ML081270639
| ML081270639 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 05/06/2008 |
| From: | Chamberlain D NRC/RGN-IV/DRP |
| To: | Minahan S Nebraska Public Power District (NPPD) |
| References | |
| EA-08-124 IR-08-002 | |
| Download: ML081270639 (42) | |
See also: IR 05000298/2008002
Text
UNITED STATES
NUC LE AR RE G UL AT O RY C O M M I S S I O N
R E GI ON I V
612 EAST LAMAR BLVD , SU I TE 400
AR LI N GTON , TEXAS 76011-4125
May 6, 2008
EA 08-124
Stewart B. Minahan
Vice President - Nuclear and CNO
Nebraska Public Power District
PO Box 98
Brownville NE 68321
SUBJECT: COOPER NUCLEAR STATION - NRC INTEGRATED INPSECTION
REPORT 05000298/2008002
Dear Mr. Minahan:
On March 22, 2008 the U.S. Nuclear Regulatory Commission (NRC) completed an integrated
inspection at your Cooper Nuclear Station. The enclosed report documents the inspection
results, which were discussed on April 14, 2008 with Mr. M. Colomb, General Manager of Plant
Operations, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
As described in Section 1R19 of this report, the NRC concluded that the failure to establish
adequate procedural controls for the maintenance of electrical connections on diesel generators
led to the failure of Diesel Generator 2 during testing on January 15, 2008. The safety
significance of this finding was assessed on the basis of the best available information, including
influential assumptions, using the applicable Significance Determination Process and was
preliminarily determined to be a White (low to moderate safety significance) finding.
Attachment 2 of this report provides a detailed description of the preliminary risk assessment.
In accordance with NRC Inspection Manual Chapter 0609, Significance Determination
Process, we intend to complete our evaluation using the best available information and issue
our final determination of safety significance within 90 days of this letter.
This finding does not represent an immediate safety concern because of the corrective actions
you have taken. These actions included applying thread locking compound to the amphenol
connections on both diesel generators.
Also, this finding constitutes an apparent violation of NRC requirements and is being
considered for escalated enforcement action in accordance with the NRC Enforcement
Policy. The current Enforcement Policy is included on the NRCs Web site at
http://www.nrc.gov/reading-rm/adams.html. This significance determination process
encourages an open dialog between the staff and the licensee, however the dialogue should not
impact the timeliness of the staffs final determination.
Nebraska Public Power District -2-
Before we make a final decision on this matter, 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 documentation at least one
week prior to the conference in an effort to make the conference more efficient and effective. If
a Regulatory Conference is held, it will be open for public observation. If you decide to submit
only a written response, such submittal should be sent to the NRC within 30 days of the receipt
of this letter. If you decline to request a regulatory conference or submit a written response,
your ability to appeal the final SDP determination can be affected, in that by not doing either you
fail to meet the appeal requirements stated in the prerequisite and limitation sections of
Attachment 2 of IMC 0609.
Please contact Mr. Rick Deese at (817) 276-6573 within 10 business days of the date 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
by separate correspondence of the results of our deliberation 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 number and
characterization of the apparent violation described in the enclosed inspection report may
change as a result of further NRC review.
The report also documents one finding which was evaluated under the risk SDP as having very
low safety significance (Green). The finding was determined to involve a violation of NRC
requirements. However, because of very low safety significance, and because the issue was
entered into your corrective action program, the NRC is treating the issue as a noncited violation
in accordance with Section VI. A. 1 of the NRC Enforcement Policy. If you contest the subject
or severity of a Non-Cited Violation, you should provide a response within 30 days of the date of
this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the
Regional Administrator, U.S. Nuclear Regulatory Commission - Region IV, 611 Ryan Plaza
Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector
Office at the Cooper Nuclear Station.
Nebraska Public Power District -3-
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter
and its enclosure will be made available electronically for public inspection in the NRC
Public Document Room or from the Publicly Available Records (PARS) component of
NRCs document system (ADAMS), accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Dwight D. Chamberlain, Director
Division of Reactor Projects
Docket No: 50-298
License No: DPR-46
Enclosure:
NRC Inspection Report 05000298/2008002
w/Attachments:
Attachment 1: Supplemental Information
Attachment 2: Preliminary Risk Assessment
cc w/enclosure:
John C. McClure, Vice President
Gene Mace
and General Counsel
Nuclear Asset Manager
Nebraska Public Power District
Nebraska Public Power District
P.O. Box 499
P.O. Box 98
Columbus, NE 68602-0499
Brownville, NE 68321
David Van Der Kamp Michael J. Linder, Director
Licensing Manager Nebraska Department of
Nebraska Public Power District Environmental Quality
P.O. Box 98 P.O. Box 98922
Brownville, NE 68321 Lincoln, NE 68509-8922
Julia Schmitt, Manager
Radiation Control Program
Chairman
Nebraska Health & Human Services
Nemaha County Board of Commissioners
Dept. of Regulation & Licensing
Nemaha County Courthouse
Division of Public Health Assurance
1824 N Street
301 Centennial Mall, South
Auburn, NE 68305
P.O. Box 95007
Lincoln, NE 68509-5007
Nebraska Public Power District -4-
H. Floyd Gilzow
Director, Missouri State Emergency
Deputy Director for Policy
Management Agency
Missouri Department of Natural Resources
P.O. Box 116
P. O. Box 176
Jefferson City, MO 65102-0116
Jefferson City, MO 65102-0176
Chief, Radiation and Asbestos Melanie Rasmussen, State Liaison Officer/
Control Section Radiation Control Program Director
Kansas Department of Health Bureau of Radiological Health
and Environment Iowa Department of Public Health
Bureau of Air and Radiation Lucas State Office Building, 5th Floor
1000 SW Jackson, Suite 310 321 East 12th Street
Topeka, KS 66612-1366 Des Moines, IA 50319
John F. McCann, Director, Licensing Keith G. Henke, Planner
Entergy Nuclear Northeast Division of Community and Public Health
Entergy Nuclear Operations, Inc. Office of Emergency Coordination
440 Hamilton Avenue 930 Wildwood, P.O. Box 570
White Plains, NY 10601-1813 Jefferson City, MO 65102
Ronald L. McCabe, Chief
Paul V. Fleming, Director of Nuclear Technological Hazards Branch
Safety Assurance National Preparedness Division
Nebraska Public Power District DHS/FEMA
P.O. Box 98 9221 Ward Parkway
Brownville, NE 68321 Suite 300
Kansas City, MO 64114-3372
Nebraska Public Power District -5-
Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov)
DRP Director (Dwight.Chamberlain@nrc.gov)
DRS Director (Roy.Caniano@nrc.gov)
DRS Deputy Director (Troy.Pruett@nrc.gov)
Senior Resident Inspector (Nick.Taylor@nrc.gov)
Branch Chief, DRP/C (Rick.Deese@nrc.gov)
Senior Project Engineer, DRP/C (Wayne.Walker@nrc.gov)
Team Leader, DRP/TSS (Chuck.Paulk@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Only inspection reports to the following:
J. Adams, OEDO RIV Coordinator (John.Adams@nrc.gov)
P. Lougheed, OEDO RIV Coordinator (Patricia.Lougheed@nrc.gov)
ROPreports
CNS Site Secretary (Sue.Farmer@nrc.gov)
SUNSI Review Completed: WCW ADAMS: ; Yes No Initials: WCW
- Publicly Available Non-Publicly Available Sensitive ; Non-Sensitive
R:\_REACTORS\_CNS\2008\CN2008-002RP-NHT.doc ML081270639
RIV:SRI:DRP/C RI:DRP/C SPE:DRP/C DRS:SRA C:DRS/OB C:DRS/EB2
NHTaylor MLChambers WCWalker MFRunyan RELantz LJSmith
E-Walker /RA/ E-mailed /RA/ /RA/ /RA/ /RA/
4/24/08 4/23/08 4/24 /08 4/24/08 4/24/08 4/23/08
C:DRS/EB1 C:DRS/PSB C:DRP/C ACES:SES D:DRP
RLBywater MPShannon RWDeese GMVasquez DDChamberlain
/RA/ /RA/ /RA/ /RA/
4/22/08 4/22/08 4/ /08 4/24/08 5/02/08
OFFICIAL RECORD COPY T=Telephone E=Email F=Fax
U. S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No: 05000298
License No: PR-46
Report No: 5000298/2008002
Licensee: Nebraska Public Power District
Facility: Cooper Nuclear Station
Location: PO Box 98, Brownville, NE 68321
Dates: January 1 through March 22, 2008
Inspectors: N. Taylor, Senior Resident Inspector
M. Chambers, Resident Inspector
P. Elkmann, Emergency Preparedness Inspector
M. Runyan, Senior Reactor Analyst
Approved by: D. Chamberlain, Director
Division of Reactor Projects
-1- Enclosure
SUMMARY OF FINDINGS
IR 05000298/2008002; 01/01/2008 - 03/22/2008; Cooper Nuclear Station. Plant Modifications
and Postmaintenance Testing.
This report covers a three-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. The significance of most findings is indicated by
their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance
Determination Process. Findings for which the Significance Determination Process does not
apply may be Green or be assigned a severity level after NRC management review. The NRCs
program for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green. The inspectors identified a Green noncited violation of Technical
Specification 5.4.1.a regarding the licensees failure to follow the requirements of
Maintenance Procedure 7.0.7, Scaffolding Construction and Control.
Specifically, licensee personnel failed to inspect all existing scaffolds and failed
to identify multiple scaffolding interactions with safety-related equipment during a
required annual scaffold inspection on January 21, 2008. This issue was
entered Into the licensees corrective action program as Condition
Report CR-CNS-2008-01576.
The finding is more than minor because if left uncorrected the failure to perform
annual scaffold inspections could become a more significant safety concern.
Specifically, annual inspections failed to inspect all existing scaffolds and failed to
identify multiple scaffolding interactions with safety-related equipment. Using the
Manual Chapter 0609, Significance Determination Process, Phase 1
Worksheet, the finding is determined to have a very low safety significance
because it did not result in the loss of function of a Technical Specification
required system for greater than its allowed outage time. The cause of this
finding is related to the human performance crosscutting component of work
practices because maintenance personnel did not follow the requirements of
Maintenance Procedure 7.0.7 (H.4(b)) (Section 71111.18).
