ML040300257
| ML040300257 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 01/30/2004 |
| From: | William Jones NRC/RGN-IV/DRP/RPB-E |
| To: | Rueger G Pacific Gas & Electric Co |
| References | |
| IR-03-008 | |
| Download: ML040300257 (51) | |
See also: IR 05000275/2003008
Text
January 30, 2004
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, CA 93424
SUBJECT: DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION
REPORT 05000275/2003008 AND 05000323/2003008
Dear Mr. Rueger:
On December 31, 2003, 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 8, 2004, with Mr. David H.
Oatley and members of your staff.
This inspection examined activities conducted under your licenses as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your
licenses. The inspectors reviewed selected procedures and records, observed activities, and
interviewed personnel.
There were five findings of very low safety significance (Green) identified in this report. Four of
the findings were NRC-identified and one was self-revealing. Four of these findings involved
violations of NRC requirements. However, because of their very low safety risk significance
and because they are entered into your corrective action program, the NRC is treating these
four findings as noncited violations (NCVs) consistent with Section VI.A of the NRC
Enforcement Policy. If you contest any NCV in this report, you should provide a response
within 30 days of the date of this inspection report, with the basis for your denial, to the U.S.
Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC
20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission,
Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office
of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the
NRC Resident Inspector at the Diablo Canyon Power Plant.
During the period of December 22, 2003, through January 9, 2004, the NRC has been
conducting event followup inspections at the Diablo Canyon Nuclear Plant in direct response to
the December 22, 2003, San Simeon earthquake. These event followup inspections continue.
The results of the inspections conducted through December 31, 2003, (referred to as Phase 1
of the event followup inspections) are documented in the enclosed inspection report (see
Section 1R14). The results of the inspection conducted January 1-9, 2004, (referred to as
Phase 2 of the event followup inspections) and additional onsite inspections planned through
Pacific Gas and Electric Company -2-
Unit 1 refueling outage, scheduled to begin in March 2004, (referred to as Phase 3 of the event
followup inspections) will be documented in NRC Inspection Report 05000275;323/2004002, to
be issued approximately at the end of April 2004.
On January 16, 2004, we provided you with some preliminary results of the NRCs event
followup for the December 22, 2003, San Simeon earthquake. (ADAMS
Accession ML040160653). That letter provided the preliminary results of the inspection
activities (Phases 1 and 2) conducted through January 9, 2004, and provided the scope for
Phase 3 of the NRCs actions that are ongoing. The Phase 3 activities will involve additional
planned inspections, including the visual inspections in Unit 1 containment during the March
2004 refueling outage and further review of your Special Report, submitted to the NRC on
January 5, 2004, and any supplemental report.
We plan to conduct a technical meeting with you on February 4, 2004, regarding your January
5, 2004, Special Report in San Luis Obispo, California. This meeting will be open to public
observation and will provide attending members of the public a period for comments and
questions prior to the conclusion of the meeting.
Pacific Gas and Electric Company operated under voluntary bankruptcy proceedings during this
inspection period. The NRC has monitored plant operations, maintenance, and planning to
better understand the impact of the financial situation and how it relates to your responsibility to
safely operate the Diablo Canyon reactors. NRC inspections, to date, have confirmed that you
are operating these reactors safely and that public health and safety is assured.
In accordance with 10 CFR 2.790 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 System (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 05000275/2003008
and 05000323/2003008
w/attachment: Supplemental Information
Pacific Gas and Electric Company -3-
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, Power
Generation & 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
2650 Maple Avenue
Morro Bay, CA 93442
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
Pacific Gas and Electric Company -4-
Ed Bailey, Radiation Control Program Director
Radiologic Health Branch
State Department of Health Services
P.O. Box 942732 (MS 178)
Sacramento, CA 94234-7320
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
James D. Boyd, Commissioner
California Energy Commission
1516 Ninth Street (MS 34)
Sacramento, CA 95814
Chief, Technological Services Branch
FEMA Region IX
1111 Broadway, Suite 1200
Oakland, CA 94607-4052
Pacific Gas and Electric Company -5-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (DLP)
Branch Chief, DRP/E (WBJ)
Senior Project Engineer, DRP/E (VGG)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (NBH)
Anne Boland, OEDO RIV Coordinator (ATB)
DC Site Secretary (AWC1)
Dale Thatcher (DFT)
W. A. Maier, RSLO (WAM)
ADAMS: Yes * No Initials: ___WBJ___
Publicly Available * Non-Publicly Available * Sensitive Non-Sensitive
R:\_DC\2003\DC2003-08RP-DLP.wpd
RIV:RI:DRP/E SRI:DRP/E TL:DRS/EMB C:DRS/PSB C:DRP/E
TWJackson DLProulx RLNease TWPruett WBJones
E E /RA/ /RA/ /RA/
1/28/04 1/28/04 1/27/04 1/26/04 1/28/04
D:DRP DRA RA C:DRP/E (for Signature)
ATHowell For TPGwynn BSMallett For WBJones
MASatorius /RA/ TPGwynn /RA/
1/28 /04 1 /30/04 1/30/04 1/30/04
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets: 50-275, 50-323
Report: 05000275/2003008
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: September 28 through December 31, 2003
Inspectors: D. L. Proulx, Senior Resident Inspector
T. W. Jackson, Resident Inspector
S. M. Wong, Risk Analyst
R. E. Lantz, Senior Emergency Preparedness Inspector
M. P. Shannon, Senior Health Physicist
B. Tharakan, Health Physicist
Approved By: W. B. Jones, Chief, Project Branch E
Division of Reactor Projects
Enclosure
CONTENTS
PAGE
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REACTOR SAFETY
1R04 Equipment Alignments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R06 Flood Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R13 Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 11
1R14 Operator Performance during Nonroutine Evolutions and Events, Including
Followup Response to Earthquakes Impacting Diablo Canyon Power Plant . . 12
1R16 Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
1EP2 Alert Notification System Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
1EP3 Emergency Response Organization Augmentation Testing . . . . . . . . . . . . . . . 22
1EP4 Emergency Action Level and Emergency Plan Changes . . . . . . . . . . . . . . . . . 22
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies . . . . . 23
1EP6 Emergency Preparedness Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
RADIATION SAFETY
2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
OTHER ACTIVITIES
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
40A4 Crosscutting Aspects of Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
40A5 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
40A6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
ATTACHMENT: SUPPLEMENTAL INFORMATION
Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
Items Opened, Closed, and Discussed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-5
Enclosure
SUMMARY OF FINDINGS
IR 05000275/2003-008, 05000323/2003-008; 09/28/03 - 12/31/03; Diablo Canyon Power Plant
Units 1 and 2; Fire Protection, Maintenance Effectiveness, Postmaintenance Testing, ALARA
Planning and Controls, Problem Identification and Resolution.
This report covered a 14-week period of inspection by resident inspectors and announced
inspections in emergency preparedness and radiation protection and followup inspections to the
October 18 and December 22, 2003, earthquakes. Specifically, Section 1R14.1 documents the
followup inspections performed in response to earthquakes impacting the Diablo Canyon Power
Plant. The NRC identified four Green noncited violations and one Green finding. 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: Mitigating Systems
- Green. The inspectors identified a violation of Technical Specification 5.4.1.d
which requires written procedures be established, implemented, and maintained
covering the Fire Protection Program implementation. Specifically, PG&E failed
to adequately establish and implement procedural changes that provided for
senior control operators, licensed control operators, and nonlicensed, Level 8
nuclear operators to serve in the operator responder position. The inspectors
noted that the applicable attachment to the procedure for conduct of the
operations response position was not established until after training had been
provided on implementing the procedure. Operations responders supporting the
fire brigades exhibited a knowledge weakness in activities such as
communications with the control room, manual actuation of fire suppression
equipment, and providing information to the fire brigade regarding safe shutdown
equipment.
The finding impacted the procedure quality objective under the mitigating
systems cornerstone and was more than minor since there was an adverse
impact to a fire protection defense-in-depth element. Using the Significance
Determination Process (SDP) Phase I Screening Worksheet and the SDP
Phase II Notebook in Appendix F of Inspection Manual Chapter (IMC) 0609, the
inspectors determined that the finding was of very low safety significance.
Specifically, the significance of the finding was evaluated by considering fire
scenarios in the vital 4 kV Bus F switchgear room and auxiliary saltwater
Pump 1-1 vault. These two areas have the highest dependence on fire brigade
response since they have the highest fire ignition frequency for areas that do not
have automatic fire suppression. The inspectors evaluated the risk-significance
using half of the nominal credit for manual fire suppression as a result of the
Enclosure
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finding. Using Tables 5.4, 5.5, and 5.6 of IMC 0609, both fire scenarios
screened as very low safety significance. Since the two fire scenarios were
considered worst-case for the finding, the inspectors determined that the finding
was of very low safety significance (Section 1R05.2).
- Green. The inspectors identified a noncited violation for the failure to adequately
monitor the performance of the Unit 1 auxiliary feedwater system in accordance
with 10 CFR 50.65(a)(2). Specifically, the unavailability time performance criteria
for the auxiliary feedwater system had been exceeded during its monitoring
period, but the system was not monitored per 10 CFR 50.65(a)(1).
The finding impacted the mitigating systems cornerstone objective to ensure the
availability and reliability of the auxiliary feedwater system to respond to initiating
events. The finding is greater than minor using Example 1.f of Inspection
Manual Chapter 0612, Appendix E. Similar to the example, the inspectors
identified that Pacific Gas and Electric did not consider unavailability time for the
Unit 1 auxiliary feedwater system, although the unavailability time was due to
prior poor maintenance practices on Valve FW-1-FCV-437. If the unavailability
time was considered, the 10 CFR 50.65(a)(2) evaluation would be invalid. Using
the Significance Determination Process Phase I worksheet in Inspection Manual
Chapter 0609, Appendix A, the finding is of very low safety significance, since
there was no loss of an actual safety function, no loss of a safety-related train for
greater than the Technical Specification allowed outage time, and the finding is
not potentially risk significant due to a seismic, fire, flooding, or severe weather
initiating event (Section 1R12).
- Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion III, when Pacific Gas and Electric personnel failed to
adequately evaluate the capability of core exit thermocouples to measure the
radial temperature gradient for Quadrant 1 of the Unit 1 reactor core.
Specifically, maintenance personnel inadvertently swapped core exit
thermocouples at a connection, leaving only three operable thermocouples per
Trains A and B for Quadrant 1. When questioned by the inspectors, engineering
personnel could not provide an adequate technical bases for how measurement
of radial temperature gradient could be accomplished.
