ML13038A714
| ML13038A714 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/07/2013 |
| From: | Geoffrey Miller NRC/RGN-IV/DRS/EB-2 |
| To: | Halpin E Pacific Gas & Electric Co |
| References | |
| EA-13-021 IR-12-008 | |
| Download: ML13038A714 (42) | |
See also: IR 05000275/2012008
Text
February 7, 2013
Mr. Edward D. Halpin
Senior Vice President and
Chief Nuclear Officer
Pacific Gas and Electric Company
Diablo Canyon Power Plant
P.O. Box 56, Mail Code 104/6
Avila Beach, CA 93424
SUBJECT: DIABLO CANYON POWER PLANT, UNITS 1 AND 2 - NRC TRIENNIAL FIRE
INSPECTION REPORT (05000275/2012008; 05000323/2012008) AND EXERCISE
Dear Mr. Halpin:
On November 8, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at the Diablo Canyon Power Plant. The enclosed inspection report documents the
inspection results, which were discussed in a debrief meeting on November 8, 2012, with you
and other members of your staff. Following additional in-office review, an exit meeting was
conducted on December 20, 2012, with you and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The team reviewed selected procedures and records, observed activities, and interviewed
personnel.
One NRC-identified finding and one self-revealing finding of very low safety significance (Green)
were identified during this inspection. Both of these findings involved violations of NRC
requirements. Additionally, two findings involving 10 CFR 50.48(b) were identified and were
violations of NRC requirements. The team screened these violations and determined that they
warrant enforcement discretion per NRC Enforcement Policy, Section 9.1, Enforcement
Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Section 11.05(b) of Inspection
Manual Chapter 0305 (EA-13-021).
UNITED STATES
NUCLEAR REGULATORY COMMISSION
RE G IO N I V
1600 EAST LAMAR BLVD
ARLINGTON, TEXAS 76011-4511
E. Halpin
- 2 -
If you contest any findings in this report, you should provide a written response within 30 days of
the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory
Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001; with copies to the
Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Senior Resident
Inspector at the Diablo Canyon Power Plant.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region IV, and the NRC Senior Resident
Inspector at Diablo Canyon Power Plant. The information you provide will be considered in
accordance with Inspection Manual Chapter 0305.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in the
NRC Public Document Room or from the Publicly Available Records (PARS) component of the
NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Geoffrey B. Miller, Chief
Engineering Branch 2
Division of Reactor Safety
Dockets: 50-275; 50-323
Enclosure: Inspection Report No. 05000275/2012008; 05000323/2012008
w/Attachment:
1 - Supplemental Information
Electronic Distribution to Diablo Canyon
E. Halpin
- 3 -
Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov)
Deputy Regional Administrator (Steven.Reynolds@nrc.gov)
DRP Director (Kriss.Kennedy@nrc.gov)
Acting DRP Deputy Director (Michael.Scott@nrc.gov)
Acting DRS Director (Tom.Blount@nrc.gov)
Acting DRS Deputy Director (Jeff.Clark@nrc.gov)
Senior Resident Inspector (Thomas.Hipschman@nrc.gov)
Resident Inspector (Laura.Micewski@nrc.gov)
Branch Chief, DRP/B (Neil.OKeefe@nrc.gov)
Senior Project Engineer, DRP/B (Leonard.Willoughby@nrc.gov)
Project Engineer, DRP/B (David.You@nrc.gov)
DC Administrative Assistant (Madeleine.Arel-Davis@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Project Manager (Joseph.Sebrosky@nrc.gov)
Branch Chief, DRS/TSB (Ray.Kellar@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Technical Support Assistant (Loretta.Williams@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
OEMail Resource
Include Mark Salley from RES on distribution
Inspection Reports/MidCycle and EOC Letters to the following:
ROPreports
Only inspection reports to the following:
RIV/ETA: OEDO (John.Cassidy@nrc.gov)
DRS/TSB STA (Dale.Powers@nrc.gov)
R:\\REACTORS\\DC\\DC 2012008 TFP
ADAMS: No Yes
SUNSI Review Complete
Reviewer Initials: GBM
Publicly Available
Non-Sensitive
Non-publicly Available
Sensitive
RIV: EB2\\SRI
RI
RI
RI
J. Mateychick
S. Alferink,
B. Correll
N. Okonkwo
/RA/
/RA/
/RA/
/RA/
2/5/13
2/6/13
2/6/13
2/6/13
ACES
C:\\DRP\\B
C:
D. Loveless
R. Browder
N. OKeefe
G. Miller
/RA/
/RA/
/RA/
/RA/
2/6/13
2/7/13
2/7/13
2/7/13
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
- 1 -
Enclosure
ENCLOSURE
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets:
50-275; 50-323
Licenses:
Report Nos.:
05000275/2012008 and 05000323/2012008
Licensee:
Pacific Gas and Electric Company
Facility:
Diablo Canyon Power Plant, Units 1 and 2
Location:
7 1/2 miles NW of Avila Beach
Avila Beach, California
Dates:
October 22 to December 20, 2012
Team Leader:
J. Mateychick, Senior Reactor Inspector, Engineering Branch 2
Inspectors:
S. Alferink, Reactor Inspector, Engineering Branch 2
B. Correll, Reactor Inspector, Engineering Branch 2
N. Okonkwo, Reactor Inspector, Engineering Branch 2
Approved By:
Geoffrey B. Miller, Branch Chief
Engineering Branch 2
Division of Reactor Safety
- 2 -
Enclosure
SUMMARY OF FINDINGS
IR; 05000275/2012008; 05000323/2012008; October 22 to December 20, 2012; Pacific Gas
and Electric Company; Diablo Canyon Power Plant, Units 1 and 2: Triennial Fire Protection
Team Inspection.
The report covered a two-week triennial fire protection team inspection by specialist inspectors
from Region IV. Two Green findings, which were non-cited violations (NCVs), were identified.
The significance of most findings is indicated by their color (Green, White, Yellow, Red) using
Inspection Manual Chapter 0609, Significance Determination Process, dated June 2, 2012.
Findings for which the significance determination process (SDP) does not apply may be Green
or be assigned a severity level after NRC management review. Cross-cutting aspect are
determined using IMC 0310, Components Within the Cross Cutting Areas dated October 28,
2012. All violations of NRC requirements are dispositioned in accordance with the NRCs
Enforcement Policy dated June 7, 2012. The NRCs program for overseeing the safe operation
of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight
Process, Revision 4, dated December 2006.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
Green. The team reviewed a self-revealing non-cited violation of License Conditions
2.C(4) for Unit 1 and 2.C(5) for Unit 2, Fire Protection Program, due to the licensee
inadvertently isolating the firewater yard loop for approximately three days, reducing the
plants fire protection capability without compensatory actions. The licensee entered this
issue in their corrective action program as Notification 50513006.
The failure to maintain the fire water system configuration as required in the approved
fire protection program was a performance deficiency. The performance deficiency was
more than minor because it was associated with the protection against external events
(fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. The performance
deficiency affected the fire protection defense-in depth strategies involving post-fire safe
shutdown systems. The major fire loading in the yard area resulted from the 12 large
transformers. The senior reactor analyst made the bounding assumption that any
transformer fire without suppression would result in an unrecoverable loss of offsite
power. A bounding value was calculated by multiplying the fire ignition frequency by the
conditional core damage probability. This resulted in a change to core damage
frequency of 1.2 x 10-7. Therefore, the subject finding was of very low safety significance
(Green).
This performance deficiency had a cross-cutting aspect in the area of resources
associated with providing complete, accurate and up-to-date design documentation,
procedures, and work packages, and correct labeling of components. Specifically, the
licensee did not provide sufficient details in procedures for operators to successfully align
an infrequently operated valve with no position indication. H.2(c) (Section 1R05.03.b)
- 3 -
Enclosure
Green. The team identified a non-cited violation of License Conditions 2.C(4) for Unit 1
and 2.C(5) for Unit 2, Fire Protection Program, due to the licensees failure to establish
or adequately implement compensatory measures for non-compliances with the
licensees approved fire protection program. These non-compliances were identified
during the licensees ongoing transition to a new fire protection program in compliance
with National Fire Protection Association Standard 805, Performance-Based Standard
for Fire Protection for Light Water Reactor Electric Generating Plants, (NFPA 805). The
licensee entered this issue in their corrective action program as Notifications 50521360
and 50531363.
The failure to establish or maintain appropriate compensatory measures for identified
deficiencies in the approved fire protection program was a performance deficiency. The
performance deficiency was more than minor because it was associated with the
protection against external events (fire) attribute of the Mitigating Systems Cornerstone
and it adversely affected the cornerstone objective of ensuring the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences. A senior reactor analyst evaluated the significance of this performance
deficiency.
A fire that results in the loss of switchgear room ventilation would cause a loss of all ac
and dc power if operators did not take action to recover cooling. The analyst determined
that the licensed operators would have at least two clear annunciators indicating that
ventilation had been lost and that room temperatures were increasing. Additionally,
Procedure CP-M10, Fire Protection of Safe Shutdown Equipment, was available to
assist in providing portable fan cooling to the rooms.
For a fire to result in an intersystem loss of coolant accident, it would have to cause
a 3-phase hot short on both of two shutdown cooling suction valves. Given that each
valve is on a different electrical train, the analyst determined that the conditional
probabilities of the hot shorts involved would best be modeled as independent.
Accounting for the risk associated with both issues evaluated, the analyst estimated the
change to core damage probability to be 1.5 x 10-7 per unit. Therefore, the performance
deficiency was considered to be of very low safety significance (Green).
This finding did not have a cross-cutting aspect because it was not indicative of the
licensees present performance. (Section 1R05.10.b)
B.
Licensee-Identified Violations
None.
- 4 -
Enclosure
REPORT DETAILS
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R05 Fire Protection (71111.05T)
This report presents the results of a triennial fire protection inspection conducted in
accordance with NRC Inspection Procedure 71111.05T, Fire Protection (Triennial), at
the Diablo Canyon Power Plant. The licensee committed to adopt a risk-informed fire
protection program in accordance with National Fire Protection Association
Standard 805 (NFPA 805) on June 24, 2011, as approved by NRC on July 28, 2011,
(ML112010657), but has not yet completed the program transition. The inspection team
evaluated the implementation of the approved fire protection program in selected
risk-significant areas, with an emphasis on the procedures, equipment, fire barriers, and
systems that ensure the post-fire capability to safely shutdown the plant.
Inspection Procedure 71111.05T requires the selection of three to five fire areas for
review. The inspection team used the fire hazards analysis section of the Diablo
Canyon Power Plants Fire-Induced Risk Model to select the following three
risk-significant fire areas in Unit 1 (inspection samples) for review:
Fire Area 3-BB, Containment Penetration Rooms (all elevations)
Fire Area 7A, Cable Spreading Room
Fire Area 5-A-4, 480V Nonvital Switchgear and Hot Shutdown Panel Area
The inspection team evaluated the licensees fire protection program using the
applicable requirements, which included plant Technical Specifications, Operating
License Condition 2.C.(5), NRC safety evaluations, 10 CFR 50.48, and Branch
Technical Position 9.5-1. The team also reviewed related documents that included the
Final Safety Analysis Report (FSAR), Section 9.5; the fire hazards analysis; and the
post-fire safe shutdown analysis.
