ML070440126
| ML070440126 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/13/2007 |
| From: | Vincent Gaddy NRC/RGN-IV/DRP/RPB-B |
| To: | Keenan J Pacific Gas & Electric Co |
| References | |
| IR-06-005 | |
| Download: ML070440126 (53) | |
See also: IR 05000275/2006005
Text
February 13, 2007
John S. Keenan
Senior Vice President - Generation
and Chief Nuclear Officer
Pacific Gas and Electric Company
P.O. Box 770000
Mail Code B32
San Francisco, CA 94177-0001
SUBJECT: DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION
REPORT 05000275/2006005 AND 05000323/2006005
Dear Mr. Keenan:
On December 31, 2006, the U.S. Nuclear Regulatory Commission completed an inspection at
your Diablo Canyon Power Plant, Units 1 and 2, facility. The enclosed integrated report
documents the inspection findings that were discussed on January 10, 2007, with Ms. Donna
Jacobs and members of your staff.
This inspection examined activities conducted under your licenses as they relate to safety and
compliance 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.
There were three NRC-identified findings and one self-revealing finding of very low safety
significance (Green) identified in this report. These findings involved violations of NRC
requirements. However, because of their very low risk significance and because they are
entered into your corrective action program, the NRC is treating these four findings as noncited
violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest
any NCV in this report, 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 the
Diablo Canyon Power Plant.
Pacific Gas and Electric Company -2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (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/
Vince G. Gaddy, Chief
Project Branch B
Division of Reactor Projects
Dockets: 50-275
50-323
Licenses: DPR-80
Enclosure:
NRC Inspection Report 05000275/2006005
and 05000323/2006005
w/attachment: Supplemental Information
cc w/enclosure:
Donna Jacobs
Vice President, Nuclear Services
Diablo Canyon Power Plant
P.O. Box 56
Avila Beach, CA 93424
James R. Becker, Vice President
Diablo Canyon Operations and
Station Director, Pacific Gas and
Electric Company
Diablo Canyon Power Plant
P.O. Box 56
Avila Beach, CA 93424
Sierra Club San Lucia Chapter
ATTN: Andrew Christie
P.O. Box 15755
San Luis Obispo, CA 93406
Pacific Gas and Electric Company -3-
Nancy Culver
San Luis Obispo Mothers for Peace
P.O. Box 164
Pismo Beach, CA 93448
Chairman
San Luis Obispo County Board of
Supervisors
County Government Building
1055 Monterey Street, Suite D430
San Luis Obispo, CA 93408
Truman Burns\Robert Kinosian
California Public Utilities Commission
505 Van Ness Ave., Rm. 4102
San Francisco, CA 94102-3298
Diablo Canyon Independent Safety Committee
Robert R. Wellington, Esq.
Legal Counsel
857 Cass Street, Suite D
Monterey, CA 93940
Director, Radiological Health Branch
State Department of Health Services
P.O. Box 997414 (MS 7610)
Sacramento, CA 95899-7414
Antonio Fernandez, Esq.
Pacific Gas and Electric Company
P.O. Box 7442
San Francisco, CA 94120
City Editor
The Tribune
3825 South Higuera Street
P.O. Box 112
San Luis Obispo, CA 93406-0112
James D. Boyd, Commissioner
California Energy Commission
1516 Ninth Street (MS 34)
Sacramento, CA 95814
Pacific Gas and Electric Company -4-
Jennifer Tang
Field Representative
United States Senator Barbara Boxer
1700 Montgomery Street, Suite 240
San Francisco, CA 94111
Chief, Radiological Emergency
Preparedness Section
Oakland Field Office
Chemical and Nuclear Preparedness
and Protection Division
Department of Homeland Security
1111 Broadway, Suite 1200
Oakland, CA 94607-4052
Pacific Gas and Electric Company -5-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
DRS Deputy Director (RJC1)
Senior Resident Inspector (TWJ)
Branch Chief, DRP/B (VGG)
Senior Project Engineer, DRP/E (FLB2)
Team Leader, DRP/TSS (RLN1)
RITS Coordinator (MSH3)
V. Dricks, PAO (VLD)
D. Cullison, OEDO RIV Coordinator (DGC)
ROPreports
DC Site Secretary (AWC1)
W. A. Maier, RSLO (WAM)
R. E. Kahler, NSIR (REK)
SUNSI Review Completed: __yes___ ADAMS: G Yes G No Initials: __vgg___
G Publicly Available G Non-Publicly Available G Sensitive G Non-Sensitive
R:\_REACTORS\_DC\2006\DC2006-05RP-TWJ.wpd
RIV:RI:DRP/B RI:DRP/B SRI:DRP/B C:DRS/OB
TAMcConnell MABrown TWJackson ATGody
T - VGGaddy T - VGGaddy T - VGGaddy /RA/
2/9/07 2/9/07 2/9/07 1/31/07
DRS:PSB DRS:EB1 DRS:EB2 C:DRP/B
MPShannon WBJones LJSmith VGGaddy
/RA/ /RA/ /RA/ /RA/
2/1/07 1/31/07 1/30/07 2/13/07
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets: 50-275, 50-323
Report: 05000275/2006005
Licensee: Pacific Gas and Electric Company
Facility: Diablo Canyon Power Plant, Units 1 and 2
Location: 7 1/2 miles NW of Avila Beach
Avila Beach, California
Dates: October 1 through December 31, 2006
Inspectors: T. Jackson, Senior Resident Inspector
T. McConnell, Resident Inspector
M. Brown, Resident Inspector
M. Peck, Senior Resident Inspector - Callaway Plant
J. Dodson, Regional Operations Officer
J. Drake, Operation Engineer
P. Goldberg, Reactor Inspector
R. Kellar, Health Physicist
R. Lantz, Senior Emergency Preparedness Inspector
Approved By: V. G. Gaddy, Chief, Projects Branch B
Division of Reactor Projects
-1- Enclosure
TABLE OF CONTENTS
PAGE
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
REACTOR SAFETY
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R07 Biennial Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R13 Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 12
1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
1EP1 Exercise Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
OTHER ACTIVITIES
40A1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
4OA5 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4OA6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
ATTACHMENT: SUPPLEMENTAL INFORMATION
Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
Items Opened, Closed and Discussed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-13
-2- Enclosure
SUMMARY OF FINDINGS
IR 05000275/2006-005, 05000323/2006-005; 10/1/06 - 12/31/06; Diablo Canyon Power Plant
Units 1 and 2; Maintenance Risk Assessments and Emergent Work Control, Problem
Identification and Resolution, Operability Evaluations, and Other Activities.
This report covered a 13-week period of inspection by resident inspectors and Region-based
health physics and reactor inspectors. Three NRC-identified and one self-revealing, Green,
noncited violations were identified. The significance of most findings is indicated by their color
(Green, White, Yellow, or Red) using Inspection Manual Chapter 0609 Significance
Determination Process. Findings for which the Significance Determination Process does not
apply may be Green or be assigned a severity level after NRC management review. The
NRCs 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 Findings
Cornerstone: Initiating Events
- Green. A self-revealing, noncited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, was identified for the failure to apply adequate
design control measures regarding the installation of thimble tubes with chrome-
plated bands. Specifically, Pacific Gas and Electric Company installed thimble
tubes with chrome-plated bands at the fuel assembly bottom nozzle/lower core
plate interface to address flow-induced vibration wear. Due to the failure of
engineering personnel to account for the chrome-plated bands in the thimble
tube relocation procedure, the chrome-plated band on Thimble Tube L-13 was
removed from its designed location at the fuel assembly bottom nozzle, thereby
increasing the potential for thimble tube through-wall wear. This issue was
entered into Pacific Gas and Electric Companys corrective action program as
Nonconformance Report N0002211.
The finding is greater than minor because it is associated with the Initiating
Events Cornerstone attribute of design control and affects the associated
cornerstone objective to limit the likelihood of those events that upset plant
stability and challenge critical safety functions during shutdown as well as power
operations. Using the Inspection Manual Chapter 0609, Significance
Determination Process, Phase 1 Worksheet, the finding is determined to have
very low safety significance because, assuming the worst-case degradation, the
finding would not result in exceeding the Technical Specification limit for
identified reactor coolant system leakage or affect mitigating systems.
Specifically, the inspectors verified the worst-case leakage, i.e., guillotine break,
from a thimble tube at the fuel assembly bottom nozzle/lower core plate interface
to be approximately 7 gpm versus the Technical Specification reactor coolant
system identified leakage limit of 10 gpm. The finding has a crosscutting aspect
in the area of problem identification and resolution associated with the corrective
action program because Pacific Gas and Electric Company removed a corrective
action to prevent recurrence of significant thimble tube wear (Section 4OA5.5).
-3- Enclosure
Cornerstone: Mitigating Systems
- Green. An NRC-identified, noncited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Actions, was identified for the failure to promptly
correct a condition adverse to quality. Specifically, on October 15, 2006, Pacific
Gas and Electric Company implemented a temporary modification to Vital
Battery 1-1 contrary to American National Standards Institute/Institute of
Electrical and Electronics Engineers Standard 450-1995, "IEEE Recommended
Practice for Maintenance, Testing, and Replacement of Large Lead Storage
Batteries for Generating Stations and Substations. Additionally, surveillance
tests to monitor the condition of the degraded battery cell were adversely
affected by the installed temporary modification. This issue was entered into
Pacific Gas and Electric Companys corrective action program as Action
Request A0678820.
The finding is greater than minor because it is associated with the Mitigating
Systems Cornerstone attribute of equipment performance and affects the
associated cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Using the Manual Chapter 0609, Significance Determination
Process, Phase 1 Worksheet, the inspectors determined that this finding is of
very low safety significance because it did not represent an actual loss of safety
function of a single train for greater than its Technical Specification allowed
outage time. This finding has a crosscutting aspect in the area of problem
identification and resolution associated with the corrective action program in that
engineering staff did not thoroughly assess the operability of the battery and
correct a condition adverse to quality in a timely manner (Section 1R15).
- Green. An NRC-identified, noncited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, was determined for the failure of engineering
personnel to apply adequate design control measures. Specifically, on
February 9, 2006, engineering personnel changed the acceptance criteria in the
auxiliary saltwater pump surveillance test from greater than zero packing leak-off
to zero packing leak-off with packing gland temperature less than 120EF. The
acceptance criteria change was based on engineering judgment, even though
vendor documentation called for greater than zero packing leak-off to prevent
packing and pump shaft damage. This issue was entered into Pacific Gas and
Electric Companys corrective action program as Action Request A0684631.
The finding is greater than minor because it is associated with the Mitigating
Systems Cornerstone attribute of procedure quality and affects the associated
cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences.
Using the Manual Chapter 0609, Significance Determination Process, Phase 1
Worksheet, the finding is determined to be of very low safety significance
because it did not represent an actual loss of system safety function, did not
represent an actual loss of a single train for greater than its Technical
-4- Enclosure
Specification allowed outage time, and the finding did not screen as potentially
risk significant due to a seismic, flooding, or severe weather initiating event. This
finding has a crosscutting aspect in the area of human performance associated
with resources because engineering personnel failed to provide up-to-date
design documentation to support a design change in surveillance test
acceptance criteria (Section 4OA2.2).
