ML113040031
| ML113040031 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 10/31/2011 |
| From: | Mccree V Region 2 Administrator |
| To: | Heacock D Virginia Electric & Power Co (VEPCO) |
| References | |
| IR-11-002, IR-11-011, IR-11-001 | |
| Download: ML113040031 (101) | |
See also: IR 05000338/2011011
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
245 PEACHTREE CENTER AVENUE NE, SUITE 1200
ATLANTA, GEORGIA 30303-1257
October 31, 2011
Mr. David A. Heacock
President and Chief Nuclear Officer
Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA 23060
SUBJECT: NORTH ANNA POWER STATION - AUGMENTED INSPECTION TEAM (AIT)
REPORT 05000338/2011011, 05000339/2011011, 07200016/2011001, and
07200056/2011002
Dear Mr. Heacock:
On October 3, 2011, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection
at your North Anna Power Station Units 1 and 2, and the North Anna Independent Spent Fuel
Storage Installation. The enclosed report documents the inspection results, which were
discussed with you and other members of your staff during a public exit meeting on October 3,
2011.
On August 23, 2011, at 2:03 p.m., Eastern Daylight Time (EDT), North Anna Power Station
declared an Alert due to significant seismic activity onsite from a 5.8 magnitude earthquake that
was centered several miles from the plant. Both units experienced automatic reactor trips from
100 percent power. All offsite electrical power to the site was lost. All four emergency diesel
generators automatically started, loaded and provided power to the emergency buses. All of the
control rods inserted into the core. Decay heat was removed via the steam dumps to the
atmosphere.
At about 2:40 p.m., EDT, plant operators stopped the 2H emergency diesel generator after
observing a cooling water leak and rising temperatures on the diesel engine. The stations
blackout diesel generator was subsequently aligned to power the 2H vital bus. Offsite power
sources were restored. Both units were brought to cold shutdown for further inspection and
repairs. Damage to several onsite non-vital transformers was noted.
Because of evidence that the seismic event may have exceeded the plants design basis, and
due to the risk significance of the operational event, the NRC dispatched an Augmented
Inspection Team to the site to gather additional information and conduct a review of the event.
The team found that: (1) your operators responded to the event in a manner that protected
public health and safety; (2) ground movement during the earthquake exceeded the sites
licensed design basis; (3) no significant damage to the plant was identified; (4) safety system
functions were maintained; and (5) some equipment issues were revealed as a result of the
VEPCO 2
event. Issues requiring additional follow-up are documented as unresolved items in the
enclosed report.
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 Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Victor M. McCree
Regional Administrator
Dockets: 50-338, 50-339, 72-16, 72-56
Licenses: NPF-4, NPF-7, SNM-2507, COC-1004
Enclosure: Inspection Report 05000338/2011011, 05000339/2011011, 07200016/2011001,
and 07200056/2011002
w/ Attachments: 1. Supplemental Information
2. Sequence of Events
3. Augmented Inspection Team Charter
4. Public Exit Meeting Slides
cc w/ encl. (See next page)
_ML113040031________ X SUNSI REVIEW COMPLETE X FORM 665 ATTACHED
OFFICE RII:DRP RII:DRP RII:DRP RII:DRS RII:RA RII:DRP RII:DRS
SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/ RA By E-mail/ /RA/
NAME SNinh GMcCoy RCroteau MFranke LWert GKolcum SWalker
DATE 10/13/2011 10/18/2011 10/20/2011 10/19/2011 10/26/2011 10/06/2011 10/06/2011
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
OFFICE RII:DRS RII:NRR RII:DCP HQ:NRO HQ:NRO RII:DRS
SIGNATURE RA By E-mail/ RA By E-mail/ RA By E-mail/ RA By E-mail/ RA By E-mail/ /RA By
HChristensen/
NAME LSuggs YLI RJackson MChakravorty SPark JMunday
DATE 10/06/2011 10/06/2011 10/06/2011 10/05/2011 10/06/2011 10/18/2011
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
VEPCO 3
cc w/encl: Michael M. Cline
Larry Lane Director
Site Vice President Virginia Department of Emergency Services
North Anna Power Station Management
Virginia Electric & Power Company Electronic Mail Distribution
Electronic Mail Distribution
Executive Vice President
Fred Mladen Old Dominion Electric Cooperative
Director, Station Safety & Licensing Electronic Mail Distribution
Virginia Electric and Power Company
Electronic Mail Distribution County Administrator
Louisa County
Michael Crist P.O. Box 160
Plant Manager Louisa, VA 23093
North Anna Power Station
Virginia Electric & Power Company
Electronic Mail Distribution
Lillian M. Cuoco, Esq.
Senior Counsel
Dominion Resources Services, Inc.
Electronic Mail Distribution
Tom Huber
Director, Nuclear Licensing & Operations
Support
Virginia Electric and Power Company
Electronic Mail Distribution
Ginger L. Rutherford
Virginia Electric and Power Company
Electronic Mail Distribution
Virginia State Corporation Commission
Division of Energy Regulation
P.O. Box 1197
Richmond, VA 23209
Attorney General
Supreme Court Building
900 East Main Street
Richmond, VA 23219
Senior Resident Inspector
North Anna Power Station
U.S. Nuclear Regulatory Commission
P.O. Box 490
Mineral, VA 23117
VEPCO 4
Letter to David A. Heacock from Victor M. McCree dated October 31, 2011
SUBJECT: NORTH ANNA POWER STATION - AUGMENTED INSPECTION TEAM (AIT)
REPORT 05000338/2011011, 05000339/2011011, 07200016/2011001, and
07200056/2011002
Distribution w/encl:
C. Evans, RII EICS
L. Douglas, RII EICS
OE Mail
RIDSNRRDIRS
PUBLIC
RidsNrrPMNorthAnna Resource
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.: 50-338, 50-339, 72-16, 72-56
License Nos.: NPF-4, NPF-7, SNM-2507, COC-1004
Report No.: 05000338/2011011, 05000339/2011011, 07200016/2011001 and
07200056/2011002
Licensee: Virginia Electric and Power Company (VEPCO)
Facility: North Anna Power Station, Units 1 & 2 and the North Anna Independent
Spent Fuel Storage Installation
Location: 1022 Haley Drive
Mineral, Virginia 23117
Dates: August 30, 2011 through October 3, 2011
Team Leader: M. Franke, Chief
Operations Branch 2
Division of Reactor Safety
Assistant Team G. Kolcum, Senior Resident Inspector, North Anna
Leader:
Inspectors: R. Jackson, Senior Resident Inspector, Construction Projects Branch 4,
Division of Construction Projects
S. Walker, Senior Reactor Inspector, Engineering Branch 1,
Division of Reactor Safety
L. Suggs, Reactor Inspector, Engineering Branch 2,
Division of Reactor Safety
Y. Li, Senior Geophysicist (Seismologist), Mechanical and Civil
Engineering Branch
Office of Nuclear Reactor Regulation
M. Chakravorty, Senior Structural Engineer, Structural Engineering
Branch 2
Office of New Reactors
S. Park, Structural Engineer, Structural Engineering Branch 1
Office of New Reactors
Approved by: Victor M. McCree, Regional Administrator
Enclosure
TABLE OF CONTENTS
Contents
1.0 Executive Summary ........................................................................................................ 2
2.0 Description of Event ........................................................................................................ 3
2.1 Summary Sequence ............................................................................................ 3
2.2 System Descriptions ............................................................................................ 4
3.0 Seismic Assessment ....................................................................................................... 6
3.1 Seismic Strength ................................................................................................. 6
3.2 Seismic Equipment Maintenance and Calibration .............................................. 19
4.0 Cause of Unit 1 and Unit 2 Reactor Trip ........................................................................ 21
5.0 Emergency Diesel Generator Performance ................................................................... 22
6.0 Electrical System Performance ..................................................................................... 27
7.0 On-Shift Human Performance ....................................................................................... 37
7.1 Emergency Operating Procedures (EOPs) ........................................................ 37
7.2 Station Black-Out Diesel Generator ................................................................... 39
7.3 2H Emergency Diesel Generator Failure ........................................................... 40
7.4 Restoration of Offsite Power .............................................................................. 41
7.5 Emergency Planning Declarations ..................................................................... 41
7.6 Post Earthquake Actions ................................................................................... 43
8.0 Plant Parameters and Assessment ............................................................................... 45
8.1 Unexplained Instrumentation Anomalies............................................................ 45
8.2 General Assessment ......................................................................................... 46
8.3 Groundwater and Buried Pipe ........................................................................... 51
9.0 Operability Determinations ............................................................................................ 52
10.0 Restart Readiness ........................................................................................................ 56
11.0 Independent Spent Fuel Storage Installation (ISFSI)..................................................... 57
12.0 Data for Risk Assessment ............................................................................................. 59
13.0 Safety Culture ............................................................................................................... 60
14.0 Exit Meeting Summary .................................................................................................. 61
ATTACHMENT 1 - Supplemental Information
ATTACHMENT 2 - Sequence of Events
ATTACHMENT 3 - Augmented Inspection Team Charter
ATTACHMENT 4 - Public Exit Meeting Slides
SUMMARY OF FINDINGS
IR 05000280/2011011 and 05000281/2011022; IR 07200016/2011001 and 07200056/2011002,
08/30/2011 through 10/03/2011, North Anna Power Station, Units 1 and 2; Augmented
Inspection Team.
An Augmented Inspection Team (AIT) was dispatched to the site on August 30, 2011, to assess
the facts and circumstances surrounding an earthquake event, dual unit trip, and loss of offsite
power that occurred on August 23, 2011. The AIT was established in accordance with NRC
Management Directive 8.3, NRC Incident Investigation Program, and implemented using
Inspection Procedure 93800, Augmented Inspection Team.
The inspection was conducted by a team of inspectors from the NRCs Region II office, senior
resident inspectors from North Anna and Construction Projects Branch 4, one Seismologist from
the NRC Office of Nuclear Reactor Regulation (NRR), and two Structural Engineers from the
NRC Office of New Reactors (NRO.) The team identified 7 issues that will require additional
NRC inspection. These issues are tracked as unresolved items in this report.
A. NRC-Identified and Self-Revealing Findings
None
B. Licensee-Identified Violations
None
Enclosure
2
1.0 Executive Summary
On August 23, at about 1:51 p.m. Eastern Daylight Time (EDT), North Anna Power Station
experienced a magnitude 5.8 earthquake with an epicenter about twelve miles southwest of the
plant. Both reactors experienced automatic trips from 100 percent power. Offsite electrical
power to the site was interrupted. All four emergency diesel generators automatically started,
loaded and provided power to the emergency buses. All control rods inserted into the core. An
Alert was declared based on shift managers judgment.
At about 2:40 p.m., control room operators stopped the 2H emergency diesel generator (EDG)
after a cooling water leak and rising temperatures were observed on the diesel engine.
Operators subsequently aligned the stations blackout (SBO) diesel generator (DG) to power the
2H vital bus. At 5:40 p.m., offsite power was first restored to the 2J emergency bus via the C
reserve station transformer. Offsite power to the site was fully restored to the emergency
busses by 10:58 p.m., and both units were later brought to cold shutdown for further inspection
and repairs.
Because it was unclear whether the ground motion from the earthquake had exceeded the
plants licensed design basis, and because of potential safety ramifications, the NRC dispatched
an Augmented Inspection Team to better understand the event and the licensees response.
The teams findings included: (1) operators responded to the event in accordance with
established procedures and in a manner that protected public health and safety; (2) the ground
motion from the earthquake exceeded the plants licensed design basis; (3) no significant
damage to the plant was identified; (4) safety system functions were maintained; and (5) some
equipment issues were experienced.
The team evaluated the event to determine if any issues should be considered on a generic
basis for other facilities. The team identified two potential issues in the areas of (1) seismic
monitoring instrument location, and (2) seismic monitoring equipment performance.
The team identified several specific issues related to equipment performance that warranted
follow-up. These included: (1) the 2H EDG developed a cooling water leak necessitating its
shutdown; (2) operators observed frequency oscillations affecting the 1J EDG that appeared to
approach Technical Specification (TS) limits; (3) some functions of the control room seismic
alarm panel were lost during the earthquake; (4) seismic instrumentation, data collection and
operator training issues were revealed; (5) missing cooling water orifice plates were identified
on the 1J and 2J EDGs; (6) an Auxiliary Feedwater Pump (AFWP) trouble alarm was
unexpected during the event; and (7) some anomalies were observed affecting some safety
related instrumentation during the event. These issues are documented as unresolved items in
this report.
Overall, the team concluded that the event did not adversely impact the health and safety of the
public. Safety limits were not approached and there was no measurable release of radioactivity
associated with the event.
Enclosure
3
2.0 Description of Event
2.1 Summary Sequence
Before the event, the North Anna electrical distribution system was in an at power
configuration and the 4160 volt portion of the system was aligned with Buses D, E, and F
powering the emergency buses from Units Reserve Station Service Transformers
(RSST). Figure 1 below shows a simplified schematic of the North Anna electrical
distribution system. This figure, along with the system descriptions in Section 2.2 of this
report, will aid in understanding the details of this event. Both Units were at 100% power
and Unit 1 turbine driven AFWP was removed from service for scheduled surveillance
testing.
Figure 1, North Anna Simplified Electrical Distribution
On August 23, 2011, at approximately 1:51 p.m. EDT, the site experienced a magnitude
5.8 earthquake with an epicenter approximately twelve miles southwest of the plant.
Both reactor trip breakers opened on negative flux rate approximately 11 seconds after
the event. Sudden pressure relay actuations were experienced on the RSSTs
approximately 12 seconds after the event, leading to a loss of off-site power (LOOP)
event. At approximately 20 seconds after the event, all four EDGs and the SBO DG
Enclosure
4
auto started. An Alert was declared at 2:03 p.m. based on shift managers judgment due
to an inability to enter the emergency action level (EAL) for a seismic event because the
LOOP prevented the seismic panel from reporting the earthquake magnitude in the
control room. At 2:40 p.m., 2H EDG was tripped in the control room due to a coolant
leak. At 2:55 p.m., an Alert was declared for Unit 2 due to the loss of 2H EDG.
Approximately 38 minutes later, the SBO DG was aligned to the 2H bus. At 10:58 p.m.,
offsite power was restored supplying all the emergency buses. Both units were safely
shutdown and stabilized under hot shutdown conditions.
A more detailed sequence of events can be found in Attachment 2.
2.2 System Descriptions
2.2.1 Emergency Diesel Generators
There are two 100 percent capacity EDGs for each unit. The EDGs automatically start
when a safety injection signal is received, a 90 percent degraded voltage level for 56
seconds is sensed on the bus, or about 74 percent voltage for 2 seconds exists on the
bus. Following a LOOP, as experienced on August 23, 2011, when the EDGs sense
voltage less than 74 percent on the bus, the emergency bus isolates and load shedding
begins. The generator output breaker automatically closes onto the bus when the
generator output voltage reaches 95 percent of nominal, either of the normal offsite
power supply breakers are open, limited residual voltage remains on the bus, and the
generator differential auxiliary relay is reset.
The EDG supply breaker automatic protective trips are diesel-engine overspeed,
generator overexcitation, bus overcurrent, and generator differential. The EDG
automatic engine trips are high lube-oil temperature, high jacket water coolant
temperature, high crankcase pressure, low lube-oil pressure, start failure, generator
differential, and diesel-engine overspeed. During an emergency start, the EDG breaker
trips automatically only on diesel overspeed, bus overcurrent, and generator differential.
The EDGs are automatically shut down only on generator differential and diesel-engine
overspeed. All other EDG protective trips are bypassed during an emergency start. The
breakers can also be manually tripped, and the diesels manually stopped.
The EDG jacket water cooling system is designed to dissipate the heat rejected by the
engine water jackets and the lube oil. Coolant is circulated through the engine at about
800 gpm by an engine driven centrifugal pump. It then passes through a temperature
control valve which directs it through or around the radiator as necessary to maintain
required temperature. Then the coolant passes through the lube oil heat exchanger
where it enters the pump suction and repeats the cycle. If jacket coolant is lost, there is
a high jacket coolant temperature alarm. The trip setpoint of 205°F is 111% of normal
operating temperature, which is low enough to protect the engine but high enough to
prevent inadvertent tripping. The alarm setpoint is 195°F.
The EDGs are load tested in accordance with TS. To allow isochronous (independent)
and droop (parallel) operation of the EDG following testing, an automatic speed reset
Enclosure
5
capability has been installed in the EDG motor-operated potentiometer circuit. The
preset speed condition (900 rpm) is necessary for two reasons: (1) to ensure that the
EDGs can accommodate the oncoming load without tripping, and (2) to ensure that
control instrumentation and other safety-related equipment will operate at the proper
frequency. Following the shutdown of the EDG system, the reset will automatically
position the speed reference potentiometer to the predetermined speed setting on the
electric governor. The control relays that are used for this purpose are powered from the
125V DC distribution panels 2A and 2B.
2.2.2 Electrical Power Distribution System
The onsite electric system includes electrical equipment necessary to generate power
and deliver it to the high-voltage switchyard. It also includes power supplies and
equipment, including batteries, necessary to distribute power, both AC and DC, to the
normal (non-safety-related) auxiliaries, and emergency (safety-related) auxiliaries. The
onsite electric system also supplies power for control and instrumentation and is
designed to provide dependable sources of power and distribute it to the plant
auxiliaries.
The normal AC power source for each unit is the main generator, which is connected to
three unit station service transformers by the isolated phase bus duct. The transformers
have adequate capacity to supply all unit auxiliaries, with the exception of 4-kV buses
1G and 2G, for plant operation during normal power generation. Buses 1G and 2G are
powered from the offsite sources via the Reserve Station Service Transformers (RSSTs)
B and C, respectively.
The preferred or reserve AC power source is the switchyard, which is connected to both
units via three 3-phase 34.5/4.16-kV transformers located near the power station. The
34.5-kV supply to these RSSTs comes from two or more of the following: two 500/36.5-
kV transformers located in the 500-kV switchyard, and one 230/34.5-kv transformer
located in the 230-kV switchyard. A switching capability is provided so that all three of
the 34.5/4.16-kV transformers can be supplied from any of the station reserve
transformers if necessary. The reserve station service power is available at all times to
the safety-related equipment and has the capacity to power the station auxiliaries in the
event of a loss of the normal AC power supply. Upon a loss of power from the normal
source on Unit 2, the normal station distribution system will transfer automatically to the
reserve station service supply, provided no fault exists on the normal 4160V bus. On
Unit 1, a main generator breaker has been installed. This allows Unit 1 to have its
normal station service buses supplied from its normal station service transformers
(backfed from the 500-kV switchyard) for most Unit 1 trips.
The standby emergency AC power source for each unit consists of two EDGs. The
standby AC power system has adequate capacity to supply the safety-related
equipment. The standby AC power source, during the periods of interrupted preferred
power, automatically supplies safety-related equipment.
Enclosure
6
An Alternate AC (AAC) DG is available to provide emergency power in the event of a
SBO. A SBO is defined as loss of offsite power, concurrent with a turbine trip (loss of
onsite power) and the failure of the emergency AC power source, but not the station
batteries for the blacked out unit. The AAC system is auto-started by an SBO event.
Operator action is required to align the AAC DG output to the desired emergency bus.
The 120V vital AC power source consists of four static inverters, each powered from its
associated DC bus. These inverters provide a dependable 120V AC power source for
the safety-related equipment, control, and instrumentation.
The 125V DC power source in each unit consists of four independent batteries and six
battery chargers, two of which are spares.