Specific documents reviewed by the team are listed in the attachment. Three inspection
samples were completed.
.01
Protection of Safe Shutdown Capabilities
a. Inspection Scope
The team reviewed the piping and instrumentation diagrams, safe shutdown equipment
list, safe shutdown design basis documents, and the post-fire safe shutdown analysis to
verify that the licensee properly identified the components and systems necessary to
achieve and maintain safe shutdown conditions for fires in the selected fire areas. The
team observed walkdowns of the procedures used for achieving and maintaining safe
shutdown in the event of a fire to verify that the procedures properly implemented the
safe shutdown analysis provisions.
- 5 -
Enclosure
For each of the selected fire areas, the team reviewed the separation of redundant
safe shutdown cables, equipment, and components located within the same fire area.
The team also reviewed the licensees method for meeting the requirements
of 10 CFR 50.48; Branch Technical Position 9.5-1, Appendix A; and 10 CFR Part 50,
Appendix R,Section III.G. Specifically, the team evaluated whether at least one post-
fire safe shutdown success path remained free of fire damage in the event of a fire. In
addition, the team verified that the licensee met applicable license commitments.
b. Findings
No findings were identified.
.02
Passive Fire Protection
a. Inspection Scope
The team walked down accessible portions of the selected fire areas to observe the
material condition and configuration of the installed fire area boundaries (including walls,
fire doors, and fire dampers) and verify that the electrical raceway fire barriers were
appropriate for the fire hazards in the area. The team compared the installed
configurations to the approved construction details, supporting fire tests, and applicable
license commitments.
The team reviewed installation, repair, and qualification records for a sample of
penetration seals to ensure the fill material possessed an appropriate fire rating and that
the installation met the engineering design. The team also reviewed similar records for
the rated fire wraps to ensure the material possessed an appropriate fire rating and that
the installation met the engineering design.
b. Findings
No findings were identified.
.03
Active Fire Protection
a. Inspection Scope
The team reviewed the design, maintenance, testing, and operation of the fire detection
and suppression systems in the selected fire areas. The team verified the automatic
detection systems and the manual and automatic suppression systems were installed,
tested, and maintained in accordance with the National Fire Protection Association code
of record or approved deviations, and that each suppression system was appropriate for
the hazards in the selected fire areas.
The team performed a walkdown of accessible portions of the detection and suppression
systems in the selected fire areas. The team also performed a walkdown of major
system support equipment in other areas (e.g., fire pumps and carbon dioxide supply
systems) to assess the material condition of these systems and components.
- 6 -
Enclosure
The team reviewed the fire pumps flow and pressure tests to verify that the pumps met
their design requirements. The team also reviewed the carbon dioxide suppression
system functional tests to verify that the system capability met the design requirements.
The team assessed the fire brigade capabilities by reviewing training, qualification, and
drill critique records. The team also reviewed pre-fire plans and smoke removal plans
for the selected fire areas to determine if appropriate information was provided to fire
brigade members and plant operators to identify safe shutdown equipment and
instrumentation, and to facilitate suppression of a fire that could impact post-fire safe
shutdown capability. In addition, the team inspected fire brigade equipment to determine
operational readiness for fire fighting.
b. Findings
Introduction. The team evaluated a self-revealing finding due to the firewater yard loop
being inadvertently isolated for approximately three days. The team determined the
finding to be a Green non-cited violation of the licensees approved fire protection
program as defined in License Conditions 2.C(4) for Unit 1 and 2.C(5) for Unit 2.
Description. The firewater yard loop within the protected area is normally supplied by
the raw water storage reservoirs with the elevation difference maintaining the firewater
yard loop pressure. The firewater yard loop supplies firewater to both the power block
and the intake structure. The power block, including safety related areas, have a backup
supply from fire water storage tank 0-1 via two electric driven fire pumps which activate
on low system pressure. The fire hose stations and two fire sprinklers in the intake
structure are only supplied from the firewater yard loop.
The south firewater loop serving additional site facilities outside of the protected area
has two additional fire pumps with their own fire water storage tank. The south firewater
loop is normally isolated from the firewater yard loop but can be aligned to feed the
firewater yard loop. The licensees Equipment Control Guideline (ECG) 18.1, Fire
Suppression Systems/Fire Suppression Water Systems, Revision 9, requires that if the
raw water gravity feed water supply is inoperable, within 7 days either restore the supply
or align the south loop fire pumps and fire water storage tank to supply the firewater yard
loop.
On September 9, 2012, operators isolated the raw water storage reservoirs from the
firewater yard loop and south firewater loop for planned maintenance work. Operators
also aligned the south firewater loop to supply the firewater yard loop. On
September 12, 2012, operators restored the fire water supply from the raw water storage
reservoirs and isolated the south firewater loop from the firewater yard loop.
On September 15, 2012, operators attempted to add water from the raw water storage
reservoirs to fire water storage tank 0-2 in the south firewater loop system. Flow to the
tank stopped and the firewater yard loop lost pressure, initiating alarms on the fire
computer in the control room. Fire pump 0-2 started on low pressure to supply the fire
suppression systems in the power block from fire water storage tank 0-1 as designed.
Operators aligned the south firewater loop to supply the firewater yard loop and started
fire pump 0-3 to restore pressure in the firewater yard loop. Operators rechecked the
- 7 -
Enclosure
system valve alignment and reopened valve MU-0-268, which pressurized the firewater
yard loop from the raw water storage reservoir.
During the approximately three day period when valve MU-0-268 was inadvertently left
in the closed position, the following fire suppression systems were without a water
supply:
The automatic water spray deluge systems for the main transformers, auxiliary
transformers, and startup transformers for both units
All outdoor fire hydrants in the protected area
The hose stations and two sprinkler heads in the intake structure
Valve MU-0-268 is a buried 12-inch valve which is manually operated with a T handle.
This valve is infrequently operated and has no position indication. The operator
restoring the valve to the open position turned the T handle approximately 20 turns in
the open direction and felt an increase in resistance. The operator interpreted the
resistance as the valve reaching its fully opened position. The second operator verifying
the valve position turned the valve closed a few turns then reopened the valve until the
increased resistance was also felt. The licensees investigation identified that valve
MU-0-268 requires approximately 80 turns to fully open. From the fully closed position,
approximately 20 turns are required before the disc begins to pull out of its seat. The
increased resistance the operators encountered was due to the forces required to pull
the disc out of its seat and was not due to the valve being fully open.
Analysis. The failure to maintain the fire water system configuration as required in the
approved fire protection program was a performance deficiency. The performance
deficiency was more than minor because it was associated with the protection against
external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely
affected the cornerstone objective of ensuring the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. The
team evaluated this deficiency using Inspection Manual Chapter 0609, Appendix F, Fire
Protection Significance Determination Process. The performance deficiency affected
the fire protection defense-in depth strategies involving post-fire safe shutdown systems.
However, the Assumptions and Limitations section of Appendix F states, The SDP
approach is intended to support the assessment of known issues only in the context of
an individual fire area. A systematic plant-wide search and assessment effort is beyond
the intended scope of the fire protection SDP. Therefore, a senior reactor analyst
evaluated the significance of this performance deficiency.
The analyst evaluated this finding using the Standardized Plant Analysis Risk Model for
Diablo Canyon, Units 1 & 2, Revision 8.15. The analyst noted that the major fire loading
in the yard area resulted from the 12 large transformers. Using the generic fire ignition
frequency for outdoor transformers (4.2 x 10-3/year) from NRC Inspection Manual
Chapter 0609, Appendix F, Attachment 4, Fire Ignition Source Mapping Information:
Fire Frequency, Counting Instructions, Applicable Fire Severity Characteristics, and
Applicable Manual Fire Suppression Curves, the analyst calculated a fire ignition
frequency for all 12 transformers of 5.0 x 10-2/year. For a 3-day exposure period, the
analyst calculated a fire ignition probability of 4.1 x 10-4.
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Enclosure
The analyst made the bounding assumption that any transformer fire without
suppression would result in an unrecoverable loss of offsite power. Using the SPAR
model, the analyst quantified this conditional core damage probability as 2.8 x 10-4. A
bounding value was then calculated by multiplying the fire ignition frequency by the
conditional core damage probability. This resulted in a change of core damage
frequency of 1.2 x 10-7. Therefore, the subject finding was of very low safety significance
(Green).
This performance deficiency had a cross-cutting aspect in the area of resources
associated with providing complete, accurate and up-to-date design documentation,
procedures, and work packages, and correct labeling of components. Specifically, the
licensee did not provide sufficient details in procedures for operators to successfully
align an infrequently operated valve with no position indication. H.2(c)
Enforcement. License Conditions 2.C(4) for Unit 1 and 2.C(5) for Unit 2, Fire Protection
Program, require the licensee to implement and maintain in effect all provisions of the
approved Fire Protection Program as discussed in the Final Safety Analysis Report
Update; in PG&Es December 6, 1984, Appendix R Report; and in the NRC staffs Fire
Protection Evaluation in the Supplements to the Diablo Canyon Safety Evaluation Report
listed for each unit.
Updated Final Safety Analysis Report Appendix 9.5B, DCPP Regulatory Compliance
Summary, Table B-1, Comparison of DCPP to Appendix A of BTP APCSB 9.5-1,
Section C, Quality Assurance Program, Sub-Section 2, Instructions, Procedures, and
Drawings, states Inspections, tests, administrative controls, fire drills, and training that
govern the fire protection program should be prescribed by documented instructions,
procedures, or drawings and should be accomplished in accordance with these
documents. The DCPP Compliance to Commitment states, Procedures govern
inspections, tests, administrative controls, fire drills, and training relating to the FP
Program.
Contrary to the above, from September 12, 2012 to September 15, 2012, the licensee
failed to implement and maintain in effect the provisions of the approved fire protection
program. Specifically, the licensee failed to maintain the required configuration of the
fire water system. The performance deficiency was due to the licensees failure to
provide adequate information to operators concerning the operation of Valve MU-0-268
in Clearance 0C18 D-16-005. Because this finding is of very low safety significance and
has been entered into the corrective action program (Notification 50513006), this
violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the
NRC Enforcement Policy: NCV 05000275/2012008-01, 05000323/2012008-01; Failure
to Maintain Required Firewater System Configuration
.04
Protection From Damage From Fire Suppression Activities
a. Inspection Scope
The team performed plant walkdowns and document reviews to verify that redundant
trains of systems required for hot shutdown, which are located in the same fire area,
would not be subject to damage from fire suppression activities or from the rupture or
inadvertent operation of fire suppression systems. Specifically, the team verified that:
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Enclosure
A fire in one of the selected fire areas would not directly, through production of
smoke, heat, or hot gases, cause activation of suppression systems that could
potentially damage all redundant safe shutdown trains.