- TBD. Two examples of a self-revealing apparent violation of Technical
Specification 5.4.1.a were identified regarding the licensees failure to establish
procedural controls for maintenance of electrical connections on essential
equipment. In the first example, the licensee failed to include amphenol
connections within the scope of existing periodic electrical connection inspections
to identify loosening connections. In the second example, the licensee failed to
incorporate internal operating experience into work control procedures to ensure
that diesel generator-mounted amphenol connections were solidly attached
following maintenance. These failures to establish adequate procedural controls
led to the trip of Diesel Generator 2 during testing on January 15, 2008. This
issue was entered into the licensees corrective action program as Condition
Report CR-CNS 2008-00304.
-2- Enclosure
The finding affected the mitigating systems cornerstone and is more than minor
because it is associated with the cornerstone attribute of equipment performance
and affects the associated cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. The Phase 1 worksheets in Inspection Manual
Chapter 0609, "Significance Determination Process," were used to conclude that
a Phase 2 analysis was required because the finding represents an actual loss of
safety function of a single train for greater than its Technical Specification
allowed outage time (7 days). A Phase 2 risk analysis was conducted using the
guidance of Manual Chapter 0609, Appendix A, Determining the Significance of
Reactor Inspection Findings for At-Power Situations. Entering the site-specific
pre-solved table with an assumed exposure time of greater than 30 days yielded
a result of red, or very high significance. A Phase 3 analysis conducted by a risk
analyst preliminarily determined the finding to be of white, or low to moderate
significance. The cause of the finding is related to the corrective action
component of the crosscutting area of problem identification and resolution in
that the licensee failed to take appropriate corrective actions for a 2007 NRC
inspection finding which identified inadequate maintenance procedures for
checking the tightness of diesel generator electrical connections (P.1(d))
(Section 71111.19).
B. Licensee-Identified Violations
No violations of significance were identified.
-3- Enclosure
REPORT DETAILS
Summary of Plant Status
The plant began the inspection period at 100 percent power. On February 19, 2008, the plant
began coastdown to Refueling Outage 24. On March 20, 2008, reactor power dropped from
90 percent to approximately 58 percent due to an unplanned trip of reactor recirculation pump
motor Generator B. The reactor was returned to full power later in the day, where it remained
for the rest of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency
Preparedness
1R04 Equipment Alignment (71111.04)
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors selected these systems based on their risk significance relative to the
reactor safety cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could impact the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, Updated Final Safety Analysis Report (UFSAR), Technical
Specification (TS) requirements, Administrative TSs, outstanding work orders (WOs),
condition reports (CR), and the impact of ongoing work activities on redundant trains of
equipment in order to identify conditions that could have rendered the systems incapable
of performing their intended functions. The inspectors also walked down accessible
portions of the systems to verify system components and support equipment were
aligned correctly and operable. The inspectors examined the material condition of the
components and observed operating parameters of equipment to verify that there were
no obvious deficiencies. The inspectors also verified that the licensee had properly
identified and resolved equipment alignment problems that could cause initiating events
or impact the capability of mitigating systems or barriers and entered them into the
corrective action program (CAP) with the appropriate significance characterization.
Documents reviewed are listed in the attachment.
The inspectors performed partial system walkdowns of the following risk-significant
systems:
during REC HX A limiting condition for operation (LCO)
- February 28, 2008, Service Water Train B during Diesel Generator (DG) LCO
- March 6, 2008, Residual Heat Removal (RHR) HX B during a RHR HX LCO
The inspectors completed three samples.
-4- Enclosure
b. Findings
No findings of significance were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
On March 11, 2008 the inspectors performed a complete system alignment inspection of
the DG 1 to verify the functional capability of the system. This system was selected
because it was considered both safety-significant and risk-significant in the licensees
probabilistic risk assessment. The inspectors walked down the system to review
mechanical and electrical equipment line ups, electrical power availability, system
pressure and temperature indications, as appropriate, component labeling, component
lubrication, component and equipment cooling, hangers and supports, operability of
support systems, and to ensure that ancillary equipment or debris did not interfere with
equipment operation. A review of a sample of past and outstanding WOs was
performed to determine whether any deficiencies significantly affected the system
function. In addition, the inspectors reviewed the CAP database to ensure that system
equipment alignment problems were being identified and appropriately resolved.
Documents reviewed by the inspectors included:
Generator), Revision 70
These activities constituted one complete system walkdown sample as defined by
Inspection Procedure 71111.04-05.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05AQ)
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability,
accessibility, and the condition of firefighting equipment.
The inspectors reviewed areas to assess if the licensee had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant, effectively maintained fire detection and suppression capability, maintained
passive fire protection features in good material condition, and had implemented
adequate compensatory measures for out of service, degraded or inoperable fire
protection equipment, systems, or features in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk
as documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to impact equipment which could initiate or mitigate a
-5- Enclosure
plant transient, or their impact on the plants ability to respond to a security event. Using
the documents listed in the attachment, the inspectors verified that fire hoses and
extinguishers were in their designated locations and available for immediate use; that
fire detectors and sprinklers were unobstructed, that transient material loading was
within the analyzed limits; and fire doors, dampers, and penetration seals appeared to
be in satisfactory condition. The inspectors also verified that minor issues identified
during the inspection were entered into the licensees corrective action program.
- February 13, 2008, Fire Zone 2C during fuel movement
- March 15, 2008, Fire Zone 19C Controlled Access Corridor
Documents reviewed by the inspectors included:
- CNS Fire Hazards Analysis Matrix for Fire Area IX, Fire Zone 14A, dated
February 28, 2003
- CNS Fire Hazards Analysis Matrix for Fire Area IX, Fire Zone 14C, dated
November 5, 2007
These activities constituted four quarterly fire protection inspection samples as defined
by Inspection Procedure 71111.05-05.
b. Findings
No findings of significance were identified.
1R07 Annual Heat Sink Performance (71111.07)
a. Inspection Scope
The inspectors reviewed the licensees testing of A and B REC heat exchangers to verify
that potential deficiencies did not mask the licensees ability to detect degraded
performance, to identify any common cause issues that had the potential to increase
risk, and to ensure that the licensee was adequately addressing problems that could
result in initiating events that would cause an increase in risk. The inspectors reviewed
the licensees observations as compared against acceptance criteria, the correlation of
scheduled testing and the frequency of testing, and the impact of instrument
inaccuracies on test results. Inspectors also verified that test acceptance criteria
considered differences between test conditions, design conditions, and testing
conditions.
Documents reviewed are listed in the attachment.
This inspection constitutes one sample as defined in Inspection Procedure 71111.07-05.
-6- Enclosure
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
Conformance With Simulator Requirements Specified in 10 CFR 55.46
a. Inspection Scope
The inspectors observed testing and training of senior reactor operators and reactor
operators to identify deficiencies and discrepancies in the training, to assess operator
performance, and to assess the evaluator's critique. The training scenario involved a
tornado, station blackout and a loss of shutdown cooling.
- February 28, 2008, Crew E drill
Documents reviewed by the inspectors included:
- Lesson SKL054-01-28, Tornado, Station Blackout, Loss of Shutdown Cooling
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the risk significant
systems of events such as where ineffective equipment maintenance has resulted in
valid or invalid automatic actuations of engineered safeguards systems and
independently verified the licensee's actions to address system performance or condition
problems in terms of the following:
- implementing appropriate work practices;
- identifying and addressing common cause failures;
- scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring;
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
-7- Enclosure
- verifying appropriate performance criteria for structures, systems, and
components (SSCs) functions classified as (a)(2) or appropriate and adequate
goals and corrective actions for systems classified as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the corrective action program with the appropriate
significance characterization.
- March 19, 2008, Reactor protection system (RPS) electronic protection
assembly (EPA) breaker failures January 12, 2008
Documents reviewed by the inspectors included:
- Functional Failure Evaluation for functions RPS-F01, RPS-F02, RPS-SD1
- Functional failure Evaluations for functions DG-PF01B, ROP-MSPI-EAC
This inspection constitutes two quarterly maintenance effectiveness samples as defined
in Inspection Procedure 71111.12-05.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the
maintenance and emergent work activities affecting risk-significant and safety-related
equipment listed below to verify that the appropriate risk assessments were performed
prior to removing equipment for work:
- March 6, 2008, Inoperability of both DGs on September 11, 2007
- March 3, 2008, Core spray A LCO with winter storm warning on February 5, 2008
These activities were selected based on their potential risk significance relative to the
reactor safety cornerstones. As applicable for each activity, the inspectors verified that
risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate
and complete. When emergent work was performed, the inspectors verified that the
plant risk was promptly reassessed and managed. The inspectors reviewed the scope
of maintenance work, discussed the results of the assessment with the licensee's
probabilistic risk analyst or shift technical engineer, and verified plant conditions were
consistent with the risk assessment. The inspectors also reviewed TS requirements and
walked down portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Documents
reviewed are listed in the attachment.
The inspectors completed two samples.
-8- Enclosure
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed the following issues:
The inspectors selected these potential operability issues based on the risk-significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the TS and UFSAR to the licensees evaluations, to determine
whether the components or systems were operable. Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled. The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations. Additionally, the inspectors also reviewed a sampling of corrective action
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations.
- January 14, 2008, DG 2 operability and common cause evaluation for loss of
overspeed governor sightglass during run
- January 15, 2008, operability evaluation of control room Board C non-essential
meters without isolation devices in DG 1 and DG 2 essential circuits, on January
14, 2008
DG 2
January 25, 2008 and February 6, 2008
This inspection constitutes four samples as defined in Inspection Procedure 71111.15-05.
b. Findings
No findings of significance were identified.
1R18 Plant Modifications (71111.18)
a. Inspection Scope
The inspectors reviewed the UFSAR, plant drawings, procedure requirements, and TSs
to ensure that temporary alterations and configuration changes to the plant conformed to
-9- Enclosure
these guidance documents and the requirements of 10 CFR 50.59. The inspectors:
(1) verified that the modifications did not have an affect on system operability/availability;
(2) verified that the installations were consistent with modification documents;
(3) ensured that the post-installation test results were satisfactory and that the impacts of
the temporary modifications on permanently installed SSCs were supported by the test;
and (4) verified that appropriate safety evaluations were completed. The inspectors
reviewed the following temporary modifications:
- March 19, 2008, Long term scaffolding program review
Documents reviewed by the inspectors included:
- Maintenance Procedure 7.0.7, Scaffolding Construction and Control,
Revision 24
The inspectors completed one sample.
b. Findings
Introduction. The inspectors identified a Green noncited violation of TS 5.4.1.a
regarding the licensees failure to follow the requirements of Maintenance Procedure
7.0.7, Scaffolding Construction and Control. Specifically, licensee personnel failed to
inspect all existing scaffolds and failed to identify multiple scaffolding interactions with
safety-related equipment during a required annual scaffold inspection on January 21,
2008.
