ML100430713
| ML100430713 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 02/11/2010 |
| From: | Geoffrey Miller NRC/RGN-IV/DRP/RPB-B |
| To: | |
| References | |
| ea-10-004, EA-10-020 | |
| Download: ML100430713 (118) | |
See also: IR 05000482/2009005
Text
February 11, 2010
Matthew W. Sunseri, President and
Chief Executive Officer
Wolf Creek Nuclear Operating Corporation
P.O. Box 411
Burlington, KS 66839
SUBJECT:
WOLF CREEK GENERATING STATION - NRC INTEGRATED INSPECTION
REPORT 05000482/2009005 AND NOTICE OF VIOLATIONS
Dear Mr. Sunseri:
On December 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Wolf Creek Generating Station. The enclosed integrated inspection report
documents the inspection findings, which were discussed on January 14, 2010, with you and
other members of your staff.
The inspections 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.
Based on the results of this inspection, the NRC has identified two issues that were evaluated
under the risk significance determination process as having very low safety significance (green).
The NRC has also determined that violations are associated with these issues. One violation
involved failure to implement corrective actions to address refueling water storage tank leakage
(EA-10-004). The second violation involved failure to correct an inadequate reactor vessel head
vent path (EA-10-020). These violations were evaluated in accordance with the NRC
Enforcement Policy included on the NRCs Web site at www.nrc.gov/about-
nrc/regulatory/enforcement/enforce-pol.html.
The violations are being cited in the enclosed Notice of Violations (Notice) and the
circumstances surrounding them are described in detail in the subject inspection report. The
violations are being cited in the Notice because Wolf Creek Generating Station failed to restore
compliance within a reasonable time after the violations were identified in NRC Inspection
Reports05000482/2007003-006 and 05000482/2008004-007, as specified in Section VI.A.1 of
You are required to respond to this letter and should follow the instructions specified in the
enclosed Notice when preparing your response. The NRC will use your response, in part, to
UNITED STATES
NUCLEAR REGULATORY COMMISSION
R E GI ON I V
612 EAST LAMAR BLVD, SUITE 400
ARLINGTON, TEXAS 76011-4125
Wolf Creek Nuclear Operating Corporation - 2 -
- 2 -
determine whether further enforcement action is necessary to ensure compliance with
regulatory requirements.
Based on the results of this inspection, the NRC has also determined that one additional
Severity Level IV violation of NRC requirements occurred. This report also documents
12 NRC identified and one self-revealing finding of very low safety significance (Green). All of
these findings were determined to involve violations of NRC requirements. Additionally, two
licensee-identified violations, which were determined to be of very low safety significance, are
listed in this report. However, because of the very low safety significance and because they are
entered into your corrective action program, the NRC is treating these findings as noncited
violations, consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the
violations or the significance of the noncited violations, 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, D.C. 20555-0001, with
copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E.
Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident
Inspector at the Wolf Creek Generating Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and its
enclosure, will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records component of NRCs document system (ADAMS).
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the
Public Electronic Reading Room).
Sincerely,
/RA/
Geoffrey B. Miller, Chief
Project Branch B
Division of Reactor Projects
Docket No. 50-482
License No. NPF-42
Enclosure
Inspection Report 05000482/2009005
w/Attachment: Supplemental Information
Wolf Creek Nuclear Operating Corporation - 3 -
- 3 -
cc w/Enclosure:
Vice President Operations/Plant Manager
Wolf Creek Nuclear Operating Corporation
P.O. Box 411
Burlington, KS 66839
Jay Silberg, Esq.
Pillsbury Winthrop Shaw Pittman LLP
2300 N Street, NW
Washington, DC 20037
Supervisor Licensing
Wolf Creek Nuclear Operating Corporation
P.O. Box 411
Burlington, KS 66839
Chief Engineer
Utilities Division
Kansas Corporation Commission
1500 SW Arrowhead Road
Topeka, KS 66604-4027
Office of the Governor
State of Kansas
Topeka, KS 66612
Attorney General
120 S.W. 10th Avenue, 2nd Floor
Topeka, KS 66612-1597
County Clerk
Coffey County Courthouse
110 South 6th Street
Burlington, KS 66839
Chief, Radiation and Asbestos
Control Section
Kansas Department of Health and
Environment
Bureau of Air and Radiation
1000 SW Jackson, Suite 310
Topeka, KS 66612-1366
Wolf Creek Nuclear Operating Corporation - 4 -
- 4 -
Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov)
Deputy Regional Administrator (Chuck.Casto@nrc.gov)
DRP Director (Dwight.Chamberlain@nrc.gov)
DRP Deputy Director (Anton.Vegel@nrc.gov)
DRS Director (Roy.Caniano@nrc.gov)
DRS Deputy Director (Troy.Pruett@nrc.gov)
Senior Resident Inspector (Chris.Long@nrc.gov)
Site Secretary (Shirley.Allen@nrc.gov)
Branch Chief, DRP/B (Geoffrey.Miller@nrc.gov)
Senior Project Engineer, DRP/B (Rick.Deese@nrc.gov)
Senior Public Affairs Officer (Victor.Dricks@nrc.gov)
Senior Public Affairs Officer (Lara.Uselding@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Team Leader, DRP/TSS (Chuck.Paulk@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Only inspection reports to the following:
DRS/TSB STA (Dale.Powers@nrc.gov)
L. Trocine, OEDO RIV Coordinator (Leigh.Trocine@nrc.gov)
ROPreports
File located: R:\\_REACTORS\\_WC\\2009\\WC20090005-RP-CML.doc ML 100430713
SUNSI Rev Compl.
- Yes No
- Yes No
Reviewer Initials
GBM
Publicly Avail
- Yes No
Sensitive
Yes : No
Sens. Type Initials
GBM
RI:DRP/
SRI:DRP/
SPE:DRP/
C:DRS/EB1
C:DRS/EB2
CAPeabody
CMLong
RDeese
TFarnholtz
NFOKeefe
/RA/GMiller for
/RA/GMiller for
/RA/
/RA/
/RA/
01/22/2010
01/29/2010
02/05/2010
02/05/2010
02/05/2010
C:DRS/OB
C:DRS/PSB1
C:DRS/PSB2
RIV:ACES
C:DRP/
SGarchow
MPShannon
GEWerner
RKellar
GBMiller
/RA/
/RA/
/RA/
/RA/
/RA/
02/09/2010
02/08/2010
02/09/2010
02/09/2010
02/11010
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
- 1 -
Enclosure 1
Wolf Creek Nuclear Operating Corporation
Docket: 50-482
Wolf Creek Generating Station
License: NPF-42
During an NRC inspection conducted October 1 through December 31, 2009, two violations of
NRC requirements were identified. In accordance with the NRC Enforcement Policy, the
violations are listed below:
A.
Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires,
in part, that measures shall be established to assure that conditions adverse
to quality are promptly identified and corrected.
Contrary to the above, from 1998 to December 31, 2009, the measures
established by Wolf Creek did not correct a condition adverse to quality.
Specifically, Wolf Creek did not correct leakage from the refueling water
storage tank.
This violation is associated with a Green Significance Determination Process finding
(EA-10-004).
B.
Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that
the design basis is correctly translated into specifications, drawings, and procedures.
The design basis of the reactor vessel head vent is to allow noncondensable gases to
escape to the pressurizer during shutdown conditions.
Contrary to the above, from December 2, 2003, to December 31, 2009, Wolf Creek
failed to ensure the design basis of the reactor vessel head vent was correctly translated
into specifications, drawings and procedures. Specifically, Wolf Creek designed and
installed a reactor vessel head permanent vent piping modification which failed to vent
noncondensable gases to the pressurizer during shutdown operations.
This resulted in the formation of voids in the reactor vessel head while the plant was
shutdown and depressurized in successive refueling outages.
This violation is associated with a Green Significance Determination Process finding
(EA-10-020).
Pursuant to the provisions of 10 CFR 2.201, Wolf Creek Nuclear Operating Corporation is
hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555, with a copy to the
Regional Administrator, Region IV, and a copy to the NRC Senior Resident Inspector at the
facility that is the subject of this Notice of Violation (Notice), within 30 days of the date of the
letter transmitting this Notice. This reply should be clearly marked as a "Reply to Notice of
Violation EA-10-004," EA 10-020, and should include for each violation (1) the reason for the
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Enclosure 1
violation, or, if contested, the basis for disputing the violation or severity level, (2) the corrective
steps that have been taken and the results achieved, (3) the corrective steps
That will be taken to avoid further violations, and (4) the date when full compliance will be
achieved. Your response may reference or include previous docketed correspondence, if the
correspondence adequately addresses the required response. If an adequate reply is not
received within the time specified in this Notice, an Order or a Demand for Information may be
issued as to why the license should not be modified, suspended, or revoked, or why such other
action as may be proper should not be taken. Where good cause is shown, consideration will
be given to extending the response time.
If you contest this enforcement action, you should also provide a copy of your response, with
the basis for your denial, to the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001.
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from the NRCs document system (ADAMS), accessible from the
NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should not
include any personal privacy, proprietary, or safeguards information so that it can be made
available to the public without redaction. If personal privacy or proprietary information is
necessary to provide an acceptable response, then please provide a bracketed copy of your
response that identifies the information that should be protected and a redacted copy of your
response that deletes such information. If you request withholding of such material, you must
specifically identify the portions of your response that you seek to have withheld and provide in
detail the bases for your claim of withholding (e.g., explain why the disclosure of information will
create an unwarranted invasion of personal privacy or provide the information required by
10 CFR 2.390(b) to support a request for withholding confidential commercial or financial
information. If safeguards information is necessary to provide an acceptable response, please
provide the level of protection described in 10 CFR 73.21.
Dated this 11h day of February 2010
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Enclosure 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
05000482
License:
Report:
Licensee:
Wolf Creek Operating Corporation
Facility:
Wolf Creek Generating Station
Location:
1550 Oxen Lane SE
Burlington, Kansas
Dates:
October 1 through December 31, 2009
Inspectors:
C. M. Long, Senior Resident Inspector
R. A. Kopriva, Senior Reactor Inspector
J. F. Drake, Senior Reactor Inspector
D. Loveless, Senior Reactor Analyst
C. A. Peabody, Resident Inspector
S. M. Alferink, Reactor Inspector
P. A. Jayroe, Project Engineer
C. Cauffman, Operations Engineer
A. L. Fairbanks, Reactor Inspector
C. C. Alldredge, Project Engineer
G. M. Vasquez, Senior Health Physicist
D. C. Graves, Health Physicist
Approved By:
G. B. Miller, Chief, Project Branch B
Division of Reactor Projects
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Enclosure 2
SUMMARY OF FINDINGS
IR 05000482/2008005, 10/01/2009 - 12/31/2009; Wolf Creek Generating Station, Integrated
Resident and Regional Report; Fire Protection, Inservice Inspection Activities; Maintenance Risk
Assessments and Emergent Work Controls; Operability Evaluations; Plant Modifications;
Refueling Outage and Other Outage Activities; Radiation Safety; Identification and Resolution of
Problems, and Other Activities.
The report covered a 3-month period of inspection by resident inspectors and an announced
baseline inspections by a regional based inspectors. Fourteen Green and one Severity Level IV
noncited violation were identified and two Green cited violations were also identified. 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 NRC's 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 Findings and Self-Revealing Findings
Cornerstone: Initiating Events
Green. The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, involving the licensees failure to
identify sources of boron leakage and document them in a corrective action document.
Specifically, prior to October 23, 2009, the licensee failed to accomplish the
requirements of Procedure AP 16F-001, Boric Acid Corrosion Control Program,
Revision 5, step 6.4.1, which states, in part, Sources of boron seepage/leakage shall
be identified/verified and documented in the applicable corrective action document.
During a boric acid walkdown, the inspectors identified 11 sources of boron leakage
which had not been previously identified and documented by the licensee. The licensee
entered this finding into their corrective action system as Condition Report 00021274.
The finding was determined to be more than minor because it was associated with the
Initiating Events Cornerstone attribute of human performance and affected the
cornerstone objective to limit the likelihood of those events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations. The
inspectors used Inspection Manual Chapter 0609, Significance Determination Process,
Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and
determined the finding was of very low safety significance (Green) because the issue
would not result in exceeding the technical specification limit for identified reactor
coolant system leakage or affect other mitigating systems resulting in a total loss of their
safety function. The inspectors also determined that the finding had a crosscutting
aspect in the area of problem identification and resolution, operating experience, where
the licensee did not institutionalize operating experience through changes to station
processes, procedures, equipment, and training programs [P.2.(b)] (Section 1R08.2.b).
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Enclosure 2
Green. On December 16, 2009, inspectors identified a noncited violation of 10 CFR
Part 50, Appendix B, Criterion III, Design Control, involving failure to obtain vendor
design data for a modification. In August 2009, a component cooling water modification
was made to the reactor coolant pump thermal barrier heat exchangers flow rates as a
corrective action to VIO 05000482/2009002 07 (EA-09-110). A flow rate above the
previous design value was justified by an internal memo of a vendor opinion from a
telephone conversation in 1992. The inspectors found this to be contrary to
Procedure AP 05-005, for obtaining data from vendors. The notice of violation will
remain open until full compliance has been restored. Wolf Creek consulted with
Westinghouse, confirmed the acceptability of the increased flow rate, and requested a
formal calculation. This issue is captured in Condition Report 22824.
The inspectors determined that this finding was more than minor because this issue
aligned with Inspection Manual Chapter 0612, Appendix E, example 2.f, in that the
modification relied on verbal statements to raise the allowable flow through the heat
exchanger. This is a significant deficiency in the modification package. The inspectors
determined this finding was associated with the design control attribute of the Initiating
Events Cornerstone and affected the cornerstone objective to limit the likelihood of
events that upset plant stability and challenge critical safety functions. The inspectors
evaluated the significance of this finding using Phase 1 of Inspection Manual
Chapter 0609.04 and determined that the finding was of very low safety significance
because assuming worst case degradation, the finding would not result in exceeding the
technical specification limit for identified reactor coolant system leakage and would not
have likely affected other mitigation systems resulting in a total loss of their safety
function because seal injection was available. This finding has a crosscutting aspect in
the area of human performance associated with work practices in that management was
unsuccessful in communicating expectations on procedure use and adherence in
engineering H.4.b] (Section 1R18).
Green. The inspectors identified a cited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, due to an inadequate vent path for the reactor vessel
head. The inadequate vent path resulted in the formation of voids in the reactor vessel
head during Refueling Outage 17. Failure to ensure an adequate vent path in the
reactor vessel head was the subject of a noncited violation in NRC Inspection
Report 05000482/2008004. During and after Refueling Outage 16, Wolf Creek initiated
a root cause evaluation and corrective actions to prevent occurrence. When one of the
possible root causes was disproven in Refueling Outage 17, no additional action was
taken to determine the cause of the vessel head vent blockage. However, the licensee
could not exclude blockage in the piping. This issue was entered into the corrective
action program and the licensee plans to conduct a more thorough inspection of the
piping during the next refueling outage. This issue is being tracked by the licensee as
Condition Report 22501.
The inspectors determined that the failure to provide adequate vessel head vent path to
prevent gas accumulation in the reactor vessel during depressurized plant operations
was a performance deficiency. The inspectors determined that this finding, which was
associated with the Initiating Events Cornerstone, was more than minor because if left
uncorrected, it would have become a more significant-safety concern. Specifically,
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Enclosure 2
without an adequate vent path the reactor vessel does not have an effective means of
relieving noncondensable gases to prevent a loss of reactor coolant system inventory.
The inspectors evaluated this finding using Inspection Manual Chapter 0609,
Appendix G, Attachment 1, and determined it be of very low safety significance based
upon the demonstrated availability of mitigating systems and the flooded reactor cavity
inventory. The inspectors determined the cause of the finding had a problem
identification and resolution aspect in the corrective action program. Specifically, Wolf
Creeks corrective actions were not successful to address the vent path blockage in a
timely manner P.1(d) (Section 1R20).
Green. The inspectors identified a noncited violation of License Condition 2.C.(5), Fire
Protection, for the failure to implement and maintain the approved fire protection
program. Specifically, the licensee prescribed mitigating actions in response to certain
fire scenarios that would result in a loss of circuit breaker coordination and could initiate
secondary fires in plant locations outside of the initial fire area. The licensee entered
this issue into their corrective action program as Condition Report 2008-005210.
This finding was more than minor because it was associated with the Protection Against
External Factors attribute of the Initiating Events Cornerstone and adversely affected the
cornerstone objective to limit the likelihood of those events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations. The
risk significance of this finding was determined using Manual Chapter 0609, Appendix F,
Fire Protection Significance Determination Process. The finding was determined to be
of very low safety significance using a Phase 2 evaluation. This finding was not
assigned a crosscutting aspect because the cause was not representative of current
performance (Section 4OA5.2).
Cornerstone: Mitigating Systems
Green. The inspectors identified a cited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, for failure to take action to stop leakage from the base
of the refueling water storage tank or evaluate the leakage and wastage for
acceptability. Specifically, the licensee did not take actions to prevent recurring
discolored boric acid deposits for approximately 11 years. Failure to correct leakage
from the refueling water storage tank base was the subject of a noncited violation in
NRC Inspection Report 05000482/2007006. This issue was entered into the licensee's
corrective action program as Condition Report 22866.
The failure to implement corrective actions for the refueling water storage tank leakage
was a performance deficiency. The inspectors determined this issue impacted the
Mitigating Systems Cornerstone and was greater than minor because if left uncorrected,
the failure to correct the presence of boric acid leakage could become a more significant
safety concern in that continued wastage could impact tank operability. Using the
Phase 1 worksheets in Inspection Manual Chapter 0609.04, "Significance Determination
Process," the finding was determined to have very low safety significance because it did
not result in a system or component being inoperable and it did not screen as potentially
risk significant due to a seismic, flooding, or severe weather initiating event. The
inspectors identified a crosscutting aspect in the area of human performance associated
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Enclosure 2
with resources. Specifically, Wolf Creek did not maintain long-term plant safety
minimizing corrective maintenance deferrals and this long-standing equipment issue
H.2.c] (Section 1R05).
Green. The inspectors identified a noncited violation of Technical Specification 5.4.1.a,
for an inadequate Procedure AP-10-101, Control of Transient Ignition Sources. On
October 21, 2009, the inspectors observed maintenance personnel performing weld
preparation work on essential service water piping to containment cooler B using a
flapper wheel. The inspectors observed that the ignition control barriers for the hot work
were insufficient in that the sparks from the preparation work extended four to five feet
from the job site and there was no fire watch posted. On December 4, 2003, a
procedure revision inappropriately incorporated a change to the procedure where a fire
watch did not have to be posted when using wire brushes, flapper wheels, polishing
devices, or Rol-Lok type buffing pads mounted on power grinder motor drives or air
tools. The maintenance supervisor stopped the work until a fire watch was posted. The
licensee entered this into their corrective action system as Condition Report 20993.
This finding is more than minor because it affected the Mitigating Systems Cornerstone
attribute of Protection Against External Factors - Fires, and adversely affected the
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. The lack of a posted
fire watch could adversely affect the ability to achieve and maintain safe shutdown in the
event of a severe fire in the affected area. Inspection Manual Chapter 0609,
Appendix F, Fire Protection Significance Determination Process, could not be used to
effectively evaluate the finding and defense-in-depth strategies because the 2003
changes to the fire watch program affected multiple fire areas and conditions. Therefore,
in accordance with Inspection Manual Chapter 0609, Appendix M, the safety significance
was determined by regional management review who concluded that the finding was of
very low safety significance (Green). This finding was reviewed for crosscutting aspects
and none were identified. The original change occurred in 2003 and was not indicative
of current performance (Section 1R05.2).
Green. The inspectors identified a noncited violation of 10 CFR 50.65(a)(4) involving the
failure to adequately perform shutdown risk assessments during Refueling Outage 17.
Between October 10 and November 17, 2009, Wolf Creek did not appropriately consider
electrical power, decay heat removal, and containment when assessing shutdown risk.
This changed the outcome or color of the qualitative calculation on several occasions.
The licensee entered this issue in their corrective action program as Condition
Reports 22295 and 22296.
The failure to meet shutdown risk assessment requirements in the daily shutdown risk
assessment process is a performance deficiency. The inspectors determined this finding
was associated with the Mitigating Systems Cornerstone and was more than minor
because it involved incorrect risk assessment assumptions by omitting requirements
specified in committed guidance without providing justification for that omission. Such
errors of omission have the potential to change the outcome of the licensees
maintenance risk assessment as described above. Per Inspection Manual
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Enclosure 2
Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management
Significance Determination Process, licensees who only perform qualitative analyses of
plant configuration risk due to maintenance activities, the significance of the deficiencies
must be determined by an internal NRC management review using risk insights where
possible in accordance with Inspection Manual Chapter 612, Power Reactor Inspection
Reports. The NRC management review concluded that this finding was of Green safety
significance because missing risk management actions did not result in loss of key
shutdown risk functions. Additionally, the cause of the finding has a human performance
crosscutting aspect in the area associated with the resources. Specifically, Wolf Creek
did not ensure that Procedure APF 22B-001-02 was complete, accurate, and up-to-date
H.2(c) (Section 1R13).