The onsite AC power distribution system consists of three normal 4160V buses, two
emergency 4160V alternate AC buses, two emergency 4160V buses per unit, and four
emergency 480V buses per unit. In addition, Unit 1 is equipped with 11 normal 480V
buses and Unit 2 is equipped with eight normal 480V buses. The 480V buses are fed
from their respective 4160V buses through transformers. The 480V buses feed motors,
motor control centers, transformers for 240/120V AC power and lighting distribution, and
battery chargers for the 125V DC system and the standby diesel generators 125V DC
systems.
3.0 Seismic Assessment
The team collected data to determine the strength of the seismic activity at the plant.
This included information about the maintenance and calibration of seismic monitoring
equipment installed at the plant.
3.1 Seismic Strength
a. Inspection Scope
The scope of the task was to determine the seismic impact at the North Anna Nuclear
Power Station from the August 23, 2011, earthquake. In order to complete the task, the
team reviewed seismic recordings and associated response spectra from seismic
monitors situated at different levels of the Unit 1 containment and Auxiliary Buildings.
The team performed a walkdown of different levels of the Auxiliary Building and the Unit
1 Containment Building where seismometers were located. In addition, the team
interviewed licensee engineers.
Enclosure
7
b. Observations and Findings
The team found that the ground motion from the earthquake exceeded the licensees
design basis.
The seismic vibratory effect to the reactor and its associated structures, systems and
components was directly demonstrated by comparing the design spectrum with
seismometer recordings at the same elevation. The Seismic Monitoring Equipment table
following this section lists elevations, structure, or system, affiliations and equipment
types for seismometers inside two buildings as well as a synopsis of the comparison
between the design and the observed spectrum. In addition, Figures 1-10 show a
comparison between the design response spectrum and the seismic recordings,
corresponding to the tables description.
The design response spectrum was exceeded based on recordings from different types
of seismic instruments. This was evident on both of the seismic recording systems,
Kinemetrics accelerometers and Engdahl scratch plates, used at the plant. However,
recordings from the two different seismic instruments (Kinemetrics and Engdahl) located
at the same floor level show conflicting spectral behaviors in terms of both frequency
and amplitudes. The team relied primarily on the information obtained from the
Kinemetrics equipment because Engdahl scratch plates only record certain maximum
levels as opposed to recording the entire time history of the event; and in this case some
of the scratch plates did not register any of the seismic event activity. Additional
discussion of the seismic instrumentation performance can be found in Section 3.2.
As part of the seismic system assessment, the team walked down the Auxiliary Building
and the Unit 1 Containment Building to visually inspect various structures, systems and
components as well as seismic instruments located at different floors. The walkdown
included a majority of the Unit 1 Containment Building and Auxiliary Building elevations.
During the walkdowns, the team did not observe significant damage. The team observed
some minor cracks in the interior wall of the Auxiliary Building and a minor crack on the
inCore room wall inside the Unit 1 Containment Building. During interviews, licensee
personnel indicated that no soil failure, neither liquefaction nor slope failure, were
observed at the North Anna site.
Enclosure
8
Seismic Monitoring Equipment
Structures Elevation Description Frequency Largest Other Seismometers
(Seismometer) And sensitive to difference (%)
Direction SSC) and associated
frequencies
Unit 1 Basemat Recorded ground Exceeded 100% at Engdahl scratch plate recordings
(Kinemetrics 216 ft motion exceeded from 2.5 Hz approximately exist; no exceedance at all
SMA-3) in the N-S DBE (5% damping) and above, 40 Hz and recorded frequencies but no
Figure 1 except at 8 above readings at 10.1 and 25.4 Hz, and
Hz conflict with Kinemetrics SMA-3
recordings
Unit 1 Basemat Recorded ground Exceeded at 31% at about 30 Engdahl scratch plates recordings
(Kinemetrics) 216 ft motion exceeded several Hz with minor exceedance at 2,8,
Figure 1 in the E-W DBE (5% damping) frequency 12.7 , 16 and 25.4 Hz only
bands
centered at
12, 16 and
30 Hz
Unit 1 Basemat Recorded ground Exceeded 88% at 29 Hz Engdahl scratch plates recordings
(Kinemetrics) 216 ft motion exceeded from 3 Hz with exceedance at 10.1 and 25.4
Figure 2 in the DBE (5% damping) and above Hz only
Vertical
Unit 1 Elevation Recorded ground Exceedance 74% at 3 Hz No Engdahl data available
(Kinemetrics) 291 ft motion exceeded almost
Figure 3 in the N-S DBE (5% damping) continuously
from 1 to 3
Hz and 7.8
Hz and
above
Unit 1 Elevation No exceedance at all No Engdahl data available
(Kinemetrics) 291 ft the frequencies
Figure 3 in the E-W
Unit 1 Elevation Recorded ground Exceeded at 176 % at about No Engdahl data available
(Kinemetrics) 291 ft motion exceeded 3-4 Hz, 5-10 40 Hz
Figure 4 in the DBE (5% damping) Hz and 26
vertical Hz and
above
Auxiliary Basemat Recorded ground Exceeded 83% at 10 Hz No Kinemetrics data available
Building 241ft motion exceeded between 6.4
(Engdahl in the N-S DBE (2% damping) Hz and 22
Scratch plates) Hz
Figure 5
Auxiliary Basemat No exceedance at all No Kinemetrics data available
Building 241ft the frequencies
Figure 6 in the E-W
Auxiliary Basemat Recorded ground Exceeded at Approximately No Kinemetrics data available
Building 241ft motion exceeded 6.4 Hz and 200% at 25.4 Hz
Figure 7 In the DBE (2% damping) above
vertical
Auxiliary Elevation Recorded ground Exceeded at Approximately No Kinemetrics data available
Building 273 ft motion exceeded 5.3 Hz and 450% at 12.7 Hz
Figure 8 in the N-S DBE (2% damping) above
Auxiliary Elevation Recorded ground Exceeded at Approximately No Kinemetrics data available
Building 273 ft motion exceeded 8 Hz and 23 200% at 20.2 Hz
Figure 9 in the E-W DBE (2% damping) Hz
Auxiliary Elevation Recorded ground Exceeded at Approximately No Kinemetrics data available
Building 273 ft motion exceeded 6.4 Hz and 250% at 10 Hz
Figure 10 in the DBE (2% damping) above
vertical
Enclosure
9
1.2
1
0.8
acceleration (g)
0.6
SSE (horizontal)
Observed (NS)
0.4
Observed (EW)
0.2
0
0.1 1 10 100
Frequency (Hz)
Figure 1, Unit 1 basemat spectrum comparison (horizontal) between the designed and the
observed
Enclosure
10
0.4
0.35
0.3
0.25
Acceleration (g)
0.2 OBE (vertical)
SSE (vertical)
Observed (vertical)
0.15
0.1
0.05
0
0.1 1 10 100
Frequency (Hz)
Figure 2, Unit 1 basemat spectrum comparison (vertical) between the designed and the
observed
Enclosure
11
ectrum comparison (horizontal) between the desig
Figure 3, Unit 1 Operating Deck spe gned and
the observed
Enclosure
12
ectrum comparison (vertical) between the designe
Figure 4, Unit 1 Operating Deck spe ed and the
observed
Enclosure
13
Figure 5, Auxiliary Building basemat spectrum comparison (N-S) between the designed and the
observed
Enclosure
14
Figure 6, Auxiliary Building basemat spectrum comparison (east-west) between the designed
and the observed
Enclosure
15
Figure 7, Auxiliary Building basemat spectrum comparison (vertical) between the designed and
the observed
Enclosure
16
Figure 8, Auxiliary Building (273 ft) spectrum comparison (north-south) between the designed
and the observed
Enclosure
17
Figure 9, Auxiliary Building (273 ft) spectrum comparison (east-west) between the designed and
the observed
Enclosure
18
Figure 10, Auxiliary Building (273 ft) spectrum comparison (vertical) between the designed and
the observed
Enclosure
19
3.2 Seismic Equipment Maintenance and Calibration
a. Inspection Scope
The team reviewed records and interviewed personnel to determine whether the seismic
instruments at the North Anna Power Station were maintained and calibrated properly to
provide accurate information for making decisions on safe shutdown during and
following a seismic event and for subsequent engineering analysis. The team completed
this task by reviewing seismic instrument manuals, and other related documents, and a
sample of calibration documents. The team also interviewed licensee engineers and
inspected instrument scratch plates that recorded the initial seismic activity.
b. Observations and Findings
The team found that two potential generic issues exist related to the seismic
instrumentation system and implementation. These issues and one related URI are
described in this section. A second related URI is described in Section 7.5.
The team conducted walkdowns of all seismic instruments located in Unit 1 Containment
and Auxiliary Buildings. During the walkdowns, the team visually inspected all of the
seismic instruments at various levels of elevation of the two buildings. The installation of
seismic equipment appeared consistent with the equipment vendor manuals. The
licensees records indicated that seismic equipment, including both Engdahl and
Kinemetrics, was checked every 18 months during refueling outages.
Through review of records and interviews with licensee personnel, the team noted the
following issues with seismic instruments:
1. All the seismic instrumentation was located on plant structures, and no
seismometers were installed on a free surface in the free field; therefore, the team
questioned whether the instrumentation would provide a reliable indicator for
determining whether an earthquake had exceeded Operating Basis Earthquake
(OBE) or Safe Shutdown Earthquake (SSE) ground motion levels.
2. A seismic alarming system panel lost power during the event and it was not
connected to an uninterruptible electric power supply. In addition, some other
equipment issues were observed during the event follow-up. The team questioned
whether the seismic equipment and associated alarming systems were adequate to
perform their expected function considering the equipment issues observed during
the event.
Because these two issues may be applicable to other operating nuclear power plants,
the team determined that they represented potential generic issues.
Enclosure
20
Specific issues with the equipment included:
- A seismic alarming system panel lost power during the event and it was not
connected to an uninterruptible electric power supply. The team questioned whether
the seismic equipment and associated alarming systems were adequate to perform
their expected function considering equipment issues observed during the event.
- Seismic recordings were inconsistent between the Kinemetrics and Engdahl scratch
plates located on the base-mat of Unit 1. Some of the Engdahl scratch plates did not
record any ground motion.
- Both orientations of Kinemetrics and Engdahl scratch plate equipment located at
different elevation levels were misidentified; therefore, the data for East-West and
North-South was initially swapped.
- A deficiency was previously identified by the licensee on the seismic alarming
system, affecting one of the panels alarms, but remained pending repair (Work
Order 59102235553 and Condition Report (CR) 403883).
exceedance) and the licensees system training manual (Module NCRODP-72-NA:
amber light indicates 67 percent of DBE for frequency of a particular reed in either
the L, T or V direction; red light indicates 100% DBE for the frequency of a particular
reed in either the L,T or V direction). The licensee entered this issue into their
corrective action program as CR 442880.
- Based on the review of maintenance and calibration records, the team did not find
documentation indicating performance of cross-checks and calibration of different
types of seismic equipment against each other to ensure the signals recorded were
consistent with regard to frequency and amplitudes.
- Seismic recordings were not clocked or referenced to the plants event recorders;
therefore, the start time of seismic activity time history recordings required
estimation.
The team determined that the issues with seismic instrument implementation warranted
additional NRC review and follow-up considering that information from this system
served as an input into event response decision making. Additional review by the NRC
will be needed to determine whether any of the issues represents a performance
deficiency. An unresolved item will be opened pending completion of this review. The
issue will be identified as URI 05000338, 339/2011011-01, Seismic Instrumentation
Implementation.
Enclosure
21
4.0 Cause of Unit 1 and Unit 2 Reactor Trip
a. Inspection Scope
To ascertain what caused the reactor trip on August 23, 2011, the team conducted
interviews with licensee staff to gather an accurate account of the sequence of events.
Plant data and logs were reviewed to gain an understanding of plant response. The
Post Trip Event Report was reviewed to gauge the licensees assessment of the plant
trip and the identified possible causes.
b. Observations and Findings
Based on the sequence of events, the team found that the reactor trips resulted from
high negative rate flux signals and occurred prior to the loss of offsite power.
Based on the plant response data, the licensee determined that both Unit 1 and 2
reactor trips were due to a Power Range High Negative Neutron Flux Rate reactor trip
signal. The bi-stables (N41 and N42) associated with the high negative flux rate trip are
for an abnormal rate of decrease in nuclear power. The reactor is tripped when a high
negative rate occurs in two out of the four power range channels. The licensees Post
Event Trip Report identified four possible causes for this trip:
- Loss of power to the control rod motor generator sets
- A dropped control rod
- Movement of the nuclear instrumentation detectors
- Core barrel movement
At the time of the teams review, the licensee was conducting a root cause evaluation
and planned to assess each one of these potential causes through engineering analysis
and testing to determine the most likely underlying cause of the trip signal and any
contributing causes. The licensee had not yet completed their root cause at the time of
the inspection.
Enclosure
22
5.0 Emergency Diesel Generator Performance
a. Inspection Scope
To adequately evaluate the performance of the EDGs in response to the seismically
induced LOOP (including the 2H EDG coolant leak and any identified anomalies), the
team performed the following activities:
- Conducted walkdowns of the EDGs to evaluate the material condition
- Conducted interviews with plant personnel (maintenance, engineering, and
operations; root cause investigation team) to determine an accurate account of
events related to the EDGs
- Reviewed design and engineering documents to verify appropriateness of licensee
actions in accordance with design and licensing basis
- Observed corrective maintenance and testing to assess the licensees actions to
restore the EDGs
In addition, the team reviewed corrective action CRs to evaluate the licensees response
to identified deficiencies associated with the EDGs. The vendor manual was referenced
to verify alignment with licensee maintenance procedures. Industry operating
experience was referenced to identify any potential generic industry issues similar to
what was observed at North Anna with respect to the EDGs performance.
b. Observations and Findings
The team found some issues with EDG performance and identified two URIs that are
described in this section.
Following the seismic event on August 23, 2011, at 1:51 p.m., all four EDGs started and
loaded their respective emergency buses due to a loss of offsite power on both units.
About 45 minutes after the EDGs started, a coolant leak was observed on the 2H EDG.
At 1:40 p.m., the 2H EDG was manually tripped and secured and the associated
emergency bus de-energized. The 2H emergency bus was subsequently re-energized
by the SBO diesel. Additionally, the 1J EDG was observed to have minor frequency
oscillations. This issue is discussed in further detail in Section 6.0 of this report.
Upon further investigation, it was determined that the 2H EDG coolant leak was caused
by failure of a fiber gasket located between the exhaust belt and the jacket water cooling
inlet jumper on the opposite control side (OCS) of the diesel engine. Initial discovery
found the gasket soft and extruding from the flange edge. Due to the excessive coolant
leak and in response to a High Jacket Coolant Temperature annunciator that came in
during the event, the licensee inspected the cylinder liners, pistons, and rings for
damage. No engine damage was found to have occurred. During restoration of the 2H
EDG, a small exhaust leak was also identified during the post-maintenance test. The
licensee subsequently replaced one exhaust gasket and the extension pipe. The small
leak did not have an impact on the EDG to perform its safety function.
Enclosure
23
2H EDG Jacket Water Cooling Gasket Leak
In May 1999, EDG vendor Fairbanks-Morse issued a Marketing Information Letter,
Vendor Technical Manual (VTM) Addenda 72, detailing a new, fiber gasket to replace
the previous rubber gaskets for the cooling water bypass fittings. The licensee began
installation of the new gaskets in 2001. One major difference was the new fiber gasket
was 1/8 thick as opposed to 1/16 for the rubber gasket. The letter also provided
recommendations for gasket installation. These recommendations included:
- Allowing a minimum dry time of 10 minutes following application of the gasket
adhesive;
- Ensure the fitting surfaces for the exhaust belt and the water inlet flange have the
appropriate finish;
- Assemble fitting to exhaust belt and torque nuts to 70 ft/lbs +/- 10
Maintenance procedure, 0-MCM-0701-27, Replacement of Emergency Diesel Generator
Cylinder Liners, Revision 19, was used for replacement of the gaskets on 2H EDG in
May 2010. The procedure did not include a dry time following application of the
adhesive (RTV). Improper curing time for the adhesive could impact the proper
alignment of the gasket; too short a time can allow the gasket to move out of place, too
much time can harden the adhesive. Following overhaul of the 2H EDG in May 2010,
which included replacement of the gaskets, the licensee performed a hydrostatic test to
ensure proper restoration. During this test, water pressure was applied (at approx. 50
psi) to the engine block above the normal operating pressure (approx. 30 psi) to ensure
no external leakage was occurring; however, coolant leakage was observed on all of the
gaskets. It was determined at this time, as documented in Condition Report (CR)
383161 and Corrective Action (CA) 172549, that the RTV adhesive should be allowed to
set for 30 - 60 minutes on the gaskets prior to installation for improved sealing. The 2H
EDG gaskets were removed and re-installed and passed a subsequent hydrostatic post-
maintenance test. A subsequent revision to the procedure was approved and
implemented in September 2010 to include the adhesive cure time.
When the 2H EDG was taken out of service for corrective maintenance following
discovery of the coolant leak on August 23, 2011, the licensee removed the OCS heat
shields and stress bars, drained the remainder of the coolant, and removed the exhaust
components as necessary to gain access to the jacket water inlet elbow. Initial
inspection of the water by-pass inlet revealed the gasket protruding past the inlet fitting
indicating that the gasket might not have been properly aligned when originally installed
in May 2010, despite having been installed twice and satisfactory completion of the
hydrostatic testing. Additional investigation by the licensee revealed that in addition to
potential misalignment of the water bypass inlet gasket, the jacket water bypass inlet
header adjustable screw and jam nut were potentially inappropriately installed. The
adjustable screw and jam nut act as a cantilever on the engine block and bypass inlet
fittings. Excessive tightening of the adjusting screw can place more compression on the
top of the gasket and cause the gasket to extrude and leak on the bottom of the inlet
pipe joint. There was no guidance in procedure 0-MCM-0701-27 for tightening the
Enclosure
24
adjustment screw and jam nut; the procedure has since been revised to include detailed
instructions.
Figure 11, 2H EDG Failed Gasket
Following installation of the gaskets in May 2010, 0-MCM-0701-27 required the water
bypass fitting bolts be torqued to 50 -55 ft-lb; however, this was in conflict with the
vendor recommended 70 ft-lbs. as outlined in VTM Addenda 72. According to the
vendor, the 50 ft-lb torque specification was applicable to the previous rubber gasket and
was specified to reduce the thickness of the gasket from 1/16 (.062) to .040-.050. The
new gasket was thicker at 1/8 and the 70 ft-lbs. was the specified torque. There are two
bolts per fitting and are torqued to ensure appropriate compression was applied between
the bypass fitting, the gasket, and the exhaust belt. This discrepancy in torque values
was identified by the licensee and documented in CR 347658 in September 2009. After
discussion with the EDG vendor, the licensee determined that the lower torque value
was acceptable given no leakage up to that time had been observed during hydrostatic
testing or operation of the diesel; however, the vendor maintained a recommendation of
70 ft-lbs. if leakage was observed. In response to the 2H EDG coolant leak on August
23, 2011, the licensee conducted follow-up discussions with the vendor to determine if
50 ft-lbs. was acceptable. The vendor restated the recommendation of 70 ft-lbs. and
performance of a hydrostatic test at 50 psi. The team questioned whether the lower 50
ft-lbs. torque value being applied to the new thicker gasket provided the appropriate
compression for sealing. A lack of compression can allow the gasket to absorb water
and soften, which can lead to gasket extrusion from the flange edge. The licensee was
going to perform a technical evaluation to demonstrate adequate compression was
available to the gasket. The procedure has since been revised to include the
recommended 70 ft-lbs. torque specification.
