ML051740204
| ML051740204 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 06/22/2005 |
| From: | Satorius M Division Reactor Projects III |
| To: | Crane C Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-05-010 | |
| Download: ML051740204 (15) | |
See also: IR 05000373/2005010
Text
June 22, 2005
Mr. Christopher M. Crane
President and Chief Nuclear Officer
Exelon Nuclear
Exelon Generation Company, LLC
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: LASALLE COUNTY STATION, UNITS 1 AND 2
NRC INSPECTION REPORT 05000373/2005010; 05000374/2005010
Dear Mr. Crane:
On May 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed a preliminary
review of the single point vulnerability within your offsite power transformer circuits. This letter
and the supporting documentation (Enclosure) discusses a finding that appears to have low to
moderate safety significance. As described in Section 4OA3 of this report, the finding pertains
to a single point vulnerability that could result in a loss of all onsite and offsite power sources to
both 4160 Vac Division 1 and Division 2 safety-related buses at either of your LaSalle County
Station units. This finding was assessed based on the best available information, including
influential assumptions, using the applicable Significance Determination Process (SDP) and
was preliminarily determined to be a White finding. The final resolution of this finding will
convey the increment in the importance to safety by assigning the corresponding color, i.e.,
White, a finding with some increased importance to safety, which may require additional
inspection. This single point vulnerability was reported to the NRC by you pursuant to the
requirements of 10 CFR 50.73 on March 28, 2005, as Licensee Event Report (LER) 2005-001.
The results of the preliminary review were discussed on June 1, 2005, with the Site Vice
President, Ms. Susan Landahl, and other members of your staff.
The inspection examined activities conducted under your licenses as they relate to safety and
to compliance with the Commissions rules and regulations and with the conditions of your
licenses. Specifically, this inspection focused on the single point vulnerability within your offsite
power transformer circuits identified by your staff on February 2, 2005, and your subsequent
corrective actions. The inspectors reviewed selected procedures and records, observed
activities, and interviewed personnel.
At approximately 3:42 p.m. on February 2, 2005, plant operators determined that they should
enter a 12-hour Technical Specification Required Action for the unavailability of offsite and
onsite power systems. A licensee analysis of the issue determined that the current transformer
(CT) circuits that supply the overcurrent relay scheme for each divisional bus were connected to
a common point that supplies control room indication for the total station auxiliary transformer
(SAT) Y winding power (kW) and current (amperes). Further, your engineering staff
C. Crane -2-
determined that an open circuit condition on any of the CT phases downstream of the common
point in the circuit would have initiated a trip of the associated SAT feed breakers for the
applicable buses (e.g., 141Y, 142Y, 241Y and 242Y). Following a trip of the bus feed breakers,
the lockout relay for the respective bus would have initiated a trip of the other bus breakers and
prevented any closure of these breakers. The ultimate result would have been a loss of all
onsite and offsite power sources to both 4160 Vac Division 1 and Division 2 safety-related
buses, because no emergency diesel generator (EDG) or offsite power source would have
been permitted to close onto the respective Division 1 or Division 2 safety buses. Division III
(High Pressure Core Spray) remained available and unaffected by this event.
In response to the identification of this condition on each unit, a temporary modification was
developed and installed by your engineering and electrical maintenance groups to isolate the
common metering circuitry between the Division 1 and Division 2 buses responsible for the
single point vulnerability while long term corrective actions were developed.
Be advised that this significance assessment is preliminary. The final significance assessment
will include consideration of any further information or perspectives you provide that may
warrant reconsideration of the methodology or assumptions used during the preliminary
significance assessment. As outlined in Section 06.06 of Inspection Manual Chapter 0305 and
based on the information we currently have, this finding appears to meet the criteria for
consideration as an old design issue.
The finding is also an apparent violation of 10 CFR Part 50, Appendix B, Criterion III, for the
failure to assure applicable regulatory requirements and the design basis for a safety-related
system were correctly maintained and controlled commensurate with the standards applied to
the original design.
Before the NRC finalizes this significance determination, we are providing you an opportunity
(1) to present to the NRC your perspectives on the facts and assumptions used by the NRC to
arrive at the finding and its significance at a Regulatory Conference; or (2) submit your position
on the finding to the NRC in writing.
If you request a Regulatory Conference, it should be held within 30 days of the receipt of this
letter and we encourage you to submit supporting documentation on the docket at least 1 week
prior to the conference in an effort to make the conference more effective. If a Regulatory
Conference is held, it will be open for public observation. If you decide to submit only a written
response, such a submittal should be sent to the NRC within 30 days of the receipt of this letter.
