ML080440436
| ML080440436 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 02/13/2008 |
| From: | Clark J NRC/RGN-IV/DRP/RPB-E |
| To: | Rosenblum R Southern California Edison Co |
| References | |
| EA-08-051, FOIA/PA-2011-0157 IR-07-005 | |
| Download: ML080440436 (65) | |
See also: IR 05000361/2007005
Text
February 13, 2008EA-08-051
Richard M. Rosenblum Senior Vice President and
Chief Nuclear Officer
Southern California Edison Company
San Onofre Nuclear Generating Station
P.O. Box 128
San Clemente, CA 92674-0128SUBJECT:SAN ONOFRE NUCLEAR GENERATING STATION - NRC INTEGRATEDINSPECTION REPORT 05000361/2007005; 05000362/2007005 AND NOTICE OF
VIOLATIONDear Mr. Rosenblum:
On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your San Onofre Nuclear Generating Station, Units 2 and 3 facility. The enclosed
integrated report documents the inspection findings, which were discussed on December 21,
2007, and February 13, 2008, with Mr. R. Ridenoure and other members of your staff.The inspection examined activities conducted under your licenses as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your
licenses. The inspectors reviewed selected procedures and records, observed activities, and
interviewed personnel.One violation is cited in the enclosed Notice of Violation (Notice) and the circumstancessurrounding this violation are described in detail in the enclosed report. The violation involved
your failure to implement effective corrective actions to ensure thermal overloads associated
with safety-related equipment would not fail prematurely (EA-08-051). Although determined to
be of very low safety significance (Green), this violation is being cited because not all the
criteria specified in Section VI.A.1 of the NRC Enforcement Policy for a noncited violation (NCV)
were satisfied. Specifically, Southern California Edison failed to restore compliance within a
reasonable time after the violation was first identified in Inspection
Report 05000361;05000362/2006005. Please note that you are required to respond to this
letter and should follow the instructions specified in the enclosed Notice when preparing your
response. The NRC will use your response, in part, to determine whether further enforcement
action is necessary to ensure compliance with regulatory requirements.This report also documents three NRC identified and self-revealing findings of very low safetysignificance (Green). These findings were determined to involve violations of NRC
requirements. Additionally, one licensee-identified violation which was determined to be of very
low safety significance is listed in this report. However, because of the very low safety
Southern California Edison Company-2-significance and because they were entered into your corrective action program, the NRC istreating these findings as NCVs consistent with Section VI.A of the NRC Enforcement Policy. If
you contest these NCVs, you should provide a response within 30 days of the date of this
inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission,
ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional
Administrator, U.S. Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive,
Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear
Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at San
Onofre Nuclear Generating Station, Units 2 and 3, facility.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be made available electronically for public inspection
in the NRC Public Document Room or from the Publicly Available Records (PARS) component
of NRC's 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/Jeffrey A. Clark, ChiefProject Branch E
Division of Reactor ProjectsDockets: 50-361 50-362Licenses: NPF-10 NPF-15Enclosures:Notice of Violation
NRC Inspection Report 05000361/2007005; 05000362/2007005
w/Attachment: Supplemental Informationcc w/enclosure:Mr. Ross T. Ridenoure
Vice President and Site Manager
Southern California Edison Company
San Onofre Nuclear Generating Station
P.O. Box 128
San Clemente, CA 92674-0128Chairman, Board of SupervisorsCounty of San Diego
1600 Pacific Highway, Room 335
San Diego, CA 92101Gary L. Nolff
Assistant Direc
tor-ResourcesCity of Riverside
3900 Main Street
Riverside, CA 92522Mark L. ParsonsDeputy City Attorney
City of Riverside
3900 Main Street
Riverside, CA 92522
Southern California Edison Company-3-Dr. David Spath, ChiefDivision of Drinking Water and
Environmental Management
California Department of Health Services
850 Marina Parkway, Bldg P, 2
nd FloorRichmond, CA 94804Michael J. DeMarcoSan Onofre Liaison
San Diego Gas & Electric Company
8315 Century Park Ct. CP21G
San Diego, CA 92123-1548Director, Radiological Health BranchState Department of Health Services
P.O. Box 997414 (MS 7610)
Sacramento, CA 95899-7414Mayor City of San Clemente
100 Avenida Presidio
San Clemente, CA 92672James D. Boyd, CommissionerCalifornia Energy Commission
1516 Ninth Street (MS 34)
Sacramento, CA 95814Douglas K. Porter, Esq.Southern California Edison Company
2244 Walnut Grove Avenue
Rosemead, CA 91770A. Edward SchererSouthern California Edison Company
San Onofre Nuclear Generating Station
P.O. Box 128
San Clemente, CA 92674-0128Mr. Steve HsuDepartment of Health Services
Radiologic Health Branch
MS 7610, P.O. Box 997414
Sacramento, CA 95899-7414Mr. James T. ReillySouthern California Edison Company
San Onofre Nuclear Generating Station
P.O. Box 128
San Clemente, CA 92674-0128Chief, Radiological EmergencyPreparedness Section
National Preparedness Directorate
Technological Hazards Division
Department of Homeland Security
1111 Broadway, Suite 1200
Oakland, CA 94607-4052
Southern California Edison Company-4-Electronic distribution by RIV:ROPreportsRegional Administrator (EEC)DRP Director (DDC)DRS Director (RJC1)DRS Deputy Director (ACC)Senior Resident Inspector (CCO1)Branch Chief, DRP/E (JAC)Senior Project Engineer, DRP/E (GDR)Senior Project Engineer, DRP/E (GBM)Team Leader, DRP/TSS (CJP)RITS Coordinator (MSH3)DRS STA (DAP)V. Dricks, PAO (VLD)D. Pelton, OEDO RIV Coordinator (DLP1)SO Site Secretary (vacant) MVasquez (GMV)N Hilton, OEJune Cai, OE
John Wray, OE
Mary Ann Ashley, NRRSUNSI Review Completed: _GBM__ADAMS: Yes G No Initials: __GBM
_ Publicly Available
G Non-Publicly Available
G Sensitive Non-SensitiveR:\_REACTORS\_SO23\2007\SO2007-05RP-CCO.wpd ADAMS ML080440436RIV:RI:DRP/ESRI:DRP/ESPE:DRP/EC:DRS/PSBC:DRS/OBGMillerCCOsterholtzGReplogleMPShannonRELantz /RA/ /RA teleph./ /RA electronic/ /RA//RA/02/13/0802/13/0802/13/0802/12/0802/12/08C:DRS/EBC:DRS/PEBSES/ACESC:DRP/ERLBywaterLJSmithGMVasquezJAClark /RA//RA NO'Keefe for//RA//RA GMiller for/02/13/0802/11/082/12/0802/13/08OFFICIAL RECORD COPYT=Telephone E=E-mail F=Fax
ENCLOSURE 1NOTICE OF VIOLATIONSouthern California Edison Co.Docket No. 50-361;362San Onofre Nuclear Generating StationLicense No. NPF-10;15EA 08-051During an NRC inspection conducted on September 27 through December 31, 2007, a violationof NRC requirements was identified. In accordance with the NRC Enforcement Policy, the
violation is listed below: 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that"measures shall be established to ensure that for significant conditions adverse to
quality, the cause of the condition is determined and corrective action taken to preclude
repetition."Contrary to this, from February 6 through August 8, 2007, the licensee failed to takecorrective actions to preclude repetition of the premature tripping of thermal overloads
for safety-related equipment, a significant condition adverse to quality. This violation is associated with a Green SDP finding.
Pursuant to the provisions of 10 CFR 2.201, Southern California Edison Company is herebyrequired to submit a written statement or explanation to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555 with a copy to the
Regional Administrator, Region IV, and a copy to the NRC Resident Inspector at the facility that
is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of
Violation (Notice). This reply should be clearly marked as a "Reply to a Notice of Violation;
EA-08-051" and should include: (1) the reason for the violation, or, if contested, the basis fordisputing the violation or severity level, (2) the corrective steps that have been taken and theresults achieved, (3) the corrective steps that will be taken to avoid further violations, and
(4) the date when full compliance will be achieved. Your response may reference or include
previous docketed correspondence, if the correspondence adequately addresses the required
response. If an adequate reply is not received within the time specified in this Notice, an order
or a Demand for Information may be issued as to why the license should not be modified,
suspended, or revoked, or why such other action as may be proper should not be taken.
Where good cause is shown, consideration will be given to extending the response time. If you contest this enforcement action, you should also provide a copy of your response, withthe basis for your denial, to the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001. Because your response will be made available electronically for public inspection in the NRCPublic Document Room or from the NRC's document system (ADAMS), accessible from the
NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it shouldnot include any personal privacy, proprietary, or safeguards information so that it can be made
available to the public without redaction. If personal privacy or proprietary information is
necessary to provide an acceptable response, then please provide a bracketed copy of your
response that identifies the information that should be protected and a redacted copy of your
response that deletes such information. If you request withholding of such material, you must
ENCLOSURE 1-2-specifically identify the portions of your response that you seek to have withheld and provide indetail the bases for your claim of withholding (e.g., explain why the disclosure of information will
create an unwarranted invasion of personal privacy or provide the information required by
10 CFR 2.390(b) to support a request for withholding confidential commercial or financial
information). If safeguards information is necessary to provide an acceptable response, please
provide the level of protection described in 10 CFR 73.21. Dated this 13th day of February, 2008
ENCLOSURE 2-1-U.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket:50-361, 50-362 Licenses:NPF-10, NPF-15
Report No.:05000361/2007005 and 5000362/2007005
Licensee:Southern California Edison Co. (SCE)
Facility:San Onofre Nuclear Generating Station, Units 2 and 3Location:5000 S. Pacific Coast Hwy. San Clemente, California Dates:September 27, 2007 through December 31, 2007
Inspectors:C. C. Osterholtz, Senior Resident Inspector, Project Branch E, DRPM. O. Miller, Senior Resident Inspector, Project Branch E, DRP
M. R. Young, Resident Inspector, Project Branch E, DRP
G. Warnick, Senior Resident Inspector, Project Branch D, DRP
R. A. Kopriva, Senior Reactor Inspector, Engineering Branch 1, DRS
J. H. Nadel, Reactor Inspector, Engineering Branch 1, DRS
G. A. George, Reactor Inspector, Engineering Branch 1, DRS
B. D. Baca, Health Physics Inspector, Plant Support Branch, DRS
L. T. Ricketson, Senior Health Physics Inspector, Plant Support
Branch, DRS
S. T. Makor, Reactor Inspector, Engineering Branch 1, DRS
J. P. Adams, Reactor Inspector, Engineering Branch 1, DRS
L. E. Ellershaw, Senior Reactor Inspector, Engineering Branch 1, DRS
M. T. Baquera, Reactor Inspector, Engineering Branch 1, DRS
K. Clayton, Senior Operations Engineer, Operations Branch, DRSApproved By:Jeffrey A. Clark, Chief Project Branch E
Division of Reactor Projects
ENCLOSURE 2-2-TABLE OF CONTENTSSUMMARY OF FINDINGS..................................................-3-REPORT DETAILS........................................................-6-1R02Evaluations of Changes, Tests, or Experiments.......................-6-1R04Equipment Alignment...........................................-7-1R05Fire Protection................................................-8-1R07Heat Sink Performance.........................................-9-1R11Licensed Operator Requalification................................-17-1R12Maintenance Effectiveness.....................................-18-1R13Maintenance Risk Assessments and Emergent Work Control...........-20-1R15Operability Evaluations........................................-20-1R17Permanent Plant Modifications...................................-23-1R19Postmaintenance Testing......................................-23-1R20Refueling and Other Outage Activities.............................-24-1R22Surveillance Testing...........................................-25-1R23Temporary Plant Modifications...................................-25-1EP6Drill Evaluation...............................................-26-RADIATION SAFETY.....................................................-27-2OS1Access Control To Radiologically Significant Areas...................-27-2OS2Planning and Controls.........................................-29-OTHER ACTIVITIES......................................................-30-4OA1Performance Indicator (PI) Verification............................-30-4OA2Identification and Resolution of Problems..........................-32-4OA5 Other......................................................-36-4OA6Meetings, Including Exit........................................-38-4OA7Licensee-Identified Violations...................................-39-ATTACHMENT: SUPPLEMENTAL INFORMATION...............................A-1
KEY POINTS OF CONTACT................................................A-1LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED...........................A-1LIST OF DOCUMENTS REVIEWED..........................................A-2
LIST OF ACRONYMS.....................................................A-20
ENCLOSURE 2-3-SUMMARY OF FINDINGSIR05000361/2007005, 05000362/2007005; 09/27/07 - 12/31/07; San Onofre NuclearGenerating Station, Units 2 & 3; Integrated Resident and Regional Report; Emergent Work,
Operability Evaluations, Occupational Radiation Safety, Problem Identification and Resolution.This report covered a 3-month period of inspection by resident inspectors and Regional officeinspectors. The inspection identified four Green findings consisting of one cited violation and
three noncited violations. 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's review. The NRC's program
for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.NRC-Identified and Self-Revealing FindingsCornerstone: Mitigating Systems
- Green. The inspectors identified a Green noncited violation of10 CFR 50.65(a)(2) associated with the failure to include Units 2 and 3
emergency diesel generator (EDG) automatic voltage regulator (AVR)
deficiencies as functional failures in the maintenance rule program. The
inspectors noted that the voltage regulator deficiencies should have placed the
emergency diesel generators into Maintenance Rule 10 CFR 50.65(a)(1) status
approximately 6 months after the failures occurred. This caused a lapse in the
determination of appropriate system monitoring and goal setting to maintain
system reliability. This issue was entered into the licensee's corrective action
program as Action Request 070300161.This finding was associated with the mitigating systems cornerstone. This issuewas similar to non-minor Example 7.b of Manual Chapter 0612, Appendix E, in
that the finding was more than minor since violations of 10 CFR 50.65(a)(2)
necessarily involve degraded system performance. This finding is not suitable
for evaluation using the Significance Determination Process because the
performance deficiency did not cause the degraded equipment performance.
This is a Category II finding per Inspection Procedure 71111.12, so it was
determined to have very low safety significance (Green) by management
judgement per Manual Chapter 0609, Appendix M. The cause of the finding has
a crosscutting aspect in the area of problem identification and resolutionassociated with the corrective action program (P.1©) because the licensee failed
to thoroughly evaluate the cause and extent of condition of the failed emergency
diesel generator automatic voltage regulator (Section 1R12).*Green. The inspectors identified a Green noncited violation of TechnicalSpecification 5.5.1.1 associated with the failure to implement procedural
guidance to ensure the proper application of a submersible pump to prevent
wetting of the steam supply to the Unit 2 turbine-driven auxiliary feedwater pump.
ENCLOSURE 2-4-If the water level were to wet the steam line insulation, it would causecondensation in the steam line and render the auxiliary feedwater pump
inoperable due to possible water hammer or turbine overspeed on a pump start.
