unit 2 refueling water storage tank.
The refueling water storage tank to charging pump suction piping for Units 2 and 3 were
preliminarily determined to be operable through application of Code Case N-513-2,
Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3
Piping. Subsequently, procedure modification permits were prepared per Procedure
SO123-0-A3, Procedure Use, Revision 8, for Unit 2 on November 25, and for Unit 3 on
November 28, to open the block valves to support operability of the functions provided
by the refueling water storage tank to charging pump suction piping. Specifically, Unit 2
initiated a procedure modification permit to modify Procedure SO23-3-2.11.1, SFP
Level Change and Purification Crosstie Operations, Revision 14, to open block valve
MU067 and maintain the ability to makeup to the spent fuel pool using the refueling
water storage tank and spent fuel pool pump. Unit 3 initiated a procedure modification
permit to modify the abnormal operating instruction Procedure SO23-13-2, Shutdown
from Outside the Control Room, Revision 12, to open block valves MU067 and MU054
to maintain the boron flow path provided by the refueling water storage tank to charging
pump suction pipe. The intention of the procedure modification permits was to replace
the automatic opening of valves with the local manual opening of block valves.
On December 2, 2009, the inspectors reviewed the actions taken by operation personnel
in response to the identification of the through wall leaks identified on Units 2 and 3. The
inspectors noted that block valves remained closed on Units 2 and 3 and questioned
operations personnel whether the refueling water storage tank to charging pump suction
lines were considered operable. Operations personnel presented the procedure
modification permits to the inspectors and explained that the procedure modifications
were being used to support operability of the functions provided by the piping. The
inspectors reviewed the procedure modification permit and noted that the actions were
described as maintenance activities rather than compensatory measures used to
substitute manual operator actions for automatic actions to perform a required function.
Consequently, the required 10 CFR 50.59 screening was not performed. Further, the
inspectors questioned whether the requirements of Procedure SO123-XV-52,
Functionality Assessments and Operability Determinations, Revision 14,
Attachment 10, were followed for the use of compensatory measures to support
operability/functionality. The inspectors reviewed Procedure SO123-XV-52,
- 32 - Enclosure
Attachment 10, and observed that Step 1.8, stated, in part, that A compensatory
measure is NOT a maintenance activity, which was contrary to the descriptions on the
procedure modification permits.
In conclusion, the inspectors determined that operations personnel did not follow the
requirements of Procedure SO123-XV-52, Attachment 10, to perform a screening per
10 CFR 50.59 and review additional considerations necessary for the procedure
modification permits that were implemented as compensatory measures. Operations
personnel initiated Nuclear Notification NN 200689450 to document the failure to follow
Procedure SO123-XV-52, and actions were taken to comply with the requirements.
Analysis. The failure to follow procedures and adequately implement identified
compensatory measures to support operability/functionality was a performance
deficiency. The finding is greater than minor because the inadequate implementation of
compensatory measures, if left uncorrected, would have the potential to lead to a more
significant safety concern. The finding is associated with the procedure quality attribute
of the Mitigating Systems Cornerstone and affects the associated cornerstone objective
to ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Using the Manual Chapter 0609,
Significance Determination Process, Phase 1 Worksheets, the finding is determined to
have very low safety significance because the finding did not result in an actual loss of
safety function, and did not screen as potentially risk significant due to a seismic,
flooding, or severe weather initiating event. This finding has a crosscutting aspect in the
area of human performance associated with decision making because operations
personnel failed to make decisions using a systematic process, especially when faced
with uncertain or unexpected plant conditions, to ensure safety is maintained H.1(a).
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion V, Instructions, Procedures and Drawings, requires that activities affecting
quality shall be prescribed by instructions, procedures, or drawings and shall be
accomplished in accordance with those instructions, procedures, and drawings. The use
of compensatory measures to substitute manual operator actions for automatic actions
to perform a required function needed to mitigate accidents was an activity affecting
quality and was implemented by Procedure SO123-XV-52, Functionality Assessments
and Operability Determinations, Revision 14, Attachment 10, Guidance for Use of
Compensatory Measures to Support Operability/Functionality. Contrary to the above,
on November 25 and November 28, 2009, operations personnel failed to follow
Procedure SO123-XV-52. Specifically, operations personnel did not follow requirements
to establish a compensatory measure to substitute manual operator actions for
automatic actions to support the operability of the functions provided by the refueling
water storage tank to charging pump suction piping. Because the finding is of very low
safety significance and has been entered into the licensees corrective action program
as Nuclear Notification NN 200689450, this violation is being treated as a noncited
violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000361;05000362/2009005-06, Failure to Adequately Implement Compensatory Measures to
Maintain Equipment Operable.
- 33 - Enclosure
1R18 Plant Modifications (71111.18)
a. Inspection Scope
To verify that the safety functions of important safety systems were not degraded, the
inspectors reviewed the temporary modification identified as installation and testing of
containment jib crane and heavy lift devices associated with Unit 2 steam generator
replacement activities.
The inspectors reviewed the temporary modifications and the associated safety-
evaluation screening against the system design bases documentation, including the
Updated Final Safety Analysis Report and the technical specifications, and verified that
the modification did not adversely affect the system operability/availability. The
inspectors also verified that the installation and restoration were consistent with the
modification documents and that configuration control was adequate. Additionally, the
inspectors verified that the temporary modification was identified on control room
drawings, appropriate tags were placed on the affected equipment, and licensee
personnel evaluated the combined effects on mitigating systems and the integrity of
radiological barriers.
These activities constitute completion of one sample for temporary plant modifications as
defined in Inspection Procedure 71111.18-05.
b. Findings
No findings of significance were identified.
.2 Permanent Modifications
a. Inspection Scope
The inspectors reviewed key parameters associated with energy needs, materials,
replacement components, timing, heat removal, control signals, equipment protection
from hazards, operations, flow paths, pressure boundary, ventilation boundary,
structural, process medium properties, licensing basis, and failure modes for the
permanent modification associated with Unit 2 replacement steam generator skirt bolt
hole enlargement and stud deletion.
The inspectors verified that modification preparation, staging, and implementation did not
impair emergency/abnormal operating procedure actions, key safety functions, or
operator response to loss of key safety functions; postmodification testing will maintain
the plant in a safe configuration during testing by verifying that unintended system
interactions will not occur; systems, structures and components performance
characteristics still meet the design basis; the modification design assumptions were
appropriate; the modification test acceptance criteria will be met; and licensee personnel
identified and implemented appropriate corrective actions associated with permanent
plant modifications. Specific documents reviewed during this inspection are listed in the
attachment.
- 34 - Enclosure
These activities constitute completion of one sample for permanent plant modifications
as defined in Inspection Procedure 71111.18-05.
b. Findings
No findings of significance were identified.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed the following postmaintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- November 5, 2009, Unit 3, pressurizer level control valve 3LV0110B flow limiter
adjustment
- November 9, 2009, Unit 2, spent fuel pool cooling pump 2P009 restoration to
normal power supply
- November 26, 2009, Unit 3, return to service testing for pressurizer pressure
instrument channel A
- December 4, 2009, Unit 2, 4.16 kV class 1E bus 2A06
- December 8, 2009, Unit 3, flexible hose for the dc auxiliary turbo pump for
emergency diesel generator train B
- December 23, 2009, Unit 2, emergency cooling unit 2ME255 train A following
thermal overload replacement
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 Part 50 requirements, licensee procedures, and
various NRC generic communications to ensure that the test results adequately ensured
that the equipment met the licensing basis and design requirements. In addition, the
inspectors reviewed corrective action documents associated with postmaintenance 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.
- 35 - Enclosure
These activities constitute completion of six postmaintenance testing inspection samples
as defined in IP 71111.19-05.
b. Findings
No findings of significance 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 Unit 2
refueling outage (U2C16) and steam generator replacement that commenced on
September 27, 2009, 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. NRC Inspection
Report 05000361/2009007 will document inspections and findings associated with
steam generator replacement. During the refueling 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.
- Clearance activities, including confirmation that tags were properly hung and
equipment appropriately configured to safely support the work or testing.
- Installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indication, accounting for instrument error.
- Status and configuration of electrical systems to ensure that technical
specifications and outage safety-plan requirements were met, and controls over
switchyard activities.
- Monitoring of decay heat removal processes, systems, and components.
- Verification that outage work was not impacting the ability of the operators to
operate the spent fuel pool cooling system.
- Reactor water inventory controls, including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss.
- Controls over activities that could affect reactivity.
- Maintenance of secondary containment as required by the technical
specifications.
- Refueling activities, including fuel handling and sipping to detect fuel assembly
leakage.
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- Licensee identification and resolution of problems related to refueling outage
activities.
Specific documents reviewed during this inspection are listed in the attachment.
Refueling outage U2C16 was still in progress at the end of this inspection period.
Consequently, these activities constitute only partial completion of one refueling outage
and other outage inspection sample as defined in IP 71111.20-05.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, procedure
requirements, and technical specifications to ensure that the five 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
- Fulfillment of ASME Code requirements
- Updating of performance indicator data
- Engineering evaluations, root causes, and bases for returning tested systems,
structures, and components not meeting the test acceptance criteria were correct
- Reference setting data
- 37 - Enclosure
- Annunciators and alarms setpoints.
The inspectors also verified that licensee personnel identified and implemented any
needed corrective actions associated with the surveillance testing.
- July 25, 2009, Unit 2, motor driven auxiliary feedwater pump MP504
comprehensive full flow surveillance test
- September 24, 2009, Unit 3, heat treatment of circulating water system
- October 7, 2009, Unit 2, emergency diesel generator train B
- October 8, 2009, Unit 3, containment spray pump 3MP-012 inservice test
- October 8, 2009, Unit 2, local leak rate test of penetration 21, service air to
containment, to include the installed blind flanges
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of five surveillance testing inspection samples as
defined in IP 71111.22-05.
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP1 Exercise Evaluation (71114.01)
a. Inspection Scope
The inspectors reviewed the objectives and scenario for the 2009 biennial emergency
plan exercise to determine if the exercise would acceptably test major elements of the
emergency plan. The scenario simulated a spill of contaminated material within the
plant, a reactor pressure transient caused by a failed reactor coolant pump causing
damage to reactor fuel cladding, a steam line break in containment, a fire on licensee
property leading to a loss of offsite power for both reactor units, a diesel generator failure
that resulted in station blackout conditions for Unit 2, and a radiological release to the
environment via a steam generator tube leak, to demonstrate licensee personnels
capability to implement their emergency plan.
The inspectors evaluated exercise performance by focusing on the risk-significant
activities of event classification, offsite notification, recognition of offsite dose
consequences, and development of protective action recommendations, in the Control
Room Simulator and the following dedicated emergency response facilities:
- Operations Support Center
- Emergency Operations Facility
- 38 - Enclosure
The inspectors also assessed recognition of, and response to, abnormal and emergency
plant conditions, the transfer of decision making authority and emergency function
responsibilities between facilities, onsite and offsite communications, protection of
emergency workers, emergency repair evaluation and capability, and the overall
implementation of the emergency plan to protect public health and safety and the
environment. The inspectors reviewed the current revision of the facility emergency
plan, emergency plan implementing procedures associated with operation of the
licensees emergency response facilities, procedures for the performance of associated
emergency functions, and other documents as listed in the attachment to this report.
The inspectors compared the observed exercise performance with the requirements in
the facility emergency plan, 10 CFR 50.47(b), 10 CFR Part 50, Appendix E, and with the
guidance in the emergency plan implementing procedures and other federal guidance.
The inspectors attended the post-exercise critiques in each emergency response facility
to evaluate the initial licensee self-assessment of exercise performance. The inspectors
also attended a subsequent formal presentation of critique items to plant management.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one sample as defined in Inspection
Procedure 71114.01-05.
b. Findings
No findings of significance were identified.