Please contact Bruce Burgess at 630-829-9629 within 10 business days of the date of receipt
of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days,
we will continue with our significance determination and enforcement decision and you will be
advised via separate correspondence of the results of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for the inspection finding at this time. In addition, please be advised that the
C. Crane -3-
characterization of the apparent violation described in this letter may change as a result of
further NRC review.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRC's
document system (ADAMS). ADAMS is accessible from the NRC Web site at:
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Mark A. Satorius, Director
Division of Reactor Projects
Docket Nos. 50-373; 50-374
Enclosure: Inspection Report 05000373/2005010; 05000374/2005010
w/Attachment: Supplemental Information
cc w/encl: Site Vice President - LaSalle County Station
LaSalle County Station Plant Manager
Regulatory Assurance Manager - LaSalle County Station
Chief Operating Officer
Senior Vice President - Nuclear Services
Senior Vice President - Mid-West Regional
Operating Group
Vice President - Mid-West Operations Support
Vice President - Licensing and Regulatory Affairs
Director Licensing - Mid-West Regional
Operating Group
Manager Licensing - Clinton and LaSalle
Senior Counsel, Nuclear, Mid-West Regional
Operating Group
Document Control Desk - Licensing
Assistant Attorney General
Illinois Department of Nuclear Safety
State Liaison Officer
Chairman, Illinois Commerce Commission
See Previous Concurrences
DOCUMENT NAME: E:\Filenet\ML051740204.wpd
To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy
OFFICE RIII RIII RIII OE RIII
NAME BBurgess*:dtp SBurgess* KObrien BLB* MSatorius
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DATE 06/14/05 06/14/05 06/15/05 06/22/05 06/22/05
OFFICIAL RECORD COPY
C. Crane -5-
DISTRIBUTION
SECY
L. Reyes, EDO
W. Kane, DEDRPP
M. Johnson, OE
C. Nolan, OE
J. Caldwell, RIII:RA
G.Grant, RIII:DRA
L. Chandler, OGC
J. Moore, OGC
J. Dyer, NRR
S. Richards, Chief, IIPB, NRR
M. Tschiltz, Chief, SPSB, NRR
D. Merzke, NRR
D. Holody, Enforcement Coordinator, RI
C. Evans, Enforcement Coordinator, RII
G. Sanborn, Enforcement Coordinator, RIV
F. Bonnett, Enforcement Coordinator, NRR
R. Barnes, Enforcement Coordinator, NSIR
R. Arrighi, OE
T. Smith, OGC
Resident Inspector
S. Gagner, OPA
H. Bell, OIG
G. Caputo, OI
J. Piccone, OSTP
C. Pederson, RIII
R. Caniano, RIII
S. Orth, RIII
C. Weil, RIII
J. Strasma, RIII:PA
R. Lickus, RIII
J. Lynch, RIII
RidsNrrDipmlipb
KKB
CAA1
DRPIII
DRSIII
PLB1
JRK1
OEWEB
OEMAIL
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-373; 50-374
Report No: 05000373/2005010; 05000374/2005010
Licensee: Exelon Generation Company, LLC
Facility: LaSalle County Station, Units 1 and 2
Location: 2601 N. 21st Road
Marseilles, IL 61341
Dates: February 1 through May 31, 2005
Inspectors: D. Kimble, Senior Resident Inspector
D. Eskins, Resident Inspector
S. Burgess, Senior Reactor Analyst
L. Kozak, Senior Reactor Analyst
J. Yesinowski, Illinois Dept. of Emergency Management
Approved by: Bruce L. Burgess, Chief
Branch 2
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000373/2005010, 05000374/2005010; 02/01/2005 - 05/31/2005; LaSalle County Station,
Units 1 & 2; Event Follow-up.
The report covered the follow-up inspection activities for a Licensee Event Report. The
inspection was conducted by the resident inspectors. This inspection identified a preliminary
White finding and associated apparent violation (AV). The significance of most findings is
indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply
may be Green or be assigned a severity level after NRC management review. The NRCs
program for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A. NRC-Identified and Self-Revealed Findings
Cornerstones: Initiating Events and Mitigating Systems
TBD. An apparent violation having a preliminary low to moderate safety significance
was identified during the licensees review of a similar issue identified at Crystal River
Nuclear Plant Unit 3 on January 27, 2005. A design deficiency in a metering circuit for
the sites normal 4160 volts-alternating current (Vac) offsite power supply induced a
vulnerability whereby a single fault in the metering circuitry, for a given unit, could have
resulted in the loss of all Division 1 and Division 2 safety-related 4160 Vac power on a
given unit.