This issue was entered into the licensee's corrective action program as Action
Request 071000309. The finding was more than minor because it was associated with the designcontrol attribute of the mitigating systems cornerstone and impacted the
cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events. Using Manual Chapter 0609,
"Significance Determination Process," Phase 1 worksheet, the finding was
determined to have very low safety significance (Green) because it did not result
in a loss of safety function and did not affect the risk of external initiators. The
finding had a crosscutting aspect in the area of problem identification andresolution associated with the corrective action program (P.1©) in that the
licensee did not thoroughly evaluate the problem such that the resolutions
address causes and extent of conditions (Section 1R15).*Green. A self-revealing Green violation of 10 CFR Part 50, Appendix B,Criterion XVI, was identified for the failure to prevent recurrence of premature
tripping of Square D thermal overloads used for equipment protection on safety-
related equipment. The licensee failed to scope the thermal overloads
associated with the Unit 3 saltwater cooling pump room because they had
previously determined that it had sufficient margin such that it would not be
susceptible to failure. This resulted in the premature tripping of thermal
overloads for the Unit 3 saltwater cooling pump room intake structure fan on
August 8, 2007. This issue was entered into the licensee's corrective action
program as Action Request 070800454.The finding was determined to be more than minor because it was associatedwith the equipment performance attribute of the mitigating systems cornerstone
and it affected the cornerstone objective by challenging the availability and
capability of safety-related components. The inspectors also noted that this a
repetitive problem in implementing corrective actions. Based on the results of
the Significance Determination Process Phase 1 evaluation, the finding was
determined to have very low safety significance because it did not result in an
actual loss of a system safety function, a loss of a single train of safety
equipment for greater than its Technical Specification allowed outage time, and
did not screen as potentially risk significant due to seismic, flooding, or severe
weather initiating events. This finding also had crosscutting aspects in the areaof problem identification and resolution associated with the corrective action
program (P.1©) because the licensee failed to thoroughly evaluate the extent of
condition of insufficient solder material on safety-related thermal overloads
(Section 4OA2).
ENCLOSURE 2-5-Cornerstone: Occupational Radiation Safety*Green. The inspector reviewed a self-revealing noncited violation of TechnicalSpecification 5.5.1.1 when a worker failed to follow radiation work permit
instructions. On July 14, 2007, after completing a pre-job site review, a worker
proceeded to verify work authorization boundaries in Unit 3, Room 209, without
contacting radiation protection for current radiological conditions and discussingthe work scope and locations as required by the radiation work permit. The
worker approached Valve S31902MU012 and received a dose rate alarm. The
maximum dose rate levels in the area were 30 millirem per hour on contact with
the piping system and 12 millirem per hour at 30 centimeters. The licensee's
corrective actions were to coach the worker and to develop and implement a
mechanism to communicate associated boundary walk downs in maintenance
orders.The failure to follow a radiation work permit instruction is a performancedeficiency. This finding is greater than minor because it is associated with one of
the cornerstone attributes (exposure control) and affected the Occupational
Radiation Safety cornerstone objective, in that workers not following their
radiation work permit does not ensure adequate protection of the worker health
and safety from additional personnel exposure. The finding was determined to
be of very low safety significance because it did not involve: (1) as low as is
reasonably achievable planning and controls, (2) an overexposure, (3) a
substantial potential for overexposure, or (4) an impaired ability to assess dose.
Further, this finding had a human performance crosscutting aspect in the workpractices component because the workers did not use human error prevention
techniques, such as self checking, to ensure the full work scope, locations, and
radiological conditions were discussed with radiation protection personnel asrequired by the radiation work permit H4a] (Section 2OS1).B.Licensee-Identified ViolationsViolations of very low safety significance which were identified by the licensee havebeen reviewed by the inspectors. Corrective actions taken or planned by the licensee
have been entered into the licensee's corrective action program. These violations and
their corrective actions are listed in Section 4OA7 of this report.
ENCLOSURE 2-6-REPORT DETAILSSummary of Plant StatusUnit 2 began the inspection period at 99 percent power. On October 20, 2007, Unit 2 wasshutdown to Mode 3 to perform an extent of condition review as a result of Unit 3 main steam
isolation valve, main feedwater isolation valve, and main feedwater block valve solenoid
failures. The surveillance tests for Unit 2 valves that contained the specific solenoids in
question were performed when Unit 2 was in Mode 3. All surveillance tests were completed
satisfactory. Unit 2 was to restart on October 21, 2007, but did not begin restart until
October 25, 2007, due to complications with the Southern California brush fires. Unit 2
returned to power operation on October 26, 2007.On November 26, 2007, Unit 2 was shutdown and cooled down for a planned refueling outage.Unit 2 entered Mode 6 and began core alterations on December 7, 2007. Unit 2 was still in the
refueling outage at the end of the inspection period. Unit 3 began the inspection period at 99.9 percent. On October 9, 2007, the licenseeperformed a shutdown of Unit 3 for a planned mid-cycle outage. Unit 3 was returned to power
operation on November 9, 2007, and ended the inspection period at approximately 99.9 percent
reactor power. 1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R02Evaluations of Changes, Tests, or Experiments (71111.02) a.Inspection ScopeThe inspectors reviewed the effectiveness of the licensee's implementation of changesto the facility structures, systems, and components (SSC); risk-significant normal and
emergency operating procedures; test programs; and the Updated Final Safety Analysis
Report (UFSA) in accordance with 10 CFR 50.59, "Changes, Tests, and Experiments."
The inspectors utilized Inspection Procedure 71111.02, "Evaluation of Changes, Tests,
or Experiments," for this inspection.The inspectors reviewed eight safety evaluations performed by the licensee since thelast NRC inspection of this area at San Onofre Nuclear Generating Station. The
evaluations were reviewed to verify that licensee personnel had appropriately
considered the conditions under which the licensee may make changes to the facility or
procedures or conduct tests or experiments without prior NRC approval. The inspectors
reviewed 33 screenings, in which licensee personnel determined that evaluations were
not required, to ensure that the exclusion of a full evaluation was consistent with the
requirements of 10 CFR 50.59. Evaluations and screenings reviewed are listed in the
attachment to this report.The inspectors reviewed and evaluated a sample of recent licensee action requests todetermine whether the licensee had identified problems related to 10 CFR Part 50.59
ENCLOSURE 2-7-evaluations, entered them into the corrective action program (CAP), and resolvedtechnical concerns and regulatory requirements. The reviewed action requests are
identified in the Attachment.The inspection procedure specifies that the inspectors review a minimum sample ofsix licensee safety evaluations and 12 applicability determinations and screenings
(combined). The inspectors completed a review of eight licensee safety evaluations and
33 screenings. b.FindingsNo findings of significance were identified.1R04Equipment Alignment (71111.04).1Partial System Walkdowns
a.Inspection ScopeThe inspectors: (1) walked down portions of the three listed risk important systems andreviewed plant procedures and documents to verify that critical portions of the selected
systems were correctly aligned; and (2) compared deficiencies identified during the walk
down to the licensee's UFSAR and CAP to ensure problems were being identified and
corrected. *October 18, 2007, Unit 3, Shutdown Cooling Train B prior to mid-loop operations
- October 29, 2007, Unit 3, Train B containment spray pump (P013) used asbackup to shutdown cooling*December 18, 2007, Unit 2, electrical alignment to safety Bus 2A06 while 2A04is out of serviceDocuments reviewed by the inspectors are listed in the attachment.
The inspectors completed three samples. b.FindingsNo findings of significance were identified..2Complete System Walkdown a.Inspection ScopeThe inspectors: (1) reviewed plant procedures, drawings, the UFSAR, Technical Specifications (TS), and vendor manuals to determine the correct alignment of the
Unit 2 auxiliary feedwater system; (2) reviewed outstanding design issues, operator
workarounds, and UFSAR documents to determine if open issues affected the
ENCLOSURE 2-8-functionality of the Unit 2 auxiliary feedwater
system; and (3) verified that the licenseewas identifying and resolving equipment alignment problems. Documents reviewed bythe inspectors are listed in the attachment.The inspectors completed one sample. b.FindingsNo findings of significance were identified.1R05Fire Protection (71111.05) a. Inspection ScopeQuarterly InspectionThe inspectors walked down the six listed plant areas to assess the material condition ofactive and passive fire protection features and their operational lineup and readiness.
The inspectors: (1) verified that transient combustibles and hot work activities were
controlled in accordance with plant procedures; (2) observed the condition of fire
detection devices to verify they remained functional; (3) observed fire suppression
systems to verify they remained functional and that access to manual actuators was
unobstructed; (4) verified that fire extinguishers and hose stations were provided at their
designated locations and that they were in a satisfactory condition; (5) verified that
passive fire protection features (electrical raceway barriers, fire doors, fire dampers,
steel fire proofing, penetration seals, and oil collection systems) were in a satisfactory
material condition; (6) verified that adequate compensatory measures were established
for degraded or inoperable fire protection features and that the compensatory measures
were commensurate with the significance of the deficiency; and (7) reviewed the UFSAR
to determine if the licensee identified and corrected fire protection problems. October 2, 2007, Unit 2, emergency diesel Generator (EDG) 2G002 roomOctober 2, 2007, Unit 2, EDG 2G003 roomOctober 2, 2007, Unit 3, EDG 3G002 roomOctober 2, 2007, Unit 3, EDG 3G003 room*November 14, 2007, Unit 2, emergency core cooling system pump Room 002
- December 5, 2007, Unit 2, containment
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples.
ENCLOSURE 2-9- b.FindingsNo findings of significance were identified.1R07Heat Sink Performance (71111.07A) a.Inspection ScopeThe inspectors reviewed licensee programs, verified performance against industrystandards and reviewed critical operating parameters and maintenance records for the
Unit 3 Train B component cooling water heat Exchanger S31203ME002. The inspectors
verified that: (1) performance tests were satisfactorily conducted for heat
exchangers/heat sinks and reviewed for problems or errors; (2) the licensee utilized the
periodic maintenance method outlined in Electric Power Research Institute (EPRI)
NP- 7552, "Heat Exchanger Performance Monitoring Guidelines;" (3) the licensee
properly utilized biofouling controls; (4) the licensee's heat exchanger inspections
adequately assessed the state of cleanliness of their tubes, and (5) the heat exchanger
was correctly categorized under the Maintenance Rule. Documents reviewed by the
inspectors are listed in the attachment.The inspectors completed one sample. b.FindingsNo findings of significance were identified.1R08Inservice Inspection Activities (71111.08) .1Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized WaterReactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control a.Inspection ScopeThe inspection procedure requires review of two or three types of nondestructiveexamination (NDE) activities and, if performed, one to three welds on the reactor coolant
system (RCS) pressure boundary. The inspectors directly observed the following nondestructive examinations:SystemComponent/Weld IDExam TypeRCSSurge Nozzle to Safe End Weld, 02-005-031PT/UTRCSShutdown Cooling Piping 10" SCH 140Pipe-Valve, 02-059-008PT/UTRCSShutdown Cooling Piping 16" SCH 160Pipe-Elbow, 02-059-002PT/UT
ENCLOSURE 2-10-RCSShutdown Cooling piping 16" SCH 160Pipe-Valve, 02-059-001PT/UTRCSSnubber, 02-052-110VT3The inspectors reviewed the following NDEs through record review:SystemComponent/Weld IDExam TypeRCSY-Stop Valve, 02-021-068VT3RCSY-Stop Valve, 02-021-081VT3
RCSGuide & Y-Stop Valve, 02-039-058VT3
FeedwaterGuide & Y-Stop Valve, 02-045-037VT3
RCS10" SCH 140 Reducer Tee-Pipe, 02-021-038UTThe inspectors observed the initial Ultrasonic Examination System calibration for thePanametrics Epoch 4 instrument, S/N 040229207, which was recorded on Ultrasonic
Instrument Calibration Data Record and Certification. The inspectors reviewed Table 1
in Electric Power Research Institute's PDI Protocol PDI-UT-2, Revision 20, dated 25
APR 07, to verify that the transducers to be used for ultrasonic examinations on
stainless steel piping were appropriately qualified. The inspectors reviewed the NDE personnel qualification records for those contractorpersonnel (Lambert MacGill Thomas, Inc. or LMT) performing ASME Code Section XI
inservice inspections. The LMT personnel had been appropriately certified using LMT's
procedure QA-46, "Qualification and Certification of NDE and Visual Examination
Personnel per ASME Section XI," Revision 0. The inspectors verified that the
requirements in QA-46 were consistent with ASNT CP-189-1995, "ASNT Standard for
Qualification and Certification of Nondestructive Testing Personnel," 1995 Edition. The inspection procedure further required verification of one to three welds on Class 1or 2 pressure boundary piping to ensure that the welding process and welding
examinations were performed in accordance with the ASME code. The inspectors
observed portions of the preemptive structural weld overlay on the ASME code Class 1
pressurizer surge line nozzle-to-safe end dissimilar weld and pipe-to-safe end stainless
steel weld identified as follows:SystemComponent/Weld IdentificationPressurizer SurgeLine Nozzle-to-Safe
End-to-PipeWeld DMW 02-0005-031and Weld 02-016-001 GasTungsten Arc Welding (machine)Welding procedures and NDE of the welding repair conformed to ASME coderequirements and licensee commitments.
ENCLOSURE 2-11-Welder qualification documentation packages and welder maintenance logs werereviewed for all contract welders (Welding Services, Inc.) performing welding activities
on the pressurizer surge nozzle. The documentation packages and logs were in
accordance with Article III, QW-300 "Welding Performance Qualification" in Section IXof the ASME code. Welding Procedure Specifications WPS 08-08-T-001-Butter SS, Revision 0, andWPS 03-08-T-804-Bottom, Revision 0, were the welding procedures observed being
used during the weld overlay process on the pressurizer surge nozzle. The inspectors
reviewed the welding procedure specifications and their corresponding procedure
qualification records (identified in the Attachment) to verify that ASME Code required
essential variables for the gas tungsten arc welding process had been identified,
recorded in the procedure qualification record, and formed the basis for qualification of
the welding procedure specifications. Additionally, the inspectors reviewed manual gas tungsten arc welding and shieldedmetal arc welding performed on an ASME Code Class 3 component cooling water
by-pass line around the letdown heat exchanger. This welding consisted of carbon steel
pipe-to-pipe and pipe-to-fitting (4" and 8") welding using ER70S-6 and E7018 welding
filler material. The reviewed welds are identified as Weld Records WR2-07-212,
WR2-07-213, and WR2-07-210. The inspectors verified, by review, that the Welding Procedure Specification (1-GT-SM) had been properly qualified in accordance with the requirements of Section IX of the
ASME code. The inspectors verified that the essential variables for both the shielded
metal arc welding and the gas tungsten arc welding processes had been identified,
recorded in the procedure qualification record, and formed the bases for qualification of
the welding procedure specification. The inspectors also observed the liquid penetrant examinations performed on the buffer(stainless steel) layer and the transition bead (between the buffer layer and the dilution
layer). The buffer layer represents the initial stainless steel layer of the weld overlay
that started at a point on the stainless steel pipe and covered the pipe, pipe-to-safe endweld, safe end, and ending as close as practical to the dissimilar metal weld fusion line,
without contacting the dissimilar metal weld. These examinations were recorded on
Liquid Penetrant Nondestructive Examination Report 104532-PT-001. The examination
personnel qualification records for the examiner performing the examination were
reviewed to verify that the individual was properly certified. Further, the inspectors
reviewed the liquid penetrant procedure (WSI QAP 9.21, Revision 1) to verify that it was
properly qualified in accordance with ASME code Section V requirements. Additionally,
the inspectors reviewed the Ultrasonic Examination Report of the ultrasonic examination
performed on December 10, 2007, of the weld overlay which was at a nominal thickness
of 0.30 inches at the examination time.
