ML050450591
| ML050450591 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/11/2005 |
| From: | William Jones NRC/RGN-IV/DRP/RPB-E |
| To: | Rueger G Pacific Gas & Electric Co |
| References | |
| EA-04-169, FOIA/PA-2011-0221 IR-04-005 | |
| Download: ML050450591 (70) | |
See also: IR 05000275/2004005
Text
February 11, 2005
EA 04-169
Gregory M. Rueger, Senior Vice
President, Generation and Chief Nuclear Officer
Pacific Gas and Electric Company
Diablo Canyon Power Plant
P.O. Box 3
Avila Beach, California 93424
SUBJECT:
DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION
REPORT 05000275/2004005 AND 05000323/2004005
Dear Mr. Rueger:
On December 31, 2004, 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 6, 2005, with Mr. David H.
Oatley and other 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.
This report documents one unresolved item concerning the potential unavailably of an
emergency diesel generator in Unit 2 due to a cracked lube oil sensing line. This finding has
potential safety significance greater than very low safety significance. The line was isolated on
September 28, 2004, to mitigate any safety concerns and the diesel engine was declared
There were four NRC-identified findings and five self-revealing findings 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 ten 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
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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/
William B. Jones, Chief
Project Branch E
Division of Reactor Projects
Dockets: 50-275
50-323
Licenses: DPR-80
Enclosure:
Inspection Report 05000275/2004005
and 05000323/2004005
w/attachment: Supplemental Information
cc w/enclosure:
David H. Oatley, Vice President
and General Manager
Diablo Canyon Power Plant
P.O. Box 56
Avila Beach, CA 93424
Lawrence F. Womack
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 3
Avila Beach, CA 93424
Pacific Gas and Electric Company
-3-
Sierra Club San Lucia Chapter
ATTN: Andrew Christie
P.O. Box 15755
San Luis Obispo, CA 93406
Nancy Culver
San Luis Obispo Mothers for Peace
P.O. Box 164
Pismo Beach, CA 93448
Chairman
San Luis Obispo County Board of
Supervisors
Room 370
County Government Center
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
Ed Bailey, Chief
Radiologic Health Branch
State Department of Health Services
P.O. Box 997414 (MS 7610)
Sacramento, CA 95899-7414
Richard F. Locke, 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
Pacific Gas and Electric Company
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James D. Boyd, Commissioner
California Energy Commission
1516 Ninth Street (MS 34)
Sacramento, CA 95814
Technical Services Branch Chief
FEMA Region IX
1111 Broadway, Suite 1200
Oakland, CA 94607-4052
Pacific Gas and Electric Company
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Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (DLP)
Branch Chief, DRP/E (WBJ)
Senior Project Engineer, DRP/E (VGG)
Team Leader, DRP/TSS (RLN1)
RITS Coordinator (KEG)
J. Dixon-Herrity, OEDO RIV Coordinator (JLD)
DC Site Secretary (AWC1)
DMB (IE35)
W. A. Maier, (RSLO)
SISP Review Completed: _WBJ__ ADAMS: / Yes
G No Initials: _WBJ__
/ Publicly Available G Non-Publicly Available G Sensitive
/ Non-Sensitive
R:\\_DC\\2004\\DC2004-05RP-DLP.wpd
RIV:SRI:DRP/E
SRI:DPE/E
C:DRS/EB
C:DRS/PEB
C:DRS/PSB
TWJackson
DLProulx
JAClark
LJSmith
MPShannon
E-WBJ
E-WBJ
/RA/
NFO For
E-WBJ
2/11/05
2/4/05
2/10/05
2/11/05
2/10/05
C:DRS/OB
C:DRP/E
ATGody
WBJones
/RA/
/RA/
2/11/05
2/11/05
OFFICIAL RECORD COPY
T=Telephone E=E-mail F=Fax
ENCLOSURE
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets:
50-275, 50-323
Licenses:
Report:
05000323/2004005
Licensee:
Pacific Gas and Electric Company (PG&E)
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, 2004
Inspectors:
D. L. Proulx, Senior Resident Inspector
T. W. Jackson, Resident Inspector
V. G. Gaddy, Senior Project Engineer
R. Lantz, Senior Emergency Preparedness Inspector
G. Johnston, Senior Reactor Engineer
D. L. Stearns, Project Engineer
W. C. Sifre, Reactor Inspector
G. D. Replogle, Senior Reactor Inspector
J. I. Tapia, Senior Reactor Inspector
B. D. Baca, Health Physicist
Approved By:
W. B. Jones, Chief, Projects Branch E
Division of Reactor Projects
Enclosure
CONTENTS
PAGE
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REACTOR SAFETY
1R01
Adverse Weather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R04
Equipment Alignments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1R06
Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R08
Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R11
Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R13
Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 11
1R14
Personnel Performance Related to Nonroutine Plant Evolutions and Events . 12
1R15
Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
1R16
Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
1R19
Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
1R20
Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
1R22
Surveillance Testing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
1EP1 Exercise Evaluation
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
1EP4 Emergency Action Level and Emergency Plan Changes . . . . . . . . . . . . . . . . 24
RADIATION SAFETY
2OS1 Access Control To Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 25
OTHER ACTIVITIES
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
4OA4 Crosscutting Aspects of Findings
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4OA5 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4OA6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
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 Used . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8
Enclosure
SUMMARY OF FINDINGS
IR 05000275/2004-005, 05000323/2004-005; 10/01/04 - 12/31/04; Diablo Canyon Power Plant
Units 1 and 2; Operability Evaluations, Event Followup, Personnel Performance Related to
Nonroutine Plant Evolutions and Events, Equipment Alignment, Access Control To
Radiologically Significant Areas, Other.
This report covered a 13-week period of inspection by resident inspectors and announced
inspections in the areas of inservice inspections, emergency preparedness, and radiation
protection. Five self-revealing, four NRC-identified Green noncited violations, and one
unresolved item with potential safety significance greater than Green 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 violations was identified for the failure to appropriately
implement the procedure for spent fuel pool skimmer filter replacement, as required by
Technical Specification 5.4.1.a. On December 23, 2004, operators cleared the spent
fuel pool skimmer system using Section 6.3.1 of Procedure OP B-7:III, Spent Fuel Pool
System - Shutdown and Clearing and Filter Replacement, Revision 15, instead of the
appropriate section, which was Section 6.3.2. A human performance crosscutting
aspect was identified for the failure on two occasions to address configuration control
concerns with the system.
This finding impacted the Initiating Events Cornerstone and was considered more than
minor using Example 5.a of IMC 0612. Specifically, Valve SFS-2-3 was mis-positioned
due to the use of the wrong section of Procedure OP B-7:III and then returned to
service. Additionally, operators had two opportunities to identify the mis-positioning of
Valve SFS-2-3 but failed to identify the condition. The mis-positioned valve resulted in a
loss of approximately 36,000 gallons of water from the spent fuel pool. This finding was
reviewed by NRC management in accordance with IMC 0609 and 0612 and determined
to be of very low safety significance (Section 1R14.2).
Cornerstone: Mitigating Systems
Green. A self-revealing, noncited violation was identified for the failure to setup phase
sequence test equipment according to procedure, as required by 10 CFR Part 50,
Appendix B, Criterion V. This failure resulted in the momentary de-energization of
Vital 4kV Bus G and the auto-start of Diesel Engine Generator 2-1. Subsequent
investigation by Pacific Gas & Electric Company revealed that the primary side of the
test transformer was wired in a wye configuration instead of a delta configuration. This
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Enclosure
wiring configuration introduced a direct short to ground, which caused the second level
undervoltage relay to sense a degraded bus voltage for Vital 4kV Bus G. Subsequently,
the relay removed the auxiliary power supply from Bus G and caused DEG 2-1 to start
and load onto the bus. This finding involved a human performance crosscutting aspect
for the failure to wire the phase sequence test equipment properly for Vital 4kV Bus G
and DEG 2-1.
The finding impacted the Mitigating Systems Cornerstone for ensuring the availability
and capability of systems that respond to initiating events to prevent undesirable
consequences that was associated with a pre-event human error performance.
Considering Example 4.b of Inspection Manual Chapter 0612, Appendix E, the finding is
greater than minor since the incorrect wiring and connection of the test equipment
resulted in a vital bus de-energization and the actuation of DEG 2-1. Using Checklist 4
of Inspection Manual Chapter 0609, Appendix G, Attachment 1, the finding did not result
in the Technical Specifications for AC and DC power sources not being met and the
finding was determined not to increase the likelihood of a loss of reactor coolant system
inventory, degrade Pacific Gas & Electric Companys ability to terminate a leak path or
add reactor coolant system inventory when needed, or degrade Pacific Gas & Electric
Companys ability to recover decay heat removal once it is lost. Therefore, the finding
was screened as having very low safety significance (Section 4OA3.1).
Green. The inspectors identified an noncited violation of 10 CFR 50 Appendix B,
Criterion XVI, for the failure to take adequate corrective actions to prevent a void space
in the Unit 1 emergency core cooling system piping from exceeding the volume allowed
by plant procedures. The void space volume caused operators to declare the
emergency core cooling system inoperable and enter Technical Specification 3.0.3 twice
on October 21, 2004. Operation of the positive displacement pump, with subsequent
operation of the centrifugal charging pump, had been discovered to create a void in the
emergency core cooling system piping approximately five months earlier on Unit 2. This
finding had problem identification and resolution crosscutting aspects for determining
the extent of the condition and preventing its recurrence.
The finding affected the Mitigating System cornerstone for ensuring the capability of
systems that respond to initiating events to prevent undesirable consequences and it
affected the equipment performance attribute for availability and reliability. The finding
is greater than minor because it is similar to Example 2.f in Appendix E of Inspection
Manual Chapter 0612. Similar to the example, the void size had exceeded the limit
described in Calculation STA-108, Allowable Accumulated Gas Volume in the CCPs
[centripetal charging pump] and SIPs [safety injection pump] Suction Cross-Tie Piping,
Revision 3. Using the Inspection Manual Chapter 0609 Phase 1 Screening Worksheet,
the finding was of very low safety significance (Green) since the finding is not a design
or qualification deficiency that was confirmed to result in a loss of function per Generic
Letter 91-18 (Section 1R15).
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Enclosure
TBD. An unresolved item was identified for the failure to promptly correct a cracked
lube oil instrument sensing line, as required by 10 CFR Part 50, Appendix B,
Criterion XVI. On August 29, 2004, operators observed a lube oil leak from the weld
connecting the outlet of Valve DEG-2-1084 to instrument tubing. Approximately one
month later, the leak had increased and it was discovered that the circumferential crack
was 180 degrees through-wall on the weld. As a result, there was an increased
potential for DEG 2-3 to trip on low lube oil level. This finding had problem identification
and resolution crosscutting aspects associated with operations and engineering
personnel not recognizing the significance of the degraded condition and not
implementing timely corrective actions.
This finding is unresolved pending a review of the crack propagation, the potential
impact on the diesel engine and completion of a significance determination. This finding
impacted the Mitigating Systems Cornerstone for reliability of systems that respond to
initiating events to prevent undesirable consequences and affects the equipment
performance attribute. The finding was more than minor using Example 4.f of
Inspection Manual Chapter 0612, Appendix E. Similar to Example 4.f, the inspectors
determined that there was impact to DEG 2-3 operability. Using the SDP Phase 1
screening worksheets in Appendix A of Inspection Manual Chapter 0609, the finding
was determined to have potentially greater than very low safety significance because
the failure could have resulted in an actual loss of the diesel engine Generator 2-3
during a loss of offsite power event (Section 1R15).
Green. A self-revealing violation of 10 CFR 50.49(f) was identified for the failure to
maintain approximately 70 safety related solenoid operated valves in an environmentally
qualified condition. On February 9, 2002, an age related ASCO solenoid operated valve
failure caused a loss of steam generator feedwater event and a Unit 2 manual plant trip.
Further, the licensee did not promptly evaluate the extent of condition of the ASCO
failure (coil insulation failure), which delayed the identification of elastomer qualification
issues for approximately 1 year. In a related finding, the team identified that the
licensee had missed earlier opportunities to identify ASCO elastomer qualification
issues, in that they failed to thoroughly evaluate several pertinent NRC information
notices and previous valve failures. The failure to: 1) properly establish equipment
qualification limits; 2) thoroughly evaluate plant events and failures; and 3) properly
evaluate industry operating experience constituted performance concerns. Pacific Gas &
Electric Company entered this issue into their corrective action program as Action
Request 0613008. These issues have crosscutting aspects in the area of problem
identification and resolution because the original problem investigation did not identify
the full scope of the cause and extent of condition, delaying some important corrective
actions for approximately 1 year.
This finding was greater than minor because, if left uncorrected, these deficiencies
would become a more significant safety concern by increasing the failure rate as the
components age. An NRC Senior Reactor Analyst performed a Phase 3 significance
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Enclosure
determination and the estimated delta-CDF for the finding is 2.2E-8/yr. This violation
was of very low risk significance (Section 4OA5).
Cornerstone: Barrier Integrity
Green. The inspectors identified a noncited violation for the failure to develop a core
offload sequence that maintained the source range neutron flux monitors operable, as
required by 10 CFR Part 50, Appendix B, Criterion V. Inaccurate labeling of two neutron
detectors in the core offload planning tool resulted in the development of a core offload
sequence that when implemented resulted in one of the detectors becoming
neutronically uncoupled from the core during core alterations. A human performance
crosscutting aspect was identified for the labeling error in the core offload planning. A
second human performance crosscutting aspect was identified for the failure to
ascertain the cause of the downward trend when first identified by the inspectors.
The finding impacts the Barrier Integrity Cornerstone to provide reasonable assurance
that physical design barriers protect the public from radio nuclide releases caused by
accidents or events and is associated with the barrier performance attribute for
procedure quality which could impact cladding. The finding is more than minor when
compared to Example 4.e of Inspection Manual Chapter 0612, Appendix E. Similar to
the example, Procedure OP B-8DS1, Step 5.2.1, described a responding nuclear
instrument as having at least one fuel assembly face-adjacent or diagonally adjacent to
the detector. Due to a labeling error in the core offload planning tool, the core offload
sequence was developed in a manner that caused a neutron detector (Detector N-52)
not to have an adjacent fuel assembly. Using Checklist 4 of Inspection Manual
Chapter 0609, Appendix G, Attachment 1, the finding was determined not to increase
the likelihood of a loss of reactor coolant system inventory, degrade Pacific Gas &
Electric Companys ability to terminate a leak path or add reactor coolant system
inventory when needed, or degrade Pacific Gas & Electric Companys ability to recover
decay heat removal once it is lost. Therefore, the finding was screened as having very
low safety significance (Section 1R04.1).
Green. The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, for the failure to promptly correct reverse rotation of containment fan
cooler units for both Units 1 and 2. Pacific Gas & Electric Company observed reverse
rotation of containment fan cooler units for approximately 13 years, as a result of the
containment fan cooler units backdraft dampers sticking partially open. The purpose of
the backdraft dampers is to prevent reverse rotation of the containment fan cooler units,
which could cause the fan motor to trip on overcurrent when the containment fan cooler
units are started following a loss of coolant accident. Prior to Refueling Outage 2R12, 2
containment fan cooler units in Unit 1 and 3 containment fan cooler units in Unit 2
exhibited reverse rotation. One of the containment fan cooler units in Unit 2 was
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Enclosure
considered inoperable due to reverse rotation and another was only considered
operable if it was running. A problem identification and resolution crosscutting aspect
was identified for the failure to correct the reverse rotation of the containment cooler
fans.
The finding impacts the Barrier Integrity Cornerstone to provide reasonable assurance
that physical design barriers protect the public from radio nuclide releases caused by
accidents or events and is associated with the barrier performance attribute. The finding
is more than minor when considering Example 3.g of Inspection Manual Chapter 0612,
Appendix EProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0612,</br></br>Appendix E" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.. Similar to the example, Pacific Gas & Electric Company observed reverse
rotation of containment fan cooler units for 13 years, and the reverse rotation impacted
the operability of the containment fan cooler units. Using the SDP Phase 1 Screening
Worksheet from Inspection Manual Chapter 0609, the finding was determined to be of
very low safety significance since it was determined that there was not an actual loss of
defense-in-depth in containment pressure control or hydrogen control (Section 1R04.2).
Cornerstone: Emergency Preparedness
C
Green. The inspectors identified a violation of 10 CFR 50.54(q) and 50.47.b(4) for the
failure to maintain the seismic force monitors during the periods, June 16-19,1999,
December 1-4, 2000, April 25-27, 2002, May 25-29, 2002, November 6-8, 2003,
December 30-31, 2003, and August 9-10, 2004, such that the emergency plan designed
to meet planning standard (4) in 10 CFR 50.47(b) could be promptly implemented.