Green. On November 18, 2009, the inspectors identified a noncited violation of
Technical Specification 3.0.4.b for ascension from Mode 4 to Mode 3 without establishing
required risk management actions. Wolf Creek used technical specification Limiting
Condition for Operation 3.0.4.b to permit mode ascension after performance of a risk
assessment and identification of risk management actions to maintain safety in the next
mode. The turbine-driven auxiliary feedwater pump was inoperable per Technical
Specification 3.7.5. As a risk management action, protected train signs would be placed
on the doors to the motor-driven auxiliary feedwater Pump A and B room doors. A
walkdown conducted by the inspector on the morning of November 18, 2009, found that
the protected train signs on the motor-driven auxiliary feedwater pump rooms were not in
place. Also, a maintenance crew was performing radiography in the motor-driven
auxiliary feedwater pump Room B. The motor-driven auxiliary feedwater Pumps A and B
were also made inoperable (at separate times) later on the morning of November 18,
2009. The licensee entered this issue in their corrective action program as Condition
Report 21926.
Mode ascension under Technical Specification LCO 3.0.4.b without establishing required
risk management actions is a performance deficiency. The finding was more than minor
because it was associated with the configuration control and alignment attribute of the
Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. The configuration control issues not only included
the work being completed on the turbine-driven auxiliary feedwater pump, but also
included containment isolation valve testing and radiography that was performed on the
motor-driven auxiliary feedwater pumps which was not included in the risk assessment.
The inspector used Inspection Manual Chapter 0609.04, to determine that the finding
was of very-low safety significance (Green) because it did not result in a loss of system
safety function; did not exceed allowable technical specification outage time; and was
not a seismic, flooding, or severe weather concern. Additionally, the cause of the finding
has a human performance crosscutting aspect in the area associated with decision
making. Specifically, Wolf Creek used a risk assessment form and an informal mode
change form to communicate between departments the requirement for risk
management actions. The two forms were in conflict and the personnel who
implemented the risk management actions were not informed H.1(c) (Section 1R13).
- 7 -
Enclosure 2
Green. On October 15, 2009, the inspectors identified a noncited violation of 10 CFR
Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to
follow Procedure AP 28A-100, Condition Reports. Wolf Creek failed to initiate a
condition report for evaluation of corrosion on containment cooler A piping. After
inspector challenging, Wolf Creek initiated condition reports, performed nondestructive
testing, replaced corroded studs, and evaluated the cause of the corrosion.
The inspectors determined that the failure to follow AP 28A-100, Appendix C, was a
performance deficiency. This issue was more than minor because it was associated
with the equipment performance attribute of the Mitigating Systems Cornerstone and
affected the cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. Using
Inspection Manual Chapter 0609.04, the issue screened to Green because there was
not a loss of operability and the finding did not screen as potentially risk significant due
to a seismic, flooding, or severe weather initiating event. A crosscutting aspect was
identified in the problem identification and resolution area of the corrective action
program. Specifically, Wolf Creek failed to implement a corrective action program with a
low threshold for identifying issues P.1.a] (Section 1R13).
Green. On November 23, 2009, a self-revealing violation of Technical
Specification 5.4.1.a was identified when a technician failed to follow procedure and
emptied 45 gallons of oil from centrifugal charging Pump A rendering the pump
inoperable. The technician was supposed to remove the temperature indicator for
calibration but instead removed the thermowell which breached the lube oil subsystem
of centrifugal charging Pump A. An unplanned entry into Technical Specification 3.5.2,
Condition A, was made for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. The licensee entered this issue in
their corrective action program as Condition Report 21993.
The failure to follow station procedures and correctly remove the detector was a
performance deficiency. The finding was more than minor because it was associated
with the equipment performance attribute of the Mitigating Systems Cornerstone and
affected the cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. The
inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual
Chapter 0609.04, and determined that the finding was of very low safety significance
(Green) because the pump was inoperable for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Also, the finding did
not screen as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. The inspectors identified a human performance crosscutting in the area
of work practices because self-checking and communication with the supervisor failed to
prevent the event H.4.a] (Section 1R13).
Green. On November 5, 2009, inspectors identified a noncited violation of 10 CFR
Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure
to perform an adequate operability evaluation required by procedure. The inspectors
identified that Operability Evaluation EF 09-010, Revisions 0 and 1, did not demonstrate
that the essential service water pumps could withstand a safe shutdown earthquake.
Revision 2 of the operability evaluation included calculations to demonstrate acceptable
- 8 -
Enclosure 2
stresses and included pump impeller clearances. This issue is captured in the corrective
action program as condition reports 22798 and 21572.
The failure to perform an adequate operability evaluation per Procedures AP 28-001
and AP 26C 004 was a performance deficiency. The inspectors determined that this
finding was more than minor because it is associated with the equipment performance
attribute of the Mitigating Systems Cornerstone, and it affected the cornerstone objective
to ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences (i.e., core damage). Specifically, this issue
relates to the availability and reliability examples of the equipment performance attribute
because a latent common mode failure mechanism was not correctly evaluated. The
inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual
Chapter 0609, Appendix A, and determined that the finding was of very low safety
significance (Green) because the issue was not a design or qualification deficiency
confirmed to result in loss of operability or functionality, did not represent a loss of
system safety function, an actual loss of safety function of a single train for greater than
its technical specification allowed outage time, an actual loss of safety function of a
nontechnical specification risk-significant equipment train, and did not screen as
potentially risk significant due to a seismic, flooding, or severe weather initiating event.
The cause of the finding has a problem identification and resolution crosscutting aspect
associated with the corrective action program because Wolf Creek failed to thoroughly
evaluate the failure mechanism such that the resolutions address the causes and extent
of conditions, as necessary P.1.c] (Section 1R15).
Green. The inspectors identified a noncited violation of Technical Specification 5.4.1.a
for failure to properly implement Procedure AP 14A-003, Scaffold Construction and
Use, when scaffolding was erected against operable safety-related equipment. On
October 15, 2009, the inspectors walked down containment and identified scaffolding in
contact with component cooling water piping. The tag on the scaffold explicitly stated
that it was not seismically qualified. At the time, both steam generators were inoperable
and both trains of residual heat removal were required to be operable. The inspectors
reviewed the bases for Technical Specification 3.4.7, RCS Loops - Mode 5, Loops
Filled, which required an operable heat sink path from residual heat removal to
component cooling water to essential service water. This issue was entered into the
corrective action program as Condition Report 22464.
The construction of an unqualified scaffold against operable component cooling water
piping was a performance deficiency. The inspectors determined that this finding was
more than minor because it is associated with the equipment performance attribute for
the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences (i.e., core damage). Specifically, this issue relates to
the availability and reliability examples of the equipment performance attribute because
a latent failure mechanism was not evaluated. The inspectors evaluated the significance
of this finding using Inspection Manual Chapter 0609, Appendix G, Attachment 1,
Shutdown Operations Significance Determination Process Phase 1 Operational
Checklists for Both PWRs and BWRs. The inspectors determined that Checklist 3 was
applicable because the unit was in cold shutdown with the refueling cavity level less than
- 9 -
Enclosure 2
23 feet. Using Appendix G, Attachment 1, Checklist 3, Phase 2 analysis was not
needed and the finding was of very low safety significance (Green) because the licensee
was able to demonstrate that the seismically unqualified scaffolding would not have
resulted in a loss of safety function. The inspectors determined the cause of the finding
had a human performance aspect in the area of resources. Specifically,
Procedure AP 14A-003 was inadequate because it had conflicting guidance that allowed
seismically unqualified scaffolds in Modes 5 and 6 H.2.c] (Section 1R20).
Cornerstone: Barrier Integrity
Green. The inspectors identified a noncited violation of Technical Specification 3.3.1,
Condition I, for making positive reactivity addition prohibited by technical specifications
in Mode 2 because one source range nuclear instrument channel was inoperable.
Following a reactor transient, one of the source range nuclear instrument channels
experienced an unanticipated increased count rate and was declared inoperable. Wolf
Creek restored the channel in an operability evaluation which cited the cause as a
problem in a component which was later determined not to exist in the installed
configuration; however, the improperly restored equipment had already been used for to
support plant startup on August 22, 2009. Wolf Creek replaced the detector during
Refueling Outage 17. This issue was entered into the correction action program as
Condition Report 20208.
Reactivity addition with source range channel Nuclear Instrument-31 inoperable is a
performance deficiency. The finding was more than minor because it was associated
with the configuration control (reactivity control) attribute of the Barrier Integrity
Cornerstone, and it affected the cornerstone objective to provide reasonable assurance
that physical design barriers (fuel cladding, reactor coolant system, and containment)
protect the public from radionuclide releases caused by accidents or events. The
inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual
Chapter 0609.04, and determined that the finding screened to Green because the
finding only affected the fuel barrier. Additionally, the cause of the finding has a human
performance crosscutting aspect in the area associated with the decision making.
Specifically, Wolf Creek did not use conservative assumptions in decision making and
adopt requirements to demonstrate that the proposed action is safe in order to proceed
rather than a requirement to demonstrate that it is unsafe in order to disapprove the
action, when performing an operability evaluation for the source range Nuclear
Instrument 31 detector prior to restarting from a forced outage H.1(b) (Section 1R15).
Green. On December 30, 2009, the inspectors identified a noncited violation of
Technical Specification Table 3.3.1-1, Function 18.a, when Wolf Creek restarted on
May 18, 2005. During a reactor shutdown on October 7, 2006, intermediate range
neutron detector Nuclear Instrument-36 did not decrease below 6E -11 amps and
energize source range detector Nuclear Instrument-32. The detector was not replaced
until Refueling Outage 16 in March 2008. The licensee entered this issue in their
corrective action program as Condition Report 22450
The inspectors determined that the failure to ensure that the P-6 interlock was operable
per the technical specification as defined in the bases was a performance deficiency.
- 10 -
Enclosure 2
The finding was more than minor because it was associated with the configuration
control (reactivity control) attribute of the Barrier Integrity Cornerstone, and it affected the
cornerstone objective to provide reasonable assurance that physical design barriers (fuel
cladding, reactor coolant system, and containment) protect the public from radionuclide
releases caused by accidents or events. The inspectors evaluated the significance of
this finding using Phase 1 of Inspection Manual Chapter 0609.04, and determined that
the finding screened to Green because the P-6 interlock only affected the fuel barrier
(Section 4OA2). This finding was not assigned a crosscutting aspect because the cause
was not representative of current performance.
Cornerstone: Occupational Radiation Safety
Green. The inspector identified a noncited violation of Technical Specification 5.7.2.a.1
for failure to maintain administrative control of door and gate keys to high radiation areas
with dose rates greater than 1 rem per hour but less than 500 rads per hour (referred to
as locked high radiation areas). Specifically, as of October 21, 2009, the licensee did
not have administrative controls over a single master key to locked high radiation areas.
This issue was entered into the licensees corrective action program as Condition
Report 20973.
Failure to maintain administrative control of the master key to locked high radiation areas
was a performance deficiency. This finding is greater than minor because if left uncorrected
the finding has the potential to lead to a more significant safety concern in that an individual
could receive unanticipated radiation dose by gaining access a locked high radiation area
without the proper controls and briefing. This finding was evaluated using the occupational
radiation safety significance determination process and determined to be of very low safety
significance because it did not involve: (1) as low as is reasonably achievable planning or
work control issue, (2) an overexposure, (3) a substantial potential for overexposure, or
(4) an impaired ability to assess dose. Additionally, the violation has a crosscutting aspect
in the area of human performance associated with the work practices component because
the lack of peer and self-checking resulted in inadequate control of keys to locked high
radiation areas H.4(a) (Section 2OS1).
Cornerstone: Miscellaneous
Severity Level IV. The inspectors identified a Severity Level IV noncited violation of
10 CFR 50.73 in which the licensee failed to submit a licensee event report within 60 days
following discovery of events or conditions meeting the reportability criteria. On December
31, 2009, the inspectors identified a licensee event report that was no timely. Licensee
Event Report 2009-009-00 was not issued within 60 days for a condition prohibited by
technical specifications, and the event report did not identify that the disabling of both trains
of the P-4 interlock on August 22, 2009 was also reportable per 10 CFR 50.73(a)(2)(v). The
P-4 interlock was required by Technical Specification 3.3.2, function 8.a, and is discussed in
USAR, Section 7.3.8, NSSS Engineered Safety Feature Actuation System. Wolf Creek
licensee event report 2009-009 was correct in that the interlock is not credited in accident
analysis. However, NUREG 1022, Section 3.2.6, specifies that inoperable systems required
by the technical specifications be reported, even if there are other diverse operable means
of accomplishing the safety function.
- 11 -
Enclosure 2
The inspectors reviewed this issue in accordance with Inspection Manual Chapter 0612 and
the NRC Enforcement Manual. Through this review, the inspectors determined that
traditional enforcement was applicable to this issue because the NRC's regulatory ability
was affected. Specifically, the NRC relies on the licensee to identify and report conditions or
events meeting the criteria specified in regulations in order to perform its regulatory function,
and when this is not done, the regulatory function is impacted. The inspectors determined
that this finding was not suitable for evaluation using the significance determination process,
and as such, was evaluated in accordance with the NRC Enforcement Policy. The finding
was reviewed by NRC management, and because the violation was determined to be of
very low safety significance, was not repetitive or willful, and was entered into the corrective
action program, this violation is being treated as a Severity Level IV noncited violation
consistent with the NRC Enforcement Policy. This finding was determined to have a
crosscutting aspect in the area of problem identification and resolution associated with the
corrective action program in that the licensee failed to appropriately and thoroughly evaluate
for reportability aspects all factors and time frames associated with the inoperability of the
engineered safety features actuation system P.1(c) (Section 4OA3).
B.
Licensee-Identified Violations
Two violations of very low safety significance, which were identified by the licensee,
have been reviewed by the inspectors. Corrective actions taken or planned by the
licensee have been entered into the licensees corrective action program. These
violations and corrective action tracking numbers (condition report numbers) are listed in
Section 4OA7.
- 12 -
Enclosure 2
REPORT DETAILS
Summary of Plant Status
The plant started the inspection period at 100 percent rated thermal power. On October 10,
2009, Wolf Creek shutdown for Refueling Outage 17. On November 17, 2009, Wolf Creek
achieved criticality and on November 24, 2009, Wolf Creek achieved 100 percent power and
remained there for the remainder of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency
Preparedness
1R01 Adverse Weather Protection (71111.01)
.1
Readiness to Cope with External Flooding
a.
Inspection Scope
On October 28, 2009, the inspectors evaluated the design, material condition, and
procedures for coping with the design basis probable maximum flood. The evaluation
included a review to check for deviations from the descriptions provided in the Updated
Safety Analysis Report (USAR) for features intended to mitigate the potential for
flooding from external factors. As part of this evaluation, the inspectors checked for
obstructions that could prevent draining, checked that the roofs did not contain obvious
loose items that could clog drains in the event of heavy precipitation, and determined
that barriers required to mitigate the flood were in place and operable. Additionally, the
inspectors performed a walkdown of the protected area to identify any modification to
the site that would inhibit site drainage during a probable maximum precipitation event
or allow water ingress past a barrier. The inspectors also reviewed the abnormal
operating procedure for mitigating the design basis flood to ensure it could be
implemented as written.
These activities constitute completion of one external flooding sample as defined in
Inspection Procedure IP 71111.01-05.
b.
Findings
No findings of significance were identified.
- 13 -
Enclosure 2
1R04 Equipment Alignments (71111.04)
.1
Partial Walkdown
a.
Inspection Scope
The inspectors performed partial walkdown of the following risk-significant systems:
October 21, 2009, Train A while emergency diesel generator B and offsite power
out of service for maintenance
October 21, 2009, Spent fuel pool train A while spent fuel pool train B out of
service
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 affect the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating Procedures,
system diagrams, USAR, technical specification requirements, administrative technical
specifications, outstanding work orders, condition reports, 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 with
the appropriate significance characterization. Specific documents reviewed during this
inspection are listed in the attachment.
These activities constitute completion of two partial system walkdown samples as
defined in Inspection Procedure IP 71111.04-05.
b.
Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
.1
Quarterly Fire Inspection Tours
a.
Inspection Scope
The inspectors conducted fire protection walkdowns that were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
- 14 -
Enclosure 2
October 7, 2009, Auxiliary boiler oil combustion Impact on turbine-driven auxiliary
feedwater room
October 29, 2009, Spent fuel pool Room A
October 15, 2009, All levels of containment in Mode 5
November 12, 2009, Refueling water storage tank valve house
The inspectors reviewed areas to assess if licensee personnel 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 affect equipment that could initiate or mitigate a
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.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four quarterly fire-protection inspection samples
as defined by Inspection Procedure IP 71111.05-05.
b.
Findings
.1
Failure to Correct Discolored Boric Acid Deposits
Introduction. The inspectors identified a Green cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the failure to take action to stop
leakage from the base of the refueling water storage tank or evaluate the leakage and
wastage for acceptability.
Description. During the component design basis inspection in June 2007, the inspection
team noted white and brown deposits resembling boric acid at the base of the refueling
water storage tank. The licensee informed the team that past analysis had determined
these deposits were from calcium-silicate insulation which had been used for insulating
the refueling water storage tank. In 1998, the licensee had initiated Problem
Identification Request 1998-3860 to pursue the nature of the deposits and discovered
that the deposits did contain amounts of insulation, but also contained boron. The
licensee had dismissed the boron as spillage from a sampling evolution. On two
subsequent occasions after 1998, the deposits were questioned by the licensee and
- 15 -
Enclosure 2
again dismissed as insulation based on the 1998 resolution. In each of these cases the
deposits were cleaned up, and the problem identification requests written only
addressed the poor materiel condition of the area. The component design basis
inspection team questioned the previous conclusions that the deposits were insulation
material based on the strong resemblance to boric acid deposits from leakage of reactor
coolant from the refueling water storage tank. The licensee sent samples of the deposits
for offsite laboratory analysis, which confirmed that the deposits contained boron.
Subsequently, the licensee performed inspections of the carbon steel components in the
area and determined that no significant wastage had occurred and operability of the
refueling water storage tank and its surrounding components was not affected. The
inspection team documented a noncited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, for inadequate corrective actions in response to the leakage from the
refueling water storage tank, documented in NRC Inspection Report 05000482/2007006
On November 12, 2009, the resident inspectors walked down the refueling water storage
tank valve house and again identified that the base of the refueling water storage tank
had deposits that resembled boric acid in several locations. Some deposits had
progressed up the tank bolting several inches from the floor. Initially, Wolf Creek again
maintained that the deposits were calcium silicate from insulation. The inspectors
questioned the licensee about the deposits, and laboratory testing again demonstrated
the presence of boric acid.
The inspectors reviewed the actions Wolf Creek had taken in response to NCV
05000482/2007006-03 in the component design basis inspection report. Wolf Creek had
performed a boric acid corrosion evaluation as part of Work Order 07-300734-000, which
concluded that the refueling water storage tank leak was not active, though the tank
deposits reappeared after cleanings in July 2007, August 2008, March 2009, June 2009,
and September 2009. Wolf Creek attempted to repair roof leaks in the refueling water
storage tank valve house as a source of rain water ingress, but took no action to address
the source of the boric acid in the deposits. Wolf Creek took several samples of
deposits from the base of the refueling tank. Though one sample in June 2009 did not
contain boric acid, the majority of samples, including the most recent sample from
November 2009, did contain boron, indicating that leakage from the base of the refueling
water storage tank continued to exist. The inspectors concluded that Wolf Creek had
failed to restore compliance from the noncited violation involving the failure to correct
refueling water storage tank leakage in the component design basis inspection report.
Analysis. The failure to implement corrective actions for the refueling water storage tank
leakage was a performance deficiency. Traditional enforcement does not apply since
there were no actual safety consequences or potential for impacting the NRC's
regulatory function, and the finding was not the result of any willful violation of NRC
requirements or Wolf Creek procedures. The issue was greater than minor because if
left uncorrected, the failure to correct the presence of boric acid for extended periods of
time would become a more significant-safety concern, in that, continued wastage could
impact the studs and tank operability. The finding affected the Mitigating Systems
Cornerstone, using the Phase 1 worksheets in Inspection Manual Chapter 0609.04,
"Significance Determination Process." The inspectors determined that the finding had
- 16 -
Enclosure 2
very low safety significance (Green) because it did not result in a system or component
being inoperable and it did not screen as potentially risk significant due to a seismic,
flooding, or severe weather initiating event. The inspectors identified a crosscutting
aspect in the area of human performance associated with resources. Specifically, Wolf
Creek did not maintain long-term plant safety minimizing corrective maintenance
deferrals and this long-standing equipment issue H.2(c).