Description. During pre-outage scaffold inspections on February 7, 2008, the licensee
discovered that some existing scaffolds were not built in accordance with established
procedures. Specifically, the licensee discovered that scaffolds constructed in 1999 had
been built in contact with safety-related service water piping, RHR piping, pipe hangers,
electrical conduit and the torus shell. This condition was documented in
CR-CNS-2008-00822. After determining that the scaffold did not affect the operability of
the impacted safety systems, the licensee took actions to remove the non-compliant
scaffold on February 22, 2008, and closed the CR.
The inspectors noted that Maintenance Procedure 7.0.7, Scaffolding Construction and
Control, Revision 24, contains the following requirement in Paragraph 3.2:
During the month of January, all erected scaffolds shall have an Industrial
Safety examination performed to ensure compliance with this procedure. This
examination is required prior to placing a new tag and entering the scaffold into
the new calendar year log.
The inspectors also noted that the required annual examination had been completed on
January 21, 2008. The maintenance personnel who conducted the examination in
WO 4552687 documented completion with no discrepancies.
On March 6, 2008, the inspectors questioned licensee management regarding the
performance of the annual scaffold examinations. Specifically, the inspectors asked why
the non-compliant scaffold had not been identified during the required annual scaffold
examinations. Following this meeting, the licensee conducted a scaffolding walkdown to
- 10 - Enclosure
identify any remaining non-compliances. The following additional violations of
Procedure 7.0.7 were discovered during this walkdown:
- Scaffold 08-04 erected under WO 4566810 on December 10, 2007 had
a board in contact with high pressure coolant injection steam line drip
leg piping. Contrary to Procedure 7.0.7, this scaffold had not been
inspected due to a misperception that only long term scaffolds that
had been in place greater than 90 days needed to be inspected. The
licensee documented this condition in CR-CNS-2008-01551.
- Scaffold 08-06 was discovered to be in contact with safety-related
conduit and pipe hangers in the torus area. The licensee was unable to
determine when this scaffold had been installed.
- Eight examples of non-compliant scaffolding handrails were discovered
in contact with safety system components in the torus area which had
been installed in 2002. This example, documented in
CR-CNS-2008-01563 on March 11, 2008 was not identified by the
annual examination because it was not included in the scaffold log and
was therefore not inspected.
The inspectors determined that Procedure 7.0.7 had been violated during the
January 21, 2008 annual scaffolding examination in that the examiner reviewed only
those scaffolds identified in the scaffolding log as Long Term Permanent versus all
erected scaffolds as required by the procedure. As a result, seven existing scaffolds
were not inspected, despite the fact that some of them had been installed for more than
one year at the time of the inspection. In addition, the examiner did not conduct a
thorough inspection to ensure compliance with this procedure. Obvious non-
compliances existed in some of the installed scaffolds that were not identified until
months later.
The inspectors also noted that since handrails built from scaffolding materials do not
meet the definition of a scaffold in Procedure 7.0.7 in that they do not contain an
elevated platform, no annual inspections have been performed on these structures.
Analysis. The performance deficiency associated with this finding involved the
licensees failure to comply with the requirements of Maintenance Procedure 7.0.7,
Scaffolding Construction and Control. The finding is more than minor because if left
uncorrected the failure to perform annual scaffold inspections could become a more
significant safety concern. Specifically, annual inspections failed to inspect all existing
scaffolds and failed to identify multiple scaffolding interactions with safety-related
equipment. Using the Manual Chapter 0609, Significance Determination Process,
Phase 1 Worksheet, the finding is determined to have a very low safety significance
because it did not result in the loss of function of a TS required system for greater than
its allowed outage time. The cause of this finding is related to the human performance
crosscutting component of work practices because maintenance personnel did not follow
the requirements of Maintenance Procedure 7.0.7 (H.4(b)).
Enforcement. TS 5.4.1.a requires that written procedures be established, implemented,
and maintained covering the activities specified in Regulatory Guide 1.33, Revision 2,
Appendix A, dated February 1978. Regulatory Guide 1.33, Appendix A, section 9.a,
- 11 - Enclosure
requires that maintenance that can affect the performance of safety-related equipment
should be properly pre-planned and performed in accordance with written procedures.
Contrary to this requirement, on January 21, 2008, maintenance personnel violated the
requirements of Maintenance Procedure 7.0.7, Scaffolding Construction and Control, in
that they did not inspect all required scaffolds or identify obvious non-compliances with
Procedure 7.0.7. Because the finding is of very low safety significance and has been
entered into the licensees CAP as CR-CNS-2008-01576, this violation is being treated
as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000298/2008002-01, "Failure to Follow Scaffold Inspection Procedures.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
These activities were selected based upon the SSCs ability to impact risk. The
inspectors evaluated these activities for the following (as applicable): the effect of testing
on the plant had been adequately addressed; testing was adequate for the maintenance
performed; acceptance criteria were clear and demonstrated operational readiness; test
instrumentation was appropriate; tests were performed as written in accordance with
properly reviewed and approved procedures; equipment was returned to its operational
status following testing (temporary modifications or jumpers required for test
performance were properly removed after test completion), and test documentation was
properly evaluated. The inspectors evaluated the activities against TS, the UFSAR, 10
CFR Part 50 requirements, licensee procedures, and various NRC generic
communications to ensure that the test results adequately ensured that the equipment
met the licensing basis and design requirements. In addition, the inspectors reviewed
corrective action documents associated with postmaintenance tests to determine
whether the licensee was identifying problems and entering them in the CAP and that
the problems were being corrected commensurate with their importance to safety.
Documents reviewed are listed in the attachment.
The inspectors reviewed the following postmaintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- March 14, 2008, Dynamic testing of SW-MO-650MV on January 30, 2008
- March 19, 2008, Test failure of northeast quad fan coil unit on February 5, 2008
- March 14, 2008, 6.EE.606 on January 30, 2008, 250 VDC charger test and
The inspectors completed five samples.
- 12 - Enclosure
b. Findings
Failure to Establish Adequate Procedures for Maintenance of Emergency DG Electrical
Connections
Introduction. Two examples of a self-revealing apparent violation of TS 5.4.1.a were
identified regarding the licensees failure to establish procedural controls for
maintenance of electrical connections on essential equipment. In the first example, the
licensee failed to include amphenol connections within the scope of existing periodic
electrical connection inspections to identify loosening connections. In the second
example, the licensee failed to incorporate internal operating experience into work
control procedures to ensure that DG-mounted amphenol connections were solidly
attached following maintenance. These failures to establish adequate procedural
controls led to the trip of DG 2 during testing on January 15, 2008.
Description. On January 15, 2008, DG 2 tripped shortly after being started as part of a
postmaintenance test. The test was being conducted to verify the ability of DG 2 to
perform its safety function following repairs to the overspeed governor oil level sight
glass. The licensee determined that the cause of the trip of DG 2 was a loose
amphenol-type connection on the relay tachometer speed sensing circuit magnetic
pickup.
The licensee determined that this failure was similar in nature to a condition identified
during previous troubleshooting of DG 2. On December 10, 1995, operations personnel
initiated a CR to document that the amphenol connector on a DG mounted magnetic
pickup (MPU) was vibrating loose during testing of the DG. In response to this CR, the
licensee initiated a minor maintenance WO to loosen both MPU amphenol connectors
and apply thread locking compound to the amphenol threads to keep the connection
from vibrating loose. The completion of these actions was documented in Minor
Maintenance WO 95-03959. Beyond the actions taken in the WO, no corrective actions
were taken to codify the use of thread locking compounds or other measures to prevent
the amphenol connections from coming unthreaded during engine operation.
During a normal shutdown of DG 2 on December 27, 2000, an engine overspeed alarm
was unexpectedly received, as described in CR 4-13285. Minor Maintenance
WO 003915 was initiated to determine the cause of the unexpected alarm. During
completion of this WO on December 29, 2000, maintenance personnel replaced the
relay tachometer and the associated MPU, and the associated amphenol connection
was disconnected and then reconnected.
In the first example of this performance deficiency, the inspectors determined that the
licensees procedures for performing periodic DG electrical examinations were
inadequate in that they did not include engine-mounted components. Maintenance
Procedure 7.3.8.2, Diesel Generator Electrical Examination and Maintenance, was
created on September 30, 1988 to perform periodic (once per operating cycle)
preventative maintenance on the DG electrical systems. On May 22, 2007, the NRC
identified an NCV regarding the licensees failure to establish adequate instructions for
emergency DG electrical maintenance (see NRC Special Inspection
Report 05000298/2007007). Two of the three examples described in the NCV dealt with
inadequate work instructions for checking the tightness of electrical connections on DG
system components. In response to this NCV, the licensee initiated Corrective Action #8
- 13 - Enclosure
under CR-CNS-2007-00480 to establish preventative maintenance tasks to periodically
check the DG systems for loose connections. In developing a revision to Maintenance
Procedure 7.3.8.2, Diesel Generator Electrical Examination and Maintenance, the
licensee made the erroneous assumption that all engine-mounted components have
other maintenance actions that satisfy the intent of the corrective action. As such,
engine-mounted connections were not included in the scope of the inspections in
Revision 20 to Maintenance Procedure 7.3.8.2 on August 13, 2007. The revised
procedure was subsequently completed for DG 2 on September 13, 2007. The
assumption was in error and resulted in a recently missed opportunity to discover the
loosening amphenol connection on the DG 2 relay tachometer MPU.
In the second example of this performance deficiency, the licensee determined that the
maintenance procedures used on December 29, 2000 did not contain adequate
guidance to ensure that thread locking compounds or other measures would be utilized
to ensure that the DG amphenol connections did not become unthreaded during engine
operation. The work was not conducted using detailed procedures, and as such the
licensee determined that the amphenol became loose as a result of either inadequate
tightening during the maintenance, or equipment vibration between 2000 and 2008 (due
to thread locking compound not being used), or a combination of both. The licensee has
initiated corrective actions to add the appropriate guidance to Administrative
Procedure 0.40.4, Planning.