ENCLOSURE 2-12-The inspectors also verified by observation that welding filler materials were properlystored and controlled in accordance with Procedure SO 123-I-11.1. Welding Filler
Material Control Records, used to document issuance and return of welding filler
materials, were reviewed for those materials issued on December 13, 2007, to verify
that specified administrative controls regarding welders, materials (quantity and time
limits), and use of portable ovens or caddys were being implemented. The inspection procedure required inspection of any augmented or industry initiationexaminations. The inspectors determined that the licensee had not performed such
examinations. Consequently, the inspectors did not perform any activities in this area. b.FindingsNo findings of significance were identified..2Vessel Upper Head Penetration (VUHP) Inspection Activities a.Inspection ScopeThe licensee performed NDEs of 100 percent of reactor VUHP. The inspector directlyobserved a sample of the examinations performed on the control element drive
mechanism element (CEDM) and incore instrumentation (ICI) as listed below:
SystemComponent/Weld IdentificationExamination MethodRCSCEDM 87UT/ETRCSCEDM 88UT/ET
RCSCEDM 79UT/ET
RCSCEDM 68UT/ET
RCSCEDM 60UT/ET
RCSCEDM 28UT/ET
RCSCEDM 78UT/ET
RCSCEDM 86UT/ET
RCSICI 96UT/ET
RCSICI 95UT/ET
RCSICI 94UT/ET
RCSICI 93UT/ET
RCSRVUH vent lineUT/ET
ENCLOSURE 2-13-The NDEs were performed in accordance with the requirements of NRC OrderEA-03-009. b.FindingsNo findings of significance were identified..3Boric Acid Corrosion Control Inspection (BACC) Activities a.Inspection ScopeResident inspectors observed a sample of BACC activities and verified that visualinspections emphasized locations where boric acid leaks can cause degradation of
safety significant components.The inspector reviewed five instances where boric acid deposits were found on reactorcoolant system piping components during the walkdown. The inspectors reviewed
licensee procedures governing the boric acid corrosion control program and inspector
qualifications, reviewed the extent of boric acid residue on the various components,
verified that the licensee inspectors who performed the walkdown were qualified, and
determined whether components that exhibited leakage during the current outage had
experienced leakage in the past. The following table lists the specific components
reviewed by the inspector, including the component numbers, brief component
descriptions, and the resulting Action Requests.Component NumberDescriptionAction Request2HV0512Pressurizer surge line sampleisolation valve
0705002612HV9203Charging line insolation valve0711011722HV9201Charging auxiliary sprayisolation valve
0711011732HV9339Shutdown cooling isolationvalve 0705002622HV9326Shutdown injection tank drainvalve 070500265No boric acid leakage evaluations were performed for any of the instances where leakswere identified during walkdowns.The condition of the components was appropriately entered into the licensee's CAP andcorrective actions taken were consistent with ASME code requirements. No engineering
evaluations were required for any of the instances where leaks were identified during
walkdowns.
ENCLOSURE 2-14- b.Findings
No findings of significance were identified..4Steam Generator Tube Inspection Activities a.Inspection ScopeThe inspection procedure specified performance of an assessment of in-situ screeningcriteria to assure consistency between assumed NDE flaw sizing accuracy and data
from the EPRI examination technique specification sheets. It further specified
assessment of appropriateness of tubes selected for in situ pressure testing,
observation of in situ pressure testing, and review of in situ pressure test results.At the time of this inspection, no conditions had been identified that warranted in situpressure testing. The inspectors did, however, review the licensee's report for Units 2
and 3, "Steam Generator Degradation Assessment for the Cycle 15 Refueling Outages
in 2007 and 2008," dated November 29, 2007, and compared the in situ test screening
parameters to the guidelines contained in the EPRI document "In Situ Pressure Test
Guidelines", Revision 2, and the Combustion Engineering Owners Group screening
criteria. This review determined that the remaining screening parameters were
consistent with the EPRI and Combustion Engineering Owners Group guidelines. In addition, the inspectors reviewed both the licensee site-validated and qualifiedacquisition and analysis technique sheets used during this refueling outage and the
qualifying EPRI examination technique specification sheets to verify that the essential
variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had
been identified and qualified through demonstration. The inspector reviewed acquisition
technique and analysis technique sheets are identified in the attachment.The inspection procedure specified comparing the estimated size and number of tubeflaws detected during the current outage against the previous outage operational
assessment predictions to assess the licensee's prediction capability. The inspectors
compared the previous outage operational assessment predictions contained in
Report R-3671-00-1, "Tube Degradation Predictions for the San Onofre Nuclear
Generating Station Unit 2 Steam Generators - 2006 Update," with the flaws identified
thus far during the current steam generator tube inspection effort. Compared to the
projected damage mechanisms identified by the licensee, the number of identified
indications fell within the range of prediction and were quite consistent with predictions.
No new damage mechanisms had been identified during this inspection. The inspection procedure specified confirmation that the steam generator tube eddycurrent test scope and expansion criteria meet TS requirements, EPRI guidelines, and
commitments made to the NRC. The inspectors evaluated the recommended steam
generator tube eddy current test scope established by TS requirements and the
licensee's degradation assessment report. The inspectors compared the recommended
test scope to the actual test scope and found that the licensee had accounted for all
known flaws and had, as a minimum, established a test scope that met TS
ENCLOSURE 2-15-requirements, EPRI guidelines, and commitments made to the NRC. The scope of thelicensee's eddy current examinations of tubes in both steam generators included: *Bobbin examination full length of tubing (tube end hot-tube end cold) from bothhot and cold legs, in non-sleeved tubes, rows 4-147*Bobbin examination of the unsleeved portion of tubing (sleeve top hot-tube endcold) from the cold leg, in sleeved tubes, rows 4-147*Bobbin examination of the straight length section of tubing from both hot andcold legs, rows 1-3*Rotating plug point coil examination of hot leg Tubsheet TSH +4", -13",100 percent of all tubes*Rotating plug point coil examination of cold leg tubesheet, TSC +2", -13",100 percent of all tubes. Exception: Steam Generator 89 tubes R141-C63,
R140-C64, R139-C63, and surrounding tubes in 2-tube bounding pattern,
examination extent is TSC +4", -13".*Rotating plug point coil examination of the sleeves (sleeve bottom hot-sleeve tophot), 100 percent of sleeved tubes*Rotating plug point coil examination of SBF 0.00", -1.25" in Steam Generator 88,Tube R28-C60 only *Rotating plug point coil examination of U-bend section of tubing (07H-07C) withmid/high frequency coil probe, 100 percent of tubes in rows 1-3 *Rotating plug point coil examination of U-bend section of tubing (07H-07C) withmid-frequency coil probe, 20 percent sample of tubes in rows 4-10 (rows 5-10
sample drawn from tubes not examined with MRPC probe in the 2006
inspection)*Rotating plug point coil examination of the following bobbin indications: ADR,DNI, DEI,DSI, DTI, LPI, PLP, NQI, TWD (0-100 percent), DNT >= 2.0 volts, DNG
>= 4.0 volts, TSD, TSM, PDP, and CUD*Rotating plug point coil examination of PLP indications (with LAR confirmation) ina 2-tube bounding pattern, location +/- 1-inch of PLP edges*Rotating plug point coil examination of all sections of tubing which cannot beexamined with the 600UL bobbin probe due to restrictionThe inspection procedure specified, if new degradation mechanisms were identified,verify that the licensee fully enveloped the problem in its analysis of extended conditions
including operating concerns and had taken appropriate corrective actions before plant
startup. To date, the eddy current test results had not identified any new degradation
mechanisms.
ENCLOSURE 2-16-The inspection procedure requires confirmation that the licensee inspected all areas ofpotential degradation, especially areas that were known to represent potential eddy
current test challenges (e.g., top-of-tubesheet, tube support plates, and U-bends). The
inspectors confirmed that all known areas of potential degradation were included in the
scope of inspection and were being inspected. The inspection procedure further requires verification that repair processes being usedwere approved in the TSs. The total number of tubes plugged was 133 tubes in Steam
Generator 88 and 125 tubes in Steam Generator 89. The inspectors verified that the
mechanical expansion plugging process to be used was an NRC-approved repair
process. The inspection procedure also requires confirmation of adherence to the TS plugginglimit, unless alternate repair criteria have been approved. The inspection procedure
further requires determination whether depth sizing repair criteria were being applied for
indications other than wear or axial primary water stress corrosion cracking in dented
tube support plate intersections. The inspectors determined that the TS plugging limits
were being adhered to (i.e., 40 percent maximum through-wall indication). If steam generator leakage greater than three gallons per day was identified duringoperations or during post shutdown visual inspections of the tubesheet face, the
inspection procedure requires verification that the licensee had identified a reasonable
cause based on inspection results and that corrective actions were taken or planned to
address the cause for the leakage. The inspectors did not conduct any assessment
because this condition did not exist.The inspection procedure requires confirmation that the eddy current test probes andequipment were qualified for the expected types of tube degradation and an assessment
of the site-specific qualification of one or more techniques. The inspectors observed
portions of eddy current tests performed on the tubes in Steam Generators 88 and 89.
During these examinations, the inspectors verified that: (1) the probes appropriate for
identifying the expected types of indications were being used, (2) probe position location
verification was performed, (3) calibration requirements were adhered, and (4) probe
travel speed was in accordance with procedural requirements. The inspectors
performed a review of site-specific qualifications of the techniques being used. These
are identified in the attachment.If loose parts or foreign material on the secondary side were identified, the inspectionprocedure specified confirmation that the licensee had taken or planned appropriate
repairs of affected steam generator tubes and that they inspected the secondary side to
either remove the accessible foreign objects or perform an evaluation of the potential
effects of inaccessible object migration and tube fretting damage. At this time of the
inspection, no foreign material had been identified.Finally, the inspection procedure specified review of one to five samples of eddy currenttest data if questions arose regarding the adequacy of eddy current test data analyses.
The inspectors did not identify any results where eddy current test data analyses
adequacy was questionable.
ENCLOSURE 2-17- b.FindingsNo findings of significance were identified..5Identification and Resolution of Problems a.Inspection ScopeThe inspection procedure requires review of a sample of problems associated withinservice inspections documented by the licensee in the corrective action program for
appropriateness of the corrective actions.The inspector reviewed corrective action reports which dealt with inservice inspectionactivities and found the corrective actions were appropriate. Action requests reviewed
are listed in the documents reviewed section. From this review the inspectors
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. b.FindingsNo findings of significance were identified. The inspectors completed one sample bycompleting all required inspection activities.1R11Licensed Operator Requalification (71111.11).1Quarterly Inspection a.Inspection ScopeThe inspectors observed testing and training of senior reactor operators and reactoroperators to identify deficiencies and discrepancies in the training, to assess operator
performance, and to assess the evaluator's critique. The training scenario on
October 22, 2007, involved just-in-time training for Unit 2 startup. Documents reviewed
by the inspectors are listed in the attachment.The inspectors completed one sample. b.FindingsNo findings of significance were identified..2Annual Inspection a.Inspection ScopeThe inspectors reviewed the annual operating examination test results for 2007. Sincethis was the first half of the biennial requalification cycle, the licensee was not required
ENCLOSURE 2-18-to administer a written examination. These results were assessed to determine if theywere consistent with NUREG 1021, "Operator Licensing Examination Standards for
Power Reactors," guidance and Manual Chapter 0609, Appendix I, "Operator
Requalification Human Performance Significance Determination Process,"
requirements. This review included the test results for a total of 15 crews composed of
87 licensed operators, which included: shift-standing senior operators, staff senior
operators, shift-standing reactor operators, and staff reactor operators. There were no
crew failures and no individual failures on the simulator scenario portion of the test.
There was one individual failure on the job performance measure portion of the test.
This individual was successfully remediated prior to returning to shift.The inspector completed one sample. b.FindingsNo findings of significance were identified.1R12Maintenance Effectiveness (71111.12) a.Inspection ScopeThe inspectors reviewed the listed maintenance activity to: (1) verify the appropriatehandling of SSC performance or condition problems; (2) verify the appropriate handling
of degraded SSC functional performance; (3) evaluate the role of work practices and
common cause problems; and (4) evaluate the handling of SSC issues reviewed under
the requirements of the maintenance rule, 10 CFR Part 50 Appendix B, and the TSs.*October 1, 2007, Units 2 and 3, upgraded EDG automatic voltage regulators
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample. b.FindingsIntroduction. The inspectors identified a Green NCV of 10 CFR 50.65(a)(2) for thefailure to include Units 2 and 3 EDG automatic voltage regulator (AVR) deficiencies as
functional failures in the maintenance rule program. The inspectors noted that the
voltage regulator deficiencies should have placed the EDGs into maintenance rule
10 CFR 50.65(a)(1) status approximately six months after the failures occurred. This
caused a lapse in the determination of appropriate system monitoring and goal setting to
maintain system reliability.Description. On March 3, 2007, the licensee identified that an AVR for the Unit 3 EDGwas oscillating excessively during a load test. The cause of the oscillation was poor
contact of the R3 potentiometer because of the open type housing of the potentiometers
which made them susceptible to dirt intrusion.
ENCLOSURE 2-19-The licensee's analysis of the failed AVR concluded that the R3 potentiometer poorcontact caused the AVR to oscillate the EDG output voltage setting between zero and
3.8 megavolt ampere reactive (MVAR). Operations personnel subsequently declared
the EDG inoperable. All of the susceptible potentiometers on all eight EDGs were
subsequently upgraded to sealed multiturn gold plated potentiometers. The upgraded
installations were completed on August 26, 2007.The inspectors discovered that the licensee had not evaluated the AVR deficiency intheir maintenance rule program for monitoring or goal setting. The inspectors
determined that the AVR failure impacted the reliability of the EDGs in accordance with
NUMARC 93-01, "Nuclear Energy Institute Industry Guideline for Monitoring the
Effectiveness of Maintenance of Nuclear Power Plants," Revision 2. The inspectors
concluded that the AVR failure if correctly counted as a MPFF, would have caused the
EDG to exceed the performance criteria and should have been tracked for monitoring
and goal setting in the licensee's maintenance rule program. In response to this finding,
the licensee subsequently placed the EDGs in 10 CFR 50.65(a)(1), and established an
EDG performance goal such that both Unit 2 and 3 EDG AVRs be successfully
surveillance tested four times each, with normal voltage and MVAR control, by the end
of the fourth quarter of 2007. Each EDG contains an AVRs A and B, therefore four
diesels each containing two AVRs would need to be surveillance tested four times to
successfully complete the goal.Analysis. The failure to recognize the applicability of the maintenance rule for a failureof the EDG AVR was a performance deficiency. This finding was associated with the
mitigating systems cornerstone. This issue was similar to non-minor Example 7.b of
Manual Chapter 0612, Appendix E, in that the finding was more than minor since
violations of 10 CFR 50.65(a)(2) necessarily involve degraded system performance.