The finding impacts the mitigating system cornerstone through degraded overall
availability of the components within a system used to assess and respond to
initiating events to prevent undesirable consequences. The finding was greater
than minor when compared to Example 3.a of Inspection Manual Chapter 0612,
Appendix E. Similar to Example 3.a, Pacific Gas and Electric performed
additional work to verify the ability of the core exit thermocouples to measure
radial temperature gradient within Quadrant 1 of the Unit 1 reactor core. Using
the Significance Determination Process Phase 1 screening worksheet from
Inspection Manual Chapter 0609, Appendix A, the finding was determined to be
of very low safety significance, since the deficiency was confirmed not to result in
loss of function per Generic Letter 91-18, Revision 1 (Section 1R19).
Enclosure
-3-
- Green. A self-revealing violation of 10 CFR Part 50, Appendix B, Criterion XVI,
was identified for failure to promptly identify and correct a condition adverse to
quality. Specifically, in December 2000, Pacific Gas and Electric failed to identify
and correct the population of Rockwell-Edwards valves in safety-related and risk-
significant systems that were susceptible to failure of the packing gland follower
flange from intergranular stress corrosion cracking. Pacific Gas and Electric
received an industry notification in December 2000 that Rockwell-Edwards
valves were vulnerable for this type of failure, but initiated corrective actions on a
very limited population of valves (those involving a trip risk). As a result, on
December 3, 2003, the packing gland follower flange for safety injection
Valve SI-1-8890A (pressure equalization valve) on the hot leg injection line
failed, due to intergranular stress corrosion cracking, resulting in excessive
packing gland leakage.
The finding impacted the mitigating systems cornerstone through degraded
equipment performance for a system train that responds to initiating events to
prevent undesirable consequences. The finding is greater than minor because
the finding would become a more significant safety concern if the valve condition
was left uncorrected. The amount of leakage from the valve would be
significantly greater than a 30 drop per minute leak rate, if the safety injection
pumps were fully running in the hot leg injection mode. The Valve SI-1-8890A
leak rate is bounded by a residual heat removal pump seal failure. Pacific Gas
and Electric concluded the safety injection system was operable but degraded
because both safety injection system trains would be available to provide
adequate flow if a demand occurs. Using the Significance Determination
Process Phase 1 worksheet in Inspection Manual Chapter 0609, Appendix A, the
finding was determined to be of very low safety significance, since there is no
loss of an actual safety function, no loss of a safety-related train for greater than
the Technical Specification allowed outage time, and the finding is not potentially
risk significant due to a seismic, fire flooding, or severe weather initiating event
(Section 4OS2.2)
Cornerstone: Occupational Radiation Safety
- Green. A finding was identified because Pacific Gas and Electric failed to
maintain collective doses as low as is reasonably achievable. Specifically, work
activities associated with Radiation Work Permit 03-2055, "Reactor Coolant
Pump (RCP) 2-2, 10 year inspection," exceeded 5 person-rem and the dose
estimation by more than 50 percent due to a miscommunication among work
groups.
The failure to maintain collective doses as low as is reasonably achievable is a
performance deficiency. This finding was more than minor because it is
associated with the Occupational Radiation Safety Cornerstone attribute
(program and process) and affected the associated cornerstone objective (to
ensure adequate protection of workers health and safety from exposure to
radiation). This occurrence involved inadequate planning which resulted in
Enclosure
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unplanned, unintended occupational collective dose for the work activity. When
processed through the Occupational Radiation Safety Significance Determination
Process, this finding was found to have no more than very low safety
significance because the finding was an as low as is reasonably achievable
planning issue and Pacific Gas and Electric Companys 3-year rolling average
collective dose was less than 135 person-rem (Section 2OS2).
B. Licensee-Identified Violations
None.
Enclosure
REPORT DETAILS
Summary of Plant Status
Diablo Canyon Unit 1 began this inspection period at 100 percent power. On December 10,
2003, operators reduced power on Unit 1 to approximately 24 percent power in anticipation of
high swells and kelp impacting the traveling screens. On December 11 operators increased
reactor power to 53 percent to support a leak search in the main condenser. Following the
search for the leak, operators increased reactor power and Unit 1 reached 100 percent power
on December 12. 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 December 10,
2003, operators reduced power to approximately 24 percent power in anticipation of high swells
and kelp impacting the traveling screens. Following the high swells, operators increased
reactor power on December 11 and achieved 100 percent power on the same day. Unit 2
remained at 100 percent power for the duration of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignments (71111.04)
The inspectors performed four partial system walkdowns and one complete system
walkdown during this inspection period.
Partial System Walkdowns
.1 Unit 2 Startup Transformer 2-1
a. Inspection Scope
On October 21, 2003, while Diesel Engine Generator (DEG) 2-2 was in a maintenance
outage window, the inspectors performed a partial system walkdown of Startup
Transformer 2-1. The inspectors observed valve alignment, material condition, labeling,
lubrication, and structural support. The inspectors used Procedure OP J-2:II, Startup
Bank Return to Service, Revision 18, for reference during the inspection.
b. Findings
No findings of significance were identified.
Enclosure
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.2 Unit 1 DEG 1-1
a. Inspection Scope
On October 27, 2003, while DEG 1-2 was in a maintenance outage window, the
inspectors performed a partial system walkdown of DEG 1-1. The inspectors reviewed
valve alignment, leakage, electrical power availability, labeling, lubrication, ventilation,
seismic supports, and absence of physical interference. The inspectors used the
following documents as reference during the inspection:
- Procedure OP J-6B:I, Diesel Generator 1-1 Make Available, Revision 26
- Drawing 106721, Diesel Engine - Generator
- Sheet 3, Revision 43
- Sheet 4, Revision 37
- Sheet 5, Revision 27
- Sheet 6, Revision 40
b. Findings
No findings of significance were identified.
.3 Unit 2 Residual Heat Removal (RHR) Pump 2-2
a. Inspection Scope
During a plant status walkdown on November 5, 2003, the inspectors noticed a slight
accumulation of bearing oil at the base of RHR Pump 2-2. The inspectors reported the
potential oil leak to operators, who in turn initiated Action Request (AR) A0594205. The
inspectors followed up with Pacific Gas and Electric Companys (PG&Es) actions
regarding the potential oil leak by performing a partial system walkdown of RHR
Pump 2-2 on November 6. The inspectors used the following documents during the
partial system walkdown:
- A0533113, RHR Pump 2-2 Oil Leak
- A0594205, RHR PP 2-2 Motor Oil at Base of Pump
b. Findings
No findings of significance were identified.
.4 Unit 2 Radiation Monitors
a. Inspection Scope
On November 5, 2003, while Radiation Monitor Power Supply Transformer TPRM21
was in a maintenance outage window, the inspectors performed a partial system
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walkdown of Unit 2 radiation monitors. The inspectors reviewed valve alignment,
electrical power availability, labeling, operational status, ventilation, seismic supports,
and absence of physical interference. The inspectors used Clearance 76058 and
Technical Specification Sheet T0047944.
b. Findings
No findings of significance were identified.
Complete System Walkdown
Unit 1 Control Room Ventilation System (CRVS)
a. Inspection Scope
The inspectors performed a complete system walkdown of the Unit 1 control room
ventilation system on November 12, 2003. During the walkdown, the inspectors
observed proper system alignment and material condition. The inspectors also
reviewed past and present deficiencies. The inspectors used Drawing 106723,
Ventilation and Air Conditioning, Sheet 16, Revision 82. The inspectors also reviewed
the ARs listed in Attachment 1.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
The inspectors performed four fire protection walkdowns and one fire drill review during
this inspection period.
.1 Routine Observations
a. Inspection Scope
The inspectors performed four fire protection walkdowns to assess the material
condition of plant fire detection and suppression, fire seal operability, and proper control
of transient combustibles. The inspectors used Section 9.5 of the Final Safety Analysis
Report (FSAR) Update as guidance. The inspectors considered whether the
suppression equipment and fire doors complied with regulatory requirements and
conditions specified in Procedures STP M-69A, Monthly Fire Extinguisher Inspection,
Revision 33, STP M-69B, Monthly CO2 Hose Reel and Deluge Valve Inspection,
Revision 14, STP M-70C, Inspection/Maintenance of Doors, Revision 8, and OM8.ID4,
Control of Flammable and Combustible Materials, Revision 10. Specific risk-significant
areas inspected included:
- Units 1 and 2, 4kV switchgear rooms in the turbine building
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- Units 1 and 2, switchgear rooms of the auxiliary building
b. Findings
No findings of significance were identified.
.2 Fire Drill
a. Inspection Scope
The inspectors verified the capability of the fire brigade to effectively prevent and fight
fires at the Diablo Canyon Power Plant. Specifically, the inspectors reviewed the
qualification and training of the operations responder position. The purpose of the
operations responder is to provide a communications link between the control room and
the incident commander (fire brigade leader), provide fire and fire protection system
status information, and support protection of safe shutdown equipment. The inspectors
interviewed PG&E operators and fire protection personnel, and reviewed fire protection
documents as part of the inspection effort.
b. Findings
Introduction. The inspectors identified a violation of Technical Specification 5.4.1.d,
which requires written procedures be established, implemented, and maintained
covering the Fire Protection Program implementation. Specifically, PG&E failed to
adequately establish and implement a procedure that provided for senior control
operators, licensed control operators and nonlicensed, Level 8 nuclear operators to
serve in the operator responder position. The inspectors noted that the applicable
attachment to the procedure for conduct of the operations response position was not
established until after training had been provided on implementing the procedure.
Operations responders supporting the fire brigades exhibited a knowledge weakness in
activities such as communications with the control room, manual actuation of fire
suppression equipment, and providing information to the fire brigade regarding safe
shutdown equipment. The failure to adequately establish the procedure and its
attachment and implement the procedural changes through effective training resulted in
an adverse change in the fire protection program, during the period the violation existed.
Description. Prior to 1998, the fire brigade leader was a senior control operator and the
fire brigade members were licensed and nonlicensed operators. The senior control
operator possessed knowledge of fire protection systems, safe shutdown equipment,
and other plant equipment, and also acted as a liaison to the control room. Following
the change to a professional fire brigade in 1998, senior control operators were
assigned to be the operations responder to a fire event. In this position, they primarily
acted as a liaison between the control room and the fire brigade and provided limited
recommendations for protecting safe shutdown equipment.