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
a. Inspection Scope
The inspector performed in-office and on-site reviews of licensee changes to the San
Onofre Nuclear Generating Station Emergency Plan, Revisions 25 and 26, both received
June 23, 2009, emergency plan implementing procedure SO123-VIII-1, Recognition and
Classification of Emergencies, Revision 28, submitted August 28, 2009, and San Onofre
Nuclear Generating Station Emergency Plan, Revision 27, implemented September 9,
2009. These revisions:
- Revised the licensees goal for staffing their emergency response facilities from
sixty minutes to ninety minutes;
- Moved the primary dose assessment function from the Technical Support Center
to the Emergency Operations Facility;
- Moved the Effluent Engineer and Administrative Leader positions from the
Technical Support Center to the Emergency Operations Facility (EOF);
- Deleted the EOF Offsite Dose Assessment Liaison, and Medical Team positions
from the emergency response organization;
- Deleted the Emergency Classification and Event Code Chart;
- 39 - Enclosure
- Combined the positions of Emergency News Center Technical Liaison and
Emergency News Center Communications Liaison;
- Clarified that Corporate Emergency Director is responsible for evacuating the
site, and the Station Emergency Director is responsible for conducting site
assembly and accountability;
- Added licensed Reactor Operators to the personnel qualified to fill the Control
Room Emergency Notification System Communicator positions;
- Added offsite monitoring teams (four technicians) to the minimum staff positions
required to be present to activate the Emergency Operations Facility;
- Added the EOF Health Physics Communicator position to the emergency
response organization;
- Added the Electrical Technician, Instrument and Control Technician, and five
Health Physics Technicians as required minimum staff positions to activate the
Operations Support Center;
- Added description of the duties of the environmental monitoring teams;
- Added several emergency response organization positions to Table 5-2,
Emergency Response Organization Duties;
- Added Table 5-5, Emergency Response Organization Minimum Staff Positions;
- Added directions for handling an inoperable plant vent stack radiation monitor to
emergency action level A1;
- Added clarifying information to emergency action level B1 to identify that steam
generator and chemical volume and control system leakage are included in the
25 gpm identified leakage criteria;
- Added clarifying information to emergency action level B3 to identify the
alternative release paths to the environment to be considered, and specify that
the calculation of release time begins when charging pump capacity is exceeded;
- Added clarifying information to emergency action level D3 to identify that the
reactor has failed to manually trip when any combination of Manual Reactor Trip
Pushbuttons are unsuccessful in tripping the reactor (initiating condition 5), and
that a loss of normal or auxiliary feedwater applies to uncontrolled reactor coolant
system temperature (initiating condition 7);
- Updated emergency response organization position titles;
- Updated titles of offsite emergency response organizations; and,
- Made minor editorial corrections.
The NRC approved the licensees proposal to change their timeliness goal for staffing
their emergency response facilities from sixty minutes to ninety minutes in a Safety
- 40 - Enclosure
Analysis Report dated November 28, 2008 (Agency Document and Management
System Accession Numbers ML071700672, ML082740060, and ML0832306080).
These revisions were compared to their previous revision, to the criteria of NUREG-
0654, Criteria for Preparation and Evaluation of Radiological Emergency Response
Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, and to the
standards in 10 CFR 50.47(b) to determine if the revision adequately implemented the
requirements of 10 CFR 50.54(q). These reviews were not documented in safety
evaluation reports and did not constitute approvals of licensee-generated changes;
therefore, these revisions are subject to future inspection. The specific documents
reviewed during this inspection are listed in the attachment.
The inspector also performed an in-office review of the licensees emergency plan
implementing procedure SO123-VIII-1, Recognition and Classification of Emergencies,
Revision 29, submitted October 14, 2009. This revision added a note describing the
validation of a fire alarm to Emergency Action Level E1-1, A Fire which is not declared
extinguished by the Fire Incident Commander within 15 minutes of Control Room
Notification or verification of a Control Room alarm.
This revision was compared to its previous revision, to the criteria of NUREG-0654,
Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants, Revision 1, and to the standards in
10 CFR 50.47(b) to determine if the revision adequately implemented the requirements
of 10 CFR 50.54(q). This 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.
These activities constitute completion of five samples as defined in Inspection
Procedure 71114.04-05.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation (71114.06)
Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on November
18, 2009, to identify any weaknesses and deficiencies in classification, notification, and
protective action recommendation development activities. The inspectors observed
emergency preparedness mini drills 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 scenarios and other documents listed in the
attachment.
- 41 - Enclosure
These activities constitute completion of one sample as defined in IP 71114.06-05.
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
a. Inspection Scope
This area was inspected to assess licensee personnels performance in implementing
physical and administrative controls for airborne radioactivity areas, radiation areas, high
radiation areas, and worker adherence to these controls. The inspectors 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 inspectors interviewed the radiation protection manager,
radiation protection supervisors, and radiation workers. The inspectors performed
independent radiation dose rate measurements and reviewed the following items:
- Performance indicator events and associated documentation packages reported
by the licensee in the Occupational Radiation Safety Cornerstone
- Controls (surveys, posting, and barricades) of radiation, high radiation, or
airborne radioactivity areas
- Radiation work permits, procedures, engineering controls, and air sampler
locations
- Conformity of electronic personal dosimeter alarm set points with survey
indications and plant policy; workers knowledge of required actions when their
electronic personnel dosimeter noticeably malfunctions or alarms
- Barrier integrity and performance of engineering controls in airborne radioactivity
areas
- Physical and programmatic controls for highly activated or contaminated
materials (non-fuel) stored within spent fuel and other storage pools
- Self-assessments, audits, licensee event reports, and special reports related to
the access control program since the last inspection
- Corrective action documents related to access controls
- Licensee actions in cases of repetitive deficiencies or significant individual
deficiencies
- Radiation work permit briefings and worker instructions
- 42 - Enclosure
- Adequacy of radiological controls, such as required surveys, radiation protection
job coverage, and contamination control during job performance
- Dosimetry placement in high radiation work areas with significant dose rate
gradients
- Changes in licensee procedural controls of high dose rate - high radiation areas
and very high radiation areas
- Controls for special areas that have the potential to become very high radiation
areas during certain plant operations
- Posting and locking of entrances to all accessible high dose rate - high radiation
areas and very high radiation areas
- Radiation worker and radiation protection technician performance with respect to
radiation protection work requirements
Either because the conditions did not exist or an event had not occurred, no
opportunities were available to review the following item:
- Adequacy of the licensees internal dose assessment for any actual internal
exposure greater than 50 millirem committed effective dose equivalent
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of 21 of the required 21 samples as defined in
Inspection Procedure 71121.01-05.
b. Findings
No findings of significance were identified.
2OS2 ALARA Planning and Controls (71121.02)
a. Inspection Scope
The inspectors assessed licensee personnels performance with respect to maintaining
individual and collective radiation exposures as low as is reasonably achievable. The
inspectors used the requirements in 10 CFR Part 20 and the licensees procedures
required by technical specifications as criteria for determining compliance. The
inspectors interviewed licensee personnel and reviewed the following:
- Dose rate reduction activities in work planning
- Workers use of the low dose waiting areas
- 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
- 43 - Enclosure
- Radiation worker and radiation protection technician performance during work
activities in radiation areas, airborne radioactivity areas, or high radiation areas
- Declared pregnant workers during the current assessment period, monitoring
controls, and the exposure results
- Self-assessments, audits, and special reports related to the ALARA program
since the last inspection
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of 4 of the required 15 samples and 2 of the
optional samples as defined in Inspection Procedure 71121.02-05.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1 Data Submission Issue
a. Inspection Scope
The inspectors performed a review of the data submitted by the licensee for the
Third Quarter 2009 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 of significance were identified.
.2 Safety System Functional Failures (MS05)
a. Inspection Scope
The inspectors sampled licensee submittals for the safety system functional failures
performance indicators for Units 2 and 3 for the period from the 4th quarter 2008 through
the 3rd quarter 2009. 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 5, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73."
The inspectors reviewed the licensees operator narrative logs, operability assessments,
maintenance rule records, maintenance work orders, issue reports, event reports, and
NRC integrated inspection reports for the period of October 2008 through September
2009, to validate the accuracy of the submittals. The inspectors also reviewed the
licensees issue report database to determine if any problems had been identified with
- 44 - Enclosure
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 two safety system functional failures sample as
defined in Inspection Procedure 71151-05.
b. Findings
No findings of significance were identified.
.3 Reactor Coolant System Specific Activity (BI01)
a. Inspection Scope
The inspectors sampled licensee submittals for the reactor coolant system specific
activity performance indicator for Units 2 and 3 for the period from the 4th quarter 2008
through the 3rd quarter 2009. 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 5. The inspectors reviewed the licensees reactor coolant system
chemistry samples, technical specification requirements, issue reports, event reports,
and NRC integrated inspection reports for the period of October 2008 through
September 2009 to validate the accuracy of the submittals. The inspectors also
reviewed the licensees issue 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. In addition to record reviews, the inspectors observed a
chemistry technician obtain and analyze a reactor coolant system sample. Specific
documents reviewed are described in the attachment to this report.
These activities constitute completion of two reactor coolant system specific activity
sample as defined in Inspection Procedure 71151-05.
b. Findings
No findings of significance were identified.
.4 Occupational Exposure Control Effectiveness
a. Inspection Scope
The inspectors sampled licensee submittals for the Occupational Radiological
Occurrences performance indicator for the period from the 2nd quarter 2009 through the
3rd quarter 2009. To determine the accuracy of the performance indicator data reported
during those periods, performance indicator definitions and guidance contained in NEI
Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5,
was used. The inspectors reviewed the licensees assessment of the performance
indicator for occupational radiation safety to determine if indicator related data was
adequately assessed and reported. To assess the adequacy of the licensees
performance indicator data collection and analyses, the inspectors discussed with
radiation protection staff, the scope and breadth of its data review, and the results of
those reviews. The inspectors independently reviewed electronic dosimetry dose rate
and accumulated dose alarm and dose reports and the dose assignments for any
- 45 - Enclosure
intakes that occurred during the time period reviewed to determine if there were
potentially unrecognized occurrences. The inspectors also conducted walkdowns of
numerous locked high and very high radiation area entrances to determine the adequacy
of the controls in place for these areas.
These activities constitute completion of the occupational radiological occurrences
sample as defined in Inspection Procedure 71151-05.
b. Findings
No findings of significance were identified.
.5 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual
Radiological Effluent Occurrences
a. Inspection Scope
The inspectors sampled licensee submittals for the Radiological Effluent Technical
Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences
performance indicator for the period from the 2nd quarter 2009 through the 3rd quarter
2009. To determine the accuracy of the performance indicator data reported during
those periods, performance indicator definitions and guidance contained in NEI
Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5,
was used. The inspectors reviewed the licensees issue report database and selected
individual reports generated since this indicator was last reviewed to identify any
potential occurrences such as unmonitored, uncontrolled, or improperly calculated
effluent releases that may have impacted offsite dose.
These activities constitute completion of the radiological effluent technical
specifications/offsite dose calculation manual radiological effluent occurrences sample
as defined in Inspection Procedure 71151-05.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical
Protection
.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
- 46 - Enclosure
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 of significance were identified.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees corrective action program. The inspectors
accomplished this through review of the stations daily corrective action documents.
The inspectors performed these daily reviews as part of their daily plant status
monitoring activities and, as such, did not constitute any separate inspection samples.
b. Findings
No findings of significance 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 six month period of July
2009 through December 2009, 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
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a sample of the issues identified in the licensees trending reports were reviewed for
adequacy.
These activities constitute completion of one semi-annual trend inspection sample as
defined in IP 71152-05.
b. Observations and Findings
Based on the inspectors observation of an inadequate log keeping trend, Nuclear
Notification NN 200614441 was initiated for operations personnel to perform a three
month log review to determine whether entries satisfied the requirements of Procedure
SO123-0-A1, Conduct of Operations, Revision 26.
The assessment confirmed the inspectors observations and concluded that operator
logs were inconsistent and did not meet procedure intent for context, clarity, and closure.
Although some entries included the elements as described in Procedure SO123-0-A1 for
operable and inoperable, they were inconsistent with the standard. Consequently, it
became difficult to determine the logic used for determining operability and inoperability.
As a result of the assessment, Nuclear Notification NN 200685073 was initiated to
review the issues through an apparent cause evaluation.
.4 Selected Issue Follow-up Inspection
a. Inspection Scope
During a review of items entered in the licensees corrective action program, the
inspectors recognized a corrective action item documenting the issue listed below. The
inspectors considered the following during the review of the licensees actions: (1)
complete and accurate identification of the problem in a timely manner; (2) evaluation
and disposition of operability/reportability issues; (3) consideration of extent of condition,
generic implications, common cause, and previous occurrences; (4) classification and
prioritization of the resolution of the problem; (5) identification of root and contributing
causes of the problem; (6) identification of corrective actions; and (7) completion of
corrective actions in a timely manner.