Cornerstone: Barrier Integrity
- Green. An NRC-identified, noncited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Actions, was determined for the failure of engineering
and operations personnel to promptly identify and correct a condition adverse to
quality. On two occasions between September 29 and November 9, 2006,
operations and engineering personnel: (1) failed to address operability when
using manual actions in place of automatic actions associated with the auxiliary
building ventilation system and (2) failed to fully address the impact of debris
between the circuit card and the panel connections of the auxiliary building
ventilation system. This issue was entered into Pacific Gas and Electric
Companys corrective action program as Action Request A0678429.
The finding is greater than minor because it is associated with the Barrier
Integrity Cornerstone attribute of structure, system, component, and barrier
performance and affects the associated cornerstone objective to provide
reasonable assurance that physical design barriers protect the public from
radionuclide releases caused by accidents or events. Using the Inspection
Manual Chapter 0609, "Significance Determination Process," Phase 1
Worksheet, the finding is determined to have very low safety significance
because the finding only represents a degradation of the radiological barrier
function provided for the auxiliary building. This finding has a crosscutting
aspect in the area of problem identification and resolution associated with the
corrective action program because operations and engineering personnel did not
adequately evaluate operability of the auxiliary building ventilation system due to
the failure to fully encompass all aspects of the degraded conditions and
corresponding compensatory measures (Section 1R13).
-5- Enclosure
REPORT DETAILS
Summary of Plant Status
Diablo Canyon Unit 1 began this inspection period at 100 percent power. On
November 26, 2006, operators reduced power to 50 percent for circulating water tunnel
cleaning. Upon completion of the maintenance, reactor power was returned to 100 percent on
December 1 and maintained that power level for the remainder of the inspection period.
Diablo Canyon Unit 2 began this inspection period at 100 percent power. On December 10,
operators reduced power and manually tripped the reactor due to indications of Reactor
Coolant Pump (RCP) 2-2 high stator temperature. Following repair activities, operators
restarted the Unit 2 reactor on December 11, entering Mode 2 (startup). On December 11,
while reactor power was being restored to 100 percent, Circulating Water Pump (CWP) 2-1
experienced an electrical short at the motor terminal leads, resulting in a reactor trip. Following
repair activities, operators restarted the Unit 2 reactor on December 12, entering Mode 2.
Reactor power was returned to 100 percent on December 19 and remained at that power level
for the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R05 Fire Protection (71111.05)
Quarterly Inspection
a. Inspection Scope
The inspectors walked down the six below listed plant areas to assess the material
condition of active 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 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 Final Safety Analysis Report (FSAR) Update to determine if Pacific
Gas and Electric Company (PG&E) identified and corrected fire protection problems.
- October 3, 2006, Unit 1, Control Room Cable Spreading Room
- October 3, 2006, Unit 2, Control Room Cable Spreading Room
-6- Enclosure
- October 10, 2006, Unit 1, Diesel Engine Generator Rooms
- October 10, 2006, Unit 2, Diesel Engine Generator Rooms
- October 11, 2006, Units 1 and 2, 140' and 85' elevation fire equipment storage
lockers
- December 28, 2006, Unit 1, 85' elevation turbine building
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples.
b. Findings
No findings of significance were identified.
1R07 Biennial Heat Sink Performance (71111.07B)
.1 Performance of Testing, Maintenance and Inspection Activities
a. Inspection Scope
The inspectors selected three heat exchangers that were either directly or indirectly
connected to the safety-related service water system. The inspectors reviewed PG&E's
test and cleaning methodology for the following heat exchangers:
- Emergency Core Cooling System Pump Lube Oil Coolers
- Containment Fan Cooler Units
- Residual Heat Removal (RHR) Heat Exchangers
In addition, the inspectors reviewed test data and inspection and cleaning records for
the heat exchangers and design and vendor-supplied information to ensure that the heat
exchangers were performing within their design bases. The inspectors also reviewed
chemical controls to avoid fouling, the heat exchanger test, and inspection and cleaning
results. Specifically, the inspectors reviewed design conditions, appropriate use of test
instrumentation, and appropriate accounting for instrument inaccuracies. Additionally,
the inspectors reviewed inspection and cleaning results and trending results, if available.
The inspectors reviewed the methods and results of heat exchanger inspection and
cleaning to verify that the methods used to inspect and clean were consistent with
industry standards. The results were found appropriately dispositioned such that the
final conditions were acceptable.
The inspectors completed three samples.
-7- Enclosure
b. Findings
No findings of significance were identified.
.2 Verification of Conditions and Operations Consistent with Design Bases
a. Inspection Scope
For the selected heat exchangers, the inspectors reviewed the documents listed in the
attachment to verify that PG&E established heat sink and heat exchanger condition and
that operation and test criteria were consistent with the design assumptions.
Specifically, the inspectors reviewed the applicable calculations to ensure that the
thermal performance test acceptance criteria for the heat exchangers were being
applied consistently throughout the calculations. The inspectors also reviewed
documents in order to verify that the appropriate acceptance values for fouling and tube
plugging for the heat exchangers cooled by the component cooling water heat
exchangers remained consistent with the values used in the design-basis calculations.
b. Findings
Introduction: An unresolved item (URI) was identified regarding inadequate design
control measures for verifying the adequacy of the safety-related RHR system heat
exchangers. PG&E stated that the RHR heat exchangers were not inspected and
cleaned, due to as low as is reasonably achievable (ALARA) considerations, and the
heat exchangers were not tested. Test Procedure STP V-13A, CCW Flow Balancing,
along with Calculation M-1017, Component Cooling Water System, were used by
PG&E to determine if the RHR heat exchanger would meet its design basis. The
calculation only establishes the flow balance for the component cooling water (CCW)
system based on PG&Es modeling assumptions. This issue is unresolved for both
significance and enforcement, since additional technical review by NRC was needed to
assess this issue.
Description: The inspectors reviewed Calculation M-1017, Component Cooling Water
System, Revision 3, and found that the purpose of the calculation was to compute the
flow rates in the CCW system for input into the accident analysis. The inspectors noted
that the calculation only established the flow balance of the CCW system based on
PG&Es modeling assumption. The calculation did not address the heat transfer
capability of any of the heat exchangers and the references listed did not appear to
provide heat transfer capability. The inspectors noted that the assumptions used by
PG&E could vary the results of the calculation. Some of the assumptions were: the
manufacturers pressure drop data for the CCW, RHR, and containment fan cooling
unit (CFCU) heat exchangers was assumed to be accurate; the RHR heat exchanger
throttle valve was assumed to be in the full open position without verification; and even
though the CCW systems of Units 1 and 2 are slightly different, PG&E concluded that
the results of Unit 1 were applicable for Unit 2. Any of these assumptions, if incorrect,
could change the results.
-8- Enclosure
The inspectors reviewed Surveillance Test Procedure STP-V13A, CCW Flow
Balancing, Revision 15. The purpose of the test is to adjust the CCW flow to assure
that the CCW system will supply sufficient flow to vital equipment without exceeding the
CCW design temperature limitations during the worst-case accident conditions. The
inspectors noted that the test was conducted with CCW flow to Vital Headers A and B.
The flow is balanced using the CFCU CCW throttling valve. Flow to each CFCU is
adjusted to establish a flow rate between the minimum and maximum flow limitations.
Based on the known hydraulics of the CCW system, when the CCW flow to each CFCU
is throttled to within the desired range, the overall header will be appropriately balanced.
The inspectors noted that, during the test, CCW flow to the RHR heat exchangers was
secured.
The inspectors reviewed Action Request (AR) A0588366, initiated on August 3, 2003,
which was written to develop a heat exchanger program to test and monitor heat
exchangers. Based on engineering judgement, PG&E decided that preventive
maintenance on the RHR heat exchangers could not be justified based on ALARA
concerns and dose considerations. The inspectors noted that performance monitoring
and trending were recommended to ensure that heat exchangers do not fail to perform
their safety function. However, the RHR heat exchangers were not recommended for
monitoring and trending. The inspectors found that the RHR heat exchangers were not
tested, not inspected and cleaned, and not monitored and trended. The inspectors
determined that PG&E had not demonstrated that the RHR heat exchangers would
meet their safety function.
PG&E stated that they would send additional material for the inspectors to review in
order to demonstrate that the RHR heat exchangers would perform their safety function.
Analysis: At the time of writing, PG&E had not demonstrated that the RHR heat
exchangers would meet their safety function. This issue is potentially more than minor
because it could affect the Mitigating Systems Cornerstone objective by causing the
safety-related RHR system to not transfer sufficient heat to the CCW system to support
the safety-related systems.
Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in
part, that design control measures shall provide for verifying or checking the adequacy
of the design, such as by the performance of design reviews, by the use of alternative or
simplified calculation methods, or by performance of a suitable testing program.
Additional review by NRC is needed to determine if the RHR heat exchangers would
meet their design safety function. Therefore, this item will be treated as a URI pending
additional review: URI 50-275; 323/06-05-01, Additional Review of Material to
Determine if the RHR Heat Exchangers Will Meet Their Safety Function.
-9- Enclosure
.3 Identification and Resolution of Problems
a. Inspection Scope
The inspectors verified that PG&E had entered significant heat exchanger/heat sink
performance problems into the corrective action program (CAP). The inspectors
reviewed 17 ARs.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
a. Inspection Scope
On November 28, 2006, the inspectors observed testing and training of senior reactor
operators and reactor operators to identify deficiencies and discrepancies in the training,
to assess operator performance, and to assess the evaluators critique. The training
scenario involved a volume control tank rupture, an auxiliary saltwater pump trip, an
earthquake, and an anticipated transient without scram. Documents reviewed by the
inspectors included:
- Lesson FRS1-B, ATWS, Revision 10
- Procedure EP G-1, Emergency Classification and Emergency Plan Activation,
Revision 34
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
.1 Routine Maintenance Effectiveness Inspection
a. Inspection Scope
The inspectors reviewed the one below listed maintenance activity to: (1) verify the
appropriate handling of structure, system, and component (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 Technical Specifications (TS).
-10- Enclosure
- November 7, 2006, Unit 1, Auxiliary Feedwater System Discharge
Valves FW-1-LCV-113/115
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1 Risk Assessments and Management of Risk
a. Inspection Scope
The inspectors reviewed the three below listed assessment activities to verify:
(1) performance of risk assessments when required by 10 CFR 50.65(a)(4) and PG&E
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 PG&E recognizes, and/or enters as
applicable, the appropriate risk category according to the risk assessment results and
PG&E procedures; and (4) PG&E identified and corrected problems related to
maintenance risk assessments.
- October 4, 2006, Unit 1, Preventive maintenance on Auxiliary Saltwater Cross-tie
Valve SW-0-FCV-601, RCP undervoltage/under-frequency relay testing, and
Morro Bay - Diablo Canyon 230 kV line outage
- October 9, 2006, Unit 2, Planned maintenance outage of condensate booster
pump
- November 17, 2006, Unit 1, Installation of cell jumper on Vital Battery 1-1
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed three samples.
b. Findings
No findings of significance were identified.