On August 29, 2003, PG&E instituted an additional change to the operations responder
position. In addition to using the senior control operators, licensed control operators and
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nonlicensed, Level 8 nuclear operators could be used as operations responders. A
2-hour training session was provided to nuclear operators on the duties of an operations
responder, prior to August 29, 2003. The training session was outlined in Lesson
Number R032C12, Operations Responder Responsibilities. Procedure CP M-6, Fire,
Revision 2, included a checklist for the operations responder duties in Attachment 4.2,
Operations Responder Checklist. However, the procedure and checklist were not
issued until September 12, 2 weeks after licensed control operators and nuclear
operators could serve as operations responders.
The inspectors interviewed various control operators and nuclear operators and
identified the following deficiencies and issues concerning the operations responder
position:
- Senior control operators and licensed control operators had not received formal
training on the operations responder position.
- A majority of the operators served on the fire brigade before the professional fire
brigade took over, and they expressed a higher degree of confidence in
performing the duties of the operations responder, as compared to those who did
not have prior fire brigade experience.
- More than one of the operators did not know the phone number for accessing
the fire conference bridge, and others had learned about the protocol for the fire
conference bridge the day the interview was performed.
- The operators expressed a desire for more thorough training on the operations
responder position.
- The operators were not aware that Attachment 4.2 of Procedure CP M-6, titled
Operations Responder Checklist, existed.
- The operations responder position does not have a qualification card, nor is it
part of requalification training for operators.
- Action Request A0579928 stated that, as of August 29, 2003, all Level 8 nuclear
operators had received the operations responder training, but the inspectors
interviewed one nuclear operator that had not received the training.
- The control operators and nuclear operators had not participated in drills with the
fire brigades and identified a lack of interaction with the brigades.
In addition to interviews, the inspectors compared Attachment 4.2 of Procedure CP M-6
to Lesson R032C12, Operations Responder Responsibilities. The inspectors noted
the following items were missing from the lesson plan when compared to
Attachment 4.2. The lesson plan did not discuss:
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- The need for the operations responder to be on the fire conference call by dialing
onto the associated bridge;
- The need to pick up the radio, pre-plans, and checklist from the fire equipment
storage locker before reporting to the incident commander;
- The combination to the fire equipment storage locker although all operators that
were interviewed knew the combination;
- The need for the operations responders to identify and communicate which fire
doors are propped open; and
- Manual actions when the automatic fire suppression systems did not operate.
Section 9.5 of the FSAR Update outlines PG&Es compliance with NRC Branch
Technical Position APCSB 9.5-1. Table B-1 of Appendix 9.5B, Regulatory Compliance
Summary, states, in part, the following aspects of Branch Technical
Position APCSB 9.5-1 for which PG&E is committed to comply with:
- Personnel
. . . the FSAR should discuss the training and the updating provisions such as
fire drills provided for maintaining the competence of the station fire fighting and
operating crew . . .
C Fire Brigade Organization, Training, and Equipment
Basic training is a necessary element in effective fire fighting operation. In
order for a fire brigade to operate effectively, it must operate as a team. All
members must know what their individual duties are.
The inspectors determined that PG&E failed to comply with the above items since all fire
brigade members did not know what their individual duties are. The inspectors
observed that PG&E does not consider the operations responder as part of the fire
brigade; therefore, they provided little or no training to the operations responders. Prior
to the implementation of the professional fire brigade in 1998, the operations responder
duties were performed by the fire team leader who was a senior control operator. When
PG&E implemented the professional fire brigade, the operations knowledge was
separated out from the fire brigade and given to the operations responder. Therefore,
without the presence of a competent operations responder, the fire brigades capability
would be adversely impacted following the 1998 fire brigade change. Since senior
control operators had performed the function of the fire brigade leader prior to the
professional fire brigade implementation, the senior control operators indicated they
were comfortable filling the operations responder position. However, operators who had
no prior experience on the fire brigade indicated they were not comfortable with
performing the operations responder duties.
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Analysis. The performance deficiency associated with this finding is a failure to adequately
establish and maintain Procedure CP M-6. The finding impacted the procedure quality
objective under the mitigating systems cornerstone and was more than minor since there was
an adverse impact to a fire protection defense-in-depth element. Using the Significance
Determination Process (SDP) Phase I Screening Worksheet and the SDP Phase II Notebook in
Appendix F of Inspection Manual Chapter (IMC) 0609, the inspectors determined that the
finding was of very low safety significance. Specifically, the significance of the finding was
evaluated by considering fire scenarios in the vital 4 kV Bus F switchgear room and auxiliary
saltwater Pump 1-1 vault. These two areas have the highest dependence on fire brigade
response since they have the highest fire ignition frequency for areas that do not have
automatic fire suppression. The inspectors evaluated the risk-significance using half of the
nominal credit for manual fire suppression as a result of the finding. Using Tables 5.4, 5.5, and
5.6 of IMC 0609, both fire scenarios screened as very low safety significance. Since the two
fire scenarios were considered worst-case for the finding, the inspectors determined that the
finding was of very low safety significance.
Enforcement. The inspectors identified a violation of Technical Specification 5.4.1.d, which
requires written procedures be established, implemented, and maintained covering the Fire
Protection Program implementation. Specifically, PG&E failed to adequately establish and
implement Procedure CP M-6 for senior control operators, licensed control operators, and non-
licensed operators to serve in the operations responder position. The inspectors noted that
Attachment 4.2 of the procedure was not established until after operators could be assigned the
operations responder position. Because the failure to establish and implement
Procedure CP M-6 was determined to be of very low safety significance and has been entered
into the corrective action program as AR A0597355, this violation is being treated as a non-
cited violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 50-275;
323/03-08-01, Failure to Establish and Implement Fire Program Procedural Changes for
Operations Responders in Support of the Fire Brigade.
1R06 Flood Protection (71111.06)
The inspectors performed one external and one internal flood protection inspection
during this inspection period.
.1 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. Specifically,
the inspectors walked down the exterior areas of the intake structure, auxiliary building,
and turbine building for flood water entry paths. The inspectors used Chapter 3 of the
FSAR Update in support of this inspection.
b. Findings
No findings of significance were identified.
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.2 Internal 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 internal flood risks. Specifically,
the inspectors reviewed corrective action documents and walked down cable pull-boxes.
The inspectors verified operable sump pumps and drains, settings for level alarms, and
intact condition of cable splices subject to submergence. The inspectors used
Probabilistic Risk Assessment Calculation F.4, PRA Internal Floods Analysis,
Revision 4, in support of this inspection.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
a. Inspection Scope
The inspectors witnessed one operator requalification training session during routine
training in the simulator. 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. The inspectors witnessed
simulator training involving shutting down and return to power of an operating unit using
the new digital electrohydraulic control system, including startup and connecting the unit
to the electrical grid. In addition, operators performed a surveillance of the reactor
protection system with respect to the turbine control and stop valves. The inspectors
used Procedures L-3, "Secondary Plant Startup," Revision 28; L-4, "Normal Operation at
Power," Revision 44; OP C-3:II, "Main Unit Turbine-Startup," Revision 33; and
OP C-3:III, "Main Unit Turbine-At Power Operations," Revision 12A, to support the
inspection activities.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors performed three inspections 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
required. Procedure MA1.ID17, Maintenance Rule Monitoring Program, Revision 11,
was used as guidance. The inspectors reviewed the following ARs:
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- A0576813, Maintenance Rule Performance Criteria, Goal Setting Review for
Units 1 and 2 Containment Isolation Valves
- A0574369, Maintenance Rule Performance Criteria, Goal Setting Review for
Unit 1 Auxiliary Feedwater System
- A0584097, Maintenance Rule Performance Criteria, Goal Setting Review for
Units 1 and 2 Containment Fan Cooler Unit Drain Collection System
b. Findings
Introduction. A Green noncited violation was identified by the inspectors for the failure
to adequately monitor the performance of the Unit 1 auxiliary feedwater (AFW) system
in accordance with 10 CFR 50.65(a)(2).
Description. On October 31, 2003, the inspectors reviewed a 10 CFR 50.65(a)(1)
evaluation in AR A0574369 for the Unit 1 AFW system. The inspectors noted a series
of AFW system water contaminations that were first noted in June 2001. Contaminates
included chlorides and other minerals and elements commonly found in natural water
supplies near the plant. The cause of the AFW system water contaminations was due
to incorrect travel stop settings for Valve FW-1-FCV-437. Valve FW-1-FCV-437 is a
butterfly valve that utilizes a Limitorque HBC gear drive and a handwheel to manually
actuate the valve. The safety function of the valve is to open and allow water from the
raw water reservoir to be used as a backup to the condensate storage tank and the
firewater storage tank. Since the travel stops were not at the proper setting, they
prevented the valve from fully closing, thus allowing water from the raw water reservoir
to enter the AFW system and result in contamination. PG&E staff discovered that the
travel stops were set during preventive maintenance, but moved when the valve was
actuated. The travel stops moved because the cover of the travel stop box on the HBC
drive did not secure the travel stop nuts. PG&E is initiating corrective actions to prevent
the travel stops from moving. Other similar valves in Units 1 and 2 have been evaluated
for travel stop movement. No other valves were found to exhibit the same condition.
Due to the water contamination, operators cleared portions of the Unit 1 AFW system in
order to flush the system. The Unit 1 AFW system incurred additional hours of
unavailability time for the flushing operation. Per AR A0574369, the performance
criteria for the Unit 1 AFW system to remain monitored under 10 CFR 50.65(a)(2) has
an unavailability time less than or equal to 67.17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />. The total unavailability time for
the Unit 1 AFW system was 69.18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. Despite exceeding the unavailability
performance criteria, PG&E continued to monitor the Unit 1 AFW system under
10 CFR 50.65(a)(2) for two reasons. First, they believed the root causes and corrective
actions under Nonconformance Reports (NCR) N0002129 and N0002148 were
sufficient to address the issue and to prevent a similar event from recurring. Second,
the cause of the contamination events was due to improper maintenance practices and
not equipment failures. Therefore, PG&E staff felt that the corrective actions for
contamination events were related to human performance and that the issue was
outside the intentions of 10 CFR 50.65(a)(1).