- December 10, 2009, Unit 3, pipe S31219ML057, T006 Refueling Water Storage
Tank Gravity Feed Outlet
These activities constitute completion of one in-depth problem identification and
resolution sample as defined in IP 71152-05.
b. Findings
No findings of significance were identified.
.5 In-depth Review of Operator Workarounds
a. Inspection Scope
The inspectors conducted a cumulative review of operator workarounds for Units 2 and 3
and assessed the effectiveness of the operator workaround program to verify that the
licensee was: 1) identifying operator workaround problems at an appropriate threshold;
- 48 - Enclosure
2) entering them into the corrective action program; and 3) identifying and implementing
appropriate corrective actions. The review included walkdowns of the control room
panels, interviews with licensed operators and reviews of the control room discrepancies
list, the lit annunciators list, the operator burden list, and the operator workaround list.
These activities constitute completion of one in-depth review of operator workarounds
sample as defined in IP 71152-05.
b. Findings
No findings of significance were identified.
.6 Hours charged for Focused Problem Identification and Resolution Inspection
Hours charged in this report include hours that were expended during the focused
problem identification and resolution inspection, the results of which will be documented
in NRC Inspection Report 05000361; 05000362/2009009.
4OA3 Event Follow-up (71153)
.1 Event Follow Up
a. Inspection Scope
The inspectors reviewed the below listed events for plant status and mitigating actions
to: (1) provide input in determining the appropriate agency response in accordance with
Management Directive 8.3, NRC Incident Investigation Program; (2) evaluate
performance of mitigating systems and licensee actions; and (3) confirm that the
licensee properly classified the event in accordance with emergency action level
procedures and made timely notifications to NRC and state/governments, as required.
- September 13, 2009, Unit 2, automatic turbine/reactor trip from approximately 94
percent power on low condenser vacuum as a result of a recirculation gate (gate
5) sticking partially open during a planned heat treat evolution
- September 29, 2009, Unit 2, inspectors follow-up of the fire declared in the
tendon gallery during tendon removal activity
- October 25, 2009, Unit 3, power transient due to high pressure turbine stop valve
UV2200E failure
- November 13, 2009, Unit 2, uncontrolled strand uncoiling and anchor head drop
on outside lift system
- November 18, 2009, Unit 2, incorrectly wired 480 volt 3-phase power cord
resulted in substation J loss of power
- December 12, 2009, Unit 3, notice of unusual event declared when unit
shutdown commenced for inoperable emergency diesel generators
- December 23, 2009, Unit 3, unexpected flow degradation for salt water cooling
train A which resulted in a loss of spent fuel pool cooling
- 49 - Enclosure
Documents reviewed by the inspectors are listed in the attachment.
These activities constitute completion of seven inspection samples as defined in
Inspection Procedure 71153-05.
b. Findings
1. Deficiencies Associated with Circulating Water Gate Maintenance
Introduction. The inspectors identified a Green finding for the failure of maintenance
personnel to use Procedure SO23-XV-2, Troubleshooting Plant Equipment and
Systems, in developing procedures and work plans to adequately perform, test, and
communicate maintenance activities on Unit 2 circulating water gate 5.
Description. On September 5, 2009, circulating water gate 5 was manipulated in
preparations for a heat treat of the Unit 2 intake. Gate 5 stuck open at 14 percent during
closure from approximately 40 percent open. Operators in the area of gate 5 noted that
the gate made a loud noise during closure. The licensee initiated Nuclear Notification
NN 200572373. The heat treat was postponed due to higher than normal seawater
temperatures. Maintenance personnel adjusted a stop nut at the south end of gate 5,
and were able to successfully close it. Operations personnel then successfully jogged
gate 5 approximately 10 percent open on two occasions and declared gate 5 functional.
On September 9, 2009, the heat treat was rescheduled to be performed. During the
attempt to open gate 5, it stuck open at approximately 35 percent. Operations personnel
effectively backed out of the evolution. As a result of operator interviews, the inspectors
discovered that the operating crew performing the heat treat evolution on September 9,
2009, received no information from any source that there had been any previous
problems associated with any of the Unit 2 circulating water gates.
Maintenance personnel indicated that they suspected actuator problems with gate 5 but
lacked spare parts to perform the desired repairs. Maintenance personnel then decided
to remove the necessary actuator parts from Unit 3 and install them on Unit 2.
Operations personnel then successfully jogged Unit 2 gate 5 approximately 10 percent
open and declared gate 5 functional at approximately 6:30 a.m. on September 13, 2009.
The heat treat was rescheduled to be performed during the day shift on September 13,
2009. During the attempt to open gate 5, it stuck open at approximately 45 percent.
Operations personnel were unable to overcome the transient caused by increasing
circulating water temperatures and the subsequent loss of condenser vacuum. The
turbine automatically tripped on low condenser vacuum, which resulted in an automatic
reactor trip. The inspectors noted that corrective maintenance procedures used to repair
gate 5 were ineffective, and the postmaintenance testing performed on gate 5 was also
ineffective in determining functionality.
Procedure SO23-XV-2, Troubleshooting Plant Equipment and Systems, Revision 3,
described the process for troubleshooting and fault analysis of installed plant equipment
and provided the methodology and consistent approach for troubleshooting Critical A
equipment. Circulating water gate 5 was rated as a Critical A component, since it has
been classified as having an effect on nuclear safety, plant reliability, or power
generation, in that its failure could result in a plant trip, as well as a 5 percent or greater
full load power reduction. The inspectors concluded that maintenance personnel did not
- 50 - Enclosure
have adequate procedures in place, since the standards of Procedure SO23-XV-2 were
not followed to perform corrective maintenance on Unit 2 circulating water gate 5. The
attempts to repair gate 5 were repeatedly unsuccessful due to inadequate planning,
execution, postmaintenance testing, and communication. The inspectors also concluded
that removing parts from Unit 3 in an attempt to make Unit 2 functional was a poor
practice and exhibited poor oversight by maintenance personnel to ensure adequate
spare parts were available to ensure the functionality of plant equipment that could
directly affect plant operations.
The inspectors noted that the root cause evaluation for Nuclear Notification NN
200580999 generated in response to the event addressed procedural deficiencies in the
maintenance and postmaintenance testing of Unit 2 circulating water gate 5, but did not
address the failure of maintenance personnel to adequately communicate their activities
to other interested departments, particularly operations. The licensee generated a new
notification (Nuclear Notification NN 200718204) to address this deficiency.
Analysis. The failure of maintenance personnel to have adequate procedures in place to
perform maintenance activities on recirculating water gates is a performance deficiency.
The finding is greater than minor because the performance deficiency was a precursor to
a significant event (reactor trip). Using the Manual Chapter 0609, Significance
Determination Process, Phase 1 Worksheets, the finding is determined to have very low
safety significance because the finding did not contribute to both the likelihood of a
reactor trip and the likelihood that mitigation equipment or functions would not be
available. The finding has a crosscutting aspect in the area of human performance
associated with work control because maintenance personnel failed to incorporate
actions to address the need for work groups to communicate, coordinate, and cooperate
with each other during activities in which interdepartmental coordination is necessary to
assure plant and human performance H.3(b).
Enforcement. No violation of regulatory requirements occurred because the finding
occurred on nonsafety, but risk significant secondary plant equipment. The licensee
entered the finding into the corrective action program as Nuclear Notifications NNs
200580999 and 200718204: FIN 05000361/2009005-07, Inadequate Circulating Water
System Maintenance Procedures Contribute to Unit 2 Inadvertent Reactor Trip.
2. Deficiencies Associated with Circulating Water Gate Operation
Introduction. The inspectors identified a Green finding for the failure of operations
personnel to perform an adequate pre-job brief in accordance with procedural
requirements for a planned Unit 2 heat treat evolution.
Description. Unit 2 experienced an automatic turbine/reactor trip from approximately
94 percent power on low condenser vacuum on Sunday, September 13, 2009. The low
vacuum was caused by increasing circulating water temperature as a result of a
recirculation gate (gate 5) sticking partially open during a planned heat treat evolution.
The heat treat evolution is normally performed at approximately six week intervals on
each unit by realigning circulating water to increase temperature in the respective units
intake to clear out unwanted marine life to prevent clogging of the intake structure and
ultimately the salt water cooling/component cooling water heat exchanger.
- 51 - Enclosure
This evolution had been attempted the previous Wednesday, September 9, 2009, and
was successfully aborted without a significant plant transient when a similar problem
occurred on gate 5.
During the event on September 13, 2009, gate 5 failed after it had opened 45 percent.
Gates 4 and 6 were also being opened and gate 3 was being closed simultaneous to the
operation of gate 5. When gate 5 failed at 45 percent open, gates 3 and 4 were 50
percent open and gate 6 was 60 percent open. The personnel operating the gates
indicated that they were confused as to which procedural direction applied, since two
gates were at 50 percent, one was less than 50 percent, and one was greater than 50
percent. The field operator suggested gate 5 be manually jogged to verify overload
status. When gate 5 failed to move, and after an approximate three minute delay,
direction was provided from the control room to close gate 3 and open gate 4. The
inspectors determined that the delay in properly reacting to the failure of gate 5
contributed to the escalation of circulating water temperatures which contributed to the
turbine/reactor trip.
The inspectors reviewed Procedure SO23-5.1.1, Heat Treating the Circulating Water
System, Revision 22, as part of their event follow-up and determined that the guidance
for reacting to circulating water gate failures contributed to the turbine/reactor trip on
Unit 2 on September 13, 2009. Specifically, Procedure SO23-5-1.1, Attachment 8,
Step 2.4 stated:
If any gate stops moving mid-position, utilize the following strategy:
- If the gates have traveled <50 percent, all movement should be stopped and the
functioning gates restored to their previous positions. The non-functioning gate
should be repaired and restored to its previous position.
- If the gates have traveled >50 percent, allow gate movement to continue. The non-
functioning gate should be repaired and placed in the intended position.
The inspectors considered the attempts to troubleshoot the cause of the gate failure, and
determine overload status, to be contrary to the Gate Failure Strategy in Procedure
SO23-5-1.1, Attachment 8, which repositions the functioning gates first and dictates no
actions for attempting to troubleshoot or determine the problem with a non-functioning
gate.
Through interviews of licensee personnel, the inspectors reconstructed the pre-job briefs
which took place prior to the commencement of heat treat evolutions on September 9,
2009, and September 13, 2009, and compared them with the requirements of Procedure
OSM-6, Operations Department Human Performance Tools, Revision 8.
The inspectors noted that Procedure OSM-6, Step 3.7.10 stated, in part, to ensure
elements of an effective Pre-job Brief are addressed if required. Under Elements of an
Effective Pre-job Brief, Procedure OSM-6 stated, in part, that the pre-job brief leader
discusses Safety Concerns, Operating Experience, Potential Problems, Error-likely
Situations, Back out Criteria, Communications. The inspectors noted that the
September 9, 2009, pre-job brief included specific requirements to back out of the
evolution should a problem with gate operation occur. The gate operator was explicitly
told to immediately shut gate 3 and open gate 4 should gate 5 stick in place during
opening without delaying to call the control room. Additionally, this back out criteria was
- 52 - Enclosure
reiterated when one of the equipment operators asked for clarification during the pre-job
brief. The inspectors also noted that although potential problems with gate 5 operation
were discussed, no such clarification on back out criteria took place during the
September 13, 2009, pre-job brief. The inspectors concluded that the lack of specificity
during the September 13, 2009, pre-job brief contributed to the delay in operator actions
which ultimately resulted in a turbine/reactor trip on low condenser vacuum due to high
circulating water temperatures. The inspectors therefore concluded that elements of an
effective pre-job brief were not performed in accordance with procedural requirements
on September 13, 2009.
The inspectors noted that the root cause evaluation for Nuclear Notification NN
200580999 generated in response to the event addressed this deficiency.
Analysis. The failure of operations personnel to follow procedural requirements for
conducting an adequate pre-job brief was a performance deficiency. The finding is
greater than minor because the performance deficiency was a precursor to a significant
event (reactor trip). Using the Manual Chapter 0609, Significance Determination
Process, Phase 1 Worksheets, the finding is determined to have very low safety
significance because the finding did not contribute to both the likelihood of a reactor trip
and the likelihood that mitigation equipment or functions would not be available. The
finding has a crosscutting aspect in the area of human performance associated with
resources because the licensee failed to provide adequate procedural guidance to
ensure that operations personnel could safely perform plant evolutions H.2(c).