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.2 Emergent Work
a. Inspection Scope
The inspectors: (1) verified that PG&E performed actions to minimize the probability of
initiating events and maintained the functional capability of mitigating systems and
barrier integrity systems; (2) verified that emergent work-related activities, such as
troubleshooting, work planning/scheduling, establishing plant conditions, aligning
equipment, tagging, temporary modifications, and equipment restoration did not place
the plant in an unacceptable configuration; and (3) reviewed the FSAR Update to
determine if PG&E identified and corrected risk assessment and emergent work control
problems.
- September 26, 2006, Unit 1, Emergent failure of POV-1 ventilation logic cabinet
- October 9, 2006, Unit 1, Emergent failure of a reactor protection channel
- November 3, 2006, Units 1 and 2, 230 kV disconnect switch warm termination
- November 22, 2006, Units 1 and 2, Hydrochloric acid developed by auxiliary
saltwater piping cathodic protection
- December 18, 2006, Unit 2, Indication of nuclear fuel leak
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed five samples.
b. Findings
Introduction: A Green NRC-identified, noncited violation (NCV) of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Actions, was determined for the failure of
engineering and operations personnel to promptly identify and correct a condition
adverse to quality. On two occasions regarding poor circuit card connections in the
auxiliary building ventilation control panel, operations and engineering personnel:
(1) failed to address operability when using manual actions in place of automatic actions
and (2) failed to fully address the impact of debris between circuit card and panel
connections.
Description: On September 27, 2006, the Unit 1 Auxiliary Building Ventilation System
Train B control panel (POV-2) was de-energized for planned maintenance. Shortly
thereafter, the Train A control panel (POV-1) ac power controller tripped. At the time,
both cabinets were declared inoperable and TS 3.0.3 was entered. Control Panel
POV-2 panel was returned to service and operators moved from TS 3.0.3 to TS 3.7.12
for having one train of the auxiliary building ventilation system inoperable. To facilitate
troubleshooting and repairs, on September 29, maintenance personnel de-energized
both Panels POV-1 and POV-2. De-energizing the control panels placed the system
dampers in their safety-related position. Additionally, operators manually started one
-12- Enclosure
auxiliary building exhaust fan and planned to manually start the other exhaust fan if
needed during a design basis event. The controls for the auxiliary building exhaust fans
were located in the cable spreading room. Operators subsequently declared both trains
of the ventilation system operable and exited TS 3.7.12.
The inspectors questioned the decision to declare the train with the standby exhaust fan
fully operable by taking credit for manual actions to start the fan during a design basis
event. The attachment to Regulatory Information Summary 2005-20, Part 9900
Technical Guidance Operability Determinations & Functionality Assessments for
Resolution of Degraded or Nonconforming Conditions Adverse to Quality of Safety,
Section C.5, states that substitution of manual actions for automatic actions requires an
operability determination. However, an operability determination was not performed. In
response to NRC questioning, operators declared Control Panel POV-1 inoperable and
re-entered TS 3.7.12. The inspectors observed that operators would have been able to
start the standby exhaust fan had it been necessary; therefore, they would have been
able to produce an operability determination.
Subsequent troubleshooting revealed the cause of the Control Panel POV-1 power
supply to trip was oxidation buildup and dust collection on the terminals. An interlock
feature on the control panels de-energizes the panel if a circuit card becomes loose.
Control Panel POV-2 was also inspected and several loose cards were found and
cleaned. The extent of condition review by engineering personnel concluded that the
Unit 2 control panels were not affected due to the interlock feature being disabled.
Unit 2 Control Panel POV-1 was inspected on November 9, 2006, during a scheduled
card replacement. Nine cards were found to have loose connections, and these cards
were cleaned and reinstalled. Unit 2 Control Panel POV-2 was scheduled for inspection
in April 2007.
The inspectors concluded that engineering personnel had failed to adequately address
operability of the Units 1 and 2 auxiliary building ventilation system control panels.
Engineering and maintenance staff were aware that debris was being blown onto the
control panel circuit cards by the panels ventilation fans. The debris would work its way
between the circuit card and panel connection points and cause the poor connections.
During a design basis event, particularly a seismic event, the connections may not
provide an adequate circuit path. While engineering staff discussed the fact that the
interlock feature would not de-energize the control panels if a loose card were detected,
their assessment did not discuss the affect of the debris on other connection points and
what the impact that would have on the auxiliary building ventilation system. The
inspectors did observe that any loose connection would still provide an alarm to the
control room operators and failure of the control panels would move the dampers to their
safety-related position. Additionally, operators would be able to manually control the
exhaust fans. Therefore, engineering staff had a basis for determining that the control
panels were degraded but operable, but failed to provide this basis in a timely manner.
Analysis: The performance deficiency associated with this finding involved two
examples where PG&E personnel failed to perform an adequate operability
determination. The finding is greater than minor because it is associated with the
Barrier Integrity Cornerstone attribute of SSC and barrier performance and affects the
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associated cornerstone objective to provide reasonable assurance that physical design
barriers protect the public from radionuclide releases caused by accidents or events.
Using the Inspection Manual Chapter 0609, "Significance Determination Process,"
Phase 1 Worksheet, the finding is determined to have very low safety significance
because the finding only represents a degradation of the radiological barrier function
provided for the auxiliary building. This finding has a crosscutting aspect in the area of
problem identification and resolution associated with the CAP because operations and
engineering personnel did not adequately evaluate operability of the auxiliary building
ventilation system regarding use of manual actions and the full impact of debris on
circuit card connections.
Enforcement: 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires,
in part, that measures be established to assure that conditions adverse to quality are
promptly identified and corrected. Contrary to this, on two occasions between
September 29 and November 9, 2006, PG&E staff failed to promptly identify and correct
a condition adverse to quality when they failed to adequately evaluate operability of the
auxiliary building ventilation system. In the first example, operations personnel credited
manual actions in place of automatic safety actions without evaluating the capability of
those actions in an operability determination. In the second example, engineering
personnel failed to fully address the effect of debris between circuit card connections
and their impact on system operability. Because the finding is of very low safety
significance and has been entered into the CAP as AR A0678429, this violation is being
treated as an NCV consistent with Section VI.A of the Enforcement Policy:
NCV 50-275; 323/06-05-02, Failure to Adequately Evaluate Operability of Auxiliary
Building Ventilation Control Panels.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors: (1) reviewed plant 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 FSAR Update and design bases documents to review the technical
adequacy of the operability evaluations; (3) evaluated compensatory measures
associated with operability evaluations; (4) determined degraded component impact on
any TS; (6) used the Significance Determination Process to evaluate the risk
significance of degraded or inoperable equipment; and (5) verified that PG&E has
identified and implemented appropriate corrective actions associated with degraded
components.
- October 17, 2006, Unit 2, Valves FW-2-LCV-111 and FW-2-LCV-115 placed in
manual due to 10 CFR Part 21 Notice
- October 30, 2006, Unit 1, Diesel Engine Generator 1-3 slow to reach rated
speed during surveillance test
- November 13, 2006, Unit 1, Vital Battery 1-1 Cell 15 low voltage
-14- Enclosure
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed three samples.
b. Findings
Introduction: An NRC-identified, NCV of 10 CFR Part 50, Appendix B, Criterion XVI,
Corrective Actions, was identified for the failure to promptly correct a condition adverse
to quality. Specifically, on October 15, 2006, PG&E implemented a temporary
modification to Vital Battery 1-1, contrary to American National Standards
Institute/Institute of Electrical and Electronics Engineers (ANSI/IEEE) Standard
450-1987, "IEEE Recommended Practice for Maintenance, Testing, and Replacement
of Large Lead Storage Batteries for Generating Stations and Substations. Additionally,
surveillance tests to monitor the condition of the degraded battery cell were adversely
affected by the installed temporary modification.
Description: The vital batteries are required to provide adequate power to loads
necessary for plant cooldown during a station blackout. The battery system consists of
three, 60-cell, 125 V battery banks with five battery chargers. Two chargers are capable
of charging Battery 1-1. However, in the event of a loss of vital 480 V Bus 1F, Battery
Charger 121 could be manually aligned to restore power to direct current (dc) loads
associated with Battery 1-1. In the event of a loss of vital 480 V Bus 1F, Battery 1-1
supplies the following risk significant loads: Diesel Engine Generator 1-2 engine panel
emergency source, solid-state protection system Train A; main steam isolation valves
and 10 percent steam dump circuitry, vital 120 V Inverter IY 1-1, and Diesel Engine
Generator 1-3 normal gage panel power. Calculation 235A-DC, Battery 11 Sizing,
Load Flow, Voltage Drop, Short Circuit and Charger Sizing, Revision 8, determined the
minimum number of cells for each operable bank to be 59 cells.
On October 3, 2006, Battery 1-1, Cell 15 indicated a low voltage of 2.093 V during the
performance of Surveillance Test Procedure STP M-11A, "Station Battery and Pilot Cell
Condition Monitoring," Revision 19. The TS 3.8.4 limit for cell voltage is 2.07 V. The
battery was subsequently placed on equalizing charge in an attempt to restore voltage.
This attempt was not successful and an individual cell equalizing charge was
commenced on October 11. On October 15, maintenance personnel installed an
individual cell charger on Cell 15 as a temporary modification. The charger was
adjusted to a float voltage charge of 2.25 V as a compensatory measure to ensure
battery operability.
On October 16, the inspectors engaged PG&E staff regarding the operability of
Battery 1-1, while an individual cell charger was installed to maintain Cell 15 at the
battery average voltage. In the event of a station blackout, the degraded cell could
adversely impact Battery 1-1 by becoming an additional load on the battery (i.e., reverse
polarizing). Engineering staff assumed that, during a battery discharge, Cell 15 voltage
would drop at the same rate as the other battery cells. Therefore, if the individual cell
charger maintained Cell 15 voltage at the same voltage level as the overall battery, the
cell would not become an additional load during battery discharge. However, the
-15- Enclosure
inspectors observed that engineering staff did not have analysis, test data, or other
information to support the assumption. In discussions with the battery vendor (C&D
Power Systems), engineering staff determined that it is not known at what point or how
much, if any, that having a degraded cell would affect battery performance. According
to ANSI/IEEE Standard 450-1987, "IEEE Recommended Practice for Maintenance,
Testing, and Replacement of Large Lead Storage Batteries for Generating Stations and
Substations," there are specified methods to correct battery cell deficiencies. This
industry standard stated that, if a cell is not recoverable through equalizing charges, it
should be removed from service. The inspectors noted that the staff had not provided
sufficient tests, analyses, or other evidence that supported the installation of a cell
charger for battery operability.
On November 17, Cell 15 was isolated electrically from Battery 1-1 by installing jumper
cables. This action restored Battery 1-1 to an analyzed, operable condition of 59 fully
functional cells. PG&E waited approximately 33 days to install the jumper cables since
they were waiting for a response on a license amendment request to extend the current
TS 3.8.4 allowed outage time from 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. On November 15, PG&E
received a one-time license amendment to extend the allowed outage time to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
The evolution on November 17 took approximately 74 minutes, which was within the
original allowed outage time of 120 minutes. The inspectors also noted that prior mock-
ups of the jumper installation demonstrated that the evolution could be completed in less
than the TS allowed outage time.