A fire in one of the selected fire areas or the inadvertent actuation or rupture of a
fire suppression system would not directly cause damage to all redundant trains
(e.g., sprinkler-caused flooding of other than the locally affected train).
Adequate drainage is provided in areas protected by water suppression systems.
b. Findings
No findings were identified.
.05
Alternative Shutdown Capability
a. Inspection Scope
Review of Methodology
The team reviewed the safe shutdown analysis, operating procedures, piping and
instrumentation drawings, electrical drawings, the Final Safety Analysis Report, and
other supporting documents to verify that hot and cold shutdown could be achieved and
maintained from outside the control room for fires that require evacuation of the control
room, with or without offsite power available.
Plant walkdowns were conducted to verify that the plant configuration was consistent
with the description contained in the safe shutdown and fire hazards analyses. The
team focused on ensuring the adequacy of systems selected for reactivity control,
reactor coolant makeup, reactor decay heat removal, process monitoring
instrumentation, and support systems functions.
The team also verified that the systems and components credited for shutdown would
remain free from fire damage. Finally, the team verified that the transfer of control from
the control room to the alternative shutdown location would not be affected by
fire-induced circuit faults (e.g., by the provision of separate fuses and power supplies for
alternative shutdown control circuits).
Review of Operational Implementation
The team verified that licensed and non-licensed operators received training on
alternative shutdown procedures. The team also verified that sufficient personnel to
perform a safe shutdown were trained and available onsite at all times, exclusive of
those assigned as fire brigade members.
The team performed a walkthrough of the post-fire safe shutdown procedure with
licensed and non-licensed operators to determine the adequacy of the procedure. The
team verified that the operators could be reasonably expected to perform specific
actions within the time required to maintain plant parameters within specified limits.
Time critical actions that were verified included restoring electrical power, establishing
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Enclosure
control at the remote shutdown and local shutdown panels, establishing reactor coolant
makeup, and establishing decay heat removal.
The team also reviewed the periodic testing of the alternative shutdown transfer
capability and instrumentation and control functions to verify that the tests were
adequate to demonstrate the functionality of the alternative shutdown capability.
b. Findings
.1 Introduction. The team identified a violation of Technical Specification 5.4.1.d for the
failure to implement and maintain adequate written procedures covering fire protection
program implementation. Specifically, the team identified five examples (with a total of
eight fire scenarios) where the licensee failed to maintain an alternative shutdown
procedure that ensured operators could safely shutdown the plant in the event of a
control room or cable spreading room fire. This violation has been screened and
determined to warrant enforcement discretion in accordance with the NRC Enforcement
Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues
(10 CFR 50.48), and Inspection Manual Chapter 0305.
Description. Operations personnel would use Procedure OP AP-8A, Control Room
Inaccessibility - Establishing Hot Standby, Revision 31, to shutdown the reactor at the
hot shutdown panel, dedicated shutdown panel, and other control stations outside of the
control room in the event a fire required evacuation of the control room. This alternative
shutdown procedure was developed based on the results of the safe shutdown and
thermal hydraulic analyses contained in the following calculations:
M-680, 10 CFR 50 Appendix R Safe Shutdown Equipment, Revision 18-01
M-928, 10 CFR 50 Appendix R Safe Shutdown Analysis, Revision 18-02
M-944, 10 CFR 50 Appendix R Alternate Shutdown Methodology - Time and
Manpower Study/Safe Shutdown System Considerations, Revision 7
STA-251, RETRAN Evaluation of Appendix R Scenarios with RSGs, Revision 0
The alternative shutdown procedure provided methods to maintain several post-fire safe
shutdown functions, including maintaining reactor coolant inventory, controlling decay
heat removal, and providing electrical power, from outside the control room. The
procedure directed operators to maintain reactor coolant inventory by isolating letdown
and maintaining the pressurizer level and pressure within prescribed limits using the
emergency core cooling system charging pumps. The procedure directed operators to
control decay heat removal by using the motor-driven auxiliary feedwater pumps to inject
water into the steam generators. The procedure directed operators to provide electrical
power by ensuring the emergency diesel generators started and energized the 4kV
and 480V busses.
The team performed a timed walkdown of the alternative shutdown procedure. Based
on the timed walkdown results, the team identified five examples (with a total of eight fire
scenarios) where the licensee failed to maintain an alternative shutdown procedure that
ensured operators could safely shutdown the plant in the event of a control room or
cable spreading room fire. These examples included scenarios where the licensee
failed to ensure charging pumps remained available to maintain reactor coolant
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Enclosure
inventory, steam generators remained available to remove decay heat, 480V equipment
remained available to shutdown the plant, and the pressurizer level remained within the
indicating region (both high and low). For each example, the licensee implemented
corrective actions to revise their procedures and establish compensatory fire patrols, as
appropriate.
Example 1: Potential Loss of the Emergency Core Cooling System Charging Pumps
The first example involved a control room or cable spreading room fire with the spurious
closure of one of the volume control tank outlet valves (LCV-112B or LCV-112C)
combined with a loss of offsite power. In this scenario, the expected plant response to
the loss of offsite power causes both emergency core cooling system charging pumps to
start, and the spurious closure of one of the volume control tank outlet valves results in
the loss of both pumps.
Westinghouse examined this scenario and provided an evaluation in Letter PGE-92-621,
Diablo Canyon Appendix R Charging Pump Evaluation, dated July 14, 1992. Their
evaluation stated that severe pump damage and failure could occur within
approximately 30 seconds after a loss of suction, but most likely would not occur for an
additional one or two minutes. Based on this evaluation, the team concluded that
operators need to stop all running charging pumps within 2.5 minutes of the loss of
suction for the charging pumps to maintain reactor coolant inventory.
The team determined that operators could mitigate this scenario by opening the refueling
water storage tank outlet valves or stopping the pumps prior to pump damage. The
alternative shutdown procedure provided steps for operators to transfer the suction for
the charging pumps from the volume control tank to the refueling water storage tank.
Based on the timed walkdown, the team determined that operators would begin opening
the refueling water storage tank outlet valves 5.5 minutes after the reactor trip and
complete this action within 3 minutes. Since this time exceeded 2.5 minutes, the team
concluded that the alternative shutdown procedure was inadequate to ensure that the
charging pumps remained available to maintain reactor coolant inventory under all
alternative shutdown fire scenarios.
The team noted that the licensee had a third charging pump which received power from
an emergency diesel generator, but would not automatically start on a loss of offsite
power. The team reviewed the alternative shutdown procedure and determined that the
procedure did not provide operators with instructions on using the third charging pump in
the event the other two pumps were damaged.
Example 2: Potential Overfilling of the Steam Generators
The second example involved a control room or cable spreading room fire where fire
damage prevents the feedwater isolation on a reactor trip and low Tavg signal, resulting in
the turbine-driven main feedwater pumps continuing to inject feedwater into the steam
generators and a loss of decay heat removal and overcooling.
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Enclosure
The licensee performed a preliminary analysis of this scenario and concluded that
operators had approximately 3 minutes to stop the main feedwater injection prior to
overfilling the steam generators.
The team determined that operators could mitigate this scenario by closing the main
feedwater isolation valves or the main steam isolation valves. The alternative shutdown
procedure provided steps for operators to close the main steam isolation valves from the
control room prior to evacuation; however, the team determined that the approved fire
protection program did not credit this action. The team noted that the alternative
shutdown procedure provided steps for operators to close the main steam isolation
valves outside the control room, but did not provide steps for operators to close the main
feedwater isolation valves. As noted in the next violation, (1R05.05.b.2), the safe
shutdown analysis determined that operator actions were required to isolate main
feedwater, but this requirement was not carried forward to the alternative shutdown
procedure.
Based on the timed walkdown, the team determined that operators would begin closing
the main steam isolation valves approximately 11 minutes after the reactor trip and
complete this action within 15 minutes. Since this time exceeded 3 minutes, the team
concluded that the alternative shutdown procedure was inadequate to ensure that the
steam generators remained available to remove decay heat under all alternative
shutdown fire scenarios.
Example 3: Potential Loss of 480V Safe Shutdown Equipment
The third example involved a control room or cable spreading room fire where fire
damage causes the 480V feeder breakers (52HF10, 52GH10, and 52HH10) to open,
resulting in a loss of the following 480V safe shutdown equipment:
E-103
Auxiliary Salt Water Pump 1-1 Room HVAC
ED11
Vital Battery Charger
PP0-2
Fuel Oil Transfer Pump 0-2
E-101
Auxiliary Salt Water Pump 1-2 Room HVAC
HTR1-2
Pressurizer Heater Group 1-2
ED12
Vital Battery Charger
LCV-85
Day Tank 1-1 Level
LCV-86
Day Tank 1-2 Level
LCV-87
Day Tank 1-3 Level
PP0-1
Fuel Oil Transfer Pump 0-1
HTR1-3
Pressurizer Heater Group 1-3
ED132
Vital Battery Charger
LCV-88
Day Tank 1-1 Level
LCV-89
Day Tank 1-2 Level
LCV-90
Day Tank 1-3 Level
The team determined that none of the affected equipment was required immediately,
and operators could mitigate this scenario by ensuring the breakers were closed after
placing the respective transfer switches to Local. The team reviewed the alternative
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Enclosure
shutdown procedure and determined that the procedure did not provide operators with
instructions on ensuring the 480V feeder breakers were closed. As noted in the next
violation, (1R05.05.b.2), the safe shutdown analysis determined that operator actions
were required to ensure the 480V feeder breakers were closed, but this requirement was
not carried forward to the alternative shutdown procedure.
Example 4: Potential Overfilling of the Pressurizer
The fourth example involved three fire scenarios that could result in overfilling the
pressurizer. Two of these scenarios could also result in voiding in the core due to rapid
depressurization of the reactor coolant system.
The first scenario involved a control room or cable spreading room fire with a spurious
safety injection signal. The second scenario involved a control room or cable spreading
room fire with the spurious actuation of a pressurizer power-operated relief valve,
resulting in a rapid depressurization of the reactor coolant system and subsequent safety
injection signal within approximately one minute. The third scenario involved a control
room or cable spreading room fire with the spurious opening of a pressurizer auxiliary
spray valve (8145 or 8148), resulting in a slightly slower depressurization of the reactor
coolant system and subsequent safety injection signal within a maximum of four minutes
(depending of the number of charging pumps running). In all three scenarios, the safety
injection signal results in the two emergency core cooling system charging pumps
starting and injecting water into the reactor coolant system through the charging injection
valves (8801A, 8801B, 8803A, and 8803B).