Analysis. The performance deficiency associated with this finding involved the
licensees failure to establish procedural controls for maintenance of electrical
connections on essential equipment. In the first example, the licensee failed to include
these amphenol connections within the scope of existing periodic electrical connection
inspections to identify loosening connections. In the second example, the licensee failed
to incorporate internal operating experience into work control procedures to ensure that
DG-mounted amphenol connections were solidly attached following maintenance.
These failures to establish adequate procedural controls led to the trip of DG 2 during
testing on January 15, 2008. The finding is more than minor because it is associated
with the mitigating systems cornerstone attribute of equipment performance and affects
the associated cornerstone objective to ensure the availability, reliability, and capability
of systems that respond to initiating events to prevent undesirable consequences. The
Phase 1 worksheets in Manual Chapter 0609, "Significance Determination Process,"
were used to conclude that a Phase 2 analysis was required because the finding
represents an actual loss of safety function of a single train for greater than its TS
allowed outage time (7 days). A Phase 2 risk analysis was conducted using the
guidance of Manual Chapter 0609, Appendix A, Determining the Significance of Reactor
Inspection Findings for At-Power Situations. Entering the site-specific pre-solved table
with an assumed exposure time of greater than 30 days yielded a result of red, or very
high significance. A Phase 3 analysis conducted by a risk analyst preliminarily
determined the finding to be of white, or low to moderate significance.
The cause of the finding is related to the corrective action component of the crosscutting
area of problem identification and resolution in that the licensee failed to take
appropriate corrective actions for a 2007 NRC inspection finding which identified
inadequate maintenance procedures for checking the tightness of DG electrical
connections (P.1(d)).
- 14 - Enclosure
Enforcement. TS 5.4.1.a requires that written procedures be established, implemented,
and maintained, covering the activities specified in Regulatory Guide 1.33, Revision 2,
Appendix A, dated February 1978. Regulatory Guide 1.33, Appendix A, Section 9 (a),
requires that maintenance affecting performance of safety-related equipment should be
performed in accordance with written procedures. Contrary to this, since December 29,
2000, the licensee used inadequate procedural guidance to reassemble amphenol
connections on DG 2. Additionally, since September 30, 1988, the licensees procedural
guidance for performing periodic electrical inspections has been inadequate in that it did
not check the tightness of engine-mounted amphenol connections. These inadequate
procedures resulted in the trip of DG 2 during testing on January 15, 2008. This issue
was entered into the licensees CAP as CR-CNS-2008-00304. Pending determination of
the findings final safety significance, this finding is identified as Apparent Violation (AV)05000298/2008002-002, "Failure to Establish Adequate Procedures for Maintenance of
Emergency DG Electrical Connections."
1R22 Surveillance Testing (71111.22)
Routine Surveillance Testing
a. Inspection Scope
The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that
the three surveillance activities listed below demonstrated that the SSCs tested were
capable of performing their intended safety functions. The inspectors either witnessed
or reviewed test data to verify that the following significant surveillance test attributes
were adequate: (1) preconditioning; (2) evaluation of testing impact on the plant; (3)
acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead controls;
(7) test data; (8) testing frequency and method demonstrated TS operability; (9) test
equipment removal; (10) restoration of plant systems; (11) fulfillment of ASME Code
requirements; (12) engineering evaluations, root causes, and bases for returning tested
SSCs not meeting the test acceptance criteria were correct; (13) reference setting data;
and (14) annunciators and alarms setpoints. The inspectors also verified that the
licensee identified and implemented any needed corrective actions associated with the
surveillance testing.
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine whether: any preconditioning occurred; effects of the testing were
adequately addressed by control room personnel or engineers prior to the
commencement of the testing; acceptance criteria were clearly stated, demonstrated
operational readiness, and were consistent with the system design basis; plant
equipment calibration was correct, accurate, and properly documented; as left setpoints
were within required ranges; the calibration frequency was in accordance with TS, the
UFSAR, procedures, and applicable commitments; measuring and test equipment
calibration was current; test equipment was used within the required range and
accuracy; applicable prerequisites described in the test procedures were satisfied; test
frequencies met TS requirements to demonstrate operability and reliability; tests were
performed in accordance with the test procedures and other applicable procedures;
jumpers and lifted leads were controlled and restored where used; test data and results
were accurate, complete, within limits, and valid; test equipment was removed after
testing; where applicable, test results not meeting acceptance criteria were addressed
with an adequate operability evaluation or the system or component was declared
- 15 - Enclosure
inoperable; where applicable for safety-related instrument control surveillance tests,
reference setting data were accurately incorporated in the test procedure; where
applicable, actual conditions encountering high resistance electrical contacts were such
that the intended safety function could still be accomplished; prior procedure changes
had not provided an opportunity to identify problems encountered during the
performance of the surveillance or calibration test; equipment was returned to a position
or status required to support the performance of the safety functions; and all problems
identified during the testing were appropriately documented and dispositioned in the
CAP.
The inspectors reviewed the test results for the following activities to determine whether
risk-significant systems and equipment were capable of performing their intended safety
function and to verify testing was conducted in accordance with applicable procedural
and TS requirements:
- January 23, 2008, Scram discharge volume vent valve inservice test (IST)
performed January 14, 2008
- February 29, 2008, DG 1 fuel oil transfer pump flow test performed January 31,
2008
- March 19, 2008, 6.REC.201 performed January 31, 2008
- March 21, 2008, DG 2 monthly operability test performed March 11, 2008
This inspection constitutes four routine surveillance testing samples as defined in
Inspection Procedure 71111.22.
b. Findings
No findings of significance were identified.
EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
CNS Emergency Plan Revision 53
a. Inspection Scope
The inspector performed an in-office review of Revision 53 to the Cooper Nuclear
Station Emergency Plan, received January 8, 2008. This revision moved the licensee's
Joint Information Center (emergency news center) from Columbus, Nebraska, to
Auburn, Nebraska, revised position duties in the Emergency Operations Facility and
Joint Information Center, deleted the Technical Information Coordinator (EOF) position,
revised position titles in the Joint Information Center, added a Letter of Agreement
between the licensee and the Nebraska City Fire Department, and revised geographical-
based protective action zones in Missouri, based on an approval letter from Federal
Emergency Management Agency, Region VII, dated October 10, 2007.
This revision was compared to its previous revision, to the criteria of NUREG-0654,
Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants, Revision 1, and to the standards in
- 16 - Enclosure
10 CFR 50.47(b) to determine if the revision adequately implemented the requirements
of 10 CFR 50.54(q). This review was not documented in a Safety Evaluation Report and
did not constitute approval of licensee changes; therefore, this revision is subject to
future inspection.
The inspectors completed one sample during the inspection.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification (71151)
.1 Data Submission Review
a. Inspection Scope
The inspectors performed a review of the data submitted by the licensee for the 4th
Quarter 2007 PIs for any obvious inconsistencies prior to its public release in
accordance with Inspection Manual Chapter 0608, Performance Indicator Program.
This review was performed as part of the inspectors normal plant status activities and,
as such, did not constitute a separate inspection sample.
b. Findings
No findings of significance were identified.
.2 Unplanned Scrams per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the unplanned scrams per 7000 critical
hours PI for the period from the 1st quarter 2007 through the 4th quarter 2007. To
determine the accuracy of the PI data reported during those periods, PI definitions and
guidance contained in Revision 5 of the Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, event reports and NRC
inspection reports to validate the accuracy of the submittals. The inspectors also
reviewed the licensees issue report database to determine if any problems had been
identified with the PI data collected or transmitted for this indicator and none were
identified.
This inspection constitutes one unplanned scrams per 7000 critical hours sample as
defined by Inspection Procedure 71151.
b. Findings
No findings of significance were identified.
- 17 - Enclosure
.3 Unplanned Transients per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the unplanned transients per
7000 critical hours PI for the period from the 1st quarter 2007 through the 4th
quarter 2007. To determine the accuracy of the PI data reported during those periods,
PI definitions and guidance contained in Revision 5 of the Nuclear Energy Institute
Document 99-02, Regulatory Assessment Performance Indicator Guideline, were used.
The inspectors reviewed the licensees operator narrative logs, issue reports,
maintenance rule records, event reports and NRC integrated Inspection reports to
validate the accuracy of the submittals. The inspectors also reviewed the licensees
issue report database to determine if any problems had been identified with the PI data
collected or transmitted for this indicator and none were identified.
This inspection constitutes one unplanned transients per 7000 critical hours sample as
defined by Inspection Procedure 71151.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical
Protection
.1 Routine Review of Items Entered Into the CAP
a. Inspection Scope
The inspectors performed a daily screening of items entered into the licensee's CAP.
This assessment was accomplished by reviewing CRs and WOs and attending
corrective action review and work control meetings. The inspectors: (1) verified that
equipment, human performance, and program issues were being identified by the
licensee at an appropriate threshold and that the issues were entered into the CAP;
(2) verified that corrective actions were commensurate with the significance of the issue;
and (3) identified conditions that might warrant additional followup through other baseline
inspection procedures.
b. Findings
No findings of significance were identified.
.2 Selected Issue Followup Inspection
a. Inspection Scope
In addition to the routine review, the inspectors selected the issues listed below for a
more in-depth review. The inspectors considered the following during the review of the
- 18 - Enclosure
licensee's actions: (1) complete and accurate identification of the problem in a timely
manner; (2) evaluation and disposition of operability/reportability issues;
(3) consideration of extent of condition, generic implications, common cause, and
previous occurrences; (4) classification and prioritization of the resolution of the problem;
(5) identification of root and contributing causes of the problem; (6) identification of
corrective actions; and (7) completion of corrective actions in a timely manner.