Enforcement. No violation of regulatory requirements occurred because the finding
occurred on nonsafety, but risk significant secondary plant equipment. The licensee
entered the finding into the licensees corrective action program as Nuclear Notification
NN 200580999: FIN 05000361/2009005-08, Unit 2 Heat Treat Pre-job Brief Not
Performed in Accordance with Procedural Requirements.
3. Fires in Tendon Gallery
Introduction. Three examples of a self-revealing Green noncited violation of Technical
Specification 5.5.1.1.d, were identified for the failure of contractor personnel to properly
implement the requirements of a fire protection procedure for the control of hot work
activities.
Description. The inspectors reviewed a series of hot work related events that were all
associated with the Unit 2 Cycle 16 steam generator replacement outage during pre-
outage and outage work activities. These events involved a failure to properly
implement the hot work procedural requirements of Procedure SO123-XV-1.41, Control
of Ignition Sources, Revision 13. All of the events required fire department response.
On September 1, 2009, a fire was reported associated with hot work activities during
replacement and welding of instrument air lines. The cause was determined to be a
failure of contractor personnel to follow hot work procedural requirements, including poor
housekeeping which allowed combustible material to be near the ignition source that
resulted in a fire. This event was documented in Nuclear Notification NN 200567213.
The other two events were associated with hot work activities during containment tendon
detensioning and removal. The containment tendons are designed as part of the Unit 2
containment structure and are comprised of a bundle of 55, 3/8-inch diameter steel
- 53 - Enclosure
strands. The bundle of strands are enclosed by a 6-inch diameter metal sheath and
filled with grease. Each strand is anchored with a wedge to carry the tensile load.
Detensioning and removal required the cutting of each tendon strand to access each
anchor wedge. The process required that contractor personnel cut each individual
strand with a hand grinder and then apply a hot flame to the exposed strand using an
acetylene torch. This resulted in hot liquefied grease and slag which needed to be
immediately collected into a sand filled metal drum to allow the hot materials to cool.
The licensees fire protection procedure for hot work, Procedure SO123-XV-1.41, did not
allow combustible materials within 35 feet of the ignition source or flame. Because of
the containment tendon detensioning and removal process, and the hot liquefied grease
and slag that was produced, it was not practical to maintain the combustible materials at
the required distance from the ignition sources or flames. Therefore, a flame permit
deviation assessment was required by fire protection engineering. Although a hot work
permit was issued, the requirements of the hot work permit were not followed, in that, the
appropriate fire protection engineering evaluation and deviation assessments were not
completed.
The first event associated with containment tendon activities occurred on September 28,
2009, when a fire was reported in the tendon gallery. This event was documented in
Nuclear Notification NN 200601793. Following the September 28 event, Nuclear
Notification NN 200602213 documented observations where no fire watch was present
to observe the sparks that were occurring during the tendon cutting process. The
nuclear notification failed to identify that uncovered combustible materials were within 35
feet of the observed sparks, and the appropriate evaluations had not been performed.
Further, the only immediate action taken, as documented in the nuclear notification, was
to have the contractor personnel communicate the fire watch inadequacies to their
supervisor. The second event associated with these activities occurred the next day, on
September 29, when a fire event was declared in the tendon gallery. The fire was
extinguished after several attempts, however, due to heat buildup, smoke continued to
fill the tendon gallery area. Workers evacuated the area and the fire department was
contacted. The fire department responded to the event and operations personnel
implemented abnormal operating instruction Procedure SO123-13-21, Fire,
Revision 13. The fire was officially declared out within 8 minutes. This event was
documented in Nuclear Notification NN 200602881.
The direct cause evaluation associated with Nuclear Notification NN 200602881,
concluded that contractor personnel were not complying with the licensees Fire
Protection Program procedures, in that, outage related hot work was authorized even
though the ignition source was in direct contact with combustible material (liquefied
tendon grease) without an approved deviation as required by Procedure
SO123-XV-1.41, Control of Ignition Sources.
Analysis. The failure to properly implement the fire protection procedure was a
performance deficiency. The finding is greater than minor because it is associated with
the protection against external factors (fires) attribute of the Initiating Events
Cornerstone and affects the cornerstone objective to limit the likelihood of those events
that upset plant stability and challenge critical safety functions during shutdown as well
as power operations. Additionally, if left uncorrected, the practice of conducting hot work
in a manner that results in unintended combustion of nearby materials would have the
potential to lead to a more significant safety concern in that it could result in a fire in or
- 54 - Enclosure
near risk significant equipment. Manual Chapter 0609, Appendix M, Significance
Determination Process Using Qualitative Criteria, was used since Appendix F, Fire
Protection Significance Determination Process, does not address the potential risk
significance of shutdown fire protection findings, and Appendix G, Shutdown Operations
Significance Determination Process, does not address fire protection findings. The
NRC management review was performed by using the Manual Chapter 0609,
Appendix F, Phase 1 Worksheet, to establish a bounding analysis. Using the bounding
analysis, the finding is determined to have very low safety significance because the
finding represented a low degradation rating, in that, it did not have any significant effect
on the likelihood that a fire might occur, or that a fire which does occur might not be
promptly suppressed. This finding has a crosscutting aspect in the area of human
performance associated with work practices because the licensee failed to ensure
supervisory and management oversight of work activities, including contractors, such
that nuclear safety was supported H.4(c).
Enforcement. Technical Specification 5.5.1.1.d requires that written procedures be
established, implemented, and maintained covering Fire Protection Program
implementation. The Fire Protection Program was implemented, in part, by Procedure
SO123-XV-1.41, Control of Ignition Sources, Revision 13. Procedure SO123-XV-1.41,
Steps 6.1.1 and 6.4.1.3, required that combustible materials be covered or stored at a
distance of 35 feet from the ignition sources or flames, or that an evaluation be
performed and compensatory actions implemented if this was not practical. Contrary to
the above, between September 1 and September 29, 2009, three examples were
identified where contractor personnel failed to properly implement the requirements of
Procedure SO123-XV-1.41, steps 6.1.1 and 6.4.1.3. Specifically, contractor personnel
failed to ensure that combustible materials were covered or stored at a distance of 35
feet from the ignition source or flame, and no compensatory evaluation was performed.
All three examples of this performance deficiency resulted in a fire. Because this finding
is of very low safety significance and has been entered into the licensees corrective
action program as Nuclear Notification NN 200604378, this violation is being treated as
a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV
05000361/2009005-09, Failure to Implement Fire Protection Plan Requirements
Related to Hot Work Activities.
4. Notice of Unusual Event
On December 7, 2009, emergency diesel generator train B was declared inoperable
after a monthly surveillance run due to an excessive lube oil system leak (NCV
05000361;05000362/2009005-05). After performing maintenance on the lube oil
system, the monthly surveillance run was performed as a postmaintenance test on
December 9. Nuclear Notification NN 200699513 documents that a low lube oil
temperature alarm was received during this postmaintenance run. Following the
temperature alarm, the emergency diesel generator train B run was stopped and the
generator was declared inoperable but functional. Troubleshooting determined that the
low lube oil temperature switch was sticking and the decision was made to repair the
switch after the diesel generator was restored to operable status. On December 10,
emergency diesel generator train B was declared operable after a satisfactory monthly
surveillance run.
On December 11, 2009, work was conducted under Nuclear Maintenance Order NMO
800422054 to replace the low lube oil temperature switch for emergency diesel
- 55 - Enclosure
generator train B. During the switch replacement, a technician inadvertently grounded a
wire that in turn blew the fuse on the annunciator alarm panel. The emergency diesel
generator train B was immediately declared inoperable. After the fuse was replaced the
emergency diesel generator train B remained inoperable because engineering personnel
determined, due to system design, that the grounded wire by itself should not have
caused the fuse to fail.
On December 12, 2009, operations personnel attempted to start emergency diesel
generator train A in order to rule out a common cause failure in accordance with
Technical Specification 3.8.1, Condition B.3.2. However, emergency diesel generator
train A failed to start and was declared inoperable; this was documented in Nuclear
Notification NN 200704606.
At 1:26 a.m. on December 12, the licensee declared a Notice of Unusual Event as
operations personnel initiated a down power of Unit 3 in accordance with Technical
Specification 3.8.1, Condition F.1, which required the unit to be in Mode 3 within six
hours. At 5:11 a.m., the down power was suspended at 40 percent power after the
emergency diesel generator train B was declared operable based on a successful
operability run and a prompt operability determination. The licensee exited the Notice of
Unusual Event at 6:45 a.m.
Troubleshooting on emergency diesel generator train A determined that voltage noise
from a degraded annunciator power supply incorrectly closed contacts in the speed
switch, which in turn prevented the generator from starting. The inspectors noted that
the emergency diesel generator train A had potentially been inoperable since the last
surveillance run on November 23, 2009. The annunciator power supplies were replaced
and the emergency diesel generator train A was declared operable on December 15,
2009.
Findings associated with this event are documented in Section 1R12.
.2 Event Report Review
a. Inspection Scope
The inspectors reviewed the five below listed licensee event reports and related
documents to assess: (1) the accuracy of the licensee event report: (2) the
appropriateness of corrective actions; (3) violations of requirements; and (4) generic
issues.
b. Observations and Findings
1. (Closed) Licensee Event Report 05000361; 05000362/2008-007-00, Failure to Comply
with TS Surveillance Requirement Completion Time
On September 18, 2008, the licensee identified a practice that did not satisfy a technical
specification condition requirement. Technical Specification 3.8.1, Condition B, requires
Surveillance Requirement 3.8.1.1, AC Sources Verification, be performed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
after declaring an emergency diesel generator inoperable, and once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
thereafter. Contrary to this requirement, operations personnel performed Surveillance
Requirement 3.8.1.1 within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> prior to declaring an emergency diesel generator
inoperable for planned periods of inoperability, and once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. This
- 56 - Enclosure
practice was consistent with the original technical specification but not with the improved
technical specification (implemented August 5, 1996). The implementing procedure for
this surveillance was not revised at the time of implementing the new improved technical
specification. This procedure has been corrected. This failure to comply with
Surveillance Requirement 3.8.1.1 completion time constitutes a violation of minor
significance that is not subject to enforcement action in accordance with the NRCs
Enforcement Policy. This licensee event report is closed.
2. (Closed) Licensee Event Report 05000361/2008-005-00, Missed Surveillance and Plant
Mode Change Causes TS Violation
On June 9, 2008, Unit 2 entered Mode 2 from Mode 3 during plant startup. At about
1443 PDT, the control room supervisor recognized that the control element assembly
alignment Surveillance Requirements 3.1.5.1 and 3.1.5.2 had not been completed prior
to the mode change. Technical Specification 3.1.5 is applicable in Modes 1 and 2, but
not in Mode 3. This was a violation of Surveillance Requirement 3.0.4 which prevents
mode entry without completing all applicable surveillance requirements. Operations
personnel completed the surveillances with satisfactory results. The procedure for the
mode change was not clear and has been revised to specifically require that the
surveillances are completed. This failure to comply with technical specification
Surveillance Requirement 3.0.4 constitutes a violation of minor significance that is not
subject to enforcement action in accordance with the NRCs Enforcement Policy. This
licensee event report is closed.
3. (Closed) Licensee Event Report 05000361/2009-001-00, Unit Trip on Low Vacuum
Caused by Intake Circulating Water Gate
San Onofre Unit 2 experienced an automatic turbine/reactor trip from approximately
94 percent power on low condenser vacuum on September 13, 2009. The low vacuum
was caused by increasing circulating water temperature as a result of a recirculation
gate (gate 5) sticking partially open during a planned heat treat evolution. Findings
associated with this event are described Section 4OA3 of this report. This licensee
event report is closed.
4. (Closed) Licensee Event Report 05000361/2007-005-00, Loose Electrical Connection
Results in Inoperable Pump Room Cooler
On March 1, 2007, the Unit 2 spent fuel pool pump room emergency air conditioning fan
was started for air flow measurement and tripped on thermal overload. The phase A
connection to the thermal overload was found to be loose with evidence of arcing. The
licensee determined the loose connection likely was caused by inadequate tightening of
the connection during maintenance on October 27, 2006. Since the backup cooling for
this room was operable and the room temperature did not exceed the design
temperature, the spent fuel pool pump remained operable. Findings associated with this
licensee event report review are described Section 4OA5.4 of this report. This licensee
event report is closed.