Specifically, Pacific Gas & Electric Company failed to provide a means for the
emergency director to promptly classify seismic events at the notification of unusual
event, alert or site area emergency levels, while the seismic force monitor utilized by the
operators (emergency director) was out of service or being replaced. This finding had a
human performance cross-cutting aspect associated with identifying compensatory
measures to address the removal of the earthquake force monitors.
This performance deficiency impacted the emergency preparedness cornerstone
because Pacific Gas & Electric Companys did not meet an emergency planning
requirement and the cause was reasonably within Pacific Gas & Electric Companys
control and should have been prevented. It is greater than minor because it has a
potential to impact safety and because it was not a record keeping or administrative
issue or an insignificant procedural error. This deficiency could have affected the
emergency preparedness cornerstone objective of ensuring the capability to implement
measures to protect the health and safety of the public during an emergency, and is
associated with attributes of facilities and equipment, and offsite emergency
preparedness. The finding is evaluated using the Emergency Preparedness Failure to
Comply flowchart of the SDP and is a violation of 10 CFR 50.54(q) and planning
standard 50.47(b)(4), which states, in part, that a standard emergency action level and
classification system... is in use Utilizing the Failure to Comply Flow Chart in Manual
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Enclosure
Chapter 0609, the performance deficiency does not result in a failure of the risk
significant planning standard or a degraded risk significant planning standard in that the
unavailability of the seismic monitors would not prevent the declaration of a Site Area
Emergency, Alert or Notification of Unusual Event (Section 4OA5).
Cornerstone: Occupational Radiation Safety
Green. A self-revealing noncited violation of Technical Specification 5.7.2 was reviewed
as a result of Pacific Gas & Electric Companys failure to prevent unauthorized entry of a
portion of the whole body into a high radiation area with dose rates greater than 1 rem
per hour. Specifically, on November 14, 2004, Pacific Gas & Electric Company failed to
use an effective locking mechanism on the lower access flaps of the primary steam
generator shield doors. The ineffective locking mechanism was discovered two days
later when workers went to remove suction hoses. This could have allowed an
individual to expose the arm above the elbow to dose rates greater than 1 rem per hour.
This finding was placed into Pacific Gas & Electric Companys corrective action
program.
The finding is greater than minor because it is associated with one of the cornerstone
attributes (exposure control) and affected the cornerstone objective because it could
have resulted in unplanned, unintended radiation dose. The inspector determined that
the finding was of very low significance because (1) it was not an ALARA finding, (2) it
was not an overexposure, (3) it did have a substantial potential for overexposure, and
(4) it did not compromise the ability to assess doses. This finding also had crosscutting
aspects associated with human performance (Section 2OS1).
Green. A self-revealing noncited violation of Technical Specification 5.7.2 was reviewed
as a result of Pacific Gas & Electric Companys failure to prevent two individuals from
entering a high radiation area with dose rates greater than 1 rem per hour on the
incorrect radiation work permit. Two individuals entered an area with dose rates of
6 rem per hour in Reactor Coolant Pump Cubicle 2-4 using a radiation work permit
which only allowed entry into areas with dose rates up to 1 rem per hour. This finding
was placed into Pacific Gas & Electric Companys corrective action program.
The finding is greater than minor because it is associated with one of the cornerstone
attributes (exposure control) and affected the cornerstone objective because it could
have resulted in unplanned, unintended radiation dose. The inspector determined that
the finding was of very low significance because (1) it was not an ALARA finding, (2) it
was not an overexposure, (3) it did have a substantial potential for overexposure, and
(4) it did not compromise the ability to assess doses. This finding also had crosscutting
aspects associated with human performance (Section 2OS1).
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Enclosure
B.
Licensee-Identified Violations
Violations of very low significance were identified by Pacific Gas & Electric Company
and have been reviewed by the inspectors. Corrective actions taken or planned by
Pacific Gas & Electric Company appear reasonable. The violations are listed in
Section 4OA7 of this report.
Enclosure
REPORT DETAILS
Summary of Plant Status
Diablo Canyon Unit 1 began this inspection period at 100 percent power. On
December 20, 2004, operators reduced reactor power to approximately 84 percent power for
main turbine valve testing and Path 15 transmission line testing. Operators restored reactor
power to 100 percent on December 21, 2004, following completion of testing. Unit 1 remained
at 100 percent power for the duration of the inspection period.
Diablo Canyon Unit 2 began this inspection period at 100 percent power. On October 3, 2004,
operators reduced Unit 2 reactor power to approximately 50 percent to support main condenser
cleaning. Following cleaning activities, reactor power was returned to 100 percent.
On October 25, 2004, operators commenced a Unit 2 reactor shutdown for Refueling
Outage 2R12 and entered Mode 3 (Hot Standby). Operators initiated a plant cooldown and
entered Mode 4 (Hot Shutdown) on October 25 and Mode 5 (Cold Shutdown) on October 26.
On October 30 Unit 2 entered Mode 6 (Refueling) when maintenance personnel de-tensioned
the reactor vessel head. Operators commenced core offload on November 2 and completed
core offload on November 4. Unit 2 remained de-fueled until November 22 when Unit 2 entered
Mode 6 as a result of operators reloading fuel into the reactor vessel. Unit 2 entered Mode 5 on
November 28 when maintenance personnel tensioned the reactor vessel head. Operators
began increasing reactor coolant temperature, and Unit 1 entered Mode 4 on December 5.
Operators continued to increase reactor coolant temperature, and Unit 2 entered Mode 3 on
December 8. On December 10 operators commenced a reactor startup, and Unit 2 reached
Mode 2 (Startup). Operators continued to increase reactor power, and Unit 2 entered Mode 1
(Power Operations) on December 12. On December 16 the Unit 2 main generator was
paralleled to the grid; ending Refueling Outage 2R12. Unit 2 reached 100 percent power on
December 22 and remained at that power level for the duration of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01
Adverse Weather (71111.01)
a.
Inspection Scope
Cold Weather Operations
The inspectors reviewed the Primary and Backup Meteorological temperature readings
for the inspection period to determine if adequate protections against cold weather were
necessary to prevent freezing of outside equipment. The inspectors noted that the
minimum outside temperature for the inspection period was 45°F, which was expected
for coastal weather conditions. The cold weather or freeze protection was therefore not
necessary, and a complete inspection sample could not be performed.
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Enclosure
b.
Findings
No findings of significance were identified.
1R04
Equipment Alignments (71111.04)
The inspectors performed two partial system walkdowns during this inspection period.
Partial System Walkdowns
.1
Unit 2 Gammametrics Neutron Detector N-52
a.
Inspection Scope
On November 3, 2004, while Source Range Detector N-32 was in a maintenance outage
window, the inspectors performed a partial system walkdown of the Gammametrics
Neutron Detector N-52. The inspectors observed alignment, the availability of electrical
power, and procedural usage of the equipment. The inspectors used the following
documents:
Drawing 108007, Neutron Detector & Temperature Monitor Locations, Sheet 6,
Revision 38
Procedure PEP R-8DS1, Core Offload Sequence, Revision 6
Procedure OP B-8DS1, Core Unloading, Revision 34
b.
Findings
Introduction. The inspectors identified a Green noncited violation (NCV) for the failure to
develop a core offload sequence that maintained the operability of the source range
neutron flux monitors, as required by 10 CFR Part 50, Appendix B, Criterion V.
Inaccurate labeling of the neutron detector for core offload planning maps resulted in
reliance on one of two detectors that had became neutronically uncoupled from the core
during core offload and required suspension of core alterations.
Description. Technical Specification 3.9.3 requires two source range neutron flux
monitors be operable while in Mode 6. The purpose of the detectors is to alert operators
to unexpected changes in core reactivity, such as a boron dilution accident or an
improperly loaded fuel assembly. Prior to core offload, Source Range Detector N-32
was removed from service for maintenance. The Diablo Canyon licensing basis
provides the use of either the Gammametrics Neutron Detectors, N-51 or N-52, as
alternate source range neutron flux monitors. Pacific Gas & Electric Company (PG&E)
chose to use Detector N-52 and Source Range Detector N-31 as the two operable
source range neutron flux monitors during core offload. Reactor engineers planned to
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Enclosure
remove the fuel assemblies farthest from the two detectors first, so that the detectors
would always sense the reactivity of the fuel assemblies. Core offloading was controlled
by Procedure OP B-8DS1, which referenced Procedure PEP R-8DS1. Procedure
PEP R-8DS1 controlled the core offload sequence.
On November 3, 2004, operators were in the process of removing fuel assemblies from
the Unit 2 reactor vessel. When operators had offloaded 46 fuel assemblies, reactor
engineers recommended that operators not remove any more fuel assemblies until it
was understood why the source range reading from Detector N-52 had trended down.
Subsequently, reactor engineers discovered that the core offload sequence was
developed using both a paper and computer-based map that had incorrectly labeled
Detector N-51 as N-52. Reactor engineers determined that Gammametrics Neutron
Detector N-52 had become neutronically decoupled from the core (i.e., would not be
able to adequately sense reactivity changes due to the distance to the fuel assemblies).
Operators then declared Detector N-52 inoperable. Operators also suspended core
alterations, as required by Technical Specification 3.9.3, Refueling Operations, until it
was later verified that Detector N-51 could now be used as the second source range
neutron flux monitor.
The inspectors verified operator actions prior to, and following, the suspension of core
alterations. On November 3, 2004, prior to the suspension of core alterations, the
inspectors questioned operators concerning the downward trend of Detector N-52. At
that time, operators stated that the trend was expected. The inspectors noted that the
operators, with reactor engineering concurrence, continued with the core offload until
they later questioned the declining trend. A human performance crosscutting aspect
was identified for the labeling error in the core offload planning maps, which
subsequently resulted in the core offload sequence being developed in a manner that
caused Detector N-52 not to have any adjacent fuel assembly. A second human
performance crosscutting aspect was identified for the failure to ascertain the cause of
the downward trend when first identified by the inspectors.
Analysis. The performance deficiency associated with this finding is the failure to
develop an adequate core offload sequence that would have maintained the operability
of both source range neutron flux monitors. The finding impacts the Barrier Integrity
Cornerstone to provide reasonable assurance that physical design barriers protect the
public from radio nuclide releases caused by accidents or events and is associated with
the barrier performance attribute for procedure quality which could impact cladding. The
finding is more than minor when compared to Example 4.e of Inspection Manual
Chapter 0612, Appendix E. Similar to the example, Procedure OP B-8DS1, Step 5.2.1
described a responding nuclear instrument as having at least one fuel assembly face-
adjacent or diagonally adjacent to the detector. Using Checklist 4 of Inspection Manual
Chapter 0609, Appendix G, Attachment 1, the finding was determined not to increase
the likelihood of a loss of reactor coolant system inventory, degrade PG&Es ability to
terminate a leak path or add reactor coolant system inventory when needed, or degrade
PG&Es ability to recover decay heat removal once it is lost. Therefore, the finding was
screened as having very low safety significance.
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Enclosure
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Contrary to the above, PG&E failed to offload the Unit 2 core
in a manner that would have left a fuel assembly adjacent to Detector N-52, in
accordance with Procedure OP B-8DS1. The failure to offload the core in the
appropriate manner resulted in the inoperability of Detector N-52. Because the failure to
offload the core in the appropriate manner is of very low safety significance and has
been entered into the corrective action system as AR A0622599, this violation is being
treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 50-323/04-05-01, Mislabel of Neutron Flux Detector Resulted in Neutronic
Decoupling of a Detector From the Core.
.2
Units 1 and 2 Containment Fan Cooler Units (CFCUs)
a.
Inspection Scope
On November 26, 2004, while Unit 2 was in a refueling outage, the inspectors
performed a partial system walkdown of Units 1 and 2 CFCUs. The inspectors
observed valve alignment, the availability of electrical power and cooling water, labeling,
lubrication, structural support, and material condition. In addition, the inspectors
reviewed corrective action documents pertaining to CFCUs. These documents are
listed in Attachment 1.
b.
Findings
Introduction. The inspectors identified a Green NCV for the failure to promptly correct
CFCU reverse rotation, as required by 10 CFR Part 50, Criterion XVI. The failure to
promptly correct CFCU reverse rotation impacted the operability of the CFCUs over the
13-year period that reverse rotation was observed.
Background. The safety-related function of the CFCUs, along with the containment
spray system, is to provide containment atmosphere cooling to limit postaccident
pressure and temperature inside containment to less than the design values. Technical
Specification 3.6.6, Containment Spray and Cooling Systems, requires that at least
3 CFCUs be operable or enter the respective action statements found in Technical
Specification 3.6.6. Both Units 1 and 2 have 5 CFCUs each. Each CFCU has a
backdraft damper to prevent reverse rotation of the fan, particularly at the onset of a
loss-of-coolant accident where the pressure pulse from the break could induce sufficient
reverse rotation of the fan. Reverse rotation of the fan could impose high starting
currents and cause the CFCUs to trip on overcurrent or overload.
Description. On September 24, 2004, PG&E initiated AR A0619185 to document the
adverse trend with respect to CFCU performance. At that time on Unit 2, CFCU 2-5 was
inoperable due to reverse rotation, CFCU 2-3 was only considered operable when it was
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Enclosure
running, and CFCU 2-4 was considered inoperable until its backdraft dampers were
verified to be closed. For Unit 1, CFCU 1-1 and CFCU 1-2 exhibited reverse rotation,
but were considered operable due to the slow rate of rotation (34 and 30 rpm
respectively). The inspectors reviewed the history of CFCU reverse rotation and found
that the issue had existed since 1991, as first documented in AR A0224682. The
inspectors observed more than 20 ARs from that time to the present that described
reverse rotation of CFCUs. The majority of the CFCUs found in reverse rotation were
determined to be operable based upon Calculation PET-92-119, RCFC Reverse Speed
vs. Torque, Rev. 0. The inspectors observed that the speed of reverse rotation was
dependent upon the size of the opening in the backdraft dampers and the proximity of
other running CFCUs. From interviews with maintenance and engineering personnel,
and through a review of ARs, the inspectors learned that the backdraft dampers would
hang partially open due to damper blades rubbing against the backdraft damper frame,
or as a result of broken bolts on some of the blades that would allow them to remain
open. Both the blade rubbing and the broken bolts were attributed to the vibration that
backdraft dampers are subjected to during normal plant operation. The inspectors also
observed that most of the operability determinations for the CFCU reverse rotation were
based on the observed reverse rotation speed of the CFCUs and not the potential
reverse rotation speed that could be experienced during a design basis accident.
Through a review of ARs, the inspectors identified that two ARs documented an adverse
trend in CFCU reverse rotation, while two other ARs evaluated design changes to
correct the problem. In September 1996, AR A0421679 was initiated to discuss
replacement alternatives to the CFCU backdraft dampers. In this evaluation, PG&E
decided to operate and maintain the backdraft dampers as they were. The decision was
reached after considering budget issues and the feasibility of design alternatives. In
May 2002, AR A0557943 was initiated to again review design alternatives to the CFCU
backdraft dampers. Approximately1 year later, PG&E decided to install anti-rotation
devices on all the CFCUs. PG&E planned to have the anti-rotation devices installed in
Refueling Outages 1R13 and 2R13, which would be Fall 2005 and Spring 2006
respectively. In November 2003, AR A0595426 was written to address a potentially
adverse trend with ventilation backdraft dampers. The AR acknowledged one CFCU
backdraft damper issue, which was associated with the reverse rotation of CFCU 2-5.
The AR was subsequently closed when it was determined that there was not an adverse
trend with backdraft dampers. In September 2004, AR A0619185 was written to
address the reverse rotation of 5 CFCUs between Units 1 and 2.
The inspectors determined that PG&E had not promptly corrected a condition adverse to
quality. CFCU reverse rotation had been observed for approximately 13 years and at
least two evaluations had considered corrective actions for the CFCU backdraft
dampers. While PG&E has planned corrective actions for the backdraft dampers in
AR A0557943, the corrective actions will not come to completion until 3 to 4 years after
the ARs initiation. Since the initiation of AR A0557943, the operability of at least two
CFCUs has been impacted. The inspectors interviewed maintenance and engineering
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Enclosure
personnel concerning current actions in Refueling Outage 2R12 to address reverse
rotation of CFCUs. The inspectors determined that the preventive maintenance
performed on the CFCUs during Refueling Outage 2R12 had no significant difference
from maintenance that had taken place in previous refueling outages.