- December 27, 2007, loss of both plant monitoring and information system
computers
Documents reviewed by the inspectors included:
- Abnormal Procedure 2.4 COMP, Computer Malfunction, Revision 4
- Computer System Operating Procedure 2.6.3, Computer Systems Operation
and Outage Recovery, Revision 23
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
4OA3 Followup of Events and Notices of Enforcement Discretion (71153)
.1 (Closed) Licensee Event Report (LER) 05000298/2007-006-00: Procedural Guidance
Leads to Rendering Second Diesel Inoperable
On September 11, 2007, the licensee commenced an operation to fill the DG 2 fuel oil
day tank following extensive maintenance on DG 2. While filling the DG 2 day tank,
control room operators received annunciators due to a rising level in the DG 1 fuel oil
day tank, indicating leakage through the DG 1 fuel oil day tank isolation valves. Due to
failure to meet the acceptance criteria in Surveillance Procedure 6.2DG.401, Diesel
Generator Fuel Oil Transfer Pump IST Flow Test - Div 2, the licensee declared DG 1
inoperable. With DG 2 already inoperable, the control room staff properly entered
Condition E of Technical Specification 3.8.1, requiring restoration of either DG to an
operable status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
In an effort to restore operability of DG 1, the licensee elected to attempt repair of the
leaking solenoid isolation valve on the DG 1 fuel oil day tank. This required placing
DG 1 into maintenance lockout and entry into an overall red risk window for the station.
The repair attempt was unsuccessful, and the control room staff subsequently entered
Condition F of TS 3.8.1, requiring the plant to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4
within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Operability of DG 1 was subsequently restored by closing a fuel oil
system crossconnect valve, and Condition F was exited prior to transitioning to Mode 3.
The licensee initiated this LER due to the loss of safety function (on-site emergency
power) that occurred during the corrective maintenance attempt on DG 1. The
inspectors reviewed all aspects of the event, including performance of control room staff,
planning of the associated WOs, evaluation and mitigation of station risk, configuration
control of the DG fuel oil system, treatment in the CAP, fleet standards for emergency
- 19 - Enclosure
and emergent work, and relationship to previous work on DG 1. A related violation of
NRC requirements is discussed in detail in NRC Integrated Inspection Report 05000298/2007005. This LER is closed.
.2 (Closed) Licensee Event Report 05000298/2007-007-00: Damaged Lead on Emergency
Filter System Fan Motor Results in Loss of Safety Function
During a preventative maintenance inspection on December 3, 2007, licensee
technicians discovered severely overheated motor leads on the Control Room
Emergency Filter System (CREFS) exhaust booster fan. Based on the discovery of the
damaged motor leads, operations staff declared the fan inoperable and determined that
since CREFS is a single-train safety system, a loss of safety function had occurred.
Immediate action was taken and the degraded booster fan was replaced. CREFS was
returned to an operable status on December 4, 2007. The degraded condition was
determined to have been caused by the improper crimping of the motor lugs by the
manufacturer prior to installation in the plant. No performance deficiencies were
identified during the review of this LER. This LER is closed.
4OA6 Management Meetings
Exit Meeting Summary
On January 15, 2008, a regional inspector conducted a telephonic exit to present the
results of the in-office inspection of licensee changes to the emergency plan to
Mr. S. Rezhab, Acting Manager, Emergency Planning, who acknowledged the findings.
The inspector confirmed that proprietary information was not provided or examined
during the inspection.
On April 2, 2008, the inspectors conducted a telephonic exit meeting to present the
results of the in-office inspection of changes to the licensees emergency plan to
Mr. J. Austin, Manager, Emergency Planning, who acknowledged the findings. The
inspector confirmed that proprietary, sensitive, or personal information examined during
the inspection had been returned to the identified custodian.
On April 14, 2008, the resident inspectors presented the inspection results to
Mr. M. Colomb, General Manager of Plant Operations and other members of the
licensee staff. The licensee acknowledged the issues presented. The inspectors asked
the licensee whether any materials examined during the inspection should be
considered proprietary. No proprietary information was identified.
- 20 - Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
John Austin, Manager, Emergency Preparedness Manager
Mark Bergmeier, Operations Support Group Supervisor
Vasant Bhardwaj, Engineering Support Manager
Michael Boyce, Director of Projects
Daniel Buman, System Engineering Manager
Michael Colomb, General Manager of Plant Operations
Jeff Ehlers, Engineer, Electric Systems/I&C
Roman Estrada, Corrective Action and Assessments Manager
Jim Flaherty, Senior Staff Licensing Engineer
Paul Fleming, Director of Nuclear Safety Assurance
Scott Freborg, Valves Engineering Programs Supervisor
Gabe Gardner, Design Engineering Civil Engineering Supervisor
Gary Kline, Director of Engineering
Dave Madsen, Licensing Engineer
Mark F Metzger, Engineer, Electric Systems/I&C
Ole Olson, Engineer, Engineering Support & Risk Management
Raymond Rexroad, Engineer, Electric Systems/I&C
Todd Stevens, Manager-Design Engineering
Mark Unruh, Senior Staff Engineer
David VanDerKamp, Licensing Manager
Marshall VanWinkle, Design Engineering Mechanical Supervisor
Dave Werner, Operations Training Support Supervisor
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000298/2008002-02 AV Failure to Establish Adequate Procedures for Maintenance of
Emergency Diesel Generator Electrical Connections
Closed
05000298/2007-006-00 LER Procedural Guidance Leads to Rendering Second Diesel
05000298/2007-007-00 LER Damaged Lead on Emergency Filter System Fan Motor
Results in Loss of Safety Function
Opened and Closed
05000298/2008002-01 NCV Failure to Follow Scaffold Inspection Procedures
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this list
does not imply that the NRC inspector reviewed the documents in their entirety, but rather that
selected sections or portions of the documents were evaluated as part of the overall inspection
A1-1 Attachment 1
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.
1R07: Heat Sink Performance
Condition Report
Procedures
Performance Evaluation Procedure 13.15.1, Reactor Equipment Cooling Heat Exchanger
Performance Analysis, Revision 27
Engineering Procedure 3.34, Heat Exchanger Program, Revision 9
Work Orders
4592135
4592134
1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
EP5.1 WEATHER, Operation During Weather Watches and Warnings, Revision 2
GOP 2.1.11, Station Operator Tours, Revision 127
Procedure 0.49, Schedule Risk Assessment, Revision 20
Procedure 0-PROTECT-EQP, Protected Equipment Program, Revision 5
Work Order
1R19: Post Maintenance Testing
Condition Reports
CR-CNS-2008-00738
Procedures
SP 6.1HV.601, Air Flow Test of Fan Coil Unit FC-R-1F (Div 1), Revision 5
6.EE.606, 250 V Battery Charger Performance Test, Revision 19
MP 7.5.33, SW-MO-650MV Dynamic Test, Revision 5
MP 7.3.14, Thermal Examination of Plant Components, Revision 7
A1-2 Attachment 1
Work Orders
WO 4532270
WO 4532754
1R22: Surveillance Testing
Condition Report
CR-CNS-02007-06517
Procedures
6.CAD.201, North and South SV Vent and Drain Valve Cycling, Open Verification, and Timing
Test, Revision 12
T.S. SR 3.1.8 Scram Discharge Volume Vent and Drain Valves, Revision 0
T.S. Sec 5.5.6, CNS IST Program
6.1DG.401, Diesel Generator Fuel Oil Transfer Pump IST Flow Test (DIV 1), Revision 24
EP 3.9, ASME OM Code Testing of Pumps and Valves,, Revision 23
CNS Inservice Testing Program Basis Document, Revision 6, 6.1, 6.2
DCD-01, p. B-12, Revision dated October 28, 2006
SOP 2.2.12, Diesel Fuel Oil transfer System, Revision 47
6.REC.201, REC Motor Operated Valve Operability Test (IST), Revision16
SR 6.2DG.101, Diesel Generator 31 Day Operability Test (IST) (Div 2), Revision 52
Work Order
LIST OF ACRONYMS USED
ASME American Society of Mechanical Engineers
AV apparent violation
CAP corrective action program
CFR Code of Federal Regulations
CR condition reports
DG diesel generator
HX heat exchange(r)
LCO limiting condition for operation
LER licensee event report
NCV noncited violation
PI performance indicator
PMT postmaintenance testing
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
WO work order
A1-3 Attachment 1
Cooper Nuclear Station
Failure of EDG 2 Speed Sensing Circuit
SDP Phase 3 Analysis
Performance Deficiency:
Inadequate maintenance resulted in EDG 2 failing to run on January 15, 2008. The event was
caused by a failure of an amphenol connection on the EDG speed sensing circuit.
Assumptions:
1. It is assumed that the amphenol-type connector of the speed sensing circuit degraded only
during times that the diesel generator was running; specifically in response to the vibration
of the operating engine. There is no assumption of accelerated degradation associated with
diesel starts or any degradation while the unit was in standby. It is further assumed that the
failure was a deterministic outcome set to occur after a specific number of operating hours.
The diesel was run at the following times:
09/13/07 - ran for 2 hrs 15 min
10/15/07 - ran for 5 hrs 45 min
11/13/07 - ran for 5 hrs 21 min
12/10/07 - ran for 5 hrs 51 min
01/14/08 - ran for 5 hrs 21 min (1700)
01/15/08 - failure less than one minute after starting
01/16/08- EDG 2 restored to a functional status (1700)
Therefore, it is assumed that EDG2 would have failed to run within one minute of a LOOP
demand, or it was inoperable for maintenance, during the two-day period from January 14 to
January 16, 2008.
Prior to this date, it is assumed that EDG 2 would have failed to run at 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> following a
LOOP demand at any time during the 35-day period from its last successful surveillance test
on December 10, 2007 until the test failure that occurred on January 14, 2008.
Prior to this date, EDG 2 would have run and failed at 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> during the 27-day period
from November 13, 2007 to December 10, 2007.
Prior to this date, EDG 2 would have run and failed at 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> during the 29-day period
from October 15, 2007 to November 13, 2007.
Prior to this date, EDG 2 would have failed to run at 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> during the 32-day period
from September 13, 2007 to October 15, 2007.
Before October 15, 2007, it is assumed that EDG 2 would not have failed from the speed
sensing circuit failure for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the mission time assumed in the SPAR model.
Therefore, prior to this date no additional risk impact is assumed.
2. The problem with the speed sensing circuit would be difficult to diagnose in time to affect the
outcome of any of the SPAR core damage sequences, the longest of which is 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> (as
modified by an extension to the battery duration (assumption #3). Adjustments made to the
A2-1 Attachment 2
performance shaping factors in the SPAR-H Human Reliability Analysis Method, NUREG
CR-6883, Sept. 2004 (expansive time, extreme stress, highly complex, nominal training,
unavailable procedures, and missing ergonomics) returned a failure probability of 0.56,
including a very small contribution from the action steps of repairing the amphenol
connection and re-starting the EDG, which are relatively simple.