This finding is not suitable for evaluation using the Significance Determination Process
because the performance deficiency did not cause the degraded equipment
performance. This is a Category II finding per Inspection Procedure 71111.12, so it was
determined to have very low safety significance (Green) by management judgement per
Manual Chapter 0609, Appendix M. The cause of the finding has a crosscutting aspect
in the area of problem identification and resolution associated with the CAP (P.1(c))
because the licensee failed to thoroughly evaluate the cause and extent of condition of
the failed EDG AVR.Enforcement. 10 CFR Part 50.65(a)(1) requires, in part, that holders of an operatinglicense shall monitor the performance or condition of SSCs within the scope of the rule
against licensee-established goals in a manner sufficient to provide reasonable
assurance that such SSCs are capable of fulfilling their intended safety functions.
10 CFR 50.65(a)(2) requires, in part, that monitoring specified in paragraph (a)(1) is not
required where it has been demonstrated the performance or condition of an SSC is
being effectively controlled through appropriate preventive maintenance, such that the
SSC remains capable of performing its intended function. Contrary to the above, from
March through September, 2007, the licensee failed to demonstrate the performance of
the EDGs was being effectively controlled through appropriate preventive maintenance
and did not establish goals to provide a reasonable assurance that the Units 2 and 3
EDGs were capable of fulfilling their intended function. Because the finding is of very
low safety significance and has been entered into the licensee's CAP as AR 070300161,
ENCLOSURE 2-20-this violation is being treated as an NCV consistent with Section VI.A of the EnforcementPolicy: NCV 05000361;05000362/2007005-01, "Failure to Properly Implement
Maintenance Rule Requirements for Emergency Diesel Generators."1R13Maintenance Risk Assessments and Emergent Work Control (71111.13).1Risk Assessment and Management of Risk a.Inspection ScopeThe inspectors reviewed the four below listed assessment activities to verify: (1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and
licensee procedures prior to changes in plant configuration for maintenance activities
and plant operations; (2) the accuracy, adequacy, and completeness of the information
considered in the risk assessment; (3) that the licensee recognizes, and/or enters as
applicable, the appropriate licensee-established risk category according to the risk
assessment results and licensee procedures; and (4) the licensee identified and
corrected problems related to maintenance risk assessments.*October 4, 2007, Unit 3, risk assessment and management during an unplannedemergency core cooling system TS 3.0.3 entry*October 25, 2007, Unit 2, risk assessment and management during a startupafter unplanned shutdown and southern California fires*October 12, 2007, Unit 3, risk assessment and management during a mainsteam isolation valve dual indication*November 30, 2007, Unit 2, risk assessment and management during theDevers offsite power out of service - delayed midloop operationsDocuments reviewed by the inspectors are listed in the attachment.
The inspectors completed four samples. b.FindingsNo findings of significance were identified.1R15Operability Evaluations (71111.15) a.Inspection ScopeThe inspectors: (1) reviewed plants status documents such as operator shift logs,emergent work documentation, deferred modifications, and standing orders to
determine if an operability evaluation was warranted for degraded components;
(2) referred to the UFSAR and design basis documents to review the technical
adequacy of licensee operability evaluations; (3) evaluated compensatory measures
associated with operability evaluations; (4) determined degraded component impact on
ENCLOSURE 2-21-any TSs; (5) used the Significance Determination Process to evaluate the risksignificance of degraded or inoperable equipment; and (6) verified that the licensee has
identified and implemented appropriate corrective actions associated with degraded
components.*October 3, 2007, Units 2 and 3, incorrect calibration probe used for saltwatercooling flow indicators*October 4, 2007, Unit 2 turbine-driven auxiliary feedwater pump failed trencheductor*October 9, 2007, Unit 3, grounded pressurizer heater
- October 25, 2007, Unit 2 and 3, main feedwater isolation Valve 2HV4048 andmain steam isolation Valve 2HV8204 solenoid failed in-service testingDocuments reviewed by the inspectors are listed in the attachment.The inspectors completed four samples.
b.FindingsIntroduction. The inspectors identified a Green NCV of TS 5.5.1.1 associated with thefailure to implement procedural guidance to ensure the proper application of a
submersible pump to prevent wetting of the steam supply to the Unit 2 turbine-driven
auxiliary feedwater pump. If the water level were to wet the steam line insulation, it
would cause condensation in the steam line and render the auxiliary feedwater pump
inoperable due to possible water hammer or turbine overspeed on a pump start.Description. On October 4, 2007, during a plant walk-down, the inspectors noted that asubmersible pump was in use in a pipe trench in the Unit 2 auxiliary feedwater (AFW)
pump building while steam was discharging into the bottom of the pipe trench. The
pump was a temporary modification installed due to a failure of a permanently installed
eductor. The purpose of the eductor was to ensure water did not accumulate in the
trench such that it could contact the steam piping. If the water level were to wet the
steam line insulation, it would cause condensation in the steam line and render the
turbine-driven AFW pump inoperable due to the possibility of water hammer or
overspeed on turbine start.The inspectors noted that the atmosphere in the top of the pipe trench felt very hot tothe touch. The inspectors then reviewed the vendor manual for the submersible pump
and hose and found that both had a maximum temperature rating of 140F. Theinspectors concluded that water in the pipe trench could easily exceed the maximum
temperature rating for the submersible pump and hose rated of 140F. Since thistemperature would exceed the rating of the pump and hose, the submersible pump
modification could not be relied upon to drain the trench. This could potentially render
the turbine driven AFW pump inoperable.
ENCLOSURE 2-22-The inspectors interviewed the licensee's staff and found that the submersible pumpand discharge hose had been installed per Procedure S023-2-16, "Use of Temporary
Sump Pumps," Revision 20. The inspectors noted this procedure did not direct
consideration of the environment in which the pump would be used or the potential
consequences of failure of the pump, as would have been required by
Procedure S0123-XV-5.1, "Temporary Modifications Control," Revision 8. Since the
failure of the submersible pump had the potential consequence of rendering safety-
related equipment inoperable, the inspectors concluded the procedure used to install the
modification was inadequate.Corrective actions taken by the licensee included revising the "Use of Temporary Sump"procedure to reflect the guidance found in the "Temporary Modifications Control"
procedure for consideration of the environmental effects on the submersible pump.
Additionally, the licensee revised Procedure OSM-5, "Operator Rounds," Revision 7, and
replaced the submersible pump with one that was adequately temperature rated for the
environment in the AFW trench.Analysis. The failure to have an adequate procedure resulting in an inadequatemodification with the potential to affect safety-related equipment was a performance
deficiency. The finding was more than minor because it was associated with the design
control attribute of the mitigating systems cornerstone and impacted the cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events. Using Manual Chapter 0609, "Significance Determination Process,"
Phase 1 worksheet, the finding was determined to have very low safety significance
(Green) because it did not result in a loss of safety function and did not affect the risk of
external initiators. The finding had a crosscutting aspect in the area of problemidentification and resolution associated with the CAP (P.1(c)) in that the licensee did not
thoroughly evaluate the problem such that such that the resolutions address causes and
extent of conditions. Enforcement. TS 5.5.1.1 requires that written procedures be established, implemented,and maintained for activities specified in Appendix A, "Typical Procedures for
Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide 1.33,
"Quality Assurance Program Requirements (Operations), dated February 1978.
Regulatory Guide 1.33, Appendix A, Section 9.e recommends general procedures for
the control of maintenance and modification work. Contrary to this requirement, on
May 11, 2007, the licensee failed to implement appropriate procedures to control
modification work in the Unit 2 auxiliary feedwater steam supply trench to ensure the
trench would not fill up with water and render the Unit 2 turbine driven auxiliary
feedwater pump inoperable. Because this violation is of very low safety significance and
has been entered into the licensee's CAP as AR 071000309, it is being treated as an
NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000362/2007005-02, "Failure to Implement Procedural Requirements for
Modifications in the Auxiliary Feedwater Steam Supply Trench."
ENCLOSURE 2-23-1R17Permanent Plant Modifications (71111.17B) a.Inspection ScopeThe inspectors reviewed seven permanent plant modification packages and associateddocumentation, such as implementation reviews, safety evaluation applicability
determinations, and screenings, to verify that they were performed in accordance with
regulatory requirements and plant procedures. The inspectors also reviewed the
procedures governing plant modifications to evaluate the effectiveness of the program
for implementing modifications to risk-significant SSCs, such that these changes did not
adversely affect the design and licensing basis of the facility. Procedures and permanent plant modifications reviewed are listed in the attachment to this report. Further, the inspectors interviewed the cognizant design and system
engineers for the identified modifications as to their understanding of the modification
packages and process. The inspectors evaluated the effectiveness of the licensee's corrective action process toidentify and correct problems concerning the performance of permanent plant
modifications by reviewing a sample of related condition reports. The reviewed
condition reports are identified in the attachment.The inspection procedure specifies inspectors review a required minimum sample of sixpermanent plant modifications. The inspectors completed review of seven permanent
plant modifications. b. FindingsNo findings of significance were identified.1R19Postmaintenance Testing (71111.19) a.Inspection ScopeThe inspectors selected the six listed postmaintenance test activities of risk significantsystems or components. For each item, the inspectors: (1) reviewed the applicable
licensing basis and/or design-basis documents to determine the safety functions;
(2) evaluated the safety functions that may have been affected by the maintenance
activity; and (3) reviewed the test procedure to ensure it adequately tested the safety
function that may have been affected. The inspectors either witnessed or reviewed test
data to verify that acceptance criteria were met, plant impacts were evaluated, test
equipment was calibrated, procedures were followed, jumpers were properly controlled,
the test data results were complete and accurate, the test equipment was removed, the
system was properly re-aligned, and deficiencies during testing were documented. The
inspectors also reviewed the UFSAR to determine if the licensee identified and
corrected problems related to post maintenance testing. *October 25, 2007, Unit 2, main steam isolation Valve 2HV8204, Train A & B, failsafe closure postmaintenance test
ENCLOSURE 2-24-*October 25, 2007, Unit 2, Main Feedwater Isolation Valve, 2HV-4048, stroke andfail safe closure postmaintenance test*October 29, 2007, Unit 3, Pressurizer Surge Line Nozzle Field Weld OVL-031,post weld overlay liquid penetrant postmaintenance test*October 31, 2007, Unit 3, reactor coolant gas vent system postmaintenance test
- November 3, 2007, Unit 3 reactor coolant gas vent system postmaintenance testfollowing corrective maintenance *November 8, 2007, Unit 3, saltwater cooling Pump 3P112 postmaintenance test
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples. b.FindingsNo findings of significance were identified.1R20Refueling and Other Outage Activities (71111.20) a.Inspection ScopeThe inspectors reviewed the following risk significant refueling items or outage activitiesto verify defense in depth commensurate with the outage risk control plan, compliance
with the TSs, and adherence to commitments in response to Generic Letter 88-17, "Loss
of Decay Heat Removal:" (1) the risk control plan; (2) tagging/clearance activities;
(3) reactor coolant system instrumentation; (4) electrical power; (5) decay heat removal;
(6) spent fuel pool cooling; (7) inventory control; (8) reactivity control; (9) containment
closure; (10) reduced inventory or midloop conditions; (11) refueling activities;
(12) heatup and coldown activities; (13) restart activities; and (14) licensee identification
and implementation of appropriate corrective actions associated with refueling and
outage activities. The inspectors' containment inspections included observations of the
containment sump for damage and debris; and observation of supports, braces, and
snubbers for evidence of excessive stress, water hammer, or aging. Documents
reviewed by the inspectors are listed in the attachment. The inspectors reviewed outage
activities for Unit 3 from October 9, 2007 to November 9, 2007. The inspectors also
reviewed outage activities for Unit 2 from November 26, 2007, until the end of the
inspection period. The inspectors completed two samples. b.FindingsNo findings of significance were identified.
ENCLOSURE 2-25-1R22Surveillance Testing (71111.22) a.Inspection ScopeThe inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure thatthe four listed surveillance activities demonstrated that the SSCs tested were capable of
performing their intended safety functions. The inspectors either witnessed or reviewed
test data to verify that the following significant surveillance test attributes were
adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;
(3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead
controls; (7) test data; (8) testing frequency and method demonstrated TS operability;
(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of ASME
Code requirements; (12) updating of performance indicator data; (13) engineering
evaluations, root causes, and bases for returning tested SSCs not meeting the test
acceptance criteria were correct; (14) reference setting data; and (15) annunciators and
alarms setpoints. The inspectors also verified that the licensee identified and
implemented any needed corrective actions associated with the surveillance testing. *August 1, 2007, Unit 2, 2HV-9900 normal chilled water to containment isolationValve 2HV-9900 stroke test*October 4, 2007, Unit 3, Train A saltwater cooling outlet Valve 3HV6497 partialmanual stroke test*October 18, 2007, Unit 2, high pressure safety injection Pump 2MP018 responsetime testing*October 18, 2007, Unit 2, component cooling water Pump 2MP024 inservice test
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed four samples. b.FindingsNo findings of significance were identified.1R23Temporary Plant Modifications (71111.23) a.Inspection ScopeThe inspectors reviewed the UFSAR, plant drawings, procedure requirements, and TSsto ensure that the below listed temporary modification was properly implemented. The
inspectors: (1) verified that the modifications did not have an affect on system
operability/availability; (2) verified that the installation was consistent with modification
documents; (3) ensured that the post-installation test results were satisfactory and that
the impact of the temporary modifications on permanently installed SSCs were
supported by the test; and (4) verified that appropriate safety evaluations were
ENCLOSURE 2-26-completed. The inspectors verified that licensee identified and implemented any neededcorrective actions associated with temporary modifications. *October 9, 2007, Unit 3, swap grounded pressurizer Heater ME616 withHeater E614
Documents reviewed by the inspectors are listed in the attachment.The inspectors completed one sample. b.FindingsNo findings of significance was identified.