The finding was determined to be greater than minor because it impacted both the
Initiating Events and Mitigating Systems Cornerstones. The finding was preliminarily
determined to be of low to moderate safety significance following the performance of a
case-specific Phase 3 SDP. Corrective actions taken by the licensee included installing
temporary modifications on each unit to remove the metering circuitry in question.
(Section 4OA3)
B. Licensee-Identified Violations
No violations of significance were identified.
2 Enclosure
REPORT DETAILS
4. OTHER ACTIVITIES
Cornerstones: Initiating Events and Mitigating Systems
4OA3 Event Follow-up (71153)
(Closed) Unresolved Item 05000373/2005002-10; 05000374/2005002-10: Single
Failure Vulnerability of Safety-Related 4160 Vac Division 1 and Division 2 Protective
Relay Circuitry Emergency Notification System (ENS) 41366
(Closed) Licensee Event Report (LER) 05000373/2005-01-00; 05000374/2005-01-00:
Single Failure Vulnerability of Division 1 and Division 2 Protective Relay Circuitry Due to
Latent Design Deficiency
a. Inspection Scope
On January 27, 2005, a single failure was discovered at Crystal River Unit 3 (CR-3) that
could prevent both emergency diesel generators (EDGs) and both offsite power sources
from supplying power to their respective engineered safeguards (ES) buses. This was a
condition reportable under 10 CFR 50.72 (b)(3)(ii)(B), for a plant being in an unanalyzed
condition that significantly degraded plant safety (ENS 41362).
The LaSalle Station Electrical System Engineering Supervisor was informed of the
CR-3 event on February 1, 2005, and was provided a copy of ENS 41362 by the
LaSalle Station NRC Senior Resident Inspector. LaSalle Station engineers reviewed the
safety-related bus protective relaying circuitry to determine if a similar vulnerability
existed. The following day, plant engineers determined that a single failure vulnerability
existed for LaSalle between the current transformer (CT) circuits of the divisional safety-
related buses (e.g., 141Y, 142Y, 241Y and 242Y).
Upon notification of the discovery and subsequent entry into a 12-hour Technical
Specification Required Action potentially leading to the shutdown of both LaSalle units,
inspectors responded to the plant to monitor the licensees actions. The inspectors
observed plant parameters and status; evaluated the performance of plant systems and
licensee actions; and confirmed that the licensee properly reported the event as
required by 10 CFR 50.72. The inspectors determined that all systems responded as
intended, and that no human performance errors complicated the event response.
The inspectors review and closure of this LER constituted a single inspection sample.
3 Enclosure
b. Findings
Introduction
A finding with a low to moderate preliminary safety significance (White) was identified
following review of an LER that communicated to the NRC a design deficiency in the
4160 Vac station auxiliary transformer (SAT) metering circuitry. An associated apparent
violation of the requirements of 10 CFR 50, Appendix B, Criterion III, Design Control,
was also identified.
Description
At approximately 3:42 p.m. on February 2, 2005, plant operators determined that they
should enter 12-hour Technical Specification Required Action for unavailability of offsite
and onsite power systems. A licensee analysis of the issue determined that the CT
circuits that supply the overcurrent relay scheme for each divisional bus were connected
to a common point that supplies control room indication for the total SAT Y winding
power (kW) and current (amperes). Further, licensee engineers determined that an
open circuit condition on any of the CT phases downstream of the common point in the
circuit would have resulted in an unbalanced current condition, which would have
initiated a trip of the associated SAT feed breakers for the applicable buses (e.g., 141Y
and 142Y, 241Y and 242Y). Specifically, the current unbalance would have actuated
the ground fault relays, causing the SAT feed breaker relays to lock out both divisions.
Following a trip of the bus feed breakers, the lockout relay for the respective bus would
have initiated a trip of the other bus breakers and prevented any closure of these
breakers. The ultimate result would have been a loss of all onsite and offsite power
sources to both 4160 Vac Division 1 and Division 2 safety-related buses, because no
EDG or offsite power source would have been permitted to close onto the respective
Division 1 or Division 2 safety buses.