Analysis. The performance deficiency associated with this finding is the failure to
promptly correct the reverse rotation of CFCUs. The finding impacts the Barrier Integrity
Cornerstone to provide reasonable assurance that physical design barriers protect the
public from radio nuclide releases caused by accidents or events and is associated with
the barrier performance attribute. The finding is more than minor when considering
Example 3.g of Inspection Manual Chapter 0612, Appendix E. Similar to the example,
PG&E observed reverse rotation of CFCUs for 13 years, and the reverse rotation
impacted the operability of the CFCUs. Using the Significance Determination Process
(SDP) Phase 1 Screening Worksheet from Inspection Manual Chapter 0609, the finding
was determined to be of very low safety significance since it was determined that there
was not an actual loss of defense-in-depth in containment pressure control or hydrogen
control.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, states,
in part, that measures shall be established to assure that conditions adverse to quality,
such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and nonconformance are promptly identified and corrected. Contrary to the
above, PG&E failed to promptly correct the reverse rotation of CFCUs, which impacted
the operability of the CFCUs for a time span of approximately 13 years. Because this
failure to promptly correct the CFCU reverse rotation is of very low safety significance
and has been entered into the corrective action program as AR A0619185, this violation
is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement
Policy: NCV 50-275; 323/04-05-02, Failure to Promptly Correct Containment Fan Cooler
Unit Reverse Rotation.
1R06
Flood Protection Measures (71111.06)
.1
Internal Flood Protection
a.
Inspection Scope
The inspectors reviewed PG&Es flood protection measures for Unit 2 to ensure that
adequate precautions had been taken to mitigate internal flood risks. In particular, the
inspectors reviewed underground electrical conduit inspections performed on the vital
4kV buses during Refueling Outage 2R12. In support of the inspection, system
engineers were interviewed and ARs A0615559 and A0620471 were reviewed.
b.
Findings
No findings of significance were identified.
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Enclosure
.2
External Flood Protection
a.
Inspection Scope
The inspectors reviewed PG&Es flood protection measures for Units 1 and 2 to ensure
that adequate precautions had been taken to mitigate external flood risks. In particular,
the inspectors walked down the transformer yards for Units 1 and 2 for flooding
potential. The inspectors used Chapter 3 of the Final Safety Analysis Report Update
and ARs A0621185 and A0621626 in support of this inspection.
b.
Findings
No findings of significance were identified.
1R08
Inservice Inspection Activities (71111.08)
.1
Performance of Nondestructive Examination Activities Other than Steam Generator
Tube Inspections
a.
Inspection Scope
The inspectors observed the ultrasonic system calibration, and ultrasonic and visual
examinations. The inspectors observed five examinations, which are listed in the
attachment.
During the review of these examinations, the inspectors verified that the correct
nondestructive examination procedure was used, examinations and conditions were as
specified in the procedures, and test instrumentation or equipment was properly
calibrated and within the allowable calibration period. The inspectors also reviewed the
documentation to determine if indications revealed were compared against the American
Society of Mechanical Engineers (ASME) Code specified acceptance standards, and
that the indications were appropriately dispositioned. The nondestructive examination
certifications of the personnel observed performing examinations or identified during
review of completed examination packages were reviewed by the inspectors.
b.
Findings
No findings of significance were identified.
.2
Steam Generator Tube Inspection Activities
a.
Inspection Scope
The inspection procedure specified, with respect to in-situ pressure testing, performance
of an assessment of in-situ screening criteria to assure consistency between assumed
nondestructive examination flaw sizing accuracy and data from the Electric Power
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Enclosure
Research Institute (EPRI) examination technique specification sheets. It further
specified assessment of appropriateness of tubes selected for in-situ pressure testing,
observation of in-situ pressure testing, and review of in-situ pressure test results. The
inspectors did not observe in-situ pressure testing because none was required based on
a review of the data.
The inspectors selected and reviewed the Acquisition Technique Sheets and their
qualifying EPRI Examination Technique Specification Sheets to verify that the essential
variables regarding flaw sizing accuracy had been identified and qualified through
demonstration.
The inspection procedure specified comparing the estimated size and number of tube
flaws detected during the current outage against the previous outage operational
assessment predictions to assess PG&Es prediction capability. The inspectors
reviewed PG&Es report, Steam Generator Tubing Degradation Assessment for
Diablo Canyon Unit 2 Refueling Outage 2R12, October 2004. The purpose of the
assessment is to identify degradation mechanisms and for each mechanism to
determine proper detection technique, determine number of tubes, establish structural
limits, and establish flaw growth rates.
The inspection procedure specified confirmation be made that the steam generator tube
eddy-current testing scope and expansion criteria meet Technical Specification
requirements, EPRI guidelines, and commitments made to the NRC. The inspectors
review determined that the steam generator tube eddy-current testing scope and
expansion criteria were being met.
The inspection procedure also specified that, if PG&E identified new degradation
mechanisms, then verify that PG&E had fully enveloped the problem in an analysis and
had taken appropriate corrective actions before plant startup. At the time of this
inspection, no new degradation mechanisms had been identified.
The inspection procedure also required confirmation that all areas of potential
degradation were being inspected, especially areas which were known to represent
potential eddy-current testing challenges (e.g., top-of-tubesheet, tube support plates,
and U-bends). The inspectors confirmed that all known areas of potential degradation,
including eddy-current testing-challenged areas, were included in the scope of
inspection and were being inspected.
The inspection procedure further required that repair processes being used were
approved in the Technical Specification for use at the site. At the time of this inspection,
PG&E had not performed or used the designated Technical Specification-approved
repair processes, thus, there was no opportunity to observe implementation of any
potential repairs (e.g., plugging operations). The inspectors also verified that none of
the flawed tubes identified by PG&E required in-situ pressure testing.
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Enclosure
The inspection procedure also required confirmation that the Technical Specification
plugging limit was being adhered to, and determination whether depth sizing repair
criteria were being applied for indications other than wear or axial primary water stress
corrosion cracking in dented tube support plate intersections. The inspectors confirmed
that PG&E adhered to these specifications.
The inspection procedure stated that if steam generator leakage greater that 3 gallons
per day was identified during operations or during post-shutdown visual inspections of
the tubesheet face, then assess whether PG&E had identified a reasonable cause and
corrective actions for the leakage based on inspection results. The inspectors did not
conduct any assessments because this condition did not exist.
The inspection procedure required confirmation that the eddy-current testing probes and
equipment were qualified for the expected types of tube degradation and assessment of
the site-specific qualification of one or more techniques. The inspectors observed
portions of all eddy-current testing performed. During these examinations, the
inspectors verified that (1) the probes appropriate for identifying the expected types of
indications were being used, (2) probe position location verification was performed,
(3) calibration requirements were adhered to, and (4) probe travel speed was in
accordance with procedural requirements. The assessment of site-specific
qualifications of the techniques being used, including a listing of the specific techniques
and qualifications reviewed, is addressed and identified in the table above.
Finally, the inspection procedure specified the review of one to five samples of eddy-
current testing data if questions arose regarding the adequacy of eddy-current testing
data analyses. The inspectors did not identify any results where eddy-current testing
data analyses adequacy was questionable.
b.
Findings
No findings of significance were identified.
.3
Identification and Resolution of Problems
a.
Inspection Scope
The inspectors reviewed 10 inservice inspection-related condition reports issued during
the current and past refueling outage, and verified that PG&E identified, evaluated,
corrected, and trended problems. In this effort, the inspectors evaluated the
effectiveness of PG&Es corrective action process, including the adequacy of the
technical resolutions.
b.
Findings
No findings of significance were identified.
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Enclosure
1R11
Licensed Operator Requalification (71111.11)
.1
Licensed Operator Requalification
a.
Inspection Scope
On December 14, 2004, the inspectors witnessed one operator requalification exam in
the simulator. The scenario involved a loss of a nuclear instrument, a trip of a main feed
pump, and a steam generator tube rupture coincident with a stuck open steam
generator safety valve. The inspectors verified the crews ability to meet the objectives
of the training scenario, and attended the post-scenario critique to verify that crew
weaknesses were identified and corrected by PG&E staff.
b.
Findings
No findings of significance were identified.
.2
Biennial Inspection
a.
Inspection Scope
The inspector reviewed the annual operating examination test results for 2004. Since
this was the first half of the biennial requalification cycle, PG&E had not yet
administered the written examination. These results were assessed to determine if they
were consistent with NUREG 1021, Operator Licensing Examination Standards for
Power Reactors, Revision 8, Supplement 1, guidance and Manual Chapter 0609,
Appendix I, Operator Requalification Human Performance Significance Determination
Process, requirements. This review included examination of test results, which
included 2 scenario group failures out of 15 total groups and 2 job performance
measures individual failures out of a total of 79 licensed operators. All personnel who
failed were remediated and retested prior to return to watch standing duty.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Effectiveness (71111.12)
a.
Inspection Scope
The inspectors performed three inspection samples of PG&Es Maintenance Rule
implementation for equipment performance problems. The inspectors assessed
whether the equipment was properly placed into the scope of the rule, whether the
failures were properly characterized, and whether goal setting was recommended, if
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Enclosure
required. Procedure MA1.ID17, Maintenance Rule Monitoring Program, Revision 13,
was used as guidance. The inspectors reviewed the following Action Requests.
A0618134, "Maintenance Rule Performance Criteria, Goal Setting Review," for
Units 1 Auxiliary Building Heating Ventilation and Air Conditioning System
A0618135, "Maintenance Rule Performance Goal Setting Review," for Unit 2
Diesel Engine Generator 2-2
A0613767, "Maintenance Rule Performance Goal Setting Review," for Unit 1
Nuclear Instrumentation System
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)
The inspectors performed two inspection samples of maintenance risk assessments and
one inspection sample of emergent work control.
.1
Risk Assessments
a.
Inspection Scope
The inspectors reviewed daily work schedules and compensatory measures to confirm
that PG&E had performed proper risk management for routine work. The inspectors
considered whether risk assessments were performed according to their procedures
and whether PG&E had properly used their risk categories, preservation of key safety
functions, and implementation of work controls. The inspectors used
Procedure AD7.DC6, On-line Maintenance Risk Management, Revision 7, as
guidance. The inspectors specifically observed the following work activities during the
inspection period.
(Unit 1) Preventive maintenance on Valve SW-1-FCV-601 and the associated
inoperability of Auxiliary Saltwater Pump 1-2 on October 7, 2004.
(Unit 2) Performance testing of Component Cooling Water Heat Exchanger 2-1,
inoperability of Containment Fan Cooler Unit 2-5, and maintenance on the Morro
Bay/Midway 1 Transmission line on October 8.
b.
Findings
No findings of significance were identified.
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Enclosure
.2
Emergent Work
a.
Inspection Scope
The inspectors observed emergent work activities to verify that actions were taken to
minimize the probability of initiating events, maintain the functional capability of
mitigating systems, and maintain barrier integrity. The scope of work activities reviewed
includes troubleshooting, work planning, plant conditions and equipment alignment,
tagging and clearances, and temporary modifications. The following activities were
observed during this inspection period:
(Unit 1) Diesel Engine Generators 1-2 and 1-3 starting air compressor crossties
to turbo air receivers (ARs A0622861 and A0622997)
b.
Findings
No findings of significance were identified.
1R14
Personnel Performance Related to Nonroutine Plant Evolutions and Events (71111.14)
.1
Unit 2 Feedwater Heater 2-2B Transient
a.
Inspection Scope
On December 23, 2004, Unit 2 experienced a feedwater transient when feedwater
Heater 2-2B tripped on high level. The cause of the high level in feedwater Heater 2-2B
was a worn groove in an air flapper for the pneumatic level controller. As a result of the
defective air flapper, the level controller failed to keep condensate from reaching a high
level in the feedwater heater. Observable effects to the plant included increased
condensate flow, a perturbation in main feedwater pump suction pressure, and a
decrease in the heater tank level.
The inspectors reviewed operator actions, equipment performance, applicable
procedures and plant records (equipment strip charts). The inspectors also interviewed
operations personnel, reviewed the event for level of investigatory response, corrective
actions, violation of NRC requirements, and generic issues.
b.
Findings
Introduction. An unresolved item was identified for review of the feedwater heater high
level trip alarm response procedure. Specifically, the inspectors are reviewing the
adequacy of the alarm response procedure to respond to abnormal conditions involving
the feedwater heaters.
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Enclosure
Description. On December 23, 2004, operators received Alarm PK 10-21, Input 646,
feedwater Heater 2-2B high level trip. The Unit 2 shift foreman dispatched the work
control lead (senior reactor operator) and turbine building nonlicensed operator to
investigate the cause of the alarm. The control room operators entered Alarm
Procedure AR PK 10-21, Feedwater Htrs High Lvl Trip, Revision 4, when the alarm
annunciated and took actions to trip the reactor if necessary. The control room
operators observed the condensate flow increased as the No. 2 heater drain tank level
and main feedwater pump suction pressure decreased. The work control lead was
instructed to investigate the cause of the feedwater heater high level trip alarm and
noticed that the level was high out-of-sight and the controlling air pressure to the level
control valve was low.
The work control lead observed that feedwater Heaters 2-2A and 2-2C were within their
normal operating band. Subsequently, he adjusted the setpoint for the level controller to
increase the controlling air pressure. This action opened the level control valve further
and allowed the condensate level within the feedwater heater to return to normal. The
work control leads statement indicated that he was proceeding to contact the control
room after adjusting the level controller that the level in the feedwater heater was high
out-of-sight when he was notified by two others in the area that the level was
decreasing. As control room operators waited to hear from the operators at the
feedwater heater, the feedwater heater high level trip alarm cleared and the work control
lead reported that the level was in normal range. After the high level trip alarm cleared,
control room operators learned that the level in feedwater Heater 2-2B was high out-of-
sight for approximately two minutes before the work control lead was able to bring the
level back within normal range
The inspectors reviewed Procedure AR PK 10-21 and noted that the diagnosis for a
feedwater heater tube break consisted of an indicated increase in condensate flow
concurrent with the feedwater heater level indication out-of-sight high. If only the level
indication was observed to be out-of-sight high then the problem may be due to a
malfunction of the level control system. However, a failed level controller, or a fail-
closed level control valve, would give the same indications of a feedwater heater tube
rupture; specifically an increase in condensate flow and an out-of-sight high condensate
level in the feedwater heater. The actions associated with a feedwater heater tube leak
would involve initiating a reactor trip and closing the main steam isolation valves, with
the shift foremans concurrence. A feedwater level controller malfunction provides other
verification steps to check the normal drain valve open and the dump valve is controlling
level in the sight glass. The operator actions also includes lowering the drain tank level.
The inspectors noted that Step 5.1.1 stated that if flow has not increased, then the high
level condition may be due to a malfunction of the level control system, and if flow has
increased, this could be an indication of a tube leak. The inspectors determined that
these statements in the procedure provided diagnostic information to the operators,
namely an increase in condensate flow and a high out-of-sight level on the feedwater
heaters, as evidence of a feedwater heater tube rupture, however, these conditions
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Enclosure
were also evident for the feedwater level controller malfunction. The inspectors
determined that with the information provided in the procedure and the plant conditions,
that there was sufficient evidence to result in the shift foreman deciding to trip the
reactor and close the main steam isolation valves. Furthermore, the inspectors
observed that PG&E had not developed a procedural bases for the actions specified by
Step 5.1.1. A human performance crosscutting aspect (resources) was identified for the
inadequate alarm procedure. The inspectors are reviewing the adequacy of alarm
response Procedure AR PK 10-21 to address a feedwater heater level control
malfunction as an unresolved item.
Analysis. No analysis was performed for this unresolved item.
Enforcement. Unresolved Item (URI) 50-323/04-05-03, Adequately of Alarm Procedure
For Feedwater Heater Level Control Malfunctions.
.2
Unit 2 Spent Fuel Pool (SPF) Level Drop
a.
Inspection Scope
On December 23, 2004, the Unit 2 SPF level dropped approximately 4 inches as a result
of Valve SFS-2-3, SFP skimmer pump casing drain to miscellaneous equipment drain
tank, being left open following a filter replacement. The inspectors observed operator
actions and equipment performance following the event. The inspectors also
interviewed operations personnel and reviewed the event for corrective actions, violation
of requirements, and generic issues.
b.
Findings
Introduction. A Green, self-revealing NCV was identified for the failure to appropriately
implement the procedure for SFP skimmer filter replacement, as required by Technical
Specification 5.4.1.a. This failure resulted in a loss of approximately 36,000 gallons of
water from the SFP.
Description. On December 23, 2004, operators implemented Clearance 79718 for
replacing the SFP skimmer filter. Attached to the clearance was Procedure OP B-7:III,
Spent Fuel Pool System - Shutdown and Clearing and Filter Replacement,
Revision 15. Section 6.3.1 of the procedures for shutting down and clearing the
skimmer pump and strainer had been marked for implementation. Following the
implementation of the clearance, the work control lead observed that Section 6.3.1 of
Procedure OP B-7:III was used, when Section 6.3.2, steps a through e, should have
been used. Section 6.3.2 of the procedure specifically addressed replacement of the
SFP skimmer filter. The work control lead marked steps g through l of Section 6.3.2
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Enclosure
for returning the SFP skimmer pump back to service. He noticed that, because
Section 6.3.1 had been used to clear the pump, 4 valves would be potentially mis-
positioned. The work control lead discussed the potential for the 4 valves to be
potentially mis-positioned with the oncoming shift work control lead.