Cornerstone: Emergency Preparedness1EP6Drill Evaluation (71114.06) a.Inspection ScopeFor the listed drill and simulator-based training evolutions contributing to Drill/ExercisePerformance and Emergency Response Organization Performance Indicators, the
inspectors: (1) observed the training evolution to identify any weaknesses and
deficiencies in classification, notification, and Protective Action Recommendation
development activities; (2) compared the identified weaknesses and deficiencies against
licensee identified findings to determine whether the licensee is properly identifying
failures; and (3) determined whether licensee performance is in accordance with the
guidance of the NEI 99-02, "Voluntary Submission of Performance Indicator Data,"
acceptance criteria. *October 3, 2007, Units 2 and 3 simulator, control room, technical support center,operations support center, and emergency operations facility, Unit 3 diesel
Generator 3G003 fuel oil day tank fire, Unit 2 steam generator tube leak and
subsequent tube rupture with potential unfiltered radioactive release pathway
through the steam driven auxiliary feed Pump P-140 turbine exhaustDocuments reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample. b.FindingsNo findings of significance were identified.
ENCLOSURE 2-27-2.RADIATION SAFETYCornerstone: Occupational Radiation Safety2OS1Access Control To Radiologically Significant Areas (71121.01) a.Inspection ScopeThis area was inspected to assess the licensee's performance in implementing physicaland administrative controls for airborne radioactivity areas, radiation areas, high
radiation areas, and worker adherence to these controls. The inspector used the
requirements in 10 CFR Part 20, the technical specifications, and the licensee's
procedures required by technical specifications as criteria for determining compliance.
During the inspection, the inspector interviewed the radiation protection manager,
radiation protection supervisors, and radiation workers. The inspector performed
independent radiation dose rate measurements and reviewed the following items:*Performance indicator events and associated documentation packages reportedby the licensee in the Occupational Radiation Safety Cornerstone*Controls (surveys, posting, and barricades) of radiation, high radiation, orairborne radioactivity areas in the Auxiliary, Radwaste, Reactor, and
Containment Buildings *Radiation exposure permits, procedures, engineering controls, and air samplerlocations*Conformity of electronic personal dosimeter alarm set points with surveyindications 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 two potentialairborne radioactivity areas*Adequacy of the licensee's internal dose assessment for any actual internalexposure greater than 50 millirem committed effective dose equivalent*Physical and programmatic controls for highly activated or contaminatedmaterials (non-fuel) stored within spent fuel and other storage pools.*Self-assessments, audits, licensee event reports, and special reports related tothe access control program since the last inspection*Corrective action documents related to access controls
- Licensee actions in cases of repetitive deficiencies or significant individualdeficiencies*Radiation exposure permit briefings and worker instructions
ENCLOSURE 2-28-*Adequacy of radiological controls, such as required surveys, radiation protectionjob coverage, and contamination control during job performance*Dosimetry placement in high radiation work areas with significant dose rategradients*Changes in licensee procedural controls of high dose rate - high radiation areasand very high radiation areas*Controls for special areas that have the potential to become very high radiationareas during certain plant operations*Posting and locking of entrances to all accessible high dose rate - high radiationareas and very high radiation areas*Radiation worker and radiation protection technician performance with respect toradiation protection work requirementsThe inspector completed 21 of the required 21 samples. b.FindingsIntroduction. The inspector reviewed a self-revealing NCV of TS 5.5.1.1 when a workerfailed to follow radiation work permit instructions. Description. On July 14, 2007, a worker notified health physics of a pre-job site reviewprior to starting work on Valve 3HV7261 in the Post Accident Sampling System Lab. The
worker was informed of the radiological conditions for the work area. However, after
completing the pre-job site review, the worker proceeded to verify the work authorization
boundaries in Unit 3, Room 209. The worker approached Valve S31902MU012 and
received a dose rate alarm. The worker exited the radiologically controlled area and
informed health physics of the alarm. The peak dose rate received by the worker was
11.1 millirem per hour and area around valve S31902MU012 had a maximum dose rate
level of 30 millirem per hour on contact with the piping system and 12 millirem per hour at
30 centimeters. During the licensee's investigation of the dose rate alarm, the licensee
determined that the worker did not inform health physics of all areas needing access to
complete the work scope and did not receive a radiological briefing for Unit 3, Room 209.
The licensee's corrective actions were to coach the worker and to develop and
implement a mechanism for communicating associated boundary walk downs in
maintenance orders.Analysis. The failure to follow a radiation work permit instruction is a performancedeficiency. This finding is greater than minor because it is associated with one of the
cornerstone attributes (exposure control) and affected the Occupational Radiation Safety
cornerstone objective, in that workers not following their radiation work permit does not
ensure adequate protection of the worker health and safety from additional personnel
exposure. This occurrence involved a worker's unplanned, unintended dose, or potential
for such a dose that could have been significantly greater as a result of a single minor,
ENCLOSURE 2-29-reasonable alteration of the circumstances, higher dose rate levels. This finding wasdetermined to be of very low safety significance because it did not involve: (1) as low as
is reasonably achievable (ALARA) planning and controls, (2) an overexposure, (3) a
substantial potential for overexposure, or (4) an impaired ability to assess dose. Further,
this finding has a work practices human performance cross cutting aspect in human error
prevention techniques because the worker failed to self check the work scope and work
locations when briefing with health physics prior to entering the radiological controlled
area H4a].Enforcement. Technical Specification 5.5.1.1.a requires applicable proceduresrecommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Section 7(e), of the Appendix, requires procedures for access control and a radiation
work permit system. Procedure SO 123-VII-20, "Health Physics Program," Revision 12,
Section 6.10.6.5 states, in part, that individuals entering a radiological controlled areasign on an appropriate radiation exposure permit acknowledging that they agree to
comply with the radiological controls specified on the radiation exposure permit.
Radiation Exposure Permit 07070562000/200159, states, in part, that workers, prior to
entering the radiologically controlled area, are to inform the Health Physics Control Point
of the job scope and work locations. Contrary to the Radiation Exposure Permit
requirement, on July 14, 2007, the worker did not inform the health physicist at the
control point of the full work scope and work locations prior to entering the radiological
controlled area which resulted in the worker knowing the current radiological conditions of
Room 209. Because this finding is of very low safety significance and was entered into
the licensee's corrective action program (Action Request 070700545), this violation is
being treated as a noncited violation in accordance with Section VI.A.1 of the
Enforcement Policy: NCV 05000362/2007005-03, Failure to follow a radiation exposure
permit requirement.2OS2Planning and Controls (71121.02) a.Inspection ScopeThe inspector assessed licensee performance with respect to maintaining individual andcollective radiation exposures ALARA. The inspector used the requirements in 10 CFR Part 20 and the licensee's procedures required by technical specifications as criteria fordetermining compliance. The inspector interviewed licensee personnel and reviewed:*Site-specific ALARA procedures
- Interfaces between operations, radiation protection, maintenance, maintenanceplanning, scheduling and engineering groups*Integration of ALARA requirements into work procedure and radiation work permit(or radiation exposure permit) documents*Dose rate reduction activities in work planning
- Exposure tracking system
ENCLOSURE 2-30-*Use of engineering controls to achieve dose reductions and dose reductionbenefits afforded by shielding*Workers' use of the low dose waiting areas
- First-line job supervisors' contribution to ensuring work activities are conducted ina dose efficient manner*Radiation worker and radiation protection technician performance during workactivities in radiation areas, airborne radioactivity areas, or high radiation areas *Self-assessments, audits, and special reports related to the ALARA programsince the last inspection*Resolution through the corrective action process of problems identified throughpost-job reviews and post-outage ALARA report critiques*Corrective action documents related to the ALARA program and follow-upactivities, such as initial problem identification, characterization, and tracking*Effectiveness of self-assessment activities with respect to identifying andaddressing repetitive deficiencies or significant individual deficiencies The inspector completed 5 of the required 15 samples and 8 of the optional samples. b.FindingsNo findings of significance were identified.4.OTHER ACTIVITIES4OA1Performance Indicator (PI) Verification (71151) a.Inspection ScopeCornerstone: Mitigating SystemsThe inspectors sampled licensee data for the Mitigating System PerformanceIndex (MSPI) performance indicators (PI) listed below for Units 2 and 3 for the period
from September 26, 2007 through December 31, 2007. The definitions and guidance of
Nuclear Energy Institute 99-02, "Regulatory Assessment Performance Indicator
Guideline," Revision 4, were used to verify the licensee's basis for reporting unavailability
and unreliability in order to verify the accuracy of PI data. The inspectors reviewed
operating logs, Limiting Conditions for Operation logs, ARs, and the maintenance rule
database to verify that the licensee properly accounted for planned and unplanned
unavailability as part of the assessment. The inspectors sampled data to verify that the
licensee: (1) accurately documented the actual unavailability hours for the MSPI systems;
and (2) accurately documented the actual unreliability information for each MSPI
ENCLOSURE 2-31-monitored component. In addition, the inspectors interviewed licensee personnelassociated with PI data collection and evaluation.*Units 2 and 3, safety system functional failures
The inspectors completed two samples.
Cornerstone: Barrier IntegrityThe inspectors sampled licensee submittals for the four performance indicators listedbelow for the period September 26, 2007 through December 31, 2007, for Units 2 and 3.
The definitions and guidance of Nuclear Energy Institute 99-02, "Regulatory Assessment
Performance Indicator Guideline," Revision 4, were used to verify the licensee's basis for
reporting each data element in order to verify the accuracy of PI data reported during the
assessment period. The inspectors: (1) reviewed RCS chemistry sample analyses for
dose equivalent Iodine-131 and compared the results to the TS limit; (2) observed a
chemistry technician obtain and analyze a RCS sample; (3) reviewed operating logs and
surveillance results for measurements of RCS identified leakage; and (4) observed a
surveillance test that determined RCS identified leakage. Licensee performance
indicator data were also reviewed for the following:Units 2 and 3, reactor coolant system specific activityUnits 2 and 3, reactor coolant system leakageThe inspectors completed four samples.
Cornerstone : Occupational Radiation Safety Occupational Exposure Control Effectiveness
The inspector reviewed licensee documents from January 1 throughSeptember 30, 2007. The review included corrective action documentation that identified
occurrences in locked high radiation areas (as defined in the licensee's technical
specifications), very high radiation areas (as defined in 10 CFR 20.1003), and unplanned
personnel exposures (as defined in Nuclear Energy Institute (NEI) 99-02, "Regulatory
Assessment Indicator Guideline," Revision 5). Additional records reviewed includedALARA records and whole body counts of selected individual exposures. The inspector
interviewed licensee personnel that were accountable for collecting and evaluating the
performance indicator data. In addition, the inspector toured plant areas to verify that
high radiation, locked high radiation, and very high radiation areas were properlycontrolled. Performance indicator definitions and guidance contained in NEI 99-02,
Revision 5, were used to verify the basis in reporting for each data element.The inspector completed the required sample (1) in this cornerstone.
Cornerstone: Public Radiation SafetyRadiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences
ENCLOSURE 2-32-The inspector reviewed licensee documents from January 1 throughSeptember 30, 2007. Licensee records reviewed included corrective action
documentation that identified occurrences for liquid or gaseous effluent releases that
exceeded performance indicator thresholds and those reported to the NRC. The
inspector interviewed licensee personnel that were accountable for collecting and
evaluating the performance indicator data. Performance indicator definitions and
guidance contained in NEI 99-02, Revision 5, were used to verify the basis in reporting
for each data element.The inspector completed the required sample (1) in this cornerstone. b.FindingsNo findings of significance were identified.4OA2Identification and Resolution of Problems (71152).1Radiological Controls Review a.Inspection ScopeThe inspector evaluated the effectiveness of the licensee's problem identification andresolution process with respect to the following inspection areas:*Access Control to Radiologically Significant Areas (Section 2OS1)*ALARA Planning and Controls (Section 2OS2) b.FindingsNo findings of significance were identified..2Routine Review of Identification and Resolution of Problems a.Inspection ScopeThe inspectors performed a daily screening of items entered into the licensee's correctiveaction program. This assessment was accomplished by reviewing maintenance orders,
action requests, the management focus list, and attending corrective action review and
work control meetings. The inspectors: (1) verified that equipment, human performance,
and program issues were being identified by the licensee at an appropriate threshold and
that the issues were entered into the corrective action program; (2) verified that
corrective actions were commensurate with the significance of the issue; and
(3) identified conditions that might warrant additional follow-up through other baseline
inspection procedures. b.FindingsNo findings of significance were identified.
ENCLOSURE 2-33-.3Selected Issue Follow-up Inspection a.Inspection ScopeIn addition to the routine review, the inspectors selected the two below listed issues for amore in-depth review. The inspectors considered the following during the review of the
licensee's 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. August 7, 2007, Unit 3, saltwater cooling pump room thermal overload trip
- December 18, 2007, Units 2 and 3, comprehensive review of operatorworkaroundsDocuments reviewed by the inspectors are listed in the attachment.b.FindingsIntroduction. A self revealing Green violation of 10 CFR Part 50, Appendix B,Criterion XVI, was identified for the failure to prevent recurrence of premature tripping of
Square D thermal overloads used for equipment protection on safety-related equipment.
The licensee failed to scope the thermal overloads associated with the Unit 3 saltwater
cooling pump room because it had erroneously determined that it had sufficient margin
such that it would not be susceptible to failure. This resulted in the premature tripping of
thermal overloads for the Unit 3 saltwater cooling pump room intake structure fan on
August 8, 2007.Description. The licensee previously had problems with spurious thermal overload tripsand received a noncited violation for untimely corrective actions to resolve the problem
(see NRC Inspection Report 05000361;362/2006-005). On October 17, 2006, the Unit 2
fuel handling building pump room emergency air conditioning Unit 2E441 Phase B
thermal overload tripped for no apparent reason with the fan turned off. The inspectors
noted that six spurious trips of other thermal overloads had occurred since December
2005. These overloads were associated with the Unit 3 fuel handling building post
accident cleanup room emergency air conditioning Unit 3E371, the Unit 2 fuel handling
building pump room emergency air conditioning Units 2E441 and 2E442, and the Unit 2
component cooling water Pump 2P024 room emergency air conditioning Unit 2E453. All
of these thermal overloads were subsequently changed out for larger devices in 2005
because of chronic problems with spurious trips.The inspectors reviewed the history of spurious thermal overload trips and discoveredthat five previous apparent cause assessments (ACEs) had been performed since
January 2001 to identify and correct spurious trips associated with thermal overloads. A
2001 ACE identified equipment aging as the cause, and directed that replacement
thermal overloads be installed. A 2002 ACE identified degraded cabling lugs as the
ENCLOSURE 2-34-cause, and the lugs were replaced. A 2003 ACE identified the cause as insufficientmargin in the trip settings, which were adjusted. A 2004 ACE attributed a series of
spurious trips to warm weather. Finally, a 2005 ACE identified that the thermal overloads
were undersized, and that new, larger thermal overloads should be installed. The
licensee upgraded 64 thermal overloads to a larger capacity model in December 2005.