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action,
requires, in part, that measures shall be established to assure that conditions adverse to
quality are promptly identified and corrected. Contrary to the above, from 1998 to
December 31, 2009, Wolf Creek did not correct the condition adverse to quality.
Specifically, Wolf Creek did not take action to correct leakage from the refueling water
storage tank. This issue and the corrective actions are being tracked in Condition
Reports 2007-02742 and 22866. Due to the licensees failure to restore compliance
from previous NCV 05000482/2007006-03 within a reasonable time after the violation
was identified, this violation is being cited as a Notice of Violation consistent with Section
VI.A of the Enforcement Policy: VIO 05000482/2009005-01, Failure to Correct
Discolored Boric Acid Deposits (EA-10-004).
.2
Control of Transient Ignition Sources
Introduction. The inspectors identified a noncited violation of Technical
Specification 5.4.1.a for an inadequate procedure for control of transient ignition sources
due to exempting the use of flapper wheels from the requirements of AP 10-101,
Control of Transient Ignition Sources.
Description. On October 21, 2009, NRC inspectors observed maintenance personnel
performing weld preparation work on essential service water piping to containment
cooler B. The inspectors observed that the ignition control barriers for the hot work were
insufficient, in that the sparks from the preparation work extended four to five feet from
the job site and there was no fire watch apparent. When the inspectors questioned the
maintenance personnel regarding the posting of a fire watch, the maintenance personnel
stated that they were using a flapper wheel and a fire watch was not required.
On December 4, 2003, the licensee modified Procedure AP-10-101, Control of
Transient Ignition Sources, such that the use of flapper wheels was exempted from the
requirements of Procedure AP10-101. The inspectors determined that the revised
procedure adversely affected the fire safety in the affected area. This was based on
recognition that the ability of the fire watch was not limited to fire identification in a timely
manner, but also on mitigation actions that an established fire watch could take in the
event of fires. These could include such actions as the ability to close doors limiting fire
exposure to adjacent areas and providing more timely fire detection capability in certain
cases. The inspectors concluded that the licensee inappropriately revised the procedure
to exempt the use of all flapper wheels without posting a fire watch. The inspectors
determined that the inadequate procedure increased the risk of fires in the plant.
Analysis. The licensee's failure to provide an adequate procedure to control transient
ignition sources was a performance deficiency and was reasonably within the ability of
- 17 -
Enclosure 2
the licensee to prevent. The inspectors concluded that this issue had a realistic
likelihood of affecting safety. Failure to properly evaluate the removal of the fire watch
posting requirements could adversely affect or degrade the ability of the licensee to
identify and report fires caused by hot work, in a timely manner. Specifically, the use of
nonconservative exemptions for requiring fire watches to be posted could affect the
ability to adequately reduce the risk of fires in the plant. This finding is more than minor
because it affected the Mitigating Systems Cornerstone attribute of Protection Against
External Factors - Fires, and adversely affected the cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. The lack of a posted fire watch could adversely
affect the ability to achieve and maintain safe shutdown in the event of a severe fire in
the affected area. Inspection Manual Chapter 0609, Appendix F, Fire Protection
Significance Determination Process, could not be used to effectively evaluate the
finding in relation to defense-in-depth strategies because it had potential effects across
multiple areas and conditions. Therefore, in accordance with Inspection Manual
Chapter 0609, Appendix M, the safety significance was determined by regional
management review and concluded that the finding was of very low safety significance
(Green) since there were no combustibles in the immediate area and fire extinguishers
were readily available. The capability of other principal defense-in-depth fire protection
features were unaffected, such as the associated fire barriers, control of transient
combustibles, manual fire suppression equipment, and the fire brigade. Additionally, the
finding was not associated with a qualification deficiency, did not result in a loss of safety
function for a system, and was not risk significance due to external initiating events.
Enforcement. Technical Specification 5.4.1.a requires, in part, that written procedures
shall be established and maintained covering the applicable procedures recommended
in Regulatory Guide 1.33, Revision 2, Appendix A, February 1972. Regulatory
Guide 1.33, "Quality Assurance Program Requirements (Operation)," Revision 2,
Appendix A, Section 1.l, requires that procedures be written for plant fire protection
program. Contrary to this requirement, from December 4, 2003, until October 21, 2009,
the licensee inappropriately exempted the use of flapper wheels from the requirements
of Procedure AP 10-101, Control of Transient Ignition Sources, reducing the fire safety
of the plant. Because this issue was determined to be of very low safety significance
(Green) and was entered into the licensees corrective action program as Condition
Report AR 00020993, this violation is being treated as a noncited violation in accordance
with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2009005-02,
Control of Transient Ignition Sources.
1R06 Flood Protection Measures (71111.06)
a.
Inspection Scope
The inspectors reviewed the USAR, the flooding analysis, and plant procedures to
assess seasonal susceptibilities involving internal flooding; reviewed the USAR and
corrective action program to determine if licensee personnel identified and corrected
flooding problems; inspected underground bunkers/manholes to verify the adequacy of
sump pumps, level alarm circuits, cable splices subject to submergence, and drainage
- 18 -
Enclosure 2
for bunkers/manholes; verified that operator actions for coping with flooding can
reasonably achieve the desired outcomes; and walked down the area listed below to
verify the adequacy of equipment seals located below the flood line, floor and wall
penetration seals, watertight door seals, common drain lines and sumps, sump pumps,
level alarms, and control circuits, and temporary or removable flood barriers. Specific
documents reviewed during this inspection are listed in the attachment.
October 6, 2009, Auxiliary feedwater rooms and sump pumps
These activities constitute completion of one flood protection measures inspection
sample as defined by Inspection Procedure IP 71111.06-05.
b.
Findings
No findings of significance were identified.
1R07 Heat Sink Performance (71111.07)
.1
Annual Inspection
a.
Inspection Scope
The inspectors reviewed licensee programs, verified performance against industry
standards, and reviewed critical operating parameters and maintenance records.
January 14, 2009, STN PE-38 on containment cooler SGN01D
The inspectors verified that performance tests were satisfactorily conducted for heat
exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the
periodic maintenance method outlined in Electric Power Research Institute
Report NP 7552, "Heat Exchanger Performance Monitoring Guidelines;" the licensee
properly utilized biofouling controls; the licensees heat exchanger inspections
adequately assessed the state of cleanliness of their tubes; and the heat exchanger was
correctly categorized under 10 CFR 50.65, Requirements for Monitoring the
Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed
during this inspection are listed in the attachment.
These activities constitute completion of one heat sink inspection sample as defined by
Inspection Procedure IP 71111.07-05.
b.
Findings
No findings of significance were identified.
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Enclosure 2
1R08 Inservice Inspection Activities (71111.08)
.1
Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water
Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control
(71111.08-02.01)
a.
Inspection Scope
The inspection procedure requires review of two or three types of nondestructive
examination activities and, if performed, one to three welds on the reactor coolant
system pressure boundary. It also requires review of one or two examinations with
relevant indications (if any were found) that have been accepted by the licensee for
continued service.
The inspectors directly observed the following nondestructive examinations:
SYSTEM
WELD IDENTIFICATION
EXAMINATION
TYPE
Feedwater System
Check Valve. Root pass indication
repair. Area 5, West Bay
Drawing WIP-M-13AE05-012-A-1
WO 08-305300-049
Charging Pump
Room B
Vent valve. 1974 foot elevation
auxiliary building, Room 1108
Drawing WIP-M-13BG02-006-A-1
WO 08-310289-043
Safety Injection
Vent Valve. Located in safety
injection pump Room A
Drawing WIP-M-13EM01-008-A-1
WO 0-310289-077
Chemical and Volume
Control System
Blowdown line coupling letdown heat
exchanger room Drawing M-13BG34
WO 06-288993-000
Feedwater System
Check valve hinge pin seal weld.
2047 foot elevation, RB C loop
Drawing WOP-M-13AE04-008-A-1
WO 08-305300-013
- 20 -
Enclosure 2
SYSTEM
WELD IDENTIFICATION
EXAMINATION
TYPE
Feedwater System
Check valve - flange to pipe weld
joint. 2026 elevation of Area 5
WO 08-305300-048 and -049
Reactor Vessel
Closure Head
ISI Number CH-101-104-B
Reactor Vessel
Closure Head
ISI Number CH-101-104-C
High Pressure Safety
Injection
HPSI pipe to elbow weld, ISI Number
EM-03-S015-B
Residual Heat
Removal
Pipe to Pipe Weld,
ISI Number EJ-04-F019
Reactor Vessel
Closure Head
Reactor vessel washer and
Bushings 19-24,
Component CH-WASH 19-24
Drawing M-189-50ISI-RBB01
WO 08-311169-014
VT - 1
Safety Injection
Vent valve. Safety injection pump
Room A
Drawing WIP-M-13EM01-008-A-01
WO 08-310289-068
VT - 1
Reactor Vessel Head
Required by 10FR50.55a, ASME
Code Case N-729-1. Also IEWA-2212
VT-2 under mirror insulation
WO 08-307175-001
VT - 2
Piping Support
In containment
Component EJ-04-H002
WO 08-311169-001
VT- 3
Piping Support
In containment.
Component EM-03-C033
WO 06-288978-001
VT- 3
- 21 -
Enclosure 2
SYSTEM
WELD IDENTIFICATION
EXAMINATION
TYPE
Piping Support
In containment.
Component BG-22-H007
WO 08-311169-011
VT- 3
During the review and observation of each examination, the inspectors verified that
activities were performed in accordance with ASME Boiler and Pressure Vessel Code
requirements and applicable procedures. During the observed nondestructive
examinations identified above, three relevant indications were identified (one dye
penetrant, one radiograph, and one boric acid leak on the control rod drive mechanism
canopy seal weld). Indications identified were dispositioned in accordance with ASME
Code and approved procedures. The two weld indications were removed and
re-examined. A control rod drive mechanism canopy seal weld clamp was installed.
There were no examinations performed where relevant indications had been accepted
by the licensee for continued service. The qualifications of all nondestructive
examination technicians performing the inspections were verified to be current.
The inspectors directly observed a portion of the following welding activities:
SYSTEM
WELD IDENTIFICATION
WELD TYPE
Pump Seal
Water
Reactor coolant pump seal
water supply line drain.
1974 foot elevation auxiliary
building, letdown heat
exchanger room.
WO 06-288993-000.
Inlay, Gas Tungsten Arc
Welding, hand welded
High Pressure
Safety Injection
System
Vent valve. 1974 foot elevation
of auxiliary building, area 1.
WO 08-310289-077
Inlay, Gas Tungsten Arc
Welding, hand welded
Chemical and
Volume Control
System
Vent valve. Reactor water
storage tank to centrifugal
charging Pump A suction check
valve. 1974 foot elevation of
auxiliary building, area 1.
WO 08-310289-007
Inlay, Gas Tungsten Arc
Welding, hand welded
- 22 -
Enclosure 2
SYSTEM
WELD IDENTIFICATION
WELD TYPE
Essential
System
Containment cooler B ESW
supply isolation valve (install
flanges on pipe for butterfly
valve). 2047 foot elevation in
containment, near Cooler B
duct. WO 07-299593-012.
Inlay, Gas Tungsten Arc
Welding, hand welded
Chemical and
Volume Control
System
Vent valve. Safety Injection
Pump Room B
Valves BG-V0842 and V0843.
1974 foot elevation of auxiliary
building, area 1.
WO 08-310289-043.
Inlay, Gas Tungsten Arc
Welding, hand welded
The inspectors verified, by review, that the welding procedure specifications and the
welders had been properly qualified in accordance with ASME Code,Section IX,
requirements. The inspectors also verified through record review that essential variables
for the welding process were identified, recorded in the procedure qualification record,
and formed the bases for qualification of the welding procedure specifications. Specific
documents reviewed during this inspection are listed in the attachment.
These actions constitute completion of the requirements for Section 02.01 of Inspection
Procedure IP 71111.08.
b.
Findings:
A finding involving control of transient ignition sources is described in Section 1RO5.2 of
this report.
.2
Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)
a.
Inspection Scope
The inspectors witnessed the licensees performance of the required visual inspection
(VT-2) of the reactor head and pressure-retaining components above the reactor
pressure vessel head in accordance with requirement of ASME Code Case N-729-1 as
mandated by 10 CFR 50.55a effective October 10, 2008. Implementation required
ASME Code IWA-2212 VT-2 under the mirror insulation on top of the reactor head
through multiple access points. The inspectors reviewed the results of this inspection for
evidence of leaks or boron deposits at reactor pressure boundaries and related
insulation above the head. Specific documents reviewed during this inspection are listed
in the attachment.
- 23 -
Enclosure 2
These actions constitute completion of the requirements for Section 02.02 of Inspection
b.
Findings
No findings of significance were identified.
.3
Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)
a.
Inspection Scope:
The inspectors evaluated the implementation of the licensees boric acid corrosion
control program for monitoring degradation of those systems that could be adversely
affected by boric acid corrosion. The inspection procedure required review of plant
areas that had recently received a boric acid walkdown by the licensee, through either
direct observation or record review. The inspectors reviewed the records associated with
the licensees most recent boric acid corrosion control walkdown, as specified in
Procedure STN PE-040D, "RCS Pressure Boundary Integrity Walkdown, Revision 3.
The inspectors directly observed some of those plant areas recently walked down by the
licensee. Additionally, the inspectors independently walked down piping and
components containing boric acid inside containment and the auxiliary building. The
inspection procedure also required verification that visual inspections emphasize
locations where boric acid leaks can cause degradation of safety-significant components.
The inspectors verified through record review that the boric acid corrosion control
inspection efforts were directed towards locations where boric acid leaks can cause
degradation of safety-related components.
The inspection procedure required review of one to three engineering evaluations
performed for boric acid found on reactor coolant system piping and components. For
those sources of boron leakage identified, the engineering evaluations gave assurance
that the ASME Code wall thickness limits were properly maintained. The inspection
procedure also required review of one to three corrective actions performed for evidence
of boric acid leaks identified. The inspectors confirmed that the work orders and
evaluations generated in response to boron leakage identification were consistent with
requirements of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI.
Specific documents reviewed during this inspection are listed in the attachment.
These actions constitute completion of the requirements for Section 02.03 of Inspection
Procedure IP 71111.08
b.
Findings
Introduction. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees
failure to identify sources of boron leakage and document them in a corrective action
document. Specifically, during a boric acid walkdown, the inspectors identified
- 24 -
Enclosure 2
11 sources of boron leakage which had not been previously identified and documented
by the licensee.
Description. On October 23, 2009, the inspectors performed a boric acid walkdown of
areas inside containment and the auxiliary building. The inspectors identified 11 sources
of leakage which had not been previously identified and documented in a corrective
action document by the licensee during the licensees boric acid walkdowns completed
on October 11, 2009. With the exception of one leak, the leaks were not active and only
had small amounts of boric acid crystals present.
The inspectors noted that those boron leakage sources which were identified during the
walkdown inside containment were described by the licensee in the completed
walkdown procedure as having no boron indication. The licensee stated that their boric
acid inspections were focused on larger amounts of boron leakage and may have been
insensitive to smaller amounts of leakage. This is contrary to station
Procedure AP 16F-001, "Boric Acid Corrosion Control Program," Revision 5, step 6.4.1,
which states that: Sources of boron seepage/leakage shall be identified/verified and
documented in the applicable corrective action document. The licensee entered the
missed leakage sources into their corrective action program and initiated a condition
report to follow up on the extent of condition of missed boron leakage sources.
Analysis. The inspectors determined that the failure to identify sources of boron leakage
was contrary to station procedures and was a performance deficiency. Specifically,
11 examples of boron leakage were not identified and documented in a corrective action
document.
The finding was determined to be more than minor in accordance with Inspection
Manual Chapter 0612, Appendix B, Issue Screening, because it was associated with
the human performance attribute of the Initiating Events Cornerstone and affected the
cornerstone objective of limiting the likelihood of those events that upset plant stability
and challenge critical safety functions during shutdown as well as power operations.
Specifically, boric acid leakage has historically been found to degrade carbon steel
components which could affect the reactor coolant system pressure boundary or impact
the reliability of emergency core cooling systems. The inspectors used Inspection
Manual Chapter 0609, Significance Determination Process, Attachment 4, Phase 1 -
Initial Screening and Characterization of Findings, and determined the finding was of
very low safety significance (Green) because the issue would not result in exceeding the
technical specification limit for identified reactor coolant system leakage or effect other
mitigating systems resulting in a total loss of their safety function. The inspectors also
determined that the finding had a crosscutting aspect in the area of problem
identification and resolution, operating experience, where the licensee did not
institutionalizes operating experience through changes to station processes, procedures,
equipment, and training programs [P.2.(b)].
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, states, in part, that Activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
- 25 -
Enclosure 2
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Licensee Procedure AP 16F-001,"Boric Acid Corrosion
Control Program," Revision 5, which prescribes activities affecting quality, states, in part,
that sources of boron seepage/leakage shall be identified/verified and documented in
the applicable corrective action document. Contrary to the above, prior to October 23,
2009, the licensee failed to accomplish the requirements of Procedure AP 16F-001.
Specifically, the licensee failed to identify 11 sources of boron leakage in the containment
structure and the auxiliary building and document them in a corrective action document.
Because this issue was determined to be of very low safety significance (Green) and
was entered into the licensees corrective action program as Condition
Report AR-00021274, this violation is being treated as a noncited violation in accordance
with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2009005-03,
Failure to Identify Sources of Boron Leakage.
.4
Steam Generator Tube Inspection Activities (71111.08-02.04)
a.
Inspection Scope:
The inspection procedure specified performance of an assessment of in situ screening
criteria to assure consistency between assumed nondestructive examination flaw sizing
accuracy and data from the EPRI examination technique specification sheets. It further
specified assessment of appropriateness of tubes selected for in situ pressure testing,
observation of in situ pressure testing, and review of in situ pressure test results.
At the time of this inspection, no conditions had been identified that warranted in situ
pressure testing. The inspectors reviewed the Licensees Report SG-CDME-08-15,
Wolf Creek Refueling 16 Condition Monitoring Assessment and Operational
Assessment, Revision 1, dated April 2008, and compared the in situ test screening
parameters to the guidelines contained in the EPRI document In Situ Pressure Test
Guidelines, Revision 2. This review determined that the remaining screening
parameters were consistent with the EPRI guidelines.
In addition, the inspectors reviewed both the licensee site-validated and qualified
acquisition and analysis technique sheets used during this refueling outage and the
qualifying EPRI examination technique specification sheets to verify that the essential
variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had
been identified and qualified through demonstration. The inspector-reviewed acquisition
technique and analysis technique sheets are identified in the attachment.
The inspection procedure specified comparing the estimated size and number of tube
flaws detected during the current outage against the previous outage operational
assessment predictions to assess the licensees prediction capability. The inspectors
compared the previous outage operational assessment predictions contained in
Report SG-CDME-08-15, Revision 1, with the flaws identified thus far during the current
steam generator tube inspection effort. Compared to the projected damage
mechanisms identified by the licensee, the number of identified indications fell within the
range of prediction and was quite consistent with predictions.
- 26 -
Enclosure 2
The inspection procedure specified confirmation that the steam generator tube test
scope and expansion criteria meet technical specification requirements, EPRI
guidelines, and commitments made to the NRC. The inspectors evaluated the
recommended steam generator tube eddy current test scope established by technical
specification requirements. The inspectors compared the recommended test scope to
the actual test scope and found that the licensee had accounted for all known flaws and
had established a test scope that met or exceeded minimum technical specification
requirements, EPRI guidelines, and commitments made to the NRC. The scope of the
licensees Eddy current examinations of tubes in both steam generators included:
100 percent, bobbin examination of tubes in steam generators A and D, full length
except for rows 1 and 2, which were inspected with the bobbin from tube end to tube
support plate 7 from both hot and cold legs
50 percent, Rows 1 and 2 U-bends, mid-range +Point examination in steam
generators A and D
Mid-range +Point examination of 100 percent of the cold leg peripheral tubes in steam
generators A and D
Dings (free span) > 5 volts: inspect 50 percent of all previously identified and new dings
>5 volts in the hot leg (including the U-bends) with the mid-range +Point probe in steam
generators A and D
Dents (structures) > 2 volts: inspect 50 percent of all previously identified and new dents
>2 volts in the hot leg (including the U-bends) with the mid-range +Point probe in steam
generators A and D
+Point examination of all "I-code" indications that were not resolved after history review
+Point inspection of new wear indications and prior wear indications that have changed
by 10 percent through-wall defect or greater in steam generators A and D
Visual inspection of mechanical and weld plugs
+Point examination of a five percent sample of bobbin indications that have not changed
since the prior inspection (H and S codes)
+Point inspection to bound (all surrounding tubes, at least one pitch removed) the tubes
exhibiting possible loose parts signals during the inspection
+Point inspection of a sample of tubes to support the scale profiling effort
The results, as known to the inspectors at the conclusion of this inspection, are as
follows:
For steam generator A, 6 tubes with wear indication of 40 percent through-wall defect or
greater at one or more anti-vibration bar intersections were plugged. Additionally, one
tube was conservatively plugged for a geometric anomaly. This tube did not exhibit any
cracking characteristic after analysis of the +Point and Ghent probe data.