Enclosure
25
Additionally, in September 2009, the licensee documented in CR 347783 that the EDG
water bypass fittings had the incorrect surface finish and were not in accordance with the
VTM Addenda 72 recommendation of ensuring the exhaust belt had a 125 micro-inch
finish and the inlet flange had a 250 micro-inch finish. Though the CR was written to
resolve the discrepancy before the next EDG outage (1J), the procedure was not revised
until August 2011, following the 2H EDG coolant leak.
The team concluded the licensee failed to properly incorporate or evaluate vendor
recommendations regarding installation of the cooling water gaskets. At the time of the
teams review, the licensee planned to continue evaluating whether the seismic event
accelerated the failure of the gasket. Though the licensee eventually inspected all four
EDGs following the discovery of the leak on 2H EDG, the team questioned why the
licensee initially determined the leak to be an isolated event without having known the
cause. The TS requires a common cause evaluation if one EDG is determined to be
inoperable. If the cause cannot be confirmed not to exist on the remaining EDGs, the
EDGs should be tested to provide reasonable assurance and the corrective action
program should continue to evaluate the common cause possibility for the other EDGs.
In the case of the 2H EDG leak, the apparent cause was known to be the gasket failure
as documented in CR 439091 on August 24, 2011. At the time, the other EDGs were
running at full load to support plant shutdown; however, it was not known if the gaskets
were installed properly on these EDGs. The CR recognized that previous related issues
existed (i.e., multiple coolant leaks across multiple EDGs); however, the licensee still
determined the leak was an isolated event. The team observed that this conclusion was
based on lack of visible evidence or result (i.e., coolant leakage), but not on a
determination of the actual cause. The licensee did submit work orders to inspect the
gaskets on the remaining EDGs, but the initial assessment of this being an isolated
event did not appear in accordance with proper corrective action program common
cause evaluations.
The failure of the jacket water cooling gasket caused a leak on the 2H EDG and
consequently, inoperability of the 2H EDG during a dual unit LOOP following a seismic
event on August 23, 2011. Additional review by the NRC will be needed to determine
whether the lack of adequate procedural guidance for EDG cooling water gasket
installation represents a performance deficiency. An unresolved item will be opened
pending completion of this review. The issue will be identified as unresolved item (URI)
05000338, 339/2011011-02: Failure of 2H Emergency Diesel Generator Jacket Water
Cooling Gasket Resulting in Inoperability During Dual Unit LOOP.
1J & 2J EDG Jacket Water Cooling Pumps Missing Orifice Plate
Following the seismic event on August 23, 2011, and subsequent failure of the 2H EDG,
all four EDGS were subject to thorough inspection and corrective maintenance. On
September 3, 2011 during a post-maintenance EDG run, a leak was observed on 1J
EDG engine-driven jacket coolant water pump. When the pump was removed for
rebuild, it was discovered the pump did not have an orifice plate installed on the
discharge of the pump. The orifice plate was subsequently found still attached to the
discharge flange of the previously removed pump. An extent of condition was performed
Enclosure
26
and it was observed that the 2J EDG was also missing its orifice plate on the jacket
cooling water pump.
A missing orifice plate on the jacket cooling water pump discharge flange can cause
increased flow and pressure in the jacket cooling system, which in turn can cause 1)
operating pressures to reach limitations; (2) degraded cooling capabilities; and (3)
potential pipe strain that could lead to leakage or pump and piping fatigue. An installed
orifice plate creates a pressure drop and corresponding decrease in flow throughout the
system. As flow decreases, the temperature delta must increase to maintain the same
amount of heat removal. It was determined the 2J EDG was missing its orifice plate
since the last time it was worked on in 2004. A review of past performance data for the
2J EDG (back to 2005) was conducted and it was observed that due to the increased
parameters, the temperature delta is lower at full load than normally (4-5 deg. vs. 10-14
delta T normally). Additionally, the 2J engine has required more work input from the
engine which lowered the available horsepower to turn the electrical generator; however,
past surveillance testing has demonstrated the ability of the 2J EDG to reach rated load.
Because the degraded 2J EDG engine driven coolant pump caused some parameter
changes on the 2J EDG and could have caused some degradation to the diesel since
2004, additional review by the NRC will be needed to determine whether the missing
orifice plate represents a performance deficiency. An unresolved item will be opened
pending completion of this review. The issue will be identified as URI 05000338,
339/2011011-03: Missing Orifice Plate on 1J and 2J EDG.
Enclosure
27
6.0 Electrical System Performance
a. Inspection Scope
The team performed the following actions to evaluate the performance of the electrical
system of the station:
The team evaluated the electrical perturbations at the site during and subsequent to the
earthquake, and until offsite power was restored to all emergency buses:
- Reviewed CRs generated during and subsequent to the seismic event pertaining to
electrical perturbations or anomalies, equipment failures and spurious equipment
actuations.
- Conducted independent visual inspections and walkdowns of a sample of safety
related 4160V load centers, 480V motor control centers (MCCs), inverters, batteries,
and battery chargers on both units to assess the general condition of systems and
components to determine whether there was visible evidence of damage or
significant movement as a result of seismic activity
- Observed licensee staff during electrical system walkdowns to examine the interior
condition of electrical cabinets and control panels for cracks in frames, termination
and component integrity; instrument or wire damage
- Reviewed the plant computer systems (PCS) raw data sequence of events to
determine whether equipment performed as expected or abnormal indications or
alarms were received during or subsequent to the seismic event
- Reviewed electrical distribution system voltage and current chart recordings during
and subsequent to the seismic event
The team evaluated the performance of the supervisory and protection relaying and
lockouts for the sites electrical distribution system:
- Reviewed CRs generated during and subsequent to the seismic event pertaining to
electrical system protection, relays, flags and spurious breaker actuations
- Interviewed licensee staff to discuss all relay flags, lockouts and trips to determine
how each protective function was addressed
- Reviewed vendor documentation on associated protection devices
The team reviewed the performance of the RSSTs, and others where applicable, in
response to the seismic event and the probable cause(s) of the transformers failure:
- Reviewed design drawings associated with the station switchyard and substation.
- Conducted interviews with licensees electrical power and transmission and
distribution personnel involved in the licensees review and investigation
- Reviewed the sequence of events and alarm data to develop a comprehensive
understanding of the event progression as well as the restoration of the RSSTs
The team evaluated the licensees implementation of vendor recommendations
regarding the performance of transformers during the seismic event.
Enclosure
28
b. Observations and Findings
The team identified one URI associated with 1J EDG frequency oscillations that is
described in this section. The team concluded that ground motion from the earthquake
was the probable cause of sudden pressure trips and bushing damage affecting some
transformers that contributed to the loss of offsite power.
4160VAC, 480VAC Electrical Buses - Normal and Emergency
The licensee did not identify any abnormal or erratic electrical issues during or
subsequent to the initial seismic event. The following relays were noted to have had
ground targets, which caused their associated breakers to trip:
U1 Station Service 4160V Bus 1A U1 Station Service 4160V Bus 1B
- Breaker 15A3 - Breaker 15B3
- Breaker 15A5 - Breaker 15B5
- Breaker 15A6 - Breaker 15B7
- Breaker 15A7 - Breaker 15B10
- Breaker 15A9
- Breaker 15A10
U2 Station Service 4160V Bus 2C U2 Station Service 4160V Bus 2A
- Breaker 25C6 - Breaker 2A
The licensee attributed the breaker trips to seismic induced vibration. These station
service breakers were not seismically qualified and not safety-related. Each occurrence
was evaluated to ensure no actual damage or fault existed and was subsequently reset.
The licensee took a tiered approach to evaluating the functionality and operability of the
electrical system. The first phase of this approach, post-shutdown, included focused
visual inspections of a preselected sample of safety and non-safety related electrical
equipment considered most likely to be damaged from a seismic event. These
inspections included 100 percent walkdowns of all equipment, external to operating
cabinets and electrical switchgear. No seismic related deficiencies were identified. The
approach was then expanded and subsequent internal visual inspections were
conducted in accordance with 0-GEP-30 Post Seismic Event Engineering Walkdown
and are categorized in the table below.
Component % Complete Findings
Transfer Buses 100% No Seismic Damage Noted
4160V Switchgear 96% No Seismic Damage Noted
480V Load Centers 95% No Seismic Damage Noted
Batteries 100% No Seismic Damage Noted
- Information obtained from OD 000442, Revision 0
Enclosure
29
100 percent of the internal inspections were not completed for the 4160V Switchgear
and 480V load centers due to the current plant configurations, which did not allow an
open cubicle inspection. A sample set of about 96% (53 of 55 breaker cubicles) of
4160V Switchgear was completed. Likewise, a sample set of about 95% (600 of 632
breaker cubicles) of 480V load centers was completed. The remaining 5% were not
internally inspected due to current plant configurations. The team confirmed that the
electrical cubicles that would not be inspected due to plant configurations were
inspected on a periodic frequency consistent with the licensees preventive maintenance
program.
At the time of the Augmented Inspection observations, the licensee had completed
visual-only inspections of the electrical system equipment. The licensees Mode 5
Operability Determination (OD) 000442 stated that no deficiencies were identified that
would prohibit any system component from being considered functional and fully capable
of performing its design function. The team questioned relying on the results of visual
walkdowns and inspections to determine electrical equipment reliability. The licensee
indicated that further inspection and full surveillance testing would be conducted on
electrical system equipment prior to its return to a fully operable status. The licensee
had developed a recovery plan for the electrical system, which included the following:
- Calibration and functional testing of protective relaying for all electrical equipment
4160VAC, main generators, oil-filled transformers, and transfer buses
- Dead bus inspections of 4160V bus work and fast transfer post maintenance tests
(PMTs) and verification
- Crawl-through visual inspections of the interior of both units isophase bus duct,
which included all insulators and bus work
- Segregated isophase bus duct hi-pot/megger testing for both the main and station
service transformers to identify any potential leakage current which would be
indicative of damaged insulator material
- De-energized disconnect switch inspections
Based on interviews with the licensees electrical power personnel involved in the
investigation, independent review of licensee inspection activities and independent
random equipment selection for visual inspection, the NRC inspection team concluded
that the licensees actions with regard to these electrical perturbations were appropriate.
Following the seismic event and the subsequent LOOP, all four station EDGs started
and loaded onto their respective emergency buses. The AAC DG started automatically
and was manually aligned to the proper bus. All relay logic and load sequencers
appeared to have worked properly during the initial event. No unexpected alarms
related to the station EDGs were received at the onset of the event. About 45 minutes
after the seismic event, the 2H EDG developed a coolant leak that required the engine to
be manually secured. A diesel trouble alarm was received in the control room during
Enclosure
30
this time period due to alarms at the local control panel. Although a confirmed record of
which alarms were locked in was not available, firsthand accounts from the event did not
reveal any unexpected conditions. Annunciators associated with the jacket water
coolant leak were lit on the local annunciator panel following engine shutdown, all of
which were expected based on current plant conditions. The licensee did not identify
any instrumentation, relay or breaker issues that negatively impacted the EDG
performance during the response to the seismic event. Report Section 5.0 provides a
more detailed account of EDG performance and the 2H EDG jacket water coolant leak.
1J EDG Frequency Oscillations
Following the seismic event on August 23, 2011, while the 1J EDG was supplying power
to the 1J emergency bus, control room operators identified frequency oscillations on the
1J EDG bus as well as 1-III and 1-IV inverter momentary trouble alarms when the
pressurizer heaters were cycled. During personnel interviews, bus frequency was
reported as oscillating between 59 and 61Hz. The inspectors noted a Technical
Specification Limit of 59.5 and 60.5Hz. Engine load cycled between 1600 and 2000KW
while the 1J EDG was supplying power to the bus, varying as pressurizer heater loads
cycled. The PCS did not have a data point for emergency bus frequency so actual
emergency bus frequency was not recorded and could not be conclusively obtained.
The licensee entered this issue into the corrective action program as CR 440231.
There was a PCS data point that indicated engine speed (rpm), which could have been
used to calculate frequency with quality data available; however this PCS point for the 1J
EDG was very noisy during the event and could not provide any useful data to determine
the magnitude of frequency oscillations. All four EDG speed points on the PCS were
trended using engine run data since the seismic event occurred. Each engine was
operating parallel to the grid (stable at 900rpm) to observe stability of the data point.
There was noise in each data point: 1H, 2H and 2J showed oscillations of 20-30rpm
when paralleled and had a nominal speed indication between 895 and 920rpm. The 1J
data point showed oscillations of 100rpm in isochronous mode and when paralleled to
the grid and could therefore not be used to conclusively determine the 1J emergency
bus frequency. This data point was used for indication only and was not related to
actual engine stability.
On September 5, the licensee conducted a PMT of the 1J EDG in manual mode. During
that run, a troubleshooting sheet was prepared in response to CR 440231 and qualified
test equipment was used to measure engine frequency/voltage, electronic governor null
voltage, and the PCS rpm data point. Frequency responded as expected when control
was switched from the mechanical governor to the electric governor actuator and was
measured stable at 60.2Hz. The licensee was not able to test the 1J EDG in
isochronous mode, which was the configuration during the event due to current plant
conditions; however, the licensee was scheduled to recreate the scenario during the
upcoming refueling outage. The engine RPM indication is a separate issue that may
also be addressed during this evolution. An unresolved item will be opened pending
completion and results of licensee testing. This issue will be identified as URI
05000338, 339/2011011-04, 1J EDG Frequency Oscillations.
Enclosure
31
Distribution System
The North Anna Power Station switchyard consists of three single phase, generator
step-up transformers (GSUs), one per unit, which supply normal power to the station
through two, 3-phase SSTs. There are three, 3-phase RSSTs, shared between both
units, which are the preferred source of supply power to the emergency buses. Within
seconds of the seismic event, GSUs 1-EP-MT-1A; 2-EP-MT-1A, 1B, 1C; all RSSTs; SST
1-EP-SST-1C and switchyard transformer #2 all tripped due to sudden pressure relay
actuations, thereby causing a LOOP to both units. The licensees systems engineering
and control operations personnel conducted visual inspections of the distribution system
equipment and relay flags/targets were recorded and addressed. The likely cause of
relay actuations was attributed to seismic induced vibrations experienced during the
seismic event.
The 230kV line tripped and locked out due to a line-to-line fault from an offsite
substation. This perturbation was automatically isolated and did not have any adverse
affect on the North Anna switchyard or any plant parameters, however it was recorded
by the switchyard digital fault recorder. No other protective relay targets or deficiencies
were identified. The licensees corporate Fault Analysis Group reviewed the fault
recorder data in the switchyard remotely and determined that no fault current was seen
flowing through the transformers onsite during the seismic event. This figure will aid in
understanding the details of this event.
Enclosure
32
Figure 12, North Anna Simplified Electrical Power Distribution
The sudden pressure relay is designed to minimize the possibility of transformer tank
damage resulting from internal pressure buildup by detecting rates of pressure increase
in excess of the safe limits established by the transformer manufacturer. According to
vendor documentation, the relays are designed such that they will not be actuated by
vibration, mechanical shock, or pump surges. However it was noted in the vendor
information that vibration amplitude of installed relays should be minimized. Changes in
transformer internal pressure deflect a sensing bellows and responding control bellows
that are part of a closed hydraulic system filled with silicone oil. A temperature
compensating control orifice in the line of one of the control bellows causes differential
deflection of the two control bellows when fluid flow in the system exceeds calibrated
values. As this differential deflection occurs, a linkage positioned on these control
bellows actuates a snap switch, tripping a circuit breaker that de-energizes the
transformer. When equilibrium between the two control bellows is reached, the snap
switch resets automatically.
Each phase of the station GSUs has three sudden pressure relays installed horizontally
on the tank wall along the same plane. The GSU circuit breakers open and lockout
when two out of the three sudden pressure relays are actuated on either phase. This de-
energizes the SSTs and the normal power supply to the station. The RSST circuit
breakers open and lockout when a singular sudden pressure relay is actuated, thereby
Enclosure
33
de-energizing the preferred power supply to the emergency buses. During the seismic
event, the following sudden pressure relays actuated:
Unit 1 GSUs - TRIPPED Unit 2 GSUs - TRIPPED
Phase A: 3 Relays (3 Actuated) Phase A: 3 Relays (3 Actuated)
Phase B: 3 Relays (0 Actuated) Phase B: 3 Relays (3 Actuated)
Phase C: 3 Relays (0 Actuated) Phase C: 3 Relays (3 Actuated)
Unit 1 SSTs - TRIPPED Unit 2 SSTs - NO TRIP
Phase A: 3 Relays (0 Actuated) Phase A: 3 Relays (0 Actuated)
Phase B: 3 Relays (1 Actuated) Phase B: 3 Relays (0 Actuated)
Phase C: 3 Relays (3 Actuated) Phase C: 3 Relays (0 Actuated)
RSSTs - ALL TRIPPED 36.5kV XFMRs - TX 2 TRIPPED
RSST A: 1 Relay (1 Actuated) TX 1: 3 Relays (0 Actuated)
RSST B: 1 Relay (1 Actuated) TX 2: 3 Relays (3 Actuated)
RSST C: 1 Relay (1 Actuated) TX 3: 1 Relays (0 Actuated)
The licensees electric transmission and distribution personnel evaluated the probable
causes of the sudden pressure relay operation. The following were preliminarily
identified:
- Sudden pressure rise in the transformer oil tank was caused by the earthquake
vibrations. Basis: When a transformer is subjected to the three-dimensional random
ground motions of the magnitude experienced at the station, substantial forces
produce vertical and horizontal accelerations, which will cause a rapid pressure rise
on the sudden pressure relay, thereby inducing actuation.
- Improper operation of the sudden pressure relay mechanism. Basis: The impact of
the seismic vibrations on the springs and micro-switch internal to the relay may
cause the micro-switch to operate improperly. The seal-in package will permanently
preserve the improper operation of the relay before a manual reset occurs. Two
relays could operate improperly at different times and the 2 out of 3 voting scheme
will still trip the lock-out due to the memory of the relays internal seal-in package.
- Relay seal-in circuit malfunction. Basis: It is possible, however unlikely, that the
normally opened and normally closed contacts of the auxiliary relays that create the
seal-in circuit (diagramed below) could both change state inadvertently at the same
time, due to the seismic event and thereby energize the auxiliary relay. The two
contacts would be actuated and the relay would remain in the improper state.
Enclosure
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Figure 13, Dominion Seal-In Package Schematic
The licensee noted that thorough seismic tests and analysis need to be performed on
the sudden pressure relay and the Dominion in-house seal-in circuit to confirm or refute
their possibilities as the root cause of the sudden pressure relay operations.
The team also reviewed the electrical distribution system voltage and current chart
recordings during and subsequent to the seismic event. There were no indications of
electrical faults present on the switchyard side of the GSUs on Unit 1 or Unit 2. There
were no indications from the chart recordings or the Digital Fault Recorders (DFRs) of
electrical faults on the 34.5kV buses. The chart recordings indicated that Unit 1 GSUs
tripped first and voltages were still present for about four cycles likely as a result of the
lowside unit breaker at the site opening slightly later than the breakers in the switchyard.
The Unit 2 GSU voltages remained and eventually decayed over time due to the residual
field voltage.