A temporary modification was developed and installed on each unit to isolate the
common metering circuitry between the Division 1 and Division 2 buses responsible for
the single point vulnerability. These modifications were installed and Technical
Specification Required Actions exited on Unit 1 in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, 23 minutes, and on Unit 2 in
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, 48 minutes. All actions were monitored by the inspectors. The licensee
entered this issue into their corrective action program as Issue Report (IR) 297076, and
into their corporate corrective action program as IR 299641.
Analysis
In accordance with IMC 0612, the inspectors determined that the licensee failed to
appropriately control the design of modifications affecting the Division 1 and Division 2
4160 Vac safety-related buses on each unit per regulatory requirements. This
performance deficiency resulted in a single failure vulnerability that would result in the
loss of all offsite and onsite AC power to both divisions of safety-related distribution
buses.
4 Enclosure
Phase 1 Screening Logic, Results, and Assumptions
The inspectors determined that the issue was more than minor because it was
associated with the design control attributes of both the initiating events and mitigating
systems cornerstones of the reactor safety strategic performance area. The issue
affected both the initiating events objective to limit the likelihood of those events that
upset plant stability and challenge critical safety functions during shutdown as well as
power operations, and the mitigating systems objective to ensure the availability,
reliability, and capability of systems that respond to initiating events.
In accordance with IMC 0609, Appendix A, the inspectors conducted an SDP Phase 1
screening and determined that the finding degraded both the Initiating Events
Cornerstone and Mitigating Systems Cornerstone. Because the issue degraded two or
more cornerstones, a Phase 2 analysis was required.
Phase 2 Risk Evaluation
The performance deficiency may result in an increased likelihood of a transient without
power conversion system (PCS) and a loss of offsite power (LOOP). In both cases, all
alternating current (AC) power is unavailable to support mitigation systems with the
exception of high pressure core spray (HPCS), powered by the Division III EDG, and
reactor core isolation cooling (RCIC), which is supported by station batteries with no
dedicated battery chargers. The Phase 2 analysis results in a RED risk
characterization. However, because this issue involves an extremely narrow window of
vulnerability (failure probability of a highly reliable component), the Phase 2 worksheets
for LaSalle do not appropriately characterize the risk significance of this event and are
overly conservative in their estimation of the risk. Because of the high reliability of
components that could fail to give a CT open circuit, the initiating event frequency of a
LOOP or a transient without PCS would not be increased by one order of magnitude.
Therefore, a Phase 3 analysis was required to characterize the risk significance of this
issue.
Phase 3 Risk Analysis
The NRCs senior risk analysts (SRAs) performed a risk evaluation of the LaSalle
single failure vulnerability using the standardized plant analysis risk (SPAR) model,
version 3.11, and generic failure probabilities obtained from the Office of Nuclear
Reactor Regulation (NRR). SPAR was run using a LOOP event with both safety-related
buses assumed unavailable to obtain a conditional core damage probability (CCDP) of
1.3E-3. No specific SPAR model changes were made, as a general risk
characterization was desired. Assuming that the single failure (CT open circuit) had a
failure rate of 1.0E-6/hr, the condition existed for a year, and assuming a conservative
recovery credit of 1E-1, the change in core damage frequency ( CDF) was 1.1E-6/yr
(White).
Potential Risk Contribution Due to Large Early Release Frequency (LERF)
Using IMC 0609, Appendix H, the SRA determined that this was a Type A finding for a
Mark II containment. Using Table 5.2, the reactor coolant system (RCS) would be at a
5 Enclosure
high pressure during the station blackout (SBO) condition; therefore, a LERF factor of
0.3 was applied to the Phase 3 calculated CDF. The resultant LERF was 3.3E-7
(White). In this case, LERF did not change the risk characterization by an order of
magnitude.
Licensees Analysis
Internal Events
Based on the licensees internal events risk assessment, the CDF was calculated at
1.82E-6/yr. In determining the failure probability of the CT circuitry, the licensee used
both a fault tree analysis and an analysis of industry operating data. The annual
initiating event frequency of the postulated CT circuitry failure scenarios was of low
frequency, in the low 1E-4/yr to low 1E-3/yr range depending upon the methodology
used in the calculation and the assumptions. The licensee determined the best estimate
frequency was that calculated using the industry experience data, which was 1.2E-4/yr.
The licensee also performed eleven sensitivity studies. The SRAs reviewed the
licensees analysis and agreed with the assumptions and the methodology used.
LERF Contribution
The licensees LERF analysis determined that the LERF for internal events, fire
scenarios, and seismic scenarios was 3.4E-7/yr, which was consistent with a White risk
characterization and would not change the overall White risk characterization of this
finding.