- 27 -
Enclosure 2
For steam generator D, 10 tubes with wear indication of 40 percent through-wall defect
or greater at one or more anti-vibration bar intersections were plugged. Additionally, one
tube was conservatively plugged for a geometric anomaly. This tube did not exhibit any
cracking characteristic after analysis of the +Point and Ghent probe data.
The inspection procedure specified that, if new degradation mechanisms were identified,
the licensee would verify the analysis fully enveloped the problem of the extended
conditions including operating concerns and that appropriate corrective actions were
taken before plant startup. No new degradation mechanisms were identified by the
eddy current examination results.
The inspection procedure required confirmation that the licensee inspected all areas of
potential degradation, especially areas that were known to represent potential eddy
current test challenges (e.g., top of tube sheet, tube support plates, and U-bends). The
inspectors confirmed that all known areas of potential degradation were included in the
scope of inspection and were being inspected.
The inspection procedure further required verification that repair processes being used
were approved in the technical specifications. At the completion of the inspection, the
inspectors were informed that 18 tubes were to be plugged. The inspectors verified that
the mechanical expansion plugging process used was an NRC-approved repair process.
The inspection procedure also required confirmation of adherence to the technical
specification plugging limit, unless alternate repair criteria had been approved. The
inspection procedure further requires determination whether depth sizing repair criteria
were being applied for indications other than wear or axial primary water stress corrosion
cracking in dented tube support plate intersections. The inspectors determined that the
technical specification plugging limits were being adhered to (i.e., 40 percent maximum
through-wall indication).
If steam generator leakage greater than three gallons per day was identified during
operations or during post shutdown visual inspections of the tube sheet face, the
inspection procedure required verification that the licensee had identified a reasonable
cause based on inspection results and that corrective actions were taken or planned to
address the cause for the leakage. The inspectors did not conduct any assessment
because this condition did not exist.
The inspection procedure required confirmation that the eddy current test probes and
equipment were qualified for the expected types of tube degradation and an assessment
of the site-specific qualification of one or more techniques. The inspectors observed
portions of eddy current tests performed on the tubes in steam generators A and D.
During these examinations, the inspectors verified that: (1) the probes appropriate for
identifying the expected types of indications were being used, (2) probe position location
verification was performed, (3) calibration requirements were adhered to, and (4) probe
travel speed was in accordance with procedural requirements. The inspectors
performed a review of site-specific qualifications of the techniques being used. These
are identified in the attachment.
- 28 -
Enclosure 2
The inspection procedure specified that if loose parts or foreign materials were identified
on the secondary side, the inspectors should review the licensee's evaluation of the
materials and/or complete appropriate repairs of affected steam generator tubes.
Additionally, the licensee should either remove accessible foreign objects or perform an
evaluation of the potential effects of inaccessible object migration and tube fretting
damage. During this inspection, 18 small foreign objects were found in steam
generator A; of these, 7 items were retrieved. There were 34 small foreign objects found
in steam generator D; of these, 18 items were retrieved. These objects, small wires and
sludge rocks, were prioritized and retrieved based on their potential to damage the
steam generator tubes in accordance with Refuel Outage 17 Degradation Assessment
and EPRI 1019039, Steam Generator Management Program: Foreign Object
Prioritization Strategy for Square Pitch Steam Generators. Those items not removed
from the steam generators were evaluated and determined to have no ability to damage
the steam generator tubes during operation. Condition Report AR-00021178 documents
the foreign objects in the licensee's corrective action program. The required chemical
and mechanical effects of these remaining pieces were analyzed with the conclusion of
negligible effects on the respective steam generators. Work Orders 09-321481-000 and
09-321386-000 evaluated the acceptability of the steam generators with these minor
foreign objects remaining.
Finally, the inspection procedure specified review of one-to-five samples of eddy current
test data if questions arose regarding the adequacy of eddy current test data analyses.
The inspectors did not identify any results where eddy current test data analyses
adequacy was questionable.
These actions constitute completion of the requirements for Section 02.04 of Inspection
Procedure IP 71111.08.
b.
Findings
No findings of significance were identified.
.5
Identification and Resolution of Problems (71111.08-02.05)
a.
Inspection Scope
The inspection procedure required review of a sample of problems associated with
inservice inspections documented by the licensee in the corrective action program for
appropriateness of the corrective actions.
The inspectors reviewed nine condition reports which dealt with inservice inspection
activities and found the corrective actions were appropriate. The specific condition
reports reviewed are listed in the documents reviewed section. From this review, the
inspectors concluded that the licensee has an appropriate threshold for entering issues
into the corrective action program and has procedures that direct a root cause evaluation
when necessary. The licensee also has an effective program for applying industry
- 29 -
Enclosure 2
operating experience. Specific documents reviewed during this inspection are listed in
the attachment.
These actions constitute completion of the requirements for Section 02.05 of Inspection
Procedure IP 71111.08.
b.
Findings:
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
a.
Inspection Scope
There were no opportunities to inspect operator requalification in the fourth quarter.
There were zero activities completed for quarterly licensed-operator requalification as
defined in Inspection Procedure IP 71111.11.
b.
Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a.
Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant systems:
October 27, 2009, 125Vdc nonsafety-related PK system
December 17, 2009, Component cooling water system
December 18, 2009, Source range neutron monitors
October 6, 2009, Residual heat removal system
December 21, 2009, Offsite power supplies
December 22, 2009, Intermediate range neutron monitors
The inspectors reviewed 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)
- 30 -
Enclosure 2
Characterizing system reliability issues for performance
Charging unavailability for performance
Trending key parameters for condition monitoring
Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or (a)(2)
Verifying appropriate performance criteria for structures, systems, and
components classified as having an adequate demonstration of performance
through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as
requiring the establishment of appropriate and adequate goals and corrective
actions for systems classified as not having adequate performance, as described
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. Specific documents reviewed during this inspection are
listed in the attachment.
These activities constitute completion of six quarterly maintenance effectiveness
samples as defined in Inspection Procedure IP 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 licensee personnel'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:
November 20, 2009, Emergent work on control room door ventilation boundary
October 15, 2009, Corrosion on containment cooler A
October 13, 2009, Emergent work on annunciator power supply failures
October 10 to November 17, 2009, Shutdown risk assessments
November 18, 2009, Technical Specification 3.0.4.b risk assessment for Mode 4
to Mode 3
November 23, 2009, Emergent work for oil loss from centrifugal charging pump A
- 31 -
Enclosure 2
The inspectors selected these activities based on potential risk significance relative to
the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified
that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)
and that the assessments were accurate and complete. When licensee personnel
performed emergent work, the inspectors verified that the licensee personnel promptly
assessed and managed plant risk. The inspectors reviewed the scope of maintenance
work, discussed the results of the assessment with the licensee's probabilistic risk
analyst or shift technical advisor, and verified plant conditions were consistent with the
risk assessment. The inspectors also reviewed the technical specification requirements
and inspected portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of three maintenance risk assessments and
emergent work control inspection sample as defined by Inspection
Procedure IP 71111.13-05.
b.
Findings
.1
Introduction. The inspectors identified a Green noncited violation of 10 CFR 50.65(a)(4)
involving the failure to adequately perform shutdown risk assessments during Refueling
Outage 17.
Description. While reviewing daily risk assessments during Refueling Outage 17, the
inspectors noted discrepancies in the calculation of the risk conditions of the shutdown
safety function condition. As a result, the inspectors reviewed the AP 22B-001, Outage
Risk Assessment, and Form APF 22B-001-02, Daily Shutdown Risk Assessment.
Wolf Creek uses Procedure AP 22B-001, to implement the requirements of 10
CFR 50.65(a)(4) during shutdown conditions (Modes 4, 5, 6, and defueled). In the
references section, the procedure lists NUMARC 93-01, Section 11, Assessment of
Risk Resulting from Performance of Activities, as well as Regulatory Guide 1.182 in
which the NRC endorses NUMARC 93-01, Section 11, dated February 2000. Wolf
Creek has no NRC approved exceptions to Regulatory Guide 1.182. NUMARC 93-01,
Section 11.3.5, provides a scope of five key Shutdown Safety Functions: decay heat
removal capability, inventory control, electric power availability, reactivity control, and
containment. Sections 11.3.6.1 through 11.3.6.5 provide specifics for each shutdown
function. Overall, the inspectors found several examples in which the five aspects
NUMARC 93-01, Section 11, were not correctly implemented for risk assessments.
Form APF 22B-001-02 defines Condition 3 or High Risk as only one safety train is
available to satisfy the shutdown safety function. In the examples below, this
contradicted with Wolf Creeks actions.
For the Decay Heat Removal Shutdown Safety Function, Procedure APF 22B-001-02
did not direct consideration of containment closure time per NUMARC 93-01,
Section 11.3.6.1. The inspectors cross-referenced the daily shutdown risk assessment
forms with the equipment out-of-service list maintained in the control room log and found
three such instances of this occurring. First, on October 16 and 17, 2009, during the
- 32 -
Enclosure 2
core offload, the reactor building equipment hatch was listed as closed during fuel
movement; however, the equipment out-of-service list showed the equipment hatch as
open from October 10 through November 15, 2009. Secondly, from October 14-17,
2009, and again on November 5-11, 2009, the reactor building auxiliary access hatch
was on the equipment out-of-service list because the interlocks were defeated to install
a temporary closure device. The daily risk assessment did not analyze this condition
which had the potential to impact the outcome of the risk assessment. The third
instance occurred on November 16, 2009, when the reactor building personnel hatch
failed to meet the surveillance requirement acceptance criteria. This was also not
analyzed for its effect on containment closure.
For the (Electric) Power Availability Shutdown Safety Function,
Procedure APF 22B-001-02 did not explicitly direct consideration of ac and dc
instrumentation and control power availability per NUMARC 93-01, Section 11.3.6.3.
The inspectors cross-referenced the daily shutdown risk assessment forms with the
equipment out-of-service list maintained in the control room log archive and found two
such instances of this occurring. First from October 19 through 25, 2009, the 125Vdc
60-Cell Battery 4 was inoperable pending further analysis due to positive plate material
separation identified during a visual inspection. The corresponding NK04 electrical bus
was incorrectly considered available on the six daily risk assessments performed during
that time period. The second instance occurred on November 6 through 10, 2009, when
the 125Vdc 60-Cell Battery 3 inoperable pending further analysis due to several cell
abnormalities identified during a visual inspection. The corresponding NK03 electrical
bus was incorrectly considered available on the five daily risk assessments performed
during that time period. Furthermore, these dc power unavailabilities were listed on the
risk assessment, but were not factored into its outcome (or color).
For the Containment Shutdown Safety Function, Procedure APF 22B-001-02 did not
direct consideration of the availability of ventilation and radiation monitoring equipment
with respect to the filtration and monitoring of releases per NUMARC 93-01,
Section 11.3.6.5. The inspectors again cross-referenced the daily shutdown risk
assessment forms with the equipment out-of-service list maintained in the control room
log and identified two such instances of this occurring. The first instance occurred
during core offload on October 17, 2009. At that time, the availability of Containment
Atmospheric Radiation Monitor GTRE0031 was degraded because it was being powered
by temporary power. The normal source, safety bus NB02, was de-energized for
maintenance from October 17 through 25, 2009. The second instance occurred during
core reload on November 5 and 6, 2009, when the GTRE0021B was removed from
service from October 29 through November 28, 2009, per the equipment out-of-service
list. Neither of these components was listed in the daily risk assessment, nor was their
impact quantified in the determination of the risk level (or color).
For the Decay Heat Removal Shutdown Safety Function, only residual heat removal
and steam generators can actually perform the function of heat removal. The risk
assessments credited reactor cavity level greater than 23 feet above the vessel flange
and a greater than 4-hour time to boil in the decay heat removal function. Thus, this
configuration would be a permissible, moderate risk condition even if there were no
active means of removing heat from the reactor. The inspectors cross-referenced the
- 33 -
Enclosure 2
daily shutdown risk assessment forms with the equipment out-of-service list and
identified two instances of this occurring. First, on October 10, 2009 at 10:29 a.m., and
again on November 13 through 17, 2009, the risk assessments specified that steam
generators were available for heat removal when the auxiliary feedwater system was
unavailable because its safety-related water source (essential service water) was
isolated by Clearance Order C17-R-OP-S-005. Steam generators were available for
reflux cooling. Wolf Creek credits reflux cooling using EPRI Technical Report 102972,
Reflux Cooling: Application to Decay Heat Removal During Shutdown Operations.
The earliest EPRI analyzed scenario is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after shutdown; however, on
October 10, 2009, only 10.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following shutdown, the decay heat load would be
significantly higher and warrant further analysis. The inspectors concluded that since
this condition was unanalyzed, it could not be credited and a steam generator feedwater
source would be required for such a short time after reactor shutdown. The decay heat
removal Shutdown Safety Function was categorized as normal risk (green) when it
should have been moderate risk (yellow) for the two risk assessments performed on
October 10, 2009. The other risk assessments that use reflux cooling were bounded by
the EPRI analysis. Lastly, the inspectors reviewed spent fuel pool cooling on
October 30, 2009. The risk assessment form specified one train was available and
resulted in moderate risk (yellow); however, red risk was defined as one safety train
available for the function. Although not an input to the color, the form specified normal
and alternate makeup water sources to the spent fuel pool. Inspectors interviewed
senior operators to identify the normal and alternate sources. One indicated that the
refueling water storage tank through the spent fuel pool transfer pumps was the normal
source. Another indicated demineralized water was the makeup source. For the
alternate makeup source, one indicated essential service water while another stated it
was fire water. In any case, none of the sources were specified and tracked by the risk
assessment form to mitigate the loss of one fuel pool cooling train.
For the [Electric] Power Availability Shutdown Safety Function, a loss of offsite power,
or loss of both diesel generators, combined with no switchyard activities is categorized
as a low risk condition. Furthermore, a station blackout with no switchyard activities in
progress is a moderate risk condition. Inspectors found that this resulted in an
inadequate risk assessment for electrical power in that the risk assessment would permit
shutdown activities without any available sources of ac power. Wolf Creek categorized
one in-service power source as moderate risk (yellow) rather than high risk. This was in
contrast to the definition of high risk in which only one safety train available to satisfy the
function. The inspectors cross-referenced the daily shutdown risk assessment forms
with the equipment out-of-service list maintained in the control room log and found that
on November 8, 2009, at 8:57 a.m. the risk assessment listed two diesel generators as
being available; however, the equipment out-of-service list indicated that emergency
diesel generator A was out of service because essential service water train A was
unavailable from November 5, 2009, at 4:37 a.m. until November 8, 2009, at 1:30 p.m.
When the credit for emergency diesel generator A is removed, the risk assessment
outcome changes from normal risk (green) to moderate risk (yellow). The second
instance occurred for the daily risk assessment performed between October 31 and
November 4, 2009, which lists two diesel generators as being available. However, the
equipment out-of-service list indicated that emergency diesel generator B was out of
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Enclosure 2
service because essential service water Train B was unavailable from October 16, 2009,
at 10:05 p.m. until November 5, 2009, at 4:19 a.m. On all five daily risk assessments
performed between October 31 and November 4, 2009, if the credit for the second diesel
generator were removed, the outcome of the risk assessment changed from normal risk
to moderate risk.
Analysis. The failure to meet shutdown risk assessment requirements in the shutdown
risk assessment process is a performance deficiency. Traditional enforcement does not
apply since there were no actual safety consequences or potential for impacting the
NRC's regulatory function, and the finding was not the result of any willful violation of
NRC requirements or Wolf Creek procedures. The inspectors determined that this
finding impacted the Mitigating Systems Cornerstone and was more than minor because
it involved incorrect risk assessments that changed the outcome or color of the
assessments. Per Inspection Manual Chapter 0609, Appendix K, Maintenance Risk
Assessment and Risk Management Significance Determination Process, licensees who
only perform qualitative analyses of plant configuration risk due to maintenance
activities, the significance of the deficiencies must be determined by an internal NRC
management review using risk insights where possible in accordance with Inspection
Manual Chapter 612, Power Reactor Inspection Reports. The NRC management
review concluded that this finding was of Green safety significance because missing risk
management actions did not result in loss of key shutdown risk functions. Additionally,
the cause of the finding has a human performance crosscutting aspect in the area
associated with the resources. Specifically, Wolf Creek did not ensure that
Procedure APF 22B-001-02 was complete, accurate, and up-to-date H.2(c).
Enforcement. Title 10 CFR 50.65(a)(4) states, in part, that before performing
maintenance activities (including but not limited to surveillance, postmaintenance testing,
and corrective and preventive maintenance), the licensee shall assess and manage the
increase in risk that may result from the proposed maintenance activities. Contrary to
the above, between October 10, and November 17, 2009, Wolf Creek did not
appropriately assess and manage the increase in risk resulting from proposed
maintenance activities. Specifically, Form APF 22B-001-02 did not appropriately
consider electrical power, decay heat removal, and containment when assessing
shutdown risk. Because the finding is of very low safety significance and has been
entered into the corrective action program as condition reports 22295 and 22296, this
violation is being treated as a noncited violation, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000482/2009005-04, Failure to Incorporate Requirements
of Regulatory Guide 1.182 into Daily Shutdown Risk Assessments.
.2
Introduction. On November 18, 2009, the inspectors identified a Green noncited
violation of Technical Specification 3.0.4.b for ascension from Mode 4 to Mode 3 without
establishing required risk management actions.
Description. On the morning of November 18, 2009, the turbine-driven auxiliary
feedwater pump was inoperable per technical specification 3.0.4.b as specified in the
control room log at 11:53 p.m. the previous day upon ascension from Mode 4 into
Mode 3 at 12:24 a.m. Technical specification 3.0.4.b permits mode ascension after
performance of a risk assessment to address the inoperable components and
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Enclosure 2
consideration and implementation of risk management actions to maintain safety in the
next mode. This condition is permissible for auxiliary feedwater per Technical
Specification LCO 3.7.5 so long as the ascension is below Mode 1. The entry was made
using an operational risk assessment Form APF 22C-003-01 in accordance with
Technical Specification LCO 3.0.4.b. The risk assessment on November 17, 2009,
specified:
1.
The turbine-driven auxiliary feedwater pump restoration following Surveillance
Requirement 3.7.5.2, completion is expected within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of entering Mode 3.
2.
As a compensatory measure [risk management action], protected train signs
would be placed on the doors to the motor-driven auxiliary feedwater pumps A
and B room doors.
A walkdown conducted by the inspector at 10:30 a.m. on November 18, 2009, found that
the protected train signs on the motor-driven auxiliary feedwater pump rooms specified
by the operational risk assessment were not in place. Also, a maintenance crew was
performing radiography in the motor-driven auxiliary feedwater pump Room B. A further
review of the control room logs revealed that motor-driven auxiliary feedwater pump
comprehensive pump testing, flow path verification, and containment isolation valve
verification testing were scheduled and performed, making both motor-driven auxiliary
feedwater pumps A and B inoperable (at separate times) during the morning of
November 18, 2009, while turbine-driven auxiliary feedwater was still inoperable.
Operators did make proper entry into Technical Specification 3.7.5, Condition C, for two
of three auxiliary feedwater trains inoperable; however, this configuration was not
analyzed in the risk assessment. Immediately following the walkdown, the inspector
discussed the issue with the shift manager, the protected train signs were installed on
the motor-driven auxiliary feedwater pump room doors and a condition report was
initiated. Wolf Creek determined that an informal mode ascension check off list was
used that conflicted with the risk assessment performed for Technical
Specification 3.0.4.b.