After review of vendor information, interviews with the licensees electrical personnel
responsible for this investigation and review of the licensees cause evaluation for the
actuation of the sudden pressure relays, the team concluded that the protective relaying
functioned as expected when subjected to a seismic event. This equipment is not
seismically qualified and can be susceptible to actuation resulting from pressure rises
caused by seismic activity. The team also concluded that all recorded data showed that
the electrical distribution system equipment functioned as expected with no signs of
electrical faults. The licensee was evaluating several mitigation options with regard to
supervisory and protection relaying in effort to make the emergency offsite power source
more reliable during future seismic events.
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Switchyard Damage
The licensee initiated walkdowns and conducted visual inspections of the switchyard and
the RSSTs to verify the status of offsite power. Technicians noted oil leaks from all six
of the GSUs. As a result of the seismic event several high voltage bushing seals were
compromised. A total of eight 500kV bushings were damaged on Unit 1 and 2 GSUs
(six main transformers and two spares). The licensees transmission and distribution
personnel identified that, in all cases, the upper porcelain shifted and compromised the
lower seal between the busing flange and upper porcelain. The bushings were not
seismically qualified and are therefore susceptible to damage and failure during a
seismic event. This issue was entered into the licensees corrective action program.
The bushings were scheduled to be returned to the vendor for inspection, test,
disassembly, and re-gasket. The licensee was also evaluating the procurement of
seismic rated bushings to replace the damaged bushings as a long-term mitigation
option.
On September 10, 2011, while performing routine maintenance on the current
transformer for the 500kV generator breaker G202 on Unit 2, the licensee removed the
upper bellows protective cover for inspection and identified that some of the support
blocks had broken and the lower bellows support arm had been displaced. The
transformers were not seismically qualified and are therefore susceptible to damage and
failure during a seismic event. All six current transformers on Unit 2 were subsequently
inspected and no additional damage was identified. The licensee attributed this damage
to have been caused by the seismic activity due to the earthquake. The licensees
electric transmission and distribution personnel were reviewing this issue and current
transformers for Unit 1 generator breakers were scheduled to be inspected prior to
switchyard restoration.
Restoration of RSSTs
The licensees systems engineering and control operations personnel performed the
following actions to verify the status of the RSSTs after the seismic event:
oil leaks
tube bus and cables, lightning arrestors and control cabinet equipment were all
visually inspected for damage
- The 480VAC supply from the station to the control cabinet was verified by checking
the LTC controllers in the A and C RSSTs and all annunciator flags/targets were
recorded and addressed
- The position indicator on the LTC was verified to be in the appropriate position and
all ground connections to the main tank were intact
Licensee personnel reported that all electrical connections and physical conditions for
the RSSTs appeared to have performed satisfactorily during the event.
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All three RSSTs tripped and locked out due to their respective sudden pressure relay
actuations on one-out-of-one logic devices. The licensee also confirmed the status of
the differential relays in the Emergency Switchgear Room monitoring the RSSTs and
noted that there were lockouts for each RSST, but no relay targets. No other abnormal
indications were identified. The licensees corporate Fault Analysis Group reviewed the
fault recorder data in the switchyard remotely and determined that no fault current was
seen flowing through the transformers onsite during the seismic event. The licensee
then locally performed a dissolved gas analysis (DGA) on the RSSTs in the priority of
RSST C, B, then A. This was a decision made by the technical support staff in the
Technical Support Center (TSC). Priority was given to RSST C because its supply bus,
34.5kV bus #3 was available, which normally supplies power to the 1H and 2J
emergency buses. In addition, RSST C supplies power to the TSC through the Unit 2 G
bus, which has a crosstie capability allowing it to supply power to the Unit 1 G bus using
the 15G10 breaker. It should be noted that the 15G10 breaker had an 86 lockout
present due to a station load shed signal being present. The station load shed actuated
from the SSTs and GSUs tripping earlier in the event. This lockout delayed the return to
service of the 15G10 breaker. RSST C was released and restored at about 4:30 p.m. on
August 23. RSST B was given second priority and would supply power to the 2H
emergency bus and the 1G bus, which is its normal supply. This would also allow the
SBO diesel to be secured, which was supplying power to the 2H emergency bus as a
result of the jacket water leak on the 2H EDG. Before RSST B was restored to service,
the licensee aligned it to the 34.5kV bus #5 due to the switchyard Transformer #2
lockout from its sudden pressure relay, which had not yet been fully restored. RSST B
was released and restored at about 5:30 p.m. on August 23. Lastly, at about 6:30 p.m.
RSST A was restored which would supply power to the 1J emergency bus. Transformer
- 2 was subsequently evaluated and released at about 7:00 p.m. on August 23, 2011.
Vendor Recommendations Regarding Transformer Response During Earthquakes
RSST A and C are original to the station. RSST B was replaced in March of 1985. Both
Unit 1 and 2 have newer GSU transformers, which were installed in 2004 and 2005,
respectively. Neither GEK-35003, General Electric Instruction Manual for Reserve
Station Transformers nor VTM-59-M947-0003 GSU Transformer Replacement for
Units 1&2 specify recommendations to prevent or mitigate the effects of a seismic event
on the installed transformers. Likewise, these documents did not stipulate a service or
end of life for the transformers. The licensee indicated that the preventative
maintenance program monitors dissolved gases and trends equipment performance to
determine the need to replace equipment. The team reviewed the transformers
component health report, which reflected deficiencies independent of the seismic event.
The team did not identify any issues in this report affecting seismic vulnerability. There
were no indications of issues with regards to dissolved gases, however the licensee
planned to replace the RSSTs and upgrade the electrical power system in the near
future.
Enclosure
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7.0 On-Shift Human Performance
The team conducted an overall and independent review of On-shift Human Performance
to determine if licensee staff responded properly during the event, procedures were
adequate, and to better understand the licensees decision making process. The
following areas were specifically addressed and are discussed in more detail in the
following sections:
- Determine whether emergency operations procedures (EOPs) were performed
consistent with training
- Verify proper and timely response to identifying and reacting to the 2H EDG failure
- Review the restoration of offsite power through the RSSTs
- Review the timeliness and adequacy of Emergency Planning declarations during the
event
- Evaluate immediate operator response with regard to the guidance in Regulatory
guide 1.166, Pre-Earthquake Planning and Immediate Nuclear plant Operator Post
Earthquake Actions
Additionally, the team reviewed the licensees corrective actions, causal analysis, and
extent of condition, with respect to On-shift Human Performance.
7.1 Emergency Operating Procedures (EOPs)
a. Inspection Scope
The team conducted an independent review of control room activities with respect to the
EOPs to determine if licensee staff responded properly during the events. The team
also reviewed the licensees implementation of abnormal, alarm and normal operating
procedures used during the event. The review included the effectiveness of the
procedures in addressing the event. With respect to operator awareness and decision
making, the team was specifically focused on the effectiveness of control board
monitoring, communications, technical decision making, and work practices of the
operating crew. With respect to command and control, the team specifically focused on
actions taken by the control room leadership in managing the operating crews response
to the event. The team performed the following activities in order to understand and/or
confirm the control room operating crews actions to diagnose the event and implement
corrective actions:
- Conducted interviews with control room operations personnel on shift during the
event
- Reviewed procedures, narrative logs, event recorder data, system drawings, and
plant computer data
- Reviewed the crews implementation of emergency, abnormal, and alarm procedures
as well as Technical Specifications
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- Reviewed Operations administrative procedures concerning shift manning and
procedure use and coordination
b. Observations and Findings
The team concluded that EOPs were performed consistent with training. The team
determined that operators exhibited fundamental operator competencies when
responding to the event while using EOPs. Specifically, the team determined that the
operating crew identified important off-normal parameters and alarms in a timely manner
for the external seismic event and the subsequent LOOP. Additionally, the team
determined that crew supervision exercised effective oversight of plant status, crew
performance, and site resources.
Monitoring of Plant Parameters and Alarms
Through a review of plant data, the team determined that the crews response to the
seismic event was effective in stabilizing the plant. Through interviews and review of
plant data, the team determined that the crew recognized the seismic event and
resulting LOOP. Based on interviews, the on-shift crews for each unit assessed the
plant conditions as being consistent with what was experienced during simulator training
for a LOOP.
Based on the sequence of events, a review of plant data, and operator interviews, the
team concluded that the LOOP prevented the normal access to plant online Alarm
Response Procedures (ARPs) because the document server was powered from offsite
power. The procedures were available in the control room as paper copies. EOPs and
Abnormal Procedures (APs) were readily available during the event with no delay.
Based on operator interviews, the team concluded that the operators completed a
satisfactory review and evaluation of alarm conditions after the event.
Command and Control
Based on NRC inspector observations during the event and interviews and a review of
plant data, the team determined that the Shift Manager (SM) and Shift Technical Advisor
(STA) maintained oversight of the plant, which included awareness of major plant
parameters such as RCS temperature and pressurizer level, during the event. Based on
observation and interviews, the team determined that the SM effectively managed the
frequency and duration of crew updates and crew briefs during the event. Crew updates
were reasonable based on the implementation of EOPs. The team concluded that the
SM and Control Room Supervisor (CRS) ensured monitoring and diagnosis of key major
plant parameters, such as RCS temperature, pressurizer level, and VCT level, by control
room crew members.
Based on a review of plant data, the team concluded that the management expectation
for establishing positive control of equipment configuration was implemented by the
operating crew. Through interviews and a review of plant data and alarm response
Enclosure
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procedures, the team determined that the SM and CRS ensured that sufficient
information necessary to assess abnormal electric plant status was collected and
evaluated prior to performing steps within a procedure that assumed a normal electric
plant configuration.
During interviews, operators stated that the loss of the document computer for ARPs
was not a common scenario in training packages. The licensee was considering
addressing this in their training program. The team determined that the loss of the
document computer only affected ARPs and did not significantly affect operator
performance during the event.
Resource Utilization
Through interviews, the team determined that the Balance of Plant (BOP) operators and
off-shift operators were available to assist the control room operators in recognizing and
diagnosing off-normal issues. The seismic event occurred on dayshift which provided
additional resources to the control room crew. The utilization of operators during the
dual unit trip was adequate.
Other Operating Procedures
The team observed that procedure 1-AR-F-D8, Turbine Driven AFW Pump Trouble or
Lube Oil Trouble did not state that the low lube oil level switch was powered from non-
vital power. Upon a loss of power, the lube oil level switch will generate an alarm signal
and the alarm, which has a different power source, will activate. The alarm procedure
did not recognize this issue. During interviews, operators revealed they were unsure as
to why the alarm was lit and the issue required additional troubleshooting. This resulted
in a short delay in the alignment of the Unit 1 terry turbine AFW pump to the steam
generator. An unresolved item will be opened pending completion of this review. The
issue will be identified as URI 05000338, 339/2011011-05: Unit 1 Turbine Driven
Auxiliary Feedwater Pump Trouble Alarm.
7.2 Station Black-Out Diesel Generator
a. Inspection Scope
Information was obtained from inspector observations during the event, interviews with
the operating crew, system descriptions, event sequence of event, plant computer data
and narrative logs to support this review. The team reviewed operator performance to
determine whether operator actions were consistent with approved procedures, TS, and
training. The team compared this to training received for a LOOP and the plant
response to this event as demonstrated by the operation of the SBO DG.
b. Observations and Findings
The team concluded that operators responded in accordance with procedures for the
SBO DG and that training contributed to the understanding of the plant response during
Enclosure
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the event. The team did not identify significant issues related to operator response
during the LOOP event for the operation for the SBO DG.
The team observed that procedure OP-6.4 Operation of the SBO Diesel (SBO Event)
contained a step to insert a synch key required for alignment of the SBO DG. The key
was not readily available to the crew in the field during the event. This resulted in delay
of about 7 minutes in the alignment of the SBO DG to the 2H bus. The team determined
that the delay was not consequential during this event. The licensee included this issue
in their corrective action program.
7.3 2H Emergency Diesel Generator Failure
a. Inspection Scope
Information was obtained from inspector observations during the event, interviews with
the operating crew, system descriptions, event sequence records, PCS data and
narrative logs to support this review. The team reviewed operator performance to
determine whether operator actions were consistent with approved procedures,
Technical Specifications, and training. The team compared operator response to
training received for a LOOP and the plant response to this event as demonstrated by
the operation and subsequent failure of the 2H EDG.
b. Observations and Findings
The team concluded that operators responded to the 2H EDG failure in accordance with
approved procedures.
From interviews, the team determined that the control room operators, in responding to
the event, relied on actions and guidance described in APs. From a review of the plant
procedures used by operators to respond to this event, there were no significant issues
identified.
During operator interviews, when the LOOP was experienced, operators stated that
access to the EDG rooms was delayed because power was lost to some access control
systems. This affected normal access for personnel entering the plant after the event.
The team determined that procedures were implemented to make keys available to
security personnel and operators, and that delays experienced obtaining keys were not
consequential. The licensee included this issue in their corrective action program.
Enclosure
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7.4 Restoration of Offsite Power
a. Inspection Scope
Information was obtained from inspector observations during the event, interviews with
the operating crew, system descriptions, event sequence records, plant computer data
and narrative logs to support this review. The team reviewed operator performance to
determine whether operator actions were consistent with approved procedures, TS, and
training. The team compared this to training received for a LOOP and the plant
response to this event as demonstrated by the operation and subsequent realignment of
the RSSTs.
b. Observations and Findings
The team concluded that operators responded in accordance with approved procedures
in the restoration of offsite power.
Based on interviews, the team determined that the SM used technical resources
available in the TSC for performing an assessment of damage to the electric plant before
the crew reset the RSSTs. The team noted that such assessments were able to
determine the sudden pressure lockout condition on the RSSTs. Report Section 6.0
provides additional discussion on restoration of offsite power.
The team determined that the licensee adequately identified and documented causes
specific to the event as well as immediate and proposed corrective actions.
7.5 Emergency Planning Declarations
a. Inspection Scope
The team reviewed the licensees implementation of the emergency preparedness (EP)
procedures used during the event. The review focused on the circumstances
surrounding the events to determine if the licensees EP classification and notifications
were appropriate and timely. The team interviewed members of the licensees
organization and other individuals involved with EP aspects of the event. The team
reviewed the event timeline, logs, statements by individuals who responded to the event,
the North Anna emergency action level (EAL) matrix, event notification worksheets, and
other documents related to EP classifications.
b. Observations and Findings
The team concluded that emergency planning declarations were appropriate. The team
identified one URI described in this section.
In order to determine the appropriateness of the EP classifications, the team performed
a detailed assessment of the event timeline with particular attention to those activities
that are entry points for the EAL matrix. On August 23, 2011, at 1:51 p.m., the site
Enclosure
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experienced a magnitude 5.8 earthquake with an epicenter twelve miles southwest of
the plant. Both reactors tripped. A LOOP occurred at 1:51:12 p.m. All four EDGs auto
started to their respective emergency bus (1H, 1J, 2H, and 2J) at 1:51:20 p.m. An Alert
was declared at 2:03 p.m. for HA6.1, SM judgment, due to an inability to enter the
seismic EAL for seismic event because the seismic monitoring panel earthquake trouble
alarm to notify operators of a seismic event did not illuminate. HA1.1, earthquake
response, required that the strong motion accelerograph peak shock annunciator
illuminates, which would indicate a seismic event greater than OBE (0.06g horizontal or
0.04g vertical) and an earthquake confirmed by any of the following:
- Earthquake felt in plant
- National Earthquake Information Center (NEIC)
- Control Room indication of degraded performance of any safety-related structure,
system, or component
The strong motion accelerograph peak shock annunciator did not illuminate.
The seismic monitoring panel has two recording systems, one provided by Kinemetrics
Inc. and the other provided by Engdahl. Both systems provide input to the main control
room via a common instrumentation panel on the Unit 2 side of the control room. All
sensors for the Kinemetrics system are located inside Unit 1 containment. The
Kinemetrics system has a seismic trigger, which activates at 0.01g in a any direction. In
addition, there is a seismic switch which activates at 0.04g vertical and 0.06 horizontal.
Neither the seismic switch nor the seismic trigger activated the earthquake trouble
alarm. Locally at the seismic panel, the seismic trigger was activated and a tape
recording of the event was recorded. Therefore, operators determined that the seismic
monitoring panel was inoperable for making a decision about the strength of the
earthquake. The team determined that the lack of control panel alarm from the seismic
monitoring panel did not delay an Alert declaration, because the SM used HA6.1, SM
judgment.
Because of the issues identified with the seismic monitoring panel and because it is
used as an input for EAL decisions, additional review by the NRC will be needed to
determine whether this issue represents a performance deficiency. An unresolved item
will be opened pending completion of this review. The issue will be identified as URI
05000338, 339/2011011-06: Seismic Alarm Panel.
Personnel in the plant monitoring the 2H EDG reported the coolant leak to the control
room via face-to-face communication. Operators tripped the 2H EDG at 2:40 p.m. An
Alert was declared at 2:55 p.m. for SA1.1, AC power, for Unit 2, because the AC
capability was reduced to a single source with 2J EDG.
The team determined that notifications to the State and Counties and to the NRC
Operations Center were timely and accurate.
The Alert event was downgraded to a Notice of Unusual Event (NOUE) at 11:16 a.m. on
August 24, for HU1.1, seismic activity, due to the potential for aftershocks. The NOUE
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was exited on August 24, 2011, at 1:15 p.m. The decision to terminate the event was
based on the following: (1) no public issues existed that would necessitate the
continued activation of the State and County Emergency Operations Facilities; (2) the
licensees Outage Control Center had established a technical focus and was aligned for
the recovery activities; and (3) no additional aftershocks were received at the plant. The
team determined that downgrade of the Alert event at 11:16 a.m. was appropriate.
7.6 Post Earthquake Actions
a. Inspection Scope
The team reviewed the licensees processes and procedures established to adequately
plan and respond to a post seismic event in accordance with Regulatory Guide (RG)
1.166, Pre-Earthquake planning and Immediate Nuclear Power Plant Operator Post-
Earthquake Actions, dated March 1997. The team reviewed multiple procedures used
to respond to a seismic event. The team also conducted interviews with the licensee
personnel involved in the response to the seismic event. The seismic data collected after
the event and manner in which this data was collected and processed was evaluated by
the team. Finally, the team reviewed relevant/critical CRs developed during the
licensees post seismic assessment.
b. Observations and Findings
Although the licensee is not committed to RG 1.166, based on the review conducted by
the team, the licensees program deviates from the guidance in this RG as listed below:
- Part B of the RG specifically states, This regulatory guide is based on the
assumption that the nuclear power plant has operable seismic instrumentation,
including the computer equipment and software required to process the data within 4
hours after an earthquake. The staff at North Anna at the time of the inspection did
not have a documented procedure or the ability to process the seismic data within
this time frame. Operators were unable to determine within four hours whether the
operational basis earthquake was exceeded in accordance with Section C.4 of RG
1.166.
- Regulatory Position 3.2.1, states, Only personnel trained in the operation of the
instrument should collect data. This statement is specifically in reference to seismic
instrumentation used to collect seismic data. Through interviews with the licensee
staff it was determined that at the time of the inspection a procedure to collect data
did exist but there were no members of the staff trained to implement the procedure.
- Part B of the RG specifically states, The data from the nuclear power plant's free-
field seismic instrumentation, coupled with information obtained from a plant
walkdown, are used to make the initial determination of whether the plant must be
shut down, if it has not already been shut down by operational perturbations resulting
from the seismic event. At the time of the inspection no free-field seismic
instrumentation existed as assumed by RG 1.166.
Enclosure
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As previously mentioned the licensee is not committed to RG 1.166.