Analysis: The performance deficiency associated with this finding involved the failure of
engineering personnel to properly implement measures to correct a condition adverse to
quality. The finding is greater than minor because it is associated with the Mitigating
Systems Cornerstone attribute of equipment performance and affects the associated
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Using the Manual
Chapter 0609, Significance Determination Process, Phase 1 worksheets, the
inspectors determined that this finding is of very low safety significance because it did
not represent an actual loss of safety function of a single train for greater than its TS
allowed outage time. This finding has a crosscutting aspect in the area of problem
identification and resolution associated with the CAP in that engineering staff did not
thoroughly assess the operability of the battery and correct a condition adverse to
quality in a timely manner.
Enforcement: 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that
measures be established to assure that significant conditions adverse to quality, such as
deficiencies, defective material and equipment, and nonconformances, are promptly
identified and corrected. Contrary to this requirement, from October 15 to
November 17, 2006, PG&E implemented a temporary modification that had not been
adequately analyzed for its effect on battery operability and was contrary to committed
industry standards. As a result, PG&E failed to correct a condition adverse to quality in
a timely manner. This finding is of very low safety significance and has been entered
into the CAP as AR A0678820. This violation is being treated as an NCV, consistent
with Section VI.A of the NRC Enforcement Policy: NCV 50-275/06-05-03, Inadequate
Temporary Modification to a Vital Battery.
-16- Enclosure
1R17 Permanent Plant Modifications (71111.17)
a. Inspection Scope
The inspectors reviewed key affected parameters associated with energy needs,
materials/replacement components, timing, heat removal, control signals, equipment
protection from hazards, operations, flowpaths, pressure boundary, ventilation
boundary, structural, process medium properties, licensing basis, and failure modes for
the one modification listed below. The inspectors verified that: (1) modification
preparation, staging, and implementation did not impair emergency/abnormal operating
procedure actions, key safety functions, or operator response to loss of key safety
functions; (2) postmodification testing maintained the plant in a safe configuration during
testing by verifying that unintended system interactions will not occur, SSC performance
characteristics still meet the design basis, the appropriateness of modification design
assumptions, and the modification test acceptance criteria has been met; and (3) PG&E
has identified and implemented appropriate corrective actions associated with
permanent plant modifications.
- September 29, 2006, Unit 1, Modification of Excess Letdown Heat Exchanger
Outlet Valve Controller HCV-123 with a 60-ohm resistor
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors selected the four below listed postmaintenance test activities of risk-
significant systems 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 realigned, and deficiencies during
testing were documented. The inspectors also reviewed the FSAR Update to determine
if PG&E identified and corrected problems related to postmaintenance testing.
- September 26, 2006, Unit 1, Excess letdown Heat Exchanger Valve HCV-123
- October 3, 2006, Unit 1, Auxiliary Building Ventilation System, POV-1/POV-2
-17- Enclosure
- October 4, 2006, Unit 1, Auxiliary Saltwater Unit Cross-tie Valve SW-0-FCV-601
- November 1, 2006, Unit 1, Safety Injection Pump 1-1
Documents reviewed by the inspectors included:
- Procedure LT 8-82, CVCS Excess Letdown Heat Exchanger Outlet HCV-123
Calibration, Revision 1
- Procedure STP V-3F3, Exercising Valve FCV-601, Units 1 and 2 ASW
Cross-tie, Revision 16
- Procedure PEP 23-01, Aux Building and Fuel Handling Building Ventilation
Systems Fan Failure Tests and Miscellaneous POV Tests, Revision 8
- Procedure STP P-SIP-11, Routine Surveillance Test of Safety Injection
Pump 1-1, Revision 19
The inspectors completed four samples.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the FSAR Update, procedure requirements, and TS to ensure
that the two below 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) jumpers; (7) test data;
(8) testing frequency and method demonstrated TS operability; (9) test equipment
removal; (10) restoration of plant systems; (11) fulfillment of American Society of
Mechanical Engineers Code requirements; (12) updating of performance indicator data;
(13) accuracy of engineering evaluations, root causes, and bases for returning tested
SSCs not meeting the test acceptance criteria; (14) reference setting data; and
(15) annunciators and alarm setpoints. The inspectors also verified that PG&E identified
and implemented any needed corrective actions associated with the surveillance testing.
- November 1, 2006, Unit 1, Eagle-21 partial trip board activation test
- December 6, 2006, Unit 2, In-Service Testing of Auxiliary Feedwater Level
Control Valve FW-2-LCV-113
Documents reviewed by the inspectors included:
-18- Enclosure
- Procedure STP- I-36-S1EPT, Protection Set 1 Eagle-21 Partial Trip Board
Activation Test, Revision 12
- Procedure STP V-3P6B, Exercising Valves LCV-115 and 113 Auxiliary
Feedwater Pump Discharge, Revision 13
The inspectors completed two samples.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors reviewed the FSAR Update, plant drawings, procedure requirements,
and TS to ensure that the one 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 postinstallation test results were satisfactory
and that the impact of the temporary modifications on permanently installed SSCs were
supported by the test; (4) verified that the modifications were identified on control room
drawings and that appropriate identification tags were placed on the affected drawings;
and (5) verified that appropriate safety evaluations were completed. The inspectors
verified that PG&E identified and implemented any needed corrective actions associated
with temporary modifications.
- November 16, 2006, Unit 1, Installation of jumper in Vital Battery 1-1
Documents reviewed by the inspectors included:
- Work Order C0207140
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
-19- Enclosure
1EP1 Exercise Evaluation (71114.01)
Cornerstone: Emergency Preparedness
a. Inspection Scope
The inspectors reviewed the objectives and scenario for the 2006 biennial emergency
plan exercise to determine if the exercise would acceptably test major elements of the
emergency plan. The scenario simulated a large condenser tube leak, with a
subsequent failure of the reactor protection system to complete a reactor scram.
Multiple main steam isolation valve failures then resulted in initiation of a small release
of radioactivity to the environment. An initially small reactor coolant leak in containment
greatly increased, ultimately resulting in a loss of reactor vessel level, core uncovering
and damage of reactor fuel, with a rapid increase in the offsite release of radioactivity to
the environment.
The inspectors evaluated exercise performance by focusing on the risk-significant
activities of event classification, offsite notification, recognition of offsite dose
consequences, and development of protective action recommendations, in the simulator
control room and the following dedicated emergency response facilities:
- Operations Support Center
- Emergency Operations Facility
The inspectors also assessed recognition of and response to abnormal and emergency
plant conditions, the transfer of decision making authority and emergency function
responsibilities between facilities, onsite and offsite communications, protection of
emergency workers, emergency repair evaluation and capability, and the overall
implementation of the emergency plan to protect public health and safety and the
environment. The inspectors reviewed the current revision of the facility emergency
plan, and emergency plan implementing procedures associated with operation of the
above facilities and performance of the associated emergency functions. These
procedures are listed in the Attachment to this report.
The inspectors compared the observed exercise performance to the requirements in the
facility emergency plan, 10 CFR 50.47(b), 10 CFR Part 50, Appendix E, and to the
guidance in the emergency plan implementing procedures and other federal guidance.
The inspectors attended the post-exercise critiques in each of the above facilities to
evaluate the initial licensee self-assessment of exercise performance. The inspectors
also attended a subsequent formal presentation of critique items to plant management.
The inspectors completed one sample during this inspection.
b. Findings
No findings of significance were identified.
-20- Enclosure
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
a. Inspection Scope
The inspectors reviewed licensee evaluations for the three emergency preparedness
cornerstone performance indicators of Drill and Exercise Performance, Emergency
Response Organization Participation, and Alert and Notification System Reliability, for
the period October 1, 2005, through September 30, 2006. The definitions and guidance
of NEI 99-02, "Regulatory Assessment Indicator Guideline," Revisions 3 and 4, and the
licensee Emergency Plan Instruction 18, "Emergency Preparedness NRC Performance
Indicators," 6/15/2006, were used to verify the accuracy of the licensees evaluations for
each performance indicator reported during the assessment period.
The inspectors reviewed a sample of drill and exercise scenarios and licensed operator
simulator training sessions, notification forms, and attendance and critique records
associated with training sessions, drills, and exercises conducted during the verification
period. The inspectors reviewed selected emergency responder qualification, training,
and drill participation records. The inspectors reviewed alert and notification system
testing procedures, maintenance records, and a 100 percent sample of siren test
records. The inspectors also reviewed other documents listed in the Attachment to this
report.
The inspectors completed three samples during the inspection.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
The inspectors performed a daily screening of items entered into PG&Es CAP. This
assessment was accomplished by reviewing ARs and event trend reports and attending
daily operational meetings. The inspectors: (1) verified that equipment, human
performance, and program issues were being identified by PG&E at an appropriate
threshold and that the issues were entered into the CAP; (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. Findings
No findings of significance were identified.
-21- Enclosure
.2 Selected Issue Follow-Up Inspection
a. Inspection Scope
In addition to the routine review, the inspectors selected the one below listed issue for a
more in-depth review. The inspectors considered the following during the review of
PG&Es 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.
- November 22, 2006, Units 1 and 2, Auxiliary Saltwater (ASW) Pump Shaft
Packing
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample.
b. Findings
Introduction: The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, for the failure of engineering personnel to apply adequate
design control measures. Specifically, engineering personnel changed the acceptance
criteria in the ASW pump surveillance test from greater than zero packing leak-off to
zero packing leak-off, with packing gland temperature less than 120EF. However, the
change was based on engineering judgment versus analysis or test data. If the
engineering judgment were incorrect, operability of the ASW pump could be impacted
and the pump may be unable to perform its safety function due to potential shaft
damage.
Description: The ASW systems safety function is to remove heat from the component
cooling water heat exchangers using the ultimate heat sink (Pacific Ocean). The system
consists of two pumps that take suction from the ocean and supply water to one or both
heat exchangers. The ASW pumps utilize packing to limit the amount of water escaping
the pump/shaft interface. The type of packing utilized in the ASW pumps is a Garlock
Type 1304 graphite-based packing. The stuffing box for the ASW pumps utilizes a
packing injection line, where the injection flow enters the box between an upper packing
and a lower packing. A portion of the injection flow travels upward, between the pump
shaft and the upper packing, and exits as visible packing leak-off at the top of the
packing gland. The rest of the injection flow travels downward, between the pump shaft
and the lower packing, and exits into the pump (i.e., nonvisible packing leak-off).
Operators observe evidence of visible packing leak-off on a daily basis to ensure that
there is adequate cooling for the packing. Inadequate cooling to the packing may result
in pump shaft seizure or damage to the packing gland and/or pump shaft. For more
-22- Enclosure
than 5 years, the ASW pump packing has been susceptible to sand and silt
accumulation from ocean water, resulting in zero packing leak-off. When operations
personnel found zero packing leak-off, the pump was declared inoperable and the pump
was repacked. In all cases where zero packing leak-off was observed, the pump had
just started versus when it had been running for some time.
Engineering personnel believed the ASW pumps were still operable without packing
leak-off since the packing gland was cool to touch in such cases. Therefore, on
February 9, 2006, engineering personnel developed a corrective action in AR A0657460
to modify the acceptance criteria in the ASW routine surveillance test procedures to
allow zero packing leak-off as long as the packing gland temperature is less than 120EF.