However, the inspectors concluded that the ACEs and the associated corrective actions
generated by the licensee had been ineffective in resolving the problem.The licensee performed a root cause evaluation as part of RCE070901311 initiated inresponse to the thermal overload failures. Procedure SO123-XV-50, "Corrective Action
Process," Revision 7, directs a root cause evaluation for significant problems and to
prevent recurrence of the consequences of these problems. The inspectors concluded a
root cause evaluation was appropriate since Procedure SO123-XV-50 specifies criteria
for a root cause that include safety equipment failures with generic operability issues and
long-standing problems requiring escalation for resolution. The inspectors determined
these criteria were met based on the generic implications involving failures of safety
related equipment and the numerous apparent causes that had been performed since
January 2001 that had failed to correct the issue. The inspectors therefore concluded
the failure of the thermal overloads represented a significant condition adverse to quality.The licensee implemented a detailed plan for testing the thermal overloads and X-rayedthe internals to determine if a design defect had previously gone undetected. The
licensee discovered that two mechanisms in concert with each other were causing the
spurious trips. Thermal overloads associated with small motors had a tendency to trip
early due to higher than expected current levels going through the overloads while the
associated line voltage was high in the normal band. Also, the X-ray analysis revealed
that approximately 20 percent of the sample had insufficient melting alloy, contributing to
a thermal overload tripping on lower current. The licensee established a plan to replace the affected thermal overloads with properlysized components that would be X-rayed for sufficient melting alloy verification prior to
installation. However, the licensee concluded sufficient margin existed in a group of 75
thermal overloads, including those associated with the Unit 3 saltwater cooling pump
room intake structure fans.On August 8, 2007, the intake structure fan for the Unit 3 saltwater cooling pump roomtripped. The cause was subsequently determined to be a defective thermal overload on
the Phase C portion due to insufficient solder material in the thermal overload. The
thermal overload was replaced, and temperature in the Unit 3 saltwater cooling pump
never approached its design value of 98°F. The licensee has since replaced all 75
susceptible thermal overloads that were previously scoped out of the corrective action
process.Analysis. The failure of the licensee to properly scope corrective actions to prevent thepremature tripping of thermal overloads for safety-related equipment was considered a
performance deficiency. The finding was determined to be more than minor because it
was associated with the equipment performance attribute of the mitigating systems
cornerstone and it affected the cornerstone objective by challenging the availability and
capability of safety-related components. Using the Manual Chapter 0609, "Significance
ENCLOSURE 2-35-Determination Process," Phase 1 worksheet, the finding was determined to have very lowsafety significance (Green) because it did not result in an actual loss of a system safety
function, a loss of a single train of safety equipment for greater than its technical
specification allowed outage time, and did not screen as potentially risk significant due to
seismic, flooding, or severe weather initiating events. The cause of the finding has a
crosscutting aspect in the area of problem identification and resolution associated withthe corrective action program (P.1(c)) because the licensee failed to thoroughly evaluate
the extent of condition of insufficient solder material on safety-related thermal overloads.Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," states, inpart, that measures shall be established to ensure that for significant conditions adverse
to quality, corrective actions are taken to preclude repetition. Contrary to this, from
February 6 through August 8, 2007, the licensee failed to take corrective actions to
preclude repetition of the premature tripping of thermal overloads for safety-related
equipment, a significant condition adverse to quality. This finding has been entered into
the licensee's corrective action program as AR 070800454. Due to the licensee's failure
to restore compliance from previous NCV 05000361;05000362/2006005-04, within a
reasonable time after the violation was identified, this violation is being cited as a Noticeof Violation consistent with Section VI.A of the Enforcement Policy: VIO 05000361;05000362/2007005-04, "Failure to Prevent Recurrence of Premature Tripping of Square
D Thermal Overloads." .3Semiannual Trend Review a.Inspection ScopeThe inspectors completed a semi-annual trend review of repetitive or closely relatedissues that were documented to identify trends that might indicate the existence of more
safety significant issues, specifically in the areas of procedural compliance and humanperformance. The inspectors review consisted of the six month period from June 25,
2007, through December 31, 2007. When warranted, some of the samples expanded
beyond those dates to fully assess the issue. The inspectors also reviewed corrective
action program items associated with human performance improvement, and met with
representatives from the San Onofre human performance improvement team at regular
intervals. Corrective actions associated with a sample of the issues identified in the
licensee's trend report were reviewed for adequacy. Documents reviewed by the
inspectors are listed in the attachment. b.FindingsNo findings of significance were identified. However, the inspectors noted that thelicensee continued to attempt to implement human performance initiatives to prevent
personnel errors. The licensee indicated that a stand alone performance improvement
plan would be implemented by January 31, 2008.
ENCLOSURE 2-36-4OA5 Other.1Temporary Instruction 2515/166, "Pressurized Water Reactor Containment SumpBlockage," San Onofre Nuclear Generating Station, Unit 2Temporary Instruction 2515/166 was performed at San Onofre Nuclear GeneratingStation, Unit 2. The results of inspection phase of Temporary Instruction 2515/166 for
Unit 2 are subsequently documented in this report. Temporary Instruction 2515/166 for
both Unit 2 and Unit 3 will be closed out after the completion and verification of
modification commitments for Unit 2 containment sumps at the end of Refueling
Outage 15.Listed below are the commitments and actions taken by the licensee:
1.Design and procurement of replacement sump screensActions TakenEngineering Change Packet ECP#040301974-11 dated Jul 17, 2006, provides forthe design changes of containment sump to address sump blockage concerns.
This engineering change packet has undergone NRC review and supplemental
responses to the NRC are to be received no later than February 29, 2008, per
letter to Nuclear Energy Institute (NEI) from NRC: Supplemental Licensee
Responses to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On
Emergency Recirculation During Design Basis Accidents At Pressurized-Water
Reactors," dated November 30, 2007. Materials for the sump screens have been
procured and are currently being installed during Refueling Outage RF15, with
modifications expected to complete at the end of the outage. 2.Resolution of potential susceptibility of emergency core cooling system andcontainment spray system pump mechanical seal to increased leakage due to
debris mix passing through the sealsActions TakenThe licensee has completed calculations to evaluate seal leakage due to debrisingestion. This action has undergone NRC review and supplemental responses
to the NRC are to be received no later than February 29, 2008, per letter to NEI
from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,
"Potential Impact Of Debris Blockage On Emergency Recirculation During Design
Basis Accidents At Pressurized-Water Reactors," dated November 30, 2007. 3.Resolution of potential susceptibility of ECCS and CSS pump mechanical sealcyclone separators to debris blockage
ENCLOSURE 2-37-Actions TakenThe licensee has completed calculations to evaluate seal leakage due to debrisingestion. This action has undergone NRC review and supplemental responses to
the NRC are to be received no later than February 29, 2008, per letter to NEI
from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,
"Potential Impact Of Debris Blockage On Emergency Recirculation During Design
Basis Accidents At Pressurized-Water Reactors," dated November 30, 2007. 4.Development of a reduced qualified protective coatings zone of influence (ZOI)Actions TakenALION-CAL-SONGS2933-02, Revision 1 "San Onofre Units 2 and 3 GSI-191Containment Recirculation Sump Evaluation: Debris Generation Calculation,"documents the assumptions and methodology that the licensee applied to
determine the ZOI and debris generated for each postulated break. This
evaluation has undergone NRC review and supplemental responses to the NRC
are to be received no later than February 29, 2008, per letter to NEI from NRC:
Supplemental Licensee Responses to Generic Letter 2004-02, "Potential Impact
Of Debris Blockage On Emergency Recirculation During Design Basis Accidentsat Pressurized-Water Reactors," dated November 30, 2007. 5.Validation of the 8 percent head loss margin adjustment factor for chemicaleffects (SONGS uses Trisodium Phosphate (TSP) as a post-LOCA pH buffering
agent, and pertinent debris loads are primarily mineral wool fibrous insulation,
making NRC's Integrated Chemical Effects Test (ICET) 2 generally applicable,
but the licensee stated that chemical effects values were subject to follow-on
sump screen vendor testing, and SCE evaluations and walkdowns).Actions TakenChemical effect tests were completed by Alion Science and Technology, anddirectly observed by the NRC, in Warrenville, Illinois on August 17 - 18, 2006.
Open items from the NRC review are to be addressed and supplemental
responses to the NRC are to be received no later than February 29, 2008, per
letter to NEI from NRC: Supplemental Licensee Responses to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On Emergency
Recirculation During Design Basis Accidents At Pressurized-Water Reactors,"
dated November 30, 2007. 6.Containment insulation configuration control to ensure the amounts and types ofinsulation remain within acceptable debris loading design marginsActions TakenThe licensee has removed microtherm insulation on four different pipingsegments in containment. This insulation is to be replaced by reflective metal
insulation where appropriate. Mineral wool insulation on the steam generators is
ENCLOSURE 2-38-to be replaced with RMI during the steam generator replacement activities in2009. These actions have undergone NRC review and supplemental responses to
the NRC are to be received no later than February 29, 2008, per letter to NEI
from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,
"Potential Impact Of Debris Blockage On Emergency Recirculation During Design
Basis Accidents At Pressurized-Water Reactors" dated November 30, 2007. 7.Replace sump screens at SONGS Unit 2 during Refueling Outage Cycle 15Actions TakenWork currently ongoing and expected to be completed by the end of the refuelingoutage.8.Removal of microporous insulation on piping to be completed coincident withsump screen replacement.Actions TakenWork currently ongoing and expected to be completed by the end of the refuelingoutage.9.Modification fo steel grates at the entry to the bioshield to reduce the potential fordebris blockage and resultant hold-up of recirculating water to be completed
coincident with sump screen replacement.Actions TakenWork currently ongoing and expected to be completed by the end of the refuelingoutage.4OA6Meetings, Including ExitOn November 9, 2007, the engineering inspectors presented the results of thepermanent plant modifications inspection and the evaluation of changes, tests, or
experiments inspection to Dr. R. Waldo and others who acknowledged the findings.On November 30, 2007, the health physics inspectors presented inspection results toMr. J. Reilly and others who acknowledged the findings.On December 3, 2007, the inspector discussed the inspection results of the licensedoperator annual requalification examination with Mr. B. Arbour, Training Supervisor. A
telephone exit was held with Mr. Arbour, on December 3, 2007. The licensee
acknowledged the findings presented in both the briefing and the final exit meeting.On December 13, 2007, the inspectors presented the results of this inservice inspectionto J.T. Reilly, Vice-President Engineering and Technical Services, and other members of
licensee management. Licensee management acknowledged the inspection findings.
ENCLOSURE 2-39-On December 21, 2007, and on February 13, 2008, the inspectors presented thequarterly inspection results to Mr. R. Ridenoure and others who acknowledged the
findings. The inspectors confirmed that proprietary information was not provided or examinedduring the inspection.4OA7Licensee-Identified ViolationsThe following violation of very low significance (Green) was identified by the licensee andis a violation of NRC requirements which meets the criteria of Section VI of the
NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.*Licensee Technical Specification Section 5.5.1.1.a requires applicable proceduresrecommended in Regulatory Guide 1.33. Revision 2, Appendix A, February 1978.
Section 7e of the Appendix requires procedures for access control and a radiation
work permit system. Radiation Exposure Permit A081997001/200117-8 requires
workers to wear radiological protective clothing for entry into contaminated areas,
such as shoe covers and gloves. Contrary to this requirement, there were three
examples of security officers entering contaminated areas without the required
protective clothing. The first example occurred on October 9, 2007, when two
security guards entered a posted contaminated area in Unit 3, Room 411 of the
penetrations building, without the required radiological protective clothing. The
second example occurred on November 12, 2007, when a security guard entered
a posted contaminated area in Unit 2, Room 209 without the required radiological
protective clothing. The third example occurred November 13, 2007, when a
security guard entered a posted contaminated area in Unit 2, Room 209 without
the required radiological protective clothing. In all three examples, the area
postings had changed and with inattention to detail, the officers entered the areas
without the required radiological protective clothing. This issue was entered into
the licensee's corrective action program (Action Requests 071000551,
071100759, and 071100760). This finding is of very low safety significance
because it did not involve: (1) ALARA planning and controls, (2) an overexposure,
(3) a substantial potential for overexposure, or (4) an impaired ability to assess
dose.ATTACHMENT: SUPPLEMENTAL INFORMATION
ATTACHMENTA-1SUPPLEMENTAL INFORMATIONKEY POINTS OF CONTACTLicensee PersonnelD. Axline, Technical Specialist, Nuclear Regulatory AffairsD. Breig, Manager, Engineering Standards and Excellence
B. Corbett, Manager, Health Physics
J. Hirsch, Manager, Maintenance
K. Johnson, Manager, Design Engineering
R. Ridenoure, Vice President, Nuclear Generation
L. Kelly, Engineer, Nuclear Regulatory Affairs
C. McAndrews, Manager, Nuclear Oversight and Assessment
N. Quigley, Manager, Mechanical/Nuclear Maintenance Engineering
J. Reilly, Vice President, Engineering and Technical Services
A. Scherer, Manager, Nuclear Regulatory Affairs
R. St. Onge, Manager, Maintenance and Systems Engineering
T. Vogt, Manager, Special Projects
D. Wilcockson, Manager, Plant Operations
C. Williams, Manager, Compliance
T. Yackle, Manager, Operations
O. Flores, Manager, Chemistry
J. Morales, Manager, Projects
M. Cooper, Manager, Maintenance and Systems Engineering
S. Gardner, Nuclear Engineer, Nuclear Regulatory Affairs
A. Mahindrakar, Technical Specialist/Scientist, Maintenance and Systems Engineering
J. Valsvig, Technical Specialist/Scientist, Maintenance and Systems Engineering
M. McDevitt, Senior Nuclear Engineer, Engineering and Technical Services
P. Chang, Nuclear Engineer, Maintenance Engineering
A. Matheney, Senior Nuclear Engineer, Engineering and Technical Services
M. Wade, Westinghouse Representative
M. Short, Director Nuclear Oversight and Assessment
J. Todd, Manager, Nuclear Oversight and Regulatory AffairsLIST OF ITEMS OPENED, CLOSED, AND DISCUSSEDOpened 05000361;05000362/2007005-04NOVFailure to Prevent Recurrence of Premature Tripping ofSquare D Thermal Overloads (Section 4OA2.2)
ATTACHMENTA-2Opened and Closed
05000361;05000362/2007005-01NCVFailure to Properly Implement Maintenance RuleRequirements for Emergency Diesel Generators
(Section 1R12)05000362/2007005-02NCVFailure to Implement Procedural Requirements forModificaitons in the Auxiliary Feedwater Steam Supply
Trench (Section 1R15)05000362/2007005-03 NCVFailure to Follow a Radiation Exposure Permit Requirement(Section 2OS1)
Closed None Discussed NoneLIST OF DOCUMENTS REVIEWEDIn addition to the documents called out in the inspection report, the following documents wereselected and reviewed by the inspectors to accomplish the objectives and scope of the
inspection and to support any findings:Section 1R02: Evaluations of Changes, Tests, or Experiments10 CFR 50.59 Evaluations020701289-37Auxiliary steam system radwaste condensate returnline rad monitor flow valve change - Fix position of
Condensate Return Valve 2/3FV-7546 and remove
2/3FIC-7546Revision 0 050801215-08 Change to the U3C14 Core Fuel Loading PatternRevision 0 060101335-13 Reduction in the number of Dome Air Circulator Fans Credited for Containment Sprayed and Unsprayed
Region Mixing.Revision 0 060401009-06 One-time change to the testing frequency for the High Pressure Turbine Stop and Control ValvesRevision 0
ATTACHMENTA-3 060700747-13 Perform Calculation to evaluate the effects of air pocket on Engineered Safety Feature pump performance.Revision 0 060700747-18 Perform Calculation to evaluate the effects of air pocket on Engineered Safety Feature pump performance.Revision 1060800698-13Engineering design work by Bechtel to support steamgenerator replacement - Remove one Containment
Hydrogen Recombiner E146 for one cycle of operation
to facilitate Steam Generator Replacement Revision 0060800698-44Change to UFSAR Section 8.1, paragraph 8.1.4.3.14.BRevision 010 CFR 50.59 Screenings040400696-17Add ECP vent line at AFW pump motor outboardbearing housing to eliminate oil leak09/25/2007 041100092-79Need to Evaluate U-2 CCW Fisher Butterfly valveconcerning valve taper pin issue 050300070-05Install Steam Trap in Auxiliary Steam Cross-tie header050901044-40Technical specification bases change to allowsubstituting B00X for battery B007 and B008 for
temporary battery outage11/01/2005050901044-43Technical specification bases change to allowsubstituting B00X for battery B007 and B008 for
temporary battery outage11/03/2005050901044-61Phase I of the Class 1E DC system upgrade10/27/2005050901044-61Technical specification bases change to allowsubstituting B00X for battery B007 and B008 for
temporary battery outage (update)12/16/2005050901044-82Technical specification bases change to allowsubstituting B00X for battery B007 and B008 for
temporary battery outage03/20/2006 051000132-06Update AOV Program Procedure to update valve ISTProcedure.051200901-07Installation of a flow orifice downstream of 2PCV471607/25/2006060200607-18Add DC shunts to batteries 2B007 and 2B009 formonitoring current06/08/2006
ATTACHMENTA-4060200607-51Add DC shunts to batteries 2B007 and 2B009 formonitoring current - Addition of an 800 Amp, 100 mV
DC shunt at the positive polarity of battery B00X08/02/2006060400474-04Modify required actions in procedure SO23-5-1.7 torequire MODE 3 entry for 1-3 inoperable MSSVs per
steam generator04/10/2006060400474-12Modify required actions in procedure SO23-5-1.7 torequire MODE 3 entry for 1-3 inoperable MSSVs per
steam generator04/14/2006060400474-32Modify required actions in procedure SO23-5-1.7 torequire MODE 3 entry for 1-3 inoperable MSSVs per
steam generator07/27/2006060400474-41Modify required actions in procedure SO23-5-1.7 torequire MODE 3 entry for 1-3 inoperable MSSVs per
steam generator10/04/2006060500070-14ECP# 060500070-10: Replace 3P123 Feeder Breaker05/052006060500211-21Replace vertical air tank S31319MV04805/18/2006060500211-38Replace vertical air tank S31319MV04806/16/2006060500211-43Replace vertical air tank S31319MV04808/10/2006
060600089-84Increase Thermal Overload size in breakers 2BY37,3BY37, 3BZ3309/18/2006 060800603-02Replace existing R3, R4 potentiometers with a newmodel in AVR for EDG.01/24/2007060800603-16Replace existing R3, R4 potentiometers with a newmodel in AVR for EDG.01/24/2007060800603-29Replace existing R3, R4 potentiometers with a newmodel in AVR for EDG.03/07/2007061001071-19Use of new E4C-109 battery short circuit methodology03/28/2007061001842-82Upsize Thermal Overloads to avoid Spurious Trips11/15/2006 061100895-11Material condition of Generator Neutral GroundingResistor is poor. 061101272-04Install Lifting Eye Pad on beam to allow in-line liftcapability when changing out safety valve.