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The inspectors determined that PG&E did not meet the requirements of
10 CFR 50.65(a)(2) when the Unit 1 AFW system exceeded the unavailability time goals
and was not placed in 10 CFR 50.65(a)(1). The inspectors identified that the corrective
actions under NCRs N0002129 and N0002148 did not fully address the issues with the
Unit 1 AFW system water contamination. PG&E initiated a third NCR, N0002167, to
address the movement of Valve FW-1-FCV-437 travel stops due to the clearance
between the travel stop box cover and the travel stop nuts. NCR N0002167 also
contained actions to address the failure of the two previous NCRs to identify and correct
the cause of the Unit 1 AFW system water contamination. NCR N0002167 was initiated
after AR A0574369 documented that corrective actions under NCRs N0002129
and N0002148 were sufficient to address the cause of the water contamination.
The inspectors determined that PG&Es conclusion regarding human performance and
10 CFR 50.65 was incorrect. Specifically, PG&E did not consider human performance
errors during maintenance activities to be within the scope of 10 CFR 50.65, even if
human performance errors resulted in a maintenance preventable functional failure or
unavailability time. 10 CFR 50.65(a)(2) states, in part, that monitoring under
10 CFR 50.65(a)(1) is not required if it has been demonstrated that the performance or
condition of a structure, system, or component is being effectively controlled through the
performance of appropriate preventive maintenance. The inspectors identified the
human performance errors, regarding preventive maintenance, on Valve FW-1-FCV-437
to be inappropriate, resulting in the Unit 1 AFW system incurring additional unavailability
time for flushing.
Analysis. The inspectors determined that PG&Es failure to adequately monitor the
performance of the Unit 1 AFW system in accordance with 10 CFR 50.65(a)(2) was a
performance deficiency. The finding impacted the mitigating systems cornerstone
objective to ensure the availability and reliability of the AFW system to respond to
initiating events and is greater than minor, using Example 1.f of Inspection Manual
Chapter (IMC) 0612, Appendix E. Similar to the example, the inspectors discovered that
PG&E staff did not consider unavailability time for the Unit 1 AFW system, although the
unavailability time was due to prior poor maintenance practices on
Valve FW-1-FCV-437. With the unavailability time considered, PG&Es
10 CFR 50.65(a)(2) evaluation was invalid. Using the SDP Phase I worksheet in
IMC 0609, Appendix A, the finding is of very low safety significance, since there was no
loss of an actual safety function, no loss of a safety-related train for greater than the
Technical Specification allowed outage time, and the finding is not potentially risk
significant due to a seismic, fire, flooding, or severe weather initiating event.
Enforcement. 10 CFR 50.65(a)(2) states, in part, that monitoring as specified in
10 CFR 50.65(a)(1) is not required where it has been demonstrated that the
performance or condition of a structure, system, or component is being effectively
controlled through the performance of appropriate preventive maintenance, such that
the structure, system, or component remains capable of performing its intended
function. However, PG&E did not consider all the unavailability time for the Unit 1 AFW
system when reviewing the systems status in 10 CFR 50.65(a)(2). The performance
criteria for the Unit 1 AFW system to remain monitored under 10 CFR 50.65(a)(2) was
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exceeded, in part, because of the human performance errors such that PG&E did not
demonstrate that the performance of the system was being effectively controlled
through the performance of appropriate preventive maintenance. Because the failure to
adequately monitor performance of the Unit 1 AFW system according to
10 CFR 50.65(a)(2) is of very low safety significance and has been entered into the
corrective action program as AR A0595257, this violation is being treated as a noncited
violation, consistent with Section VI.A of the NRC Enforcement Policy: NCV 50-275/
03-08-02, Failure to Adequately Monitor Auxiliary Feedwater System According to
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
The inspectors performed five inspection samples of maintenance risk assessments and
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 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, maintenance outage windows for Component Cooling Water Heat
Exchanger 1-2, Atmospheric Dump Valve MS-1-PCV-19, and Positive
Displacement Pump 1-3 on September 30
- Unit 2, Eagle 21 Protection Set Rack 13 Nonvolatile Random Access Memory
replacement and Atmospheric Dump Valve MS-2-PCV-20 calibration on
October 23
- Units 1 and 2, 500 kV breaker replacement work on November 6
b. Findings
No findings of significance were identified.
.2 Emergent Work
a. Inspection Scope
The inspectors observed two emergent work activities to verify that actions were taken
to minimize the probability of initiating events, maintain the functional capability of
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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 2, Valve FCV-495 actuator replacement
- Unit 1, Valve SI-1-8890 packing leakage
b. Findings
No findings of significance were identified.
1R14 Operator Performance during Nonroutine Evolutions and Events, Including Followup in
Response to Earthquakes Impacting Diablo Canyon Power Plant (71111.14)
a. Inspection Scope
The inspectors reviewed three inspection samples (two earthquakes and high Pacific
Ocean swells) of nonroutine evolutions or events.
.1 Earthquakes In the Vicinity of the Diablo Canyon Power Plant
Background
Diablo Canyon Power Plant is located in a seismically active area along the interface of
the Pacific and North American Plates. Several faults are located within 50 miles of the
plant. PG&E is required by the operating license to maintain a Long-Term Seismic
Program to reevaluate the seismic design bases against insights and knowledge gained
with each seismic event. FSAR Update Section 3.7 describes the seismic design basis
of the facility. The plant was designed for ground motion from a Design Earthquake,
equivalent to an "Operating Basis Earthquake," in which the plant can be expected to
continue to operate. This value is ground motion acceleration at the containment base
of 0.2g. The Double Design Earthquake, equivalent to a Safe Shutdown Earthquake,
is the design basis for most safety-related structures, and has ground motion
acceleration of 0.4. The plant is also evaluated for the maximum ground acceleration
which can result from an earthquake originating in the Hosgri fault. This evaluation
ensures the plant can be safely shut down if the expected maximum ground motion
were to occur.
Technical Specification 3.3.1, "Reactor Trip System," requires instrumentation to initiate
a reactor trip for a nominal ground acceleration of 0.35 g. An earthquake force monitor,
which has three sensors, provides an alarm in the control room at a minimum of 0.01g
of ground acceleration. Procedure CP M-4, Earthquake, Revision 18, addresses the
actions required to be taken in the event of an earthquake of 0.01 g or greater.
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Deer Canyon Earthquakes
Description
At 12:52 a.m., on October 18, 2003, Diablo Canyon Power Plant Units 1 and 2 declared
a Notification of Unusual Event (NOUE) because an earthquake that measured 3.4 was
felt by the control room operators. No damage to plant equipment was observed and
both units remained at 100 power throughout the event.
A preshock occurred at 12:27 a.m. that lasted approximately 3 seconds and was felt by
the control room operators. No alarms or other effects were noted. The primary shock
occurred at 12:39 a.m. and lasted approximately one second. The epicenter of the
seismic event was located 2.8 miles east-southeast of the plant (within the owner
controlled area) and measured 3.4. The primary shock resulted in momentary turbine
bearing high vibration alarms on both units and a high level alarm on the Unit 1 Safety
Injection Accumulator 1-3. The plants seismic monitor recorded a peak acceleration of
0.02 g.
Following declaration of the NOUE, operators entered Procedure CP M-4, which
contained instructions for response to earthquakes detected at the site. The shift
manager initiated a preliminary evacuation of the intake structure (where valve
maintenance was in progress) until the extent of the seismic event was understood.
PG&E performed walkdowns of both containments and all vital areas to ensure no
immediate structural damage was evident. PG&E performed enhanced monitoring of
safety-related tank levels to ensure no ruptures occurred. No damage to any plant
equipment was identified.
Following confirmation that the earthquake resulted in no plant damage, PG&E exited
the NOUE at 3:30 a.m. The inspectors responded to the site to monitor PG&Es actions
and verified that PG&E performed the actions prescribed by Procedure CP M-4. The
inspectors walked down safety-related areas of the plant and noted no evidence of
damage that would affect safety system operability. The inspectors continued to
examine the status of structures following the October 18, 2003, earthquake during
routine plant status walkdowns throughout the inspection period.
The inspectors reviewed Special Report 50-275;323/03-03-00, "Seismic Event of
October 18, 2003," which discussed the Deer Canyon earthquakes of October 18 and
provided analysis of the effects of the earthquakes on plant structures, systems, and
components. The inspectors found the report properly analyzed the seismic data and
the impact that the ground motion had on structures, systems, and components.
San Simeon Earthquake 35 Miles Northwest of the Site
Description
At approximately 10:30 a.m. PST on December 22, 2003, the resident inspectors heard
a noise on the roof of the Diablo Canyon administrative building. The inspectors
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responded to the control room to report this information to the shift manager. The shift
manager received similar reports from personnel in the warehouse and the training
building outside the protected area. The inspectors and the operators verified that no
alarms were received in the control room and that the seismic monitor did not register
this event. The shift manager and the inspectors reviewed Procedure CP M-4 and
verified that no action was required.
At 11:16 a.m. PST a magnitude 6.5 earthquake struck 35 miles north-northwest of
Diablo Canyon. Both resident inspectors were at the site. The shaking lasted
22 seconds. The senior resident inspector (SRI) immediately contacted the Region IV
branch chief and informed the branch chief that an earthquake had been felt.
While the SRI was briefing Region IV, the resident inspector (RI) responded to the
control room at 11:18 a.m. to observe the operators. The RI walked down the panels,
reviewed the status of safety systems, and verified that PG&E was implementing the
emergency plan. The RI noted that the seismic monitor recorded a seismic event of
0.04g. The RI established the NRCs reactor safety counterpart link and advised the
NRC headquarters operations officer that PG&E would soon be declaring a NOUE.
The SRI reported to the control room to observe PG&E actions. The inspectors verified
that the requirements of Procedure CP M-4 were followed. The procedure required
verification of the tank levels of all of the major safety-related tanks to ensure that no
catastrophic failures of the important tanks had occurred. The inspectors verified the
applicable tank levels. The procedure also required a complete walkdown of plant
areas. PG&E received annunciators for the Unit 1 spent fuel pool level and safety
injection accumulator high and low levels for both units during the seismic event
because of sloshing of the water. Operators received temporary alarms that included
high vibration for the Unit 1 turbine. The operating electrohydraulic control pump tripped
and was immediately restarted. Operators cleared the alarms following the shaking.
PG&E declared a NOUE at 11:22 a.m. The inspectors verified that PG&E made the
required calls to the state and local officials. PG&E sent personnel to the Emergency
Operating Facility (EOF), which is co-located with the San Luis Obispo County Office of
Emergency Services to assist in monitoring the community and the emergency services
response. PG&E established a video conference between the EOF and the shift
manager's office for the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. One of the inspectors was present in the shift
managers office during each of the updates between the EOF and the control room.