Potential Risk Contribution Due to External Events
The licensee evaluated external event contributions and determined that external
hazards such as flooding, transportation, chemical spills, etc., were not considered
credible events that could have lead to a circuit fault.
Seismic-induced CT failures of interest were based on the likelihood of a seismic event
being of sufficient magnitude to shake the subject panel of interest (located in the main
control room) enough to create an open circuit CT failure. This was judged to be an
unlikely occurrence; however, the licensee did quantitatively calculate the CDF for the
seismic open circuit as 6.3E-8.
Fire
Fire-induced CT failures were considered as the most likely credible initiating event that
could potentially cause the CT failure. The CT circuitry was located in the main control
room and contained electrical circuits for operating the EDGs, bus-tie breakers, unit
auxiliary transformer (UAT) feed breakers, and SAT feed breakers. Panels for HPCS
and RCIC were located across the room from the CT panels. Based on the licensees
fire analysis, the total contribution for fire-induced open circuit scenarios was 9.5E-8.
6 Enclosure
The licensees initiating event frequency for main control room cabinets was
approximately one order of magnitude lower than the fire protection SDP result;
however, the SDP took into account the entire main control room and not simply the
electrical panels of interest. The severity factor and non-suppression factor were also
consistent with the SDP, and the licensee did not take much credit for mitigating
systems. The SRAs determined that the overall analysis was acceptable.
Licensee Analysis Conclusion
The licensees total CDF considering internal events, LERF considerations, and
external events was 2E-6/yr, indicating a finding of low to medium safety significance
(White).
Significance Determination Conclusion
The NRCs calculation of the CDF was based on generic CT open circuit failure
assumptions and on conservative recovery actions. Based on a review of the licensees
analysis using industry component failure data, reasonable operator recovery actions,
plant-specific fire analysis, and plant-specific seismic analysis, the NRC SRAs
recommended a White risk characterization for this finding. The SPAR analysis
obtained similar results indicating that the risk characterization was appropriate.
Enforcement
10 CFR 50, Appendix B, Criterion III requires, in part, that design changes, including
field changes, shall be subject to design control measures commensurate with those
applied to the original design.
10 CFR 50, Appendix A, General Design Criterion 17, requires, in part, that onsite
electric power supplies, including the onsite electric distribution system, shall have
sufficient independence, redundancy, and testability to perform their safety functions
assuming a single failure.
Contrary to the above, modifications made to the emergency diesel generation (EDG)
output circuit breakers that were completed on December 21, 1988, for Unit 2,
Division 1; September 26, 1989, for Unit 1, Division 1; March 8, 1991, for Unit 1,
Division 2; and February 1, 1992, for Unit 2, Division 2 did not contain design control
measures commensurate with those applied to the original design. Specifically, the
design change introduced a single failure vulnerability such that a failure (i.e., open
circuit) of the common CT circuit would have resulted in all loss of all AC, including the
EDG supplied feeds, for the Division 1 and Division 2 safety buses on both Units.
The original issue associated with this finding was identified by an NRC inspection team
at CR-3 and, within NRC Region III, the issue was first brought to the attention of the
licensee by inspectors at Clinton, Dresden, and Quad Cities Stations on Monday,
January 31, 2005, and at LaSalle County Station by the NRC Senior Resident Inspector
on Tuesday, February 1, 2005. Although the interactions between licensee site
personnel and the inspectors accelerated the licensees examination of the issue at
each site and perhaps prompted a more thorough examination than might have
7 Enclosure
otherwise taken place, the inspectors determined that in all likelihood the licensees own
internal operating experience program would have triggered the licensee to have looked
into the issue in due course. As a result, the finding was considered licensee-identified
for enforcement purposes.
Following identification of the single point vulnerability by the Electrical Engineering
Group at LaSalle Station, the licensee took prompt action to remove the vulnerability on
each unit via the temporary modification process. These temporary modifications were
completed in less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> on each unit, and within the Technical Specification
Allowed Outage Time limit. A plant modification was performed during the
February-March 2005 Unit 2 refuel outage to permanently eliminate the vulnerability on
Unit 2. On Unit 1, the temporary modification will remain in place until the 2006 Unit 1
refuel outage when a permanent plant modification will be installed on that unit.
The inspectors determined that normal licensee surveillances and QA activities were not
likely to have identified the vulnerability. Because the metering circuits connecting the
Division 1 and Division 2 buses have existed from the time of original construction and
the modifications to the EDG breakers occurred over 10 years ago, the performance
errors that caused the issue were determined not to be representative of licensee
present day performance.