The following table presents the diagnosis tabulation:
Diagnosis (0.01) Multiplier Action (0.001) Multiplier
Available Time Expansive 0.01 Nominal 1
Stress Extreme 5 High 2
Complexity High 5 Nominal 1
Experience/Training Nominal 1 Nominal 1
Procedures Not Available 50 Nominal 1
Ergonomics Poor 10 Nominal 1
Product of Multipliers 125 2
Diagnosis HEP = 0.01(125)/ [0.01(125-1)] + 1 = 0.558
Action HEP = 0.001(2) = 0.002
Total HEP = 0.56
For this analysis, it is assumed that the recovery of EDG 2 from the speed sensor circuit
failure applies to sequences of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or greater. The only sequence that is less than 4
hours is a 30 minute sequence, for which no recovery of the amphenol connection is
assumed.
The SPAR model does not distinguish between cutsets that contain two or just one EDG
failure as it relates to EDG non-recovery basic events. Theoretically, it would be more likely
to succeed in restoring one of two EDGs versus recovering one (of one) EDG. However, in
this analysis, this feature of the SPAR model is not altered
3. The standard CNS SPAR model credited the Class 1E batteries with an 8-hour discharge
capability following a station blackout. Based on information received from the licensee, this
credit was extended to 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />. Although the batteries could potentially function beyond
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> under certain conditions other challenges related to the operation of RCIC and
HPCI in station blackout conditions would be present. These challenges include the
availability of adequate injection supply water and operational concerns of RCIC under high
back pressure conditions as a result of the unavailability of suppression pool cooling during
an extended station blackout event.
4. For the purpose of this analysis, it is assumed that EDG 2 would not be unavailable or fail to
operate for the period of time before it is assumed to fail from the connector failure during
the various exposure periods. This introduces a slight inconsistency to the risk estimate, but
because it would similarly affect both the base and current case, it does not significantly
influence the result of this analysis.
5. Common cause vulnerabilities for EDG 1 did not exist, that is, the failure mode is assumed
to be independent in nature. The reason for this determination is based on the following
A2-2 Attachment 2
reasoning. The loosening of the amphenol connection on EDG 2 resulted from engine
vibration while the EDG was running. Historically, EDG 2 has experienced vibration
problems while EDG 1 has not. Therefore, it is likely that vibration induced loosening of the
amphenol connection would proceed at a faster pace for EDG 2 than EDG 1, making It very
unlikely that this type of failure would occur on both EDGs at the same time. The fact that it
took 7 years of operation for EDG 2 to reach the point of failure also points to the
unlikelihood that the same failure would have occurred on EDG 1 within the timeframe of the
exposure period of this finding.
Even if both EDGs were determined to be vulnerable to a speed sensor amphenol
connection failure, there was no mechanism that would tend to cause both EDGs to fail
simultaneously. That is, the failure of one amphenol connection would not make failure of
the other one more likely. Therefore, for this case, the failure of both EDGs from this issue
would mathematically be modeled by the combined independent failures of both EDGs
instead of by a classic common cause coupling mechanism. For this case, the estimated
probability of an independent failure of EDG 1 from a failed amphenol connection during the
exposure period would be a small number compared to its baseline SPAR fail-to-run
probability and therefore this application would not appreciably affect the final result.
Finally, if EDG 1 had experienced problems with this connection, thereby making it
comparatively vulnerable to the same type of failure; it is likely that the licensee would have
taken more aggressive actions to address this issue, seeing that it affected both trains of
emergency power. Therefore, the conditions necessary to create the possibility of a
common cause failure would also have triggered actions to prevent it.
The Cooper SPAR model, Revision 3.40, dated February 28, 2008, was used in the analysis. A
cutset truncation of 1.0E-13 was used. Average test and maintenance was assumed.
The model was revised by INL to increase the battery life to 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />, as discussed above. In
addition, the timing of various sequences was lengthened based on data provided by the
licensee. INL also adjusted the credit applied for firewater injection (base model HEP = 1.0),
with an HEP of 0.15. However, based on observations by the senior resident inspector, the
analyst concluded that credit for firewater injection should not be granted. This is because
barely enough time was available to perform the necessary actions and a valve that must be
opened to establish a flow path was non-functional with a stem-disk separation for the entire
period of exposure. There were other valves that could have been used in alternate lineups, but
it was clear that the disabled valve would have been chosen first, leaving no time to reconfigure
the flow path.
Also, changes were made to the containment venting fault tree. In the original version, a loss of
Division 2 AC was sufficient to fail the containment vent function. However, a recovery of the
vent function is possible by taking manual local actions to open the vent valves. The failure
probability of this action was estimated based on an observed evolution conducted in response
to questions concerning this analysis. This observation revealed that the actions needed to
perform this function were dangerous and complex and would be conducted in poor lighting and
high temperatures. Also, operators had little experience. The recovery efforts applied to both a
loss of Division 2 AC and to a loss of instrument air. A non-recovery probability of 0.23 for basic
events CVS-XHE-XL-LOAC and CVS-XHE-XL- LOIAS was determined based on the following
SPAR-H analysis.
A2-3 Attachment 2
The diagnosis of the need to manually vent containment is obvious based on emergency
operating procedures that direct this action when containment pressure reaches 25 psig.
Operators would be continually monitoring this parameter, and it is very unlikely that the effort to
manually vent containment would not be undertaken at 25 psig and possibly prior to this point.
For the action steps, approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of time are available from the time that containment
pressurizes to 25 psig until containment would fail. The nominal time needed to perform the
manually venting task is estimated at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. In this case, the relevant SPAR-H category for
time is nominal. Extreme stress is chosen because the effort to manually open the vent valves
involves a high risk of falling 40 feet through a maze of pipes, possibly resulting in death. The
effort is complex because of the need to carry a lot of equipment, including nitrogen bottles, to
the valves and performing several manipulations. Operators have little experience with this
evolution and the ergonomics are limited by high temperatures, restricted clearances, and a lack
of lighting.
Diagnosis (0.01) Multiplier Action (0.001) Multiplier
Available Time Expansive 0.01 Nominal 1
Stress High 2 Extreme 5
Complexity Obvious 0.1 Moderate 2
Experience/Training Nominal 1 Low 3
Procedures Nominal 1 Nominal 1
Ergonomics Nominal 1 Poor 10
Product of Multipliers 0.002 300
Diagnosis HEP = 0.01(.002) = 2.0E-5
Action HEP = 0.001(300)/ [0.001(300-1)] +1 = 0.23
Total HEP = 0.23
To model the failure of the speed sensing circuit and its specific recovery, a new and gate was
added to the EDG 1B Faults fault tree, with an input from two basic events (one modeling the
speed sensor failure set at 1.0 and another modeling the recovery set at 0.56). The chance of
restoring the EDG for LOOPs occurring during the two-day diagnosis and repair period are
considered similar to the same for the various prior exposure periods. The common cause
probability for fail-to-run events was restored to its nominal value. Therefore, only cutsets
containing the independent failure of EDG 2 contribute to the delta CDF of this finding.
Because the recovery of EDG 2 for speed sensor faults was built into the fault tree, all EDG
recovery basic events were removed from cutsets that contained an EDG 2 speed sensor
failure, but did not also contain either an EDG 1 fail-to-start or EDG 1 fail-to-run or EDG 1 failure
to restore basic event. Additionally, a correction factor (1/0.56 = 1.78) was applied to the subset
of the above that contained 30-minute recovery events to effectively remove all EDG 2 recovery
for those sequences.
Internal Events Analysis:
A. Risk Estimate for the 2-day period between January 14 and January 16, 2006:
During this 48-hour period, it is assumed that EDG 2 was completely unavailable either
because of maintenance or because it would have failed within one minute after a LOOP
A2-4 Attachment 2
demand. To represent the assumed failure and potential recovery of EDG 2, the new
basic event EPS-SPEED-SENSOR was set to 1.0 and EPS-SPEED-SENSOR-RCV was
set to 0.56. The basis event EPS-DGN-CF-RUN was reset to its base case value of
4.172E-4 to ensure that cutsets containing common cause to run events would cancel
out in the base and current case.
The result was a delta-CDF of 2.789E-5/yr. or 1.528E-7 for two days.
B. Risk Estimate for the 35-day period between December 10, 2006 and January 14,
2007:
During this exposure period, EDG 2 is assumed to have been capable of running for
5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />. The LOOP frequency used in the analysis was adjusted to reflect the
situation that only LOOPs with durations greater than 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> would result in a risk
increase attributable to the speed sensor failure.
The base LOOP frequency is 3.59E-2/yr. The 5.35-hour non-recovery of offsite power is
0.1112. Therefore, the frequency of LOOPs that are not recovered in 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> is
3.99E-3/yr.
Resetting event time t=0 to 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> following the LOOP event requires that the
recovery factors for offsite power be adjusted. For instance, in 2-hour sequences in
SPAR, the basic event for non-recovery of offsite power should be adjusted to the non-
recovery at 7.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />, given that recovery has failed at 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />.
An adjustment to account for the diminishment of decay heat must be considered. This
is because the magnitude of decay heat at 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> following shutdown is less than in
the early moments following a reactor trip, and the timing of core damage sequences is
affected by this fact. In the modified SPAR model, recovery times for offsite power are
set at the intervals of 30 minutes, 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. The analyst
determined that the average decay heat level in the first 30 minutes is approximately two
times the average level that exists between 5.35 and 6.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> following shutdown.
Therefore, baseline 30-minute SPAR model sequences, that essentially account for
boiloff to fuel uncovery, should be adjusted to 1-hour sequences. The 2-hour sequences
model safety relief valve failures to close, and are based more on inventory control than
core heat production. Therefore, no adjustment was made for these sequences. The
analyst determined that decay heat rates leveled out quickly following shutdown and
could find no basis for adjusting the times associated with the 4 and 10-hour sequences.