The EOF advised the control room of damage to Highway 46 and fallen rocks on
Highway 41, which is an emergency evacuation route. The inspectors communicated
the status of local roadways to Region IV. Highways 46 and 41 had debris on the road,
and Highway 46 experienced some buckling, but the highways were passable for
emergency response purposes. In addition, personnel in the EOF communicated the
status of several emergency sirens that were inoperable because of the power outages
in San Luis Obispo county.
Fifty-six of the 131 emergency sirens were inoperable because of power outages.
Alternate means of notifying people within the affected areas were available. As of
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3:40 p.m., on December 22, 2003, 35 sirens were without power, and at 6 p.m.
26 sirens were still without power. At 1:30 a.m., on December 23, 2003, four sirens
were without power. The remaining four were restored in the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The inspectors monitored reports of PG&E walkdowns of the plant. At approximately
3 p.m., the RIs began independent inspections of plant equipment, for Phase I of the
NRC inspection plan following the earthquake. One RI remained in the control room to
monitor operator actions and maintain communications within the agency, while the
other inspector walked down plant areas.
The inspectors walked down the turbine building first. The emergency diesel
generators, the component cooling water heat exchangers, and high voltage switchgear
are in this building. The inspectors verified that no leaks existed in the safety-related
systems and that no cracks were evident in structural members.
The inspectors then walked down the switchgear areas of the auxiliary building. The
inspectors verified that no damage occurred in the ac and dc switchgear rooms, the
cable spreading room, and the battery rooms.
The inspectors entered the radiologically controlled area of the auxiliary building and
performed complete inspections of the emergency core cooling pumps and systems,
component cooling water pumps, auxiliary feedwater pumps, and RHR system heat
exchangers.
The inspectors entered the fuel building and verified the level in the spent fuel pools. All
structural elements in the spent fuel pool were unaffected. Spent fuel pool water clarity
was good. No cracks were evident in the fuel building ventilation system or structural
members.
The inspectors walked down the outside areas of the plant. The inspectors verified that
the applicable security barriers were still intact. The inspectors verified that the major
outside tanks (condensate storage tanks, refueling water storage tanks, primary water
storage tanks, and fire water storage tank) had no cracks or obvious damage. The
inspectors toured the intake structure and verified that no damage occurred to the
traveling screens and auxiliary saltwater pumps, pipes, and valves.
The RIs provided continuous site coverage until PG&E exited the NOUE. Because the
area continued to experience aftershocks, PG&E elected to remain in a NOUE for
approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The RIs continued to inspect the facility and monitor control
room actions for the duration of the NOUE. During the evening, the inspectors walked
down the offsite power sources (startup transformers) and continued to monitor
communications with the emergency facilities. The inspectors examined the auxiliary
and startup transformers for damage. PG&E personnel reported that two switches were
damaged in the 230 kV system at the offsite Morro Bay switchyard. The Morro Bay
switchyard is one source of offsite power to the startup transformers. PG&E declared
the startup transformers inoperable to provide safe electrical isolation and cleared the
230 kV lines to support replacement of the damaged switches. The startup
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transformers were returned to operable status within the 72-hour limiting condition for
operation action statement. The RIs remained at the site, continuing to inspect and
monitor PG&E actions until 2 p.m. PST on December 23. PG&E exited the NOUE at
approximately 12:15 p.m., PST on December 23, 2003.
In the days following the event, the inspectors continued to review PG&Es response to
aftershocks and the adequacy of the PG&E procedures and the Emergency Plan. The
inspectors attended PG&E's Event Review Team meetings throughout the remainder of
the inspection period.
a. Findings
During the inspections, no system or structural damage or evidence of differential
deflections were detected, and no site ground effects were noted during exterior visual
inspections. In addition, no damage was noted to the administration building, which is
designed to the Uniform Building Code. The licensees immediate response to the
earthquake was effective in ensuring continued safe operation, and their implementation
of the NRCs prompt notification requirements was timely and correct.
All seismic instrumentation functioned correctly. The NRC inspectors conducted a
review of the required surveillances on seismic monitoring instruments. All instruments
were correctly calibrated. The inspectors noted that the licensee is in the process of
upgrading the current Earthquake Force Monitor to a digital distributed system that will
provide better information (e.g., wider frequency response and more monitoring
locations).
Casualty Procedure M-4 was used in responding to the earthquake. Although overall
response to the earthquake was adequate, several lessons were learned by PG&E from
a subsequent review of the implementation of the procedure. PG&E has begun a
general revision to improve its quality based on this experience.
The inspectors reviewed PG&Es reportability procedure for loss of the early warning
system sirens. During the review, the inspectors noted that the procedure for
notification of the NRC for a loss of the early warning system sirens only addressed
sirens within a 10-mile radius and not the entire Diablo Canyon Emergency Planning
Zone, as defined in the Emergency Plan. In this case, the licensee did inform the NRC
of the loss at the time the Unusual Event notification was made.
.2 Units 1 and 2 Downpowers because of High Pacific Ocean Swells
a. Inspection Scope
On December 9, 2003, PG&E received warning of impending high Pacific Ocean swells.
Upon notification of the high swells, PG&E management determined that the units would
be ramped down to approximately 25 percent power to prevent the traveling screens,
from being clogged with kelp, which could necessitate tripping the circulating water
pumps and a reactor trip of the affected unit. At 1:30 a.m., on December 10, operators
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slowly decreased power on both units. The inspectors responded to the site and
monitored the operator performance during the downpower and operator response to
any high differential pressure across the traveling screens.
b. Findings
No findings of significance were identified.
1R16 Operator Workarounds
a. Inspection Scope (71111.16)
The inspectors reviewed three samples of operator workarounds.
The inspectors reviewed PG&Es documented actions in which degraded conditions or
changes to accident analyses required additional operator action beyond that credited in
the design basis to compensate for these conditions. PG&E tracked two types of these
conditions: operator burdens and operator workarounds.
PG&E defined an operator burden as a manual action taken to compensate for
degraded equipment that affected normal operation of a unit. PG&E had 17 operator
burdens.
PG&E defined an operator workaround as a manual action taken to compensate for a
degraded condition required for response to abnormal or emergency operating
procedures. PG&E had 17 active operator workarounds. The inspectors assessed the
cumulative affect of the operator workarounds to determine if operators would be overly
taxed with working around numerous degraded conditions that would complicate an
abnormal or emergency condition.
The NRC inspectors reviewed PG&Es program for tracking the operator workarounds
and restoring the applicable systems to full qualification to determine if PG&E
appropriately managed these items. None of the operator workarounds involved
risk-significant actions.
b. Findings
No findings of significance were identified.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed eight postmaintenance 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 was compared to the
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Technical Specifications and the FSAR Update. Additionally, the inspectors verified that
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 corrective maintenance activities were reviewed by the inspectors:
- Unit 1, Thermocouple Monitoring System Trains A and B reconnection following
open thermocouple detection circuit on April 13 and 26, 2002 (Work
Orders C0176158 and C0176579)
- Unit 1, RHR Pump 1-2 inspection for water intrusion into terminal box on
January 14 (Work Orders C0178108 and C0178123)
- Unit 2, Diesel Engine Generator 2-1 routine maintenance outage window on
September 30 (Work Orders R0240283, R0231007, and R0231009)
- Unit 2, Diesel Engine Generator 2-3 high pressure fuel line leak repair on
October 9 (AR A0592470 and Work Order C0184992)
- Unit 1, Atmospheric Dump Valve MS-1-PCV-21 calibration on October 21-22
(Work Orders R0245981 and R0245983)
- Unit 1, Diesel Engine Generator 1-2 air start motor preventive maintenance on
October 27 (Work Order C0182839)
- Unit 1, Auxiliary Building Ventilation System Exhaust Fan E-1 preventive
maintenance on December 2 (Work Order R0228685)
- Unit 1, Pressure Balancing Valve SI-1-8890A packing replacement and repair
tool installation on December 3 (Work Order C0185920)
b. Findings
Introduction. A Green noncited violation was identified by the inspectors for failure to
adequately evaluate the capability of core exit thermocouples to measure radial
temperature gradient for Quadrant 1 of the Unit 1 reactor core, as required by 10 CFR
Part 50, Appendix B, Criterion III.
Description. During Refueling Outage 1R11, maintenance personnel disconnected the
core exit thermocouple connections on top of the Unit 1 reactor vessel head for reactor
vessel head removal for refueling operations. On April 26-27, 2002, maintenance
personnel concluded reconnection of the core exit thermocouples on top of the Unit 1
reactor vessel head. On September 10, 2003, reactor engineers identified a
discrepancy among several of the core exit thermocouple temperature readings while
performing an in-core flux map. The reactor engineers noticed that some of the
thermocouples were reading lower than expected temperatures and others were reading
higher than expected temperatures. A troubleshooting team evaluated the
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discrepancies and concluded that maintenance personnel had incorrectly swapped the
Trains A and B thermocouple connectors at Port 79 on the reactor vessel head.
Maintenance personnel and operators did not identify the incorrect connection prior to
reactor startup, since the temperature readings were uniform for all thermocouples. The
discrepancy in thermocouple readings becomes noticeable at full reactor power when
the thermocouples near the center of the reactor core read higher than those towards
the outside of the core. However, operators did not notice the discrepancy at full power
operation since they checked to see if the thermocouple readings were in a valid range
rather than checking to see if the readings were an expected value.
The inspectors reviewed the Technical Specification bases documents for core exit
thermocouples and identified the following design aspects:
- At least two channels of valid core exit thermocouples per quadrant are required,
with a channel consisting of two thermocouples.
- In a channel, one thermocouple must be near the core center and the other must
be near the core periphery in order to measure radial temperature gradient.
- The two channels must ensure that a single failure will not disable the ability to
determine radial temperature gradient.
The inspectors observed that PG&E did not take credit for the swapped thermocouples,
leaving only 6 operable thermocouples in Quadrant 1 of the reactor core. The
inspectors questioned whether the possible core exit thermocouple pairs for each train
could meet the requirement for measuring radial temperature gradient. Specifically,
Train A relied on a combination of Thermocouple 15 with Thermocouples 1 or 11.
Thermocouple 15 had three assemblies from the outside of the core, while
Thermocouples 1 and 11 had one and two assemblies from the outside of the core,
respectively. Similarly, Train B relied on a combination of Thermocouple 5 with
Thermocouples 14 or 36. Thermocouple 5 had three assemblies from the outside of the
core, while Thermocouples 14 and 36 had one and two assemblies from the outside of
the core, respectively. When the inspectors requested design bases information for the
selection of thermocouple pairs for each quadrant, PG&E was not able to provide the
design documents or an adequate technical basis for the selection.