Analysis. Mode ascension under Technical Specification LCO 3.0.4.b without
establishing required risk management actions is a performance deficiency. Traditional
enforcement does not apply since there were no actual safety consequences or potential
for impacting the NRC's regulatory function, and the finding was not the result of any
willful violation of NRC requirements or Wolf Creek procedures. The inspectors
determined that the violation was more than minor because it was associated with the
configuration control and alignment attribute of the Mitigating Systems Cornerstone and
affected the cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. The
configuration control issues not only included the work being completed on the
turbine-driven auxiliary feedwater pump, but also included containment isolation valve
testing and radiography that was performed on the motor-driven auxiliary feedwater
pumps which was not included in the risk assessment. The inspector used Inspection
Manual Chapter 0609.04, Phase 1 SDP - Worksheet, to determine that the finding was
of very low safety significance (Green) because it did not result in a loss of system safety
function; exceed allowable technical specification outage time; and was not a seismic,
- 36 -
Enclosure 2
flooding, or severe weather concern. Additionally, the cause of the finding has a human
performance crosscutting aspect in the area associated with the decision making.
Specifically, Wolf Creek used a risk assessment form and informal mode change form to
communicate between departments the requirement for risk management actions. The
two forms were in conflict, and the personnel who implemented the risk management
actions were not informed H.1(c).
Enforcement. Wolf Creek Technical Specification LCO 3.0.4.b states, in part, When an
LCO is not met, entry into a MODE or other specified condition in the Applicability shall
only be made after performance of a risk assessment addressing inoperable systems
and components, consideration of the results, determination of the acceptability of
entering the MODE or other specified condition in the Applicability, and establishment of
risk management actions, if appropriate. Prior to MODE ascension with the
turbine-driven auxiliary feedwater pump inoperable, Wolf Creek performed a risk
assessment and identified risk management actions. Contrary to the above, on
November 18, 2009, at 12:24 a.m. Wolf Creek invoked Technical Specification 3.0.4.b to
ascend from Mode 4 to Mode 3 without implementing the risk management actions
required by the risk assessment performed to justify the Mode change with the
turbine-driven auxiliary feedwater pump inoperable. Because the finding is of very low
safety significance and has been entered into the corrective action program as Condition
Report 00021926, this violation is being treated as a noncited violation, consistent with
Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-05, Mode
Change under Technical Specification 3.0.4.b Without Required Risk Management
Actions.
.3
Introduction. On October 15, 2009, the inspectors identified a violation of 10 CFR
Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to
follow Procedure AP 28A-100, Condition Reports. Wolf Creek failed to initiate a
condition report for evaluation of corrosion on containment cooler A piping.
Description. On October 15, 2009, the inspectors identified dried white and brown
deposits on vertical piping from insulation seams on containment cooler A. The
inspectors identified the condition to Wolf Creek. On October 17, Wolf Creek completed
Work Order 09-321113-000 to remove the insulation and found significant corrosion of
piping and flanges for containment cooler A. Work Order 09-321113-000 stated that the
cause of the corrosion was unknown. Wolf Creek informed the inspectors that the cause
of the corrosion was condensation. The inspectors noted that since no ultrasonic testing
had been performed, leakage from through-wall defects could not be eliminated as a
cause. Wolf Creek later informed the inspectors that the visual inspection showed no
through wall defects. The inspectors again challenged Wolf Creek since no ultrasonic
testing was performed to demonstrate that through wall defects could be eliminated as a
cause. The inspectors reviewed Procedure AP 28A-100, Condition Reports,
Revision 10, Attachment C. Attachment C required condition reports when equipment
issues require evaluation beyond the work controls (work order) process.
Procedure AP 28A-100 defines an adverse condition as one that could impact nuclear
safety. Wolf Creek subsequently initiated Condition Report 20964 on October 21, 2009,
stating that there was extensive corrosion on containment cooler A and that all
containment coolers could be affected. Condition Report 20964 went on to evaluate the
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Enclosure 2
piping insulation and how it did not prevent condensation on the piping which allowed
the corrosion.
On October 23 and October 26, Wolf Creek initiated several work requests to perform
ultrasonic testing of containment coolers A, B, and C. Wolf Creek initiated the work
order to perform piping and flange thickness measurements which were found to be
satisfactory. Wolf Creek engineering determined that containment coolers A, B, and C
had piping flange studs that needed to be replaced due to corrosion. From November 1
to November 2, a total of 32 studs and 96 nuts were replaced for the three coolers. On
November 8 and 11, 2009, Wolf Creek completed engineering dispositions to address
the cause and the results of the ultrasonic testing. Condition Report 22443 also
identified the need for more ultrasonic inspections in the next refueling outage to verify
acceptable corrosion rates. On December 16, 2009, Wolf Creek initiated Condition
Report 22443 which described the lack of a timely condition report to determine a cause
of the corrosion.
Analysis. The inspectors determined that the failure to follow Procedure AP 28A-100,
Appendix C, was a performance deficiency. Traditional enforcement does not apply
since there were no actual safety consequences or potential for impacting the NRCs
regulatory function, and the finding was not the result of any willful violation of NRC
requirements or Wolf Creek procedures. This issue was more than minor because it
was associated with the equipment performance attribute of the Mitigating Systems
Cornerstone and affected the cornerstone objective to ensure the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences. Using Inspection Manual Chapter 0609.04, the issue screened to Green
because there was not a loss of operability and the finding did not screen as potentially
risk significant due to a seismic, flooding, or severe weather initiating event. A
crosscutting aspect was identified in the problem identification and resolution area of the
corrective action program. Specifically, Wolf Creek failed to implement a corrective
action program with a low threshold for identifying issues P.1.a].
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, requires, in part, that activities affecting quality be described by
documented instructions, procedures or drawings appropriate to the circumstances and
be accomplished in accordance with these instructions, procedures or drawings.
Procedure AP 28A-100, Attachment C, Equipment Problems Requiring a Condition
Report, requires, in part, that condition reports be written where further evaluation is
needed outside the work control process. Contrary to the above, from October 15 to 23,
2009, Wolf Creek failed to complete an activity affecting quality in accordance with
documented procedures appropriate to the circumstances. Specifically, Wolf Creek
failed to write a condition report for corrosion on containment cooler A after Work
Order 09-321113-000 stated that the cause of the corrosion was unknown. Because this
violation was determined to be of very low safety significance and was placed in the
corrective action program as Condition Reports 20964 and 22443, this violation is being
treated as a noncited violation in accordance with Section VI.A.1 of the Enforcement
Policy: NCV 05000482/2009005-06, Failure to Follow Corrective Action Procedure.
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Enclosure 2
.4
Introduction. On November 23, 2009, a self-revealing violation of Technical
Specification 5.4.1.a was reviewed by the inspectors after a technician failed to follow
procedures and emptied 45 gallons of oil from centrifugal charging pump A.
Description. On November, 23, 2009, a technician loosened the wrong nut and removed
the thermowell for Temperature Indicator BG TI-0036 on centrifugal charging pump A. At
the time, the auxiliary lube oil pump was running. The auxiliary lube oil pump normally
runs while the pump is in standby. This emptied 45 gallons of oil from the pump.
Removal of the temperature indicator normally would not affect operability since the oil
temperature indication is not required; however, the pump cannot function without lube
oil. Control room operators declared the pump inoperable and entered Technical
Specification 3.5.2. Approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> later, the thermowell and oil were replaced,
the pump was leak tested and Technical Specification 3.5.2, Condition A was exited.
Wolf Creek performed a root cause analysis for this issue under Condition
Report 21993. During interviews, the technician stated that he performed a 2 minute
self-check (a recognized error reduction technique at Wolf Creek) but failed to identify
the correct nut to loosen. This task is a required training task for these temperature
indicators, which involves a similar training rig. The technician stated that he understood
the difference between the thermowell nut and the temperature indicator but failed to
make the differentiation on November 23. The technician and the supervisor discussed
the work, but the communication was inadequate because the technician was left with
the idea to perform the work independently, and the supervisor believed that the
technician was only going to perform a walkdown of the indicator. The prejob briefing
standard at Wolf Creek required supervisor approval for a self-briefing.
Analysis. The failure to follow Procedure STN IC-294A and correctly remove the
detector was considered a performance deficiency. Traditional enforcement does not
apply since there were no actual safety consequences or potential for impacting the
NRC's regulatory function, and the finding was not the result of any willful violation of
NRC requirements or Wolf Creek procedures. The finding was more than minor
because it was associated with the equipment performance attribute of the Mitigating
Systems Cornerstone, and it affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. The inspectors evaluated the significance of this finding
using Phase 1 of Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and
Characterization of Findings, and determined that the finding was of very low safety
significance (Green) because the pump was inoperable for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Also, the
finding did not screen as potentially risk significant due to a seismic, flooding, or severe
weather initiating event. The inspectors identified a human performance crosscutting in
the area of work practices because a 2-minute self-check and communication with the
supervisor failed to prevent the event H.4.a].
Enforcement. Technical Specification 5.4.1.a requires the implementation of written
procedures described in Regulatory Guide 1.33, Revision 2, Appendix A. Section 9.A of
Regulatory Guide 1.33 requires procedures for performing maintenance that can affect
the performance of safety-related equipment. Procedure STN IC-294A, Calibration of
CCP A Outboard Bearing and Lube Oil Supply Temperature Indicators BGTI0036
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Enclosure 2
and BGTI0040, Revision 0, step 8.2.1, requires that the temperature detector be
removed from its thermowell for calibration. Contrary to the above, on November 23,
2009, a worker removed the thermowell and breached the lube oil subsystem. Because
this violation was determined to be of very low safety significance and was placed in the
corrective action program as Condition Report 21993, this violation is being treated as a
noncited violation in accordance with Section VI.A.1 of the Enforcement Policy:
NCV 05000482/2009005-07, Failure to Follow Procedure Results in Draining of
Emergency Core Cooling System Pump Oil.
1R15 Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors reviewed the following issues:
October 9, 2009, Source range nuclear instrument (NI)-31 response
November 5, 2009, Essential service water pump seismic operability
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 technical specification 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 technical specifications and USAR 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.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of three operability evaluations inspection samples
as defined in Inspection Procedure IP 71111.15-05
b.
Findings
.1
Introduction. On November 5, 2009, the inspectors identified a Green noncited violation
of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
for failure to perform an adequate operability evaluation as required by procedure.
Description. On November 1, 2009, Wolf Creek was defueled for Refueling Outage 17,
and essential service water pump A was being replaced. On November 1, 2009, Wolf
Creek found that the as-constructed clearances at the essential service water pump A
flange did not meet design requirements. This allowed the pump column to flex up to
0.125 inches until it would engage the seismic supports. The pumps were designed to
be rigidly restrained. This resulted in Condition Reports 21400 and 21572. Wolf Creek
- 40 -
Enclosure 2
completed Operability Evaluation EF-09-010 that provided the basis for the past
operability of essential service water Pump A and future operability of essential service
water pump B on November 1, 2009, and initiated Condition Report 22400 to correct the
clearances.
On November 5, 2009, the inspectors reviewed Operability Evaluation EF-09-010. The
evaluation concluded that the increased movement of the pump would increase stresses
to 10 ksi, which was below the specified allowable ASME Code Section III limit of
17.5 ksi. The evaluation identified requirements that the pumps shall operate during and
after a safe shutdown earthquake as one of the design basis functions as required per
10 CFR Part 50, Appendix A, General Design Criterion 2. These seismic design
requirements are contained in Sections 3.9(B) and 9.2.1 of the USAR. The inspectors
found that the operability evaluations technical basis was inadequate due to the
following: (1) the evaluation did not contain a formal calculation that demonstrated that
stresses were below limits, (2) the evaluation only considered operating basis
earthquake accelerations and not the larger safe shutdown earthquake accelerations,
(3) the evaluation did not contain a calculation to demonstrate that the pump impeller
clearances were allowable if an earthquake occurred while the pump was running, and
(4) the method of analysis for the stresses was not described as an appropriate
alternative method to the original stress calculation done with the SAP V computer
program. The inspectors could not verify that the simplified method was appropriate.
The inspectors reviewed Procedure AP 26C-004, Technical Specification Operability,
Revision 20 and Procedure AP 28-001, Operability Evaluations, Revision 17.
Procedure AP 26C-004, step 6.2.6, states that documentation for prompt operability
evaluations shall include information needed to support operability. Step 4.5 states that
safety functions specified in the current licensing basis shall be met.
Procedure AP 28-001, Operability Evaluations, step 4.9, also describes that the
specified safety functions in the current licensing basis shall be met. Step 6.1.7 states
that design basis events and safety evaluations should be considered. There is no
description of the use of alternative analysis methods in AP 28-001 or AP 26C-004 that
is consistent with Regulatory Information Summary 2005-20, Section C.4.
On November 7, 2009, Wolf Creek initiated Condition Report 21572 to resolve the items
identified above. Wolf Creek completed Operability Evaluation EF-09-010, Revision 1,
on December 14, 2009. The inspectors reviewed Revision 1 and determined the above
identified deficiencies still existed. Wolf Creek performed a third revision to Operability
Evaluation EF-09-010 and initiated Condition Report 22798. The four items were
resolved with Operability Evaluation EF-09-010, Revision 2 which contained drawings
and calculations to demonstrate that the pumps were seismically qualified and that the
simplified calculations were appropriate. In Revision 2, the calculated stresses
increased to 16.4 ksi but were still below the limit of 17.5 ksi.
Analysis. The failure to perform an adequate operability evaluation per
Procedures AP 28-001 and AP 26C-004, was a performance deficiency. Traditional
enforcement does not apply since there were no actual safety consequences or potential
for impacting the NRC's regulatory function, and the finding was not the result of any
willful violation of NRC requirements or Wolf Creek procedures. The inspectors
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Enclosure 2
determined that this finding was more than minor because it is associated with the
equipment performance attribute for the Mitigating Systems Cornerstone, and it affected
the cornerstone objective to ensure the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences (i.e., core
damage). Specifically, this issue relates to the availability and reliability examples of the
equipment performance attribute because a latent common mode failure mechanism
was not correctly evaluated. The inspectors evaluated the significance of this finding
using Phase 1 of Inspection Manual Chapter 0609, Appendix A, "Significance
Determination of Reactor Inspection Findings for At Power Situations," and determined
that the finding was of very low safety significance (Green) because the issue was not a
design or qualification deficiency confirmed to result in loss of operability or functionality,
did not represent a loss of system safety function, an actual loss of safety function of a
single train for greater than its technical specification allowed outage time, an actual loss
of safety function of a nontechnical specification risk-significant equipment train, and did
not screen as potentially risk significant due to a seismic, flooding, or severe weather
initiating event. The cause of the finding has a problem identification and resolution
crosscutting aspect in the area associated with the corrective action program because
Wolf Creek failed to thoroughly evaluate the failure mechanism such that the resolutions
address the causes and extent of conditions, as necessary P.1.c].
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions or procedures of a type appropriate to the circumstances,
accomplished in accordance with those instructions or procedures, and contain
acceptance criteria to demonstrate that the activity was successfully accomplished.
Procedure AP 26C-004, Technical Specification Operability, Revision 20, implements
this requirement and states, in part, that continued operability decisions shall be made in
accordance with Procedure AP 28-001, Operability Evaluations, Revision 17.
Procedure AP 28-001 requires, in part, that operability evaluations shall demonstrate
that equipment meets its design functions. Per Sections 3.9(B) and 9.2.1 of the USAR,
the essential service water pumps are designed to withstand a safe shutdown
earthquake. Contrary to the above, from November 1, 2009, to January 13, 2010,
Operability Evaluation EF-09-010, Revisions 0 and 1, did not demonstrate that the
essential service water pumps could withstand a safe shutdown earthquake.
Specifically, no calculations existed to demonstrate allowable stresses and pump
impeller clearances. Because the finding is of very low safety significance and has been
entered into the corrective action program as Condition Reports 22798 and 21572, this
violation is being treated as a noncited violation, consistent with Section VI.A of the
NRC Enforcement Policy: NCV 05000482/2009005-08, Inadequate Operability
Evaluation of Essential Service Water Pumps.
.2
Introduction. The inspectors identified a Green, noncited violation of Technical
Specification 3.3.1, Condition I, for making positive reactivity addition prohibited by
technical specifications in Mode 2 because one source range nuclear instrument
channel was inoperable.
Description. On August 19, 2009, at 3:47 p.m., a loss of offsite power and reactor trip
occurred. As a result, cavity cooling fans were lost causing an increase in air
- 42 -
Enclosure 2
temperature in the reactor cavity. Shortly thereafter, the indicated count rate on source
range nuclear instrument NI-31 began increasing from the expected value of about 250
counts per minute (cpm) to 15,000 cpm and then to a maximum of 27,000 cpm over an
8-hour period. Control room operators declared the source range channel NI-31
inoperable as a result of this abnormal behavior. Power to the cavity fans was restored
around 1 a.m. on August 20, 2009, and the source range nuclear instrument NI-31 count
rate returned to its expected value below 250 cpm, based on its anticipated reading
relative to source range NI-32 which did not experience any increase in count rate with a
loss of cavity cooling.
Wolf Creek concluded, based on feedback from the vendor, the most likely cause of the
abnormal readings was moisture intrusion at the cable to detector connection at the
base of the detector inside the reactor cavity. As long as cavity cooling remained
available, the moisture intrusion would not be an issue. Based on this information, Wolf
Creek declared the source range NI-31 operable restarted from the forced outage on
August 23, 2009. Wolf Creeks operability evaluation failed to identify that safety-related
equipment was now reliant on nonsafety cavity cooling fans and nonsafety electrical
power to those fans. The source range instruments NI-31 and -32 are required to be
operable in Mode 2 below the P-6 interlock to monitor the approach to criticality.
During this time, the resident inspectors questioned the operability of source range
instrument NI-31. When entering Refueling Outage 17, a power supply failure in the
control cabinet caused source range NI-31 to fail upon demand during shutdown. On
October 7, 2009, Wolf Creek performed another operability evaluation that stated that
the source range was operable because it had passed its surveillance tests during the
last refueling outage that ended in May 2008. The inspectors noted that this evaluation
did not address the observed problem and therefore did not provide a reasonable basis
for operability. On October 28, 2009, during interviews with Wolf Creek engineering
personnel, the inspectors learned that the original operability determination used to
restart from the forced outage was inaccurate because the equipment configuration in
the field was different than described in the operability determination. The detectors are
in fact hard wired and there are no cabling connections until the containment bio-shield
wall, therefore, no connectors would be affected by the reactor cavity temperature
increase following the loss of cavity cooling fans. Consequently, there was no valid
explanation for the increase in count rate observed on August 19, 2009. Shortly
thereafter, Wolf Creek replaced the source range NI-31 detector before restart from
Refueling Outage 17 to definitively restore operability to the channel.
On November 13, 2009, the resident inspectors observed the removal of source range
Detector SE-0031 from the reactor cavity. There was some minor damage to the outer
layer of cable wrap, however, nothing was observed that could conclusively explain the
detectors malfunction on August 19, 2009, or ensure its future operability. Wolf Creek
USAR, Chapter 15, credits low power reactor trips as being terminated by the power
range instruments. The power range instruments are not required to be operable in
Mode 3. USAR, Chapter 15, credits the source range and intermediate range reactor
trips to stop reactivity excursions at a much lower power. This allows technical
specifications to credit these trips in Mode 3. During the shutdown in August 2009, rod
drive motor-generator set testing was performed which cycled the reactor trip breakers
- 43 -
Enclosure 2
and made the control rods capable of withdrawal. The inspectors also reviewed the
technical specification bases for the source range which stated that they are required to
perform a monitoring function of neutron levels and provide indication of reactivity
changes that may occur.
Analysis. Reactivity addition with source range channel nuclear instrument-31
inoperable is a performance deficiency. The finding was more than minor because it
was associated with the configuration control (reactivity control) attribute of the Barrier
Integrity Cornerstone, and it affected the cornerstone objective to provide reasonable
assurance that physical design barriers (fuel cladding, reactor coolant system, and
containment) protect the public from radionuclide releases caused by accidents or
events. The inspectors evaluated the significance of this finding using Phase 1 of
Inspection Manual Chapter 0609.04, and determined that the finding screened to Green
because the finding only affected the fuel barrier. Additionally, the cause of the finding
has a human performance crosscutting aspect in the area associated with the decision
making. Specifically, Wolf Creek did not use conservative assumptions in decision
making and adopt requirements to demonstrate that the proposed action is safe in order
to proceed rather than a requirement to demonstrate that it is unsafe in order to
disapprove the action, when performing an operability evaluation for the source range
Nuclear Instrument 31 detector prior to restarting from a forced outage H.1(b).
Enforcement. Wolf Creek Technical Specification LCO 3.3.1 Reactor Trip System
Instrumentation, Condition I, requires immediate suspension of all operations activities
involving positive reactivity additions when one source range channel is inoperable while
in Mode 2. Contrary to the above on August 22, 2009, at 11:10 a.m., Wolf Creek
entered Mode 2 with one source range channel inoperable and continued withdrawing
control rods until the reactor was critical at 11:54 a.m. At that time, Wolf Creek went
above the P-6 interlock and source range monitoring was no longer required by technical
specifications. Because the finding is of very low safety significance and has been
entered into the corrective action program as Condition Report 20208, this violation is
being treated as a noncited violation, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000482/2009005-09, Positive Reactivity Addition
Prohibited by technical specifications while in Mode 2.