5. (Closed) Licensee Event Reports 05000361; 05000362/2007-006-00 and 05000361;
05000362/2007-006-01, Loose Electrical Connection Results in One Train of
Emergency Chilled Water (ECW) System Inoperable
- 57 - Enclosure
On June 9, 2007, operations personnel found the control panel for emergency chiller
E336 de-energized. Further investigation identified that the retaining screw anchoring
the cable to the supply breaker in the power panel was stripped, preventing the cable
from being secured tightly. The licensee concluded that the loose connection was most
likely due to over tightening the terminal screw on June 28, 2005, when the breaker was
replaced. Findings associated with this licensee event report review are described
Section 4OA5.4 of this report. This licensee event report is closed.
4OA5 Other Activities
.1 Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
During the inspection period, the inspectors performed observations of security force
personnel and activities to ensure that the activities were consistent with San Onofre
Nuclear Generating Station security procedures and regulatory requirements relating to
nuclear plant security. These observations took place during both normal and off-normal
plant working hours.
These quarterly resident inspector observations of security force personnel and activities
did not constitute any additional inspection samples. Rather, they were considered an
integral part of the inspectors normal plant status review and inspection activities.
b. Findings
No findings of significance were identified.
.2 Temporary Instruction 2515-175, Emergency Response Organization, Drill/Exercise
Performance Indicator, Program Review
a. Inspection Scope
The inspector performed Temporary Instruction 2515-175, Emergency Response
Organization, Drill/Exercise Performance Indicator, Program Review, ensured the
completeness of Attachment 1 to the Instruction, and forwarded the data to NRC
Headquarters.
b. Findings
No findings of significance were identified.
.3 Temporary Instruction 2515-172, Reactor Coolant System Dissimilar Metal Butt Welds
a. Inspection Scope
The reactor coolant system for this unit is carbon steel with stainless steel cladding and
has the following dissimilar metal welds subject to the requirements of the Materials
Reliability Program-139:
1. Two 12-inch pressurizer surge line nozzles were mitigated during a previous
outage using a weld overlay process. Both welds were classified as
Category F per material reliability program guidelines.
- 58 - Enclosure
2. Three 6-inch pressurizer safety nozzles were mitigated during a previous
outage using a weld overlay process. Both welds were classified as
Category F per materials reliability program guidelines.
3. One 4-inch pressurizer spray nozzle was mitigated during a previous outage
using a weld overlay process. The weld was classified as Category F per
materials reliability program guidelines.
4. One 16-inch shutdown cooling nozzle was mitigated during a previous outage
using a weld overlay process. The weld was classified as Category F per
materials reliability program guidelines.
5. Four 12-inch emergency core cooling system injection nozzles were
previously left unmitigated. The licensee performed a volumetric inspection
of each nozzle during the current outage and classified the welds as
Category I per materials reliability program guidelines.
6. Four 30-inch reactor coolant pump inlet nozzles (unmitigated as of this
outage). The licensee performed a volumetric inspection of each nozzle
during the current outage and classified the welds as Category I per materials
reliability program guidelines.
7. Four 30-inch reactor coolant pump outlet nozzles (unmitigated as of this
outage). The licensee performed a volumetric inspection of each nozzle
during the current outage and classified the welds as Category I per materials
reliability program guidelines.
All of the pressurizer and hot-leg-temperature welds have been mitigated, in previous
outages, using a full-structural overlay weld. The cold-leg-temperature welds have not
been mitigated as of this outage. The cold-leg welds have been, or will be,
volumetrically inspected and any decision to mitigate these welds will be made on the
basis of these inspections.
03.01 Licensees Implementation of the Materials Reliability Program-139 Baseline
Inspections
a. The inspector reviewed records of structural weld overlays and
nondestructive examination activities associated with the licensees
pressurizer structural weld overlay mitigation effort. The inspector observed
nondestructive examination activities associated with one cold leg weld that
was not overlaid.
b. The licensee was not planning to take any deviations from the baseline
inspection requirements of Materials Reliability Program-139, and all other
applicable dissimilar metal butt welds were scheduled in accordance with
Materials Reliability Program-139 guidelines.
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03.02 Volumetric Examinations
a. The inspector observed the ultrasonic examination of one cold leg weld that
was not scheduled to be overlaid. This examination was conducted in
accordance with ASME Code,Section XI, Supplement VIII Performance
Demonstration Initiative requirements regarding personnel, procedures, and
equipment qualifications. No relevant conditions were identified during this
examination.
b. The inspector reviewed records for the nondestructive evaluations performed
on one pressurizer surge line weld overlay. Inspection coverage met the
requirements of Materials Reliability Program-139 and no relevant conditions
were identified.
c. The certification records of ultrasonic examination personnel were reviewed
for those personnel that performed the examinations of the pressurizer and
cold-leg welds. All personnel records showed that they were qualified under
the EPRI Performance Demonstration Initiative.
d. No deficiencies were identified during the nondestructive examinations.
03.03 Weld Overlays
a. The inspector reviewed the welding activities associated with the weld
overlay performed on the pressurizer surge line nozzle.
b. The licensee submitted and received NRC authorization for the use of relief
request from the ASME code to apply weld overlays on their dissimilar metal
butt welds. Using this, the licensee performed weld overlays on all of the
dissimilar metal butt welds associated with pressurizer and hot leg
temperatures. This welding took place in previous outages. The inspector
reviewed the weld records for one of these welds to ensure the welding was
performed in accordance with the ASME code, as modified by the approved
relief requests.
c. Deficiencies have not been identified in the completed full structural weld
overlays.
03.04 Mechanical Stress Improvement
This item was not applicable because the licensee did not have plans to employ
a mechanical stress improvement process.
03.05 Inservice inspection program
The inspector reviewed the licensees risk informed inservice plan and verified
that all dissimilar metal butt welds have been entered into the plan and will be
examined on a schedule consistent with Materials Reliability Program-139.
b. Findings
No findings of significance were identified.
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.4 (Closed) Unresolved Item 05000361;05000362/2008013-07, Degraded Electrical
Connections
a. Inspection Scope
The inspectors evaluated Unresolved Item 05000361;05000362/2008013-07,
Degraded Electrical Connections.
b. Findings
Introduction. The inspectors identified a Green noncited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, with thirteen examples for the failure of the
licensee to ensure that appropriate measures were in place to assure that systems
specified in the design basis were maintained in a configuration which provided a
reasonable assurance of operability during design basis events.
Description. Details associated with this unresolved item were described in
Section 2.2.1 of NRC Inspection Report 05000361; 05000362/2008013 and are
summarized in the table below.
Table 1: Identified Loose Electrical Connections
Item Equipment Description Condition
1 3A276 Emergency Diesel Generator 3G003 Failed to start;
Building Supply Fan (3BH11) Discovered June
2005
2 3A277 Emergency Diesel Generator 3G002 2 loose connections;
Building Supply Fan (3BH12) Discovered June
2005
3 E549 Emergency Diesel Generator 3G002 Discovered June
Radiator Fan (3BH07) 2005
4 2BY37 Fuel Handling Building Pump Room Failed to run;
Emergency Air Conditioning Discovered March
Unit E441 Feeder Breaker 2007
5 2BJ06 Safety Injection Tank 2T008 to Documented January
Reactor Coolant Loop 1A Valve 2HV9340 2006
6 3BE06 Auxiliary Feedwater to Steam Generator 3 loose connections;
Control Valve 3HV4713 Discovered August
2005
7 2BY30 Component Cooling Water Building Loose grounding wire
Pump Room Emergency AC Unit E453 in MCC bucket;
Discovered July 2005
8 2BE11 Safety Injection Tank T009 to Reactor 3 loose connections;
Discovered January
- 61 - Enclosure
Table 1: Identified Loose Electrical Connections
Coolant Loop 2A Valve 2HV9360 2006
9 BS09 Control Building Control Room Loose connection in
Emergency Air Supply Fan A206 indicator circuit;
Discovered February
2006
10 2/3ME336 Emergency Chiller Supply Breaker E336 Instrumentation panel
failed; Discovered
June 2007
11 2B008 125 VDC Battery 2D2 Loose connection on
bus bar; Discovered
September 2007
12 3RY7870 Condenser Air Ejector Wide Range Failed Surveillance;
Radiation Monitor Discovered June
2008
13 3BD21 Diesel Radiator Fan 3E550 Feeder Degraded
Breaker connection;
Discovered July 2008
Analysis. The failure to ensure the integrity of electrical connections in equipment which
may be called upon during design basis events was a performance deficiency. The
finding is greater than minor because it is associated with the equipment performance
attribute of the Mitigating Systems Cornerstone and affects the associated cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. In accordance with Manual
Chapter 0609, Attachment 4, Table 4a, Question 5, a Phase 3 analysis was required
because the finding screened as potentially risk significant due to a seismic, flooding, or
severe weather initiating event. In accordance with Inspection Manual Chapter 0609,
Appendix A, the analyst determined that the conditions documented in Table 1 of this
inspection report should be evaluated as a single inspection finding because they
resulted from a common cause.
Internal Initiators:
The analyst evaluated Conditions 2, 3, 5 through 9, 11, and 13 documented in Table 1.
While the conditions of the fasteners were degraded, none of these components were
found to be in a failed condition. Therefore, there was no impact to internal initiated risk.
The remainder of the conditions documented on Table 1 was evaluated as discussed
here:
Condition 1: This condition involved the failure of the building supply fan for emergency
diesel generator 3G003 to start on demand in June, 2005. This fan was one of two
redundant fans performing the same function. However, to bound the change in risk, the
analyst conducted a Phase 3 analysis assuming the failure of emergency diesel
- 62 - Enclosure
generator 3G003, using the plant-specific SPAR model. The CDF (Core Damage
Frequency) for a failed diesel generator was 1.9 x 10-5/year. The exact time of failure
was unknown, but the fan had worked properly during a surveillance test approximately
30 days earlier. Therefore, the analyst assumed the diesel had been failed for 15 days.
This resulted in a bounding CDF of 7.8 x 10-7 over a 15-day period.
The analyst noted that this was a bounding evaluation of a specific postulated failure and
was not appropriate to combine with the risk of other evaluations performed. The
analyst determined qualitatively that this condition would not have greatly increased the
overall risk of the finding.
Condition 4: This condition involved the failure of the fuel handling building pump room
emergency air conditioning unit feeder breaker E441. The failure of this breaker
potentially affected the functionality of its associated spent fuel pool cooling pump.
Given the volume of water stored in the spent fuel pool, the low heat loading of fuel in
the pool, the availability of makeup systems, and the other train of spent fuel pool
cooling, the analyst determined that this condition did not greatly affect the core damage
frequency.
Condition 10: This condition involved the inoperability of the train A emergency chilled
water system chiller ME336 discovered on June 9, 2007 and reported by the licensee in
LER 2-2007-006-001. The licensees investigation of the cause of control panel (L177)
for ME336 being found de-energized on June 9, 2007 revealed that a power cable was
pulled out of the feeder breaker in a separate panel (Q033) supplying 120 VAC to the
chiller control panel, L177. Information provided by the licensee established May 17,
2007 as the date of the last successful surveillance of emergency chilled water train A,
representing a 23 day period that the performance deficiency potentially affected the
plant.
The analysts agreed with the licensee assessment that the subject performance
deficiency would result in the loss of the emergency chilled water train A from a
postulated seismic event that also causes a loss of offsite power. Under such a
scenario, the emergency chilled water system would be required to cool important loads
such as the main control room and critical switchgear and distribution panel rooms on
the 50 foot elevation in the auxiliary building. The inability to successfully dissipate the
heat loads could ultimately result in control room abandonment and the added
complexity of shutting down and cooling down from the remote shutdown panel. The
aggregate of these factors would adversely affect the core damage frequency. To
quantify the increase in core damage frequency (CDF) caused by the condition, the
analysts evaluated the added risk associated with the following circumstances: a)
emergency chilled water system becoming unavailable due to a seismically induced loss
of offsite power (8.0 x 10-7/year); b) emergency chilled water system becoming
unavailable due to internal event initiators (3.3 x 10-6/year); and c) Loss of both
emergency chilled water trains following a postulated loss of offsite power event causing
temperature increases that would necessitate main control room abandonment
(6.0 x 10-6/year).