Following SFP skimmer filter replacement, the oncoming shift work control lead
informed operators to restore the SFP skimmer system using Section 6.3.2. The work
control lead also informed the operators that he was not sure how the SFP skimmer
system had been cleared by the previous shift. Operators restored the SFP skimmer
system, and when they started the system, they found 3 valves mis-positioned.
Approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later operators noticed a steady increasing level in the
miscellaneous equipment drain tank. Operators then found that Valve SFS-2-3 was still
mis-positioned from the clearance of the skimmer pump. For the 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> that
Valve SFS-2-3 was mis-positioned, approximately 36,000 gallons of water was drained
from the SFP.
The inspectors determined that PG&E failed to properly implement Procedure OP B-7:III
when clearing the SFP skimmer system. Section 6.3.2 specifically addressed
replacement of the SFP skimmer filter. The inspectors also observed that other
operators were aware of a potential mis-position of valves. However, the need for
checking the alignment of these valves had not been adequately communicated to
and/or carried out by the operators who restored the SFP skimmer system. The
operators who restored the SFP skimmer system recognized and corrected the 3 mis-
positioned valves, but failed to adequately investigate the reason for the mis-position,
which was a missed opportunity to discover the 4th mis-positioned valve. A human
performance cross cutting aspect was identified for the failure on two occasions to
address configuration control concerns with the system.
Analysis. The performance deficiency associated with this event is the failure to
properly implement Procedure OP B-7:III as required by Technical Specification 5.4.1.a.
This deficiency impacted the Initiating Events Cornerstone that limit the likelihood of
events that upset plant stability during shutdown and affected the configuration control
attribute for operating equipment lineup. The finding was considered more than minor
using Example 5.a of Inspection Manual Chapter 0612. Specifically, Valve SFS-2-3 was
mis-positioned due to the use of the wrong section of Procedure OP B-7:III and then
returned to service. Additionally, operators had two opportunities to identify the mis-
positioning of Valve SFS-2-3 but failed to identify the condition. The mis-positioned
valve resulted in a loss of approximately 36,000 gallons of water from the spent fuel
pool. This finding was reviewed by NRC management in accordance with Inspection
Manual Chapter 0609 and 0612 and determined to be of very low safety significance.
This determination was based on the performance deficiency would not have resulted in
a loss of spent fuel pool inventory below the Technical Specification required level on a
loss of spent fuel pool cooling.
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Enclosure
Enforcement. Technical Specification 5.4.1.a requires, in part, that written procedures
shall be established, implemented, and maintained covering the applicable procedures
recommended in Appendix A of Regulatory Guide 1.33, Revision 2. Item 3.h of
Regulatory Guide 1.33, Appendix A recommends procedures for startup, operation, and
shutdown of fuel storage pool purification and cooling systems. Contrary to the above,
PG&E failed to properly implement Procedure OP B-7:III with regards to replacing the
SFP skimmer filter. The failure to properly implement this procedure resulted in mis-
position of Valve SFS-2-3 and the loss of approximately 36,000 gallons of water from
the SFP. Because the failure to properly implement Procedure OP B-7:III is of very low
safety significance and has been entered into the corrective action system as
AR A0628635, this violation is being treated as an NCV, consistent with Section VI.A of
the NRC Enforcement Policy: NCV 50-323/04-05-04, Failure to Properly Implement
Procedure for Spent Fuel Pool Skimmer Filter Replacement.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors reviewed seven inspection samples of operability evaluations. These
reviews of operability evaluations and/or prompt operability assessments and supporting
documents were performed to determine if the associated systems could meet their
intended safety functions despite the degraded status. The inspectors reviewed the
applicable Technical Specification, Codes/Standards, and Final Safety Analysis Report
Update sections in support of this inspection. The inspectors reviewed the following
ARs and operability evaluations:
(Unit 2) Environmental qualification of auxiliary feedwater flow indication cable
(ARs A0620857, A0621502)
(Unit 1) Emergency core cooling system (ECCS) voiding (AR A0621502)
(Unit 1) Startup Transformer 1-1 automatic tap changer in manual due to
unexpected step increases (AR A0625650)
(Unit 2) Residual Heat Removal Pump 2-2 socket weld crack at suction pressure
instrument line (AR A0624790)
(Units 1 and 2) Valve FW-2-LCV-110 failed closed (AR A0624790)
(Unit 2) DEG 2-3 lube oil instrument line crack (AR A0617419)
(Unit 1) Small water drip on feedwater pipe lead 2-2 (AR A0628484)
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Enclosure
b.
Findings
1.
Introduction. The inspectors identified a Green NCV for the failure to take
adequate corrective actions to prevent the ECCS void space from exceeding the
volume allowed by plant procedures. The void space volume caused operators
to declare the ECCS inoperable and enter Technical Specification 3.0.3 twice on
October 21, 2004.
Background. The ECCS shares components of the normal charging system.
The charging system consists of two centrifugal charging pumps (CCPs), one
positive displacement pump (PDP), the volume control tank and associated
piping, valves, and instrumentation. A hydrogen concentration is maintained in
the reactor coolant at a level of approximately 35 cc/kg to scavenge oxygen in
the primary coolant system. During normal system operation, gases come out of
solution at the reactor coolant pump seals due to the large pressure drop from
the high pressure primary system to the low pressure pump seal leak-off return
line and due to the low pressure and high temperature in portions of the pump
seal return line. When these gases come out of solution, they form voids in the
piping system. The presence of large voids can result in gas binding of pumps,
resulting in the loss of pump flow. With a CCP in operation, the high flow rates
entrain the gas bubbles and prevent the formation of voids in the piping system.
When the PDP is placed in service, the seal return line flow is reduced allowing
some of the entrained gases to accumulate in the stagnant CCP miniflow
recirculation line. This gas void can then be transported to the piping upstream
of Valves 8807A/B when a CCP is again placed in service.
In November 1998, Calculation STA-089, Allowable Accumulated Gas Volume
in the CCPs and SIPs [safety injection pump] Suction Cross-Tie Piping,
Revision 0, was developed based on industry experience. The calculation was
revised in 1999 and 2000 to include allowable gas accumulation near
Valves 8804A and 8807A/B. Parallel Valves 8807A/B are located in the high
point of the cross-tie section of the CCPs and safety injection pump suctions.
On May 14, 2004, during performance of Procedure STP M-89 (Unit 2), ECCS
System Venting, Revision 31, a void volume was discovered which exceeded
the allowable volume stated in Calculation STA-089. The void caused operators
to enter Technical Specification 3.0.3 for Unit 2 and vent the affected section of
piping in order to return the system to operable status.
In July 2004, a revision to Procedure OP B-1A:V (Unit 1), CVCS - Transfer of
Charging Pumps, Revision 19, was incorporated to include void monitoring
requirements recommended by Calculation STA-108. The procedure change
required monitoring of the piping on a shiftly basis for three days following
switching from PDP to CCP operation. This was done as an interim corrective
action to identify void formation prior to exceeding the allowable limits.
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Enclosure
Description. On October 21, 2004, following transfer from PDP 1-3 to CCP 1-2,
a void was identified at Valves SI-1-8807A/B during performance of
Procedure OP B-1A:V. The water level was determined to be 4.05 inches with a
minimum allowed level of 4.5 inches. Unit 1 entered Technical
Specification 3.0.3 at 9:52 a.m. and operators proceeded to vent the piping.
Unit 1 exited Technical Specification 3.0.3 at 10:08 a.m. Approximately
two hours later, at 12:03 p.m., the void space was monitored and found to be
4.45 inches. Technical Specification 3.0.3 was again entered until the piping
was vented and the system declared operable at 12:07 p.m.
Analysis. The performance deficiency associated with this finding is the failure
to take effective corrective action to prevent the formation of a gas void that
exceeded the volume allowed by station procedures. The finding involved the
Mitigating System cornerstone to ensure the availability, reliability and capability
of systems that respond to initiating events and affected the equipment
performance attribute. The finding is greater than minor because it is similar to
Example 2.f in Appendix E of Inspection Manual Chapter 0612. Similar to the
example, the void size had exceeded the limit described in Calculation STA-108.
Using the Inspection Manual Chapter 0609 Phase 1 Screening Worksheet, the
finding was of very low safety significance (Green) since the finding is not a
design or qualification deficiency that has been confirmed to result in a loss of
function per Generic Letter 91-18.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions,
states, in part, that measures shall be established to assure that conditions
adverse to quality, such as failures, malfunctions, deficiencies, deviations,
defective material and equipment, and nonconformance are promptly identified
and corrected. Contrary to the above, PG&E failed to incorporate adequate
corrective actions to prevent the void volume from exceeding the procedural
limit. Because this failure to apply adequate corrective actions is of very low
safety significance and has been entered into PG&Es corrective action program
(AR A0621238), this violation is being treated as an NCV, consistent with
Section VI.A of the NRC Enforcement Policy: NCV 50-275/04-05-05, Failure to
Adequately Correct ECCS Voiding Following Operation of the Positive
Displacement Pump.
2.
Introduction. The inspectors identified an unresolved item for the failure to
promptly correct a cracked lube oil instrument sensing line, as required by
10 CFR Part 50, Appendix B, Criterion XVI. As a result, there was an increased
potential for DEG 2-3 to trip on low lube oil level.
Description. On August 29, 2004, operators discovered a lube oil leak coming
from the welded connection of Valve DEG-2-1084 to the downstream 3/8 inch
instrument line. The instrument line connected the lube oil system to pressure
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Enclosure
switch PS-237. The pressure switch provided a low pressure alarm for the pre-
circulation lube oil pump. PG&E decided to correct the leak in the next available
maintenance outage window, which would be in Refueling Outage 2R12.
Additionally, in AR A0617419, engineers did not consider the leak to affect the
operability of DEG 2-3 and no formal prompt operability assessment was
performed at that time.
Following the Parkfield earthquake on September 28, 2004, operators initiated a
test run of the Unit 1 and 2 DEGs to verify their capability start and run. During
the pre-firing checks for DEG 2-3, it was noted that the oil leak had grown
significantly (approximately 12 drops per minute). Following discussions
between operations, maintenance, and engineering personnel, DEG 2-3 was
declared inoperable. Operators subsequently closed Valve DEG 2-1084, which
isolated the leak. DEG 2-3 was again considered operable under a prompt
operability assessment documented in AR A0617419. The cracked instrument
line was replaced on October 2, 2004.
PG&E personnel performed a failure analysis of the cracked tubing and
determined that the crack initiated at the toe of the weld and was the result of
high-cycle fatigue. The crack was circumferential at the toe of the weld, and was
through-wall for half of the tubings outer diameter. The source of the stress that
created the crack was the unsecured mass of Valve DEG-2-1084 and vibration
from the pre-circulation lube oil pump at standby and the DEG when it was in
operation. PG&E personnel evaluated the crack and determined that it would
have minor impact on DEG 2-3 operation. This evaluation was based on the
estimated force to completely break the cracked tubing (30 to 40 pounds) and
the calculated leakrate at an operating lube oil pressure of 90 psig, as compared
to a standby lube oil pressure of 15 psig. Engineers calculated the leakrate to be
0.0015 gph at a lube oil pressure of 90 psig. Based on this leakrate, and the
lube oil low level alarm setpoint of 110 gallons, engineers estimated
107,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of operation before the alarm would activate.
The inspectors performed an independent evaluation of the cracked tubings
impact on DEG 2-3. Based on the fact that DEG 2-3 only operated
approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> between the time the leak was discovered and the time
DEG 2-3 was declared inoperable, the inspectors observed that the crack had
propagated quickly; primarily from the vibration of the pre-circulation lube oil
pump only. The inspectors surmised that there was an increased probability that
the instrument tube would completely severe under several hours of DEG 2-3
operation. The inspectors, and PG&E personnel, calculated that if the tubing
severed, and was not obstructed, then the leakrate would become 10 to 15 gpm.
However, based on the mounting of the tubing it was determined that if the
tubing were to completely severe, the flow out of Valve DEG-2-1084 would be
obstructed by instrument tubing and the resulting flow would be 1 to 3 gpm.
PG&E estimated that DEG 2-3 could sustain a loss of 200 gallons of lube oil
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Enclosure
before damage to the engine began and/or the engine shutdown on low-low lube
oil pressure. The low lube oil level alarm would become active after DEG 2-3
lost 170 gallons of lube oil. Assuming no operator intervention before the low
lube oil level alarm became active, operators would have 10 to 30 minutes to
respond to DEG 2-3 and isolate Valve DEG-2-1084. The inspectors determined
that operators would be able to respond to such a scenario in a timely manner to
prevent damage to DEG 2-3.
Analysis. The performance deficiency associated with this event is the failure to
correct a cracked lube oil instrument tubing downstream of Valve DEG-2-1084.
This deficiency impacted the Mitigating Systems Cornerstone for reliability of
systems that respond to initiating events to prevent undesirable consequences
and affects the equipment performance attribute. The finding was and is more
than minor using Example 4.f of Inspection Manual Chapter 0612, Appendix E.
Similar to Example 4.f, the inspectors determined that there was impact to
DEG 2-3 operability. Using the SDP Phase 1 screening worksheets in
Appendix A of Inspection Manual Chapter 0609, the finding was determined to
be potentialy greater than very low safety significance because the failure could
have resulted in an actual loss of safety function of DEG 2-3.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action,
requires, in part, that measures shall be established to assure that conditions
adverse to quality, such as failures, malfunctions, deficiencies, deviations,
defective material and equipment, and nonconformance are promptly identified
and corrected. Contrary to the above, PG&E failed to promptly correct the
cracked lube oil instrument tubing on DEG 2-3. Specifically, PG&E observed the
crack, but did not adequately assess the growth rate of the crack or its potential
impact on DEG 2-3 operability. The failure to promptly correct the lube oil
instrument tubing is of very low safety significance and has been entered into the
corretive action system as AR A0617419. This is an unresolved item
URI 50-323/04-05-06, Failure to Promptly Correct Diesel Engine Generator Lube
Oil Instrument Line Crack, pending completion of the safety significance
determination.
1R16
Operator Workarounds (71111.16)
a.
Inspection Scope
The inspectors reviewed two individual operator workarounds and performed one
cumulative-effects review during this inspection period. An operator workaround is an
operator action taken to compensate for a degraded or nonconforming condition that
complicates the operation of plant equipment. The cumulative effect evaluation
assessed the impact of all operator workarounds on the operators ability to respond in a
correct and timely manner to plant transients and emergency situations. The individual
workarounds evaluated were:
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Enclosure
Auxiliary salt water heat exchanger differential pressure indicator
Steam dump setpoint
b.
Findings
No findings of significance were identified.
1R19
Postmaintenance Testing (71111.19)
a.
Inspection Scope
The inspectors reviewed six post-maintenance tests for selected risk-significant systems
to verify their operability and functional capability. As part of the inspection process, the
inspectors witnessed and/or reviewed the postmaintenance test acceptance criteria and
results. The test acceptance criteria were compared to the Technical Specification and
the Final Safety Analysis Report-Update. Additionally, the inspectors verified the tests
were adequate for the scope of work and were performed as prescribed, jumpers and
test equipment were properly removed after testing, and test equipment range,
accuracy, and calibration were consistent for the application. The following selected
maintenance activities were reviewed by the inspectors:
(Unit 2) Diesel Engine Generator 2-3 lube oil filter housing O-ring replacement
on July 12, 2004, (Work Order C0186068)
(Unit 2) Source Range Nuclear Instrument N-32 detector and moderator
replacement on October 30, 2004, (Work Order C0184572)
(Unit 2) Actuator replacement for steam lead 3 supply valve, MS-2-FCV-38, to
the turbine-driven auxiliary feedwater pump on October 26, 2004, (Work
Order C0189735)
(Unit 2) Air hose replacement for main steam isolation bypass
valve MS-2-FCV-25 on November 18, 2004, (Work Order R0260881)
(Unit 2) Position switch calibration for main steam isolation bypass
valve MS-2-FCV-24 on November 23, 2004, (Work Order R0260827)
(Unit 2) Position switch replacement for steam generator blowdown isolation
valve MS-2-FCV-762 on November 29, 2004, (Work Order C0192771)
b.
Findings
No findings of significance were identified.
-22-
Enclosure
1R20
Refueling and Outage Activities (71111.20)
a.
Inspection Scope
The inspectors witnessed and evaluated PG&Es performance during the 12th refueling
outage for Unit 2. The outage lasted from October 25 to December 16, 2004. Before
and during the outage, the inspectors evaluated PG&Es consideration of risk in
developing outage schedules; use of risk reduction methodologies in control of plant
configurations; development of mitigation strategies for losses of key safety functions;
and adherence to the operating license and Technical Specification requirements.