The team determined that the seismic monitoring panel earthquake trouble alarm,
intended to notify operators of a seismic event, did not illuminate. The operators did not
see the control panel alarm lit after the earthquake, after the LOOP, or after the
emergency buses were powered from the EDGs. Operators determined that the seismic
monitoring panel was inoperable for making a decision about the severity of the
earthquake. Operators were therefore unable to make a rapid determination of the
degree of severity of the seismic event. The portion of the seismic monitoring panel that
provides immediate feedback as to the severity of the earthquake lost power during the
LOOP. It was powered from non-vital power. In addition, the panel has no electronic
memory. The magnetic tape recording system, which had a back-up power supply,
recorded the event. Additional discussion of this issue is in Section 7.5.
The team made the following additional observations with regard to RG 1.166:
- The seismic event tripped both Unit 1 and 2 reactors and the decision to shutdown
was not required based on seismic monitoring equipment.
- Operators and engineers were able to conduct plant walkdown inspections within
eight hours of the event and discovered no significant damage to plant systems in
accordance with EPRI NP-6695 as recommended with Section C.1.2 of RG1.166.
- Operators were able to take actions immediately after the earthquake in accordance
with Section C.2 of RG 1.166.
- Operators were able to take some actions for data collection after the earthquake in
accordance with Section C.3.2 of RG 1.166.
- The licensees procedure, AP-36, Seismic Event, incorporated guidance in Appendix
A of RG 1.166, but operable seismic instrumentation and equipment (hardware and
software) to process the data was not available. The licensee would have been able
to determine if OBE was exceeded by following Appendix A because an earthquake
of magnitude 5.0 or greater had occurred within 200km of the plant.
Enclosure
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8.0 Plant Parameters and Assessment
8.1 Unexplained Instrumentation Anomalies
a. Inspection Scope
During the post event review, the licensee identified some unexpected anomalies that
occurred during the event, related to safety related instrumentation. The team
independently reviewed event recorders, plant records, and interviewed personnel to
determine whether the licensee had identified and appropriately addressed any
observed equipment performance issues.
b. Observations and Findings
The team found that some plant instrumentation anomalies warranted follow-up. The
team identified one URI described in this section.
The licensee had identified and recorded a number of instrument anomalies, many of
which were attributed to the earthquake. Some examples of instruments affected
included:
- Minor perturbations in Units 1 and 2 Safety Injection Accumulator and Refueling
Water Storage Tank (RWST) levels
- Nuclear Instrumentation
- Loop 1C High Delta Temperature
- Hi-Hi Steam Generator Level
- RWST Chemical Addition Tank Temperature
The team questioned whether these anomalies were indications of actual parameter
changes in level, pressure, etc. due to the seismic event or false indications that were
seismically induced. If the indications were seismically induced, the team inquired
whether the instrument exceeded their seismic qualification or whether the seismic
qualification of the instrument was appropriate. The licensee planned to determine the
most likely cause of the anomalies through their root cause assessment of the August
23, 2011 seismic event.
Because some of the anomalies identified with the safety related instrumentation could
have been seismically induced and thus potentially calls into question the seismic
qualification of the instruments, additional review by the NRC will be needed to
determine whether this issue represented a performance deficiency. An unresolved item
will be opened pending completion of this review. The issue will be identified as URI
05000338, 339/2011011-07: Safety Related Instrumentation Anomalies.
Enclosure
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8.2 General Assessment
a. Inspection Scope
The team reviewed the licensees Probabilistic Risk Assessments (PRA) to select the
most risk significant systems and associated structures for physical walkdowns and
review. Sections 5.0 and 6.0 of this report contain additional information on walkdowns
and reviews of electrical systems. In addition, the team reviewed the licensees
Independent Plant Examination for External Events (IPEEE) report to identify structures
and systems most vulnerable to seismic activity for walkdowns and review. In addition
to selecting samples based on PRA and IPEEE, the team conducted general plant
walkdowns to include areas of potential interest, including but not limited to the Spent
Fuel Pool and the North Anna Dam.
The team observed walk-downs of safety related systems conducted by the licensee.
The team reviewed design drawings associated with the specific systems inspected by
the licensee. In addition, the team conducted walkdowns of systems already completed
by the licensee to verify any post seismic event damage was adequately documented by
the licensee. Historical walkdowns of systems and components conducted due to
routine maintenance were reviewed to determine if documented issues were classified
properly (new or existing). The team also conducted interviews with the licensee
personnel involved in the response to the seismic event. The seismic design
methodology contained in Final Safety Analysis Report (FSAR) was also reviewed to
determine the DBE for all safety-related structures and components. Finally, the team
reviewed relevant/critical CRs developed during the licensees post seismic assessment.
b. Observations and Findings
Based on the scope of the inspection, the team found no significant damage to the plant
related to the earthquake. Some equipment issues were experienced, as documented in
this report.
The licensee had assembled a seismic event response team to assess the overall
condition of safety-related system, structures, and components (SSC). The licensee
drafted two post seismic event inspection procedures based on EPRI Technical Report,
NP-6695, Guidelines for Nuclear Plant Response to an Earthquake, dated December
1989. The two procedures were established to provide guidance for structures and
systems visual inspections. The team reviewed procedure ER-NA-INS-104, Monitoring
of Structures North Anna Power Station, Revision 1 for structures that meet the
regulatory Requirements for Maintenance Rule and License Renewal that contribute to
the operation of the station. Procedure 0-GEP-30, Post Seismic Event System
Engineering Walkdown, Revision 1 was also reviewed for adequacy. This was used by
licensee personnel to provide guidance for performing a general condition assessment
of system based SSCs following a seismic event. During the review of these procedures
the inspection team noted a common issue in both procedures, in that neither procedure
directed its user to review past inspection history to determine if observed damage is
pre-existing or post seismic event damage. Conservatively all damage found was
Enclosure
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documented in a Deficiency Log and a corresponding CR was drafted. All damage
found was then cross-referenced on with previous historical inspection to determine if
the condition was a post-event issue or previously identified. This action was not
proceduralized but was currently being implemented by licensee staff conducting walk-
downs related to post-inspected activities.
The team directly observed a sample of walk-downs conducted by the licensee
engineering staff. Prior to the inspection observation, the pre-job brief was observed by
the team to verify safety and technical guidance was provided to licensee staff
conducting inspections. This briefing also verified that staff conducting walk-downs were
properly trained and qualified to the procedure being implemented.
After walkdowns were completed by the licensee, their plan was to conduct
Nondestructive Examination (NDE) on a sampling basis prior to start-up. This was
referred to as Owner Elective examinations above and beyond the requirements of their
Inservice Inspection (ISI) program. The NDE will be performed on a sample of
components based on previous NDE conducted prior to the earthquake to provide a
baseline for the NDE results.
In North Annas IPEEE report, seismic margin assessment was used with a review level
earthquake of 0.3g and a spectral shape given in NUREG/CR-0098. Only 13
component types were found to have a High Confidence of Low Probability of Failure
(HCLPF) capacity less than 0.3g and these components are identified in Table 3.2-1 of
the licensees IPEEE report. The licensee performed walkdowns of these components
with qualified and trained seismic review teams. The team reviewed the results of the
completed walkdown inspections performed by the licensee for these components. The
licensee had not completed these inspections for 120V AC Bus and 4160V emergency
buses at the time of the teams review. Based on inspections conducted at the time of
the review, the licensee had not identified any damage that was earthquake related.
However, the licensee had found several non-structural issues, e.g., grout cracking,
improperly installed bolt, insulation banding coming loose, and loose nuts, which the
licensee concluded were not earthquake related. These conditions were previously
identified during baseline inspections prior to the earthquake. The licensee issued a
number of CRs to correct these conditions.
The inspectors selected a representative sample of systems for walkdown based on
HCLFP capacity. These systems included Emergency Condensate Storage Tanks,
Refueling Water Storage Tanks, Refueling Water Chemical Addition Tank (Unit 1), and
Control Room Air Conditioners. The team also reviewed some design calculations for
selected components for determination of HCLPF capacities.
The team conducted a number of general plant walkdowns. The following includes the
results of system walkdowns, including those selected based on IPEEE HCLFP reviews,
where the team conducted a focused sample or where observations were made.
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Safety Injection System
The Safety Injection (SI) System as part of the Emergency Core Cooling System (ECCS)
will provide borated emergency cooling water to the reactor core for the entire spectrum
of RCS break sizes to limit core temperature, maintain core integrity, and provide
negative reactivity for additional shutdown capability. The Low Head SI System provides
core cooling in the event of a Design Basis Loss of Coolant Accident (LOCA), it provides
flow to the High Head SI pumps in the event of a safety Injection, and provides backup
core cooling during shutdown and refueling.
The team accompanied the licensee engineering staff on walkdowns of the SI system for
Unit 1. This inspection included an assessment of the SI low-head A and B injection
pumps for seal leaks and structural support damage. The inspections included pipe
sections leading into containment penetrations 61 and 62 for weld cracks and damage to
the penetrations entry points. The 1-SI-MOV-1885A and 1-SI-MOV-1885C MOVs were
also inspected for yoke crack and support damage due to the seismic event. Snubbers
were inspected for leakage and damage. These components were identified on drawing
11715-FM-096A to track the specific areas inspected. All walkdowns for the SI system
were completed during the time of inspection. The licensee was in the process of
conducting functional and performance testing to fully qualify this system. Based on
successful resolution of discrepancies noted during walkdowns, satisfactory testing of
SSCs and satisfactory performance, the SI system was considered operable/functional
but not fully qualified on Units 1 and 2 for Mode 5. Additional performance tests were
planned in order to make the system operable for all modes as a path to reactor start-up.
Service Water System
The Service Water (SW) system provides vital cooling to the following components
during normal and accident conditions: Core Cooling Heat Exchanger, main control room
chillers, charging pump lube oil coolers and gear box coolers, and the Instrument Air
coolers. Additionally, a 22.5 million gallon spray pond provides the function of Ultimate
Heat Sink when heat is transferred from the Recirculation Spray Heat Exchangers
(RSHX) to the SW system following a Containment Depressurization Actuation. The SW
system also provides backup cooling to the Spent Fuel Pool, Aux Feed Water system,
and Containment Air Recirculation Fan coolers in the event the normal cooling supply is
lost. The SW system is a diverse system consisting of four main SW pumps, two Aux
Service Water pumps, the spray pond, and two trains providing cooling to plant
components. During a Design Basis Accident, the SW system is cross-tied at the
RSHXs and acts as a single large system while still cooling both the accident and non-
accident units load.
The team conducted an independent walkdown of the SW pump and valve house for
Units 1 and 2. Prior to conducting the walkdown the team reviewed the walkdown
inspection report conducted by the licensee to identify areas of interest to the team. The
licensee SW system engineer accompanied the team during the walkdown to address
any questions the team had related to the system. This inspection was focused on an
assessment of the pump and valve house building structures and the condition of safety
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related components located in these structures. Specifically, the SW A and B pumps for
Units 1 and 2 were inspected for seal leaks and structural support damage. The special
Technical Requirements for settlement of both structures were evaluated to determine if
any excessive differential settlement was observed due to the seismic event. Post event
survey readings were taken by the licensee but the results were not available at the time
of inspection. Water-hammer restraints were inspected for evidence of plastic
deformation of connections and anchorage. These components were identified on
drawings 11715-FM-096A to track the specific structural elements and components
inspected and to determine original design configuration of each SSC. All walk-downs
for the SW system were completed during the time of inspection. The licensee was in
the process conducting functional and performance testing to fully qualify this system.
Based on successful resolution of discrepancies noted during the walkdown, satisfactory
testing of SSCs and satisfactory performance, the SI system was considered
operable/functional but not fully qualified on Units 1 and 2 for Mode 5. Additional
performance tests were planned in order to make the system operable for all modes as a
path to reactor start-up.
Refueling Water Storage Tank
The RWST supplies borated water to the Chemical and Volume Control System (CVCS)
during abnormal operation conditions, to the refueling, and to the ECCS and the Quench
Spray System during accident conditions. This component is an IPEEE component and
has a seismic capacity less than 0.3g under their IPEEE. All other IPEEE systems and
components with seismic capacities less than 0.3g were given additional evaluations
under the Seismic Qualification Utility Group (SQUG), Generic Implementation
Procedure (GIP) for Seismic Verification of Nuclear Plant Equipment, Revision 2 (GIP-
2). The GIP-2 was developed by SQUG in response to Unresolved Safety Issue (USI)
A-46. This additional evaluation was to verify each component maintained the
requirements of the criteria established in the GIP-2.
During a review of the licensees design drawing (Drawing # 11715-FV-44A, Refueling
Water Storage Tank, Revision 7), the team identified a note that appeared to indicate
that the tank was designed for a horizontal acceleration of 0.69g and vertical
acceleration of 0.35g. Table 3.2-1 of the licensees IPEEE report indicates a HCPLF
value of 0.18g. The team requested a clarification of this discrepancy. The licensees
response indicated that the basis for the acceleration values shown on the drawing is not
known. The tank was evaluated during the licensees response to USI A-46 and IPEEE.
The team reviewed the licensees calculations in the A-46 evaluation (Calculation #
52308.04-C-004, A-46 Evaluation of Refueling Water Storage Tank, Revision 3, dated
March 15, 1999), and the HCLPF calculation, (Calculation # 52182-C-039, Seismic
Margin HCLPF Calculations for Refueling Water Storage Tank, Revision 2, dated April 5,
1997). The calculation documented the basis of the current HCLPF value of 0.18g for
the RWST. Based on the review of the actual earthquake response spectrum record, it
appears that the spectral acceleration at the frequency of interest for the measured
earthquake would result in exceeding the HCLPF capacity of the RWST.
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The team conducted an independent walkdown of the RWST for Unit 1. Prior to
conducting the walkdown the team reviewed the walkdown inspection report conducted
by the licensee to identify areas of interest to the team. A licensee staff member
accompanied the team during the walkdown to address any questions the team had
related to the system. This inspection was focused on an assessment of the external
tank structure and foundation. The team observed the condition of the foundation pad
and weld and bolt anchor connections. One lose anchor bolt was identified by the
licensee and determined to exist prior to the seismic event. The licensee also identified
one area where grout under a base plate spalled but this was also determined to be
existing prior to the seismic event. The licensee was monitoring the tank level, (which
remained constant) for evidence of damage due to the seismic event. A review of
seismic calculations was conducted by the team to determine the structural design
margin. This review also included an evaluation of Dominion design drawing 11715-FV-
44A to verify structural elements and components are installed as designed. All walk-
downs for the RWST were completed during the time of inspection. The licensee was in
the process conducting testing to fully qualify this component.
Refueling Water Chemical Addition Tank
Per request of the team, the licensee provided information concerning how the tank was
connected to the support shroud. This information indicated that the 11/16 thick tank
shell was attached to the 5/8 thick support skirt via a 3/4 circumferential weld. A review
of licensees design drawing, 11715-FV-65A-4, Refueling Water Chemical Additional
Tank, identified a note that appeared to indicate that the tank was designed for a
horizontal acceleration of 1.84g and vertical acceleration of 1.23g. Table 3.2-1 of the
IPEEE report indicated a HCPLF of 0.19g. The team requested clarification of this
discrepancy. The licensee indicated that the basis for the acceleration values shown on
the drawing was not known. The inspectors reviewed licensees HCLPF calculation,
52308.04-C-005, Seismic Margin HCLPF Calculations for Refueling Water Chemical
Additional Tank, dated February 26, 1997. The calculation documented the basis of the
current HCLPF value of 0.19g for this tank. Based on the review of the actual
earthquake response spectrum record, it appeared that the measured earthquake would
result in exceeding the HCLPF capacity. The team performed a walkdown of the tank
and no significant issues were identified.
Internal Containment Structure
The containment consists of the concrete reactor building, its steel liner, and the
penetrations through this structure. The structure is designed to contain radioactive
material that may be released from the reactor core following a design basis LOCA.
Additionally, this structure provides shielding from the fission products that may be
present in the containment atmosphere following accident conditions.
The containment is a reinforced concrete structure with a cylindrical wall, a flat
foundation mat, and a hemispherical dome roof. The inside surface of the containment
is lined with a carbon steel liner to ensure a high degree of leak tightness during
operation and accident conditions. The concrete reactor building is required for
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structural integrity of the containment under DBE conditions. The steel liner and its
penetrations establish the leakage limiting boundary of the containment.
The team conducted an independent walkdown of the interior of the containment
structure for both Unit 1 and Unit 2. Prior to conducting the walkdown the team reviewed
the walk-down inspection report conducted by the licensee to identify areas of interest to
the team. The licensee staff identified a through crack with minor spalling located in the
Unit 1 In-core RCP cubical wall. CRs 440252 and 440184 both documented this area
and this was inspected by the NRC team during the walkdown. A licensee staff member
accompanied the team during the walkdown to address any questions the team had
related to the containment. This inspection was focused on damage sustained by the
concrete structure, anchor bolts, and the exposed mat foundation, specifically cracks
and construction joint movement. The team inspected the foundation pad and weld and
bolt anchor connections. The team also reviewed the documentation associated with the
exterior of the Unit 1 containment. The team also reviewed Engineering Technical
Evaluations (ETE) conducted by the licensee through their ISI program before and after
the earthquake. This review also included an evaluation of design drawings to identify
areas of potential structural concern. All walkdowns for the Unit 1 containment were
completed during the time of inspection and licensee walkdowns for Unit 2 remained
ongoing during the time of the inspection observation.
Emergency Condensate Storage Tanks
During walkdowns, a puddle of liquid with brown stain was observed on the floor
adjacent to the tank. The team requested an explanation of the condition. The licensee
explained that the puddle was attributed to roof seal leakage and the condition was
documented in the licensees corrective action program prior to the earthquake as CR
376171. The team questioned whether the leak could be from the tank and the licensee
replied that there was no valve on the drain line from the tank enclosure to the catch
pan. After further investigation, the team concluded that this observation did not
represent a significant issue related to the earthquake since the condition was identified
prior to the earthquake.
Masonry Walls in Service Building
A crack was identified by the licensee on the Service Building masonry walls apparently
due to the earthquake. The team reviewed CR 439771 that addressed this issue. The
team performed a walkdown and no significant structural safety issues were identified.
8.3 Groundwater and Buried Pipe
a. Inspection Scope
The team reviewed the licensees processes and procedures established to control the
Buried Piping Monitoring/Ground Water Monitoring Program. The team reviewed
multiple documents and sampling data collected in response to the seismic event. The
team also conducted interviews with the licensee personnel involved in the response to
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the seismic event. Finally, the team reviewed relevant/critical CRs developed during the
licensees post seismic assessment.
b. Observations and Findings
The licensee preformed an ETE on its Engineering Programs as a design input to
determine the impact of the seismic event. The Buried Pipe Monitoring/Ground Water
Monitoring Program was included in this ETE. The licensee conducted walkdowns of
numerous areas that were deemed risk-significant. The licensee routinely sampled
ground water on a quarterly basis but increased the planned frequency, inside the
stations Protected Area, to weekly for the first month after the event and then to monthly
for the next six months after that. The results of this increased sampling have not shown
any change in chemical levels tested within this program. It should also be noted that
during any significant liquid waste discharge such as releasing Boron Recovery Tank the
licensee is sampling on a daily basis. The team also conducted walkdowns of the
accessible portions of the Emergency Diesel Fuel Oil system and found no evidence of
leakage or damage.