1R18 Plant Modifications (71111.18)
Permanent Modifications
The inspectors reviewed key affected parameters associated with energy needs,
materials, replacement components, timing, heat removal, control signals, equipment
protection from hazards, operations, flow paths, pressure boundary, ventilation
boundary, structural, process medium properties, licensing basis, and failure modes for
the permanent modifications listed below.
December 16, 2009, Instrument setpoints for reactor coolant pump thermal
barrier isolation and Valve EGHV62
- 44 -
Enclosure 2
The inspectors reviewed key parameters associated with energy needs, materials,
replacement components, timing, heat removal, control signals, equipment protection
from hazards, operations, flow paths, pressure boundary, ventilation boundary,
structural, process medium properties, licensing basis, and failure modes for the
permanent modification identified as configuration Change Package 013096.
The inspectors verified that modification preparation, staging, and implementation did not
impair emergency/abnormal operating procedure actions, key safety functions, or
operator response to loss of key safety functions; postmodification testing will maintain
the plant in a safe configuration during testing by verifying that unintended system
interactions will not occur; systems, structures and components, performance
characteristics still meet the design basis; the modification design assumptions were
appropriate; the modification test acceptance criteria will be met; and licensee personnel
identified and implemented appropriate corrective actions associated with permanent
plant modifications. Specific documents reviewed during this inspection are listed in the
attachment.
These activities constitute completion of one sample for permanent plant modifications
as defined in Inspection Procedure IP 71111.18-05.
b.
Findings
Introduction. On December 16, 2009, inspectors identified a Green noncited violation of
10 CFR Part 50, Appendix B, Criterion III, Design Control, involving failure to obtain
vendor design data for a modification.
Description. On December 16, 2009, the inspectors reviewed configuration change
Package 013096 from August 2009 which modified the upper flow limit through the
reactor coolant pump thermal barrier heat exchangers from 60 to 68 gpm. The change
package cited an internal memo from 1992 as the justification for the increased flow.
The inspectors reviewed the internal memo and noted that it described the thermal
barrier outlet valves going closed on high flow. It also indirectly described a telephone
conversation with a Westinghouse representative who stated that the thermal barriers
were capable of up to 90 gpm sustained flow. The inspectors found no accompanying
data from Westinghouse to justify this claim. Procedure AP 05-005, Design Control,
required that vendor data be obtained in accordance with Procedure AP 05-013, Review
of Vendor Technical Documents, Revision 7A. The inspectors reviewed
Procedure AP 05-013 and noted that it stated that documentation would be obtained
from the vendor consistent with procurement standards for acceptance.
Procedure AP 05-013, step 6.5, specified evaluation of vendor technical documentation,
but it did not specify how to disposition informal information. This step required a review
of vendor documentation by engineering to ensure design requirements are met.
Procedure AP 05-013, step 6.6, specified incorporating changes to vendor documents
that originate with Wolf Creek, but it did not specify that the vendor must be contacted for
changes that Wolf Creek has not evaluated.
Procedure AP 05-002, Dispositions and Change Packages, Revision 8, specified how
Wolf Creek prepares, documents, and implements modifications to plant equipment and
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Enclosure 2
design documents. Procedure AP 05-002, step 6.4.5, required that the data be obtained
from the vendor and placed in the modification package supporting the plant change.
Procedure AP 05-002, step 6.4.6.6, did not allow informal communications to form the
basis for a modification. Telephone calls are defined as informal communication per
Procedure AP 05-005. The inspectors found no documentation to show validation of the
verbal data provided by the vendor. This modification was a corrective action to
VIO 05000482/2009002-07 (EA-09-110). This notice of violation will remain open until
full compliance has been restored. Wolf Creek subsequently consulted with
Westinghouse to confirm the acceptability of the increased flow rate, and requested a
formal calculation. This issue is captured in Condition Report 22824.
Analysis. The inspectors found that the failure to follow procedure for the modification
was a performance deficiency. Traditional enforcement does not apply since there were
no actual safety consequences or potential for impacting the NRC's regulatory function,
and the finding was not the result of any willful violation of NRC requirements or Wolf
Creek procedures. The inspectors determined that this finding was more than minor
because this issue aligned with Inspection Manual Chapter 0612, Appendix E,
example 2.f, in that the modification relied on verbal statements to raise the allowable
flow through the heat exchanger. This is a significant deficiency in the modification
package. The inspectors determined this finding was associated with the design control
attribute of the Initiating Events Cornerstone and affected the cornerstone objective to
limit the likelihood of events that upset plant stability and challenge critical safety
functions. The inspectors evaluated the significance of this finding using Phase 1 of
Inspection Manual Chapter 0609.04 and determined that the finding was of very low
safety significance because assuming worst case degradation, the finding would not
result in exceeding the technical specification limit for identified reactor coolant system
leakage and would not have likely affected other mitigation systems resulting in a total
loss of their safety function because seal injection was available. This finding has a
crosscutting aspect in the area of human performance associated with work practices in
that management was unsuccessful in communicating expectations on procedure use
and adherence in engineering H.4.b].
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control," requires,
in part, that the licensee establish measures for the identification and control of design
interfaces and for coordination among participating design organizations. These
measures shall include the establishment of procedures among participating design
organizations for the review, approval, release, distribution, and revision of documents
involving design interfaces. It also requires, in part, that design changes shall be subject
to design control measures commensurate with those applied to the original design.
Procedures AP 05-005 and AP 05-002 implement this requirement by requiring formal
vendor data required for modifications to be incorporated into modifications. Contrary to
the above, from August 13, 2009, to December 31, 2009, Wolf Creek failed to obtain
vendor design data for configuration change Package 013096 in accordance with
Procedures AP 05-005 and AP 05-002. Because the finding is of very low safety
significance and has been entered into the corrective action program as Condition
Report 22824, this violation is being treated as a noncited violation, consistent with
Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-10, Failure to
Obtain Vendor Data Necessary for Plant Modification.
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Enclosure 2
1R19 Postmaintenance Testing (71111.19)
a.
Inspection Scope
The inspectors reviewed the following postmaintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
October 23, 2009, Emergency diesel generator A run after replacement of speed
switch
October 23, 2009, Instrumentation and control testing of emergency diesel
generator A instrument power supply
November 6, 2009, Essential service water train B pump and motor replacement
November 2, 2009, Motor-operated valve MOV 8811A after actuator and internals
replacement
The inspectors selected these activities based upon the structure, system, or
component's ability to affect 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
The inspectors evaluated the activities against the technical specifications, the USAR,
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 corrective action
program and that the problems were being corrected commensurate with their
importance to safety. Specific documents reviewed during this inspection are listed in
the attachment.
These activities constitute completion of four postmaintenance testing inspection
samples as defined in Inspection Procedure IP 71111.19-05.
b.
Findings
No findings of significance were identified.
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Enclosure 2
1R20 Refueling and Other Outage Activities (71111.20)
a.
Inspection Scope
The inspectors reviewed the outage safety plan and contingency plans for the Wolf
Creek refueling outage, conducted from October 10 to November 17 2009, to confirm
that licensee personnel had appropriately considered risk, industry experience, and
previous site-specific problems in developing and implementing a plan that assured
maintenance of defense in depth. During the refueling outage, the inspectors observed
portions of the shutdown and cooldown processes and monitored licensee controls over
the outage activities listed below.
Configuration management, including maintenance of defense in depth, is
commensurate with the outage safety plan for key safety functions and
compliance with the applicable technical specifications when taking equipment
out of service.
Clearance activities, including confirmation that tags were properly hung and
equipment appropriately configured to safely support the work or testing.
Installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indication, accounting for instrument error.
Status and configuration of electrical systems to ensure that technical
specifications and outage safety-plan requirements were met, and controls over
switchyard activities.
Monitoring of decay heat removal processes, systems, and components.
Verification that outage work was not impacting the ability of the operators to
operate the spent fuel pool cooling system.
Reactor water inventory controls, including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss.
Controls over activities that could affect reactivity.
Maintenance of secondary containment as required by the technical
specifications.
Refueling activities, including fuel handling and sipping to detect fuel assembly
leakage.
Startup and ascension to full power operation, tracking of startup prerequisites,
walkdown of the drywell (primary containment) to verify that debris had not been
left which could block emergency core cooling system suction strainers, and
reactor physics testing.
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Enclosure 2
Licensee identification and resolution of problems related to refueling outage
activities.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one refueling outage and other outage
inspection sample as defined in Inspection Procedure IP 71111.20-05.
b.
Findings
.1
Introduction. The inspectors identified a Green cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, for failure to correct a previous violation for an
inadequate vent path for the reactor vessel head.
Description. NRC Inspection Report 05000482/2008004 documented a Green noncited
violation of 10 CFR Part 50, Criterion III, Design Control, associated with the formation
of voids in the reactor vessel head during refueling outages.
During Refueling Outage 17 on October 13, 2009, Wolf Creek depressurized the reactor
and drained the reactor coolant system via the pressurizer to a level 374 inches above
the bottom of the hot leg. Reactor coolant system pressure was established at
atmospheric pressure, approximately 6-10 psig below the volume control tank pressure.
These actions were performed in accordance with plant operating
Procedure SYS BB-215, RCS Drain Down with Fuel in Reactor. The operators
completed Sections 6.1 and 6.2 of the procedure to vent the reactor vessel head to the
pressurizer and purge the pressurizer with nitrogen.
Control room operators subsequently initiated Condition Reports 20648 and 20633 to
identify anomalous readings in pressurizer and reactor vessel level. The inspectors
reviewed plant computer data from October 11 to 14, 2009, and confirmed that a void
had formed in the reactor vessel head region following reactor coolant system
depressurization. As the gas built up, it forced primary coolant out of the reactor vessel
and into the pressurizer over many hours, causing the observed level changes.
Following the previous refueling outage, Wolf Creek Mode 5 Procedure GEN 00-009 had
been changed to require reactor vessel level instrumentation system to be in service so
that control room operators could observe any decrease in reactor vessel level. Based
on plant computer data, the observed change of approximately 41 inches in pressurizer
level equated to a maximum void size of 1100 gallons of primary coolant in the reactor
vessel. Excluding the void, time to boil in the reactor coolant system was calculated to
be 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> during outage planning.
Following the formation of a similar void in Refueling Outage 16, Wolf Creek initiated a
root cause evaluation during under Condition Report 2008-001032. The void size during
Refueling Outage 16 was 2600 gallons. Wolf Creek determined that the root cause was
a loop seal or blockage in the piping. The root cause described boron precipitation as a
possible source of the blockage. Corrective actions were subsequently planned for
Refueling Outage 17. The slope of the vessel head piping was verified to be correct to
ensure no loop seals was performed as a corrective action to prevent recurrence.
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Enclosure 2
However, after the piping slope was verified and loop seals ruled out as a possible
cause, no additional actions were taken to identify the cause of the inadequate vent. A
corrective action to perform an internal inspection of the vessel head was not performed
because Wolf Creek did not have tools to inspect around 90 bends in the piping. The
inspectors determined that Wolf Creek failed to identify the cause of the inadequate vent
path to relieve gases to the pressurizer, with the result that voiding would continue to be
a concern in the next refueling outage.
When the NRC issued NCV 05000482/2008004-07 on November 7, 2008, for the
reactor vessel head voiding during outages, corrective actions were tracked under
Condition Report 2008-001032. The inspectors concluded that Wolf Creek has yet to
correct the inadequate vent path, allowing void formation to continue to occur in the
reactor vessel head. Without an adequate vent from the top of the reactor vessel head
to the pressurizer, noncondensable gas voids will form, decreasing reactor coolant
inventory and reducing the time to core boiling following a loss of shutdown cooling. The
gas voids could grow to the top of the hot legs or until the driving head forces the void
past the blockage and into the gas space of the pressurizer, causing the plant to
inadvertently enter mid-loop operations. An adequate vent path is necessary to control
reactor coolant level. Wolf Creek has initiated a second root cause under Condition
Report 22501.
Analysis. The inspectors determined that failure to provide an adequate vessel head
vent path to prevent gas accumulation in the reactor vessel during depressurized plant
operations was a performance deficiency. The inspectors determined that this finding
was associated with the design control attribute of the Initiating Events Cornerstone.
Specifically, the voiding reduces time to boil and impacted the cornerstone objective to
limit the likelihood of those events that upset plant stability and challenge critical safety
functions during shutdown as well as power operations. The inspectors evaluated the
significance of this finding using Inspection Manual Chapter 0609, Appendix G,
Attachment 1, Shutdown Operations Significance Determination Process Phase 1
Operational Checklists for Both PWRs and BWRs. The inspectors determined that
Checklist 3 was applicable because the unit was in cold shutdown with the refueling
cavity level less than 23 feet. Based upon Appendix G, Attachment 1, Checklist 3,
Phase 2, analysis was not needed to characterize the risk significance of this finding
because the level of loss was less than two feet, did not occur during reduced inventory,
and appropriate action was taken regarding the level deviation. The finding was
determined to be of very low safety significance based upon the demonstrated
availability of mitigation systems and the reactor coolant system cavity inventory. The
inspectors determined the cause of the finding had a problem identification and
resolution aspect in the corrective action program. Specifically, Wolf Creeks corrective
actions were not successful to address the vent path blockage in a timely manner
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires,
in part, that the design basis is correctly translated into specifications, drawings, and
procedures. The design basis of the reactor vessel head vent is to allow
noncondensable gases to escape to the pressurizer during shutdown conditions.
Contrary to the above, from December 2, 2003, to December 31, 2009, Wolf Creek
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Enclosure 2
failed to ensure the design basis of the reactor vessel head vent was correctly translated
into specifications, drawings, and procedures. Specifically, Wolf Creek designed and
installed a reactor vessel head permanent vent piping modification which failed to vent
noncondensable gases to the pressurizer during shutdown operations. This resulted in
the formation of voids in the reactor vessel head while the plant was shutdown and
depressurized in successive refueling outages. This issue and the corrective actions are
being tracked by the licensee in Condition Reports 22501, 20648, 20568, and 20633.
Due to the licensees failure to restore compliance from previous
NCV 05000482/2008004-07 within a reasonable time after the violation was identified,
this violation is being cited as a Notice of Violation consistent with Section VI.A of the
Enforcement Policy: VIO 05000482/2009005-11, Failure to Correct Vessel Head Vent
Path (EA-10-020).
.2
Introduction. The inspectors identified a Green noncited violation of Technical
Specification 5.4.1.a for failure to properly implement Procedure AP 14A-003, Scaffold
Construction and Use, when scaffolding was erected against operable safety-related
equipment.
Description. On October 15, 2009, the inspectors identified scaffolding in contact with
component cooling water piping inside containment. The piping was the containment
loop which did not have any required cooling loads, but was part of an operating
component cooling water train that was cooling the core. At the time, reactor coolant
system level was below the vessel flange. The tag on the scaffold explicitly stated that it
was not seismically qualified. The inspectors discussed the issue with the shift manager
who immediately had the scaffold moved. Both steam generators were inoperable and
both trains of residual heat removal were required to be operable. The inspectors
reviewed the bases for Technical Specification 3.4.7, RCS Loops - Mode 5, Loops
Filled, which required an operable heat sink path from residual heat removal to
component cooling water to essential service water.
Procedure AP 14A-003, Scaffold Construction and Use, step 6.4.15, required
scaffolding to be two inches away from equipment. Attachment F of this procedure
specifies the requirements for seismically qualified scaffolds. The scaffold form stated
that the scaffolding was required to be removed prior to Mode 4, which was incorrect
because it allowed nonseismically qualified scaffold to be installed in the zone of
influence of operable equipment since seismic qualification is still required for equipment
required to be operable in Modes 5 and 6. This issue was entered into the corrective
action program as Condition Report 22464.
Analysis. The construction of an unqualified scaffold against operable component
cooling water piping was a performance deficiency. Traditional enforcement does not
apply since there were no actual safety consequences or potential for impacting the
NRC's regulatory function, and the finding was not the result of any willful violation of
NRC requirements or Wolf Creek procedures. The inspectors determined that this
finding was more than minor because it is associated with the equipment performance
attribute for the Mitigating Systems Cornerstone, and it affected the cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences (i.e., core damage). Specifically,
- 51 -
Enclosure 2
this issue relates to the availability and reliability examples of the equipment
performance attribute because a latent failure mechanism was not evaluated. The
inspectors evaluated the significance of this finding using Inspection Manual
Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance
Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs. The
inspectors determined that Checklist 3 was applicable because the unit was in cold
shutdown with the refueling cavity level less than 23 feet. Using Appendix G,
Attachment 1, Checklist 3, Phase 2 analysis was not needed and the finding was of very
low safety significance (Green) because the licensee was able to demonstrate that the
seismically unqualified scaffolding would not have resulted in a loss of safety function.
The inspectors determined the cause of the finding had a human performance aspect in
the area of resources. Specifically, Procedure AP 14A-003 was inadequate because it
had conflicting guidance that allowed seismically unqualified scaffolds in Modes 5 and 6
H.2.c].
Enforcement. Technical Specification 5.4.1.a requires that procedures be established,
implemented and maintained as recommended in Regulatory Guide 1.33, Appendix A.
Section 9.a of Appendix A, requires, in part, that maintenance affecting safety-related
equipment be accomplished in accordance with procedures. Procedure AP 14A-003
Scaffold Construction and Use, Revision 16, step 6.4.15 required two inches of
clearance from safety-related structures. Contrary to the above, from October 14 to 15,
2009, the licensee did not provide two inches of clearance between scaffolding and
safety-related structures. Specifically, component cooling water Train B was in contact
with a seismically unqualified scaffold while component cooling water was required to be
operable. Because the finding is of very low safety significance and has been entered
into the corrective action program as Condition Report 22464, this violation is being
treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement
Policy: NCV 05000482/2009005-12, Unevaluated Scaffold Against Component Cooling
Water Piping.
1R22 Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors reviewed the USAR, procedure requirements, and technical
specifications to ensure that the seven surveillance activities listed below demonstrated
that the systems, structures, and/or components tested were capable of performing their
intended safety functions. The inspectors either witnessed or reviewed test data to verify
that the significant surveillance test attributes were adequate to address the following:
Preconditioning
Evaluation of testing impact on the plant
Acceptance criteria
Test equipment
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Enclosure 2
Procedures
Jumper/lifted lead controls
Test data
Testing frequency and method demonstrated technical specification operability
Test equipment removal
Restoration of plant systems
Fulfillment of ASME Code requirements
Updating of performance indicator data
Engineering evaluations, root causes, and bases for returning tested systems,
structures, and components not meeting the test acceptance criteria were correct
Reference setting data
Annunciators and alarms setpoints
The inspectors also verified that licensee personnel identified and implemented any
needed corrective actions associated with the surveillance testing.
October 28, 2009, MOV 8811A as-found inservice surveillance test
August 10, 2009, STS IC-250B, Channel operational test containment
atmosphere and reactor coolant system leak rate radiation Monitor GT RE-0031
November 5, 2009, STS PE-139, Local leak rate test of Penetration 39,
BB HV-351C
September 17, 2009, Train A auxiliary feedwater inservice testing of
Valves ALV0002 and ALV0009
November 3, 2009, Essential service water Train B leak test of underground pipe
September 28, 2009, Emergency Diesel Generator A, 24-hour endurance run
October 15, 2009, Emergency Diesel Panel KJ-122/123 safety to nonsafety fuse
inspections
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of seven surveillance testing inspection samples
as defined in Inspection Procedure IP 71111.22-05.
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Enclosure 2
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational and Public Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
a.
Inspection Scope
This area was inspected to assess licensee personnels performance in implementing
physical and administrative controls for airborne radioactivity areas, radiation areas, high
radiation areas, and worker adherence to these controls. The inspectors used the
requirements in 10 CFR Part 20, the technical specifications, and the licensees
procedures required by technical specifications as criteria for determining compliance.