A one year exposure time was considered appropriate for the seismic event vulnerability
whereas a 12-day (T/2 + repair time) exposure time was applied in the analysis of
internal event initiators and main control room abandonment. Considering the total loss
of emergency chilled water (train A loss due to the performance deficiency and nominal
- 63 - Enclosure
failure probability loss of train B) the change in core damage probability, assuming that
the above postulated conditions occurred, was calculated as follows:
CDF = (8.0 x 10-7/yr * 1 yr) + (3.3 x 10-6/yr * 12/365 yrs) + (6.0 x 10-6/yr * 12/365 yrs)
= 8.0 x 10-7 + 1.1 x 10-7 + 6.2 x 10-8
= 9.7 x 10-7
The analyst noted that the core damage sequences associated with this condition
resulted in loss of equipment from overheating. Therefore, the risk associated with this
condition was not considered additive to the bounding analyses conducted for the other
conditions.
Condition 12: This condition involved the condenser air ejector wide range radiation
monitor. The loose termination was discovered when recorder Point 9 was found out of
specification during a required 92-day surveillance. This recorder point had been found
high, but within the acceptable range, during the previous surveillance. Therefore, the
analyst assumed the point drifted out of specification, purportedly because of the loose
termination, at some time during the 92-day interval. The licensee stated that the
monitor does not perform any automatic isolation, control or alarm function, nor is the
monitor referenced in the decision logic for abnormal or emergency procedures. As
such, failure would not directly affect the core damage frequency. Additionally, although
the point was indicating high, it would have indicated a trend had a primary to secondary
leak developed.
External Initiating Events:
Seismic
Using a method similar to that documented in Attachment 3 of NRC Inspection Report
05000361/2008013; 05000362/2008013, the analyst evaluated the impact of the
Conditions 1 through 9 and 11 through 13 listed in Table 1 for their impact to risk during a
seismic event. Assuming that the loose connections listed doubled the probability that
the associated motor-control center would fail as a result of a seismic event, the analyst
quantified the seismic impact. The frequency of a seismically induced failure occurring
simultaneous with a nonrecoverable loss of offsite power was calculated to be
1.8 x 10-4/year. Based on an evaluation of the equipment redundancy and safety
function of each condition, the analyst determined that the worst case failure would be
the loss of a single diesel generator. The conditional core damage probability for this
was quantified as 2.0 x 10-3. Therefore, the analyst estimated the worst case failure at a
CDF of 3.6 x 10-7. The analyst determined that the probability of failure of more than
one of the components in the correct combination to increase the core damage
frequency significantly would be very low.
High Winds, Floods, and Other External Events
The analyst reviewed the IPEEE and determined that no other credible scenarios
initiated by high winds, floods, fire, and other external events could initiate a loss of
offsite power and directly cause the perturbation of the thirteen conditions associated
with this finding. Therefore, the analyst concluded that external events other than
seismic events were not significant contributors to risk for this finding.
- 64 - Enclosure
In accordance with the guidance in NRC Inspection Manual Chapter 0609, Appendix H,
this finding would not involve a significant increase in risk of a large early release of
radiation because San Onofre has a large, dry containment and the accident sequences
contributing to a change in the core damage frequency did not involve either a steam
generator tube rupture or an intersystem loss of coolant accident.
As a combined result of these evaluations, the analyst determined that this finding was
of very low safety significance (Green).
The finding has a crosscutting aspect in the area of human performance associated with
resources for the failure to maintain complete, accurate, and up-to-date design
documentation, procedures, and work packages H.2(c).
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion III, Design Control, states, in part, that measures shall be established to
assure that applicable regulatory requirements and the design basis, as defined in
§ 50.2 and as specified in the license application, for those structures, systems, and
components to which this appendix applies are correctly translated into procedures and
instructions. These measures shall include provisions to assure that appropriate quality
standards are specified and included in design documents. Contrary to this requirement,
between June 2005 and July 2008, the licensee failed to ensure that appropriate
measures were in place to assure that systems specified in the design basis were
maintained in a configuration which provided a reasonable assurance of operability
during design basis events. Specifically, thirteen examples of safety-related equipment
were identified with electrical connections that were not maintained in the required
design configuration.
Because this finding is of very low safety significance and has been entered into the
licensees corrective action program as Action Requests ARs 050601315, 050601324,
060101159, 070200254, 200066209, Nuclear Notifications NNs 200089167, 200058371,
200100730, and Corrective Action Order 800126624, this violation is being treated as a
noncited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV
05000361;05000362/2009005-10, Inadequate Design Control for Safety-Related
Electrical Connections.
4OA6 Meetings
Exit Meeting Summary
On September 25, 2009, the inspectors presented the results of the onsite inspection of the
2009 emergency preparedness exercise, and the inspection of licensee changes to their
emergency plan and emergency action levels to Mr. R. Ridenoure, Senior Vice President and
Chief Nuclear Officer, and other members of the licensees staff. The licensee acknowledged
the issues presented.
On October 16, 2009, the inspector presented the in-service inspection results to Mr. D. Bauder,
Plant Manager, and other members of the licensee staff. The licensee acknowledged the issues
presented.
- 65 - Enclosure
On October 29, 2009, the inspector conducted a telephonic exit meeting to present the results of
the in-office inspection of changes to the licensees emergency action levels to Mr. B. Ashbrook,
Manager, Onsite Emergency Preparedness. The licensee acknowledged the issues presented.
On October 30, 2009, the inspectors presented the radiation safety inspection results to
Mr. A. Hochevar, Station Manager, and other members of the licensee staff. The licensee
acknowledged the issues presented.
On December 15, 2009, the inspector briefed Mr. Bill Arbour, Training Supervisor, of the results
of the annual licensed operator requalification program inspection. The licensee acknowledged
the issues presented.
On January 13, 2010, the inspectors presented the integrated inspection results to
Mr. R. Ridenoure, Senior Vice President and Chief Nuclear Officer, and other members of the
licensee staff. The licensee acknowledged the issues presented.
The inspectors asked the licensee whether any materials examined during the inspections
should be considered proprietary or sensitive. The inspectors returned or destroyed all
proprietary information reviewed during the inspections and all identified sensitive information
has been returned to the appropriate licensee custodian.
4OA7 Licensee-Identified Violations
The following violations of very low safety significance (Green) were identified by the licensee
and are violations of NRC requirements which meet the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600, for being dispositioned as noncited violations.
.1 On August 8 and August 9, 2009, the licensee failed to follow their emergency plan in
that during one full shift and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 46 minutes of another shift the emergency plan-
required electrical maintenance position was not staffed. This finding is a failure to
comply with an NRC requirement, is associated with a 50.47(b) Planning Standard, is
not associated with a risk-signifcant Planning Standard, and is not a functional failure of
the planning standard because processes for ensuring the staffing of required on-shift
emergency response organization positions were generally effective. This finding has
been entered into the licensees corrective action program as Direct Cause Evaluation
200535198.
.2 Title 10 of the Code of Federal Regulations 50.65(a)(4), states in part, that before
performing maintenance activities, the licensee shall assess and manage the increase in
risk that may result from the proposed maintenance activities. Contrary to the above,
between September 30, 2009, and December 10, 2009, work control and operations
personnel failed to adequately assess and manage the increase in risk associated with
planned maintenance activities. Specifically, on September 30, errors were inadvertently
introduced to the risk model, such that, the risk assessments for planned maintenance
utilized a safety monitor with nonconservative allowed configuration time values until
discovery of the error on December 10, 2009. This finding has been entered into the
licensees corrective action program as Nuclear Notification NN 200701778. The finding
is of very low safety significance because the incremental core damage probability deficit
and the incremental large early release probability deficit were of sufficiently low
magnitudes.
- 66 - Enclosure
.3 Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings, states, in part, that activities affecting quality
shall be prescribed by documented instructions, procedures, or drawings, of a type
appropriate to the circumstances and shall be accomplished in accordance with these
instructions, procedures, or drawings. Procedure SO123-XV- 50.CAP-1, Writing
Nuclear Notifications for Problem Identification and Resolution, Revision 2, stated that
all personnel identifying problems that have the potential to affect the ability of a
structure, system, or component to perform its specified function will immediately notify
the shift manager or designee, and write a nuclear notification prior to the end of their
shift. Contrary to the above, on November 20, 2009, engineering personnel failed to
initiate a nuclear notification in a timely manner in accordance with their procedures.
Specifically, engineering personnel failed to write a nuclear notification in accordance
with Procedure SO123-XV-50.CAP-1, for a boric acid leak identified on Unit 2 pipe
S21219ML057, T006 RWST Gravity Feed Outlet. This finding has been entered into
the licensees corrective action program as Nuclear Notification NN 200683697. The
finding is of very low safety significance because the finding did not result in an actual
loss of safety function.
This licensee identified violation is another example of NCV 05000361/2009005-01,
Failure to Initiate a Notification in a Timely Manner, and is further discussed in
Section 1R06.1 of this report.