The following table presents the adjusted offsite power non-recovery factors for the
event times that are relevant in the SPAR core damage cutsets:
A2-5 Attachment 2
SPAR SPAR base SPAR base SPAR base Modified
recovery offsite power offsite power offsite power SPAR non-
time non-recovery non-recovery at non-recovery at recovery
5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> + (Column 4
SPAR recovery divided by
time in Column 1 Column 3)
30 min. 0.7314 0.1112 0.0905 1 0.814
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 0.1566 0.1112 0.0554 0.498
5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 0.1205 0.1112 0.0487 0.438
9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> 0.05789 0.1112 0.0325 0.292
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> 0.04500 0.1112 0.0278 0.250
1. A SPAR recovery time of 1.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> is used, as discussed above, to account for the
lessening of decay heat
To compensate for sequences where EDG 1 fails to start (FTS) and then is recovered
before EDG 2 fails from the speed sensor circuit failure at 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />, the result for the
base and the current case that contain an EDG 1 FTS event were multiplied by the
success probability of recovering EDG 1 in 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />, which was 0.5934 (1- non-
recovery probability). This value was then subtracted to obtain a final result for the base
and current case. This adjustment recognizes/assumes that recovery of an EDG 1 fail to
start event before EDG 2 fails from the speed sensor circuit failure will not end in core
damage. Also, the methodology used effectively assumes that for EDG 1 fail to run
events, the failure occurs more or less at the same time that EDG 2 fails (5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />).
This then would suggest that the EDG recovery terms in the SPAR model would
coincide with the event time t=0 at 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> following the onset of the LOOP and
therefore do not require adjustment.
The results of this portion of the analysis are presented in the following table:
CDF/yr CDF/35 days EDG1 FTS EDG1 FTS Remaining
Recovered Recovered/35 CDF (column
(EDG1 FTS days 3- column 5)
Cutset total
times 0.5934)
Base Case 6.989E-7 6.702E-8 3.686E-8 3.535E-9 6.348E-8
Current Case 1.394E-5 1.337E-6 4.706E-7 4.513E-8 1.292E-6
Delta 1.229E-6
CDF/35 days
A2-6 Attachment 2
C. Risk Estimate for the 27-day period between November 13, 2007 and December 10,
2007:
During this exposure period, EDG 2 is assumed to have been capable of running for
11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The LOOP frequency was adjusted to reflect the situation that only LOOPs
with durations greater than 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> would result in a risk increase attributable to the
speed sensor failure.
The base LOOP frequency is 3.59E-2/yr. The 11.2-hour non-recovery of offsite power is
0.0441. Therefore, the frequency of LOOPs that are not recovered in 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is
1.58E-3/yr.
Resetting event time t=0 to 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following the LOOP event requires that the
recovery factors for offsite power be adjusted. For instance, in 2-hour sequences in
SPAR, the basic event for non-recovery of offsite power should be adjusted to the non-
recovery at 13.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, given that recovery has failed at 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The analyst considered an adjustment to account for the diminishment of decay heat as
in the 5.35-hour case above. The analyst determined that the average decay heat level
in the first 30 minutes is approximately three times the average level that exists between
11 and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> following shutdown. Therefore, baseline 30-minute SPAR models, that
essentially account for boiloff to fuel uncovery were adjusted to 1.5-hour sequences.
The 2-hour sequences model safety relief valve failures to close, and are based more on
inventory control than core heat production. Therefore, no adjustment was made for
these sequences. Sequences of 4 and 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> were increased by 30 minutes each
The following table presents the adjusted offsite power non-recovery factors for the
event times that are relevant in the SPAR core damage cutsets:
SPAR SPAR base SPAR base SPAR base Modified
recovery offsite power offsite power offsite power SPAR non-
time non-recovery non-recovery at non-recovery at recovery
11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> + (Column 4
SPAR recovery divided by
time in Column 1 Column 3)
30 min. 0.7314 0.0441 0.0377 1 0.855
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 0.1566 0.0441 0.02922 0.662
5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 0.1205 0.0441 0.02712 0.615
9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> 0.05789 0.0441 0.02122 0.481
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> 0.04500 0.0441 0.01912 0.433
1 A SPAR recovery time of 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> is used, as discussed above, to account for
the lessening of decay heat
2 The SPAR recovery time was increased by 30 minutes.
A2-7 Attachment 2
To compensate for sequences where EDG 1 fails to start (FTS) and then is recovered
before EDG 2 fails from the speed sensor circuit failure at 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the result for the
base and the current case that contain an EDG 1 FTS event were multiplied by the
success probability of recovering EDG 1 in 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, which was 0.7907 (1- non-
recovery probability). This value was then subtracted to obtain a final result for the base
and current case. This adjustment recognizes/assumes that recovery of an EDG 1 fail to
start event before EDG 2 fails from the speed sensor circuit failure will not end in core
damage. Also, the methodology used effectively assumes that for EDG 1 fail to run
events, the failure occurs more or less at the same time that EDG 2 fails (11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />).
This then would suggest that the EDG recovery terms in the SPAR model would
coincide with the event time t=0 at 11.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following the onset of the LOOP and
therefore do not require adjustment.
The results of this portion of the analysis are presented in the following table:
CDF/yr CDF/27 days EDG1 FTS EDG1 FTS Remaining
Recovered Recovered/27 CDF (column
(EDG1 FTS days 3- column 5)
Cutset total
times 0.7907)
Base Case 4.332E-7 3.204E-8 3.168E-8 2.343E-9 2.970E-8
Current Case 9.216E-6 6.817E-7 4.216E-7 3.119E-8 6.505E-7
Delta 6.208E-7
CDF/27 days
D. Risk Estimate for the 29-day period between October 15, 2007 and November 13,
2007:
During this exposure period, EDG 2 is assumed to have been capable of running for
16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The LOOP frequency was adjusted to reflect the situation that only LOOPs
with durations greater than 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> would result in a risk increase attributable to the
speed sensor failure.
The base LOOP frequency is 3.59E-2/yr. The 16.5-hour non-recovery of offsite power is
0.0275. Therefore, the frequency of LOOPs that are not recovered in 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> is
9.87E-4/yr.
Resetting event time t=0 to 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following the LOOP event requires that the
recovery factors for offsite power be adjusted. For instance, in 2-hour sequences in
SPAR, the basic event for non-recovery of offsite power should be adjusted to the non-
recovery at 18.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, given that recovery has failed at 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
The analyst considered an adjustment to account for the diminishment of decay heat as
in the 5.35-hour case above. The analyst determined that the average decay heat level
in the first 30 minutes is approximately four times the average level that exists between
16 and 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> following shutdown. Therefore, baseline 30-minute SPAR models, that
essentially account for boiloff to fuel uncovery were adjusted to 2-hour sequences. The
A2-8 Attachment 2
2-hour sequences model safety relief valve failures to close, and are based more on
inventory control than core heat production. Therefore, no adjustment was made for
these sequences. Sequences of 4 and 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> were increased by 60 minutes each
The following table presents the adjusted offsite power non-recovery factors for the
event times that are relevant in the SPAR core damage cutsets:
SPAR SPAR base SPAR base SPAR base Modified
recovery offsite power offsite power offsite power SPAR non-
time non-recovery non-recovery at non-recovery at recovery
16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> + (Column 4
SPAR recovery divided by
time in Column 1 Column 3)
30 min. 0.7314 0.0275 0.02411 0.876
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 0.1566 0.0275 0.02032 0.738
5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 0.1205 0.0275 0.01922 0.698
9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> 0.05789 0.0275 0.01602 0.582
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> 0.04500 0.0275 0.01482 0.538
1. A SPAR recovery time of 2.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> is used, as discussed above, to account for the
lessening of decay heat
2. The SPAR recovery time was increased by 60 minutes.
To compensate for sequences where EDG 1 fails to start (FTS) and then is recovered
before EDG 2 fails from the speed sensor circuit failure at 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the result for the
base and the current case that contain an EDG 1 FTS event were multiplied by the
success probability of recovering EDG 1 in 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, which was 0.8760 (1- non-
recovery probability). This value was then subtracted to obtain a final result for the base
and current case. This adjustment recognizes/assumes that recovery of an EDG 1 fail to
start event before EDG 2 fails from the speed sensor circuit failure will not end in core
damage. Also, the methodology used effectively assumes that for EDG 1 fail to run
events, the failure occurs more or less at the same time that EDG 2 fails (16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />).
This then would suggest that the EDG recovery terms in the SPAR model would
coincide with the event time t=0 at 16.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following the onset of the LOOP and
therefore do not require adjustment.
The results of this portion of the analysis are presented in the following table:
CDF/yr CDF/29 days EDG1 FTS EDG1 FTS Remaining
Recovered Recovered/29 CDF (column
(EDG1 FTS days 3- column 5)
Cutset total
times 0.8760)
Base Case 3.263E-7 2.593E-8 2.675E-8 2.125E-9 2.380E-8
A2-9 Attachment 2
Current Case 7.071E-6 5.618E-7 3.601E-7 2.861E-8 5.332E-7
Delta 5.094E-7
CDF/29 days
E. Risk Estimate for the 32-day period between September 13, 2007 and October 15,
2007:
During this exposure period, EDG 2 is assumed to have been capable of running for 22.3
hours. The LOOP frequency was adjusted to reflect the situation that only LOOPs with
durations greater than 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> would result in a risk increase attributable to the speed
sensor failure.
The base LOOP frequency is 3.59E-2/yr. The 22.3-hour non-recovery of offsite power is
0.01944. Therefore, the frequency of LOOPs that are not recovered in 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> is
6.98E-4/yr.