ATTACHMENTA-5070200876-05Code upgrade installation for CENTS computer codeversion 0610002/26/2007070200876-06Code upgrade installation for TORCGEOM computercode version 1.0.503/26/2007070200876-07Code upgrade installation for REX computer codeversion 2.1.609/20/2007070200876-08Code upgrade installation for CORD computer codeversion 1.3.709/20/2007 070700512-06Lower the Set Point of the concerned instruments andprovide Control Room indication of actual pressure.CalculationsE4C-112, CCN 72Class 1E 480V MCC Protection CalculationRevision 1E4C-112, ECN A46476Class 1E 480V MCC Protection CalculationRevision 1E4C-112,CCN 55Class 1E 480V MCC Protection CalculationRevision 1M-0012-039ESF Pump Suction with Entrained Air after RAS(Recirculation Actuation Signal)Revision 0N-4061-001Post-Loss Of Coolant Accident Summary of LowPopulated Zones and Offsite DosesRevision 2N-4061-002Post-Loss Of Coolant Accident Containment Leakage -Control Room and Offsite DosesRevision 1Action Requests050901044060200607060400474060800603061001071Section 1R04: Equipment Alignment ProceduresSO23-3-2.6"Shutdown Cooling System Operation"Revision 24SD-SO23-780"Auxiliary Feedwater System"Revision 10
SD-SO23-120"6.9 kV, 4.16 kV and 480 V Electrical Distribution Systems"Revision 16
SO23-5-1.8.1"Shutdown Nuclear Safety"Revision 17
ATTACHMENTA-6Drawings and CalculationsSD-SO23-740"Shutdown Cooling System"Revision 1740160A"Auxiliary Feedwater System - No. 1305"Revision 43
40160B"Auxiliary Feedwater Steam Supply System - No. 1301"Revision 21
40160C"Auxiliary Feedwater System Hydraulic Valves 2HV-4714& 4731 Control Fluid System No. 1305"Revision 740160X"Auxiliary Feedwater System No. 1305 and AuxiliaryFeedwater Steam Supply System No. 1301"Revision 4Section 1R05: Fire ProtectionProcedures2-013"Unit 2, diesel generator pre-fire plans"Revision 43-0345"Unit 3, diesel generator pre-fire plans"Revision 4
2-007"Unit 2, Safety Equipment Building (-)15'6"elevation"Revision 3UFHA 2/3-7.0-2SE"Updated Fire Hazard Analysis"May 2007Action Requests070901019070901022Section 1R08: Inservice InspectionsProceduresNumberTitleRevisionSO23-XXVII-20.51Visual Examination Procedure for Operability of NuclearComponents and Supports and Conditions Relating to
Their Functional Adequacy
2SO23-XXVII-20.48Liquid Penetrant Examination1SO23-XXVII-30.13Risk-Informed Ultrasonic Examination of Class 1Austenitic Piping Welds
0SO23-XXVII-30.6Ultrasonic Examination of Austenitic Piping Welds2SO23-XXVII-30.9Ultrasonic Examination of Dissimilar Metal Piping Welds2
ATTACHMENTA-7PDI-UT-10PDI Generic Procedure for the Ultrasonic Examination ofDissimilar Metal Welds
C9022Reactor Coolant System Alloy 600 Material ManagementProgram 5SO23-XXXIII-8.16Reactor Coolant System Alloy 600 Inspection5SO23-3-2.34Containment Access Control, Inspections and AirlocksOperation 20SO123-XXIV-10.1Engineering Change Package15SO123-0-A4Configuration Control9
SO23-1-1.11.1Plant Maintenance Procedure for Coating Service Level 1 Application
6SO23-XV-23.1.1Containment Cleanliness/Loose Debris Inspection1SO23-V-8.17Containment Coatings Assessment1
QA-46Qualification and Certification of NDE and VisualExamination Personnel per ASME Section XI
0WSI QAP 9.21Liquid Penetrant Examination1SI-UT-126Phased Array Ultrasonic Examination3
T4EN51Non-RCS Alloy 600 Boric Acid Leakage, Inspection andEvaluation
1T4EN52RCS Alloy 600 Boric Acid Leakage, Inspection andEvaluation
0SO23-V-8.15 ISS2Containment Boric Acid Leak Inspection2SO23-V-8.18Reactor Coolant System (RCS) Leak Monitoring andInvestigation Guide
0SO23-XV-85Boric Acid Corrosion Control Program1SO23-XXXIII-8.16Reactor Coolant System Alloy 600 Inspection5SO23-XXVII-3.51.9IntraSpec UT Analysis Guidelines5
SO23-XXVII-3.51.2IntraSpec Eddy Current Imaging Procedure for Inspectionof Reactor Vessel Head Penetrations
5SO23-XXVII-3.51.4IntraSpec Ultrasonic Procedure for Inspection of ReactorVessel Head Penetrations, Time-of-Flight Ultrasonic,
Longitudinal Wave & Shear Wave
5SO23-XXVII-3.51.3IntraSpec Eddy Current Analysis Guidelines6
ATTACHMENTA-8SO23-I-2.53Containment Emergency Sump Inspection Surveillance7SO 123-I-11.1Welding Filler material control9Corrective Action DocumentsAR 070500261AR 071101172AR 071101173AR 070500262AR 070500263AR 070500265AR 071200384AR 071200384
AR 060100998AR 060101057AR 060100961AR 071200751
AR 071200830AR 060901108-89CalculationsNumberTitleRevisionSONG-10Q-301Weld Overlay Sizing for Pressurizer Surge Nozzle2DrawingsNumberTitleRevisionSONG-10Q-02Pressurizer Surge Nozzle Weld Overlay Design and BufferLayer, Shts 1 and 2
1403974Construction Drawing Surge, SONGS, Unit 2, Shts 1 and 20S2-1203-ML-229Letdown Heat Exchanger E-602 to Line 100: UA2TV-0223, Sht 1
12S2-1203-ML-498Component Cooling Water, Sht 10Examination Technique Specification Sheets (ETSS)San Onofre Nuclear Generating StationETSSQualifying EPRI ETSSsETSS #196004.1, 96005.2, 96008.1, 96012.1,24013.1, 20511.1ETSS #923514.1, .2, .3
ETSS #320510.1, 20511.1, 21409.1, 21410.1,21998.1, 22401.1, 96703.1ETSS #420510.1, 20511.1, 21409.1, 21410.1,21998.1, 22401.1, 96703.1
ATTACHMENTA-9ETSS #596008.1, 96511.2ETSS #696511.2, 99997.1Welding Procedure Specifications and Corresponding Procedure Qualification ReportsWPS 08-08-T-001-Butter SS, Revision 0: PQRs 08-08-T-009, 08-08-TS-001, 8.8.6-OKG, and08-08-TS-002WPS 03-08-T-804-Bottom, Revision 0: PQRs A08202.3-3, 43-43-T-001, 03-03-T-803, andA843256-52WPS 1-GT-SM, Manual GTAW and/or SMAW of P-Number 1 CS, Revision 1: PQRs 51, 112, and 153MiscellaneousNumberTitleRevisionRPA 02-0080Quantification of Containment Latent Debris1
ECP#04031974-74Microtherm Insulation to RMI Change-out ECP; Unit 2
ECP#04031974-58Microtherm Insulation to RMI Change-out ECP; Unit 3
ECP#04031974-12Sump Screen Installation and Bioshield GateModification ECP; Unit 2ECP#04031974-11Sump Screen Installation and Bioshield GateModification ECP; Unit 3Letter to NRC from SCE: NRC Generic Letter 2004-02Response To NRC Request For Information San
Onofre Nuclear Generating Station Units 2 and 3March 7, 2005Letter to SCE from NRC: San Onofre NuclearGenerating Station Units 2 and 3-Request For
Additional Information (RAI) Related to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On
Emergency Sump Recirculation At Pressurized-Water
Reactors" (TAC NOS. MC4714 and MC4715)June 2, 2005Letter to NRC from SCE: NRC Generic Letter 2004-02Response To NRC Request For Additional Information July 5, 2005Letter to NRC from SCE: NRC Generic Letter 2004-02San Onofre Nuclear Generating Station Units 2 and 3September 1, 2005
ATTACHMENTA-10Letter to SCE from NRC: San Onofre NuclearGenerating Station, Units 2 and 3, Request For
Additional Information RE: Response to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On
Emergency Sump Recirculation At Pressurized-Water
Reactors" (TAC NOS. MC4714 and MC4715) February 9, 2006Letter to PWR Owners Group from NRC: AlternativeApproach for Responding to the Nuclear Regulatory
Commission Request for Additional Information Letter
RE: Generic Letter 2004-02 (TAC NOS. See
Enclosure)March 26, 2006Letter to PWR Owners Group from NRC: AlternativeApproach for Responding to the Nuclear Regulatory
Commission Request for Additional Information Letter
RE: Generic Letter 2004-02 (TAC NOS. See
Enclosure)January 4, 2007San Onofre Nuclear Generating Station Units 2 and 3-Report on Results of Staff Audit of Corrective Actions
to Address Generic Letter 2004-02 (TAC NOS.
MC4714 and MC4715) May 16, 2007Letter to NEI from NRC: Plant-Specific Requests forExtension of Time to Complete One or More
Corrective Actions for Generic Letter 2004-02,
"Potential Impact Of Debris Blockage On Emergency
Recirculation During
Design Basis Accidents At Pressurized-Water
Reactors" November 8, 2007Letter to NEI from NRC: Supplemental LicenseeResponses to Generic Letter 2004-02, "Potential
Impact Of Debris Blockage On Emergency
Recirculation During Design Basis Accidents At
Pressurized-Water Reactors" November 30, 2007ASNTCP-189-1995, ASNT Standard for Qualificationand Certification of Nondestructive Testing Personnel,
1995 EditionRequest For Relief ISI-3-25, Use of Structural WeldOverlay and Associated Alternative Repair
TechniquesNRC Safety Evaluation for Request For Relief ISI-3-25 June 12, 2007
Weld Data Sheet, Pressurizer Surge Line Nozzle -Weld ID DMW 02-005-031
ATTACHMENTA-11Welder Bead Logs for ER308L and Alloy 52Mdeposition on Unit 2 Pressurizer Surge NozzleSteam Generator Degradation Assessment for theCycle 15 Refueling Outages in 2007 and 2008November 29, 2007EA-03-009, Issuance of Order Establishing InterimInspection Requirements for Reactor Pressure Vessel
Heads at Pressurized Water Reactors February 11, 2003EPRI Report 1010087, Materials Reliability Program:Primary System Piping Butt Weld Inspection and
Evaluation Guidelines (MRP-139) August 2005Certificate of Compliance dated 5/29/07 for ASMECode Section II SFA5.9 Class ER 308/308L welding
material used on sacrificial layer on pressurizer surge
nozzleCertificate of Compliance 06369301 for ASME CodeSection II, Part C SFA-5.14 Inconel 52M welding
material used to deposit weld overlay on pressurizer
surge nozzle WSI Traveler No. 104532-TR-004 Pressurizer SurgeNozzle Repair Work Steps
0San Onofre Nuclear Generating Station Unit 3 BoricAcid Corrosion Control Program (BACCP) Health
Report for Cycle 13: 12/29/2004 - 12/12/2006 May 8,
2007Letter from T. G.Hiltz (NRC) to R.