4OA6 Meetings
Exit Meeting
The inspectors presented the inspection results to the Site Vice President,
Ms. S. Landahl, and other members of licensee management on June 1, 2005. The
inspectors asked the licensee about proprietary information associated with the
inspection; no proprietary information was identified.
ATTACHMENT: SUPPLEMENTAL INFORMATION
8 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
S. Landahl, Site Vice President
D. Enright, Plant Manager
T. Connor, Maintenance Director
L. Coyle, Operations Director
D. Czufin, Site Engineering Director
C. Dieckmann, Training Manager
A. Ferko, Nuclear Oversight Manager
F. Gogliotti, System Engineering Manager
P. Holland, Regulatory Assurance - NRC Coordinator
B. Kapellas, Radiation Protection Manager
H. Madronero, Engineering Programs Manager
W. Riffer, Emergency Planning Manager
T. Simpkin, Regulatory Assurance Manager
Nuclear Regulatory Commission
B. Burgess, Chief, Reactor Projects Branch 2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000373/2005010-01; AV Failure to Maintain Required Design Redundancy Against
05000374/2005010-01 a Single Failure Involving Safety-Related 4160 Vac
Division 1 and Division 2 Bus Metering Circuitry
(Section 4OA3)
Closed
05000373/2005002-10; URI Single Failure Vulnerability of Safety-Related 4160 Vac
05000374/2005002-10 Division 1 and Division 2 Protective Relay Circuitry
(ENS 41366) (Section 4OA3)
05000373/2005-01-00; LER Single Failure Vulnerability of Division 1 and Division 2
05000374/2005-01-00 Protective Relay Circuitry Due to Latent Design Deficiency
(Section 4OA3)
Discussed
None.
1 Attachment
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety, but rather that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
4OA3 Event Follow-up
Modifications:
- M1-1-86-085; Emergency Diesel Generator No. 0, Unit 1; 9/26/1989
- M1-1-84-018; Emergency Diesel Generator No. 1A, Unit 1; 3/8/1991
- M1-2-84-031; Emergency Diesel Generator No. 2A, Unit 2; 2/1/1992
- M1-2-86-093; Emergency Diesel Generator No. 0, Unit 2; 12/21/1988
Issue Reports:
- 299188; Lack of Minimum 6-Inch Physical Separation in Division 1 and 2 CTs;
2/8/2005
- 297076; Vulnerability of Division 1 and 2 Protective Relay Circuitry; 2/2/2005
Operability Evaluation:
- OE 05-001; Vulnerability of Division 1 and 2 Protective Relay Circuitry; Revision 0
Exelon Risk Management Team Report on the Risk Significance of the Single Point
Vulnerability; Revision 0
Root Cause Report:
- 299641; Single Failure Vulnerability of Safety-Related Division 1 and 2 Protective
Relay Circuitry; 3/8/2005
- EC 353657; TCCP to Isolate Metering Common to 141Y/142Y and 241Y/242Y
Safety-Related Buses; 2/2/2005
Drawings and Prints:
- 1E-2-4000PG; Relaying & Metering Diagram - 4160 Vac Switchgear 241Y; Revision L
- 1E-1-4000PJ; Relaying & Metering Diagram - 4160 Vac Switchgear 142Y; Revision M
- 1E-1-4000PG; Relaying & Metering Diagram - 4160 Vac Switchgear 141Y; Revision N
- 1E-2-4000PJ; Relaying & Metering Diagram - 4160 Vac Switchgear 242Y; Revision K
2 Attachment
LIST OF ACRONYMS USED
AC Alternating Current
AV Apparent Violation
CCDP Conditional Core Damage Probability
CDF Core Damage Frequency
CFR Code of Federal Regulations
CR-3 Crystal River Unit 3
CT Current Transformer
EDG Emergency Diesel Generator
ENS Emergency Notification System
ES Engineered Safeguards
IMC Inspection Manual Chapter
IR Issue Report
kW Kilowatts
LER Licensee Event Report
LERF Large Early Release Frequency
LOOP Loss of Offsite Power
NRC Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation
PCS Power Conversion System
RCIC Reactor Core Isolation Cooling
SAT Station Auxiliary Transformer
SBO Station Blackout
SDP Significance Determination Process
SPAR Standardized Plant Analysis Risk
SRA Senior Risk Analyst
UAT Unit Auxiliary Transformer
URI Unresolved Item
Vac Volts - Alternating Current
3 Attachment