The licensee examined the spurious actuation of the safety injection system in the Final
Safety Analysis Report Section 15.2.15. The licensees analysis assumed the safety
injection signal occurred at 100 percent power, the emergency core cooling system
actuated, letdown isolated, and offsite power was lost. The licensee concluded that
operators had 8.5 minutes to control charging prior to the pressurizer reaching a water
solid condition.
The team determined this time limit was not conservative for all three scenarios. First,
the time limit was based on reaching a water solid condition in the pressurizer, not
maintaining the level within the indicating region, as required by the approved fire
protection program. Second, the analysis was based on an injection from the charging
pumps. In the second and third scenarios, the depressurization of the reactor coolant
system could lower the pressure quickly enough that the safety injection pumps would
also be able to inject water into the reactor coolant system, thereby reducing the amount
of time available prior to exceeding the indicating region of the pressurizer or reaching a
water solid condition in the pressurizer.
The team determined that operators could mitigate all three scenarios by controlling
charging at the hot shutdown panel. The alternative shutdown procedure provided steps
for operators to control charging and maintain the pressurizer level between 22 percent
and 70 percent, and it provided steps to stop the charging pumps if level could not be
maintained. Based on the timed walkdown, the team determined that operators would
reach this step nearly 30 minutes after the reactor trip. Since this time exceeded the
amount of time allowed for all three scenarios (even though this limit was not
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Enclosure
conservative), the team concluded that the alternative shutdown procedure was
inadequate to ensure the pressurizer level remained within the indicating region and the
pressurizer did not overfill under all alternative shutdown fire scenarios.
Example 5: Potential Draining of the Pressurizer
The fifth example involved two fire scenarios that could result in draining of the
pressurizer and the potential to develop a bubble outside of the pressurizer. The first
scenario involved a control room or cable spreading room fire with the spurious opening
of a 10 percent atmospheric dump valve.
The licensee examined this scenario in Calculation STA-251 and concluded that
operators had approximately 4.5 minutes to close the atmospheric dump valve prior to
the pressurizer reaching 0 percent indicated level. The team noted that this number was
not conservative since it assumed that the reactor coolant pumps remained running and
main feedwater was isolated shortly after the reactor trip, adding heat to the reactor
coolant system and lengthening the plant cooldown.
The team determined that operators could mitigate this scenario by closing the
atmospheric dump valves. The alternative shutdown procedure provided steps for
operators to close the atmospheric dump valves. Based on the timed walkdown, the
team determined that operators would begin closing the atmospheric dump valves
approximately 20 minutes after the reactor trip and complete this action within 15
additional minutes. Since this time exceeded 4.5 minutes, the team concluded that the
alternative shutdown procedure was inadequate to ensure that the pressurizer remained
within the indicating region and a bubble did not develop outside of the pressurizer under
all alternative shutdown fire scenarios.
The second scenario involved a control room or cable spreading room fire with the
spurious opening of a steam dump valve combined with a loss of offsite power.
The licensee examined this scenario in Calculation STA-251 and concluded that
operators had less than 24.5 minutes to close the main steam isolation valves prior to
the pressurizer reaching 0 percent indicated level.
The team determined that operators could mitigate this scenario by closing the main
steam isolation valves. The alternative shutdown procedure provided steps for
operators to close the main steam isolation valves. Based on the timed walkdown, the
team determined that operators would begin closing the main steam isolation valves
within 11 minutes and complete this action within 15 additional minutes. Since this time
exceeded 24.5 minutes, the team concluded that the alternative shutdown procedure
was inadequate to ensure that the pressurizer remained within the indicating region and
a bubble did not develop outside of the pressurizer under all alternative shutdown
scenarios.
Analysis. The failure to maintain adequate written procedures covering fire protection
program implementation was a performance deficiency. The performance deficiency
was more than minor because it was associated with the protection against external
events (fire) attribute of the Mitigating Systems cornerstone and it adversely affected the
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Enclosure
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences.
A senior reactor analyst performed a hand calculation to bound the risk significance of
this finding. The senior reactor analyst determined that the change in core damage
frequency was less than 1E-4, so the finding was not of high safety significance (Red).
Therefore, this finding qualified for enforcement discretion using Section 9.1 of the
Enforcement Policy, Enforcement Discretion for Certain Fire Protection Issues
This finding did not have a cross-cutting aspect because it qualified for enforcement
discretion.
Enforcement. Technical Specification 5.4.1.d states that written procedures shall be
established, implemented, and maintained covering fire protection program
implementation. Contrary to this requirement, prior to November 8, 2012, the licensee
failed to establish, implement, and maintain adequate written procedures covering fire
protection program implementation. Specifically, the team identified five examples
involving the potential loss of the emergency core cooling system charging pumps,
overfilling of the steam generators, loss of 480V safe shutdown equipment, overfilling of
the pressurizer, and draining of the pressurizer where the licensee failed to maintain an
alternative shutdown procedure that ensured operators could safely shutdown the plant
in the event of a control room or cable spreading room fire.
Because the licensee committed to adopting National Fire Protection Association
Standard 805, Performance-Based Standard for Fire Protection for Light Water Reactor
Electric Generating Plants, and committed to changing their fire protection program
license basis to comply with 10 CFR 50.48(c) by submitting a license amendment
request to the NRC, this violation was eligible for enforcement discretion as described in
Section 9.1 of the Enforcement Policy, Enforcement Discretion for Certain Fire
Protection Issues (10 CFR 50.48). Under this Enforcement Policy, the NRC will
normally not take enforcement action for a violation of 10 CFR 50.48(b) (or the
requirements in a fire protection license condition) involving a problem in an area such
as engineering, design, implementing procedures, or installation if the violation is
documented in an inspection report and meets all of the following criteria:
The licensee identified the violation as a result of a voluntary initiative to adopt
the risk-informed, performance-based fire protection program under
10 CFR 50.48(c), or, if the NRC identified the violation, the NRC found it likely
that the licensee would have identified the violation in light of the defined scope,
thoroughness, and schedule of its transition to 10 CFR 50.48(c).
The licensee corrected the violation or will correct the violation after completing
its transition to 10 CFR 50.48(c). Also, the licensee took immediate corrective
action or compensatory measures or both within a reasonable time
commensurate with the risk significance of the issue following identification; this
action should involve expanding the initiative, as necessary, to identify other
issues caused by similar root causes.
Routine licensee efforts, such as normal surveillance or quality assurance
activities, were not likely to have previously identified the violation.
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Enclosure
The violation was not willful.
The violation is not associated with a finding of high safety significance.
Specifically, the team determined that the licensee: (1) would have identified the
violation in light of the defined scope, thoroughness, and schedule of its transition
to 10 CFR 50.48(c) because the licensee was performing new analyses and developing
a new alternative shutdown procedure for the transition to NFPA-805; (2) the licensee
will correct the violation after completing its transition to 10 CFR 50.48(c) and took
immediate corrective action or compensatory measures or both within a reasonable time
commensurate with the risk significance of the issue following identification; (3) routine
licensee efforts (such as normal surveillance or quality assurance activities) were not
likely to have previously identified the violation; (4) the violation was not willful; and
(5) the team determined that this violation was not of high safety significance (Red).
The licensee entered these issues into their corrective action program as Notification
50522666 and implemented appropriate compensatory measures. Since all the criteria
for enforcement discretion were met, the NRC is exercising enforcement discretion for
this issue. (EA-13-021)
.2 Introduction. The team identified a violation of License Condition 2.C(5) for the failure to
implement and maintain in effect all provisions of the approved fire protection program.
Specifically, the team identified four examples where the licensee failed to maintain the
fire protection program design basis documents (e.g., fire hazards analysis, safe
shutdown analysis, and thermal hydraulic analysis) and the alternative shutdown
procedure to adequately implement the approved fire protection program. This violation
has been screened and determined to warrant enforcement discretion in accordance
with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire
Protection Issues (10 CFR 50.48), and Inspection Manual Chapter 0305.
Description. Operations personnel used Procedure OP AP-8A, Control Room
Inaccessibility - Establishing Hot Standby, Revision 31, to shutdown the reactor at the
hot shutdown panel, dedicated shutdown panel, and other control stations outside of the
control room in the event a fire required evacuation of the control room. This alternative
shutdown procedure was developed based on the results of the safe shutdown and
thermal hydraulic analyses contained in the following calculations:
M-680, 10 CFR 50 Appendix R Safe Shutdown Equipment, Revision 18-01
M-928, 10 CFR 50 Appendix R Safe Shutdown Analysis, Revision 18-02
M-944, 10 CFR 50 Appendix R Alternate Shutdown Methodology - Time and
Manpower Study/Safe Shutdown System Considerations, Revision 7
STA-251, RETRAN Evaluation of Appendix R Scenarios with RSGs, Revision 0
The team reviewed the alternative shutdown procedure, safe shutdown equipment list
(Calculation M-680), safe shutdown analysis (Calculation M-928), time and manpower
study (Calculation M-944), thermal hydraulic analysis (Calculation STA-251), and the fire
hazards analysis. During this review, the team identified four examples of errors and
inconsistencies between these documents. Some of these errors led to examples of the
inadequate alternative shutdown procedure described above in Section 1R05.05.b.1.
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Enclosure
Example 1: Errors Associated with the 10 percent Atmospheric Dump Valves
The first example involved a discrepancy between the safe shutdown analysis and the
time and manpower study. The safe shutdown analysis noted that a fire in the cable
spreading room could spuriously open the 10 percent atmospheric dump valves and
prevent operation from the hot shutdown panel. The time and manpower study,
however, stated that the spurious opening of a 10 percent atmospheric dump valve
would not occur due to a fire in the control room or cable spreading room. This study
also stated that this scenario was not a credible scenario. As a result, the licensee failed
to provide a time limit for operators to close the atmospheric dump valves.
The team disagreed with the licensees position that the scenario was not credible for an
alternative shutdown scenario. The team noted that supplemental guidance, specific for
alternative shutdown scenarios, was promulgated in Generic Letter 86-10,
Question 5.3.10. In this question, the staff noted that the safe shutdown capability
should not be adversely affected by any one spurious actuation or signal resulting from a
fire in any plant area. The team noted that the spurious opening of a 10 percent
atmospheric dump valve is considered a single spurious actuation and was required to
be considered.
Example 2: Errors Associated with the Alternative Shutdown Procedure
The second example involved a discrepancy between the safe shutdown analysis and
the alternative shutdown procedure. The safe shutdown analysis included requirements
for operators to close the 480V feeder breakers as well as isolate the main feedwater
system by closing the main feedwater isolation valves and their bypasses.
As discussed above in Section 1R05.05.b.1, the team determined that these actions
were not carried forward from the safe shutdown analysis into the alternative shutdown
procedure. Further, the team noted that the requirement to close the 480V feeder
breakers was described in the fire hazards analysis, but the licensee failed to carry
forward the requirement to isolate the main feedwater system from the safe shutdown
analysis to the fire hazards analysis.