Specifically, the inspectors observed PG&Es actions in the following areas:
Outage risk control plan prior to, and during, implementation
Mode transitions from power operation (Mode 1) to reactor vessel de-fueled, and
then the return to power operation
Defense-in-depth and handling of unexpected conditions
Plant configuration control, particularly clearance of equipment
Supply and control of electrical power with regards to Technical Specification
requirements and outage risk plans
Adequacy of decay heat removal for the reactor vessel, refueling cavity, and
spent fuel pool
Fuel assembly movement, tracking, and inspections
Containment closure and containment closure capability with respect to the
Technical Specification and outage risk plans
Adequate control of reduced inventory and midloop conditions
Movement of heavy loads inside containment and the turbine building
b.
Findings
No findings of significance were identified.
1R22
Surveillance Testing (71111.22)
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Enclosure
a.
Inspection Scope
The inspectors evaluated eight routine surveillance tests to determine if PG&E complied
with the applicable Technical Specification requirements to demonstrate that equipment
was capable of performing its intended safety functions and operational readiness.
Included in the seven samples, one surveillance test involved a reactor coolant system
leak detection system and one surveillance test was also an inservice test. The
inspectors performed a technical review of the procedure, witnessed portions of the
surveillance test, and reviewed the completed test data. The inspectors also considered
whether proper test equipment was utilized, preconditioning occurred, test acceptance
criteria agreed with the equipment design basis, and equipment was returned to normal
alignment following the test. The following tests were evaluated during the inspection
period:
(Unit 2) Procedure STP M-9A, Diesel Engine Generator Routine Surveillance
Test, Revision 68, for DEG 2-3
(Unit 2) Reactor Coolant System Leak Detection Procedure STP I-65,
Containment Fan Cooler Collection Monitoring System Calibration, Revision 5A
for CFCU 2-3
(Unit 2) Procedure STP M-13H, 4KV Bus H Non-SI Auto-Transfer Test,
Revision 26
(Unit 2) Procedure STP M-15, Integrated Test of Engineered Safeguards and
Diesel Generators, Revision 38
(Unit 2) Procedure STP V-8, Slave Relay Test and Time Response of MSIV,
MSIV Bypass, and Steam Generator Blowdown Valves, Revision 13
(Unit 1) Procedure STP I-36-S3R13, Protection Set III, Rack 13 Channels
Operational Test, Revision 12
(Unit 2) Procedure STP V-7B, Test of Engineered Safeguards, Valve Interlocks
and RHR Pump Trip for RWST Level Channels, Revision 23
(Unit 2) Inservice Test Procedure STP P-AFW-21, Routine Surveillance Test of
Turbine-Driven Auxiliary Feedwater Pump 2-1, Revision 17
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
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Enclosure
1EP1 Exercise Evaluation (71114.01)
a.
Inspection Scope
The inspectors reviewed the objectives and scenario for the 2004 Biennial Emergency
Preparedness Exercise to determine if the exercise would acceptably test major
elements of the emergency plan. The scenario included a large and sudden loss-of-
reactor coolant to the reactor containment, with subsequent loss-of-coolant makeup and
injection sources, resulting in fuel cladding damage. A containment over-pressure
condition resulted in the rupture of a containment penetration, resulting in an ongoing
radioactive steam release to the environment. The licensee activated all of their
emergency facilities to demonstrate their capability to implement the emergency plan.
The inspectors evaluated exercise performance by focusing on the risk-significant
activities of classification, notification, protective action recommendations, and
assessment of offsite dose consequences in the simulator control room and the
following emergency response facilities:
Operations Support Center
The inspectors also assessed personnel recognition of abnormal plant conditions, the
transfer of emergency responsibilities between facilities, communications, protection of
emergency workers, emergency repair capabilities, and the overall implementation of
the emergency plan to verify compliance with the requirements of 10 CFR 50.47(b),
10 CFR 50.54(q), and Appendix E to 10 CFR Part 50.
The inspectors attended the postexercise critiques in each of the above emergency
response facilities to evaluate the initial licensee self-assessment of exercise
performance. The inspectors also attended the formal presentation of critique items to
plant management. The inspectors completed one sample during the inspection.
b.
Findings
No findings of significance were identified.
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
a.
Inspection Scope
The inspector reviewed changes made to Revision 4 of the Diablo Canyon Emergency
Plan, submitted in April, 2004. The revision change included Change 5 to Section 5,
Change 4 to Sections 4 and 7, Change 3 to Section 6, Change 2 to Sections 1, 2, and 8,
and Change 1 to Appendix A. In addition to several administrative changes, the revision
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Enclosure
change modified the notification process for the emergency response organization to
clarify that during an actual alert declaration, all emergency response organization
personnel will be called to respond to the declared emergency. The revision change
also clarified the onsite personnel accountability process, relocated the onsite support
center to the office area at the southern end of the technical support center, removed
the operations simulator UHF system radio broadcast function console due to an
upgrade of health physics communications equipment to satellite phones, and replaced
fluorescent lightning fixtures in the auxiliary building with metal halide fixtures to improve
plant lighting.
The revision change was compared to the previous revisions, to the criteria of
NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency
Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to
the requirements of 10 CFR 50.47(b) and 50.54(q), and to Diablo Canyon
Procedure AWP EP-004, 10 CFR 50.54(q) Guidance, Revision 0, to determine if the
revisions were made consistent with the regulations. The inspector completed one
sample during the inspection.
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control To Radiologically Significant Areas (71121.01)
a.
Inspection Scope
This area was inspected to assess PG&Es performance in implementing physical and
administrative controls for airborne radioactivity areas, radiation areas, high radiation
areas (HRAs), and worker adherence to these controls. The inspectors used the
requirements in 10 CFR Part 20, the Technical Specification, and PG&Es procedures
required by Technical Specification as criteria for determining compliance. During the
inspection, the inspector interviewed the radiation protection manager, radiation
protection supervisors, and radiation workers. The inspectors performed independent
radiation dose rate measurements and reviewed the following items:
Performance indicator events and associated documentation packages reported
by PG&E in the Occupational Radiation Safety Cornerstone
Controls (surveys, posting, and barricades) of the Auxiliary Building, Spent Fuel
Building, Radwaste Building, and Containment Building radiation, high radiation,
and airborne radioactivity areas
Radiation work permit, procedure, engineering controls, and air sampler
locations
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Enclosure
Conformity of electronic personal dosimeter alarm set points with survey
indications and plant policy; workers knowledge of required actions when their
electronic personnel dosimeter noticeably malfunctions or alarms
Barrier integrity and performance of engineering controls in two potential
airborne radioactivity areas
Adequacy of PG&Es internal dose assessment for one actual internal exposure
greater than 50 millirem CEDE
Physical and programmatic controls for highly activated or contaminated
materials (nonfuel) stored within spent fuel and other storage pools
Self-assessments and audits related to the access control program since the last
inspection
Corrective action documents related to access controls
Licensee actions in cases of repetitive deficiencies or significant individual
deficiencies
Radiation work permit briefings and worker instructions
Adequacy of radiological controls such as required surveys, radiation protection
job coverage, and contamination controls during job performance
Dosimetry placement in high radiation work areas with significant dose rate
gradients
Changes in licensee procedural controls of high dose rate - high radiation areas
and very high radiation areas
Controls for special areas that have the potential to become very high radiation
areas during certain plant operations
Posting and locking of entrances to all accessible high dose rate - high radiation
areas and very high radiation areas
Radiation worker and radiation protection technician performance with respect to
radiation protection work requirements
The following items were not available to be reviewed by the inspector:
Licensee event reports, and special reports related to the access control
program since the last inspection
-27-
Enclosure
b.
Findings
1.
Introduction. The inspectors reviewed a self-revealing, noncited violation of
Technical Specification 5.7.2. resulting from PG&Es failure to correctly lock a
high radiation area with dose rates greater than 1 rem per hour. The violation
had very low safety significance.
Description. On November 14, 2004, workers accessed the steam generator
platforms to remove the bowl suction fixtures from the hot and cold legs of all
four steam generators. Before removal of the suction hoses, the workers were
able to demonstrate to a radiation protection technician that the lower access
flaps of the shield doors could be opened far enough to remove the suction
fixtures with the locking mechanism still in place. With the lower flaps open, an
individual could expose a portion of the whole body (arm above the elbow) to
dose rates greater than 1 rem per hour, according to PG&Es radiation surveys.
The locking mechanism was the method used by PG&E to comply with the
Technical Specification requirements for control of a high radiation area
containing dose rates greater than 1 rem per hour; however, this control was
shown to be ineffective. The locking mechanisms were installed incorrectly.
Analysis. The failure to correctly control a high radiation area is a performance
deficiency. The finding is greater than minor because it is associated with one of
the cornerstone attributes (exposure control) and affected the cornerstone
objective because it could have resulted in unplanned, unintended radiation
dose. The finding involved the potential for workers to receive significant,
unplanned, unintended doses as a result of conditions contrary to Technical
Specification requirements; therefore, the inspector used the Occupational
Radiation Safety SDP described in Manual Chapter 0609, Appendix C, to
analyze the significance of the finding. The inspectors determined that the
finding was of very low significance because (1) it was not an ALARA finding,
(2) it was not an overexposure, (3) it did have a substantial potential for
overexposure, and (4) it did not compromise the ability to assess doses.
In addition, this finding had crosscutting aspects associated with human
performance. When the individuals failed to correctly install the locking
mechanism, it directly contributed to the finding.
Enforcement. Technical Specification 5.7.2.a. states, in part, that High Radiation
Areas with dose rates greater than 1 rem per hour at 30 cm from the radiation
source or from any surface penetrated by the radiation, but less than 500 rads
per hour at 30 cm from the radiation source or from any surface penetrated by
the radiation, each entryway to such an area shall be provided with a locked or
continuously guarded door or gate that prevents unauthorized entry. PG&E
violated this requirement when it used an ineffective method of preventing
unauthorized access to areas inside the steam generators with dose rates
greater than 1 rem per hour. The finding was documented in PG&Es corrective
action program as AR A0624199. Because this violation was of very low safety
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significance and was entered into PG&Es corrective action program, it is being
treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 50-323/04-05-07, Failure to lock a high radiation area with dose rates
greater than 1 rem per hour.
2.
Introduction. The inspectors reviewed a self-revealing, noncited violation of
Technical Specification 5.7.2, resulting from PG&Es failure to control entry into a
high radiation area with dose rates greater than 1 rem per hour through the use
of the correct radiation work permit. The violation had very low safety
significance.
Description. On July 31, 2004, a radiation protection technician and a reactor
operator entered the reactor containment building and went to Reactor Coolant
Pump Cubicle 2-4 to check the pump oil level. The objective was to observe the
sight glass from the cubicle labyrinth. The entry was authorized by a radiation
protection foreman, who instructed the two individuals to use Radiation Work
Permit 04-0002. The radiation work permit limited the total dose to 25 millirems
and limited the entry into areas with dose rates of no more than 1 rem per hour.
Upon reaching the Reactor Coolant Pump cubicle labyrinth, the two individuals
found that they could not see the sight glass as anticipated. The radiation
protection technician surveyed the work area inside the cubicle, identified
general area dose rates of 6 rem per hour, informed the operator, and decided
the work could progress. The two individuals exited the work area with dose and
dose rate alarms. As a result, PG&E determined that control of a high radiation
area with dose rates greater than 1 rem per hour had not been correctly
implemented.
Analysis. The failure to correctly control a high radiation area is a performance
deficiency. The finding is greater than minor because it is associated with one of
the cornerstone attributes (exposure control) and affected the cornerstone
objective because it could have resulted in unplanned, unintended radiation
dose. Because the finding involved the potential for workers to receive
significant, unplanned, unintended doses as a result of conditions contrary to
Technical Specification requirements, the inspector used the Occupational
Radiation Safety SDP described in Manual Chapter 0609, Appendix C, to
analyze the significance of the finding. The inspector determined that the finding
was of very low significance because (1) it was not an ALARA finding, (2) it was
not an overexposure, (3) it did have a substantial potential for overexposure, and
(4) it did not compromise the ability to assess doses.
In addition, this finding had crosscutting aspects associated with human
performance. When the individuals failed to follow the correct radiation work
permit, it directly contributed to the finding.
Enforcement. Technical Specification 5.7.2.a. states, in part, that High Radiation
Areas with dose rates greater than 1 rem per hour at 30 cm from the radiation
source or from any surface penetrated by the radiation, but less than 500 rads
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Enclosure
per hour at 30 cm from the radiation source or from any surface penetrated by
the radiation, the access to, and activities in, each such area shall be controlled
by means of a radiation work permit. PG&E violated this requirement when the
radiation protection technician and the reactor operator used the incorrect
radiation work permit to access an area with dose rates greater than 1 rem per
hour. The finding was documented in PG&Es corrective action program as
Action Request 615777. Because this violation was of very low safety
significance and was entered into PG&Es corrective action program, it is being
treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 50-323/04-05-08, Failure to access a high radiation area with dose rates
greater than 1 rem per hour with the correct radiation work permit.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1
Reactor Safety Performance Indicator Verification
a.
Inspection Scope
The inspectors verified six samples of performance indicators. The inspectors reviewed
these indicators for the period from the fourth quarter of 2003 through the third quarter
of 2004 to assess the accuracy and completeness of the indicator. The inspectors
reviewed plant operating logs and PG&E monthly operating reports to support this
inspection. The inspectors used NEI 99-02, Regulatory Assessment Performance
Indicator Verification, Revision 2, as guidance for this inspection. The following
performance indicators were verified:
Safety System Failures
Reactor Coolant System Activity
Reactor Coolant System Identified Leakage
b.
Findings
No findings of significance were identified.
.2
Occupational Radiation Safety Performance Indicator Verification
a.
Inspection Scope
The inspectors sampled licensee submittals for the performance indicators (PIs) listed
below for the period from the first quarter 2003 through the third quarter 2004. To verify
the accuracy of the PI data reported during that period, PI definitions and guidance
contained in NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 2, were
used to verify the basis in reporting for each data element.
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Occupational Exposure Control Effectiveness PI
Licensee records reviewed included corrective action documentation that identified
occurrences of locked high radiation areas (as defined in PG&Es Technical
Specification), very high radiation areas (as defined in 10 CFR 20.1003), and
unplanned personnel exposures (as defined in NEI 99-02). Additional records
reviewed included ALARA records and whole body counts of selected individual
exposures. The inspectors interviewed licensee personnel that were accountable for
collecting and evaluating the PI data. In addition, the inspectors toured plant areas
to verify that high radiation, locked high radiation, and very high radiation areas were
properly controlled.
Radiological Effluent Technical Specification/Offsite Dose Calculation Manual
Radiological Effluent Occurrences
Licensee records reviewed included corrective action documentation that identified
occurrences for liquid or gaseous effluent releases that exceeded PI thresholds and
those reported to the NRC. The inspectors interviewed PG&E personnel that were
accountable for collecting and evaluating the PI data.
b.
Findings
No findings of significance were identified.
.3
Emergency Preparedness Cornerstone:
a.
Inspection Scope
The inspectors sampled submittals for the performance indicators listed below for the
period from October, 2003, through September 30, 2004. The definitions and guidance
of Nuclear Engineering Institute NEI 99-02, Regulatory Assessment Indicator
Guideline, Revision 2, were used to verify the licensees basis for reporting each data
element in order to verify the accuracy of performance indicator data reported during the
assessment period.
@
Drill and exercise performance
@
Emergency response organization participation
@
Alert and notification system reliability
The inspectors reviewed a 100 percent sample of drill and exercise scenarios, 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 documentation related to three actual
emergency declarations of a Notice of Unusual Event, all related to earthquakes that
were monitored at the Diablo Canyon Plant. The inspectors reviewed the qualification,
training, and drill participation records for a sample of 10 emergency responders. The
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inspectors reviewed alert and notification system maintenance records and procedures,
and a 100 percent sample of siren test results. The inspectors also interviewed licensee
personnel that were responsible for collecting and evaluating the performance indicator
data. The inspectors completed three samples during this inspection.
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1
Daily Reviews
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
and in order to help identify repetitive equipment failures or specific human performance
issues for followup, the inspectors performed a daily screening of items entered into the
corrective action program (CAP). The review was accomplished by reviewing daily
Action Request Review Team packages and attending daily Operations morning
meetings.
.2
Semi-Annual Trend Review
a.
Inspection Scope
The inspectors performed a review of the PG&Es CAP and associated documents to
identify trends that could indicate the existence of a more significant safety issue. The
inspectors review was focused on repetitive equipment issues, but also considered the
results of daily inspector CAP item screening and inspectors review of daily plant status.
Other information that was considered in the semi-annual trend review was licensee
trending efforts and licensee human performance results. Particular items that were
considered in this semi-annual trend report include:
ARs associated with adverse trends
Quarterly Trending Manager Reports
Human performance error-free clock reset data
Quality assurance audit reports
System Health Reports
b.