ATTACHMENT: SUPPLEMENTAL INFORMATION
- 67 - Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
T. Adler, Manager, Maintenance/Systems Engineering
B. Arbour, Operator Continuing Training Supervisor
J. Armas, Supervisor, Maintenance Engineering Fluid Process
B. Ashbrook, Manager, Emergency Preparedness
D. Axline, Technical Specialist, Nuclear Regulatory Affairs
D. Bauder, Plant Manager
P. Blakeslee, Supervisor, Mechanical Auxiliary Systems
J. Carey, Technician, Health Physics
S. Chun, Supervisor, Electrical/I&C Systems
B. Corbett, Manger, Performance Improvement
G. Cook, Manager, Compliance, Nuclear Regulatory Affairs
D. Deglopper, ALARA Planner, Health Physics
S. Deines, Technician, Health Physics
P. Elliot, Operations Supervisor, Health Physic Department
R. Elsasser, Manger, Training
M. Farmer, Radioactive Materials Control Supervisor, Health Physics
J. Fee, Manager, Site Emergency Preparedness
K. Gallion, ALARA Supervisor, Health Physics
S. Gardner, Electrical/System Engineering Manager
M. Graham, Manager, Plant Operations
A. Hochevar, Station Manager, Plant Operations
E. Hubley, Director, Maintenance/Construction
G. Johnson, Jr., Senior Nuclear Engineer, Maintenance/Systems Engineering
K. Johnson, Manager, Design Engineering
L. Kelly, Engineer, Nuclear Regulatory Affairs
D. Spires, Director, Work Control
J. Madigan, Manager, Health Physics
J. McGaw, Engineering Supervisor
A. Meichler, Mechanical/System Engineering Supervisor
M. Mihalik, Areva Project Manager, Steam Generator Replacement Project
M. Miranda, Technician, Health Physics
R. Nielsen, Supervisor, Nuclear Oversight
B. MacKissock, Director, Plant Operations
L. Pepple, ALARA Planner, Health Physics
N. Quigley, Manager, Maintenance/System Engineering
R. Richter, Engineering Supervisor, Fire Protection
M. Russell, Technical Specialist, Health Physics
C. Ryan, Manager, Maintenance & Construction Services
R. Sherman, ALARA Planner, Health Physics
R. St. Onge, Director Nuclear Regulatory Affairs
J. Todd, Manager, Security
G. Vechinski, Inservice Inspection/Steam Generator Support Supervisor
D. Wilcockson, Manager of Operations Training
A. Williams, Technician, Health Physics
A-1 Attachment
NRC Personnel
D. Loveless, Senior Reactor Analyst
E. Schrader, Emergency Preparedness Specialist
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000361/2009005-01 NCV Failure to Initiate a Notification in a Timely Manner
(Section 1R06)05000361/2009005-02 NCV Failure to Adequately Identify Problems in Corrective Action
Program (Section 1R06)05000362/2009005-03 NCV Failure to Correct Problems with Emergency Diesel
Generator Train B (Section 1R12)05000362/2009005-04 NCV Failure to Correct Problems with Emergency Diesel
Generator Train A (Section 1R12)05000362/2009005-05 NCV Failure to Follow the Operability Determination Process
(Section 1R15)05000361/2009005-06 NCV Failure to Adequately Implement Compensatory Measures05000362/2009005-06 to Maintain Equipment Operable (Section 1R15)05000361/2009005-07 FIN Inadequate Circulating Water System Maintenance
Procedures Contribute to Unit 2 Inadvertent Reactor Trip
(Section 4OA3)05000361/2009005-08 FIN Unit 2 Heat Treat Pre-job Brief Not Performed in
Accordance with Procedural Requirements (Section 4OA3)05000361/2009005-09 NCV Failure to Implement Fire Protection Plan Requirements
Related to Hot Work Activities (Section 4OA3)05000361/2009005-10 NCV Inadequate Design Control for Safety-Related Electrical
05000362/2009005-10 Connections (Section 4OA5)
Closed
05000361/2008-007-00 LER Failure to Comply with TS Surveillance Requirement
05000362/2008-007-00 Completion Time (Section 4OA3)
A-2 Attachment
Closed
05000361/2008-005-00 LER Missed Surveillance and Plant Mode Change Causes TS
Violation (Section 4OA3)
05000361/2009-001-00 LER Unit Trip on Low Vacuum Caused by Intake Circulating Water
Gate (Section 4OA3)
05000361/2007-005-00 LER Loose Electrical Connection Results in Inoperable Pump
Room Cooler (Section 4OA3)
05000361/2007-006-00 LER Loose Electrical Connection Results in One Train of
05000362/2007-006-00 Emergency Chilled Water (ECW) System Inoperable
05000361/2007-006-01 (Section 4OA3)
05000362/2007-006-01
05000361/2008013-07 URI Degraded Electrical Connections (Section 4OA5)05000362/2008013-07
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
Procedures
NUMBER TITLE REVISION
SO23-13-8 ISS2 Severe Weather 7
Miscellaneous
NUMBER TITLE
UFSAR 2.3 Meteorology NA
UFSAR 3.11 Environmental Design of Mechanical and Electrical NA
Equipment
UFSAR 9.2.6 Condensate Storage and Transfer System NA
A-3 Attachment
Section 1RO4: Equipment Alignment
Procedures
NUMBER TITLE REVISION
SO23-3-2.11 Spent Fuel Pool Operations 26
SO23-3-3.27.2 Surveillance Operating Instruction 19
SO23-2-8 Saltwater Cooling System Operation 32
SO23-2-8.1 Saltwater Cooling Removal and Returning to Service 9
Evaluation
SO23-2-13.1 Diesel Generator Alignment 4
Nuclear Notifications
NUMBER
200657834
Drawings
NUMBER TITLE REVISION
40122A Fuel Pool Cooling System 18
40122B Fuel Pool Cooling System 25
40122C Fuel Pool Cooling System 16
40122X Fuel Pool Cooling System 5
A-4 Attachment
Section 1RO5: Fire Protection
Procedures
NUMBER TITLE REVISION
SO23-XV-4.13 Control of Work and Storage Areas Within the Protected 5
Area
SO23-XIII-4.13 Inspection for Control of Combustibles and Transient Fire 1
Loads
Nuclear Notifications
NUMBER
200602405
Drawings
NUMBER TITLE REVISION
2-001A Pre-Fire Plans 6
2-001 Pre-Fire Plans 4
2/3-019 Pre-Fire Plans 6
2/3-024 Pre-Fire Plans 6
2/3-020 Pre-Fire Plans 6
2/3-025 Pre-Fire Plans 5
2/3-023 Pre-Fire Plans 7
Section 1RO6: Flood Protection Measures
Procedures
NUMBER TITLE REVISION
SO23-V-8.3 External Corrosion and Aging Program 0
Miscellaneous
A-5 Attachment
NUMBER TITLE NA
UFSAR 3.4 Water Level (Flood) Design
Section 1RO8: In-service Inspection Activities
Procedures
NUMBER TITLE REVISION
SO23-XXXIII- Reactor Coolant System Alloy 600 Inspection 7
8.16
SO23- IntraSpect Eddy Current Inspection of Vessel Head 7
XXVII.3.5.1.1 Penetration J-Welds and Tube OD Surfaces
SO23-XV-85 Boric Acid Corrosion Control Program (BACCP) 4
SO23-V-8.15 Containment Boric Acid Leak Inspection 2
SO123-IN-1 Inservice Inspection/Inservice Test Programs 8
S23-XVII-1.1 Inservice Inspection Program Maintenance 5
SO123-XV- SONGS Nuclear Notification Screening 3
50.CAP-2
PQS T4EN51 Non-RCS Alloy 600 Boric Acid Leakage Inspection and 1
Evaluation
PQS T4EN52 RCS Alloy 600 Boric Acid Leakage Inspection and 0
Evaluation
SO23-XXVII- Liquid Penetrant Examination 2
20.48
SO23-XXVII- Procedure for the Phased Array Ultrasonic Examination of 1
33.14 Weld Overlaid Similar and Dissimilar Metal Welds
SO23-XXVII- Ultrasonic Examination of Dissimilar Metal Piping Welds 2
30.9
A-6 Attachment
Section 1RO8: In-service Inspection Activities
PDI-UT-10 PDI Generic Procedure for the Ultrasonic Examination of C
Nuclear Notifications
NUMBER
200599549 200599604 200599688 200599422 200599618
200599623 200629478 200618073 200633298
Action Requests
NUMBER
071200751 071200830 080401360
Miscellaneous
NUMBER TITLE REVISION / DATE
Letter from R J. Docket Nos. 50-361 and 50-362 Revision 1 to October 2, 2009
St. Onge (SCE) Third Ten-Year Inservice Inspection (151) Interval
to USNRC Relief Request 151-3-29 Inspection of Reactor
Vessel Head Control Element Drive Mechanism
Nozzles San Onofre Nuclear Generating Station
Units 2 and 3
Letter from R J. Docket Nos. 50-361 and 50-362 Third Ten-Year October 2, 2009
St. Onge (SCE) Inservice Inspection (151) Interval Relief Request
to USNRC 151-3-30 Inspection of Reactor Vessel Head In-
Core Instrument Nozzles San Onofre Nuclear
Generating Station Units 2 and 3
Letter from J. CRDM/CEDM Qualifications October 2, 2009
Spanner (EPRI)
to M. McDevitt
(SC&E)
Code Case N- Alternative Examination Requirements for PWR March 28, 2006
729-1 Reactor Vessel Upper Heads With Nozzles Having
Pressure-Retaining Partial-Penetration Welds
Section XI Division 1
A-7 Attachment
Section 1RO8: In-service Inspection Activities
Code Case N- Additional Examinations for PWR Pressure July 5, 2005
722-1 Retaining Welds in Class 1 Components
Fabricated With Alloy 600/82/182 Materials Section
XI Division 1
MRP 2008-066 Letter from J. Hagan (EPRI) to MRP Technical December 17, 2008
Advisory Group Primary System Piping Butt Weld
Inspection and Evaluation Guideline (MRP-139
Revision 1)
MRP 2009-031 Letter from J. Hagan (EPRI) to MRP Technical June 8, 2009
Advisory Group MRP-139 Revision 1 Interim
Guidance on Reconciliation of BMV Requirements
with Code Case N-722 (Mandatory Element)
WR2-08-203 Weld Record for S2-1208-ML-003 (2TSH9205) 0
PQR-68 Manual Welding of Austenitic Stainless Steel January 3, 1985
Materials
PQR-5 Manual Gas Tungsten Arc Welding of Stainless June 28, 1984
Steel Material
WPS 8-GT Manual GTAW of P-Number 8 Austenitic Stainless September 13, 1998
Steel Alloys using IN308L/ER308L or
IN316Ll/ER316L Filler Metals
PQR 08-08-TS- 0
001
PQR-08-08-TS- 0
002
WPS 08-08-TS- 4
001
107294-TR-253 WSI Traveler Replacement of Check Valve MU 0
021
Phased Array SONGS U2 Hot Leg Surge January 11, 2009
Ultrasonic
Examination
Record
02-008-002 SONGS ISI Ultrasonic Calibration/Examination October 6, 2009
A-8 Attachment
Section 1RO8: In-service Inspection Activities
209-16PT-001 Liquid Penetrant Examination Report September 16, 2009
209-16PT-002 Liquid Penetrant Examination Report September 16, 2009
209-16PT-003 Liquid Penetrant Examination Report September 17, 2009
209-16PT-004 Liquid Penetrant Examination Report September 17, 2009
209-16PT-005 Liquid Penetrant Examination Report September 18, 2009
209-16PT-006 Liquid Penetrant Examination Report September 18, 2009
209-16PT-007 Liquid Penetrant Examination Report September 18, 2009
209-16PT-008 Liquid Penetrant Examination Report September 18, 2009
209-16PT-009 Liquid Penetrant Examination Report September 18, 2009
209-16PT-010 Liquid Penetrant Examination Report September 21, 2009
209-16PT-011 Liquid Penetrant Examination Report September 22, 2009
209-16PT-013 Liquid Penetrant Examination Report October 20, 2009
Section 1R11: Licensed Operator Requalification Program
Procedures
NUMBER TITLE REVISION
SO23-3-2.22 Engineered Safety Features Actuation System Operation 18
Miscellaneous
NUMBER TITLE REVISION
RS09C7 2009 Cycle 7b Simulator Summary 0
A-9 Attachment
Section 1R12: Maintenance Effectiveness
Procedures
NUMBER TITLE REVISION
SO123-XV-5.3 Maintenance Rule Program 11
Nuclear Notifications
NUMBER
200457220 200463358 200458378 200704606 200457220
200669151 200695875 200696832 200692595
Maintenance Orders
NUMBER
800321529 800321436 800410821 800318576
Miscellaneous
NUMBER TITLE REVISION /
DATE
3rd Quarter SONGS System Health Reports 0
2009
AR 030500466 SONGS Operational Experience Reviews May 9, 2003
EDGS SONGS 3rd Quarter EDGS System Health Report September 21,
2009
MJ7058 Personnel Qualification Standard - Advanced Soldering 2
MT7058 Lesson Plan - Advanced Soldering 2
A-10 Attachment
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
Procedures
NUMBER TITLE REVISION
SO123-I-1.13 NUREG 0612 Cranes, Rigging and Lifting Controls 17
SO23-1-3.3 Reactor Vessel Head Removal and Storage 13
SO123-1-7.14 Maintenance and Inspection of Cranes 10
Nuclear Notifications
NUMBER
200394201 200628904 200648805 200648807 200641130
200615912 200701778
Maintenance Orders
NUMBER
WCA 700002477 NMO 800251432 NECP 800175646 NECP 800072640
NECP 800130487
Drawings
NUMBER TITLE REVISION
23156-3 Containment Interior Structure Inserts 0