The inspectors reviewed AR A0528665, which was initiated in April 4, 2001. The AR
requested a clarification of the core exit thermocouple surveillance procedure with the
design bases. However, the AR failed to adequately address the technical basis for the
location of thermocouples for measuring radial temperature gradient within the reactor
core. The inspectors determined that both core exit thermocouple channels for
Quadrant 1 of the Unit 1 reactor could be considered operable if appropriate
compensatory actions/modifications were taken. Specifically, the swapped
thermocouples continued to provide reliable temperature information, but in the wrong
locations. The inspectors observed that PG&E posted a sign on the Unit 1
thermocouple monitoring system, indicating the swapped thermocouples and what
locations of the core they were actually measuring temperature.
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Analysis. The inspectors determined that, following the swapping of core exit
thermocouples, PG&Es failure to adequately evaluate the technical bases for
measuring radial temperature gradient within the reactor core was a performance
deficiency. The finding impacts the mitigating system cornerstone through degraded
overall availability of the components within a system used to assess and respond to
initiating events to prevent undesirable consequences and was greater than minor when
compared to Example 3.a of IMC 0612, Appendix E. Similar to Example 3.a, PG&E
staff performed additional work to verify the ability of the core exit thermocouples to
measure radial temperature gradient within Quadrant 1 of the Unit 1 reactor core. Using
the SDP Phase 1 screening worksheet from IMC 0609, Appendix A, the finding was
determined to be of very low safety significance, since the deficiency was confirmed not
to result in loss of function per Generic Letter 91-18, Revision 1.
Enforcement. 10 CFR Part 50, Appendix B, Criterion III, states, in part, that measures
shall be established for the selection and review for suitability of application of materials,
parts, equipment, and processes that are essential to the safety-related functions of
structures, systems, and components. Contrary to the above, PG&E failed to
adequately address the suitability of the remaining operable Quadrant 1 core exit
thermocouples for measuring core radial temperature gradient. Because this failure to
provide adequate technical basis for core exit thermocouple operability is of very low
safety significance and has been entered into the corrective action program as
AR A0597575, this violation is being treated as a noncited violation, consistent with
Section VI.A of the NRC Enforcement Policy: NCV 50-275/03-08-03, Failure to Provide
Adequate Technical Bases for Core Exit Thermocouple Radial Temperature
Measurement.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors performed three inspection samples of surveillance testing.
The inspectors evaluated several 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. 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:
- Procedure STP I-1C, Routine Weekly Checks Required By Licenses (Unit 1),
Revision 77 on October 9
- Procedure STP P-AFW-21, "Routine Surveillance Test of Turbine Driven
Auxiliary Feedwater Pump 2-1," Revision 16, on October 16
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- Procedure STP I-2D, Nuclear Power Range Incore/Excore Calibration,
Revision 48 on November 18
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors reviewed two inspection samples of temporary plant modifications.
The inspectors reviewed a sample of two temporary plant modifications that could
potentially impact the mission of important safety systems. Temporary plant
modifications include jumpers, lifted leads, temporary systems, repairs, design
modifications, and procedure changes which can introduce changes to plant design or
operations. There were 30 active temporary modifications during this inspection period.
Inspection activities included a review of the temporary modification impact on:
(1) operability of equipment, (2) energy requirements, (3) material compatibility,
(4) structural integrity, (5) environmental qualification, (6) response time, and (7) logic
and control integration. The inspectors also verified the design and alignment of safety
systems when the temporary modifications were no longer needed. The following
temporary modification was reviewed during this inspection period:
- Unit 1, Measuring and test equipment added to battery Charger 1-2 float
feedback circuit for troubleshooting per Work Order C0185038 and
- Unit 1, Add second off-globe valve to 1-04L-41, per Work Order C0184388 and
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert Notification System Testing (71114.02)
a. Inspection Scope
The inspector performed one inspection sample. The inspector discussed the status of
offsite siren and tone alert radio systems with the PG&E staff to determine if significant
changes had been made to those systems or methods of maintenance and testing of
the systems. The inspector reviewed the documents and correspondence associated
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with the November 2000 Early Warning System Operating System Project Proposal.
The inspector compared the current testing and maintenance methods described in
EP MT-43, Early Warning System Testing and Maintenance, with requirements in
10 CFR Part 50, Appendix E. PG&Es alert and notification system testing program was
compared with criteria in NUREG-0654, Criteria for Preparation and Evaluation of
Radiological Emergency Response Plans and Preparedness in Support of Nuclear
Power Plants; Federal Emergency Management Agency (FEMA) Report REP-10,
Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants;
and the PG&Es FEMA-approved alert and notification system design report.
b. Findings
No findings of significance were identified.
1EP3 Emergency Response Organization Augmentation Testing (71114.03)
a. Inspection Scope
One inspection sample was performed. The inspector discussed with PG&E the status
of primary and backup systems for mobilizing the emergency response organization
during an emergency to determine PG&Es ability to staff emergency response facilities
in accordance with PG&Es emergency plan and the requirements of 10 CFR Part 50,
Appendix E. The inspector reviewed correspondence associated with contracting out
the emergency response organization call out function. The inspector reviewed the
results of three rapid-response drills conducted following activation of the new call out
process. The inspector also reviewed the following documents related to the
emergency response organization augmentation system:
- EP G-2, Interim Emergency Response Organization
- EP G-3, Emergency Notification of Off-Site Agencies
b. Findings
No findings of significance were identified.
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
a. Inspection Scope
One inspection sample was performed. The inspector performed an on-site review of
the following Emergency Plan revisions. The revisions were compared to the previous
revisions; the criteria of NUREG-0654, Criteria for Preparation and Evaluation of
Radiological Emergency Response Plans and Preparedness in Support of Nuclear
Power Plants; and the requirements of 10 CFR 50.47(b) and 50.54(q) to determine if
the revisions decreased the effectiveness of the emergency plan.
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- Revision 4, Change 4 to Tab 5, Organizational Control of Emergencies, and
Revision 4, Change 3 to Tab 7, Emergency Facilities and Equipment, submitted
on November 4, 2003. These revisions replaced the on-site health physics
communication phone line with a satellite phone system.
- Revision 4, Change 3 to Tab 4, Emergency Classification, and Revision 33 to
EP G-1, Attachment 7.1, Emergency Action Level Classification Chart,
submitted November 4, 2003. This revision replaced the control room main
annunciator printer with a computer and touch screen monitor to provide the
same functions.
b. Findings
No findings of significance were identified.
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)
a. Inspection Scope
One inspection sample was performed. The inspector reviewed the following
documents related to PG&Es corrective action program to determine PG&Es ability to
identify and correct problems in accordance with 10 CFR 50.47(b)(14) and 10 CFR Part
50, Appendix E:
- Summaries of corrective actions assigned to the emergency preparedness
department between September 2001 and October 2003
- Detailed review of 27 action requests
- Annual exercise and quarterly drill self-assessments from October 23, 2002;
May 28, 2003; and July 17, 2003
- Emergency Preparedness Self-Assessment, April 9-11, 2003
- 50.54(t) Review, May 11, 2002; and April 4, 2003
- Quality Performance Assessment Report, Third Period 2003, July 1 to
September 30, 2003
b. Findings
No findings of significance were identified.
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1EP6 Emergency Preparedness Evaluation (71114.06)
a. Inspection Scope
The inspectors witnessed one emergency preparedness drill that included emergency
plan implementation conducted on October 29, 2003. The scenario simulated a large
break loss-of-coolant accident, coupled with clogging of the containment recirculation
sump. The scenario continued with damage to fission product barriers, core damage,
and a radiological release to the environment to demonstrate PG&Es capabilities to
implement the emergency plan. The inspectors witnessed PG&E performance in the
control room (i.e., simulator), the Technical Support Center, and the Emergency Offsite
Facility. The inspectors also attended PG&Es self-critique of the scenario. The
following procedures were used to evaluate the performance:
- Procedure EOP E-0, Reactor Trip or Safety Injection, Revision 27
- Procedure EOP E-1, Loss of Reactor or Secondary Coolant, Revision 18
- Procedure EOP FR-C.1, Response to Inadequate Core Cooling, Revision 15
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS2 As Low as is Reasonable Achievable (ALARA) Planning and Controls (71121.02)
a. Inspection Scope
The inspector completed eight samples of ALARA planning and controls.
The inspector assessed PG&Es performance in implementing physical and
administrative controls for airborne radioactivity areas, radiation areas, and high
radiation areas, radiation worker practices, and work activity dose results against
procedural and regulatory requirements. No high exposure work activities in high
radiation or airborne areas were performed during the inspection. Therefore, this aspect
could not be evaluated.
The inspector interviewed radiation protection staff and other radiation workers to
determine the level of planning, communication, ALARA practices, and supervisory
oversight integrated into work planning and work activities. The inspector reviewed
initial and emergent work scopes and estimated man-hours provided to the radiation
protection group for accuracy. In addition, the following items were reviewed and
compared with procedural and regulatory requirements to assess PG&Es program to
maintain occupational exposures ALARA:
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- Plant collective exposure history for the past 3 years, current exposure trends,
source term measurements, and 3-year rolling average dose information
- ALARA program procedures
- Processes, methodology, and bases used to estimate, justify, adjust, track, and
evaluate exposures
- Three ALARA prejob, in-progress, and postjob reviews and associated radiation
work permit (RWP) packages from Unit 2 Refueling Outage 11 activities which
resulted in some of the highest personnel collective exposures (RWPs 03-2002,
03-2044, and 03-2005)
- Temporary shielding program and implementation
- Hot spot tracking and reduction program
- Quality Verification Audit 031700023, Quality Verification Assessment Report for
the Third Period 2003, Quality Verification Assessment Report 030410010, and
the 2002 Annual Review of the DCPP Radiation Protection Program
- Three ALARA Review Committee meeting minutes (February 6, June 19, and
October 14, 2003)
- Declared pregnant worker and embryo/fetus dose evaluation, monitoring, and
controls
- Summary of corrective action documents written since the last inspection and
selected documents relating to exposure tracking, higher than planned exposure
levels, radiation worker practices, and repetitive and significant individual
deficiencies.
b. Findings
Introduction. The inspector identified collective doses for reactor coolant pump (RCP)
work activities performed during Unit 2 Refueling Outage 11 were not maintained
ALARA. Specifically, the inspector determined that the work activity associated with
RWP 03-2055, "Reactor Coolant Pump (RCP) 2-2, 10 year inspection," exceeded
5 person-rem and the dose estimation by more than 50 percent.