Findings
The inspectors reviewed the second period 2004 (June 1 to October 24) Quality
Performance Assessment Report. The report discussed challenges seen in Unit 1
Refueling Outage 1R12 and, at the time of the report, challenges for preparing for Unit 2
Refueling Outage 2R12. Specific challenges mentioned included high workload and
lower resources during the summer. The report mentioned self-assessments,
management observations, operating experience trending, and bench marking
programs as needing management attention and focus in the year 2005 for long-term
improvements and sustained excellent performance to be achieved. Human
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performance issues, at the time of the report, tended to center on the Operations and
Security departments. With respect to the corrective action program, the Corrective
Action Review Board had been implemented, as well as the morning AR review meeting.
The report discussed problem identification and resolution issues associated with
troubleshooting and extent of condition issues related to Containment Spray Pump 2-2
grounds. The inspectors also reviewed quality assurance audits of the Emergency
Planning and Operations departments, but no outstanding trends were noted.
The inspectors reviewed the 3rd Quarter Trending Manager Reports for equipment
reliability and processes, procedures, and programs. The trending manager uses event
trending report data to identify potential adverse trends at Diablo Canyon Power Plant.
The tool was placed in full operation in the 4th quarter of 2003. The trending manager
reports showed an increasing trend in maintenance preventable functional failures, with
117 failures in the last three quarters of 2003 and 178 in the first three quarters of 2004.
Most of the maintenance preventable functional failures were related to diesel engine
generators, ventilation systems, compressed air systems, plant annunciator, and doors.
The inspectors reviewed the following ARs associated with adverse trends identified by
PG&E.
A0609910, Adverse Trend in Design Basis Documentation, listed 9 ARs from
Quality Assurances audit (Audit No. 040080101) of the diesel engine
generators, which identified several inconsistencies between the design criteria
memorandum, the calculations, and the design drawings. None of the
inconsistencies were considered significant by Quality Assurance. Corrective
actions included training and briefs with design engineering personnel to discuss
the types of findings in the audit.
A0609950, Adverse Trend in Configuration Control, listed 13 ARs that
described discrepancies between the design documentation and the as-found
installation and material condition of DEG components, impairment of fire
barriers, incorrect component database entry, and inadequate documentation of
DEG generator housing cracks. None of the discrepancies were determined by
Quality Assurance to impact DEG operability.
A0604597, Adverse Trend in Printed Circuit Cards Solder Connections, listed
two nonconformance reports, two quality evaluations, and one AR that described
issues with printed circuit card solder quality. Printed circuit card solder quality
issues had been discovered on DEG control circuits, battery charger control
circuits, and the solid-state protection system. Nonconformance
report N0002181 was initiated to address the root cause and corrective actions
for the poor solder quality.
A0612564, Potential Adverse Trend in Butterfly Valve Performance, was
generated by the Corrective Action Review Board based on past issues involving
butterfly valve liner degradation and limit stop settings. PG&E had initiated an
apparent cause analysis to address the past butterfly valve issues.
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A0618217, Evaluate Adverse Trend in Corrosion Problems, was generated by
reliability engineering based on equipment trend reports. The adverse trend
revealed an increase from 20 corrosion problems in the 4th quarter 2003 to 42 in
the 2nd quarter 2004. PG&E convened a panel of maintenance, engineering, and
coatings personnel to discuss the aspects of the corrosion issues. The most
affected equipment for corrosion was found at the intake structure, pipe racks,
and on top of the auxiliary buildings. Lack of resources for re-coating surfaces
and inadequate preventive maintenance were cited as the main causes of
corrosion problems.
The inspectors reviewed the system health reports and observed that both the DEGs
and fire protection equipment were in a yellow status, which required senior
managements attention. The DEGs were in a yellow status due to a need for
completing corrective actions associated with lube oil coking, auto-voltage regulator
card replacement, and system availability exceeding plant administrative limits. The fire
protection equipment was in yellow status due to a failure to fund long-term plans to
resolve corrosion degradation in the system.
The inspectors reviewed the human performance event free clock reset trend and data.
The event free clock reset trend is a 12 month-rolling average of the number of days
between clock resets. For the later half of 2004, the trend has been constant with an
average number of days between clock resets as 33 days. There were 11 clock reset
events from December 2003 to November 2004. Six of the events occurred during
refueling outages, 2 events were related to personnel injuries, and the other three
events occurred outside refueling outages. The inspectors reviewed the non-injury
events in the current inspection quarter, or previous inspection quarters.
.3
a.
Inspection Scope
Section 2OS1 evaluated the effectiveness of PG&E's problem identification and
resolution processes regarding access controls to radiologically significant areas and
radiation worker practices. The inspectors reviewed selected corrective action
documents for root cause/apparent cause analysis against PG&Es problem
identification and resolution process.
b.
Findings
No findings of significance were identified.
.4
Annual Sample Review
a.
Inspection Scope
The inspectors reviewed all action requests (corrective action program inputs)
associated with the last three emergency preparedness exercises. Action requests
associated with event classification, notification of offsite authorities, and processes for
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providing protective action recommendations were reviewed in detail to ensure that the
full extent of the issues were identified, an appropriate evaluation was performed, and
appropriate corrective actions were specified and prioritized.
b.
Findings
No findings of significance were identified.
.5
Problem Identification and Resolution Crosscutting Aspects Identified Elsewhere in this
Report
Section 1R04.2 identified a problem identification and resolution crosscutting aspect for
the failure to promptly correct the reverse rotation of CFCUs over a 13 year time period.
Section 1R15 identified two problem identification and resolution crosscutting aspects
for the failure to take adequate corrective actions to prevent the ECCS void space from
exceeding the volume allowed by plant procedures and the failure to promptly correct a
cracked lube oil instrument sensing line for DEG 2-3.
Section 4OA5 identified a problem identification and resolution crosscutting aspect
associated with the corrective actions to ensure measures taken to provide
compensatory actions for the removal of the earthquake force monitors were effective
and appropriately implemented.
Section 4OA5 identified a problem identification and resolution crosscutting aspect
documented in of this report. The issue involves the failure to ensure proper
environmental qualification of ASCO solenoid operated valves.
4OA3 Event Followup (71153)
.1
Vital 4kV Bus G De-Energized During Testing
a.
Inspection Scope
On November 2, 2004, DEG 2-1 auto-started from a valid 4kV Bus G undervoltage
signal. At the time the undervoltage signal was activated, maintenance personnel were
in the process of performing a phase sequence verification for DEG 2-1. The inspectors
observed operator actions and equipment performance. The inspectors also
interviewed operations, engineering, and maintenance personnel. The inspectors
reviewed the event for level of investigatory response, corrective actions, violation of
requirements, and generic issues.
b.
Findings
Introduction. A Green, self-revealing NCV was identified for the failure to set up phase
sequence test equipment according to procedure, as required by 10 CFR Part 50,
Appendix B, Criterion V. This failure resulted in the momentary de-energization of
Vital 4kV Bus G and the auto-start of DEG 2-1.
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Enclosure
Description. On November 2, 2004, maintenance personnel were performing
Procedure PMT 21.46, Diesel Generator 2-1 Phase Sequence Verification, Revision 1,
to verify the phase sequence of DEG 2-1. Maintenance personnel connected the test
equipment to Vital 4kV Bus G potential transformers and to DEG 2-1 potential
transformers. Seconds later, the auxiliary power supply to Vital 4kV Bus G was
removed and DEG 2-1 auto-started. Upon investigation, it was found that the test
equipment had been wired incorrectly, when compared to the drawing in
Procedure PMT 21.46. The drawing had maintenance personnel connect the primary
side of the test transformers in a delta configuration. The primary side of the test
transformers was denoted X1', X2', and X3'. The drawing had maintenance personnel
connect the secondary side of the test transformers in a wye configuration. The
secondary side of the test transformers was denoted H1', H2', and H3'. Contrary to
the drawing, maintenance personnel connected the primary side of the test transformers
in a wye configuration and the secondary side in a delta configuration. The result of
wiring the test transformers in this manner and connecting them to the potential
transformers was to introduce a direct short to ground on the secondary side of the
Vital 4kV Bus G and DEG 2-1 potential transformers. The short was introduced since
the secondary side of the potential transformers is an open-delta configuration and the
primary side of the test transformers was a wye configuration. The short circuit
degraded the voltage on the secondary side of the Vital 4kV Bus G potential
transformers, which caused the second level undervoltage relay to perceive an actual
degraded voltage on the bus. After second level undervoltage relay timed out, it
removed the auxiliary power supply from Vital 4kV Bus G. Since startup power was
cleared for maintenance, DEG 2-1 auto-started and loaded onto the bus.
The inspectors observed that safety-related electrical equipment operated as designed
when the undervoltage condition was sensed. PG&E acknowledged the maintenance
crew that performed the work were PG&E employees. However, the crew worked for
the substation-grid maintenance group, which is separate from Diablo Canyon Power
Plant. The inspectors also observed that Diablo Canyon Power Plant labels the primary
side of its three-phase transformers as X1', X2', and X3' and the secondary side as
H1', H2', and H3'. This labeling scheme is the opposite of industry practice, which is to
name the primary side as H1', H2', and H3' and the secondary side as X1', X2', and
X3'. The substation-grid maintenance crew was accustomed to the industry convention
for labeling transformer connections. This finding involved a human performance cross-
cutting aspect for the failure to wire the phase sequence test equipment properly for
Vital 4kV Bus G and DEG 2-1.
Analysis. The performance deficiency associated with this event is the failure to wire
and connect the test equipment according to Procedure PMT 21.46. The finding
impacted the Mitigating Systems Cornerstone for ensuring the availability and capability
of systems that respond to initiating events to prevent undesirable consequences that
was associated with pre-event human error performance. Considering Example 4.b of
Inspection Manual Chapter 0612, Appendix E, the finding is greater than minor since the
incorrect wiring and connection of the test equipment resulted in a vital bus de-
energization and the actuation of DEG 2-1. Using Checklist 4 of Inspection Manual
Chapter 0609, Appendix G, Attachment 1, the finding did not result in the Technical
Specifications for AC and DC power sources not being met and the finding was
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Enclosure
determined not to increase the likelihood of a loss of reactor coolant system inventory,
degrade PG&Es ability to terminate a leak path or add reactor coolant system inventory
when needed, or degrade PG&Es ability to recover decay heat removal once it is lost.
Therefore, the finding was screened as having very low safety significance
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Contrary to the above, PG&E failed to wire and connect the
phase sequence test equipment in accordance with Procedure PMT 21.46. The failure
to wire and connect the test equipment properly resulted in a momentary de-
energization of Vital 4kV Bus G and the auto-start of DEG 2-1. Because the failure to
correctly wire and connect the test equipment is of very low safety significance and has
been entered into the corrective action system as AR A0622434, this violation is being
treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 50-323/04-05-09, Failure to Wire and Connect Test Equipment Resulted in Vital
Bus De-Energization.
.2
(Closed) Licensee Event Report (LER) 05000323/2003-001-00, Steam Generator Tube
Plugging Due to Stress Corrosion Cracking.
On February 13, 2003, with Unit 2 in Mode 6 (Refueling), analysis of eddy current
testing on Steam Generator 2-4 indicated that greater than one percent of tubes were
defective. The inspectors verified that PG&E complied with Technical
Specification 5.5.9 and 5.6.10 and documented the deficiency in the corrective action
program. The inspectors also verified that PG&E took appropriate corrective actions
and no new findings were identified during the review. This LER is closed.
.3
(Closed) LER 05000323/2003-002-00, Unanalyzed Condition in the Unit 2 Component
Cooling Water System
On February 17, 2003, while Unit 2 was de-fueled, PG&E discovered that the liner for
Valve CCW-2-18 was damaged such that the valve could not close to provide adequate
train separation post-accident.
In NRC Inspection Report 50-275;323/2003-05, a self-revealing Green noncited violation
of 10 CFR 50, Appendix B, Criterion XI was identified for this issue. No new information
that would change the disposition of this issue was provided in this LER. This LER is
closed.
.4
(Closed) LER 05000323/2003-003-00, Technical Specification 3.4.12 Not Met Due to
Personnel Error.
On March 9, 2003, while Unit 2 was in Mode 5 (Cold Shutdown), operators placed the
power operated relief valve control switches in the "Closed" position vice the required
"Auto" position as required by Technical Specification 3.4.12 for low temperature over
pressure protection. This condition existed for approximately 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />.
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Enclosure
In NRC Inspection Report 50-275;323/2003-05, a licensee-identified Green noncited
violation of Technical Specification 3.4.12 was documented for this issue. No new
information that would change the disposition of this issue was provided in this LER.
This LER is closed.
4OA4 Other Crosscutting Aspects of Findings
Section 1R04.1 identified a human performance crosscutting aspect for the labeling
error in the core offload planning maps, which subsequently resulted in the core offload
sequence being developed in a manner that caused Detector N-52 not to have any
adjacent fuel assembly. A second human performance crosscutting aspect was
identified for the failure to ascertain the cause of the downward trend when first
identified by the inspectors.
Section 1R14.1 identified a human performance crosscutting aspect (resources) for an
inadequate alarm procedure.
Section 1R14.2 identified a human performance cross cutting aspect for the failure on
two occasions to address configuration control concerns with the spent fuel pool
skimmer system.
Section 2OS1 describes two issues with human performance crosscutting aspects which
involved personnel entry into a high radiation area with dose rates greater than 1 rem
per hour while using the incorrect radiation work permit and the incorrect installation of
locking mechanisms for a high radiation area with dose rates greater than 1 rem per
hour.
Section 4OA3.1 identified a human performance crosscutting aspect for the failure to
wire the phase sequence test equipment properly for Vital 4kV Bus G and DEG 2-1.
Section 4OA5.5 identified a human performance crosscutting aspect associated with
compensatory measures to address the removal of the earthquake force monitors.
4OA5 Other
.1
Temporary Instruction 2515/150: Circumferential Cracking of Reactor Pressure
Vessel (RPV) Head Penetration Nozzles
a.
Inspection Scope
The inspectors observed and reviewed PG&Es activities associated with the RPV head
and vessel head penetration nozzle inspection that were implemented in accordance
with the requirements of Order EA-03-009.
PG&E performed ultrasonic and eddy-current examinations of all control element drive
mechanism penetrations. The inspectors independently reviewed the inspection results
for two of the penetrations. PG&E did not identify any nozzle or weld degradation.
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Enclosure
PG&E performed a 100 percent visual inspection of the reactor vessel head. The
inspectors reviewed a detailed video tape of the head examination. No flaws were
identified.
b.
Findings
No findings of significance were identified.
.2
Temporary Instruction (TI) 2515/152, Reactor Pressure Vessel Lower Head Penetration
Nozzles (NRC Bulletin 2003-02), Revision 1
Background. The NRC noted in Regulatory Issue Summary 2003-13, NRC Review of
Response to Bulletin 2002-01, Reactor Pressure Head Degradation and Reactor
Coolant Pressure Boundary Integrity, that most licensee do not perform inspections of
Alloy 600/82/182 materials beyond those required by Section XI of the ASME Code to
identify potentially cracked and leaking components. For the RPV lower head, the
ASME Code specifics that a visual examination be performed during system pressure
testing. Licensees may meet the ASME Code requirement by performing an inspection
of the RPV lower head without removing insulation from around the head and its
penetrations. By performing the visual inspection in this manner, licensees may not be
able to detect the amounts of through-wall leakage that would be expected from flaws
due to primary water stress corrosion cracking or other potential cracking mechanisms.
Diablo Canyon Power Plant performed a bare metal visual (BMV) examination of the
RPV lower head penetrations on October 27-28, 2004. The BMV examination was
implemented to verify the absence of boric acid crystals, which may be evidence of a
leak in the lower head penetration nozzles.
a.
Inspection Scope
During the week of November 29, 2004, the inspectors conducted an evaluation and
assessment of the Unit 2 RPV lower head penetration BMV examination performed by
PG&E staff according to TI 2515/152. During the inspection, the inspectors performed
the following actions:
A review of PG&E response to NRC Bulletin 2003-02, Leakage from Reactor
Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure
Boundary Integrity, to ensure compliance with existing regulations;
A review of qualifications and certification of inspection personnel, as well as, the
quality of techniques and equipment to identify small boric acid deposits;
A verification that PG&E staff were appropriately following their procedural
guidance during the examination;
An independent review of a sample of lower head penetrations to verify the
absence of boric acid deposits that may be indicative or primary stress corrosion
cracking around the penetrations;
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Enclosure
A review of how PG&E staff dispositions evidence of boric acid on the RPV lower
head;
A verification of PG&Es ability and performance of a 100 percent visual
inspection of the penetrations;
A review of PG&Es corrective actions with regards to anomalies, deficiencies,
and discrepancies associated with reactor coolant system structures or the
examination process; and
Identification of areas on the RPV lower head or lower head penetration nozzles
obscured by debris, insulation, dirt, boric acid deposits from pre-existing leaks
such as from the reactor cavity seal, coatings, or other obstructions.