21015 Underground Utilities Protection Plan and Sections 8
25211-002 Unit 2 Service Crane/Runway Erection and Load Drop 0
Zones
716029 SH1 Unit 2 Safe Load Path 4
Calculations
NUMBER TITLE REVISION
A-11 Attachment
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
25221-000-COC- Outside Lift System and Erection and Collapse Load Drop 0
7100-00011 Effects
Miscellaneous
NUMBER TITLE REVISION
DID 4a Defense in Depth Sheet 4a 1
R2C16 Probabilistic Risk Assessment Group Recommendations 0
Risk Matrix Analysis- 480V transformer addition project 0
WCCP 15000 Reactor Head Lift 0
Section 1R15: Operability Evaluations
Procedures
NUMBER TITLE REVISION
SO123-XV-5 Nonconforming Materials, Parts, or Components 19
SO123-XV-52 Functionality Assessments and Operability Determinations 13
SO123-0-A3 Procedure Use 8
SO23-3-2.11.1 SFP Level Change and Purification Crosstie Operations 14
SO23-13-2 Shutdown from Outside the Control Room 12
SO123-XV-52 Functionality Assessments and Operability Determination 14
SO23-3-3.23 Diesel Generator Monthly and Semi-Annual Testing 43
SO123-XX-19 Operational Decision Making 4
Nuclear Notifications
A-12 Attachment
NUMBER
200645996 200643134 200695732 200692347 200691509
200682817 200689450 200683165 200683974 200689450
200683739 200704606 200457220 200702905 200695875
200696832 200669151 200700917
Drawings
NUMBER TITLE
835878 3000 Amp Jump Assembly
835879 Jump Assemblies 75 to 350 MVA
Calculations
NUMBER TITLE REVISION
J-KJA-012 Diesel Generator Low Lube Oil Level Alarm Setpoint 1
Maintenance Orders
NUMBER
800410821
Section 1R18: Plant Modifications
Procedures
NUMBER TITLE REVISION
P-2902-28 Hydraulic Life Device Load Test 0
P-2902-26 Temporary Handling Device Load Tet 0
Nuclear Notifications
NUMBER
200638659 200634389
A-13 Attachment
Maintenance Orders
NUMBER
NECP 800072651
Drawings
NUMBER TITLE REVISION
SO23-617-3B-D53 Temporary Handling Device 0
SO23-617-3B-D563 Load Test Hydraulic Lifter and Details 0
Calculations
NUMBER TITLE REVISION /
DATE
SO23-617-1-C995 Evaluation for Replacement Steam Generator (RSG) 0
Pedestal Skirt Bolt Hole Enlargement and Stud Deletion
Section 1R19: Postmaintenance Testing
Procedures
NUMBER TITLE REVISION
SO23-6-32 Electrical Bus Outages 16
SO23-6-2 Transferring of 4KV Buses 15
SO23-3-3.27.2 Weekly Electrical Bus Surveillance 19
SO23-3-3.23 Diesel Generator Monthly and Semi-Annual Testing 43
Nuclear Notifications
NUMBER
200638791 200657834 200402124 200695875 200696832
200669151 200700917
Maintenance Orders
A-14 Attachment
NUMBER
800397782 WCD 30003055 WCA 70002397 800256628 800410821
800429930 800430174 800130487 800404685
Drawings
NUMBER TITLE REVISION
30162 480 Volt Motor Control Center 2BY 35
30216 Elementary Diagram Electrical Auxiliary 4.16KV Bus 2A06 21
Tie Breaker
30299 Sheet 2 Elementary Diagram Electrical Auxiliary 4.16KV Bus 2A06 20
Metering
30220 Sheet 1 Elementary Diagram Electrical Auxiliary 4.16KV Bus 2A06 15
Metering
Miscellaneous
NUMBER TITLE DATE
Letter From Impact of U2 LOVS Relay Work on U3 Safety Busses December 4,
Gary Segich to 2009
Lou Bosch
Section 1R20: Refueling and Other Outage Activities
Procedures
NUMBER TITLE REVISION /
DATE
SO23-X-7 Refueling Operations 19
SO123-I-1.43 Maintenance Human Performance Application 9
25221-PP-63 Tendon Replacement Methodology Demonstration 0
Program
A-15 Attachment
Section 1R20: Refueling and Other Outage Activities
SO23-3-3.23 AC Sources Verification (Modes 5, 6, and Defueled) 41
Attachment 8
SO23-3-1.7 Aligning the Oil Lift Pump(s) and/or ARRD Pump(s) 35
Power Supplies
P-2502-30 Runway and Outside Lift System Installation and
Removal Program
Specification 240 Steam Generator Skirt Flange Bolts- Preload Evaluation September 30,
1980
SO123-XV-23.1 Housekeeping 4
SGRPP-SO123-G-1 Event Response Plan 1
SO23-X-7.2 Nuclear Fuel Management - Spent Fuel Pool 18
SO23-5-1.8.1 Shutdown Nuclear Safety 23
SO23-I-6.155 Containment Equipment Access Hatch Operation 9
Nuclear Notifications
NUMBER
200616238 200637174 200626409 2000633500 200616724
200620113 200611066 200606500 200613762 200619631
Maintenance Orders
NUMBER
800257416 800221379 800280086 800229724 800279989
800221369 800251355 800251357 800251354 800251435
800257416 8000313756
A-16 Attachment
Drawings
NUMBER TITLE REVISION
23056 Containment Structure Wall Liner and Installation 0
SO23-915-45 Steam Generator Support Installation 5
41276 Area CA10 drain 50' Elevation plans 8
Work Control Activities/Documents
NUMBER
30003180 30003055 70001551 30002002 30002007
700002478 30002398 30001921 30003180
Calculations
NUMBER TITLE REVISION /
DATE
25221-PP-05 Bechtel Project Plan Containment Opening Plan 2
M-120.09 Flooding Analysis April 20, 1977
Miscellaneous
NUMBER TITLE REVISION
WPIR WCN 25221- Chipping and Cutting for the Containment Construction Hole 0
002-CON-3050-
20114
WPIR WCN 25221- Preassembly Erection and Disassembly of inside runway
002-COP-0058-
00106
WPIR WCN 25221- Steam Generator Replacement 89 Whip Restraint Removal
002-MOP-7057-
0882
Section 1R22: Surveillance Testing
A-17 Attachment
Section 1R22: Surveillance Testing
Procedures
NUMBER TITLE REVISION
SO23-5-1.1 Heat Treating the Circulating Water System 23
SO23-13-10 Loss of Condenser Vacuum 8
SO23-V-3.4 Engineering Procedure Inservice tests 18
SO23-3-3.60.6 Surveillance Operating Instruction Inservice test 16
SO23-3-3.51 Containment Penetration Leak Rate Testing 7
SO23-3-3.51.8 Containment Penetration Leak Rate Testing Air System 9
SO23-3-3.23 Diesel Generator Monthly Testing 41
SO123-0-A4 Diesel Generator Starts 12
SO23-3-3.60.7 Containment Spray Pump 3MP-012 Group B Inservice Test 12
2JQ203B Local Leak Rate Testing (LLRT) Qualification Guide 1
2JQ101G Inservice Pump Testing Qualification Guide 1
Nuclear Notifications
NUMBER
200598566 200615026 200616518
Drawings
NUMBER TITLE REVISION
41061 AFW 2P504 Pump Curve 2
Miscellaneous
NUMBER TITLE DATE
Penetration 21 Test Data Sheet October 8, 2009
A-18 Attachment
Section 1EP1: Exercise Evaluation
Procedures
NUMBER TITLE REVISION
SO123-VIII-1 Recognition and Classification of Emergencies 28
SO123-VIII-10 Emergency Coordinator Duties 25-1
SO123-VIII-10.1 Station Emergency Director Duties 18-1
SO123-VIII-10.2 Corporate Emergency Director Duties 14-1
SO123-VIII-10.3 Protective Action Recommendations 12
SO123-VIII-30.3 OSC Operations Coordinator Duties 6
SO123-VIII-30.7 Emergency Notifications 11
SO123-VIII-40.100 Dose Assessment 13
Section 1EP6: Drill Evaluation
Miscellaneous
NUMBER TITLE REVISION
NEI 99-02 Regulatory Assessment Performance Indicator Guideline 5
Section 2OS1: Access Controls to Radiologically Significant Areas
AUDITS, SELF-ASSESSMENTS, AND SURVEILLANCES
TITLE
HPD U2C16 Refuel Outage 30 Day Self-Assessment
Procedures
A-19 Attachment
NUMBER TITLE REVISION
SO123-VII-20.6 External Occupational Exposure Monitoring 9
SO123-VII-20.9 Radiological Surveys 9
SO123-VII- Health Physics Pre-Job Briefings/Pre-job Meetings 5
20.10.2
SO123-VII- Access Control Program 12
20.11
SO123-VII- Radiological Posting 10
20.11.1
Nuclear Notifications
NUMBER
200530881 200596501 200623393 200625730
Radiation Work Permits
NUMBER TITLE
800211520 Perform ISI Inspections in U2C16 outage
800211882 Regenerative Heat Exchanger
A0216090013 2SGRP - RCS Piping Work
A0216090015 2SGRP - RCS Pipe End Decon
Section 2OS2: ALARA Planning and Controls
Procedures
NUMBER TITLE REVISION
SO123-VII- Radiological Work Planning and Controls 14
20.10
A-20 Attachment
Section 2OS2: ALARA Planning and Controls
SO123-VII-20.4 ALARA Program
Miscellaneous
NUMBER TITLE REVISION
R2C16 Outage ALARA Plan 0
Section 4OA1: Performance Indicator Verification
Procedures
NUMBER TITLE REVISION
SO123-VIII-1 Recognition and Classification of Emergencies 26, 27, 28
SO123-VIII-10.3 Protective Action Recommendations 11, 12
SO123-VII-30.7 Emergency Notifications 10, 11
Drills and Exercises
NUMBER TITLE DATE
0905 Emergency Plan Drill August 19, 2009
0904 ERO Restructure June 24, 2009
0903 Environmental April 8, 2009
0902 Assembly March 17, 2009
0901 Backshift January 6-12,
2009
0812 Contaminated Injury November 19,
2008
A-21 Attachment
Section 4OA1: Performance Indicator Verification
0806 Environmental October 8, 2008
0805 INPO Visit September 17,
2008
0804 Proficiency August 27, 2008
0803 Hostile Action Drill May 7, 2008
0802 Hostile Action Table Top April 23, 2008
0801 Mini-Drill April 2, 2008
0702 Emergency Plan Exercise April 18, 2007
0701 Emergency Plan Drill March 14, 2007
0502 Emergency Plan Exercise April 13, 2005
0501 Emergency Plan Drill March 9, 2005
Miscellaneous
NUMBER TITLE REVISION
San Onofre Nuclear Generating Station Emergency Plan 25, 26
SA-1 Self Assessment Program 5
VIII-0.202 Assignment of Emergency Response Personnel 10
XII-2.7 Reporting of Quality Trends 3-2
XV-50 Corrective Action Program 12
XV-50.CAP-2 SONGS Nuclear Notification Screening 2
A-22 Attachment
Section 4OA1: Performance Indicator Verification
XV-50.CAP-3 Corrective Action Program Evaluations and Action Plans 1
SO123-XXI-1.11.3 Emergency Plan Training Program Description 20, 21
Section 4OA2: Identification and Resolution of Problems
Procedures
NUMBER TITLE REVISION /
DATE
SO123-0-A1 Conduct of Operations 26
SO23-XVII-3.2.1 Class 2 System Leakage Test of the Chemical and 4
Volume Control System
Nuclear Notifications
NUMBER
200685073 200614441 200683697 200683767 200683165
200682817 200687365 200120199 200129036 200175511
200007225 200211509 200231399 200252142 200253424
200278159 200226143 200278221 200278222 200027824
200278227 200336666 200345873 200352006 200356782
200357504 200370464 200417017 200444208 200444284
200456915 200459256 200462583 200498500 200501123
200535198 200544102 200552330 200597585
Action requests
A-23 Attachment
NUMBER
011200984 950600074
Drawings
S3-1219-ML-057 From RWT T006 to Line 007 10
Maintenance Orders
800415935 800415909 800416417
Miscellaneous
NUMBER TITLE REVISION /
DATE
Document 90463 Unit 2 and 3 Schedule 10, Stainless Steel Piping Inspection 0
and Repair Plan
RCE 92-018 Corrosion of Stainless Steel Piping in the FFCPD System June 19,
Sluice Water Inlet Line 1992
Failure Analysis Failure Analysis of BAMU Line Cracking February 1,
Report 96-001 1996
Section 4OA3: Event Follow-Up
Procedures
NUMBER TITLE REVISION / DATE
LER 05000361/2007-005-00 Loose Electrical Connection Results in October 16, 2008
Inoperable Pump Room Cooler
LER 05000361/2008-005-00 Missed SR for Mode Change July 30, 2008
LER 05000361;05000362/2008- Failed to Comply with Completion Time November 14,
007-00 for SR 3.8.1.1 2008
SO123-0-A4 Configuration Control 12
A-24 Attachment
Section 4OA3: Event Follow-Up
SO123-XV-HU-1 Human Performance Program 3
SO123-0-A1 Conduct of Operations 25
SO23-6-33 Ground Isolation 6
SO23-5.1.1 Heat Treating the Circulating Water 22
System
SO23-13-10 Loss of Condenser Vacuum 8
OSM-6 Operations Department Human 8
Performance Tools
SO123-0-A1 Conduct of Operations 24
SO123-XV-HU-1 Human Performance Program 2
OSM-12 Operator Fundamentals 9
SO123-XV-1.41 Control of Ignition Sources 13
SO23-2-8 Saltwater Cooling System Operation 32
SO23-13-7 Loss of Cooling Water/Saltwater Cooling 14
Nuclear Notifications
NUMBER
200638837 200638791 200638786 200648875 200626763
200638641 200636533 200100730 200666537 20067114
A-25 Attachment
Section 4OA3: Event Follow-Up
200704617 200580999 200718204 200572373 200601793
200602881 200619437 200602213 200614395 200618783
200602881 200617708
Action Requests
NUMBER
070300033
Miscellaneous
NUMBER TITLE
Personnel Statements
Control Room Logs
45564 Event Log
A-26 Attachment