Resetting event time t=0 to 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> following the LOOP event requires that the
recovery factors for offsite power be adjusted. For instance, in 2-hour sequences in
SPAR, the basic event for non-recovery of offsite power should be adjusted to the non-
recovery at 24.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, given that recovery has failed at 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
The analyst considered an adjustment to account for the diminishment of decay heat as in
the 5.35-hour case above. The analyst determined that the average decay heat level in the
first 30 minutes is approximately four times the average level that exists between 22 and
23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> following shutdown. Therefore, baseline 30-minute SPAR models, that
essentially account for boiloff to fuel uncovery were adjusted to 2-hour sequences. The 2-
hour sequences model safety relief valve failures to close, and are based more on
inventory control than core heat production. Therefore, no adjustment was made for these
sequences. Sequences of 4 and 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> were increased by 60 minutes each
The following table presents the adjusted offsite power non-recovery factors for the event
times that are relevant in the SPAR core damage cutsets:
SPAR SPAR base SPAR base SPAR base Modified
recovery offsite power offsite power offsite power SPAR non-
time non-recovery non-recovery at non-recovery at recovery
22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> + (Column 4
SPAR recovery divided by
time in Column 1 Column 3)
30 min. 0.7314 0.0194 0.0177 1 0.912
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 0.1566 0.0194 0.01692 0.871
5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 0.1205 0.0194 0.01492 0.768
9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> 0.05789 0.0194 0.01342 0.691
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> 0.04500 0.0194 0.01272 0.655
A2-10 Attachment 2
1. A SPAR recovery time of 2.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> is used, as discussed above, to account for the
lessening of decay heat
2. The SPAR recovery time was increased by 60 minutes.
To compensate for sequences where EDG 1 fails to start (FTS) and then is recovered
before EDG 2 fails from the speed sensor circuit failure at 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, the result for the base
and the current case that contain an EDG 1 FTS event were multiplied by the success
probability of recovering EDG 1 in 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, which was 0.9267 (1- non-recovery
probability). This value was then subtracted to obtain a final result for the base and current
case. This adjustment recognizes/assumes that recovery of an EDG 1 fail to start event
before EDG 2 fails from the speed sensor circuit failure will not end in core damage. Also,
the methodology used effectively assumes that for EDG 1 fail to run events, the failure
occurs more or less at the same time that EDG 2 fails (22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />). This then would
suggest that the EDG recovery terms in the SPAR model would coincide with the event time
t=0 at 22.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> following the onset of the LOOP and therefore do not require adjustment.
The results of this portion of the analysis are presented in the following table:
CDF/yr CDF/32 days EDG1 FTS EDG1 FTS Remaining
Recovered Recovered/32 CDF (column
(EDG1 FTS days 3- column 5)
Cutset total
times 0.9267)
Base Case 2.745E-7 2.407E-8 2.402E-8 2.106E-9 2.196E-8
Current Case 6.033E-6 5.289E-7 3.262E-7 2.860E-8 5.003E-7
Delta 4.783E-7
CDF/32 days
The following table presents the aggregate internal events result:
TIME PERIOD DAYS OF EXPOSURE DELTA CDF
01/14/08 - 01/16/08 2 1.528E-7
12/10/07 - 01/14/08 35 1.229E-6
11/13/07 - 12/10/07 27 6.208E-7
10/15/07 - 11/13/07 29 5.094E-7
09/13/07 - 10/15/07 32 4.783E-7
Total Internal Events Delta-CDF 2.990E-6
External Events Analysis:
The risk increase from fire initiating events was reviewed and determined to have a small impact
on the risk of the finding. Two fire scenarios were identified where equipment damage could
cause a loss of Division 2 vital power, thereby requiring the function of EDG 2. One was a
control room fire that affected either Vertical Board F or Board C. The second was a fire in the
Division 2 critical switchgear. For the control room fires, the scenario probabilities are remote
because of the confined specificity of their locations and the fact that a combination of hot shorts
of a specific polarity are needed to cause a LOOP. In addition, recovery from a LOOP induced
in this manner would be likely to succeed for the station blackout sequences that comprise the
majority of the risk, because a minimum of 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> of battery power would be available, power
A2-11 Attachment 2
would presumably be available in the switchyard, and the breaker manipulations needed to
complete this task would be possible and within the capability of an augmented plant staff that
would respond to the event.
Fires in the Division 2 switchgear would eliminate the importance of EDG 2 because Division 2
power would be unavailable whether or not EDG 2 succeeds. Therefore, there would be no
change in risk from the finding.
The other type of fires that would result in a LOOP are those that require an evacuation of the
control room. In this case, plant procedures require offsite power to be isolated from the vital
buses and the preferred source of power, the Division 2 EDG, is used to power the plant. With
the assumption that the Division 2 EDG will fail 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> into the event, a station blackout
would occur at this time. The sequences that could lead to core damage would include a failure
of the Division 1 EDG, such that ultimate success in averting core damage would rely on
recovery of either EDG or of offsite power. A review of the onsite electrical distribution system
did not reveal any particular difficulties in restoring switchyard power to the vital buses in this
scenario, especially given that many hours are available to accomplish this task. The licensee
confirmed that for all postulated fire scenarios that would require evacuation of the control room,
a undamaged and available power pathway exists from the switchyard through the emergency
transformer to the Division 2 vital bus, and that the breaker manipulation needed to accomplish
this task would take only a few minutes.
In general, the fire risk importance for this finding is small compared to that associated with
internal events because onsite fires do not remove the availability of offsite power in the
switchyard, whereas, in the internal events scenarios, long-term unavailability of offsite power is
presumed to occur as a consequence of such events as severe weather or significant electrical
grid failures. Also, the fire risk corresponding the two-day period when EDG 2 was essentially
non-functional (no run time remaining) is small because of a very low initiating event probability.
The Cooper IPEEE Internal Fire Analysis screened the fire zones that had a significant impact
on overall plant risk. When adjusted for the exposure period of this finding, the cumulative
baseline core damage frequency for the zones that had the potential for a control room
evacuation (and a procedure-induced LOOP) or an induced plant centered LOOP was
approximately 3.6E-7/yr. The methods used to screen these areas were not rigorous and used
several bounding assumptions. The analyst qualitatively assumed that the increase in risk from
having EDG 2 in a status where it is assumed to fail at 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> would likely be somewhat
less than one order of magnitude above the baseline, or 3.6E-6/yr. This is easily demonstrated
by an assumption that failure to re-connect offsite power within a period of at least 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> is
well less than 10 percent. Based on these considerations, the analyst concluded that the risk
related to fires would not be sufficiently large to change the risk characterization of this finding.
The seismicity at Cooper is low and would likely have a small impact on risk for an EDG issue.
As a sensitivity, data from the RASP External Events Handbook was used to estimate the scope
of the seismic risk particular to this finding. The generic median earthquake acceleration
assumed to cause a loss of offsite power is 0.3g. The estimated frequency of earthquakes at
Cooper of this magnitude or greater is 9.828E-5/yr. The generic median earthquake frequency
assumed to cause a loss of the diesel generators is 3.1g, though essential equipment powered
by the EDGs would likely fail at approximately 2.0g. The seismic information for Cooper is
capped at a magnitude of 1.0g with a frequency of 8.187E-6. This would suggest that an
earthquake could be expected to occur with an approximate frequency of 9.0E-5/yr that would
remove offsite power but not damage other equipment important to safe shutdown. In the
A2-12 Attachment 2
internal events discussion above, it was estimated that LOOPS that exceeded 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />
duration would occur with a frequency of 3.99E-3/yr. Most LOOPS that exceed 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />
duration would likely have recovery characteristics closely matching that from an earthquake.
The ratio between these two frequencies is 44. Based on this, the analyst qualitatively
concluded that the risk associated with seismic events would be small compared to the internal
result.
Flooding could be a concern because of the proximity to the Missouri River. However, floods
that would remove offsite power would also likely flood the EDG compartments and therefore
not result in a significant change to the risk associated with the finding. The switchyard
elevation is below that of the power block by several feet, but it is not likely that a slight
inundation of the switchyard would cause a loss of offsite power. The low frequency of floods
within the thin slice of water elevations that would remove offsite power for at least 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />
but not debilitate the diesel generators indicates that external flooding would not add
appreciably to the risk of this finding.
Based on the above, the analyst determined that external events did not add significantly to the
risk of the finding.
Large Early Release Frequency:
In accordance with Manual Chapter 0609, Appendix A, Attachment 1, Step 2.6, "Screening for
the Potential Risk Contribution Due to LERF," the analyst reviewed the core damage sequences
to determine an estimate of the change in large early release frequency caused by the finding.
The LERF consequences of this performance deficiency were similar to those documented in a
previous SDP Phase 3 evaluation regarding a misalignment of gland seal water to the service
water pumps. The final determination letter was issued on March 31, 2005 and is located in
ADAMS, Accession No. ML050910127. The following excerpt from this document addressed
the LERF issue:
The NRC reevaluated the portions of the preliminary significance determination related
to the change in LERF. In the regulatory conference, the licensee argued that the
dominant sequences were not contributors to the LERF. Therefore, there was no
change in LERF resulting from the subject performance deficiency. Their argument was
based on the longer than usual core damage sequences, providing for additional time to
core damage, and the relatively short time estimated to evacuate the close in population
surrounding Cooper Nuclear Station.
LERF is defined in NRC Inspection Manual Chapter 0609, Appendix H, Containment
Integrity Significance Determination Process as: the frequency of those accidents
leading to significant, unmitigated release from containment in a time frame prior to the
effective evacuation of the close-in population such that there is a potential for early
health effect. The NRC noted that the dominant core damage sequences documented
in the preliminary significance determination were long sequences that took greater than
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to proceed to reactor pressure vessel breach. The shortest calculated interval
from the time reactor conditions would have met the requirements for entry into a
general emergency (requiring the evacuation) until the time of postulated containment
rupture was 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The licensee stated that the average evacuation time for Cooper,
from the declaration of a General Emergency was 62 minutes.
A2-13 Attachment 2
The NRC determined that, based on a 62-minute average evacuation time, effective
evacuation of the close-in population could be achieved within 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Therefore, the
dominant core damage sequences affected by the subject performance deficiency were
not LERF contributors. As such, the NRCs best estimate determination of the change in
LERF resulting from the performance deficiency was zero.
In the current analysis, the total contribution of the 30-minute sequences for the 35-day period
(when 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> of EDG run time remained) to the current case CDF is only 0.54% of the total.
That is, almost all of the risk associated with this performance deficiency involves sequences of
duration 5.35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> or longer following the loss of all ac power.
The two-day period where EDG 2 was essentially unavailable had a delta-CDF of 1.528E-7. Of
these, the 30-minute sequences comprise only 2 percent of the total current case CDF and the
two-hour sequences comprise only 0.3 percent of the total.
Consequently, the analyst determined that the risk associated with large early release was very
small.
References:
SPAR-H Human Reliability Analysis Method, NUREG CR-6883, Sept. 2004
GE-NE-E1200141-04R2, Table 5-1, Shutdown Power at Cooper Nuclear Station (proprietary)
Green Screen Source Data, External Events PRA model, Nine Mile Point, Unit 1
NUREG/CR-6890, Reevaluation of Station Blackout Risk at Nuclear Power Plants, Analysis of
Loss of Offsite Power Events: 1986-2004"
Peer Review:
See-Meng Wong, NRR
A2-14 Attachment 2