For example, the following procedures stated under Section 6, Acceptance Criteria,
that pump packing leakage is greater than zero drops per minute, or stuffing box
temperature is less than 120EF.
- STP P-ASW-11, Routine Surveillance Test of Auxiliary Saltwater Pump 1-1,
Revision 23
- STP P-ASW-12, Routine Surveillance Test of Auxiliary Saltwater Pump 1-2,
Revision 20
- STP P-ASW-21, Routine Surveillance Test of Auxiliary Saltwater Pump 2-1,
Revision 22
- STP P-ASW-22, Routine Surveillance Test of Auxiliary Saltwater Pump 2-2,
Revision 18
Prior revisions of these procedures required packing leakage to be greater than zero to
pass the surveillance test and for the pump to be considered operable.
The inspectors reviewed AR A0657460 and the bases for the procedure change. The
inspectors observed that licensee personnel based the change on engineering
judgment, since there was no industry or vendor-specific criteria for an allowable stuffing
box temperature. The inspectors also observed that Vendor Document 663030,
Sheet 17, Bingham Centrifugal Pumps - Instructions for Installation, Operation, and
Maintenance, Revision 18, stated that a slight amount of leakage was needed to
provide lubrication between the packing and the rotating element. If the leakage was
cut off too much, the heat generated by the friction between the packing and the rotating
element would destroy the packing and damage the rotating element. Engineering
personnel felt that, with the stuffing box temperature less than 120EF, neither the shaft
or packing would degrade and fail. The inspectors were concerned that there was no
data or experience to show that the packing would remain at a constant temperature
over time, particularly when the packing was full of sand and silt. Furthermore, the
procedure change did not require temperature surveillance of the stuffing box on a
periodic frequency if there was zero packing leak-off. Engineering personnel had
determined that shift walkdowns of the ASW pumps performed twice a day by operators
would be sufficient for monitoring. Again, there was no test data or experience to
demonstrate that the surveillance frequency would be sufficient.
-23- Enclosure
Analysis: The performance deficiency associated with this finding involved engineering
personnel failing to apply design control measures to a routine surveillance test
acceptance criteria that were commensurate with those applied to the original design.
The finding is greater than minor because it is associated with the Mitigating Systems
Cornerstone attribute of procedure quality and affects the associated cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Using the Manual Chapter 0609,
Significance Determination Process, Phase 1 Worksheet, the finding is determined to
be of very low safety significance, because it did not represent an actual loss of system
safety function, did not represent an actual loss of a single train for greater than its TS
allowed outage time, and the finding did not screen as potentially risk significant due to
a seismic, flooding, or severe weather initiating event. This finding has a crosscutting
aspect in the area of human performance associated with resources because
engineering personnel failed to provide up-to-date design documentation to support a
design change in surveillance test acceptance criteria.
Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in
part, that design control measures shall be applied to items such as acceptance criteria
for inspections and tests. Design changes, including field changes, shall be subject to
design control measures commensurate with those applied to the original design.
Contrary to this, on February 9, 2006, engineering personnel failed to apply design
control measures to a change in the routine surveillance test acceptance criteria that
were commensurate with the original design. Specifically, engineering personnel
modified the ASW pump routine surveillance test procedure acceptance criteria to allow
zero packing leak-off, although original vendor documentation required greater than
zero packing leak-off. Engineering personnel used judgment to justify the design
change rather than vendor information or test results, which would have been
commensurate with the original design. The corrective actions to restore compliance
included obtaining vendor documentation to justify zero packing leak-off from the
pumps. Because the finding is of very low safety significance and has been entered into
PG&Es CAP as AR A0684631, this violation is being treated as an NCV consistent with
Section VI.A of the Enforcement Policy: NCV 50-275; 323/06-05-04, Inadequate
Change to Auxiliary Saltwater Pump Routine Surveillance Test Acceptance Criteria.
.3 Semiannual Trend Review
a. Inspection Scope
The inspectors completed a semiannual trend review of repetitive or closely-related
issues documented in ARs to identify trends that might indicate the existence of more
safety-significant issues. The inspectors review consisted of the 6-month period of
July 1 to December 31, 2006. When warranted, some of the samples expanded beyond
those dates to fully assess the issue. The inspectors also reviewed corrective actions
associated with Emergency Action Level (EAL) Alert 2 and emergency core cooling
system (ECCS) piping voids. The inspectors compared and contrasted their results with
the results contained in PG&Es quarterly trend reports. Corrective actions associated
with a sample of the issues identified in PG&Es trend reports were reviewed for
adequacy. Documents reviewed by the inspectors are listed in the attachment.
-24- Enclosure
b. Findings
.1 EAL Alert 2
Procedure EP G-1, Emergency Classification and Emergency Plan Activation,
Revision 34, EAL Alert 2, describes the identification of fuel damage as shown
by: Confirmed Reactor Coolant System (RCS) sample > 300 µCi/cc of
equivalent I-131 specific activity OR equivalent fuel failure is measured by
exposure rate from systems carrying reactor coolant per EP RB-14A. During
the critique of the emergency drill on September 20, 2006, a concern was raised
regarding the ability to determine the extent of possible fuel damage using
Procedure EP RB-14A, Initial Detection of Core Damage, Revision 0.
AR A0678189 was written to capture this concern.
The inspectors observed that several ARs had been written since 2004
(A0616739, A0670612, A0670613, and A0675097) regarding the ability to
perform the requirements of EAL Alert 2 using Procedure EP RB-14A or through
confirmation of an RCS sample > 300 µCi/cc of equivalent I-131 specific activity.
Concerns included the high dose rates that would occur in the letdown heat
exchanger room, where piping dose rates would be taken, and the lack of
training for radiological protection personnel that would perform the procedure
during an event. Other concerns involved the use of the postaccident sampling
system for obtaining and analyzing RCS samples, since much of that system had
been abandoned in place. Some ARs were still open and others had been
closed without fully addressing the concerns.
PG&E stated that, in an event, Procedure RB-14A would be adequately briefed
and preparations made for taking dose rates. Also, portions of the postaccident
sampling system were maintained operable for taking RCS samples. However, it
was not until the NRC began to research the issue that PG&E adequately
addressed the concerns.
.2 ECCS Piping Voids
The inspectors reviewed Diablo Canyon Power Plant performance with respect
to ECCS piping voids. Within the past 6 years, both units exhibited voids at
ECCS suction piping that could adversely impact the ability of ECCS pumps to
perform their safety function. A notable area of ECCS voids was the cross-over
suction piping from the RHR system to the safety injection system. PG&E
believed that the voiding was caused by hydrogen gas coming out of solution at
the RCP seal injection system and migrating to this section of pipe. To eliminate
concerns of ECCS pipe voids at this location, PG&E installed an approximate
40 gallon void chamber (i.e., tank) to that section of pipe for both units. Gas
accumulating in that section of the pipe now travels up piping to the void
chamber. During monthly ECCS void surveillances, operators vent the void
chamber. Per design, the gas coming out of solution is removed from the piping
-25- Enclosure
and contained in the void chamber where it does not affect the performance of
safety-related pumps. The inspectors reviewed the performance of the void
chambers and found them to operate as designed, without any adverse impacts
to the plant.
The inspectors reviewed other operating experience at Diablo Canyon Power
Plant that may point to potential ECCS void concerns. The inspectors observed
that a section of RHR discharge piping in both units have experienced voiding in
the past. This section of discharge piping, Line 509, is located inside
containment, but outside the bioshield. In April 2001, AR A0528837 documented
the presence of a large void in Line 509 for Unit 1. The voiding was caused by
leakage of nitrogen-saturated water from Accumulator 1-3 into the RHR
discharge piping. Prior to this determination, operators noticed an increase in
RHR discharge pressure by a factor of four and a declining level in
Accumulator 1-3. To prevent the voiding from impacting operability of the RHR
system at that time, PG&E maintained high pressure on the RHR discharge
piping. Later, PG&E was able to correct the accumulator leakage and eliminate
the void. In May 2006, while performing an extent of condition review for a water
hammer that occurred on Accumulator 2-3 discharge piping, engineering
personnel discovered small void pockets in Unit 1 Line 509. As documented in
AR A0669488, the volume of the void was approximately 3 percent of the pipe
area, which was less than the 20 percent limit as described in
Calculation STA-108, ECCS Pump Suction Void Evaluation, Revision 0. PG&E
continued to monitor Line 509 for the next 6 months on Units 1 and 2 and were
able to vent at a maximum of 1/2 cup of gas during that time period for both units.
The inspectors reviewed PG&Es actions in regard to the voiding found inside
containment, including their monitoring efforts. The inspectors found that in both
cases the voids would not be a water hammer concern or impede core cooling
following a safety injection. The inspectors also found that PG&Es monitoring
efforts were consistent with industry practices. Specifically, PG&E would verify
the piping inside containment was full before restarting the reactor following a
refueling outage. Additionally, PG&E monitored RCS leakage and accumulator
levels and pressures to identify the potential for nitrogen or hydrogen gas coming
out of solution in ECCS piping.
4OA3 Event Followup (71153)
.1 Unit 2 Reactor Shutdown Due to Indicated High Stator Temperature for RCP 2-2
a. Inspection Scope
On December 10, 2006, operators received alarms for Unit 2 RCP 2-2 high stator
temperature. Using Procedures AR PK05-02, RCP No. 22, Revision 20, and
OP AP-28, Reactor Coolant Pump Malfunction, Revision 2, operators responded to the
alarm condition. Both procedures required a reactor trip if the RCP stator temperature
exceeded 300EF. Operators determined that a reactor shutdown was necessary as
indicated stator temperature was 249EF and increasing. Operators manually tripped the
-26- Enclosure
reactor when indicated stator temperature was 300EF. Just prior to the reactor trip, the
reactor was subcritical with keff less than 0.99; however, operators had not been able to
fully insert control rods as part of the reactor shutdown. Upon the manual reactor trip,
all control rods inserted. PG&E investigated the cause of the high stator temperature
alarm and identified a failed resistance temperature detector. An installed spare
resistance temperature detector in the RCP 2-2 stator was selected and operators
began actions to restart Unit 2 on December 11.
The inspectors responded at the time of the event and: (1) observed plant parameters
and status, (2) evaluated performance of mitigating systems and operators,
(3) confirmed that PG&E properly classified the event in accordance with EAL
procedures and made timely notifications to the NRC and state/local governments, and
(4) communicated the details of the events and conditions to NRC management as input
to determining the need for additional inspection effort.
b. Findings
No findings of significance were identified.
.2 Unit 2 Reactor Trip Due to Electrical Fault Associated With CWP 2-1
a. Inspection Scope
On December 12, 2006, an electrical fault occurred in Unit 2 CWP 2-1. The apparent
cause of the fault was the failure of an oil-filled surge capacitor located at the motor
terminal leads. As a result of the electrical fault, voltage on 12 kV nonvital Bus D
dropped to approximately 6.5 kV for less than a second. This bus supplies CWP 2-1, as
well as RCPs 2-2 and 2-4. Relay devices on Bus D sensed the degraded voltage and
opened the breakers for RCPs 2-2 and 2-4 per design. With two RCP breakers open,
the coincidence logic in the reactor protection system was met for a reactor trip.
Subsequently, the Unit 2 reactor tripped from 25 percent power.