Description. During a review of RWP packages and accumulated dose for Unit 2
Refueling Outage 11 work, the inspector identified that work associated with RCP 2-2
was originally estimated on January 10, 2003, to be completed for 1.5 person-rem. Due
to concerns identified during the inspection of RCP 2-2, the work scope was expanded
to include similar work on RCP 2-1. On February 15, 2003, the job dose was properly
re-estimated and justified, for the known work scope, to be 2.9 person-rem. However,
due to the failure to communicate the full work scope and radiological conditions among
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the predictive maintenance personnel, the RCP component engineer, and the ALARA
staff, the 2.9 person-rem estimate was exceeded. Specifically, the ALARA staff and the
RCP component engineer were not informed by the predictive maintenance staff that
the maintenance task included numerous motor stator balance efforts that would be
performed during the time the steam generators were drained. The job was completed
for 5.4 person-rem (86 percent greater than the justified estimate).
Analysis. The failure to maintain collective doses ALARA is a performance deficiency.
This finding was more than minor because it is associated with the Occupational
Radiation Safety Cornerstone attribute (program and process) and affected the
associated cornerstone objective (to ensure adequate protection of worker health and
safety from exposure to radiation). This occurrence involved inadequate planning,
which resulted in unplanned, unintended occupational collective dose for a work activity.
When processed through the Occupational Radiation Safety SDP, this finding was
found to have no more than very low safety significance because the finding was an
ALARA planning issue and the PG&Es 3-year rolling average collective dose was less
than 135 person-rem. PG&E entered this finding into their corrective action program as
AR A0595776 (FIN 50-323/2003-08-04, Failure to maintain job dose ALARA).
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
a. Inspection Scope
Three inspection samples were performed. The inspector sampled PG&E submittals for
the performance indicators listed below for the period from October 31, 2002, through
September 30, 2003. The definitions and guidance of NEI (Nuclear Energy
Institute 99-02, Regulatory Assessment Indicator Guideline, were used to verify
PG&Es basis for reporting each data element in order to verify the accuracy of
performance indicator data reported during the assessment period. PG&Es
performance indicator data were reviewed against the requirements of Procedure
AWP EP-001, Emergency Preparedness Performance Indicators.
Emergency Preparedness Cornerstone:
- Drill and Exercise Performance (DEP)
- Emergency Response Organization Participation (ERO)
- Alert and Notification System Reliability
The inspector reviewed a sample of drill and exercise scenarios and licensed operator
simulator training sessions, notification forms, and attendance and critique records
associated with training sessions, drills, and exercises conducted during the verification
period. PG&Es performance was reviewed against the requirements of the PG&Es
Emergency Plan and EP G-3, Emergency Notification of Off-Site Agencies. The
inspector reviewed a sample of 8 emergency responder qualification and training
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records and a sample of 10 drill participation records. The inspector reviewed alert and
notification system testing procedures, maintenance records, and a 100 percent sample
of siren test records.
b. Findings
The inspector observed one instance where a DEP performance indicator opportunity
for notification accuracy and timeliness was incorrectly judged as a successful
opportunity. During an operator continuing training simulator session, the scenario
conditions required an Alert declaration and changed approximately 3 minutes later to
require a Site Area Emergency declaration. The first emergency declaration was made
as a Site Area Emergency approximately 17 minutes after conditions required the Alert
declaration. This performance was critiqued thoroughly by the PG&E operations and
emergency preparedness staff, and it was concluded to be acceptable performance due
to the rapidly changing plant conditions. The DEP performance indicator for event
classification was also evaluated as successful. The inspectors discussed this
evaluation with the emergency preparedness staff and concluded that the classification
opportunity should have been evaluated as a missed opportunity. NEI 99-02 requires
that the classification opportunity be evaluated as unsuccessful if the declaration of the
emergency classification is not made within 15 minutes of the time that conditions that
require the declaration are available to the decision maker. Based on that criteria in this
case, the performance indicator would be successful if an Alert or Site Area Emergency
had been declared within 15 minutes of the time that conditions for an Alert were
available. This change would not have affected the reported performance indicator
color.
The inspector also noted that Procedures EP G-2 and EP G-3 discussed the role of the
unaffected unit shift foreman as the control room communicator with responsibilities
including gathering information and completing the offsite notification form and
performing the communications to the offsite agencies. This would require that the unit
shift foremen be tracked in the ERO performance indicator as control room
communicators, in addition to the Shift Manager, who also performs those functions.
PG&E only tracks the shift manager for the ERO performance indicator, since, in
practice, the shift manager is the only individual who completes the notification form.
PG&E entered the procedure inconsistency in the corrective action process as
AR A0594284 to change Procedures EP G-2 and EP G-3 to reflect the site practice that
only the shift manager performs the communicator functions of filling out the notification
forms.
4OA2 Problem Identification and Resolution (71152)
.1 Emergency Planning Annual Sample Review
a. Inspection Scope
The inspector selected 27 action requests for detailed review. The entries were
reviewed to ensure that the full extent of the issues was identified, an appropriate
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evaluation was performed, and appropriate corrective actions were specified and
prioritized. The inspector reviewed seven assessment reports and corrective actions
resulting from those assessments. The inspector evaluated corrective actions against
the requirements of Procedure OM7.ID1, Problem Identification and Resolution-Action
Requests, and Emergency Planning Guide EPG01, Problem Identification.
b. Findings
No findings of significance were identified.
.2 Packing Gland Follower Failure (Unit 1)
a. Inspection Scope
The inspectors reviewed the licensee response and actions that led to a packing gland
follower failure and leak from Valve SI-1-8890. The inspectors reviewed operator
actions on December 3, 2003, upon discovery of a significant leak from the packing
gland of Valve SI-1-8890 (as discussed in AR A0595692). The inspectors also
evaluated PG&E operating experience reviews dating to December 2000 that discussed
the potential for packing gland follower failures in Rockwell-Edwards valves
(AR A0522770).
b. Findings
Introduction. A self-revealing Green noncited violation was identified for the failure to
adequately evaluate operating experience related to failed packing gland followers for
Rockwell-Edwards valves. This was a violation of 10 CFR Part 50, Appendix B,
Criterion XVI, for failure to identify and correct a condition adverse to quality.
Description. On December 3, 2003, at 10:24 a.m., inservice inspection engineers
identified that Unit 1 Valve SI-1-8890A (the hot leg injection equalizing valve) had a
30 drop per minute leak rate from the packing gland. The inservice inspection engineer
initiated AR A0595692 to enter this item into the corrective action program. This
information was reported to the control room but not immediately acted upon. The
engineers reported this information to the system and component engineers, who
inspected the valve. The system engineer found that the packing gland follower flange
for Valve SI-1-8890 had split in two and that the valve leakage was excessive for the low
pressure condition with no pumps running. The system engineer reported this additional
information to the control room and stated that the packing would be rejected from the
valve and an excessive amount of leakage (on the order of several gallons per minute)
would result if the safety injection pumps were running.
The shift foreman evaluated this condition and, due to the cross-connected alignment of
the safety injection system, declared both trains of safety injection inoperable at
1:10 p.m. This entry into Technical Specification 3.0.3 required PG&E to take action to
shut down Unit 1 within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and go to Hot Standby within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. At
1:18 p.m., operators closed Valve SI-1-8821A, the cross-connect valve between the two
Enclosure
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safety injection trains. Thus, safety injection Pump 1-2 was isolated from the leak and
failed packing follower of Valve SI-1-8890A, and the shift foreman exited Technical Specification 3.0.3. The shift foreman entered the 72-hour limiting condition for
operation for inoperable safety injection Pump 1-2. On December 4, 2003, the
mechanics repaired and retested Valve SI-1-8890A and declared safety injection
Pump 1-2 operable.
Valve SI-1-8890A was a one-inch manual globe valve purchased from the
Rockwell-Edwards company. Operating experience Letter OE11685 issued in
December 2000 discussed a failure of a Rockwell-Edwards 1-inch manual globe valve at
another facility that resulted in a reactor trip. The valve failure at the other facility also
resulted from the splitting in two of the packing gland follower flange, ejecting the
packing gland follower, causing excessive packing leakage. The other licensee analyzed
this failure and determined that the packing gland follower flange was made from 410
stainless steel, a material with a very high hardness that was very susceptible to
intergranular stress corrosion cracking.
PG&E analyzed operating experience Letter OE11685 and determined that this
operating experience was applicable to Diablo Canyon. PG&E initiated AR A0522770 to
evaluate the impact of this industry experience on Diablo Canyon and take corrective
actions as deemed necessary. The engineers noted that Diablo Canyon had
225 Rockwell-Edwards valves installed, 113 for Unit 1 and 112 for Unit 2. PG&E staff
determined that, since the operating experience letter described an event in which the
packing gland follower flange failure resulted in a reactor trip, the evaluation for Diablo
Canyon need only encompass valves whose failure could cause a reactor trip. The
engineers did not consider taking action for valves in emergency core cooling systems
or valves that served as containment isolation valves, nor did the evaluation examine the
impact on plant risk. Thus, PG&E identified that only 12 valves at Diablo Canyon
needed to be repaired or back seated to meet the intent of operating experience
Letter OE11685.
The inspectors evaluated PG&Es review in AR A0522770 and determined that this
review of industry experience was insufficient, lacked thoroughness, and did not meet
the intent of determining the impact of the operating experience on plant safety. The
inspectors determined that this was a missed opportunity to identify and correct this
condition at Diablo Canyon, a violation of 10 CFR Part 50, Appendix B, Criterion XVI.
PG&E initiated AR A0595762 to enter this item into the corrective action program and
reevaluate operating experience OE 11685. PG&E then prioritized and took action to
either backseat, repair, or use a strongback on risk important valves.