9.0 Operability Determinations
a. Inspection Scope
To assess the adequacy of the licensees operability determinations for safety
equipment, the team performed the following activities:
- Conducted walkdowns of the U1 and U2 EDGs and Main Steam Trip Valves; and
Unit 2 Pressurizer Power Operated Relief Valves (PORVs) to evaluate the material
condition
- Conducted interviews with plant personnel (maintenance, engineering, and
operations) to establish a clear understanding of each system analysis
- Reviewed design and engineering documents (i.e., calculations, drawings, vendor
manuals) to verify appropriateness of licensee actions in accordance with design and
licensing bases
- Observed corrective maintenance and testing to assess the licensees actions to
restore the identified systems
In addition, the team reviewed corrective action CRs to evaluate the licensees response
to identified deficiencies associated with the identified systems. Completed work order
packages and test results were reviewed to verify the licensees restoration actions were
appropriately implemented and completed. Industry operating experience was
referenced to identify any potential generic industry issues.
The team also reviewed the recommendations that the licensee documented as follow-
up actions to the evaluation performed which included that the Fire Protection systems
be fully tested for each unit in accordance with RG 1.167 and concluded these were
appropriate actions prior to closing the functionality review.
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b. Observations and Findings
Based on the scope of the inspection, no findings of significance were identified related
to licensee operability determinations.
Pressurizer PORVs
An OD was performed and documented in OD 000438 and 439, for the Pressurizer
PORVs to declare the valves operable but not fully qualified due to the possibility the
seismic accelerations experienced during the August 23 event may have exceeded a
portion of the applicable seismic response spectra used for the qualification of the
valves. Full qualification of the Pressurizer PORVs depended on completion of the
plants seismic review. The two Pressurizer PORVs on each unit were required in the
shutdown condition to relieve pressure, preventing any cold overpressure of the RCS.
The team reviewed the seismic calculations, which supported the licensees conclusion
that the valves were designed with margin to accept water hammer loads, followed by
steam in combination with the DBE seismic load. The team concluded that these
calculations validated the design margin of the valves, which was greater than the
seismic load alone. The team determined that these calculations in conjunction with the
visual walkdowns conducted by both the licensee and the inspection team, and the
functional performance testing performed on each units PORVs provided reasonable
assurance the valves could provide their design safety function.
1J & 2J EDG Jacket Water Cooling Pump Missing Orifice Plate
The team reviewed the OD written in response to the missing orifice discovered on the
1J and 2J EDGs. Section 5.0 of this report includes a more detailed discussion. The
team determined based on current parameters observed during testing, system
walkdowns, and engineering analysis, that the licensee supported their conclusion that
the EDGs could currently provide their design safety function.
Mode 5 and Mode 6 Systems
Two ODs were performed for systems required for Mode 5 and Mode 6, for both units,
and documented in OD 000442 (Mode 5 Systems) and OD 000448 (Mode 6 Systems).
The purpose of the ODs was to review the operability/functionality of systems required
by TS or the Technical Requirements Manual (TRM) for Mode 5 and Mode 6 following
the seismic event on August 23. The systems were declared Operable/Functional but
not fully qualified pending review and resolution of seismic issues.
The systems and components scoped in the Mode 5 OD included:
- RCS Loops
- EDGs and supporting systems (Start Instrumentation, Fuel Oil, Starting Air)
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- Boration Flow Path
- ASME Code Class 1,2,3 Components
- Service Water and Component Cooling Water Systems
- MOV Thermal Overload Protection Devices
The systems and components scoped in the Mode 6 OD were those needed to move the
units into a refueling condition and included, but not limited to:
- Nuclear Instrumentation
- Ventilation Systems
- Spent Fuel Pool and supporting systems
- Radiation Monitoring
The team reviewed the operability evaluations and concluded they were adequate in
determining the required systems were capable to perform their intended design
function; albeit, they were not fully qualified pending review of any seismic issues. The
operability determinations were based on successful completion of engineering
walkdowns and resolution of any discovered discrepancies; satisfactory completion of
functional testing; and engineering analysis of system performance.
During the review of the Mode 5 OD, the team noted that during the seismic event, minor
perturbations were observed on Units 1 and 2 RWST and SI accumulator levels. In
addition to these perturbations, other anomalies were noted to occur on various other
safety related instruments. Section 8.0 of this report includes additional discussion on
these perturbations.
Fire Protection & Appendix R Systems
A basis for functionality of the fire protection systems and Appendix R alternate
shutdown equipment was documented in a Reasonable Assurance of Safety (RAS)
review as RAS 000187. The RAS evaluation reviewed all aspects of the Fire Protection
and Appendix R systems (seismic and non-seismic) to determine reasonable assurance
they met their functional requirements without further compensatory actions.
The licensees review included functional validation of Appendix R systems including:
- required instrumentation;
- alternate shutdown equipment; and
- equipment required to maintain communications.
Pumps and valves required for safe shutdown were operated and tested satisfactorily.
The Appendix R panels and isolations switches were installed safety-related and
seismically qualified and were inspected for damage and degradation and were found to
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be available for service. The Appendix R radio channel, repeater, and antenna were
checked to perform their function satisfactorily. During containment walkdowns, the
reactor coolant pump oil collection systems were inspected and were found to have no
deficiencies.
Suppression systems for defense-in-depth were also verified and validated by the
licensee including:
- Manual systems (i.e., extinguishers, hoses)
- Detection systems (e.g., smoke and heat detectors)
- Hydraulic systems (i.e., fire pumps, hydrants, standpipes)
- Gaseous systems (e.g., CO2, halon)
On August 25, 2011, two days following the seismic event, a fire alarm for the Unit 2
reactor coolant pump 2-RC-P-1A radiant heat detector locked in and would not reset.
The license confirmed there was no fire present at the time of the alarm. The cause of
the alarm was not immediately identified; however, the team confirmed maintenance and
testing was being performed to determine the reason for the alarm. The team also
confirmed the licensee would inspect and test all circuits for the reactor coolant pump
heat detectors on both units prior to restarting.
Additionally, passive fire protection systems were visually inspected by the licensee for
any signs of degradation or damage as a result of the seismic event. This review
included a walkdown of structures including, but not limited to:
- Fire doors;
- Fire walls and barriers;
- Fire dampers;
- Penetration fire seals;
- Radiant energy shields
- Conduit fire wraps and seals
The licensees visual inspection identified some minor cracks in some of the fire walls
and barriers but determined they were only cosmetic in nature and did not constitute
degradation in barrier integrity given the cracks allowed no passage of air or light.
Based on the engineering walkdowns of the systems, results of applicable performance
tests and periodic maintenance, and use of the Test Requirements Manual to determine
functionality acceptance, the team concluded the licensee provided reasonable
assurance that the systems could meet their functional requirements; though, they would
be considered not fully qualified pending review of any applicable plant seismic issues.
The team reviewed the recommendations that the licensee documented as follow-up
actions to the evaluation performed, which included that the Fire Protection systems be
fully tested for each unit in accordance with RG 1.167 and concluded these were
appropriate actions prior to closing the RAS.
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10.0 Restart Readiness
a. Inspection Scope
The inspectors conducted a review of the licensee plans and procedures for evaluating
the conditions of the plant prior to restart. At the close of the inspection, the licensee
had developed a plan for restart and presented the plan to the NRCs Office of Nuclear
Reactor Regulation for review.
b. Observations and Findings
Because the licensees restart plans were in development during most of the teams
inspection and because they were subject to separate NRC review, the team did not
draw conclusions related to the adequacy of the plans.
The licensees plan included nine parts, each of which detailed actions to be performed
prior to restart:
- A characterization of the North Anna seismic event of August 23, 2011
- Post-earthquake inspections of plant structures, systems, and components
- Post-earthquake evaluation of reactor vessel internals
- Post-earthquake assessment of new and irradiated fuel
- Post-earthquake assessment of the spent fuel storage racks
- Post-earthquake evaluation of the independent spent fuel storage installation
- Post-earthquake impact assessment on engineering programs
- Near-term actions to be completed prior to Unit startup
- Long-term actions to be completed after Unit startup
The licensee planned to use the guidance of EPRI NP-6695, Guidelines for Nuclear
Plant Response to an Earthquake, dated 1989, which is endorsed by RG 1.167. At the
close of this inspection, the NRC was continuing to review the licensees plans.
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11.0 Independent Spent Fuel Storage Installation (ISFSI)
a. Inspection Scope
The team reviewed design drawings associated with the two Independent Spent Fuel
Storage Installation (ISFSI) types contained in the storage area. In addition, the team
conducted a walkdown to assess the condition of each ISFSI pads and the associated
casks and the Horizontally Stored Modules (HSM) modules after the seismic event. The
team also conducted interviews with the licensee personnel involved in the response to
the seismic event. The seismic design methodology contained in FSAR was also
reviewed to determine the DBE for each type of ISFSI. Finally, the team reviewed all
CRs developed during the licensees post seismic assessment.
b. Observations and Findings
The team found that the ISFSIs were intact and found no significant damage during
walkdowns.
TN-32 Units (Pad 1)
There are two ISFSI pads at the North Anna site. Each pad supports two different types
of ISFSI units. ISFSI pad #1 stores TN-32. The TN-32 cask body is a right circular
cylinder composed of a confinement vessel with bolted lid closure, basket for fuel
assemblies, gamma shield, trunnions, neutron shield, overpressure monitoring system,
and a weather cover and is stored vertically on a 24 reinforced concrete pad supported
by an additional 48 of engineered backfill. The inspection team conducted a walkdown
of pad #1 to assess the condition of each of the ISFSI units. The team noted some
lateral sliding due to the seismic activity in 25 of the 27 TN-32 casks ranging from 0.5 to
4.5. As a result of this movement, six pair of the casks were found to be less than the
original minimum center to center spacing of 16 required by Section 4.0 of the TN-32
ISFSI Technical Specification. The team determined that the magnitude of sliding of TN-
32 casks was rather limited. The adjusted spacing based on movement due to the
earthquake ranged from 15-3.5 to 15-11. Section 4.0 of the TN-32 ISFSI TS also
states that space requirements are still in compliance based on 27.1 KW rating. The
licensee completed an Immediate OD for the ISFSI on August 23, 2011. All ISFSI
instrumentation was tested for operability and determined to be functioning properly. No
pressurization alarms were signaled during or after the seismic event. Based on a
review of the TN-32 ISFSI FSAR no sliding or tipping of the TN-32 casks is expected to
occur due to a DBE. Design drawings indicate the TN-32 casks are structurally
adequate to withstand the excitation of the earthquake as indicated by the pressurization
system alarm not tripping. No visual damage to the casks or the supporting pad was
observed by the inspection team.
The teams simplified analysis of ISFSI TN-32 casks subjected to the earthquake
shakings recorded at the Unit 1 Containment Basemat resulted in a factor of safety
against sliding greater than 1.0, indicating no sliding. A coefficient of friction between
the bottom of the steel casks and concrete pad of 0.3, as adopted in the FSAR, was
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used in this analysis. Aside from the difference in subsurface conditions between the
Unit 1 and ISFSI sites and corresponding site soil amplifications, the team considered
that a potential deviation of the assumed value of 0.3 from the actual coefficient of
friction could be a contributing factor to the discrepancy between the analysis (no sliding)
and observation (sliding).
The teams inspection of the traces of sliding indicated that both the magnitude and
orientation of sliding were irregular across the pad. Casks on a surface-founded
concrete pad subjected to vertically propagating seismic waves are largely expected to
move uniformly across the pad based on the traditional assumption of coherent ground
motion. However, the irregular sliding pattern suggested to the team that the actual
ground motion at the ISFSI site might have been incoherent motion characterized by
spatial non-uniformity across the footprint of the pad. The team did not identify any
immediate safety concern associated with this observation or with the positioning of the
casks.
NUHOMS HD System (Pad 2)
The second ISFSI pad utilizes the NUHOMS HD-32PTH System, a horizontal canister
system composed of a steel Dry Shielded Canister (DSC) inside a reinforced concrete
Horizontal Storage Module (HSM-H). The NUHOMS HD is designed for enhanced heat
rejection capabilities, and permits storage of non fuel assembly hardware with the fuel
and/or damaged spent fuel assemblies. The welded DSC provides confinement and
criticality control for the storage and transfer of irradiated fuel. The concrete module
provides radiation shielding while allowing cooling of the DSC and fuel by natural
convection during storage.
The HSM-H is a reinforced concrete unit designed to provide environmental protection
and radiological shielding for the 32PTH DSC. The HSM-H consists of two separate
units: a base storage unit, where the 32PTH canister is stored, and a roof that serves to
provide environmental protection and radiation shielding. The roof is attached to the
base unit by four vertical ties or by four angle brackets. Three-foot thick shield walls are
installed behind each HSM-H (single row array only) and at the ends of each row to
provide additional environmental protection and radiological shielding. Each HSM-H
Unit has penetrations that are located at the top and bottom for air flow and are
protected from debris intrusions by wire mesh screens during storage operation. The
DSC Support Structure, a structural steel frame with rails, is installed within the HSM-H
module to provide for sliding the DSC in and out of the HSM-H and to support the DSC
within the HSM-H. HSM-Hs are arranged in arrays to minimize space and maximize
self-shielding.
The pad for these units is also 24 of reinforced concrete above 48 of engineered
backfill. These units were also walked-down by the inspection team in a similar manner.
The team noted minimal movement of these units during inspections of the roof and
ventilation system at the top of each unit. Based on post event inspections by the
licensee the HSM-H units have gaps between each module ranging from 0.5 to 1.5. It
should also be noted that 13 of the 26 NUHOMS HD Systems are loaded and the rest
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are empty. The ventilation system for each HSM-H containing stored fuel within a DSC
was tested to determine if there was any blockage of airflow and it was determined that
each unit was functioning properly. The licensee had already documented exterior
damage caused by the seismic event.
Multiple areas of concrete spalling and cracking were identified by the licensee and
pointed out to the NRC team members during their walkdowns. All damage identified
was classified as cosmetic and the licensee determined each unit currently in service
was functioning properly. No damage to the supporting pad was observed by the
licensee or the NRC team members.
The main unknown related to both pads is the lack of seismic data for this area. No
seismic instrumentation was wired for this portion of the site. This area of the site was
approximately one half mile from the closest location seismic data was collected. This
makes it difficult to assess the performance of the area from a structural perspective.
Based on the information reviewed and the inspection activities conducted, the team
determined that there were no immediate safety concerns with the ISFSI facility.
12.0 Data for Risk Assessment
a. Inspection Scope
During the course of the inspection, the team collected information to support the final
determination of the risk of significance of the event. In accordance with Management
Directive (MD) 8.3, NRC Incident Investigation Program, deterministic and conditional
risk criteria were used to evaluate the level of NRC response for the operational event.
This issue met the deterministic criteria of MD 8.3 in that the ground movement of the
earthquake could have exceeded the design bases of the facility. The Conditional Core
Damage Probability (CCDP) for the event was estimated to be 1.1E-4.
b. Observations and Findings
Overall, the team concluded that the event did not adversely impact the health and
safety of the public. Safety limits were not approached and there was no measurable
release of radioactivity associated with the event.
The team collected additional information to support the NRCs final risk assessment.
The team noted that the CCDP estimate of 1.1E-4 relied, in part, on assumptions of
potential common cause aspects related to the failure of the 2H EDG due to a jacket
water leak about 45 minutes into the event. During the teams review of the 2H EDG
failure, the team determined that a faulty gasket installation in May 2010 may have
contributed to the EDGs failure and noted issues with the licensees maintenance
procedure that addressed gasket installation. An unresolved item was opened to
address the issue. Additional information on the 2H EDG failure may be found in
Section 5.0 of this report.
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Additional issues with the EDGs were noted that could affect the NRCs final risk
assessment of the event. 1J EDG and 2J EDG were found to have missing orifice plates
in their jacket water cooling systems. At the time of the teams review, the licensee was
in the process of determining the significance of the missing orifice plates. An
unresolved item addressing this is described in Section 5.0. Also, while performing its
function during the event, 1J EDG experienced frequency oscillations that were
observed by operators in the control room. Reports from operators indicated that the
oscillations may have approached TS operability limits. At the time of the teams review,
the licensee had planned to test 1J EDG in isochronous mode. An unresolved item on
this issue is described in Section 6.0.
The team noted that the operators responded to the earthquake in accordance with
approved procedures and in a manner that protected public health and safety. Both
reactors automatically shut down during the event and safety system functions were
maintained. Plant walkdowns did not identify significant damage to the plant.
13.0 Safety Culture
a. Inspection Scope
Safety culture is defined as that assembly of characteristics and attitudes in
organizations and individuals, which establishes that, as an overriding priority, nuclear
plant safety issues receive the attention warranted by their significance. Therefore, an
organizations characteristics (i.e., safety culture components that comprise the visible
aspects of a safety culture) can be assessed by evaluating the extent to which its
policies, programs, and processes ensure that nuclear safety issues receive the
attention warranted by their significance. For example, the effectiveness of the
licensees corrective action program at identifying, prioritizing, and resolving issues with
nuclear safety impacts provides important insights into the licensees safety culture. An
organizations members shared attitudes and behaviors with respect to nuclear safety
also provide important insights into a licensees safety culture and can be assessed
through behavioral observations, interviews, and focus groups.
In conducting inspections to address the AIT charter items, the team interacted with and
interviewed licensee staff, reviewed corrective action program documents, and
examined licensee programs and policies. During this process, the team considered
safety culture components to determine whether safety culture was a contributing factor
in the event or issues related to the event.
b. Observations and Findings
No findings of significance were identified in this report related to the licensees safety
culture.
Enclosure
61
14.0 Exit Meeting Summary
On October 3, 2011, the NRC held a public meeting and presented the inspection results
to Mr. David Heacock and other members of the staff, who acknowledged the findings.
The inspectors asked the licensee whether any of the material examined during the
inspection should be considered proprietary. No proprietary information was identified.
Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel:
W. Anthes, Manager, Nuclear Maintenance
M. Becker, Manager, Nuclear Outage and Planning
M. Crist, Plant Manager
R. Evans, Manager, Radiological Protection and Chemistry
T. Huber, Director, Nuclear Engineering
S. Hughes, Manager, Nuclear Operations
C. Gum, Manager, Nuclear Protection Services
L. Lane, Site Vice President
J. Leberstien, Technical Advisor Licensing
P. Kemp, Manager, Organizational Effectiveness
F. Mladen, Director, Station Safety and Licensing
R. Scanlon, Manager, Nuclear Site Services
D. Taylor, Supervisor, Station Licensing
R. Wesley, Manager, Nuclear Training
M. Whalen, Technical Advisor Licensing
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
05000338, 339/2011011-01 URI Seismic Instrumentation Implementation (Section 3.2)
05000338, 339/2011011-02 URI Failure of 2H Emergency Diesel Generator Jacket Water
Cooling Gasket Resulting in Inoperability during Dual Unit
LOOP (Section 5.0)
05000338, 339/2011011-03 URI Missing Orifice Plate on 1J and 2J EDG (Section 5.0)
05000338, 339/2011011-04 URI 1J EDG Frequency Oscillation (Section 6.0)
05000338, 339/2011011-05 URI Unit 1 Turbine Driven Auxiliary Feedwater Pump Trouble
Alarm (Section 7.1)
05000338, 339/2011011-06 URI Seismic Alarm Panel (Section 7.5)
05000338, 339/2011011-07 URI Safety Related Instrumentation Anomalies
(Section 8.1)
Discussed
None
Attachment 1
2
List of Documents Reviewed
Corrective Action Documents
CR 439724; VG-RI-178,179,180 seismic qualification; dated August 27, 2011
CR 439681; Determine which TR 3.3.6, TR 12.4 and TR section 7.0 SSC are seismic; dated
August 26, 2011
CR 439394; 2-RC-P-1A Radiant Heat Fire Alarm locked in; dated August 25 2011
CR 441362; 1-MS-TV-101B Train B SOV failed stroke time; dated September 4, 2011
CR 441358; 1-MS-TV-101A Train A SOV failed stroke time; dated September 4, 2011
CR 428754; Replace source range pulse shaper circuit card; dated May 26, 2011
CR 441864; Source range NI pulse shaper heat damage; dated September 7, 2011
CR 383161; Need a WO to change oil in the 2H EDG governor - revise cure time & installation
of water by-pass fitting; dated June 2, 2010
CR 440023; Incorrect torque values listed in procedures 0-MCM-0701-02/-27; dated August 29,
2011
CR 347658; Conflicting torque values on EDG water bypass plate fasteners; dated September
8, 2009
CR 347783; EDG water by-pass plates have incorrect surface finish; dated September 9, 2009
CR 442606; Standby Coolant Circulating Pump has 100 dpm seal leak; dated September 12,
2011
CR 439952; 2H EDG jacket cooling temperature dropped from 124 deg to 116 deg in 12 hrs;
dated August 28, 2011
CR 440297; 2H coolant leak; dated August 30, 2011
CR 439992; 2J EDG coolant water bypass connection inspection; dated August 28, 2011
CR 439091; 2H EDG manually secured; dated August 23, 2011
CR 439699; Generate new WO to inspect 2H EDG water bypass fitting gaskets
CR 440263; Torque water bypass fittings to 70 ft-lbs.; dated August 30, 2011
CR 439470; During start for Maintenance run, found 2H cylinder petcock valves open; dated
August 24, 2011
CR 439357; 2H EDG has an exhaust leak on OCS #4 extension pipe; dated August 25, 2011
CR 439272; Replace gaskets on 2H EDG; dated August 24, 2011
CR 439086; Generate WO to inspect 1J EDG; dated August 24, 2011
CR 439080; Generate WO to inspect 2J EDG; dated August 24, 2011
CR 439084; Generate WO to inspect 1H EDG; dated August 24, 2011
CR 439075; Generate WO to inspect 2H EDG; dated August 24, 2011
CR 439657; Perform OD for Unit 1 PORVs; dated August 26, 2011
CR 439662; Perform OD for Unit 2 PORVs; dated August 26, 2011
CR 441352; Engine driven coolant pump is leaking on 1J EDG; dated September 3, 2011
CR 441537; 1-EG-P-7J does not have an orifice plate installed on the discharge of the pump;
dated September 5, 2011
CR 441540; 2-EG-P-7J does not have an orifice plate installed on the discharge of the pump;
dated September 5, 2011
CR 440422; Request WO to repair coolant leaks identified during engine hydro; dated August
30, 2011
CR 439921; CR to allow processing of formal OD on ISFSI; August 28, 2011
CR 440205; Repair cosmetic concrete damage to NUHOMS HSM 1-3 intake vent; August 29,
2011
Attachment 1
3
CR 440207; Repair cosmetic concrete damage to NUHOMS HSM 23-25; August 29, 2011
CR 440204; Post seismic inspection found broken roof vent on HSM 15/17; August 29, 2011
CR 440200; Post seismic inspection of HSM 25 roof has cosmetic damage; August 29, 2011
CR 439315; ISFSI Pad 1 Post Seismic Inspection; August 24, 2011
CR 439319; ISFSI Pad 2 Seismic Inspection; August 24, 2011
CR 440987; ISFSI Pad 2 HSM Fastener; September 1, 2011
CR 440991; ISFSI Pad 1&2 Walkdown; September 1, 2011
CR 439921; CR to allow processing of formal OD on ISFSI; August 28, 2011
CR 440205; Repair cosmetic concrete damage to NUHOMS HSM 1-3 intake vent; August
29, 2011
CR 440207; Repair cosmetic concrete damage to NUHOMS HSM 23-25; August 29, 2011
CR 440204; Post seismic inspection found broken roof vent on HSM 15/17; August 29,
2011
CR 440200; Post seismic inspection of HSM 25 roof has cosmetic damage; August 29,
2011
CR 439315; ISFSI Pad 1 Post Seismic Inspection; August 24, 2011
CR 439319; ISFSI Pad 2 Seismic Inspection; August 24, 2011
CR 440987; ISFSI Pad 2 HSM Fastener; September 1, 2011
CR 440991; ISFSI Pad 1&2 Walkdown; September 1, 2011
CR 439217; Crack in Block Wall Above Door 1-BLD-STR-SO7-4 U2 307 Switchgear Back
Stairwell; dated August 23, 2011
CR 442328; Damage Found on C Phase CT Column for G202; dated September 10, 2011
CR 441027; Capacitor with Slight Bulge in 2H Swing Charger WU13 Card; dated September 1,
2011
CR 439210; 2J 4160V Relay Drops; dated August 24, 2011
CR 440227; Investigate Nuisance Alarms for Inverters while EDG Supplying Bus; dated August
23, 2011
CR 440231; Investigate 1-III and 1-IV Trouble Alarms while Energizing PZR Heaters; dated
August 23, 2011
CR 439127; 1-EP-SST-1A/1B Bus Duct Sagging - Previously Existing Condition; dated August
23, 2011
CR 439275; Unplanned Entry Into a Red Maintenance Rule Window; dated August 24, 2011
CR 439242; 2-EP-ST-2A1 No Mounting Bolts (Evaluate Before Energizing); dated August 23,
2011
CR 439204; Need Work Orders to Replace 500kV bushings on Unit 2 GSUs; dated August 23,
2011
CR 439202; Need Work Orders to Replace 500kV bushings on Unit 1 GSUs; dated August 23,
2011
CR 439194; PCS Points are Inaccurate for Unit 1G 4160V Bus; dated August 24, 2011
CR 439135; Breaker 01-EP-BKR-15G10 Fail to Close; dated August 24, 2011
CR 439306; 0-AP-23 Entered Due to Oil Leak within Berm of U1/U2 Main Transformers; dated
August 23, 2011
CR 439356; Line Fuse Clip Holder Installed in the Back of 1-EP-BKR-15C4 is Broken; dated
August 25, 2011
CR 439665; HI-Pot U2 Isophase; dated August 26, 2011
CR 439916; 2H1 Bus Potential Red Light Not Lit; dated August 28, 2011
Attachment 1
4
CR 439671; Programmatic Work Request U1 Isophase; dated August 29, 2011
CR 440145; Post Seismic Event System Engineering Walkdown - Emergency Switchgear
Room; dated August 29, 2011
CR 440164; Post seismic Event Walkdown - Insulation Falling from Top of 1-EI-CB 48B; dated
August 29;
CR 440068; Post Seismic Walkdown of the Vital Bus; dated August 29, 2011
CR 440065; Post Seismic Walkdown of Vital Bus; dated August 29, 2011
CR 439640; Walkdown of Unit 2 Cable Spreading Room Identified Broken Tie-Wraps; dated
August 26, 2011
CR 439638; Walkdown of Unit 1 Cable Spreading Room Identified Broken Tie-Wraps; dated
August 26, 2011
CR 440263; Torque Water Bypass Fittings to 70ft.lbs; dated August 30, 2011
CR 439812; Missing Vents on 1-EE-ST-1H; dated August 27, 2011
CR 442891; Recommended Revision to 0-AP-36, dated September 14, 2011
CR 212320; ETE-CEP-2011-0004, Update Underground Piping and Tank Life Cycle
Management (Unit 1); August 23, 2011
CR 212322; ETE-CEP-2011-0004, Update Underground Piping and Tank Life Cycle
Management (Unit 2); August 23, 2011
CR 439052; Event Review Team Issue Plan and Report for Dual Unit Trip Following Magnitude
5.8 Earthquake; dated September 3, 2011
CR 376171, NANN - Leakage from suction pipe gasket at U-1 ECST, 4-12-2010
CR 439771, NANN - Cracks in block north wall of service building locker room, 8-27-2011
Drawings
NAPS-S-ONE LINE; North Anna Power station Simplified One Line Diagram; Sh. 1; Rev. 1
11715-FE-1BB; One Line Diagram Electrical Distribution System; Sh. 1; Rev. 44
11715-FE-21P; D.C. Elementary Diagram Reserve Station Service Transformer Protection; Sh.
1; Rev. 8
11715-FE-5L-10; Wiring Diagram Rod Drive Supply Cabinet; Issue 10; Rev. D; dated March 18,
1988
11715-FE-21D1; D.C. Elementary Diagram Generator 1 and Transformers Protection; Sh. 1;
Rev. 2
11715-FE-1BD; One Line Switching Diagram Switchyard; Sh. 1; Rev. 44
11715/12050-1.30-201A; Emergency Diesel Generator Jacket Cooling Schematic; Rev. 5
11715-FM-070B; Flow/Valve Operating Numbers Diagram Main Steam Systems; Rev. 35
11715-TV-MS101A; Main Steam Line Trip Valve TV-MS101A Control; Sh. 1; Rev. 11
Transnuclear; DWG 10494-30-9, NUHOMS 32PTH, Transportable Canister for PWR Fuel
Basket Assembly, Rev 4
Transnuclear; DWG-NUH-03-7103; Base; Rev. 2
Transnuclear; DWG-NUH-03-7103; General Arrangement; Rev. 1
Transnuclear; DWG-NUH-03-7103; Roof, Rev. 2
Transnuclear; DWG-NUH-03-7103; Walls and Outlet Vent Cover; Rev. 2
Dominion, DWG-05004-0-1FC49A1; Plans, Section and Details ISFSI Storage; Rev. 3
Transnuclear, DWG-1049-30-1, TN-32 Dry Storage Cask Assembly and Parts (Longitudinal
Section); Rev. 12
Transnuclear; DWG-1049-30-2; TN-32 Dry Storage Cask Shell Assembly and, Rev. 15
Attachment 1
5
Transnuclear; DWG-1049-30-1; TN-32 Dry Storage Cask Overpressure Tank Assembly,
Rev. 12
12050-FW-157, Feedwater System Turbine Driven AUX FD Pump Lube Oil Reservoir Level
Switch & Alarm, Revision 33
122050-FE-1M, 480V One line Diag MCC 2A1-1, 2B1-2, 2C1-1 Above Cable Tunnel and MCC,
Revision XX
2A1-3 VAC Priming Hose North Anna Power Station Unit 2, Revision 33
12050-FE-1F, 480V One Line Diagram Bus 2A1, 2C2, 2B1, and 2A2, Revision 19
12050-FE-1B, 4160V One Line Diagram Bus 2A and Bus 2B North Anna Power Station Unit 2,
Revision 11
Drawing # 11715-FV-44A, Refueling Water Storage Tank, Rev. 7
Drawing # 11715-FV-65A-4, Refueling Water Chemical Additional Tank
Miscellaneous
Calculation # 52308.04-C-005; Seismic Margin HCLPF Calculations for Refueling Water
Chemical Additional Tank; dated February 26, 1997
Calculation # 52308.04-C-004; A-46 Evaluation of Refueling Water Storage Tank; Rev. 3; dated
March 15, 1999
Calculation # 52182-C-039, Seismic Margin HCLPF Calculations for Refueling Water Storage
Tank; Rev. 2; dated April 5, 1997
PO 70181906; VEPCO Power Transformer Standard Specifications
20497; Qualitrol 900/910 Series Rapid Pressure Rise Relay Operational Verification Test Report
Certification
20498; Qualitrol 900/910 Series Rapid Pressure Rise Relay Operational Verification Test Report
Certification
20499; Qualitrol 900/910 Series Rapid Pressure Rise Relay Operational Verification Test Report
Certification
Transformers Program/Component System Health Report; 3rd Quarter 2011
20110914T164920Z; Dissolved Gas Analysis; Transformer Oil Analyst 4.0; dated August 23,
2011
NAS-2027; Specification for Seismic Electrical Panels for Appendix R Isolation Panels; dated
March 7, 1985
QDR-N-8.5/QDR-S-8.3; Qualification Package for Rosemount 1153D Transmitter; Rev. 33
Rosemount Report D8300040; Qualification Report for Pressure Transmitters Rosemount
Model 1153 Series D; Rev. E; dated July 13, 2000
DC 94-016; SI Accumulator Level Transmitter Replacement
Quality Certificate of Compliance Data Sheet; Pressure Transmitter Rosemount Model
1152DP3N92PB; dated January 11, 1996
OE33510; Unit 1 NI Channel N32 Failed South Texas Project
NCRODP-23-NA; Main Steam System
Operator Logs
OD 000442; Prompt Operability Determination for Mode 5 systems; dated September 7, 2011
OD 000448; Prompt Operability Determination for Mode 6 systems; dated September 9, 2011
OD 000443/444; Prompt Operability Determination for 1J and 2J EDG missing orifice plates on
engine driven jacket water cooling pump; dated September 7, 2011
OD 000438/439; Prompt Operability Determination for Unit 1 and 2 PORVs; dated August 27,
2011
Attachment 1
6
RAS 000187; Reasonable Assurance of Safety Review of Appendix R Alternate Shutdown
Equipment; Rev. 1; dated September 9, 2011
14938-02-NPB-010-XC; Stress Analysis of Pressurizer Safety and Relief Piping (Class 1)
Reactor Containment; Rev. 0
CE-1109; Pipe Stress Analysis of PSARV Piping for DBE and SMA Spectra with Revised
Natural Frequency/Stiffness for Valves 1-RC-PCV-1455C and 1-RC-PCV-1456; Rev. 0
CE-1436; Seismic Qualification of Pressure Control Valves for USI A-46 and IPEEE; Rev. 0
ETE-NA-2011-0057; Evaluation 2H EDG Cooling Water Bypass Fitting Gasket Torque
Adequacy; Rev. 0
ETE-CEP-2011-0004; Impact of August, 2011Seismic Activity on Engineering Program; Rev.1
RP-AA-502; Ground Water Protection Program; Revision 2
EN#47181 - North Anna 1 & 2 - Alert Declared Due To An Earthquake In The Area And Loss Of
Offsite Power
EN#47196 - North Anna 1 & 2 - Unusual Event Declared Due To An Aftershock Earthquake
EN#47198 - North Anna 2 - Notification To Offsite Agency Regarding An Onsite Oil Spill
North Anna UFSAR, Revision 46.08, dated August 12, 2011
IEB 79-04; Incorrect Weights for Swing Check Valves Manufactured by Velan Engineering
Corporation; dated March 30, 1979
IEB 79-07; Seismic Stress Analysis of Safety-Related Piping; dated April 14, 1979
IEB 79-14; Seismic Analyses for As-Built Safety-Related Piping Systems; dated July 2, 1979
10 CFR 100, Appendix A, Seismic and Geologic Siting Criteria for Nuclear Power Plants
10 CFR 72.102, Geological and Seismology Characteristics
Regulatory Guide 1.100; Seismic Qualification of Electric and Mechanical
Equipment for Nuclear Power Plants, Revs.1 and 2
Regulatory Guide 1.92; Combining Model Responses and Spatial Components in Seismic
Response Analysis; Rev. 1
Regulatory Guide 1.60; Design Response Spectra for Seismic Design of Nuclear Power Plants,
Rev. 1
Regulatory Guide 1.61; Damping Values for Seismic Design of Nuclear Power Plants, Rev. 1
Regulatory Guide 1.97; Instrumentation for Light-Water-Cooled Nuclear Power Plants to A
Assess Plant and Environs Conditions During and Following an Accident; Rev.0
Regulatory Guide 1.166, Pre-Earthquake Planning and Immediate Nuclear Power Plant
Operator Post-Earthquake Actions; Rev. 1
Regulatory Guide 1.167, Restart of a Nuclear Power Plant Shutdown by a Seismic Event, Rev.