The inspectors responded at the time of the event and: (1) observed plant parameters
and status, (2) evaluated performance of mitigating systems and operators,
(3) confirmed that PG&E properly classified the event in accordance with EAL
procedures and made timely notifications to the NRC and state/local governments, and
(4) communicated the details of the events and conditions to NRC management as input
to determining the need for additional inspection effort.
b. Findings
No findings of significance were identified.
-27- Enclosure
4OA5 Other
.1 Onsite Fabrication of Components and Construction of an Independent Spent Fuel
Storage Installation (ISFSI) (60853)
a. Inspection Scope
The inspectors witnessed portions of the ongoing ISFSI construction activities and
evaluated PG&Es performance in accordance with the criteria contained in Inspection
Procedure 60853. PG&E continued concrete placement activities for the cask transfer
facility (CTF) and the second ISFSI pad. Concrete was placed for the CTF on
August 9, 2006, and for the Transporter Seismic Anchors (TSAs) on
September 7, 2006. Concrete placement activities were completed for the second
ISFSI pad on August 23, 2006. The inspectors witnessed portions of the concrete
placement and testing activities for the CTF, TSAs, and the second ISFSI pad.
Grouted anchors were installed as part of the TSA design on October 31, 2006, to
securely anchor the transporter during a seismic event. The grouted anchors were
tensioned on November 6, 2006. The inspectors witnessed portions of the anchor
installation, grouting, and tensioning.
b. Findings
No findings of significance were identified.
.2 Temporary Instruction 2515/169, Mitigating Systems Performance Index
Verification (MSPI)
a. Inspection Scope
The inspectors verified that PG&E correctly implemented the Mitigating Systems
Performance Index (MSPI) guidance for reporting unavailability and unreliability of the
monitored safety systems. Monitored safety systems included emergency diesel
generators, RHR pumps, secondary heat removal pumps, cooling water pumps, and
high head safety injection pumps. During the inspection, the inspectors assessed the
following:
- Accurate documentation of the baseline planned unavailability hours for the
MSPI systems
- Accurate documentation of the actual unavailability hours for the MSPI systems
- Accurate documentation of the actual unreliability information for each MSPI
monitored component
- Significant errors in the reported data, which resulted in a change of the
indicated index color
-28- Enclosure
- Significant errors in the basis document which resulted in: (1) a change of the
system boundary; (2) an addition of a monitored component; or (3) a change in
the reported index color
This temporary instruction is complete for Units 1 and 2.
b. Findings
No findings of significance were identified.
.3 (Closed) URI 05000275, 323/2006012-01, Oil Found in the Vicinity of RHR Pumps
In response to inspectors identifying the presence of oil in the vicinity of the drain plugs
of the motors for RHR Pumps 1-1, 2-1, and 2-2, PG&E monitored leakage from the
motors during subsequent pump runs and concluded that the RHR pumps would have
remained operable for their mission times. Additionally, PG&E staff evaluated the use of
a shortened cure time on the RHR pump motor oil drain plugs and determined that the
sealing capability of the plugs had not been adversely affected. These evaluations were
reviewed by the inspectors, no findings of significance were identified, and no violations
of NRC requirements were identified. PG&E documented the evaluations for presence
of the oil and the shortened sealant cure time in ARs A0670760 and A0675763. This
URI is closed.
.4 (Closed) URI 07200026/2006-01, Review the concrete compressive strength test results
to confirm that the concrete compressive strength of the CTF basemat and initial ISFSI
pad meet the specified compressive strength of 5,000 psi at 90 days.
During the concrete placement activities for the Diablo Canyon ISFSI, several minor
deviations were identified by the inspectors and those were not considered to be safety
significant as documented in NRC Inspection Report 05000275/2006008;
05000323/2006008; 07200026/2006001. The determination that the deviations were
not safety significant was based on the expectation that the concrete would meet or
exceed the required minimum compressive strength of 5,000 psi at the specified cure
period of 90 days. URI 07200026/2006-01 was opened to track and confirm that the
minimum concrete compressive strength was achieved.
PG&E transmitted the 90-day concrete compressive strength test results for the initial
ISFSI pad and the CTF basemat to the NRC on October 12, 2006. The 90-day concrete
compressive test results varied from a low of 7,420 psi to a high of 9,060 psi. The
arithmetic average of any three consecutive strength tests exceeded the required
minimum concrete compressive strength of 5,000 psi as required by Section 5.6.2.3 of
ACI 349, Code Requirements for Nuclear Safety Related Concrete Structures. There
were no maximum concrete compressive strength limitations associated with the Diablo
Canyon ISFSI. Based on satisfactory concrete compressive strength results for the
initial ISFSI pad and the CTF basemat, URI 07200026/2006-01 is considered closed.
-29- Enclosure
.5 (Closed) URI 05000323/2006004-03, Corrective Actions Regarding RCS Leakage
Through In-core Thimble Tube
a. Inspection Scope
On August 31, 2006, an approximate 1.5 gpm RCS leak occurred in Unit 2. The
location of the leakage was in the movable in-core detector system (MIDS) L-13 thimble
tube. The inspectors responded to the RCS leakage at the time of the event and
observed operator actions to identify, quantify, and mitigate the leakage. As discussed
in NRC Inspection Report 05000275; 323/2006004, the inspectors found that PG&E
staff took appropriate action in response to the leakage.
PG&E initiated Nonconformance Report (NCR) N0002211 to identify the root cause(s)
of the leakage and ensure that appropriate corrective actions were taken. Following the
RCS leakage on August 31, maintenance personnel began activities to repair the MIDS,
which had been damaged by water. On September 6, maintenance personnel noticed
leakage from the Path L-13 manual isolation valve at the threaded connection on the
high pressure side. The leakage was determined to be 4 to 6 drops per minute.
Maintenance personnel initially installed a freeze seal to isolate the leakage, and then
tighten the threaded connection three flats to stop the leakage. PG&E subsequently
continued with repair activities on the MIDS.
URI 05000323/2006004-03 was initiated in NRC Inspection Report 05000275;
323/2006004 in order to: (1) evaluate PG&Es root cause and corrective actions
following the RCS leakage and (2) evaluate PG&Es response to the leak on the
threaded connection on the high pressure side of the Path L-13 manual isolation valve.
The inspectors have completed the necessary actions to evaluate these two aspects.
Therefore, URI 05000323/2006004-03 is closed.
b. Findings
1. Failure to Preserve Corrective Action for Thimble Tube Wear
Introduction: A self-revealing, Green NCV of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, was identified for the failure to apply adequate
design control measures regarding the installment of thimble tubes with chrome-
plated bands. Specifically, PG&E installed thimble tubes with chrome-plated
bands at the fuel assembly bottom nozzle/lower core plate interface to address
flow-induced vibration wear. Due to engineering personnels failure to account
for the chrome-plated bands in the thimble tube relocation procedure, the
chrome-plated band on Thimble Tube L-13 was removed from its designed
location at the fuel assembly bottom nozzle, thereby increasing the potential for
thimble tube through-wall wear.
Background: Westinghouse pressurized-water reactors utilize MIDS to monitor
nuclear power distribution within the reactor core. MIDS consists of a detector
that travels inside the thimble tubes, with the thimble tubes inserted into select
fuel assemblies. The thimble tubes are constructed of 316 stainless steel with a
-30- Enclosure
typical outer diameter of 0.3 inches and a wall thickness of 0.049 inches. The
thimble tubes are flexible to allow withdrawal and re-insertion into fuel
assemblies during reactor refueling activities. Inside the reactor vessel, the
thimble tubes are supported by the fuel assembly instrument tube and the lower
reactor internals guide columns. The thimble tubes enter the reactor vessel at
the bottom of the vessel and are supported outside the reactor vessel by
permanently-mounted thimble guide tubes. The permanently-mounted thimble
guide tubes are welded at the bottom of the reactor vessel and stop at the in-
core seal table, where a high pressure seal prevents reactor coolant from
traveling between the thimble tube and thimble guide tube out of the RCS. The
thimble tube connects to a selector device that directs the detector into the
selected thimble tube. Since the thimble tube and thimble guide tube are
subjected to RCS pressure, they are considered an extended portion of the RCS
pressure boundary.
Description: On August 31, 2006, an approximate 1.3 gpm RCS leak occurred in
the Unit 2 MIDS L-13 thimble tube. NCR N0002211 identified a presumed root
cause and developed corrective actions to prevent recurrence. NCR N0002211
stated that the RCS leak was due to accelerated wear/wear-induced fatigue of
the L-13 thimble tube due to flow-induced vibration in combination with multiple
wear scars in a short length of tube, which was not prevented by the thimble tube
wear management program. Until the thimble tube is removed for examination
in the next refueling outage in early 2008, PG&E staff has classified the root
cause as presumed and not definite.
The inspectors reviewed operating experience associated with thimble tubes at
the Diablo Canyon Power Plant and in the nuclear industry. In 1987, NRC
Information Notice 87-44, Thimble Tube Thinning in Westinghouse Reactors,
was issued to discuss thimble tube wall thinning due to flow-induced vibration on
the exposed portion of thimble tubes at the bottom of fuel assemblies and the
lower core plate. In 1988, NRC Bulletin 88-09, Thimble Tube Thinning in
Westinghouse Reactors, requested that licensees establish an inspection
program to detect thimble tube wall thinning. For Unit 1, PG&E responded to
NRC Bulletin 88-09 via PG&E Letter DCL-89-280, dated November 10, 1989. In
the letter, PG&E noted that they found 20 of 58 thimble tubes exceeded the
60 percent through-wall degradation limit, with other tubes experiencing lesser
degrees of damage. PG&E subsequently replaced 28 thimble tubes and
repositioned the wear point on 17 other tubes by pulling up at least 1.5 inches on
the seal table end of the tube and cutting off the excess tube at the high
pressure seal. For Unit 2, PG&E responded in PG&E Letter DCL-90-094, dated
April 4, 1990, with the results of the Unit 2 thimble tube inspection. PG&E found
that 3 tubes, including Thimble Tube L-13, exceeded the acceptable wear limit,
and they were capped for future replacement. In 4 other tubes, PG&E
repositioned the wear points and kept the tubes in service, since the tube wall
degradation did not exceed the acceptable wear limit.
The inspectors found that PG&E continued to inspect the thimble tubes each
refueling outage using eddy current techniques. Thimble Tube L-13 remained
-31- Enclosure
capped and out of service until Refueling Outage 2R10 (May 2001), when it was
replaced. The new thimble tube included a 16-inch long chrome band to protect
the thimble tube from flow-induced vibration at the fuel assembly/lower core plate
interface. In Refueling Outage 2R11 (February 2003), Thimble Tube L-13
showed 16 percent wear at the upper tie plate area (located in the reactor vessel
lower internals). Since the wear was deemed acceptable per
Procedure STP R-22, Thimble Tube Inspection Program, Revision 5, PG&E did
not perform any corrective actions on the tube. In Refueling Outage 2R12
(November 2004), the wear on Thimble Tube L-13 indicated 46 percent at the
upper tie plate area, and maintenance personnel repositioned the tube by
5 inches. In Refueling Outage 2R13 (May 2006), the wear on Thimble
Tube L-13 again showed 46 percent through-wall, and maintenance personnel
repositioned the tube by another 5 inches. Thimble Tube L-13 began leaking
approximately 3 months later.