M. Rosenblum
(SCEC)San Onofre Nuclear Generating Station Units 2 and 3Re: Third 10-year Inservice Inspection Interval
Request ISI-3-25, Use of Structural Weld Overlays
and Associated Alternative Repair Techniques (TAC
NOS MD2579 and MD2580)June 12, 2007Guide 5System Component Walkdown1Generic Letter88-05Boric Acid Corrosion of Carbon Steel PressureBoundary Components in PWR PlantsMarch 17, 1988Information Notice86-109,
Supplement 3Degradation of Reactor Coolant System BoundaryResulting from Boric Acid CorrosionJanuary 5, 199590022Southern California Edison San Onofre NuclearGenerating Station Units 2 and 3: Reactor Coolant
System Alloy 600 Material Management Program Plan
5
ATTACHMENTA-12Section 1R07A: Heat Sink PerformanceSO23-I-8.94"Component Cooling Water Heat Exchanger Cleaning andInspection"Revision 8Action Requests071000587071200968Maintenance Orders
06040726000Section 1R11: Licensed Operator RequalificationProcedures
Lesson Plan
2RS767"Reactor Startup (Simulator)"Revision 1
Lesson Plan
2RS768"Plant Startup - Power Ascension from Mode 2 to 20%Power (Simulator)"Revision 1Action Requests
071000587Maintenance Orders
06040726000Section 1R12: Maintenance Effectiveness (Quarterly
)ProceduresSO23-3-3.23"Diesel Generator Monthly and Semi-annual Testing"Revision 30
Action Requests
070300161
ATTACHMENTA-13Maintenance Orders070300161-02070300161-04Section 1R13: Maintenance Risk Assessments and Emergent Work ControlProceduresSO23-5-1.4"Plant Shutdown to Hot Standby" Revision 13SO23-5-1.3.1"Plant Startup from Hot Standby to Minimum Load" Revision 26
Shutdown NuclearSafety Program"Defense in Depth Planning Sheets Unit 3 Cycle 14 FallMidcycle Outage"Revision 0SO23-5-1.8.1"Shutdown Nuclear Safety"Revision 16SO123-VIII-1"Recognition and Classification of Emergencies"Revision 26
SO123-XX-6"Operator Work Around Program"Revision 5
SO23-15-52.A"Annunciator Panel 52A - FWCS/SBCS"Revision 7
SO23-3-2.10"Main Steam Isolation Valve Operation"Revision 16
SD-SO23-110"220 kV Switchyard System"Revision 16
SSSPG-SO123- G-10"Assessment of Offsite Capabilities Following a NaturalDisaster"Revision 0
Drawings and CalculationsSO23-507-6A-3-3"MSIV, FWIV, and FWBV Hydraulic Dump Valve"Revision MSO23-507-6A-5-3"MSIV, FWIV, and FWBV Hydraulic Dump Valve"Revision M
40156FSO3"High Pressure Feedwater System Feedwater IsolationValve 3HV4051 Electro-Hydraulic Actuation System"Revision 1340141GSO3"Main Steam System Electro-Hydraulic Valve 3HV-8204System"Revision 1540141G"Main Steam System Electro-Hydraulic Valve 2HV-8204System"Revision 17M3C14 DID #1"Barrier Map - Unit 3 Auxiliary Building (El. 50')"Revision 0M3C14 DID #1"Barrier Map - Unit 3 Safety Equipment Building (El. 15'-6" & 5'-3")"Revision 0
ATTACHMENTA-14M3C14 DID #3"Barrier Map - Train A Shutdown Cooling - Unit 3Auxiliary Building (El. 50')"Revision 0M3C14 DID #3"Barrier Map - Train A Shutdown Cooling - Unit 3 SafetyEquipment Building (El. 15'-6" & 5'-3")"Revision 0M3C14 DID #3"Barrier Map - Train B Shutdown Cooling - Unit 3Auxiliary Building (El. 50')"Revision 0M3C14 DID #3"Barrier Map - Train B Shutdown Cooling - Unit 3 SafetyEquipment Building (El. 15'-6" & 5'-3")"Revision 0UFSAR Fig. 8.2-1"One line Diagram - SwitchyardsRevision 16Action Requests071000609070500815071100595071201499071000250Section 1R15: Operability EvaluationsProceduresSO23-2-16"Operation of Waste Water systems"Revision 20SO23-20-4"Auxiliary Feedwater System Operation"Revision 22Vendor Spec"Kanaline SR PVC Hose"undatedVendor Spec"Prosser Standard-Line Submersible Dewatering PumpsSeries: 9-01000 & 9-01300" June 2003Vendor Spec"Prosser Standard-Line Submersible Dewatering PumpsSeries: 9-50000"March 2001SO23-3-3.31.6"Main Feedwater System Valve Test"Revision 7SO23-3-3.31.4"Main Steam Valve Testing - Offline"Revision 7
SO123-XV-5.1"Temporary Modification Control"Revision 8
SO23-2-16"Use of Temporary Sump Pumps"Revision 20
SO123-XV-52"Functionality Assessments and OperabilityDeterminations" Revision 7SO23-3-3.60.4"Saltwater Cooling Pump and Valve Testing"Revision 9 Drawings and Calculations40160A"Auxiliary Feedwater System"Revision 43
ATTACHMENTA-1540160B"Auxiliary Feedwater Steam Supply System"Revision 21DCP 52"Plant design package to add trench eductor to TDAFW"Revision 0Action Requests070500586051200901070500815071100965071000309070500578
071000901Section 1R17: Permanent Plant Modifications (71111.17A)Engineering Change Packages060400474-40Modify required actions in procedure SO23-5-1.7 torequire MODE 3 entry for 1-3 inoperable MSSVs per
steam generatorRevision09/27/2006060800177-07Replacement of Diesel Generator Temperature Switchper SEE 000036Revision 00061001379-84Install CCW Bypass Flow around the Unit 3 LetdownHeat ExchangerRevision 00061001842-16Replace Existing TOL for Breaker 2BZ17Revision 00061001842-46Replace Existing TOL for Breaker 3BZ25DrawingsS3-1023-ML-229,Sht 1Letdown Heat Exchanger, Line 100: Valve 3TV-0223Revision 15S3-1203-ML-498,Sht 1Component Cooling Water Line S3-1203-ML-498-4"-D-LL1 Sys 1203Revision 0S3-1203-ML-228,Sht 1S3-1203-ML-228-8"-D-LL1, From Line 099 Valve 138 toLetdown Heat ExchangerRevision 1340123BS03Reactor Coolant Chemical & Volume Control SystemNo. 1208Revision 29Permanent Plant Modifications020701289-37Fix Position of Condensate Return Valve 2/3FV7546and Remove 2/3FIC-754601/15/2007040400696-17Add ECP vent line at AFW pump motor outboardbearing housing to eliminate oil leak09/25/2007
ATTACHMENTA-16050901044-40Technical specification bases change to allowsubstituting B00X for battery B007 and B008 for
temporary battery outage11/01/2005051200901-07Installation of a flow orifice downstream of 2PCV471607/25/2006060500211-21Replace vertical air tank S31319MV04805/18/2006060800603-29Replace existing R3, R4 potentiometers with a newmodel in AVR for EDG.03/07/2007061101272-04Install Pad Eye on beam over Safety Valve 3PSV020008/28/2007ProceduresSO123-XV-4410 CFR 50.59 and 72.48 ProgramRevision 8Tech Spec AmendmentsPCN 576Request to revise Main Steam Safety ValveRequirements and Actions (T.S. 3.7.1)11/07/2006Section 1R19: Postmaintenance Testing ProceduresSO23-3-3.31.4"Main Steam Isolation Valve-Offline Testing" Revision 7SO23-3-3.31.6"Main Feedwater System Valve Test"Revision 7
SO23-XXVII-33.14"Procedure for the Phased Array Ultrasonic Examination ofWeld Overlaid Similar and Dissimilar Metal Welds"Revision 1WSI 104125-TR-
004"SONGS Pressurizer Surge Nozzle Repair Work Steps"Revision 0SO23-3-3.60.4"Saltwater Cooling Pump and Valve Testing"Revision 9SO23-3-3.31.10"Reactor Coolant Gas Vent System Test"Revision 13
Miscellaneous006-07"Repair/Replacement Plan for Weld Overlay Repair toPressurizer Surge Nozzle"Revision 0WPS -03-08-T-804-Bottom"Weld Procedure Specification for Inconel to StainlessSteel"Revision 0
ATTACHMENTA-17WPS-08-08-T-001-ButterSS"Weld Procedure Specification for Stainless Steel Butter"Revision 0"WPS-08-08-T-001-ButterSS Bead Log""WPS-03-08-T-804-Bottom Bead Log"Section 1R20: Refueling and Outage ActivitiesProceduresSO23-5-1.4"Plant Shutdown to Hot Standby" Revision 13SO23-5-1.5"Plant Shutdown from Hot Standby to Cold Shutdown" Revision 28
SO23-3-1.8"Draining the Reactor Coolant System" Revision 26
SO23-5-1.8"Shutdown Operations (Mode 5 and 6)" Revision 17
SO23-3-3.29"Determination of Reactor Shutdown Margin"Revision 18
SO23-3-2.6"Shutdown Cooling System Operation"Revision 24
SO23-I-3.5"Refueling Sequence" Revision 14
SO23-5-1.3"Plant Startup from Cold Shutdown to Hot Standby" Revision 30
SO23-5-1.7"Operating Instruction"Revision 35
SO23-13-15"Loss Of Shutdown Cooling"Revision 16
SO23-V-8.15"Containment Boric Acid Inspection"Revision 2" M3C14 Defense In Depth Planning Sheets"Revision 0Action Requests071200870071200486Section 1R22: Surveillance TestingProceduresSO23-3-3.30.8"Normal HVAC and Radiation Monitor Online Valve Test"Revision 5SO23-3-3.30.3"Component Cooling Water Seismic Makeup Valve Test"Revision 11
SO23-3-3.30.2"Train A Saltwater Cooling Valve Test"Revision 5
SO23-3-3.60.1"High Pressure Safety Injection Pump 2MP-018 Testing"Revision 7
ATTACHMENTA-18SO23-3-3.60.3"Component Cooling Water Pump 2MP-024 Test"Revision 8SO23-3-3.60"Inservice Pump Testing Program"Revision 8Section 1R23: Temporary Plant ModificationsProceduresECP-07100097-3"Replace grounded pressurizer heater S31201ME616with pressurizer heater S31201ME614"Revision 0Drawings and Calculations32631"Elementary diagram reactor pressurizer backup heaters
E124"Revision 1332632"Elementary diagram reactor pressurizer backup heaters
E128"Revision 2732171"One line diagram pressurizer heaters distribution panels"Revision 16SO23-919-2-
D58"Heater element assembly"Revision 4Section 1EP6 Drill EvaluationProceduresSO123-VIII-1"Emergency plan implementing procedures"Revision 26"Emergency plan Drill 0704"October 3, 2007
"SONGS Emergency Plan"Revision 16SO123-0-A7"Notification and Reporting of Significant Events"Revision 5Section 2OS1: Access Controls to Radiologically Significant Areas (71121.01)
Action Request Documents061001562, 061100484, 061101431, 070700048, 070700545, 070701137, 070701389, 070800826, 071000512, 071000551, 071000551, 071100267, 071100759, 071100760 Audits, Self-Assessments, Observations, and Surveillance ReportsHealth Physics Division Self-Assessment Reports for First, Second, and Third Quarter 2007Leader Observation Program Records from May through November 2007
SCES-006-07
ATTACHMENTA-19ProceduresHP-I-2Reactor Mode Change Checklist, Revision 14SO123-VII-20 Health Physics Program, Revision 12
SO123-VII-20.6.1Calculation of Dose from Skin Contamination, Revision 4
SO123-VII-20.7Monitoring Internal Radiation Exposure, Revision 6
SO123-VII-20.9Radiological Surveys, Revision 8
SO123-VII-20.9.6Laboratory Analysis of Health Physics Air Samples, Revision 2
SO123-VII-20.11Access Control Program, Revision 9
SO123-VII-20.11.1Radiological Posting, Revision 8Radiation Exposure Permits
A0707562000/200159, A0727070026, A0727070032/200101-12, A0819970001/200117-8
MiscellaneousSelected Radiological Surveys during initial entry to Unit 2 Containment Refueling Outage Unit 2 Shutdown Cooling Posting PlanSection 2OS2: ALARA Planning and Controls (71121.02)Action Request Documents070400180, 070401109, 070401115, 070501042, 070600855, 070800568, 071101117, 071101118, 071101120, 071101121, 071101122, 071101124Audits, Self-Assessments, Observations, and Surveillance ReportsHealth Physics Division Self-Assessment Reports for First, Second, and Third Quarter 2007Leader Observation Program Records from May through November 2007
SCES-006-07 and SOS-007-07ProceduresHP-I-2Reactor Mode Change Checklist, Revision 14SO123-VII-20 Health Physics Program, Revision 11
SO123-VII-20.4ALARA Program, Revision 4
SO123-VII-20.4.1ALARA Design Change Reviews, Revision 4
SO123-VII-20.10Radiological Work Planning and Controls, Revision 10Radiation Exposure PermitsA0727070026, A1018940021
MiscellaneousReactor Coolant System Cobalt-58 Clean Up Curve for Unit 3 Midcycle 14
ATTACHMENTA-20Unit 2 Refueling Cycle 15 ALARA Daily Current Performance for November 26 through 29, 2007Section 4OA1: Performance Indicator Verification (71151)ProceduresSO23-XV-24Quarterly NRC Performance Indicator (PI) Process, Revision 5"San Onofre Nuclear Generating Station; StationPerformace Report"
2 nd Quarter 2007"San Onofre Nuclear Generating Station; StationPerformace Report"3rd Quarter
2007MiscellaneousQuarterly Radiation Doses at the Site Boundary (Effluent Releases) for 2006 and 2007Worker exposure records for radiological controlled area entries greater than 100 milliremSection 4OA2: Identification and Resolution of ProblemsProceduresPolicy Note 14"Human Performance Strategic Plan"November 9, 2007LIST OF ACRONYMS
AFWauxiliary feedwater
ALARAas low as reasonably achievable
ARAction Request
AVR Automatic Voltage Regulator
BACCboric acid corrision control
CAPCorrective Action Program
CFRCode of Federal RegulationsEDGemergency diesel generator
EPRIElectric Power Re
search InstituteLERLicensee Event Report
NCVnoncited violation
NDEnondestructive examination
SSCstructure, system, and component
TSTechnical Specification
UFHAUpdated Fire Hazards Analysis
UFSARUpdated Final Safety Analysis Report
VUHPvessel upper head penetration