Example 3: Errors Associated with Reactor Coolant Pump Seal Cooling
The third example involved a discrepancy between the fire hazards analysis, safe
shutdown equipment list, safe shutdown analysis, and the alternative shutdown
procedure. The fire hazards analysis stated that Valves 8384A and 8384B would be
used to isolate seal injection and component cooling water to the thermal barrier heat
exchanger. This requirement was reflected in the logic diagrams contained in the safe
shutdown equipment list. The team determined that the licensee modified the safe
shutdown analysis and the alternative shutdown procedure at some point to use
Valves 8382A and 8382B instead, but failed to update the fire hazards analysis and the
safe shutdown equipment list logic diagrams.
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Enclosure
Example 4: Errors Associated with the Thermal Hydraulic Analysis
The fourth example involved errors associated with the thermal hydraulic analysis. The
time and manpower study was used to determine the amount of time available for
operators to perform specific manual actions. This study provided a set of assumptions
to be used when calculating the time limits. These assumptions included the
consideration of any single spurious actuation, the potential loss of automatic function
(signals, logic, etc.), and the potential for a loss of offsite power. These assumptions
were consistent with the regulatory guidance.
The team determined that the thermal hydraulic analysis did not properly implement the
assumptions contained in the time and manpower study. Specifically, the team
determined that the licensees RETRAN calculations included assumptions that the
turbine tripped, main feedwater isolated, and letdown isolated.
The team noted that the incorrect assumptions in the thermal hydraulic analyses led to
errors in the safe shutdown analysis. First, the assumption that the turbine tripped
provided additional time for the operators to perform their actions and led to the turbine
trip not being included as a required manual action. This, in turn, led to a lack of
dedicated 8-hour emergency lighting for the operators to perform a manual turbine trip.
The results of the thermal hydraulic analysis indicated that the spurious opening of a
single steam dump valve coincident with a loss of offsite power would result in the
pressurizer reaching 0 percent indicated level within 24.5 minutes. However, the time
and manpower study stated that the spurious opening of a steam dump valve was not a
credible scenario. As a result, the licensee failed to provide a time limit for operators to
close the main steam isolation valves. Instead, the licensee assumed that operators
would perform this task within 30 minutes. The team disagreed with the licensees
position that the scenario was not credible for an alternative shutdown scenario as
discussed in Example 1 of this violation.
Analysis. The failure to maintain the fire protection program design basis documents
(e.g., fire hazards analysis, safe shutdown analysis, and thermal hydraulic analysis) and
the alternative shutdown procedure to adequately implement the approved fire protection
program was a performance deficiency. The performance deficiency was more than
minor because it was associated with the protection against external events (fire)
attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone
objective of ensuring the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences.
A senior reactor analyst performed a hand calculation to bound the risk significance of
this finding. The senior reactor analyst determined that the change in core damage
frequency was less than 1E-4, so the finding was not of high safety significance (Red).
Therefore, this finding qualified for enforcement discretion using Section 9.1 of the
Enforcement Policy, Enforcement Discretion for Certain Fire Protection Issues
This finding did not have a cross-cutting aspect because it qualified for enforcement
discretion.
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Enclosure
Enforcement. License Condition 2.C.(5) requires, in part, that the licensee shall
implement and maintain in effect all provisions of the approved fire protection program
as discussed in the Final Safety Analysis Report Update and the staffs fire protection
evaluation contained in Supplements 8, 9, 13, 23, and 27 of the Safety Evaluation
Report. Supplement 13 of the Safety Evaluation Report stated that the licensee met the
requirements of 10 CFR Part 50, Appendix R, Sections III.G, III.J, and III.O. Since the
licensee was required to meet the requirements of 10 CFR Part 50, Appendix R,
Section III.G, they were also required to meet the requirements of 10 CFR Part 50,
Appendix R,Section III.L.
The licensee demonstrated compliance with Sections III.G and III.L of 10 CFR Part 50,
Appendix R through the fire hazards analysis and Calculations M-680, M-928, M-944,
and STA-251. The results of these calculations were used to develop the alternative
shutdown procedure, OP AP-8A, Control Room Inaccessibility - Establishing Hot
Standby, Revision 31. Contrary to the above, prior to November 8, 2012, the licensee
failed to implement and maintain in effect all provisions of the approved fire protection
program. Specifically, the licensee failed to maintain the fire hazards analysis and
Calculations M-680, M-928, M-944, and STA-251 such that the licensee met the
requirements of 10 CFR Part 50, Appendix R, Sections III.G and III.L.
The licensee entered these issues into their corrective action program as Notification
50522745 and implemented appropriate compensatory measures. Because the
licensee committed to adopting National Fire Protection Association Standard 805, the
team evaluated this issue using the process described above in Section 1R05.05.b.1.
Since all the criteria for enforcement discretion were met, the NRC is exercising
enforcement discretion for this issue. (EA-13-021)
.06
Circuit Analysis
a. Inspection Scope
The team reviewed the post-fire safe shutdown analysis to verify that the licensee
identified the circuits that may impact the ability to achieve and maintain safe shutdown.
The team verified, on a sample basis, that the licensee properly identified the cables for
equipment required to achieve and maintain hot shutdown conditions in the event of a
fire in the selected fire areas. The team verified that these cables were either
adequately protected from the potentially adverse effects of fire damage or were
analyzed to show that fire induced circuit faults (e.g., hot shorts, open circuits, and
shorts to ground) would not prevent safe shutdown. The team reviewed the circuits
associated with the following components:
RP086, RP086A and 456
Pressurizer Power-Operated Relief Valves
RP093, RP093A and 474
Pressurizer Power-Operated Relief Valves
RP100, RP100A and 455C
Pressurizer Power Operated Relief Valves
F40P00 and 8000A
Pressurizer Power-Operated Relief Block Valves
G46P00 and 8000B
Pressurizer Power Operated Relief Block Valves
H33P00 and 8000C
Pressurizer Power Operated Relief Block Valves
G44P00 and G68P00
Auxiliary Feedwater Pumps Motor Operated Valves
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Enclosure
G69P00 and G70P00
Auxiliary Feedwater Pumps Motor Operated Valves
For this sample, the team reviewed electrical elementary and block diagrams and
identified power, control, and instrument cables necessary to support their operation. In
addition, the team reviewed cable routing information to verify that fire protection
features were in place as needed to satisfy the separation requirements specified in the
fire protection license basis. The team also reviewed circuit coordination studies for the
safety-related 4160 volt emergency bus.
b. Findings
No findings were identified.
.07
Communications
a. Inspection Scope
The team inspected the contents of designated emergency storage lockers and
reviewed the alternative shutdown procedure to verify that portable radio
communications and fixed emergency communications systems were available,
operable, and adequate for the performance of designated activities. The team verified
the capability of the communication systems to support the operators in the conduct and
coordination of their required actions. The team also verified that the design and
location of communications equipment such as repeaters and transmitters would not
cause a loss of communications during a fire. The team discussed system design,
testing, and maintenance, and conducted a communication system visual inspection with
the system engineer.
b. Findings
No findings were identified.
.08
a. Inspection Scope
The team reviewed the portion of the emergency lighting system required for alternative
shutdown to verify that it was adequate to support the performance of manual actions
required to achieve and maintain hot shutdown conditions, and to illuminate access and
egress routes to the areas where manual actions would be required. The team
evaluated the locations and positioning of the emergency lights during an in-plant
walkthrough of the alternative shutdown procedure.
The licensee received NRC approval in Supplement 23 to the Safety Evaluation Report
to credit use of the emergency AC and emergency DC lighting systems, in conjunction
with the 8-hour self-contained battery light units described in Appendix R, section III.J.
The team verified that the licensee installed emergency lights with an 8-hour capacity, or
had credited appropriate emergency AC or emergency DC powered lights to meet the
requirements of Appendix R, section III.J. The team verified that the licensee
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Enclosure
maintained the emergency light batteries in accordance with industry standards, and
tested and performed maintenance in accordance with plant procedures and industry
practices. The team verified through a sample of maintenance records that emergency
AC lights, emergency DC lights, and battery operated lights were repaired within a 7 day
self-imposed commitment. The team verified through in-plant inspections and
engineering calculation reviews that required access and egress routes, and manual
actions of safe shutdown components were properly illuminated with emergency lighting
fixtures.
b. Findings
No findings were identified.
.09
Cold Shutdown Repairs
a. Inspection Scope
The team verified that the licensee identified repairs needed to reach and maintain cold
shutdown and had dedicated repair procedures, equipment, and materials to accomplish
these repairs. Using these procedures, the team evaluated whether these components
could be repaired in time to bring the plant to cold shutdown within the time frames
specified in their design and licensing bases. The team verified that the repair
equipment, components, tools, and materials needed for the repairs were available and
accessible on site.
b. Findings
No findings were identified.
.10
Compensatory Measures
a. Inspection Scope
The team verified that compensatory measures were implemented for out-of-service,
degraded, or inoperable fire protection and post-fire safe shutdown equipment, systems,
or features (e.g., detection and suppression systems and equipment; passive fire
barriers; or pumps, valves, or electrical devices providing safe shutdown functions). The
team also verified that the short-term compensatory measures compensated for the
degraded function or feature until appropriate corrective action could be taken and that
the licensee was effective in returning the equipment to service in a reasonable period of
time.
b. Findings
Introduction. The team identified a Green non-cited violation of License
Conditions 2.C(4) for Unit 1 and 2.C(5) for Unit 2, Fire Protection Program, due to the
licensees failure to establish or adequately implement compensatory measures for non-
compliances with the licensees approved fire protection program. These non-
compliances were identified during the licensees ongoing transition to a new fire
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Enclosure
protection program in compliance with National Fire Protection Association
Standard 805, Performance-Based Standard for Fire Protection for Light Water Reactor
Electric Generating Plants, (NFPA 805).
Description. The licensee is transitioning to a new fire protection program in compliance
with NFPA 805 as allowed by 10 CFR 50.48(c). Corrective actions for non-compliances
with the licensees current approved fire protection program identified during the
licensees transition process may be deferred until implementation of the new NFPA 805
fire protection program. To ensure that adequate safety is maintained, the licensee must
establish compensatory measures within a reasonable time commensurate with the risk
significance of the issue following identification. Appropriate compensatory measures
could be those specified in the plants Equipment Control Guidelines for fire protection or
alternate compensatory measures developed for the specific issue.
The team requested the licensee provide a list of non-compliances identified during the
ongoing transition process and the compensatory measures established. Issues were
identified where compensatory measures either had not been established or the
implementation of the compensatory measures was inadequate. The licensee reported
the current unanalyzed condition to the NRC in an event notification (Event
Number 48395). The non-compliances identified by the NFPA transition process
included errors in the post-fire safe shutdown analysis and inadequate implementing
procedures including operator guidance on dealing with the potential effects of fire
damage and multiple spurious operations scenarios not addressed in the approved fire
protection program. Should a fire have occurred in an area with missing or inadequate
compensatory measures, operators might not have had adequate procedural guidance
to deal with the effects of fire damage and their ability to achieve safe shutdown could
have been challenged.