During the inspection, the inspectors interviewed the radiation protection manager,
radiation protection supervisors, and radiation workers. The inspectors performed
independent radiation dose rate measurements and reviewed the following items:
Performance indicator events and associated documentation packages reported
by the licensee in the Occupational Radiation Safety Cornerstone
Controls (surveys, posting, and barricades) of radiation, high radiation, or
airborne radioactivity areas
Radiation work permits, procedures, engineering controls, and air sampler
locations
Conformity of electronic personal dosimeter alarm set points with survey
indications and plant policy; workers knowledge of required actions when their
electronic personnel dosimeter noticeably malfunctions or alarms
Barrier integrity and performance of engineering controls in airborne radioactivity
areas
Physical and programmatic controls for highly activated or contaminated
materials (nonfuel) stored within spent fuel and other storage pools
Self-assessments, audits, licensee event reports, and special reports related to
the access control program since the last inspection
Corrective action documents related to access controls
Licensee actions in cases of repetitive deficiencies or significant individual
deficiencies
- 54 -
Enclosure 2
Radiation work permit briefings and worker instructions
Adequacy of radiological controls, such as required surveys, radiation protection
job coverage, and contamination control during job performance
Dosimetry placement in high radiation work areas with significant dose rate
gradients
Changes in licensee procedural controls of high dose rate - high radiation areas
and very high radiation areas
Controls for special areas that have the potential to become very high radiation
areas during certain plant operations
Posting and locking of entrances to all accessible high dose rate - high radiation
areas and very high radiation areas
Radiation worker and radiation protection technician performance with respect to
radiation protection work requirements
Either because the conditions did not exist or an event had not occurred, no
opportunities were available to review the following items:
Adequacy of the licensees internal dose assessment for any actual internal
exposure greater than 50 millirem committed effective dose equivalent
These activities constitute completion of 21 of the required 21 samples as defined in
Inspection Procedure IP 71121.01-05.
b.
Findings
.1
Introduction. The inspector identified a Green noncited violation of
Technical Specification 5.7.2.a.1 for failure to maintain administrative control of door
and gate keys to high radiation areas with dose rates greater than 1 rem per hour but
less than 500 rads per hour (referred to as locked high radiation areas).
Description. During a review of the licensees program for administrative control of
keys to doors and gates to locked high radiation areas and very high radiation areas, the
inspector found that the health physics department had a master key to locked high
radiation areas. This key was not controlled in accordance with licensee
Procedure AP 25A-200, Access to Locked High or Very High Radiation Areas,
Revision 20, which stated that site security was responsible for issuing locked high
radiation area and very high radiation area keys. In accordance with technical
specifications, health physics management designated the site security department to
administratively (and procedurally) control the keys. Although site security was
effectively meeting the procedure requirement for issuing all other locked and very high
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Enclosure 2
radiation area keys, site security was unaware that the health physics department had
the only master key to locked high radiation areas at the site. By procedure, site security
administratively controlled the other keys (to locked and very high radiation areas) by
maintaining an inventory of them, performing physical inventories of the keys each shift,
and labeling the keys. None of these administrative controls were implemented for the
master key in the health physics department. The licensee immediately documented the
deficiency in a condition report and implemented temporary administrative controls until
a permanent disposition for the master key had been identified.
Analysis. Failure to maintain administrative control of the master key to locked high
radiation areas was a performance deficiency. This finding is greater than minor because if
left uncorrected the finding has the potential to lead to a more significant safety concern in
that an individual could receive unanticipated radiation dose by gaining access a locked high
radiation area without the proper controls and briefing. This finding was evaluated using
Inspection Manual Chapter 0609, Significance Determination Process, Appendix C,
Occupational Radiation Safety Significance Determination Process, and was determined to
be of very low safety significance because it did not involve: (1) an as low as is reasonably
achievable (ALARA) planning or work control issue, (2) an overexposure, (3) a substantial
potential for overexposure, or (4) an impaired ability to assess dose. Additionally, the
violation has a crosscutting aspect in the area of human performance associated with the
work practices component because the lack of peer and self-checking resulted in
inadequate control of keys to locked high radiation areas H.4(a).
Enforcement. Technical Specification 5.7.2.a.1 requires, in part, that each entryway to a
high radiation area with dose rates greater than 1.0 rem per hour but less than 500 rads
per hour shall be provided with a locked or continuously guarded door or gate that
prevents unauthorized entry and all keys shall be maintained under the administrative
control of the shift manager/control room supervisor, health physics supervision, or
his/her designee. Contrary to the above, as of October 21, 2009, the licensee failed to
maintain administrative control of a master key to high radiation areas with dose rates in
excess of 1.0 rem per hour but less than 500 rads per hour. Because this violation was
of very low safety significance and has been entered into the licensee's corrective action
program as Condition Report 20973, it is being treated as a noncited violation consistent
with Section VI.A of the NRC Enforcement Policy: NCV 05000482/2009005-13, Failure
to Maintain Administrative Control of Keys to Locked High Radiation Areas.
2OS2 ALARA Planning and Controls (71121.02)
a.
Inspection Scope
The inspectors assessed licensee personnels performance with respect to maintaining
individual and collective radiation exposures as low as is reasonably achievable. The
inspectors used the requirements in 10 CFR Part 20 and the licensees procedures
required by technical specifications as criteria for determining compliance. The
inspectors interviewed licensee personnel and reviewed the following:
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Enclosure 2
Five outage or on-line maintenance work activities scheduled during the
inspection period and associated work activity exposure estimates which were
likely to result in the highest personnel collective exposures
Site-specific ALARA procedures
ALARA work activity evaluations, exposure estimates, and exposure mitigation
requirements
Interfaces between operations, radiation protection, maintenance, maintenance
planning, scheduling and engineering groups
Shielding requests and dose/benefit analyses
Dose rate reduction activities in work planning
Use of engineering controls to achieve dose reductions and dose reduction
benefits afforded by shielding
Workers use of the low dose waiting areas
First-line job supervisors contribution to ensuring work activities are conducted in
a dose efficient manner
Radiation worker and radiation protection technician performance during work
activities in radiation areas, airborne radioactivity areas, or high radiation areas
Self-assessments, audits, and special reports related to the ALARA program
since the last inspection
Corrective action documents related to the ALARA program and follow-up
activities, such as initial problem identification, characterization, and tracking
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of 6 of the required 15 samples and 6 of the
optional samples as defined in Inspection Procedure IP 71121.02-05.
b.
Findings
No findings of significance were identified.
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Enclosure 2
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1
Data Submission Issue
a.
Inspection Scope
The inspectors performed a review of the data submitted by the licensee for the 3rd
Quarter 2009 performance indicators 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
Mitigating Systems Performance Index - Emergency ac Power System
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - Emergency ac Power System performance indicator data for the period from the
4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the
performance indicator data reported during those periods, performance indicator
definitions and guidance contained in Revision 6 of the Nuclear Energy Institute (NEI)
Document 99-02, Regulatory Assessment Performance Indicator Guideline, were
used. The inspectors reviewed the licensees operator narrative logs, mitigating systems
performance index derivation reports, issue reports, event reports, and NRC integrated
inspection reports for the period of October 1, 2008, through September 30, 2009, to
validate the accuracy of the submittals. The inspectors reviewed the mitigating systems
performance index component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable NEI guidance. The inspectors also reviewed the licensees
issue report database to determine if any problems had been identified with the
performance indicator data collected or transmitted for this indicator and none were
identified. Specific documents reviewed are described in the attachment to this report.
This inspection constitutes one mitigating systems performance index - emergency ac
power system sample as defined by Inspection Procedure IP 71151.
b.
Findings
No findings of significance were identified.
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Enclosure 2
.3
Mitigating Systems Performance Index - High Pressure Injection Systems
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - High Pressure Injection Systems performance indicator data for the period from
the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the
performance indicator data reported during those periods, performance indicator
definitions and guidance contained in Revision 6 of the NEI Document 99-02,
Regulatory Assessment Performance Indicator Guideline, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, mitigating systems
performance index derivation reports, event reports, and NRC integrated inspection
reports for the period of October 1, 2008, through September 30, 2009, to validate the
accuracy of the submittals. The inspectors reviewed the mitigating systems performance
index component risk coefficient to determine if it had changed by more than 25 percent
in value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the performance
indicator data collected or transmitted for this indicator and none were identified.
Specific documents reviewed are described in the attachment to this report.
This inspection constitutes one mitigating systems performance index - high pressure
injection system sample as defined by Inspection Procedure IP 71151.
b.
Findings
No findings of significance were identified.
.4
Mitigating Systems Performance Index - Auxiliary Feedwater System
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - Auxiliary Feedwater System performance indicator data for the period from the
4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the
performance indicator data reported during those periods, performance indicator
definitions and guidance contained in Revision 6 of the NEI Document 99-02,
Regulatory Assessment Performance Indicator Guideline, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, event reports, mitigating
systems performance index derivation reports, and NRC integrated inspection reports
for the period of October 1, 2008, through September 30, 2009, to validate the accuracy
of the submittals. The inspectors reviewed the mitigating systems performance index
component risk coefficient to determine if it had changed by more than 25 percent in
value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the performance
indicator data collected or transmitted for this indicator and none were identified.
Specific documents reviewed are described in the attachment to this report.
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Enclosure 2
This inspection constitutes one mitigating systems performance index - auxiliary
feedwater sample as defined by Inspection Procedure IP 71151.
b.
Findings
No findings of significance were identified.
.5
Mitigating Systems Performance Index - Residual Heat Removal System
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - Residual Heat Removal System performance indicator data for the period from
the 4th quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the
performance indicator data reported during those periods, performance indicator
definitions and guidance contained in Revision 6 of the NEI Document 99-02,
Regulatory Assessment Performance Indicator Guideline, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, mitigating systems
performance index derivation reports, event reports, and NRC integrated inspection
reports for the period of October 1, 2008, through September 30, 2009, to validate the
accuracy of the submittals. The inspectors reviewed the mitigating systems
performance index component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable NEI guidance. The inspectors also reviewed the licensees
issue report database to determine if any problems had been identified with the
performance indicator data collected or transmitted for this indicator and none were
identified. Specific documents reviewed are described in the attachment to this report.
This inspection constitutes one Mitigating Systems Performance Index - Residual Heat
Removal System sample as defined by Inspection Procedure IP 71151.
b.
Findings
No findings of significance were identified.
.6
Mitigating Systems Performance Index - Cooling Water Systems
a.
Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index - Cooling Water Systems performance indicator data for the period from the 4th
quarter 2008 through the 3rd quarter 2009. To determine the accuracy of the
performance indicator data reported during those periods, performance indicator
definitions and guidance contained in Revision 6 of the NEI Document 99-02,
Regulatory Assessment Performance Indicator Guideline, were used. The inspectors
reviewed the licensees operator narrative logs, issue reports, mitigating systems
performance index derivation reports, event reports, and NRC integrated inspection
reports for the period of October 1, 2008, to September 30, 2009, to validate the
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Enclosure 2
accuracy of the submittals. The inspectors reviewed the mitigating systems
performance index component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable NEI guidance. The inspectors also reviewed the licensees
issue report database to determine if any problems had been identified with the
performance indicator data collected or transmitted for this indicator and none were
identified. Specific documents reviewed are described in the attachment to this report.
This inspection constitutes one mitigating systems performance index - cooling water
system sample as defined by Inspection Procedure IP 71151.
b.
Findings
No findings of significance were identified.
.7
Occupational Exposure Control Effectiveness (OR01)
a.
Inspection Scope
The inspectors sampled licensee submittals for the Occupational Radiological
Occurrences performance indicator for the period from the 4th quarter 2008 through 3rd
quarter 2009. To determine the accuracy of the performance indicator data reported
during those periods, performance indicator definitions and guidance contained in NEI
Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6,
was used. The inspectors reviewed the licensees assessment of the performance
indicator for occupational radiation safety to determine if indicator related data was
adequately assessed and reported. To assess the adequacy of the licensees
performance indicator data collection and analyses, the inspectors discussed with
radiation protection staff, the scope and breadth of its data review, and the results of
those reviews. The inspectors independently reviewed electronic dosimetry dose rate
and accumulated dose alarm and dose reports and the dose assignments for any
intakes that occurred during the time period reviewed to determine if there were
potentially unrecognized occurrences. The inspectors also conducted walkdowns of
numerous locked high and very high radiation area entrances to determine the adequacy
of the controls in place for these areas.
These activities constitute completion of the occupational radiological occurrences
sample as defined in Inspection Procedure IP 71151-05.
b.
Findings
No findings of significance were identified.
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Enclosure 2
.8
Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual
Radiological Effluent Occurrences (PR01)
a.
Inspection Scope
The inspectors sampled licensee submittals for the Radiological Effluent Technical
Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences
performance indicator for the period from the 4th quarter 2008 through 3rd quarter 2009.
To determine the accuracy of the performance indicator data reported during those
periods, performance indicator definitions and guidance contained in NEI
Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6,
was used. The inspectors reviewed the licensees issue report database and selected
individual reports generated since this indicator was last reviewed to identify any
potential occurrences such as unmonitored, uncontrolled, or improperly calculated
effluent releases that may have impacted offsite dose.
These activities constitute completion of the radiological effluent technical
specifications/offsite dose calculation manual radiological effluent occurrences sample
as defined in Inspection Procedure IP 71151-05.
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 Identification and Resolution of Problems
a.
Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensees
corrective action program at an appropriate threshold, that adequate attention was being
given to timely corrective actions, and that adverse trends were identified and
addressed. The inspectors reviewed attributes that included: the complete and
accurate identification of the problem; the timely correction, commensurate with the
safety significance; the evaluation and disposition of performance issues, generic
implications, common causes, contributing factors, root causes, extent of condition
reviews, and previous occurrences reviews; and the classification, prioritization, focus,
and timeliness of corrective actions. Minor issues entered into the licensees corrective
action program because of the inspectors observations are included in the attached list
of documents reviewed.
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Enclosure 2
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples. Instead, by inspection procedure, they were
considered an integral part of the inspections performed during the quarter and
documented in Section 1 of this report.
b.
Findings
No findings of significance were identified.
.2
Daily Corrective Action Program Reviews
a.
Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for followup, the inspectors performed a daily screening of
items entered into the licensees corrective action program. The inspectors
accomplished this through review of the stations daily corrective action documents.
The inspectors performed these daily reviews as part of their daily plant status
monitoring activities and, as such, did not constitute any separate inspection samples.
b.
Findings
No findings of significance were identified.
.3
Semi-Annual Trend Review
a.
Inspection Scope
The inspectors performed a review of the licensees corrective action program and
associated documents to identify trends that could indicate the existence of a more
significant safety issue. The inspectors focused their review on repetitive equipment
issues, but also considered the results of daily corrective action item screening
discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human
performance results. The inspectors nominally considered the 6-month period of
June 30 through December 31, 2009, although some examples expanded beyond those
dates where the scope of the trend warranted.
The inspectors also included issues documented outside the normal corrective action
program in major equipment problem lists, repetitive and/or rework maintenance lists,
departmental problem/challenges lists, system health reports, quality assurance
audit/surveillance reports, self-assessment reports, and maintenance rule assessments.
The inspectors compared and contrasted their results with the results contained in the
licensees corrective action program trending reports. Corrective actions associated with
a sample of the issues identified in the licensees trending reports were reviewed for
adequacy.
These activities constitute completion of one single semi-annual trend inspection sample
as defined in Inspection Procedure IP 71152-05.
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Enclosure 2
b.
Findings
No findings of significance were identified.
.4
Selected Issue Follow-up Inspection
a.
Inspection Scope
The inspectors selected two issues for follow-up inspection per Inspection
Procedure IP 71152. During a review of items entered in the licensees corrective action
program, the inspectors recognized a corrective action item documenting a problem with
extraction steam on June 23, 2009, that caused an increase in reactivity. The inspectors
reviewed corrective actions and new procedure changes for level control of high
pressure feedwater heaters. The inspectors also reviewed several condition reports and
interviewed personnel pertaining to the intermediate range nuclear instrument NI-36.
The deficiencies associated with NI-36 constituted one in-depth review of an operator
work-around.
These activities constitute completion of two in-depth problem identification and
resolution samples as defined in Inspection Procedure IP 71152-05.
b.
Findings
Introduction. On December 30, 2009, the inspectors identified a Green noncited
violation of Technical Specification, Table 3.3.1-1, Function 18.a, when Wolf Creek
restarted from on May 18, 2005.
Description. On April 9, 2005, Wolf Creek shut down for Refueling Outage 14. The
inspectors found no control room log entries stating that source range instrument NI-32
had to be manually energized. The inspectors reviewed a completed copy of
STN IC-236, Revision 4, dated April 9, 2005, which stated that compensation voltage
and current were found within tolerance and were left as-found. At the end of Refueling
Outage 14, in Mode 3, NI-36 indication deviated from indication from intermediate range
detector NI-35. During interviews with licensed operators, when shutdown banks were
withdrawn, NI-36 went above 6 E-11 amps and cleared the P-6 interlock while the
reactor was subcritical. Indication above 6E-11 normally means the reactor is critical.
The source ranges count rates and NI-35 also increased, but did not indicate criticality.
Troubleshooting was performed under Work Order 05-272906-000 was performed on
May 16, 2005. Instrumentation and controls technicians disconnected, cleaned, and
reconnected NI-36 cables. The NI-36 cables were then disconnected and reconnected
two more times. Work Order 05-272906-000 was also used to perform STS IC-436,
Channel Calibration NIS Intermediate Range N-36, Revision 15, test the log current
amplifier and indicator calibrations, Work Order 05-272906-000 was also used to
perform STN IC-236, Intermediate Range N36 Compensation Voltage Adjustment,
Revision 4 to calibrate the compensating voltage power supply and test the loss of
compensating voltage bistable relay driver. On May 17, 2005, during calibration of the
compensating voltage, during step 8.2.4.1, the technicians noted that compensating
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Enclosure 2
voltage was not changing indication permanently, only temporarily. The as-found and
as-left compensating voltage were satisfactory, but the compensating current as-found
and as-left was at 1E-10amps which is one order of magnitude above the 3E-11amps
acceptance criteria. The surveillance was closed stating used only as troubleshooting
tool only. No credit taken. The surveillance test routing sheet noted this as a technical
specification failure. This was then used to generate Work Order 05-272906-000 which
stated that there was a possible problem with the signal cable for NI-32 and the
compensation cable for NI-36 and to rework the cables. The operators had to remove
instrument fuses from the NI-36 instrument rack to cause the interlock to clear after the
efforts below. During control rod pulls during preparations for criticality, the P-6 interlock
came in with the reactor subcritical. Fuses had to later be pulled and re-inserted to clear
the interlock after NI-36 was worked during this series of work orders.
Using Work Order 05-272926-005, the technicians used STS IC-236 to successfully test
the positive and negative 25 Vdc power supplies, the high voltage power supply, the
power above permissive P-6 bistable relay driver, and the reactor trip high level
bistable relay driver. However, other than disconnecting cleaning, and reconnecting the
connectors, no corrective maintenance was performed on cables. The cause of the
failure was documented as suspect loose connection. Wolf Creek concluded that after
the above efforts, that NI-36 indication had been reduced sufficiently to declare it
operable because it channel checked with NI-35 to within one decade. Reactor startup
commenced on May 18, 2005, and concluded Refueling Outage 14.
During a reactor shutdown for Refueling Outage 15 on October 7, 2006, intermediate
range neutron Detector NI-36 did not decrease below 6E -11 amps and energize source
range detector NI-32. Following NI-36s failure to decrease below the P-6 setpoint,
reactor operators correctly transitioned to Procedure OFN SB-008, Instrument
Malfunctions to manually energize source range detector NI-32. On October 7, 2006,
Wolf Creek performed STN IC-236 under Work Order 05-274604-000. Detector NI-36
failed STN IC-236, Intermediate Range N36 Compensation Voltage Adjustment,
Revision 4, because the as-found detector current was outside of the tolerance range at
9E-11 amps (upper limit is 3E-11 amps) and could not be adjusted to within the
tolerance. As-found compensating voltage was within the allowable range.
Wolf Creek then replaced the jacks for the triaxial connector using Work
Order 05-272987-000. Work Order 05-272987-000 stated that the connector was found
failed but did not state what acceptance criteria it did not meet. Work
Order 05-272987-000 stated that the cause of the failure was suspect failed connector.
Also, Work Order 05-272987-000 took measurements of the compensation voltage cable
insulation resistance testing, but stated no acceptance criteria. Work Order 05-272987-
000 the performed surveillance test STS IC-236, Channel Operational Test Nuclear
Instrumentation System Intermediate Range N-36 Protection Set II, Revision 17, which
was followed by Work Order 06-289017-000 to perform STN IC-236. On October 17,
2006, STN IC-236 adjusted the compensating voltage to be more positive. The as-found
adjustment of the detector current was less than 1E-11amps, which was outside the
STN IC-236 acceptance criteria. The inspectors noted that the instrument drawer will
not allow detector current to decrease below 1E-11 amps due to a designed idling
current at 1E-11 amps. As-left current was 1E-11 amps. Later in the outage, control
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Enclosure 2
room operators requested that instrumentation and control workers adjust NI-36
because its output was not tracking with the other intermediate range detector, NI-35.