NCR N0002211 noted that, when maintenance personnel repositioned Thimble
Tube L-13 the second time in Refueling Outage 2R13, the tube had been
repositioned such that the chrome-plated band on the thimble tube was no
longer in its designed location. As a result of thimble tube wall-thinning
discovered in 1989 and 1990, NCR N0001325, Corrective Action to Prevent
Recurrence 3, called for implementation of a design change to eliminate or
greatly reduce flow-induced thimble tube wear rates. Westinghouse had
developed thimble tubes with chrome-plated bands which would be more
resistant to flow-induced thimble tube wear. PG&E installed these thimble tubes
in Refueling Outage 1R6 for Unit 1 and Refueling Outage 2R10 for Unit 2.
When the new thimble tube was installed at the L-13 position, the chrome-plated
band was 16 inches long, with approximately 9 inches above the fuel assembly
bottom nozzle and 7.5 inches below the lower core plate. The chrome-plated
band was placed in this location since operating experience had shown the fuel
assembly bottom nozzle/lower core plate interface to be a high wear-rate area.
As discussed in AR A0205526, engineering personnel observed that the chrome-
plated thimble tubes were an approved replacement part provided by
Westinghouse. Therefore, engineering staff did not implement a design change
for the new thimble tubes, but did have the drawings updated to reflect the
chrome band on the thimble tubes. Subsequently, Procedure STP R-22 was not
revised in order to restrict the amount of reposition for the chrome-plated thimble
tubes. Therefore, when maintenance personnel repositioned Thimble Tube L-13
in Refueling Outage 2R13, the tube had been repositioned a total of 10 inches
during its life. The final reposition moved a section of nonchrome-plated thimble
tube area to the fuel assembly bottom nozzle/lower core plate interface.
Analysis: The performance deficiency associated with this finding involved
engineering personnel failing to apply adequate design control measures, which
would have included necessary procedure changes to reflect the use of thimble
tubes with chrome bands. The finding is greater than minor because it is
associated with the Initiating Events Cornerstone attribute of design control and
affects the associated cornerstone objective to limit the likelihood of those events
that upset plant stability and challenge critical safety functions during shutdown
-32- Enclosure
as well as power operations. Using the Inspection Manual Chapter 0609,
Significance Determination Process, Phase 1 Worksheet, the finding is
determined to have very low safety significance because, assuming the worst-
case degradation, the finding would not result in exceeding the TS limit for
identified RCS leakage or affect mitigating systems. Specifically, the inspectors
verified the worst-case leakage, i.e. guillotine break, from a thimble tube at the
fuel assembly bottom nozzle/lower core plate interface to be approximately
7 gpm versus the TS RCS identified leakage limit of 10 gpm. The finding has a
crosscutting aspect in the area of problem identification and resolution
associated with the CAP because PG&E disabled a corrective action to prevent
recurrence of significant thimble tube wear.
Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control,
requires, in part, that design control measures shall provide for verifying or
checking the adequacy of design. Design changes, including field changes,
shall be subject to design control measures commensurate with those applied to
the original design. Contrary to this, on April 24, 2006, engineering personnel
removed a corrective action to prevent significant thimble tube wear when they
repositioned Thimble Tube L-13 such that the tube was no longer in its intended
location. Specifically, Thimble Tube L-13 was repositioned to the extent that its
chrome-plated band was no longer effectively covering the fuel assembly bottom
nozzle and lower core plate interface zone. The cause of the violation was the
failure of engineering personnel to update applicable procedures with information
that would prevent the chrome-plated bands from being removed from their
designed location during repositioning of thimble tubes. The corrective actions
to restore compliance included actions to update the applicable procedures to
provide repositioning limits on thimble tubes with chrome-plated bands and to
utilize thimble tubes with chrome-plated bands for the entire length of tube inside
the reactor vessel. Because the finding is of very low safety significance and
has been entered into PG&Es CAP as NCR N0002211, this violation is being
treated as an NCV consistent with Section VI.A of the Enforcement Policy:
NCV 50-323/06-05-05, Failure to Update Relocation Procedure for Thimble Tube
Chrome Band.
40A6 Management Meetings
Exit Meeting Summary
On October 27, 2006, the lead inspector presented the results of the biennial
emergency preparedness exercise inspection to Ms. D. Jacobs, Vice President, Nuclear
Services, and other members of her staff, who acknowledged the findings. The
inspector confirmed that proprietary information was not provided or examined during
the inspection.
On December 20, 2006, the inspectors presented the findings of the inspection on
biennial heat sink performance to Mr. L. Parker and other members of PG&E
management. PG&E acknowledged the inspection findings.
-33- Enclosure
The resident inspection results were presented on January 10, 2007, to Ms. D. Jacobs,
Vice President, Nuclear Services, Diablo Canyon and other members of PG&E
management. PG&E acknowledged the findings presented.
The inspectors asked PG&E whether any materials examined during the inspection
should be considered proprietary. Proprietary information was reviewed by the
inspectors and left with PG&E at the end of the inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
-34- Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
PG&E Personnel
J. Becker, Vice President - Diablo Canyon Operations and Station Director
D. Burns, Operations Training Supervisor
C. Dougherty, Regulatory Services Senior Engineer
S. David, Operations Director
D. Fried, Emergency Planning Coordinator
M. Ginn, Emergency Planning Coordinator
J. Haynes, Training manager
J. Haynes, Licensing Services Manager
R. Hite, Manager, Radiation Protection
D. Jacobs, Vice President - Nuclear Services
S. Ketelsen, Manager, Regulatory Services
K. Langdon, Director, Operations Services
M. Lemke, Emergency Planning Principal
M. Meko, Director, Site Services
C. Over, Regulatory Services Supervisor
L. Parker, Regulatory Services Supervisor
K. Peters, Director, Engineering Services
J. Purkis, Director, Maintenance Services
P. Roller, Director, Performance Improvement
D. Taggart, Manager, Quality Verification
B. Terrell, Emergency Planning Supervisor
R. Waltos, Manager, Emergency Preparedness
M. Zawalick, Emergency Services, Senior Coordinator
S. Zawalick, Regulatory Services Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-275; 323/06-05-01 URI Additional Review of Material to Determine if the RHR
Heat Exchangers Will Meet Their Safety Function
(Section 1R07.2)
Opened and Closed
50-275; 323/06-05-02 NCV Failure to Adequately Evaluate Operability of Auxiliary
Building Ventilation Control Panels (Section 1R13)
50-275/06-05-03 NCV Inadequate Temporary Modification to a Vital Battery
(Section 1R15)
A-1 Attachment
50-275; 323/06-05-04 NCV Inadequate Change to Auxiliary Saltwater Pump Routine
Surveillance Test Acceptance Criteria (Section 4OA2.2)
50-323/06-05-05 NCV Failure to Preserve Corrective Action for Thimble Tube
Wear (Section 4OA5.5)
Closed
50-275; 323/06-12-01 URI Oil Found in the Vicinity of Residual Heat Removal Pumps
(Section 4OA5.3)
72-026/06-01-01 URI Review the Concrete Compressive Strength Test Results
to Confirm that the Concrete Compressive Strength of the
Cask Transfer Facility Basemat and Initial Independent
Spent Fuel Storage Installation Pad Meet the Specified
Compressive Strength of 5,000 psi at 90 days
(Section 4OA5.4)
50-323/06-04-03 URI Corrective Actions Regarding RCS Leakage Through In-
core Thimble Tube (Section 4OA5.5)
LIST OF DOCUMENTS REVIEWED
Section 1R05: Fire Protection
Procedures
Number Title Revision
A-6 Equipment Inspections 5
OM8.ID4 Control of Flammable and Combustible Materials 14
STP M-69A Monthly Fire Extinguisher Inspection 36
STP M-69B Monthly CO2 Hose Reel and Deluge Valve Inspection 14
STP M-70C Inspection/Maintenance of Doors 10
A-2 Attachment
Section 1R07: Biennial Heat Sink Performance (71111.07B)
Action Requests
A0341604 A0556717 A0600918 A0608887 A0617092 A0648128
A0391927 A0588366 A0608886 A0608888 A0640406 A0653252
A0380732 A0592857
Calculations
Number Title Revision
M-938 CCW Data Input for 1993 Containment Analysis Program 3
M-1017 Determine Flows in the CCW System 3
Procedures
Number Title Revision
STP M-93A Refueling Interval Surveillance - Containment Fan Cooler 18
STP M-13A CCW Flow Balancing 15
BIO D-5 Microfouling Sample Collections in Component Cooling 0A
Water Heat Exchangers
CAP O-6 Chemical Additions to the Closed Cooling Water Systems 16A
OP F-5:III Chemistry Control Limits and Action Guidelines for the 18
Plant Support Systems
PEP M-200 Flow Balancing CCW to Equipment on CCP Pump Skid 0
Miscellaneous Documents
Title Date/Revision
DCM No. S-23A, Design Criteria Memorandum Containment HVAC 18C
System
DCM No. S-10, Design Criteria Memorandum S-10 Residual Heat 13D
Removal System
A-3 Attachment
Title Date/Revision
DCM No. S-14, Design Criteria Memorandum Component Cooling Water 15E
System
Nonconformance Report N0002194, Void at CCP - SIP Suction Cross Tie 0
PG&E letter DCL 90-027 Jan. 26, 1990
Westinghouse Letter PGE 96-605 Sept. 3, 1996
Work Orders
C0193402 R0234221 R0258879 R0259792 R0259790 R0259627
R0259787 R0269129 R0269164 R0234221 R0244369 R0244367
Section 1R12: Maintenance Effectiveness (71111.12)
Action Requests
A0678838 A0681428 A0681464
Procedures
Number Title Revision
MP E-53.7 Maintenance of ITT, General Controls Hydramotor Actuator 9A
AD13.ID4 Post-Maintenance Testing 14
Section 1R13: Maintenance Risk Assessments and Emergent Work Control (71111.13)
Action Requests
A0610558 A0636037 A0637526 A0642790 A0660739 A0678429
A0678436 A0681559 A0683008 A0684812
Procedures
Number Title Revision
A-29 Protected Train Restrictions 3