In September 2008, the NFPA 805 transition project identified four fire areas in Unit 1
and five fire areas in Unit 2 where circuits for redundant HVAC fans for electrical rooms
could be damaged. No compensatory measures were established. This issue was
identified during the licensees preparation for the current inspection and hourly fire
patrol was established as a compensatory measure in accordance with Equipment
Control Guideline 18.7 on October 8, 2012. The licensees current fire protection
program identified the potential loss of normal ventilation to these rooms for other fire
locations and has both procedures and equipment available to use portable fans to
provide cooling to assure the continued operation of the required electrical equipment.
In January 2008, the NFPA 805 transition project identified two fire areas in each unit
containing both power cables to motor-operated valves 8701 and 8702 for the respective
unit. Valves 8701 and 8702 are in series in the piping between the reactor coolant
system and the residual heat removal system. During normal operation, these valves
isolate the low pressure piping from the coolant system, operating at high pressure.
Since these are high/low pressure interface valves the potential for 3-phase hot shorts
causing spurious operation of the valves must be considered in the fire safe shutdown
analysis. Administrative controls maintain the breakers for each valve open during
normal operation which prevents the possibility of fire damage to control circuits causing
a valve to spuriously open. An open breaker does not address potential spurious
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Enclosure
operation due to a 3-phase hot short on a power cable between the breaker and the
valve motor.
Analysis. The failure to establish or maintain appropriate compensatory measures for
identified deficiencies in the approved fire protection program was a performance
deficiency. The performance deficiency was more than minor because it was associated
with the protection against external events (fire) attribute of the Mitigating Systems
Cornerstone and it adversely affected the cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. The performance deficiency affected the fire
protection defense-in depth strategies involving post-fire safe shutdown systems. The
team evaluated this deficiency using Inspection Manual Chapter 0609, Appendix F, Fire
Protection Significance Determination Process. However, the Assumptions and
Limitations section of Appendix F states, The SDP approach is intended to support the
assessment of known issues only in the context of an individual fire area. A systematic
plant-wide search and assessment effort is beyond the intended scope of the fire
protection SDP. Therefore, a senior reactor analyst evaluated the significance of this
performance deficiency.
Failure to Compensate for Ventilation System Failure
A fire in Fire Areas 3BB-100, 3BB-115, 5A1, 5A3, 3CC-100, 3CC-115, 5B1, 5B3,
and 6B5 containing cables associated with the redundant 480 V switchgear, dc panels,
and battery chargers could result in loss of ventilation systems for the affected rooms
which could require non-proceduralized use of portable fans to maintain adequate
cooling of the electrical equipment necessary to perform the Appendix R safe shutdown
function.
A fire that results in the loss of switchgear room ventilation would cause a loss of all ac
and dc power if operators did not take action to recover cooling. The analyst determined
that the licensed operators would have at least two clear annunciators indicating that
ventilation had been lost and that room temperatures were increasing. Additionally,
Procedure CP-M10, Fire Protection of Safe Shutdown Equipment, was available to
assist in providing portable fan cooling to the rooms. Using the SPAR-H method, the
analyst approximated the failure of operators to provide portable cooling to the ac
switchgear and dc equipment as 6.0 x 10-3. This approximation compares well with the
licensees human error probability of 3.2 x 10-3.
The analyst determined that the fire ignition frequency for all affected areas in Unit 1 (the
higher of the two units) was 5.9 x 10-3/year. Additionally, the analyst applied a hot short
probability of 0.015 for all areas to account for the requirement that the fire cause the
failure of 2 trains. The total bounding risk was then calculated to be 1.0 x 10-7/year
without compensation.
Failure to Administratively Control High/Low Pressure Interface Valves
The licensee determined that a high consequence interfacing system loss of coolant
accident could occur from the spurious opening of residual heat removal system hot leg
suction valves 8701 and 8702.
- 24 -
Enclosure
For a fire to result in an intersystem loss of coolant accident, it would have to cause
a 3-phase hot short on both of two shutdown cooling suction valves. Given that each
valve is on a different electrical train, the analyst determined that the conditional
probabilities of the hot shorts involved would best be modeled as independent. Using
the methods in NUREG 6850, the licensee calculated conditional probabilities for
a 3-phase proper-polarity hot short on ungrounded ac systems using thermoplastic
cables. The bounding high value was 2.25 x 10-4 per occurrence. Therefore, the
conditional probability of two independent hot shorts causing both valves to open would
be 5.1 x 10-8.
Evaluating the core damage probability would likely be much lower because this
probability would be multiplied by the frequency of the fire scenarios and the conditional
core damage probability of the event.
Summary
Accounting for the risk associated with all issues evaluated, the analyst estimated the
change in core damage frequency to be 1.5 x 10-7 per unit. Therefore, the performance
deficiency was considered to be of very low safety significance (Green).
This finding did not have a cross-cutting aspect because it is not indicative of the
licensees present performance.
Enforcement. License Conditions 2.C(4) for Unit 1 and 2.C(5) for Unit 2, Fire Protection
Program, require the licensee to implement and maintain in effect all provisions of the
approved Fire Protection Program as discussed in the Final Safety Analysis Report
Update; in PG&Es December 6, 1984, Appendix R Report; and in the NRC staffs Fire
Protection Evaluation in the Supplements to the Diablo Canyon Safety Evaluation Report
listed for each unit.
Updated Final Safety Analysis Report Appendix 9.5B, DCPP Regulatory Compliance
Summary, Table B-1, Comparison of DCPP to Appendix A of BTP APCSB 9.5-1,
Section C, Quality Assurance Program, Sub-Section 8, Corrective Action, states:
Measures should be established to assure that conditions adverse to fire
protection, such as failures, malfunctions, deficiencies, deviations, defective
components, uncontrolled combustible material, and nonconformance are
promptly identified, reported, and corrected.
The DCPP Compliance to Commitment states, Policies governing corrective measures
relative to fire protection failures, malfunctions, deficiencies, deviations, defective
components, uncontrolled combustible material, and nonconformances are addressed in
administrative procedures.
Contrary to the above, from 2008 through November 8, 2012, the licensee failed to
implement and maintain in effect all provisions of the approved fire protection program.
Specifically, the licensee failed to establish and maintain timely and adequate
compensatory measures for deficiencies identified in the current fire protection program.
- 25 -
Enclosure
Because this finding is of very low safety significance and has been entered into the
corrective action program (Notifications 50521360 and 50521363), this violation is being
treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement
Policy: NCV 05000275/2012008-02, 05000323/2012008-02; Inadequate Compensatory
Measures for Fire Protection Program Deficiencies.
.11
B.5.b Inspection Activities
a. Inspection Scope
The team reviewed the licensees implementation of guidance and strategies intended to
maintain or restore core, containment, and spent fuel pool cooling capabilities under the
circumstances associated with loss of large areas of the plant due to explosions or fire
as required by Section B.5.b of the Interim Compensatory Measures Order, EA-02-026,
dated February 25, 2002 and 10 CFR 50.54(hh)(2).
The team reviewed licensees strategies to verify that they continued to maintain and
implement procedures, maintain and test equipment necessary to properly implement
the strategies, and ensure station personnel are knowledgeable and capable of
implementing the procedures. The team performed a visual inspection of portable
equipment used to implement the strategy to ensure the availability and material
readiness of the equipment, including the adequacy of the fire engines used to
implement the strategies. The team also verified the availability of on-site fuel trucks
required to refuel the fire engine. The team performed a sample inspection of the B.5.b
equipment storage locker and visually inspected a penetration used to implement the
mitigation strategy. The strategy and procedure selected for this inspection sample was
Containment Flooding with Portable Pump; EDMG EDG-10, Containment Flooding with
Portable Pump, Revision 0.
b. Findings
No findings were identified.
4.
OTHER ACTIVITIES [OA]
4OA2 Identification and Resolution of Problems
Corrective Actions for Fire Protection Deficiencies
a. Inspection Scope
The team selected a sample of notifications associated with the licensee's fire protection
program to verify that the licensee had an appropriate threshold for identifying
deficiencies. In addition the team reviewed the corrective actions proposed and
implemented to verify that they were effective in correcting identified deficiencies. The
team also evaluated the quality of recent engineering evaluations through a review of
notifications, calculations, and other documents during the inspection.
- 26 -
Enclosure
b. Findings
An example of a problem with establishing and maintaining timely and adequate
compensatory measures for deficiencies identified in the current fire protection program
through the corrective action program is discussed in Section 1R05.10(b).
4OA6 Meetings, Including Exit
Exit Meeting Summary
The team presented the inspection results to Mr. E. Halpin, Senior Vice President and
Chief Nuclear Officer, and other members of the licensee staff at an debrief meeting
on November 8, 2012. The licensee acknowledged the findings presented.
Following additional in-office review and determination of the safety significance of the
findings, an exit meeting was conducted on December 20, 2012, with Mr. E. Halpin,
Senior Vice President and Chief Nuclear Officer, and other members of the licensee
staff.
The team asked the licensee whether any of the material examined during the inspection
should be considered proprietary. No proprietary information was identified.
4OA7 Licensee-Identified Violations
None.