0
Regulatory Guide 1.13; Spent Fuel Storage Facility Design Basis; Rev. 1
Regulatory Guide 1.122; Development of Floor Design Response Spectra for Seismic Design of
Floor-Supported Equipment or Components; Rev. 1
Regulatory Guide 1.12; Nuclear Plant Instrumentation for Earthquakes; Rev. 1
NUREG-0800; Standard Review Plan for the Review of Safety Analysis Reports for Nuclear
Power Plants
USI A-46; Verification of Seismic Adequacy of Mechanical and Electrical Equipment in
Operating Reactors, dated February 27, 1987
NUREG-1742; Perspectives Gained from the Individual Plant Examination of External Events
(IPEEE) Program, Volume 1, Volume 2, dated April 2002
DCP-95-005; Independent Spent Fuel Storage Installation
Attachment 1
7
DCP 82-19; Spent Fuel Storage Racks
GL 87-02; Verification of Seismic Adequacy of Mechanical and Electrical Equipment in
Operating Reactors, Unresolved Safety Issue (USI) A-46, dated February 19, 1987
GL 88-20; Supplement 4, Individual Plant Examinations of Severe Accident Vulnerabilities,
dated June 28, 1991
GIP-2; Generic Implementation Procedure for Seismic Verification of Nuclear Plant
Equipment, Seismic Qualification Utility Group (SQUG), Revision 2, dated February 14, 1992
IEEE 344, IEEE Recommended Practice for Seismic Qualification of Class 1 E Equipment for
Nuclear Power Generating Stations, 1987 - 2004
STD-GN-0038; Seismic Qualification of Equipment, Rev. 9
STD-GN-0035, NRC Regulatory Guide 1.97 Compliance Engineering Guidelines for Post-
Accident Monitoring, Rev. 10
STD-CEN-001 6, Pipe Stress Analysis Standard for North Anna, Rev. 2
STD-CEN-0020, Equipment Supports - Mechanical & Electrical, Rev. 2
STD-CEN-0018, Nuclear Pipe Support Standard, Rev. 7
NAS-2016, Safety Related Standard for Conduit Supports, Rev. 8
NAS-0104, Design Criteria for Earthquake and Tornado Requirements for Structural Work,
Revision 3
Technical Report CE-0137, Seismic Event Abnormal Procedures and Seismic Instrumentation,
Revision 0
Technical Report PE-001 3, North Anna Power Station Response to Regulatory Guide 1.97,
Revision 14
NUREG-1407, Procedural and Submittal Guidance for the Individual Plant Examination of
External Events (IPEEE) for Severe Accident Vulnerabilities, dated June 1991
Letter VEPCO to Stone and Webster, Preliminary Report on Seismology, dated February 4,
1969
Letter Stone and Webster to VEPCO, Notes of Conference, dated August 27, 1969
Preliminary Safety Analysis Report, North Anna Power Station, dated March 1, 1969
NRC SER, Docket No. 50-338 and 50-339, Related to the Operation of North Anna Power
Station Units 1 and 2 (NUREG-0053), dated June 7, 1976
NRC SER, Docket No. 50-338 and 50-339, GL 87-02 Plant Specific Safety Evaluation for USI
Program Implementation at North Anna Power Station, Units 1 and 2, dated November 3,
2000
0-GEP-30, Post Seismic Event System Engineering Walk-down, Revision 2
NRC SSER No 2, Supplemental Safety Evaluation Report No. 2 (SSER No. 2) on Seismic
Qualification Utilities Group's Generic Implementation Procedure for Implementation of GL 87-
02 (USI A-46), Revision 2, corrected February 14, 1992,
Verification of Seismic Adequacy of Equipment in Older Operating Nuclear Plants, U.S. Nuclear
Regulatory Commission, dated May 22, 1992
NRC report to the Commission, Inquiry into Certain Issues Concerning the North Anna Fault
Matter, dated August 1978
DCP 78-18, Spent Fuel Racks
North Anna Power Station Units 1 & 2 Independent Spent Fuel Storage Installation (ISFSI)
Safety Analysis Report, Revision 2
NRC SER Issuance of Materials License SNM-2507 for the North Anna Independent Spent Fuel
Storage Installation, dated June 30 1998
Attachment 1
8
PDBD-NAPS, Plant Design Basis Document for North Anna Power Station, Revision 3, dated
April 19, 2011
North Anna Power Station Units 1 and 2 Report on Individual Plant Examination of External
Events (IPEEE) - Seismic, Prepared in Response to USNRC Generic Letter 88-20
Supplement 4 and 5, dated May 1997
North Anna, Units 1 and 2, Completion of Outlier Resolution - USI A-46 Program Generic Letter
(GL) 87-02 -- Verification of Seismic Adequacy of Mechanical and Electrical Equipment,
dated May 26, 2000
UFSAR Change Request NA-UCR-000-FN-1999-014, Seismic/Civil Integrated Review Team
(IRT) Change Package
Calculation 52308.04-0-003, USI A-46 Evaluation of Condensate Storage Tanks (CST) at North
Anna, Revision 1, dated April 9, 2007
EPRI Guideline NP-6695, Guidelines for Nuclear Plant Response to an earthquake, dated
January 26, 1990
Procedure VPAP-2802, Notifications and Reports, Revision 35, dated July 22, 2011
CR442891, Recommended Revision to 0-AP-36, dated September 14, 2011
CA212518, CA to North Anna Procedures to revise 0-AP-36 to verify detector, circuitry, and
Indication
VEPCO letter to the NRC, Response to the Request for Additional Information on Summary
Report on USI A-46 Program, Serial No.99-027, dated April 1 1999
Procedures
0-MCM-0701-27; Replacement of Emergency Diesel Generator Cylinder Liners; Rev. 19
0-MCM-0701-27; Replacement of Emergency Diesel Generator Cylinder Liners; Rev. 20
0-MCM-0701-27; Replacement of Emergency Diesel Generator Cylinder Liners; Rev. 21
2-OP-6.8; Slow Start and Operation of 2H Emergency Diesel Generator; Rev. 32
2-MOP-6.95; 2H EDG Coolant Changeout Using Bleed and Feed Method; Rev. 17
2-MOP-6.90; Emergency Diesel Generator 2-EE-EG-2H; Rev. 57
2-AR-17; Annunciator Response Procedure; Rev. 23
2-E-0; Reactor Trip or Safety Injection; Rev. 47
1-PT-36.9.1H; Degraded Voltage/Loss of Voltage Operational Test: 1H Bus; Rev. 11
Transformers - Operating Guidelines and Work Procedures; Electric Transmission and
Distribution Substations Operations and Maintenance; Rev. 1.0322011
05-04-06; FPR: 900, 910 Series; Control Operations Relay Test Procedures Manual; Rev. 3
1-EPM-1802-06; Protective Relay Maintenance for Reserve Station Service Transformer A
Differential and Backup Ground; Rev. 4
0-PT-39.1; Triaxial Time-History Accelerograph Instrument Channel Check; Rev. 7
1-PT-39.2; Triaxial Time-History Accelerograph Instrumentation and Seismic Operational Test;
Rev. 19
1-PT-39.8; Triaxial Time-History Accelerograph Calibration; Rev. 4; dated 10/25/2011
0-GEP-30; Post Seismic Event System Engineering Walkdown; Rev. 1
1-PT-212.29; Valve Inservice Inspection (1-RC-PCV-1455C) NDT Protection Response Time
Test; Rev. 9; dated August 24, 2011
1-PT-212.30; Valve Inservice Inspection (1-RC-PCV-1456) NDT Protection Response Time
Test; Rev. 9; dated August 24, 2011
2-PT-212.29; Valve Inservice Inspection (2-RC-PCV-2455C) NDT Protection Response Time
Test; Rev. 10; dated August 26, 2011
Attachment 1
9
2-PT-212.30; Valve Inservice Inspection (2-RC-PCV-2456) NDT Protection Response Time
Test; Rev. 10; dated August 26, 2011
2-PT-44.4.1; Overpressurization Protection Instrumentation Operational Test; Rev. 42; dated
August 25, 2011
1-PT-44.4.1; Overpressurization Protection Instrumentation Operational Test; Rev. 39; dated
August 25, 2011
1-PT-212.9; Valve Inservice Inspection (Main Steam); Rev. 17; Completed September 4, 2011
1-PT-36.8; Reactor Protection and Engineered Safety Feature Total Response Time
Verification; Rev. 32; dated September 7, 2011
0-AP-36; Seismic Event; Revision 19
0-PT-39.7; Seismic Instrumentation after a Seismic Event; Revision 3
1-E-0, Reactor Trip or Safety Injection, Revision 44
2-E-0, Reactor Trip of safety Injection, Revision 47
1-ES-0.1, Reactor Trip Response, Revision 30
2-ES-0.1, Reactor Trip Response, Revision 30
EPIP-1.01, Emergency Manager Controlling Procedure, Revision 46
EPIP-1.03, Response to Alert, Revision 18
2-AR-F-D8, 2-EI-CB-21F annunciator D8 Turbine Driven AFW Pump Trouble or Lube Oil
Trouble, Revision 2
Earthquake Response and the North Anna Restart Readiness Demonstration Plan during a
public meeting on September 8, 2011, ML11252A006
North Anna Power Station Emergency Plan, Rev. 36
NAPS Emergency Action Level Matrices (Hot and Cold) and Technical Bases Document,
Revision 2
EPIP-1.06, Protective Action Recommendations, Revision 9
EPIP-2.01, Notification of State and Local Governments, Revision 35
EPIP-3.02, Activation of Technical Support Center, Revision 30
EPIP-3.03, Activation of Operational Support Center, Revision 17
EPIP-4.01, Radiological Assessment Director Controlling Procedure, Revision 28
EPIP-4.02, Radiation Protection Supervisor Controlling Procedure, Revision 22
EPIP-4.05, Respiratory Protection and KI Assessment, Revision 10
EPIP-4.07, Protective Measures, Revision 19 and 20
0-AP-36, Seismic Event, Revision 19
0-AP-10, Loss of Electrical Power, Revision 67
0-AP-23, Oil or Hazardous Substance Spill Response, Revision 16
1-AP-22.1, Loss of 1-FW-P-2 Turbine-Driven AFW Pump, Revision 14
1-AP-19, Loss of Bearing Cooling Water, Revision 17
1-AP-28, Loss on Instrument Air, Revision 31
1-AP-33.1, Reactor Coolant Pump Seal Failure, Revision 15
1-AP-35, Loss of Containment Air Recirculation Cooling, Revision 18
1-AP-5, Unit 1 Radiation Monitoring System, Revision 33
2-AP-22.2, Loss of 2-FW-P-3A Motor-Driven AFW Pump, Revision 11
2-AP-19, Loss of Bearing Cooling Water, Revision 15
2-AP-13, Loss of One or More Circulating Water Pumps, Revision 17
2-AP-14, Low Condenser Vacuum, Revision 20
2-AP-35, Loss of Containment Air Recirculation Cooling, Revision 18
2-AP-5, Unit 2 Radiation Monitoring System, Revision 44
Attachment 1
10
Vendor Manuals
VTM 59-F173-00002; Fairbanks Morse Opposed Piston Engines Instructions 3800TD8-1/8
Model 38TD8-1/8 Diesel Stationary
ET-N-10-0054; Use of Inconel X-750 EDG Exhaust Gaskets; Rev. 0
00813-0100-4235; Rosemount 1152 Alphaline Nuclear Pressure Transmitter Data Sheet; Rev.
BA; dated April 2007
GEK-35003; General Electric Instruction Manual for Reserve Station Transformers
Qualitrol 900/910 RPRR; Rapid Pressure Rise Relays
59-K001-00004; Kinemetrics, Inc. Operating Instructions for Model SP-1/TS-3 Seismic Switch
System
59-K001-00005; Kinemetrics, Inc. FBA-3 Trixial Force-Balance Accelerometer; dated February
1, 1978
59-K001-00002; Kinemetrics, Inc. Operating Instructions for SMA-3 Strong Motion
Accelerograph System; dated August 8, 1976
59-K001-00001; Kinemetrics, Inc. Operating Instructions for Model TS-3 Triaxial Seismic
Switch; Rev. 1; dated June 1, 1989
VTM-59-M947-0003; GSU Transformer Replacement for Units 1&2 Transformers T4059
through T4066 512.5 - 22KV 400MVA Transformers; Rev. 1
Vendor Technical Manual 59-E01 5-00001, Model PAR400 Peak Acceleration Recorder
Operation and Maintenance Manual, Revision 2
Vendor Technical Manual 59-E015-00002, Model PSR 1200 Peak Shock Recorder Operation
and Maintenance Manual, Revision 2
Vendor Technical Manual 59-E015-00003, Models P5A875 and PSA1575 Peak Shock
Annunciator Operation and Maintenance Manual, Revision 1
Vendor Technical Manual 59-K001-00001, Operating Instructions for SMP-1 Magnetic Tape
Playback System, Revision 1
Vendor Technical Manual 59-K001-00002, Operating Instructions for SMA-3 Strong Motion
Accelerograph System, Revision 2
Vendor Technical Manual 59-K000-00003, Operating Instructions for Model TS-3 TriaxaI
Seismic Switch, Revision 1
Vendor Technical Manual 59-K001-00004, Operating Instructions for Model SP-1/TS-3 Seismic
Switch System, Revision 1
Vendor Technical Manual 59-K001-00005 Operating Instructions for FBA-3 Triaxial Forced-
Balance Accelerometer, Revision 1
Work Orders
WO 59102038161; 2H EDG Install New Style Oil Scraper Rings and Pistons; dated May 27,
2010
WO 59080512401; 1H EDG Replace All 12 Cylinder Liners; dated September 9, 2009
WO 59079496201; 1J EDG Replace 10 Remaining Old Style Cylinder Liners; dated September
17, 2009
WO 59101704113; 2J EDG Replace All 12 Cylinder Liners; dated January 16, 2011
WO 59102341733; 2H EDG Repair Coolant Leak Post EPIP-3.03 Documentation; dated August
23, 2011
WO 59102342316; 2H EDG Replace Exhaust Gasket OCS #4 Extension Pipe; dated August,
25, 2011
WO 59102342452; 2H EDG Replace Water Inlet Gaskets on CS; dated August, 30, 2011
Attachment 1
11
WO 59102344717; 2J EDG Replace Water Inlet Pipe Gaskets; dated September 1, 2011
WO 59102341713; 2H EDG Remove Heat Shields For Inspection; dated August 24, 2011
WO 59102341714; 2J EDG Remove Heat Shields For Inspection; dated August 28, 2011
WO 59102341715; 1H EDG Remove Heat Shields For Inspection; dated August 28, 2011
WO 59102341716; 1J EDG Remove Heat Shields For Inspection; dated 8/xx/11
WO 59102345583; 1H EDG Water Bypass Fittings Re-Torque; dated September 2, 2011
WO 59102345639; 1J EDG Water Bypass Fittings Re-Torque (CS/OCS); dated September 3,
2011
WO 59102349576; Rebuild/Replace Coolant Pump on 1J EDG; dated September 5, 2011
WO 59102346517; Crane #15 Possible Bus Bar Damage; dated September 7, 2011
WO 59101674310; Protective Relay Maintenance for Reserve Station Service Transformer A
Differential and Backup Ground; Rev. 4; dated July 27, 2009
WO 59102343487; Perform Hi-pot Test for the U1 Isophase Bus Duct (Post Seismic
Inspection); dated August 31, 2011
WO 59102343486; Hi-Pot U2 Isophase; dated August 31, 2011
WO 59102345224; Post Seismic Event Walkdown - Fuse Holder 1-EI-CB-48B Found in Bottom
of Cabinet, dated August 31, 2011
WO 59102342521; 2J 4160V Relay drops; dated August 31, 2011
Attachment 1
SEQUENCE OF EVENTS
North Anna Power Station, Unit 1
Date/Time Event Description
August 23, 2011 Unit 1 at 100% power; U1 Turbine Driven Auxiliary Feedwater pump
removed from service for scheduled surveillance test
Magnitude 5.8 earthquake with epicenter near Mineral VA
13:51:10.224 Pressurizer High Level, Back up Heaters alarm begins to toggle. This is
assumed to be the onset of the earthquake on Unit 1
13:51:11.722 Power Range Instrument High Flux Rate (N42) received
13:51:11.791 Reactor Coolant System Loop 1A Low Flow Channel III alarm begins to
toggle
13:51:11.867 Power Range Instrument High Flux rate (N41) received
13:51:11.873 Nuclear Instruments Power Range High Flux Rate Trip Reactor Trip is
the first Out Reactor Trip signal
13:51:11.888 Main Transformer Sudden Pressure Relay (63X ABC) received
13:51:11.892 Main Transformer Low Relay Turbine Trip (86T) is the First Out Turbine
Trip Signal
13:51:11.918 B Reactor Trip Breaker Open
13:51.11.927 A Reactor Trip Breaker Open
13:51.12.047 Reserve Station Service Transformer B Sudden Pressure Relay (63A)
alarm received. B Reserve Service Transformer is de-energized
13:51:12.055 Generator output Breaker open (G12)
13:51:12.058 Reserve Station Service Transformer A Sudden Pressure Relay (63A)
alarm received. A Reserve Station Service transformer is de-energized
13:51:12.558 Reserve Station Service Transformer C Sudden Pressure Relay (63A)
alarm received. C Reserve Station Service Transformer is de-energized
13:51:12.695 Rod Position Indicator Rod Bottom Rod Drop received. Rods inserted.
Attachment 2
SEQUENCE OF EVENTS
North Anna Power Station, Unit 1
August 23, 2011 (continued)
Date/Time Event Description
13:51:13.384 Motor Driven Auxiliary Feedwater Pumps supplying B and C Steam
Generators. Steam Driven Pump Performance Test was in progress prior
to the event
13:51:15.570 Motor Driven Auxiliary Feedwater Pumps shut down on Emergency bus
undervoltage
13:51:20.579 1J Re-energized from 1-EE-EG-1J (1J Emergency Diesel Generator)
13:51:21.590 B Motor Driven Auxiliary Feedwater Pump re-started
13:51:21.669 1H Re-energized from 1-EE-EG-1H (1H Emergency Diesel Generator)
13:51:22.650 A Motor Driven Auxiliary Feedwater pump re-started
Attachment 2
SEQUENCE OF EVENTS
North Anna Power Station, Unit 2
Date/Time Event Description
August 23, 2011 Unit 2 at 100% power
Magnitude 5.8 earthquake with epicenter near Mineral VA
13:51:11.072 Refueling Water Storage Tank Chemical Addition Tank Low Level On
alarm begins to toggle. This is assumed to be the onset of the earthquake
on Unit 2
13:51:11.559 Pressure High Level Back Up Heaters On alarm begins to toggle similar
to Unit 1.
13:51:11.676 Power Range Instrument High Flux Rate (N41) received
13:51:11.756 Reactor Coolant System Loop A Channel I Low Flow alarm begins to
toggle
13:51:11.768 Reactor Coolant System Loop B Channel II Low Flow alarm begins to
toggle
13:51:11.829 Power Range Instrument High Flux Rate (N42) received
13:51:11.829 Power Range Instrument High Flux Rate (NI) Reactor Trip is the first
Out Reactor Trip signal
13:51:11.860 Reactor Coolant System Loop C Channel III Low Flow alarm begins to
toggle
13:51.11.888 A Reactor Trip Breaker Open
13:51.11.891 B Reactor Trip Breaker Open
13:51.11.900 Reactor Tripped - Turbine Trip is the first Out Turbine Trip signal
13:51:11.969 Main Transformer Low Relay Turbine Trip (86T) alarm received
13:51:12.048 Main Transformer Sudden Pressure Relay (63A) alarm received. B
Reserve Station Service Transformer is de-energized.
13:51:12.059 Main Transformer Sudden Pressure Relay (63A) alarm received. A
Reserve Station Service Transformer is de-energized.
13:51:12.193 Rod Position Indicator Rob Bottom Rod Drop received. Rods inserted.
Attachment 2
SEQUENCE OF EVENTS
North Anna Power Station, Unit 2
August 23, 2011 (continued)
Date/Time Event Description
13:51.12.559 Reserve Station Service Transformer C Sudden Pressure Relay (63A)
alarm received. C Reserve Station Service transformer is de-energized
13:51:14.139 All Auxiliary Feedwater Pumps running and supplying respective Steam
Generators
13:51:16.260 Motor Driven Auxiliary Feedwater Pumps shut down on Emergency bus
undervoltage
13:51:20.196 2H Re-energized from 2-EE-EG-2H (2H Emergency Diesel Generator)
13:51:21.100 A Motor Driven Auxiliary Feedwater Pump re-started
13:51:21.296 2J Re-energized from 2-EE-EG-2J (2J Emergency Diesel Generator)
13:51:22.130 B Motor Driven Auxiliary Feedwater pump re-started
Attachment 2
SEQUENCE OF EVENTS
North Anna Power Station, Unit 1 and 2
August 23, 2011 Unit 1 and Unit 2 in Mode 3
Date/Time Event Description
14:03 Alert declared Tab HA6.1, Shift Manager judgment
14:19 1-FW-P-2 available (flowing to A Steam Generator)
14:40 2H Emergency Diesel Generator manually tripped on coolant leak 2H
Emergency Bus de-energized
14:55 Alert declared Tab SA1.1 U2 AC capability reduced to a single source
(2J Emergency Diesel Generator)
15:18 2H Emergency Bus de-energized by the Station Blackout Diesel
17:23 Energized C Reserve Station Service Transformer and F transfer bus
17:40 2J emergency bus transferred to C Reserve Station Service
Transformer
17:48 1H energized from F transfer bus, securing 1H Emergency Diesel
Generator
20:03 B Reserve Station Service Transformer energized
20:17 A Reserve Station Service Transformer energized
22:58 Offsite power supplying Emergency Busses, 3 Emergency Diesel
Generators and Station Blackout diesel is Auto and available
August 24, 2011
08:51 Commenced Unit 1 cooldown
11:16 Downgrade to Notice of Unusual Event under Tab HU1.1
13:15 Notice of Unusual Event terminated
13:34 Unit 1 in Mode 4, Hot Shutdown
21:26 Unit 1 in Mode 5, Cold Shutdown
Attachment 2
SEQUENCE OF EVENTS
North Anna Power Station, Unit 1 and 2
Date/Time Event Description
August 25, 2011
01:08 Notice of Unusual Event declared under tab HU1.1 (aftershock)
11:37 Commenced Unit 2 cooldown
16:22 Unit 2 in Mode 4, Hot Shutdown
August 26, 2011
14:05 NRC notification emergency preparedness criteria seismic activity >
Operating Basis Earthquake met but not declared (Emergency Action
Level HAA6.1 versus HA1.1)
16:23 NRC notification of potential unanalyzed condition (Design Basis
Earthquake above 5 Hz)
20:38 Unit 2 in Mode 5, Cold Shutdown
August 28, 2011
15:36 Notice of Unusual Event terminated
September 1, 2011
05:18 Notice of Unusual Event declared, Tab HU1.1 (aftershock)
12:23 Notice of Unusual Event terminated
Attachment 2
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