A-4 Attachment
Number Title Revision
AD7.DC6 On-line Maintenance Risk Management 9
MA1.DC10 Troubleshooting 9
MA1.DC11 Risk Assessment 7
OP J-2:VIII Guidelines for Reliable Transmission Service for DCPP 10
OP1.DC17 Control of Equipment Required by the Plant Technical 11
Specifications or Other Designated Programs
OM7.ID12 Operability Determination 9
OP H-1:I Auxiliary Building Ventilation System - Make Available 9
and System Operation
Work Requests
C0202499 C0206797 C0208219
Section 1R15: Operability Evaluations (71111.15)
Action Requests
A0678820 A0680025 A0681006 A0682008
Calculations
Number Title Revision
235A-DC Battery 11 Sizing, Load Flow, Voltage Drop, Short Circuit 8
and Charger Sizing
369-DC Vital 125 VDC System Calculation for PRA System 1
Analysis (Station Blackout)
Drawings
Number Title Revision
437546 Single Line Meter and Relay Diagram 125 Volt DC System 39
445075 Single Line Meter and Relay Diagram 125 Volt DC System 156
A-5 Attachment
445076 Single Line Meter and Relay Diagram 125 Volt DC System 15
050024 List of Electrical Devices for Protection and Control Circuits 47
D-INV-4- Discharge Characteristics LCUN-33 1
88598
Procedures
Number Title Revision
MP E-67.6 Station Battery Preventive Maintenance 6
OP O-2 Operation of Hagan Controllers 10
STP M-11A Station Battery and Pilot Cell Condition Monitoring 20
STP M-11B Station Battery Condition Monitoring 26
STP M-21A Vital Station Battery Modified Performance Test 12
Work Requests
R0233847 R0213290
Miscellaneous Documents
Title Date/Revision
Amendment to Facility Operating License, Amendment No. 190, Nov. 15, 2006
License DPR-80
ASCO Letter, Potential Non-Conformances of Plunger Tubes Used In Sept. 15, 2006
Certain NH Series Hydramotor Pump and pump Kits
BCT-2000 Battery Load Test Report, Modified Performance Test Vital Oct. 27, 2005
Battery 1-1"
BCT-2000 Battery Load Test Report, Modified Performance Test Non- May 12, 2006
Vital Battery 2-5"
DCM No. T-42, Station Blackout 9
A-6 Attachment
Title Date/Revision
IEEE Standard 535-1986, Qualification of Class 1E Lead Storage
Batteries
Operations Shift Orders Oct. 17, 2006
Regulatory Guide 1.155, Station Blackout Aug. 1988
PG&E Letter DCL-06-120, Exigent License Amendment Request 06-08
Revision to Technical Specification 3.8.4, DC Sources-Operating, Oct. 18, 2006
Condition B
PG&E Letter DCL-06-126, Supplement to Exigent License Amendment
Request 06-08 Revision to Technical Specification 3.8.4, DC Sources- Oct. 18, 2006
Operating, Condition B
Section 1R17: Permanent Plant Modifications (71111.17)
Action Requests
A0678267
Documents
IB-129-154, Westinghouse Instruction bulletin, Remote/Manual Setpoint Station, dated
November 1968
Drawings
Number Title Revision
102032 Excess Letdown Heat Exchanger Outlet Loop Block Diagram, 148
Sheet 26
102032 Excess Letdown Heat Exchanger Outlet Loop Block Diagram, 116
Sheet 31
106725 Unit 1 Containment 109
448928 Electrical Diagram Connections Unit 1 Vertical Control 31
Board 1VB2
437930 Electrical Diagram Of Connections Penetration No. 24E 16
A-7 Attachment
Work Requests
C0206720
Section 1EP1: Emergency Plan Implementing Procedures (71114.01)
EP G-1 Revision 34 Emergency Classification and Emergency Plan Activation
EP G-2 Revision 31 Interim Emergency Response Organization
EP G-3 Revision 47 Emergency Notification of Off-Site Personnel
EP G-4 Revision 22 Assembly and Accountability
EP G-5 Revision 9A Evacuation of Nonessential Personnel
EP OR-3 Revision 6B Emergency Recovery
EP RB-1 Revision 5B Personnel Dosimetry
EP RB-2 Revision 5 Emergency Exposure Guides
EP RB-3 Revision 5 Stable Iodine Thyroid Blocking
EP RB-4 Revision 4A Access to and Establishment of Controlled Areas Under
Emergency Conditions
EP RB-5 Revision 6 Alternate Personnel Decontamination Facilities
EP RB-8 Revision 19 Instructions to Field Monitoring Teams
EP RB-9 Revision 11A Calculation Release Rate
EP RB-10 Revision 12 Protective Action Recommendations
EP RB-11 Revision 12 Emergency Offsite Dose Calculations
EP RB-12 Revision 6 Plant Vent Iodine and Particulate Sampling During
Accident Conditions
EP RB-14 Revision 8A Core Damage Assessment Procedure
EP RB-14A Revision 0 Initial Detection of Core Damage
EP RB-15 Revision 11 Post Accident Sampling System
EP RB-16 Revision 0 Operating Instructions for the EARS Computer Program
EP R-2 Revision 23 Release of Airborne Radioactive Materials Initial
Assessment
EP R-3 Revision 8C Release Of Radioactive Liquids
EP R-7 Revision 15A Off-Site Transportation Accidents
EP EF-1 Revision 33A Activation and Operation of the Technical Support Center
EP EF-2 Revision 28 Activation and Operation of the Operations Support
Center
EP EF-3 Revision 26A Activation and Operation of the Emergency Operations
Facility
EP EF-4 Revision 15 Activation of the Off-Site Emergency Laboratory
EP EF-9 Revision 10 Backup Emergency Response Facilities
EP EF-10 Revision 8 Activation and Operation of the Joint Media Center
TQ1 Revision 3 Personnel Training and Qualification
TQ1.ID3 Revision 5 Non-accredited Training Program Management
OM10.ID4 Revision 7 ERO Management
OM10.DC2 Revision 4 ERO On-Call
Exercise Evaluation Reports:
Drill Reports for 2004 and 2002 Biennial NRC Evaluated Exercise
All full-scale Exercise reports conducted in 2005-2006
A-8 Attachment
Summary List of Drill/Exercise Evaluation related Condition Reports, July 2004 through
September 2006
Emergency Plan, Revision 45
Section 4OA2: Problem Identification and Resolution (71152)
Action Requests
A0528837 A0631582 A0657460 A0669488 A0680274 A0685913
A0535731 A0636681 A0661341 A0672126 A0680773
A0558389 A0636984 A0664245 A0679011 A0684631
Procedures
Number Title Revision
STP M-89 (Unit 1) ECCS System Venting 46
STP P-ASW-11 Routine Surveillance Test of Auxiliary Saltwater Pump 1-1 23
STP P-ASW-12 Routine Surveillance Test of Auxiliary Saltwater Pump 1-2 20
STP P-ASW-21 Routine Surveillance Test of Auxiliary Saltwater Pump 2-1 22
STP P-ASW-22 Routine Surveillance Test of Auxiliary Saltwater Pump 2-2 18
Calculations
Number Title Revision
STA-108 ECCS Pump Suction Void Evaluation 0
Miscellaneous Documents
Title Date
Licensing Position - Definition of Full and Accessible for Performance of Sept. 4, 2001
Technical Specification (TS) Surveillance Requirement (SR) 3.5.2.3
(Revision 1)
A-9 Attachment
Title Date
NRC Information Notice 97-40, Potential Nitrogen Accumulation June 26, 1997
Resulting From Backleakage From Safety Injection Tanks
Vendor Document DC 663030-17-8, Page 69, Auxiliary Saltwater Pumps Dec. 24, 1969
Section 4OA1: Emergency Implementing Procedures (71151)
OM10.DC1, Emergency Preparedness Drills and Exercises, Revision2A
AWP EP-001, Emergency Preparedness Performance Indicators, Revision 5
EP G-3, Emergency Notification of Off-Site Agencies, Revision 43, Attachment
6.1, Instructions for the DCPP Emergency Notification Form
EP R-2, Release of Airborne Radioactive Materials Initial Assessment, Revision
23
EP RB-10, Protective Action Recommendations, Revision 11
Section 4OA3: Event Followup (71153)
Action Requests
A0132116 A0165736 A0342551 A0665509 A0684192 A0685056
A0164337 A0205526 A0623606 A0684170 A0684536 A0686189
Drawings
Number Title Revision
441227 Single Line Meter & Relay Diagram 12 kV System Bus 21
Section D & E
441284 Schematic Diagram - Circulating Water Pumps 31
441338 Schematic Diagram - Bus Potential and Synchronizing 16
12 kV System
441350 Schematic Diagram - 12 kV Bus Sections D & E Automatic 8
Transfer
A-10 Attachment
Procedures
Number Title Revision
EP G-1 Emergency Classification and Emergency Plan Activation 34
EP G-3 Emergency Notification of Off-Site Agencies 47
NDE ET-2 Eddy Current Examination of Heat Exchanger Tubing 5
OP AP-28 Reactor Coolant Pump Malfunction 2
STP R-22 Thimble Tube Inspection Program 5/6
Miscellaneous Documents
Title Date
DC-663102-24-2, Westinghouse Installation - Operation - Maintenance Jan. 4, 1985
Instructions for Types SSV-T and SSC-T Relays for Class 1E Application
Event Investigation Report 2006-001, Unit 2 Reactor Trip and Unusual Dec. 13, 2006
Event Due to CWP 2-1 Fault
Event Notification 42822 Aug. 31, 2006
Event Notification 43042 Dec. 10, 2006
Event Notification 43047 Dec. 12, 2006
Licensee Event Report 93-007-00, Manual Reactor Trip Initiated Due to June 26, 1993
High Stator Temperature on Reactor Coolant Pump
Nonconformance Report (NCR) DC1-89-TN-N096/2, Incore Thimble Jan. 30, 1991
Tubes (also titled NCR N0001325)
A-11 Attachment
Title Date
NCR N0002211, Root Cause Analysis Report - RCS Leak Through MIDS Oct. 18, 2006
Thimble Tube
NRC Bulletin 88-09, Thimble Tube Thinning in Westinghouse Reactors July 26, 1988
NRC Information Notice 87-44, Thimble Tube Thinning in Westinghouse Sept. 16, 1987
Reactors
PG&E Letter DCL-88-208, Thimble Tube Thinning in Westinghouse Aug. 26, 1988
Reactors
PG&E Letter DCL-89-280, Thimble Tube Thinning in Westinghouse Nov. 10, 1989
Reactors
PG&E Letter DCL-89-292, Thimble Tube Thinning Due to Flow-Induced Nov. 20, 1989
Vibration
PG&E Letter DCL-90-094, Thimble Tube Thinning April 4, 1990
PG&E Memorandum File No. 96, Licensing Position - TS 3.4.13 Oct. 5, 2006
Application for Threaded Connection Leakage
WCAP-12866, Bottom-Mounted Instrumentation Flux Thimble Wear Jan. 1991
Westinghouse Letter PGE-87-064, Flux Thimble Wear May 5, 1987
Westinghouse Letter PGE-90-537, BMI Thimble Tube Wear Evaluation Feb. 16, 1990
A-12 Attachment
LIST OF ACRONYMS
ac alternating current
ADAMS agency document and management system
ALARA As Low As is Reasonably Achievable
ANSI/IEEE American National Standards Institute/Institute of Electrical and Electronics
Engineers
AR action request
ASW auxiliary saltwater
CAP corrective action program
CCW component cooling water
CFR Code of Federal Regulations
CFCU containment fan cooling unit
CTF cask transfer facility
CWP circulating water pump
dc direct current
EAL emergency action level
ECCS emergency core cooling system
FSAR Final Safety Analysis Report
ISFSI Independent Spent Fuel Storage Installation
LER licensee event report
MIDS movable in-core detector system
MSPI Mitigating Systems Performance Index
NCR nonconformance report
NCV noncited violation
A-13 Attachment
NRC Nuclear Regulatory Commission
PG&E Pacific Gas and Electric Company
RCP reactor coolant pump
SSC structure, system, and component
TS Technical Specifications
TSA transporter seismic anchor
URI unresolved item
A-14 Attachment