ATTACHMENT: SUPPLEMENTAL INFORMATION
- 1 -
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
B. Allan, Site Vice President
A. Arsene, Engineer, Fire Protection
S. Baker, Manager, Design Engineering
T. Baldwin, Manager, Regulatory Services
R. Baradaran, Supervisor, Probabilistic Risk Assessment
A. Bates, Director, Engineering Services
P. Bemis, Strategic Projects
A. Chitwood, Operations Shift Manager
J. Cook, Engineer, Electrical Design
K. Cormany, Engineer, ICE
T. Cuddy, Senior Manager, Communications
F. DePeralta, Consultant
R. Dyer, Engineer, Project Engineering
S. Ellis, Fire Training Coordinator
J. Fields, Auditor, Quality Verification
J. Fledderman, Director, Strategic Projects
L. Fusco, Engineer, NFPA 805
P. Gerfen, Manager, Operations
W.Giffrow, Supervisor, Operations Services
J. Gregerson, Technical Manager, NFPA 805
E. Halpin, Senior Vice President and Chief Nuclear Officer
D. Hampshire, Supervisor, Fire Protection Engineering
C. Harbor, Director, Compliance and Risk
C. Harrison, Engineer
B. Hinds, Manager, Operations Planning
J. Hinds, Director, Quality Verification
K. Hiwrichsen, Programs Supervisor, Radiological Protection
L. Hopsm, Assistant Director, Maintenance Services
T. Jaurez, Engineer, Balance of Plant Systems
K. Johnston, Manager, Operations Performance
R. Justice, Fire Chief
T. King, Director, Work Management
S. Kirvsen, Manager, Security
W. Landreth, Engineer, Regulatory Services
G. Lautt, Supervisor, Quality Verification
R. Leatham, Electrical Engineer
J. MacIntyre, Director, Maintenance Services
M. McCoy, Engineer, Regulatory Services
C. Murry, Director, Safety
J. Nimick, Director, Operations Services
L. Padovan, Supervisor, Regulatory Services
T. Poindexter, Consultant
- 2 -
Attachment
M. Richardson, Senior Engineer, Regulatory Services
S. Queen, Engineer, Electrical Design Engineering
L. Radle, Engineer, Contractor
J. Schmidf, Auditor, Quality Verification
M. Sheppard, Engineer, Probabilistic Risk Assessment
P.Soenen, Supervisor, Regulatory Services
T. Stanton, Engineer, NFPA 805
M. Stephens, Auditor, Quality Verification
J. Summy, Senior Director, Engineering and Technical Services
L. Walter, Station Director
J. Welsch, Senior Station Director
D. Wilcox, Licensing Basis Verification Project
M. Winsor, Manager, Project Engineering
B. Wong, Contractor
M. Wright, Manager, Mechanical Systems
T. Wright, Auditor, Quality Verification
NRC personnel
L. Micewski, Resident Inspector
L. Willoughby, Senior Project Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
None
Opened and Closed 05000275/2012008-01
Failure to Maintain Required Firewater System
Configuration (Section 1R05.03.b)05000275/2012008-02
Inadequate Compensatory Measures for Fire
Protection Program Deficiencies (Section 1R05.10.b)
Closed
None
- 3 -
Attachment
LIST OF DOCUMENTS REVIEWED
CABLE ROUTING DATA
Component
Component
Component
Component
Component
RP086A
RP093A
RP100A
F40P00
G46P00
H33P00
ABAN025
H23P00A
H37P00A
H65P01
G44P00
G68P00
G69P00
G70P00
RP086
RP093
RP100
PCV45
PCV455C
PCV474
PORV 8000A
PORV 8000B
PORV 8000C
CALCULATIONS
Number
Title
Revision
M-680
High/Low Pressure Interface Component
14
M-680
10 CFR 50 Appendix R Safe Shutdown Equipment
17
M-680
10 CFR 50 Appendix R Safe Shutdown Equipment
18-01
M-912
HVAC Interactions for Safe Shutdown, Room Heat-up
Due to Loss of HVAC
5
M-928
10 CFR 50 Appendix R Safe Shutdown Analysis
17
M-928
10 CFR 50 Appendix R Safe Shutdown Analysis
18-01
M-928
10 CFR 50 Appendix R Safe Shutdown Analysis
18-02
M-944
10 CFR 50 Appendix R Alternate Shutdown
Methodology - Time and Manpower Study/Safe
Shutdown System Considerations
7
M-997, Appendix
2.16
Qualification of Penetration Seal Typical F-1L, A Three
A Hour Rated Six Inch Silicone Foam Seal
10
M-997, Appendix
2.25
Qualification of Penetration Seal Typical FP-5, A Three
A Hour Rated Low Density Silicone Elastomer (LDSE)
Seal
12
M-997, Appendix 2.3
Qualification of Penetration Seal Typical F-3, A Three A
Hour Rated Silicone Foam Sea Without Permanent
Ceramic Damming
10
N-089
Fire Protection Study for Pressurizer PORV Stuck
Open
July 29,
1993
STA-207
RETRAN Evaluation of Appendix R Operator Action
Times
1
STA-251
RETRAN Evaluation of Appendix R Scenarios with
0
- 4 -
Attachment
134-DC
Circuit Analysis-Electrical Appendix R Analysis
26
335-DC
Emergency Lighting and Communications
8
CONDITION REPORTS
A0642680
A0646729
A0724491
A0627424
A0635344
A0620761
A0646729
50035114
50408579
50409764
500032962
50513006
50514313
50512140
50512128
50511911
50511896
50511882
50511736
50511729
50510511
5059635
50509560
50507834
50507529
50506331
5050594
50358360
50350593
50340288
50340108
50513995
50474308
50286358
50038548
50515422
50515872
505209828*
502022298*
50521043*
50520533*
50520532*
50520531*
50520530*
50520521*
50520512*
50520493*
50520487*
50520485*
50520371*
50520370*
50520333*
50520332*
50520331*
50520330*
50520299*
50520283*
50520282*
50520149*
50520513*
50520144*
50520096*
50520095*
50520092*
50519958*
50519957*
50519857*
50516460*
50516347*
50507988*
50507455*
50507350*
50507230*
50503976*
50520148*
50518956*
50519957*
50519958*
50520092*
50520144*
50520148*
50520299*
50520330*
50520331*
50520332*
50520333*
50520929*
50520962*
50521394*
50522131*
50522141*
50522145*
50522149*
50522161*
50518721*
50520530*
50520531*
50520532*
50520533*
50521470*
50521471*
50520341*
50522103*
50520531*
50520980*
50520202*
50522666*
50522072*
50522445*
50522478*
50522191*
50522479*
50522273*
50522745*
50521601*
- Issued as a result of inspection activities.
- 5 -
Attachment
DRAWINGS
Number
Title
Revision
437507, Sheet 1
Schematic Diagram Auxiliary Feed water Motor
Operated Valves
24
437811, Sheet 1
Schematic Diagram of Connections 480 Volt Motor
Control Center IH Units 1R, 2R, & 3R
23
437798
Schematic Diagram of Connections 480 Volt Motor
Control Center IF Units 1R, 2R, & 3R
21
437543, Sheet 1
Single line meter and relay Diagram 480 Volt System
Bus Section H
49
437916, Sheet 1
Single line meter and relay Diagram 480 Volt System
Bus Section 1F
46
437587
Electrical Schematic diagram Reactor Coolant Motor
Operated Valves
20
437916, Sheet 1
Electrical Single line meter and relay Diagram 480 Volt
System Bus Section 1F
46
437542, Sheet 1
Electrical Single line meter and relay Diagram 480 Volt
System Bus Section 1G
53
437895, Sheet 1
Electrical Single line Diagram Main Control Board 1VB1
and 1BV2 Fuse Panel
49
437519, Sheet 1
Electrical Single line Diagram 12/4.16KV system
24
437526
Electrical System Phasing Diagram
13
437529, Sheet 1
Electrical Single line Meter & Relay Diagram
Generation Excitation Main and Auxiliary Transformers
41
437533, Sheet 1
Electrical Single line Diagram Single line meter & Relay
Diagram 4160 Volt System
40
437531, Sheet 1
Single line Meter & Relay Diagram 12KV System
27
437532, Sheet 1
Single line Meter & Relay Diagram 4160 Volt System
28
050003, Sheet 1
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
7
050003, Sheet 2
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
050003, Sheet 3
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
050003, Sheet 4
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
050003, Sheet 5
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
- 6 -
Attachment
050003, Sheet 6
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
050003, Sheet 7
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
050003, Sheet 8
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
050003, Sheet 9
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
6
050003, Sheet 10
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
7
050003, Sheet 11
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
7
050003, Sheet 12
Description of Electrical Schematic Diagrams, Symbol,
Circuit designations and Related Notes for Diagram of
Connections
7
102001
Instrument Schematic Legend Systems
18
102030, Sheet 3
Instrument Schematic Legend Systems
21
102030, Sh 3A
Instrument Schematic Legend Systems
29
102030, Sheet 3B
Instrument Schematic Legend Systems
16
102030, Sheet 4
Instrument Schematic Legend Systems
26
102030, Sheet 5
Instrument Schematic Legend Systems
26
445650
Separation & Color Code Instrument & Control
Engineered Safety Features
7
445651
Separation & Color Code Instrument & Control
Engineered Safety Features
10
102008, Sheet 4
Chemical & Volume Control System
114
102008, Sheet 4D
Chemical & Volume Control System
128
102931, Sheet 6B
Radiation Instrument System
72
102036, Sheet 7F
Multivariable Instrument Systems
107
109807, Sheet 31
Functional Loop Diagram
19
109807, Sheet 72
Functional Loop Diagram
20
109807, Sheet 85
Functional Loop Diagram
9
- 7 -
Attachment
109807, Sheet 92
Functional Loop Diagram
19
109807, Sheet 4a
Functional Loop Diagram
2
109807, Sheet 23
Functional Loop Diagram
25
109807, Sheet 5a
Functional Loop Diagram
1
109807, Sheet 21
Functional Loop Diagram
25
109807, Sheet 71
Functional Loop Diagram
19
109807, Sheet 73
Functional Loop Diagram
21
109807, Sheet 74
Functional Loop Diagram
13
109807, Sheet 75
Functional Loop Diagram
19
109807, Sheet 89
Functional Loop Diagram
19
102008, Sheet 4
Chemical Volume Control System
114
102008, Sheet 4D
Chemical Volume Control System
128
109808, Sheet 3
Functional Loop Diagram
2
102032, Sheet 26
Flow Instrument Systems
152
102032, Sheet 26J
Flow Instrument Systems
112
102036, Sheet 7
Multivariable Instrument Systems
98
102036, Sheet 7B
Multivariable Instrument Systems
98
102036, Sheet 7H
Multivariable Instrument Systems
98
102036, Sheet 7I
Multivariable Instrument Systems
98
102034, Sheet 7C
Multivariable Instrument Systems
2
102035, Sheet 6F
Multivariable Instrument Systems
94
102034, Sheet 7D
Multivariable Instrument Systems
1
102035, Sheet 6E
Multivariable Instrument Systems
94
102036, Sheet 7A