Analysis. The inspectors determined that PG&Es failure to promptly identify and correct
a condition adverse to quality, which resulted in a packing gland follower failure and leak
from Valve SI-1-8890, was a performance deficiency. The finding impacts the mitigating
system cornerstone through degraded overall availability of the components within a
system used to assess and respond to initiating events to prevent undesirable
consequences and is greater than minor because the finding would become a more
significant safety concern if the leaky valve condition was left uncorrected. The amount
Enclosure
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of leakage from the valve would be significantly greater than a 30 drop per minute leak
rate, if the safety injection pumps were fully running in the hot leg injection mode. The
Valve SI-1-8890A leak rate is bounded by a RHR pump seal failure. Although PG&E
declared both trains of the safety injection system to be inoperable and entered
Technical Specification 3.0.3 upon discovery of the condition, the safety injection system
was considered to be operable but degraded because both safety injection system
trains would be available to provide adequate flow when a demand occurs. Using the
SDP Phase 1 worksheet in IMC 0609, Appendix A, the finding was determined to be of
very low safety significance, since there is no loss of an actual safety function, no loss of
a safety-related train for greater than the Technical Specification allowed outage time,
and the finding is not potentially risk significant due to a seismic, fire flooding, or severe
weather initiating event.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, states, in part, that measures
shall be established to assure that conditions adverse to quality are promptly identified
and corrected. Contrary to the above, in December 2000, PG&E failed to identify and
correct the population of Rockwell-Edwards valves in safety-related and risk-significant
systems that were susceptible to intergranular stress corrosion cracking and failure of
the packing gland follower flange. As a result, on December 3, 2003, the packing gland
follower flange for Valve SI-1-8890A on the hot leg injection line failed, due to
intergranular stress corrosion cracking. Because the failure to promptly identify and
correct Rockwell-Edwards valves that were susceptible to the hardened packing gland
follower flanges is of very low safety significance and has been entered into the
corrective action program as AR A0595762, this violation is being treated as a noncited
violation, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 50-275/03-08-05, Failure to promptly identify and correct Rockwell-Edwards valves
susceptible to packing gland follower flange failures.
.3 Cross-References to Problem Identification and Resolution Findings Documented
Elsewhere
Section 1RO5.2 of this report describes a PI&R crosscutting aspect for corrective
actions not being promptly implemented, related to the Fire Protection Program,
following concerns with implementation of the operations responder position.
4OA3 Event Followup (71153)
.1 (Closed) Licensee Event Report 50-275/03-001-00: Technical Specification 3.8.1,
Action B.1, Not Met Due to Personnel Error.
On October 9, 2003, a unit shift foreman recognized that operators failed to perform an
offsite power circuit check when an emergency diesel generator was declared
inoperable for exhaust stack slide bearing replacement. Technical Specification 3.8.1,
AC Sources - Operating, Action B.1, requires that an offsite power circuit check be
performed within one hour upon declaring an emergency diesel generator inoperable.
PG&E determined that the cause of Technical Specification violation was a failure of the
Unit 1 shift foreman to recognize the need to perform the offsite power circuit check.
Enclosure
-31-
The operators subsequently determined that two independent circuits between the off-
site transmission network and the on-site distribution system were operable. Corrective
actions include briefing all operating crews on effective control room communication and
modifying the Technical Specification tracking module to require a sign-off that any
required conditional surveillances are being implemented upon declaring equipment
inoperable. No new findings were identified in the inspectors review. The finding
constitutes a violation of minor significance that is not subject to enforcement action in
accordance with Section IV of the NRCs Enforcement Policy. PG&E documented the
problem in Nonconformance Report N0002172. This licensee event report is closed.
40A4 Crosscutting Aspects of Findings
Section 1R12 of the report describes a human performance crosscutting issue where
maintenance personnel performed improper maintenance practices on Valve FW-1-
FCV-437.
Section 1R19 of the report describes a human performance crosscutting issue where
personnel inappropriately assembled the core exit thermocouples and subsequently
failed to recognize for an extended period the thermocouple readings were not
consistent with the core design.
40A5 Other
Evaluation of Diablo Canyon Safety Condition in Light of Financial Conditions
a. Inspection Scope
Due to PG&Es financial condition, Region IV initiated special review processes for
Diablo Canyon. The RIs continued to evaluate the following factors to determine
whether the financial condition and power needs of the station impacted plant safety.
The factors reviewed included: (1) impact on staffing, (2) corrective maintenance
backlog, (3) corrective action system backlogs, (4) changes to the planned maintenance
schedule, (5) reduction in outage scope, (6) availability of emergency facilities and
operability of emergency sirens, and (7) grid stability (i.e., availability of offsite power to
the switchyard, status of the operating reserves, and main generator Volt-Ampere
reactive loading).
b. Findings
No findings of significance were identified.
Enclosure
-32-
40A6 Management Meetings
Exit Meeting Summary
The resident inspection results were presented on January 8, 2004, to Mr. David H.
Oatley, Vice President and General Manager, and other members of PG&E
management. PG&E acknowledged the findings presented.
The inspectors asked PG&E whether any materials examined during the inspection
should be considered proprietary. Proprietary information was reviewed by the
inspectors and left with PG&E at the end of the inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
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. Hays, Director, Maintenance Services
S. Ketelsen, Manager, Regulatory Services
T. King, Manager, Learning 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
L. Womack, Vice President Nuclear Services
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
None
Opened and Closed
50-275; 323/03-08-01 NCV Failure to Establish and Implement Fire Program
Procedural Changes for Operations Responders in Support
of the Fire Brigade (Section 1R05.2)
50-275/03-08-02 NCV Failure to Adequately Monitor Auxiliary Feedwater System
According to 10 CFR 50.65(a)(2) (Section 1R12)
50-275/03-08-03 NCV Failure to Provide Adequate Technical Bases for Core Exit
Thermocouple Radial Temperature Measurement
(Section 1R19)
50-323/03-08-04 FIN Failure to Maintain Job Dose ALARA (Section 2OS2)
50-275;323/03-08-05 NCV Failure to promptly identify and correct Rockwell-Edwards
valves susceptible to packing gland follower flange failures
(Section 4OA2.2)
Closed
50-275/03-001-00 LER Technical Specification 3.8.1, Action B.1, Not Met Due to
Personnel Error (Section 4OA3.1)
-2-
A-1 Attachment
LIST OF DOCUMENTS REVIEWED
Section 1R04: Complete System Walkdown
Action Requests
A0546025 A0565358 A0575523 A0585572
A0546040 A0565369 A0575525 A0586410
A0547457 A0566251 A0575726 A0586489
A0549020 A0566911 A0577029 A0588816
A0549960 A0569438 A0577556 A0589346
A0552544 A0570386 A0577805 A0589783
A0553380 A0571874 A0579085 A0593236
A0558563 A0572253 A0583139 A0593493
A0560487 A0573626 A0584455 A0593495
A0560628 A0574099 A0584487
A0564139 A0575499 A0584685
A0564837 A0575511 A0584839
Section 1R05: Fire Protection
Licensing Basis Impact Evaluation Screen 1998-146, FSAR Section 9.5H - Revision 12"
Licensing Basis Impact Evaluation Screen 2003-004, FSAR Section 9.5H - Revision 14"
Section 1R06: Flood Protection
Action Requests
A0565300 A0568332 A0572819 A0581849
A0566672 A0571777 A0573248 A0592884
A0566894 A0572772 A0573508
Work Orders
R0239570
A-2 Attachment
Section 1R19: Post-Maintenance Testing
Action Requests
A0528665
A0538684
A0590156
Work Orders
C0176158
C0176579
Other Documents
Diablo Canyon Units 1 & 2, Technical Specification Bases, B3.3.3, PAM Instrumentation,
Revision 2
Procedure STP R-27A, Monthly Incore Thermocouple Evaluation, Revisions 6 & 8
Troubleshooting Log for A0590156
NRC Safety Evaluation Report SSER 31, Diablo Canyon - SSER 31: Staff Evaluation of
Miscellaneous Matters for Unit 2 (Board Notification No.85-051), May 2, 1985
Section 1EP2: Alert Notification System Testing
DCPP EWS Operating System - Project Proposal, November 2000
FEMA Region IX letters to PG&E, February 22 and May 11, 2001
PGE letter to FEMA Region IX, April 24, 2001
FEMA Early Warning System Design Report, December 1984
Section 1EP3: Emergency Response Organization Augmentation Testing
Rapid response drill reports from January 22, May 17, and September 9, 2003
Section 1EP4: Emergency Action Level and Emergency Plan Changes
OM10.ID2, Emergency Plan Revision and Review
Section 1EP5: Correction of Emergency Preparedness Weaknesses and Deficiencies
Action Requests: 0547774, 0550693, 0551200, 0554959, 0555070, 0558465, 0558491,
0558493, 0559139, 0566575, 0567256, 0567309, 0570531, 0572729, 0579860, 0580113,
0580122, 0580152, 0580154, 0582237, 0583140, 0583142, 0583391, 0584767, 0587734,
0589170, 0592987
A-3 Attachment
Section 4OA2: Problem Identification and Resolution
Self-Assessment for NRC Information Notice 2002-14, October 3, 2003
Self-Assessment, Bravo Team Graded Exercise, October 23, 2002
Self-Assessment, Charlie Team Drill, May 28, 2003
Self-Assessment, Alpha Team Drill, July 17, 2003
Section 2OS2: ALARA Planning and Controls
Procedures:
AD2.ID1 Procedure Use and Adherence, Revision 11
RP1 Radiation Protection, Revision 3
RP1.DC4 Radiological Hot Spot Identification and Control Program, Revision 1A
RP1.ID1 Requirements For The ALARA Program, Revision 2B
RP1.ID2 Use and Control of Temporary Radiation Shielding, Revision 5B
RP1.ID10 Embryo/Fetus Protection Program, Revision 2A
RCP D-205 Performing ALARA Reviews, Revision 13
RCP D-240 Radiological Posting, Revision 12A
Temporary Shielding Packages:
91-163
98-059
Hot Spot Packages:
113
116
Action Requests:
ETR-V0042728, AR- A0536032, A0571273, A0572734, A0572911, A0575867, A0577951,
A0578496, A0579604, A0581774, A0585060, A0589289, A0591813, and A0592291
A-4 Attachment
LIST OF ACRONYMS
ADAMS agency document access and management system
ALARA as low as is reasonably achievable
AR action request
DEG diesel engine generator
CFR Code of Federal Regulations
DEP drill and exercise performance
EOF Emergency Operations Facility
ERO emergency response organization
FEMA Federal Emergency Management Agency
FIN finding
FSAR Final Safety Analysis Report
IMC Inspection Manual Chapter
LER licensee event report
NCR nonconformance report
NCV noncited violation
NEI Nuclear Energy Institute
NOUE notification of unusual event
NRC Nuclear Regulatory Commission
PARS publicly available records system
PG&E Pacific Gas and Electric Company
RCP reactor coolant pump
RI resident inspector
RWP radiation work permit
SDP significance determination process
SRI senior resident inspector
URI unresolved item
A-5 Attachment