The inspectors observed 100 percent of the lower head penetration nozzles using
videotapes of the RPV lower head examination.
b.
Findings
The inspectors confirmed that PG&E staff inspected 360 degrees of 100 percent of the
RPV lower head penetration nozzles. In addition, PG&E performed a thorough
inspection of the general condition of the lower head. PG&E staff concluded that none
of the RPV lower head penetration nozzles indicated leakage per the BMV examination.
The inspectors reviewed staff training, equipment capability, procedures, and the
process by which the inspection was performed and found them to be adequate in
detecting small boron deposits that would indicate RPV lower head penetration nozzle
leakage.
Training and Qualifications
The inspectors reviewed the qualification and certification of the personnel performing
the examination. Qualifications for a VT-2 examiner were described in Procedure
TQ1.ID12, Qualification and Certification or NDE Personnel, Revision 2. The
inspectors found the procedure requirements to be consistent with industry standards.
In addition to training and qualification, each of the examiners had previous experience
with BMV examinations for both RPV top head and lower head. The examination
experience was gained at the Diablo Canyon Power Plant and other Westinghouse
pressurized water reactors. The inspectors reviewed training material for the
examiners, which included photos of the RPV lower head penetration nozzle leakage at
the South Texas Project Unit 1 and EPRI Technical Report 1007842, Visual
Examination for Leakage of PWR Reactor Head Penetrations.
Procedure ISI X-CRDM, Reactor Vessel Tap and Bottom Head Visual Inspections,
Revision 3, governed the BMV examination of the RPV lower head penetration nozzles.
The inspector verified that (1) criteria for the disposition of boric acid indications was
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Enclosure
appropriate, (2) conduct of the examination was sufficient and according to the
procedure, and (3) the procedural guidance satisfied commitments in PG&Es response
Condition of Unit 2 RPV Lower Head
The Unit 2 RPV did not have any active indications of boric acid leakage form any of the
penetrations. This determination was made based on a review of the videotaped
examination. The inspectors did note boric acid stains which ran down the RPV and
down some of the lower head penetrations. The boric acid stains did not have a three-
dimensional structure and were determined to have originated from an earlier reactor
cavity seal leak. In some instances, the boric acid stains supported very light surface
rust, but there was not indication of metal loss. PG&E determined the boric acid stains
would not impact the integrity of the RPV lower head, and therefore, no cleaning is
planned. The inspectors verified that the boric acid stains would not mask any potential
boric acid accumulation that would indicate RPV lower head penetration nozzle leakage.
No condition was identified that required repair.
Impediments to Effective Examinations
The inspectors concluded that PG&E examiners encountered no impediments that
impacted the examination of the RPV lower head. The examiners performed a
100 percent visual inspection of the RPV lower head.
.3
Temporary Instruction (TI) 2515/153, "Reactor Containment Sump Blockage (NRC
a.
Inspection Scope
The inspectors reviewed PG&E's response to NRC Bulletin 2003-001. PG&E's
response included plant modifications, interim procedure revisions, training, and
analysis to verify that the containment sump screens would be operable following the
spectrum of design basis accidents. The inspectors verified PG&E's actions in
response to NRC Bulletin 2003-001. The inspection consisted of interviews, reviews of
training records, containment sump inspections, containment walkdowns, and inspection
of the new containment sumps.
PG&E modified the containment sump screens to have greater surface area and to
cause the water to change direction to prevent direct impingement of debris on the
screens in Refueling Outages 1R12 (Unit 1), and 2R12 (Unit 2). PG&E constructed a
partial scale mockup to demonstrate the effectiveness of this new design. The
inspectors observed that the mockup of the new screens provided reasonable
assurance that the new design would maintain sump operability in the event of debris
migration to the containment sump screens postaccident.
The inspectors also verified that the emergency operating procedures were revised to
include interim actions to take in the event of screen clogging. The inspectors verified
that operators had been trained on this interim guidance.
-41-
Enclosure
During outage 2 R12 (Unit 2) on December 3, 2004, the inspectors performed a
containment walkdown to ensure that the containment was free debris. In addition, the
inspectors entered the containment sump to ensure there were no gaps in the screens
and that the sumps were free of debris.
Answers to Interim Questions in TI 2515/153
a.
Yes. PG&E conducts containment walkdowns to identify potential debris
sources at the end of each refueling outage (including the recently completed
outage 2R12).
b.
Not applicable.
c.
Not applicable.
d.
Yes. The walkdowns conducted in Outages 1R12 (Unit 1) and 2R12 (Unit 2)
included checks for gaps in the containment sump screens.
e.
Yes. Modifications to the containment sump screens are complete.
b.
Findings
No findings of significance were identified.
.4
(Closed URI 05000275;323/2003002-01): Licensee Made Changes to the Fire
Protection Program That Could Have the Potential to Adversely Affect Their Ability to
Achieve and Maintain Safe Shutdown.
a.
Inspection Scope
The inspectors identified an unresolved item in which PG&E made changes to the fire
protection program that could have the potential to adversely affect their ability to
achieve and maintain safe shutdown. In particular, PG&E removed a Thermo-Lag fire
barrier, and established manual actions to open component cooling water supply header
motor-operated Valve FCV-431 if it spuriously operated as a result of fire damage. This
item was made unresolved pending receipt of additional information from PG&E
concerning the methodology used for determining that Valve FCV-431 would not sustain
damage to the extent that it would not be able to be manually operated.
b. Findings
The inspectors referred this issue to the NRC Office of Nuclear Reactor
Regulation (NRR) for review. The NRR staff had discussions with PG&E and reviewed
technical information provided by PG&E. The conclusion was that Valve FCV-431 would
not be damaged in a stall condition and would remain available to be manually operated.
This closes URI 05000275;323/2003002-01.
-42-
Enclosure
Whether reliance on the manual use of Valve FCV-431 during a fire event, in lieu of
providing protection required by 10 CFR Part 50, Appendix R, Section III.G.2,
constitutes a violation of NRC requirements will be addressed in the closure of
Unresolved Item 05000275;323/2003002-02.
.5
(Closed URI 05000275;323/2004004-02): Evaluation of Earthquake Force Monitors for
EAL [emergency action level] Implementation that were identified in Section 1R14.1 and
1R17 of Inspection Report 05000275;323/2004004 and was the subject of EA 04-0169.
a.
Inspection Scope
The inspectors performed additional inspection associated with this unresolved item to
determine any performance issues associated with the modification to the earthquake
force monitors and the impact on implementing the Diablo Canyon Emergency Plan.
This included the adequacy of the earthquake force monitor modification, the associated
reviews, impact of work activities prior to and subsequent to August 9, 2004, on the
operators ability to appropriately assess a seismic event per the emergency action
levels (EALs) and any reduction in the effectiveness of the emergency plan.
b.
Findings
Introduction. The inspectors identified a Green NCV for the failure to establish
compensatory measures to ensure the prompt implementation of the Diablo Canyon
Emergency Plan as required by 10 CFR 50.54(q) and the risk significant planning
standard function,10 CFR 50.47(b)(4) was met.
Description. The inspectors noted that on August 9, 2004, PG&E removed the
earthquake force monitor (EFM) from service for surveillance testing on numerous
occasions without implementing compensatory actions for the operators to determine
the magnitude of a seismic event. The inspectors noted that from 1999-2004 the EFM
was inoperable for test and/or calibration 91 times. Most of these instances were of
short duration (i.e. up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />). However, several of these outages were of
appreciably longer duration. The longer outages occurred during June 16-19,1999;
December 1-4, 2000; April 25-27, 2002; May 25-29, 2002; November 6-8, 2003; and
December 30-31, 2003, respectively. In each of these instances, the EFM was
unavailable without specifically identifying the compensatory measures to be taken to
implement the emergency plan for natural phenomena (earthquake).
Procedure CP M-4, Section 2.2 required operators to determine the magnitude of an
earthquake (to classify the event in accordance with the emergency plan and direct
personnel actions) using the Earthquake Force Monitor in the control room. When the
EFM was removed from service for replacement, operators were not provided with
direction or training to implement the emergency plan with respect to assessing the
magnitude of a seismic event, without the EFM available. Operators questioned this
action, but were not given immediate direction on what instrumentation to use to assess
a seismic event. The inspectors questioned the Operations Manager, who stated that
"Operators would make a conservative call and declare a Notification of Unusual Event
-43-
Enclosure
if they felt an earthquake." The inspectors further continued to question PG&E as to
how a determination would be made for a significant earthquake (at the level of Site
Area Emergency). On August 10, 2004, Operations Management provided "Shift
Orders" to use one seismic monitor (ESTA-05, part of the backup system) that was
already installed, to determine the magnitude of an earthquake for classification
purposes. Procedure CP M-4 was revised on August 24, 2004, to provide the means of
assessing the magnitude of an earthquake.
Prior to August 10, 2004, PG&E had not identified the compensatory measures or
alternate seismic instrumentation that would be utilized to implement a significant
requirement of the emergency plan, i.e., to classify a seismic event at the level of a
NOUE (0.01 g as indicated on the EFM), an Alert (0.2 g as indicated on the seismic
monitors) or a Site Area Emergency (0.4 g's as indicated on the seismic monitors). Only
the NOUE criteria specifies the EFM as the means of validating the magnitude of a
seismic event.
PG&Es basis for emergency action levels is NUREG-0654, Revision 1, Appendix 1.
The emergency action levels affected by lack of seismic instrumentation were
Table 4.1-1, Diablo Canyon Emergency Plan, Revision 4.03:
Natural Phenomena (All Modes), VIII (18), Unusual Event, Ground motion felt
and recognized as an earthquake by a consensus of Control Room operators on
duty AND measuring greater than 0.01g on the Earthquake Force Monitor
Natural Phenomena (All Modes), VIII (17), Alert, Earthquake > 0.2g verified by
Seismic Monitors
Natural Phenomena (All Modes), VIII (9), Site Area Emergency, Earthquake >
0.4g verified by Seismic Monitors
In assessing PG&Es initial corrective actions, the inspectors questioned PG&E as to the
basis of the assigned significance of the action request to ensure that this deficiency
received sufficient management attention, and to verify that the immediate corrective
actions were effective. Following the identification of the concern on August 9, 2004,
PG&E upgraded the deficiency from an action request (lowest tier of significance) to a
nonconformance report (highest tier of significance) on August 28, 2004.
Other seismic monitors available during these periods would have required a trained
technician onsite to access the data or a coordinated effort with PG&Es offsite
geosciences group to assess the weak motion sensors located in the vicinity of Diablo
Canyon. These monitors and/or recorders were the Kinemetrics Free Field (ESTA27),
the former Engdhal acceleration and shock recorders, the Temp System installed for the
inoperable Terra Tech system and the Geoscience weak motion sensors. The reactor
seismic trip instrumentation was operable throughout each of these periods.
On August 9, 2004, the EFMs were removed from service to replace the Basic System
EFM with the new Syscom system. This same day operators raised concerns with how
they were to assess the magnitude of a seismic event during the period the seismic
-44-
Enclosure
instrumentation was unavailable. PG&E has provided additional information and
confirmed by the inspectors that establishes the initial duration as 2 days with a second
2 day period when the shift order referenced instrument was taken out of service. For
the first two day period other instruments could have been accessed within a half hour
to 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> period based on PG&Es assessment of the time required to call in a trained
technician if required (dependent on whether the trained technicians were on shift). The
inspectors determined that this time period could be met, however, the time involved
could be appreciably longer for large magnitude earthquakes that could present physical
limitations of an individuals ability to respond from road closures, etc. The NRC staff
has determined that at all times seismic instruments would be available to determine the
magnitude of a seismic event; however, delays could occur and these delays could
impact PG&Es ability to timely assess the magnitude of an earthquake in order to
implement its emergency plan for Natural Phenomena.
The inspectors determined that there were other periods when the EFMs had been
taken out of service for surveillance testing without compensatory actions being
identified for assessing the magnitude of an earthquake. On June 16-19,1999,
December 1-4, 2000, April 25-27, 2002, May 25-29, 2002, November 6-8, 2003,
December 30-31, 2003, August 9-10, 2004, and other lesser periods, PG&E failed to
establish compensatory measures to determine earthquake ground accelerations which
are used as entry conditions.
Analysis. The finding did not rise to a failure or degradation of the risk significant
planning standard function as other seismic instrumentations were available for the
periods identified that would permit PG&Es classification process to make an
appropriate classification, although the classification could be substantially delayed
beyond a 15 minute period. Other EALs have been established that would cause the
Notification of Unusual Event (NOUE), Alert and Site Emergency Classification to be
declared (IV. Loss of Control or Release of Radioactive Material and VI. Loss of
Engineered Safety Feature) if a release were to occur or damage to the plant following a
seismic event. Only the NOUE EAL specifies the use of the EFMs for classifying the
event.
Failure to provide compensatory actions for the timely implementation of the Diablo
Canyon Emergency Plan, Revision 4.03, for Natural Phenomena (All Modes) is a
performance deficiency because PG&E did not meet an RSPS function to ensure the
emergency classification and action levels for natural phenomena is in use. It is more
than minor because it has a potential to impact safety and because it was not a record
keeping or administrative issue or an insignificant procedural error. This deficiency
could have affected the Emergency Preparedness Cornerstone objective of ensuring the
capability to implement measures to protect the health and safety of the public during an
emergency, and is associated with attributes of facilities and equipment, and offsite
emergency preparedness. Utilizing the Failure to Comply Flow Chart in Manual
Chapter 0609, the performance deficiency does not result in a failure of the RSPS or a
degraded RSPS in that the unavailability of the seismic monitors would not prevent (but
could delay) the declaration of a Site Area Emergency, Alert or NOUE and results in a
Green finding. A seismic event is a self-revealing event that would cause the operators
to immediately initiate actions to assess the event. Other EALs were not impeded that
-45-
Enclosure
would result in EAL classifications up to and including the Site Area Emergency if
complications from a seismic event occurred. This finding has problem identification
and resolution aspects in that PG&E had opportunities to identify the emergency plan
impact prior to removing seismic instrumentation from service, followed by poor
recognition of the significance of the issue, and ineffective initial corrective action.
Enforcement. This finding is a violation of 10 CFR 50.54(q) which requires in part that a
licensee follow and maintain in effect emergency plans. Specifically, Diablo Canyon
Emergency Plan, Revision 4.03, specifies emergency action thresholds in Table 4.1-1
for a NOUE, an Alert, and a Site Area Emergency based on seismic activity. The finding
is associated with a risk significant planning standard function,10 CFR 50.47(b)(4), in
that a standard scheme of emergency classification and actions levels is in use.
Because PG&Es failure to establish compensatory measures to ensure the prompt
implementation of the Diablo Canyon Emergency Plan is of very low safety significance
and has been entered into the corrective action system as AR XXXXXXX, this violation
is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement
Policy: NCV 50-275; 323/2004-005-10, Failure to Establish Compensatory Measures to
Ensure the Prompt Implementation of the Diablo Canyon Emergency Plan.
.6
(Closed) AV 05000275/2004006-01; 05000323/2004006-01: Noncompliance of
Solenoid Operated valves with 10 CFR 50.49 requirements.
Introduction. A self-revealing violation of 10 CFR 50.49(f) was identified for the failure to
maintain approximately 70 safety related solenoid operated valves in an environmentally
qualified condition. On February 9, 2002, an age related ASCO solenoid operated valve
coil failed and caused a loss of Steam Generator feed event and a Unit 2 manual plant
trip. Further, PG&E did not promptly evaluate the extent of condition of the ASCO
failure, which delayed the identification of elastomer qualification issues for
approximately 1 year. In a related finding, the team identified that PG&E had missed
earlier opportunities to identify ASCO elastomer qualification issues, in that they failed to
thoroughly evaluate several pertinent NRC information notices and previous valve
failures. The failure to: 1) properly establish equipment qualification limits; 2)
thoroughly evaluate plant events and failures; and 3) properly evaluate industry
operating experience constituted performance concerns. These issues have
crosscutting aspects in the area of problem identification and resolution.
Description. On February 9, 2002, operators manually tripped Unit 2 due to lowering
Steam Generator 2-4 water level. An ASCO solenoid operated valve had failed, causing
Main Feedwater Regulating Valve FW-2-FCV-540 to close. PG&E determined the
failure was due to thermal aging degradation of the coil wire insulation. PG&E found
that inappropriate criteria were used in determining the acceptable qualified life of the
solenoid coils.
The team identified that PG&E did not promptly perform an extent of condition
evaluation, which delayed the identification that qualification life for ASCO valve
elastomers was also miscalculated. Approximately a year after the plant trip, PG&E
-46-
Enclosure
recognized the error. The elastomer limitations were slightly more restrictive than those
of the coil. These discrepancies resulted in the qualified life of the solenoid operated
valves being corrected from approximately 22 years to 7 years. Overall, approximately
70 valves were affected in both units.