Multivariable Instrument Systems
98
102036, Sheet 7B
Multivariable Instrument Systems
98
437579, Sheet 1
Electrical Schematic diagram 4KV Diesel Generator
Control No. 11 & 12
42
437580, Sheet 1
Electrical Schematic diagram 4KV Diesel Generator
Control No. 11 & 12 Valves
39
- 8 -
Attachment
437587
Electrical Schematic Diagram Reactor Coolant Motor
Operated Valves
20
437683, Sheet 1
Electrical Schematic Diagram Chemical & Volume
Control System
23
437682, Sheet 1
Electrical Schematic Diagram Chemical & Volume
Control System
23
441312, Sheet 1
Schematic Diagram, Charging Pumps No 21 & 22
26
050016, Sheet 1
Raceway and Wire Color separation Charts
7
050016, Sheet 2
Raceway and Wire Color separation Charts
7
050016, Sheet 3
Raceway and Wire Color separation Charts
7
437533, Sheet 1
Single Line Diagram Single line meter and Relay
Diagram 4160 Volt System
40
437738, Sheet 1
Electrical Wiring Diagram 4160 Volt Switchgear Bus
Sect. G Cell 5 to 9
8
448580
Electrical Diagram of Connections 4160 Volt Switchgear
Bus Sect. G Cell 6
15
437594, Sheet 1
Electrical Schematic diagram Auxiliary Salt Water Pump
30
57601
Cable Tray & Conduit Layout Below elevation 115-0
Area H
46
57606
Cable Tray & Conduit Layout Section E-E and F - F
Area H
32
437595, Sheet 1
Electrical Schematic diagram Charging Pumps No 11 &
12
33
437513
Diagram of Connection, Hot Shutdown Control Panel
24
437667, Sheet 1
Electrical Schematic Diagram 4KV Diesel Generator
Control No. 13,
45
4007993, Sheet 1
Diagram of Connections Diesel Generator 11 DC
Control Power Transfer switch
2
4007994, Sheet 1
Diagram of Connections Diesel Generator 12 DC
Control Power Transfer switch
2
4007995, Sheet 1
Diagram of Connections Diesel Generator 13 DC
Control Power Transfer switch
2
102007, Sheet 6
Piping Schematic Diagram Reactor Coolant System
68
102008, Sheet 4D
Piping Schematic Diagram, Chemical and Volume
Control
128
102008, Sheet 4
Piping Schematic Diagram, Chemical and Volume
Control
114
102017, Sheet 1
Piping Schematic Salt Water System
89
102017, Sheet 3B
Piping Schematic Diagram, Salt Water System
128
106725, Sheet 26
Compressed Air System
172
- 9 -
Attachment
111906, Sheet 17
Fire Protection Auxiliary Building Elevation 85
7
111906, Sheet 19
Fire Protection Auxiliary Building Elevation 100
4
111906, Sheet 21
Fire Protection Auxiliary Building Elevation 115*
5
111906, Sheet 25
Fire Protection Auxiliary Building Elevations 128, 154
and 164
3
693299, Sheet 8
Mechanical Fire Protection North Auxiliary Building
Elevation 100 Area GE/GW Penetration Area
8
693299, Sheet 9
Mechanical Fire Protection North Auxiliary Building
Elevation 115 Area GE/GW Penetration Area
3
ENGINEERING INFORMATION RECORDS
Number
Title
Revision
TE-PG&E-113-R001
Multiple Spurious Operation Report dated Nov. 3, 2010
0
MODIFICATIONS
Number
Title
Revision
DCP A-049070
Thermo-Lag Removal/Install 3M Fireproofing
0
PROCEDURES
Number
Title
Revision
AR PK01-08
Annunciator Response CCW Header C
19
AR PK05-01
Annunciator Response RCP Number 11
33
AR PK05-04
Annunciator Response RCP Number 14
31
AWP E-002
10 CFR 50 Appendix R Safe Shutdown Analysis
1A
AWP E-009
Combustible Design Control
1
CP M-6
Fire
33A
CP M-10
Fire Protection of Safe Shutdown Equipment - Unit 1
24
CP M-10
Fire Protection of Safe Shutdown Equipment - Unit 1
25
CP M-10
Fire Protection of Safe Shutdown Equipment - Unit 1
26
CP M-10
Fire Protection of Safe Shutdown Equipment - Unit 2
25
CP M-10
Fire Protection of Safe Shutdown Equipment - Unit 2
26
- 10 -
Attachment
CP M-10
Fire Protection of Safe Shutdown Equipment - Unit 2
27
DCM No. T-18
Electrical System Protection
13
DCM No. T-19
Electrical Separation and Isolation
11
DCM No. T-22
Electrical Cable and Raceway
10D
EDMG EDG-6
Makeup to Condensate Storage Tank
1
EDMG EDG-7
Manually Depressurize the SGs to Minimize RCS
Inventory Loss
1
EDMG EDG-9
Use of Fire Engine to Supply Water to Steam
Generators
0
EDMG EDG-10
Containment Flooding with Portable Pump
0
EDMG EDG-14
EDMG Equipment Annual Inventory
2
MP E-50.30B
Electrical Maintenance Procedure Maintenance Agastat
Type ETR Timing Relay maintenance
19
MP E-50.34
Electrical Maintenance Procedure Maintenance
Strutter-Dunn Ground Sensor Relay Maintenance
11
MP E-50.55
Electrical Maintenance Procedure Maintenance Basler
Type BE1-50/51 Over current Relay Maintenance
14
MP E-57.10B
Electrical Maintenance Procedure Maintenance Generic
115VAC and 480 VAC Motor Preventive Maintenance
16
MP E-57.11A
Preparation for Working on Potentially Energized Load
Centers and Transformers
14
MP E-57.11B
Protective Grounding
30
MP E-60.10
Electrical Maintenance Procedure Maintenance Generic
Relay Functional Test
16
MP E-63.3C
Electrical Maintenance Procedure Maintenance of 4
and 12 KV Switchgear
24
MP E-67.5A
Testing and Maintenance of Battery Operated Lights
Inside Power Block
32
OM8
3
OM8.ID1
Fire Loss Prevention
23
OM8.ID2
Fire System Impairment
17
OM8.ID4
Control of Flammable and Combustible Materials
19
OM8.ID5
Fire Protection Program Administration
0
OP AP-8A
Control Room Inaccessibility - Establishing Hot
Standby
31 & 32
OP AP-8B
Control Room Inaccessibility - Establishing Hot
Standby to Cold Shutdown
23
OP AP-28
Reactor Coolant Pump Malfunction
12
- 11 -
Attachment
OP AP-31
Rapid Containment Entry
5
OP B-1A:III
CVCS - Establishing a Hydrogen Blanket on the VCT
14
OP B-1A:X
31
OP C-2:II
Main Steam and Steam Dump Systems - Local
Operation of Steam Dumps
11
STP I-29
Emergency Signals and Communication Systems
Functional Test
41
STP I-34A
Fire Detection System Detector Functional Panel A
24
STP I-34C
Fire Detection System Supervisory Functional
11
STP I-34H
Fire Detection System RTD Calibration Check
3
STP M-5
Surveillance Test of the Fuel Handling Building
Ventilation System
30
STP M-13A
Manual and Auto Transfer of 4KV Vital Buses Off-Site
Power Source
13
STP M-13F
4KV Bus F Non-SI Auto Transfer Test
47
STP M-16Q3FG
Functional Testing of Buses F and G Auto transfer to
Startup Power
2
STP M-17C3
Check of the Emergency AC Lighting System
17A
STP M-31A
Continuity Testing of Remote Shutdown Control
Transferfr Switches (4KV Pumps)
1
STP M-39B
Routine Surveillance Test of Cable Spreading Room
Carbon Dioxide Fire System Operation
27
STP M-51
Routine Surveillance Test of Containment Fan Cooler
31
STP M-67A
Fire Valve Inspection
49
STP M-70D
Inspection of Fire Barriers, Rated Enclosures, Credited
Cable Tray Fire Stops, and Equipment Hatches
13
STP M-71
Firewater System Flow Test
9
STP M-74
Auto Start of ASW Pumps on Low pressure
8
STP P-FPP-A01
Fire Pump 0-1 Performance Test
3
STP P-FPP-A02
Fire Pump 0-2 Performance Test
5
STP P-FPP-B01
Fire Pump 0-1 Routine Surveillance
12
STP P-FPP-B02
Fire Pump 0-2 Routine Surveillance
12
STY V-2Y
Surveillance Test Procedure, Regenerative Heat
Exchanger Letdown Inlet and Letdown Outlet Orifice
Isolation Valves
19
- 12 -
Attachment
VENDOR DOCUMENTS
Number
Title
Revision
RPE E-6653
Vendor Manual - Eaton Cutler Hammer Industrial
Related AC/DC Toggle Switch
2
663336
Vendor Diagram-Westinghouse Motor Control Center IF
IG & IH Control Center Drawings
8
01914963-WD-04
Nuclear Logistics Inc, Wiring Diagram for 18 NEME
Size 3 FVNR Cubicle 52-1F-05
2
01914963-WD-05
Nuclear Logistics Inc, Wiring Diagram for 36 NEME
Size 4 FVNR Cubicle 52-1F-66
2
01914963-WD-06
Nuclear Logistics Inc, Wiring Diagram for 18 NEME
Size 2 two SPD cubicle 52-1F-50
2
01914963-WD-07
Nuclear Logistics Inc, Wiring Diagram for 12 NEME
Size 3 FVNR Cubicle 52-1F-38
2
01914963-WD-08
Nuclear Logistics Inc, Wiring Diagram for 12 NEME
Size 2 FVNR Cubicle 52-1F-39
2
WORK ORDERS
64031002
64019502
64066957
64080891
64051343
64020120
64087588
64039494
64021407
64079883
64079086
64083409
R0232602
6009159
C0130254
R0192538
64009147
64008771
64082180
64006554
MISCELLANEOUS DOCUMENTS
Number
Title
Revision
ANSUL Technical
Bulletin Number 54
Shelf Life of ANSULITE AFFF Concentrates and Their
Premixed Solutions
N/A
A-8
Systems Training Guide, Remote/Hot Shutdown Panels
8
E-6
Systems Training Guide, Salt Water System
14
ECG 18.1
Equipment Control Guideline - Fire Suppression
Systems/Fire Suppression Water Systems
9
ECG 18.2
Equipment Control Guideline - Fire Hose Stations
9
ECG 18.3
Equipment Control Guideline - Fire Detection
Instrumentation
10
ECG 18.4
Equipment Control Guideline - Spray and/or Sprinkler
Systems
6
ECG 18.5
Equipment Control Guideline - CO2 System
9
- 13 -
Attachment
ECG 18.7
Equipment Control Guideline - Fire Rated Assemblies
9
FHARE 110
Separation of Redundant ASW Pump and Exhaust Fan
Circuits in the Intake Structure
1
FHARE 150
Administrative Control Requirements for Fire Rated
Assemblies
1
FHARE 152
Evaluation of Fire Dampers in 480V Switchgear and
Battery Rooms
0
FSAR Section 9.5.1
Fire Protection System
20
Information Notice "Potential For Loss of Remote
Shutdown Capability During a Control Room Fire,"
February
28, 1992
Letter PGE-92-621
Diablo Canyon Appendix R Charging Pump Evaluation
July 14,
1992
Memo
Appendix R Transient Analysis for Stuck Open
Pressurizer PORV
August 11,
1993
NFPA Standard 805
Performance-Based Standard for Fire Protection for
Light Water Reactor Electric Generating Plants
2001
Edition
Operations Crew
Watch Bill
October 15 - 21, 2012
39
Operations Crew
Watch Bill
October 22 - 28, 2012
33
SSER 23
Supplement 23 of Safety Evaluation Report
June 1984
TE-PG&E-113-R001
Multiple Spurious Operations Report
0
T35110
Appendix R Operability of Emergency Lights
0C18 D-16-005
Clearance - Equipment ID: 0-16-M-TK-RWOR1A, Raw
Water Storage Reservoir West 0-1A
September
9, 2012
13698
Maintenance Item 13698 ASP2 Test and Calibrate
Motor
N/A
67997
Set Route Data Raceway Report for Raceway K6958-
61
19
N/A
Diablo Canyon Nuclear Power Plant 450 MHz System
Coverage Report
October 5,
2004
N/A
Time Critical Operator Action Documentation
39