In a related concern, the team identified that PG&E failed to effectively utilize industry
operating experience that discussed the failure of ASCO solenoids due to degraded
elastomers. This information was provided to the industry in NRC Information Notices
88-43, Solenoid Valve Problems; 89-66, Qualification Life of Solenoid Valves; 85-17,
Possible Sticking of ASCO Solenoid Valves; 86-57, Operating Problems with Solenoid
Operated Valves at Nuclear Power Plants; and 84-23, Results of the NRC-Sponsored
Qualification Methodology Research Test on ASCO Solenoid Valves. The team
reviewed PG&Es responses to these notices and determined that in general PG&Es
responses were narrowly focused. For example, PG&E determined that a solenoid
problem would not be seen at their facility because they were not using the same model
number that was being discussed in the notice, even though the issue concerned the
potential for general elastomer material degradation due to elevated temperatures. The
team also noted that PG&E had experienced prior failures of ASCO solenoid operated
valves due to sticking or binding conditions.
This finding involved crosscutting aspects in the area of problem identification and
resolution because the original corrective actions did not identify the full scope of the
cause and extent of condition, delaying corrective actions for approximately 1 year. In
addition, PG&E did not properly address generic industry information concerning ASCO
elastomers.
Analysis. This finding was greater than minor because, if left uncorrected, these
deficiencies would become a more significant safety concern by increasing the failure
rate as the components age. This finding potentially affected the Initiating Events,
Mitigating Systems, and Barrier Integrity Cornerstone objectives.
An NRC Senior Reactor Analysts performed a Phase 3 significance determination. The
following assumptions were utilized:
Based on a historical data review performed by PG&E at the request of the
Senior Reactor Analyst, the following failure rates were determined for solenoid
valves that had exceeded their EQ replacement frequencies:
Demand failures = 2.1E-3 / demand
This applies to a situation where the valve is called upon to change state, but
fails to do so
Failure rate = 3.19E-7/hr.
This applies to a situation where the valve unintendedly changes state because
of a failure of the solenoid valve related to the EQ issue.
-47-
Enclosure
The above failure information applies only to valve failures that occurred in a
manner such that the failure could be attributed to the aging effects related to
EQ. Failures for other causes were not included in the analysis. The period of
the review was 1998 to the present.
The individual effect of a short-term harsh environment on an over-aged solenoid
valve is considered to be negligible because the finding contributed to a long-
term aging mechanism and not a short-term temperature, water, radiation, or
humidity intrusion effect. Therefore, the over-aged valves are considered to
perform equivalently to the in-specification valves during an accident scenario.
The estimated delta-CDF for the finding is 2.2E-8/yr. Therefore, the violation was of
very low risk significance (Green).
Enforcement. Section (a) of 10 CFR 50.49(f) requires, in part, that each item of electric
equipment important to safety to be environmentally qualified. Contrary to the above,
PG&E did not maintain environmental qualification for a total of approximately 70 ASCO
solenoid operated valves in Units 1 and 2. The failure to maintain the environmental
qualification was a violation of 10 CFR 50.49(f). Because the violation was of very low
safety significance, and was entered into PG&Es corrective action program (Action
Request A0613008), this violation is being treated as an NCV, consistent with
Section VI.A of the NRC Enforcement Policy (NCV 05000275; 323/2004005-11).
40A6
Management Meetings
Exit Meeting Summary
The inspectors presented the emergency preparedness exercise inspection results to
Mr. Jim Becker, Station Director, and other management and staff members at the
conclusion of the inspection on December 10, 2004. PG&E acknowledged the findings
presented. The inspector verified no proprietary information was discussed during the
inspection.
The resident inspection results were presented on January 6, 2005, to Mr. David
Oatley, Vice President and General Manager, 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 not reviewed by the
inspectors.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by PG&E
and is a violation of NRC requirements, which meets the criteria of Section VI
of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.
-48-
Enclosure
Technical Specification 5.4.1.a requires procedures to be established, implemented and
maintained covering the activities described in Regulatory Guide 1.33, Revision 2,
Appendix A, February 1978. Appendix A of Regulatory Guide 1.33, requires procedures
for the residual heat removal (RHR) system. Final Safety Analysis Report Section 5.5.6
states that, to maintain the ability to open the RHR suction valves (Valves RHR-2-8701
and -8702) from the control room when the solid state protection system (SSPS) is de-
energized, a jumper is installed to bypass the SSPS interlocks. Contrary to the above,
procedures for the RHR system were not adequately maintained. Specifically, as of
November 1, 2004, the jumper to bypass the interlocks had not been installed, following
and during Unit 2 mid-loop operations. PG&E procedures for operation of the RHR
system, or control of outage activities, did not direct installation of this jumper.
Procedure STP I-38-AB.1 "SSPS Train A&B Removal from Service for
Testing/Maintenance in Modes 5 or 6," Revision 1, required the jumper to be installed to
maintain the ability to open the RHR suction valves only if the SSPS system was de-
energized by removing fuses. The SSPS system was removed from service by opening
the supply breaker. This finding is more than minor because the condition existed while
Unit 2 was in mid-loop operations, and would have impeded recovery from a loss of
RHR, if the RHR suction valves were closed. This finding is of very low safety
significance because the ability to locally open the valves using the handwheel was
maintained. In addition, the RHR system continued to operate properly during midloop
operations and was not challenged. Therefore, this issue screens as Green. This
finding is entered into PG&Es corrective action program as Action Request A0622371.
ATTACHMENT: SUPPLEMENTAL INFORMATION
A-1 Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
PG&E personnel
J. Becker, Vice President - Diablo Canyon Operations and Station Director
C. Belmont, Director, Nuclear Quality, Analysis, and Licensing
S. Chesnut, Director, Engineering Services
J. Fledderman, Acting Director, Maintenance Services
S. Ketelsen, Manager, Regulatory Services
M. Lemke, Manager, Emergency Preparedness
D. Oatley, Vice President and General Manager, Diablo Canyon
P. Roller, Director, Operations Services
J. Tompkins, Director, Site Services
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
50-323/2004-05-01
Mislabel of Neutron Flux Detector Resulted in Neutronic
Decoupling of Detector From the Core
(Section 1R04.1)
50-275; 323/2004-05-02
Failure to Promptly Correct Containment Fan Cooler
Unit Reverse Rotation (Section 1R04.2)
50-323/2004-05-04
Failure to Properly Implement Procedure for Spent Fuel
Pool Skimmer Filter Replacement (Section 1R14.2)
50-275/2004-05-05
Failure to Adequately Correct ECCS Voiding Following
Operation of the Positive Displacement Pump
(Section 1R15)
50-323/2004-05-07
Failure to Lock a High Radiation Area with Dose Rates
Greater than 1 Rem per Hour Area with Dose Rates
Greater than 1 Rem per Hour (Section 2OS1)
50-323/2004-05-08
Failure to Access a High Radiation Area with Dose
Rates Greater than 1 Rem per Hour with the Correct
Radiation Work Permit (Section 2OS1)
50-323/2004-05-09
Failure to Wire and Connect Test Equipment Resulted
in Vital Bus De-Energization (Section 4OA3.1)
50-275; 323/2004-05-10
Failure to Establish Compensatory Measures to Ensure
the Implementation of the Diablo Canyon Emergency
Plan as Required by 10 CFR 50.54(q) and the Risk
Significant Planning Standard Function,10 CFR 50.47(b)(4) (Section 4OA5.5)
A-2 Attachment
50-275; 323/2004-05-11
Inadequate ASCO valve qualification causes plant trip
(Section 4A05)
Open
50-323/2004-05-03
Adequately of Alarm Procedure For Feedwater Heater
Level Control Malfunctions.(Section 1R14.1)
50-323/2004-05-06
Failure to Promptly Correct Diesel Engine Generator
Lube Oil Instrument Line Crack (Section 1R15)
Closed
50-323/2003-001-00
LER
Steam Generator Tube Plugging Due to Stress
Corrosion Cracking (Section 4OA3.2)
50-323/2003-002-00
LER
Unanalyzed Condition In the Unit 2 Component Cooling
Water System (Section 4OA3.3)
50-323/2003-003-00
LER
Technical Specification 3.4.12 Not Met Due to Personnel
Error (Section 4OA3.4)
50-275; 323/2003-002-01
Licensee Made Changes to the Fire Protection Program
That Could Have the Potential to Adversely Affect Their
Ability to Achieve and Maintain Safe Shutdown
(Section 4OA5.4)
50-275; 323/2004-004-02
Evaluation of Earthquake Force Monitors for EAL
Implementation that were identified in Section 1R14.1
and 1R17 and was the subject of EA 04-0169
(Section 4OA5.5)05000275/2004006-01
05000323/2004006-01
APV
Inadequate ASCO valve qualification causes plant trip
(Section 4A05)
LIST OF DOCUMENTS REVIEWED
Section 1R04: Equipment Alignment
Action Requests
A0224682
A0533621
A0589415
A0326457
A0539622
A0595426
A0412679
A0542698
A0602491
A0478486
A0557943
A0610960
A0479124
A0568655
A0613036
A-3 Attachment
A0492190
A0574615
A0619139
A0518387
A0587895
A0619185
Calculations
PET-92-119, RCFC Reverse Speed vs. Torque, Revision 0
PCE-92-0044, PGE - RCFC Reverse Speed vs. Torque, Revision 0
Section 1R08: Inservice Inspection Activities
Procedures
ISI-VT-2-1, Visual Examination During Section XI System Pressure Test, Revision 6,
NDE-N-UT-4, Ultrasonic Examination of Pressure Vessel Welds Other Than Reactor Vessels,
Revision 9
NDE-PDI-UT-2, Ultrasonic Examination of Austenitic Piping, Revision 3A
STP-R-8C, Containment Walkdown for Evidence of Boric Acid Leakage, Revision 8A
Miscellaneous Documents
Steam Generator Tubing Degradation Assessment, Diablo Canyon Unit 2, Refueling
Outage 2R12, Revision 0
Ultrasonic Examinations
WIB-248
WIB-358-1
WIB-358-2
WIB-393
WIB-394
Action Requests
A0574355
A0606347
A0623246
A0574572
A0608944
A0595426
A0574893
A0618807
A0623417
A0576197
A0622851
A0623440
A0577052
A0622911
A0623471
A0584122
A0622916
A0623473
A0606013
A0623160
A-4 Attachment
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
OP J-6B:III, Diesel Generator 1-3 Make Available, Revision 22
Other
Clearance 79266
Risk Assessment RA02-05, Revision 2
Section 1R15: Operability Evaluations
Action Requests
A0584039
A0624988
A0625020
Procedures
OP J-2:VIII, Guidelines for Reliable Transmission Service for DCPP, Revision 5
Section 1R19: Postmaintenance Testing
Action Requests
A0627391
Work Orders
R0243795
Section 1R22: Surveillance Test
Action Requests
A0622185
A0622199
A0623371
1EP1 Exercise Evaluation (71114.01)
Emergency Plan Implementing Procedures (EPIPs)
EP G-1, Emergency Classification and Emergency Plan Activation, Revision 33B
EP G-2, Interim Emergency Response Organization, Revision 30
EP G-3, Emergency Notification of Off-site Agencies, Revision 42
EP RB-8 Instructions for Field Monitoring Teams, Revision 18
EP RB-9, Calculation of Release Rate, Revision 11A
EP RB-10, Protective Action Recommendations, Revision 11
EP RB-11, Emergency Offsite Dose Calculations, Revision 12
EP EF-1, Activation and Operation of the Technical Support Center, Revision 32
EP EF-2, Activation and Operation of the Operational Support Center, Revision 28
EP EF-3, Activation and Operation of the Emergency Operations Facility, Revision 26
A-5 Attachment
EP EF-10, Activation and Operation of the Joint Media Center, Revision 7
Administrative Procedure OM10.ID4, Emergency Response Organization Management,
Revision 5
Section 2OS1: Access Controls to Radiologically Significant Areas
Action Requests
573555, 574447, 575297, 576284, 578891, 579124, 579474, 579616, 579880, 581129,
581131, 581675, 603992, 604397, 604648, 604958, 605030, 605695, 609454, 610681,
615721, 619134, 621210, 621924, 622297, 622516, 622930, and 623133
Audits and Assessments
2003 DCPP Radiation Protection Program Audit
Assessment Number 030410010, 2R11 Radiation Protection Assessment Report - Outage
Coverage
Assessment Number 031780001, Radiological Risk Assessment Process for 2R11
Assessment Number 040630025, 1R12 Radiation Protection Assessment Report - Outage
Coverage
Quality Performance Assessment Report, Fourth Period 2002 and First Period 2003
Quality Performance Assessment Report, Second, Third and Fourth Periods 2003
Quality Performance Assessment Report, First Period 2004
Quality Verification Assessment of 1R12 Performance Windows 1, 2, and 3
Radiation Work Permits (RWP)
RWP04-0004, RWP04-0011, RWP04-1004, and RWP04-2007
Procedures
DCPP Standard Radiation Practices Manual, Revision 4
RCP D-200
Writing Radiation Work Permits, Revision 30
RCP D-211
Use of Remote Monitoring Technology for Radiation Protection, Revision 0
RCP D-215
Radiological Coverage of Underwater Work, Revision 5
RCP D-220
Control of Access to High, Locked High, and Very High Radiation Areas,
Revision 27
RCP D-222
Radiation Protection Lock and Key Control, Revision 3
A-6 Attachment
RCP D-240
Radiological Posting, Revision 16
RCP D-250
Radiological Occurrence Reports, Revision 10A
RCP D-330
Personnel Dosimetry Evaluations, Revision 6
RCP D-420
Sampling and Measurement of Airborne Radioactivity, Revision 18A
RCP D-600
Personnel Decontamination and Evaluation, Revision 21
RCP D-610
Control of Radioactive Materials, Revision 11
RP1.ID7
Control of Radiography, Revision 4
RP1.ID9
Radiation Work Permits, Revision 7
Miscellaneous
Committed Effective Dose Equivalent Calculations and whole body counts for one individual
Selected Radiologically Control Access exit dose transactions during the inspection period
Section 4OA1: Performance Indicator Verification
Action Requests
578891, 579124, 581129, 581131, and 605030
Procedures
AWP O-002, NRC Performance Indicators: RETS/ODCM Radiological Effluent Occurrences,
Revision 2
AWP O-003, NRC Performance Indicators: Occupational exposure Control Effectiveness,
Revision 2
RCP D-250, Radiological Occurrence Reports, Revision 10A
XI1.DC1, Collection and Submittal of NRC Performance Indicators, Revision 4
AWP EP-001, Emergency Preparedness Performance Indicators, Revision 4
OM10.ID1, Maintaining Emergency Preparedness, Revision 4
OM10.DC1, Emergency Preparedness Drills and Exercises, Revision 2A
Emergency Preparedness Training, Program of Instruction, Revision 10
-7-
A-7 Attachment
Audits
2003 Annual Radioactive Effluent Release Report
2003 Annual Radiological Environmental Operating Report
Quality Verification Audit 041820006, 2004 Radiological Environmental Monitoring Program
(REMP) Audit
Drill, Exercise, and Actual Event Reports
October 23, 2002 Bravo Team Exercise
October 18, 2003 Notice of Unusual Event
October 29, 2003 Bravo Team Exercise
December 22, 2003 Notice of Unusual Event
September 22, 2004 Alpha Team Exercise
September 28, 2004 Notice of Unusual Event
Section 4OA2: Problem Identification and Resolution
Audits
Second Period 2004 (June 1 to October 24) Quality Performance Assessment Report (QPAR)
2004 DCPP Emergency Preparedness Program 50.54(t) Review
Operations Activities Audit 040690003
4OA2 Problem Identification and Resolution
Emergency Planning Guideline EP-G01, Problem Identification, May 17, 2002
Self-Assessment of Emergency Action and Classification Levels, EPSA 2004-01
Self-Assessment, Alpha Team Evaluated Exercise December 8, 2004
Self-Assessment, Bravo Team Full-Scale Drill, October 29, 2003
A-8 Attachment
LIST OF ACRONYMS
agency document and management system
as low as reasonably achievable
action request
American Society of Mechanical Engineers
BMV
bare metal visual
Centrifugal Charging Pump
component cooling water
CFCU
containment fan cooler unit
CFR
Code of Federal Regulations
Electric Power Research Institute
Final Safety Analysis Report
LER
Licensee Event Report
noncited violation
NEI
Nuclear Energy Institute
Publicly Available Records System
PDP
positive displacement pump
Pacific Gas and Electric Company
pressurized water reactor
radiation work permit
Significance Determination Process
SFM
shift foreman
safety injection pump
SSPS
solid state protection system
TI
Temporary Instruction