On November 9, 2006, STN IC-236 was performed again. During this test,
compensation current was unable to be adjusted below 3E-11 amps. The as-found
value was 7E-11 amps and the as-left value was 6E-11 amps. The 6E-11 amp current
was outside the allowable limit, but the surveillance procedure was completed with a
deficiency stating no credit taken. The surveillance cover sheet said that NI-36 was
reading within an order of magnitude of NI-35. The control room logs stated the same.
Work Order 06-290208-000 was generated to replace the detector during the Refueling
Outage 16.
On March 17, 2008, Wolf Creek tripped from 100 percent power and NI-36 automatically
energized source range detector NI-32. The inspectors checked plant computer data
and found that the source range instrument energized at 5E-11 amps which is below the
acceptance criteria of greater than 6 E-11amps (P-6 setpoint). The detector was
subsequently replaced during Refueling Outage 16.
The need to transition to Procedure EMG FR-S2, Response to Loss of Core Shutdown,
was not previously identified in a condition report, operator work around, or operator
burden. The inspectors found no other evaluation of the detectors behavior before Wolf
Creek ascended to Mode 2 in Refueling Outages 14 and 15. The inspectors found that
the connector cleaning in Refueling Outage 14 and the jack replacement in Refueling
Outage 15 were not likely to correct the problem found in STN IC-236. The inspectors
concluded that the STN IC-236 surveillances in Refueling Outage 14 and Refueling
Outage 15 had not met the acceptance criteria and that startup should not have
continued until the nuclear instrument issue was resolved. Wolf Creek did not identify
the issue as a technical specification violation. Although work orders were planned in
Refueling Outage 14 to replace NI-36, all were closed without action. The inspectors
found that NI-36 was conditioned through troubleshooting until it could pass its one
decade channel check. Other testing performed by Wolf Creek only impacted the
instrument drawer in the control room, while the problem was related to the detector
itself. Condition Report 2006-003187 found that the problems with compensating
voltage could not be determined, but concluded that it was not necessary for operability
because the system had no risk significance. The inspectors determined that the
compensation current is critical to the operation of the detectors because the design of
the compensated ion chamber is to allow the instrument drawer to sum currents in
opposing directions to discriminate neutrons from gamma. The condition report also
identified that the P-6 interlock may not work correctly, but no action was taken.
The inspectors reviewed Wolf Creek Technical Specification 3.3.1, Function 18.a,
Intermediate Range Flux, P-6 [interlock], and its bases statement. The bases state
that Function 18.a ensures that, on decreasing power, the P-6 interlock automatically
energizes nuclear instrumentation source range detectors and enables the source range
neutron flux reactor trip. During reactor trip, the function is required as reactor power
decreases to energize the source range detectors and the source range reactor trips.
The inspectors found that Wolf Creeks bases are consistent with the NUREG-1431,
Standard Technical Specifications Westinghouse Plants, Revision 3.0.
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Enclosure 2
Analysis. The inspectors determined that the failure to ensure that the P-6 interlock was
operable per the technical specification as defined in the bases was a performance
deficiency. The finding was more than minor because it was associated with the
configuration control (reactivity control) attribute of the Barrier Integrity Cornerstone, and
it affected the cornerstone objective to provide reasonable assurance that physical
design barriers (fuel cladding, reactor coolant system, and containment) protect the
public from radionuclide releases caused by accidents or events. The inspectors
evaluated the significance of this finding under the Mitigating Systems Cornerstone
using Phase 1 of Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and
Characterization of Findings, and determined that the finding screened to Green
because the P-6 interlock only affected the fuel barrier. This finding was not assigned a
crosscutting aspect because the cause was not representative of current performance.
Enforcement. Wolf Creek Technical Specification, Table 3.3.1-1, Function 18.a,
requires, in part, that when intermediate range instrument measured neutron flux
decreases below the allowable value of greater than or equal to 6 E-11 amps that the
source range instruments be energized and enable the source range reactor trip signal.
Technical Specification, Table 3.3.1-1, Function 4, requires the intermediate range
detectors to be operable at low power in Modes 1 and 2. These functions are required
on reactor trip. Contrary to the above, from May 17, 2005, to March 17, 2008,
intermediate range detector NI-36 was inoperable because its output did not decrease
below the P-6 setpoint when the reactor tripped and failed to energize source range
instrument NI-32 and the source range reactor trip. Because this violation was
determined to be of very low safety significance and was placed in the corrective action
program as Condition Report 00022450, this violation is being treated as a noncited
violation in accordance with Section VI.A.1 of the Enforcement Policy: NCV 05000482/2009005-14, Failure to Identify Inoperable P-6 Interlock and Intermediate
Range Detector.
4OA3 Event Follow-up (71153)
.1
Response to Notice of Unusual Event
On October 22, 2009, Emergency Diesel Generator B was out of service for planned
maintenance. At 12:06 p.m., the Wolf Creek control room received trouble annunciators
for Emergency Diesel Generator A. The speed sensor failed high which would cause
any diesel start to fail. This stopped the jacket water keep warm pump, and prevented
air start system solenoids from starting the engine. Since the engine was in standby, low
lube oil pressure also would have prevented the engine from starting. Wolf Creek
initiated troubleshooting and repair. At 5:39 p.m., Wolf Creek declared an Unusual Event
under Emergency Action Level (EAL) 6/AC5 for loss of both diesels with the reactor
defueled. At 5:45 p.m., Wolf Creek made notification to state and local governments of
the Notice of Unusual Event. At 7:14 p.m., Wolf Creek notified the NRC Operations
Officer that the power supply had excessive voltage ripple which caused the speed
sensors failure. The speed switch and its power supply were replaced. The inspectors
observed control room activities, repair activities, and post-maintenance testing of
repairs. On October 23, 2009, at 7:38 a.m., Emergency Diesel Generator A was
restored to operable status and the unusual event was terminated.
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Enclosure 2
b.
Findings
One violation of very low safety significance (Green) is described in Section 4OA7 of this
report.
.2
Licensee Event Report Review
a.
Inspection Scope
The inspectors reviewed potentially reportable events under Inspection
Procedure IP 71153. Inspectors also utilized NUREG 1022, Event Reporting Guidelines
10 CFR 50.72 and 50.73, Revision 2.
b.
Findings
Introduction. The inspectors identified a Severity Level IV noncited violation of
10 CFR 50.73, in which the licensee failed to submit licensee event reports within 60
days following discovery of events or conditions meeting the reportability criteria.
Description. The licensee submitted Licensee Event Report LER 2009-009-00 under
10 CFR 50.73(a)(2)(i)(B) for an operation prohibited by technical specifications. The
inspectors determined this event report was not submitted within the 60 days allowed by
10 CFR 50.73. The inspectors identified that other reporting requirements of 50.73 also
applied but were not included in the licensee event report.
In the event on August 22, 2009, Wolf Creek disabled both trains of the P-4 interlock for
planned maintenance. Specifically, the feedwater isolation signal that is generated by
P-4 (reactor trip coincident with low Tave) was taken out of service for control rod drive
motor-generator set testing. This allowed reactor trip breaker cycling without isolation of
main feedwater. The P-4 interlock was required by Technical Specification 3.3.2 function
8.a. This function is discussed in USAR Section 7.3.8, NSSS Engineered Safety
Feature Actuation System. which describes the function of a main feedwater isolation as
to prevent or mitigate the effect of an excessive cooldown. Wolf Creek technical
specification Bases also state that one or more functions may backup other engineered
safety feature actuation signal functions credited in Chapter 15 of the USAR.
Licensee Event Report 2009-009-00 reported a condition prohibited by technical
specifications under a(2)(i)(B) and correctly described that the P-4 interlock was not
credited in accident analysis. The licensee did not report the event under reporting
criteria 50.73(a)(2)(v). The engineered safety features actuation signal system has other
signals that cause feedwater isolations that are used in Chapter 15 of the USAR.
The inspectors consulted NUREG 1022, Event Reporting Guidelines 10 CFR 50.72
and 50.73, Revision 2. NUREG 1022, Section 3.2.7, reportability under 50.73(a)(2)(v),
specified that inoperable systems required by the technical specifications are to be
reported, even if there are other diverse, operable means of accomplishing the safety
function. The inspectors found that Wolf Creek was not correct in concluding that the
50.73(a)(2)(v)(A) through (D) only applied to the accident analysis contained in
Chapter 15 of the USAR. The inspectors consulted with the NRC Office of Nuclear
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Enclosure 2
Reactor Regulation, who agreed with the inspectors application of the rule and
NUREG 1022. The untimely licensee event report was entered into the corrective action
program as Condition Report 22781.
Analysis. The failure to submit a timely and complete licensee event report was a
performance deficiency. The inspectors reviewed this issue in accordance with
Inspection Manual Chapter 0612 and the NRC Enforcement Manual. Through this
review, the inspectors determined that traditional enforcement was applicable to this
issue because the NRC's regulatory ability was affected. Specifically, the NRC relies on
the licensee to identify and report conditions or events meeting the criteria specified in
regulations in order to perform its regulatory function, and when this is not done, the
regulatory function is impacted. The inspectors determined that this finding was not
suitable for evaluation using the significance determination process, and as such, was
evaluated in accordance with the NRC Enforcement Policy. The finding was reviewed
by NRC management, and because the violation was determined to be of very low
safety significance, was not repetitive or willful, and was entered into the corrective
action program, this violation is being treated as a Severity Level IV noncited violation
consistent with the NRC Enforcement Policy. This finding was determined to have a
crosscutting aspect in the area of problem identification and resolution associated with
the corrective action program in that the licensee failed to appropriately and thoroughly
evaluate for reportability aspects all factors and time frames associated with the
inoperability of the engineered safety features actuation system P.1(c).
Enforcement. Title 10 CFR 50.73(a)(1) requires, in part, that licensees shall submit a
licensee event report for any event of the type described in this paragraph within 60
days after the discovery of the event. Title 10 CFR 50.73(a)(2)(v) requires, in part, that
events or conditions that could have prevented the fulfillment of the safety function of
structures or systems that are needed to shutdown the reactor and maintain it in a safe
shutdown condition, remove residual heat, control the release of radioactive material, or
mitigate the consequences of an accident. Contrary to the above, on October 23, 2009,
Wolf Creek failed to submit a licensee event report within 60 days for removing the P-4
interlock from service, and failed to identify that the condition could have prevented the
fulfillment of the safety function of structures or systems that are needed to mitigate the
consequences of an accident. In accordance with the NRC's Enforcement Policy, the
finding was reviewed by NRC management and because the violation was of very low
safety significance, was not repetitive or willful, and was entered into the corrective
action program, this violation is being treated as a Severity Level IV noncited violation,
consistent with the NRC Enforcement Policy: NCV 05000482/2009005-15, Failure to
Report a Condition that Could Have Prevented Fulfillment of a Safety Function.
4OA5 Other Activities
.1
Quarterly Resident Inspector Observations of Security Personnel and Activities
a.
Inspection Scope
During the inspection period, the inspectors performed observations of security force
personnel and activities to ensure that the activities were consistent with Wolf Creek
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Enclosure 2
security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during both normal and off-normal plant working hours.
These quarterly resident inspector observations of security force personnel and activities
did not constitute any additional inspection samples. Rather, they were considered an
integral part of the inspectors normal plant status review and inspection activities.
b.
Findings
No findings of significance were identified.
.2
Temporary Instruction 2515-172, Reactor Coolant System Dissimilar Metal Butt Welds
a.
Inspection Scope:
Portions of Temporary Instruction 2515/172, Reactor Coolant System Dissimilar Metal
Butt Welds, were performed at Wolf Creek during Refueling Outage 17. Specific
documents reviewed during this inspection are listed in the attachment. This unit has
the following dissimilar metal butt welds.
COMPONENT ID
DESCRIPTION
CATEGORY
BASELINE
EXAM
COMMENT
RV-301-121-A
Loop 1 Outlet
Nozzle to Safe-
end weld
D
April 2005
RF14
Next exam:
October 2009
RF17
RV-301-121-B
Loop 2 Outlet
Nozzle to Safe-
end weld
D
April 2005
RF14
Next exam:
October 2009
RF17
RV-301-121-C
Loop 3 Outlet
Nozzle to Safe-
end weld
D
April 2005
RF14
Next exam:
October 2009
RF17
RV-301-121-D
Loop 4 Outlet
Nozzle to Safe-
end weld
D
April 2005
RF14
Next exam:
October 2009
RF17
RV-302-121-A
Loop 1 Inlet
Nozzle to Safe-
end weld
E
April 2005
RF14
Next exam:
April 2011 RF18
RV-302-121-B
Loop 2 Inlet
Nozzle to Safe-
E
April 2005
Next exam:
- 70 -
Enclosure 2
COMPONENT ID
DESCRIPTION
CATEGORY
BASELINE
EXAM
COMMENT
end weld
RF14
April 2011 RF18
RV-302-121-C
Loop 3 Inlet
Nozzle to Safe-
end weld
E
April 2005
RF14
Next exam:
April 2011 RF18
RV-302-121-D
Loop 4 Inlet
Nozzle to Safe-
end weld
E
April 2005
RF14
Next exam:
April 2011 RF18
TBB03-1-W /
MW7090-WOL-DM
Pressurizer surge
nozzle to safe-
end weld
D / F
October 2006
RF15
Note 1
TBB03-2-W /
MW7089-WOL-DM
Pressurizer spray
nozzle to safe-
end weld
D / B
October 2006
RF15
Note 1
TBB03-3-A-W /
MW7086-WOL-DM
Pressurizer
safety nozzle A to
safe-end weld
D / B
October 2006
RF15
Note 1
TBB03-3-B-W /
MW7087-WOL-DM
Pressurizer
safety nozzle B to
Safe-end weld
D / B
October 2006
RF15
Note 1
TBB03-3-C-W /
MW7088-WOL-DM
Pressurizer
safety nozzle C
to safe-end weld
D / F
October 2006
RF15
Note 1
TBB03-4-W /
MW7085-WOL-DM
Pressurizer relief
nozzle to safe-
end weld
D / F
October 2006
RF15
Note 1
Note 1: The pressurizer dissimilar metal butt-welds had full structural weld overlay
applied in Refueling Outage 15. The first Component ID was the designation prior to
overlay, the latter Component ID is the current weld designation (after overlay).
Likewise, the first MRP-139 category was the designation prior to baseline exam and
overlay, and the latter is the current designation (after overlay). Note that these
locations are now examined in accordance with approved alternative of relief
Request I3R-05.
- 71 -
Enclosure 2
03.01 Licensees Implementation of the MRP-139 Baseline Inspections
a.
MRP-139 baseline inspections:
The inspectors reviewed records nondestructive examination activities associated with
the licensees hot leg inspection effort. The baseline inspections of the pressurizer
dissimilar metal butt welds were completed during the spring 2008 Refueling Outage 16.
b.
At the present time, the licensee is not planning to take any deviations from the baseline
inspection requirements of MRP-139, and all other applicable dissimilar metal butt welds
are scheduled in accordance with MRP-139 guidelines.
03.02 Volumetric Examinations
a.
The inspectors reviewed the ultrasonic examination records of the four unmitigated
reactor hot leg nozzles and piping. The inspectors concluded that the ultrasonic
examination for these welds was done in accordance with ASME Code,Section XI,
Supplement VIII, Performance Demonstration Initiative requirements regarding
personnel, procedures, and equipment qualifications. No relevant conditions were
identified during these examinations.
b.
The inspectors reviewed the nondestructive evaluations performed on the four reactor
hot leg nozzles and piping. Inspection coverage met the requirements of MRP-139 and
no relevant conditions were identified.
c.
The certification records of examination personnel were reviewed for those personnel
that performed the examinations of the inspected nozzles. All personnel records
showed that they were qualified under the EPRI Performance Demonstration Initiative.
d.
No deficiencies were identified during the nondestructive evaluations.
03.03 Weld Overlays.
The licensee performed all weld overlays during the previous outage (RF 15).
03.04 Mechanical Stress Improvement
The licensee did not employ a mechanical stress improvement process this outage.
03.05 Inservice inspection program
a.
Inspection Scope:
The licensees MRP-139 program is part of their Alloy 600 program and future
inspections are in accordance with the MRP-139 requirements.
- 72 -
Enclosure 2
b.
Findings
No findings of significance were identified.
.3
(Closed) Unresolved Item 05000482/2008010-04: Operator Actions May Create the
Potential for Secondary Fires
Introduction. The inspectors identified a Green non-cited violation of License
Condition 2.C.(5), Fire Protection, for the failure to implement and maintain the
approved fire protection program. Specifically, the licensee prescribed mitigating actions
in response to certain fire scenarios that would result in a loss of circuit breaker
coordination and could initiate secondary fires in plant locations outside of the initial fire
area.
Description. Procedure OFN KC-016, Fire Response, Revision 19, specified operator
actions to be taken in response to fires outside of the control room. This procedure
provided the mitigating actions needed to maintain the reactor in hot standby in the
event of various failures and spurious actuations. The inspectors identified the following
13 fire areas where the prescribed mitigating actions would remove electrical circuit
protection (i.e., circuit breaker coordination) for the train affected by the fire and could
initiate secondary fires in plant locations outside of the initial fire area:
Fire Area A-8
Auxiliary Building - 2000 Elevation, General Area
Fire Area A-11
Cable Chase (Room 1335)
Fire Area A-16
Auxiliary Building - 2026 Elevation, General Area
Fire Area A-17
South Electrical Penetration (Room 1409)
Fire Area A-18
North Electrical Penetration (Room 1410)
Fire Area C-18
North Vertical Cable Chase (Room 3419)
Fire Area C-21
Lower Cable Spreading (Room 3501)
Fire Area C-22
Upper Cable Spreading (Room 3801)
Fire Area C-23
South Vertical Cable Chase (Room 3505)
Fire Area C-24
North Electrical Chase (Room 3504)
Fire Area C-30
South Vertical Cable Chase (Room 3617)
Fire Area C-33
South Vertical Cable Chase (Room 3804)
Fire Area RB
Reactor Building (Containment)
For these fire areas, the procedure directed the operators to remove power to a
power-operated relief valve if a fire caused the power-operated relief valve to spuriously
open and operators could not close its associated block valve. Specifically, the
procedure directed the operators to open circuit breakers on the associated 125 Vdc
power supply. The inspectors noted that the failure of the block valve to close resulted
from fire damage and not from a spurious operation of the valve.
The licensee specified this action in order to close the power-operated relief valve and
preclude the potential for spurious opening due to inter-cable faults (i.e., cable-to-cable
hot shorts). However, the inspectors determined this action would also remove the
control power used to operate 4160 Vac and 480 Vac circuit breakers. The removal of
- 73 -
Enclosure 2
control power would prevent remote breaker operations and disable the circuit breaker
protective trips for the train affected by the fire.
Removing control power to the circuit breaker results in a loss of its ability to
automatically isolate faults before severe damage occurs. As a result, fire-induced faults
(shorts to ground) in non-essential power cables of the affected 4160 Vac and 480 Vac
supplies may not clear until after tripping an upstream feeder breaker to the supplies,
which would remove power from equipment that was assumed by the safe shutdown
analysis to be unaffected. This action would also prevent breakers from automatically
opening during an overload condition and could initiate secondary fires in plant locations
outside of the initial fire area.
The safe shutdown analysis assumed that a fire occurred in one fire area at any time.
The inspectors determined that the mitigating actions taken in response to fires in the
listed fire areas had the potential to initiate secondary fires in other plant locations, which
would invalidate the safe shutdown analysis and could impact the ability to achieve and
maintain safe shutdown.
Analysis. Prescribing mitigating actions in response to certain fire scenarios that would
result in a loss of circuit breaker coordination and could initiate secondary fires in plant
locations outside of the initial fire area was a performance deficiency. The inspectors
determined that this deficiency was more than minor because it was associated with the
Protection Against External Factors attribute of the Initiating Events Cornerstone and
adversely affected the cornerstone objective to limit the likelihood of those events that
upset plant stability and challenge critical safety functions during shutdown as well as
power operations.
The significance of this finding was evaluated using the Significance Determination
Process in Manual Chapter 0609, Appendix F, Fire Protection Significance
Determination Process, because it affected fire protection defense-in-depth strategies
involving post-fire safe shutdown systems.
The inspectors associated the finding with the post-fire safe shutdown category since the
performance deficiency would remove power from equipment that was assumed by the
safe shutdown analysis to be unaffected and could initiate secondary fires in plant
locations outside of the initial fire area. The inspectors assigned the finding a high
degradation rating since the affected circuit breakers would not provide any fire
protection benefit and would receive no fire protection credit.
The inspectors performed a Phase 2 evaluation to determine an upper limit for the
change in core damage frequency. The inspectors determined eight credible fire
scenarios that could result in core damage under certain conservative assumptions. The
pertinent parameters and results of these scenarios are summarized below.
Attachment B provides a more detailed discussion of the Phase 2 evaluation.
- 74 -
Enclosure 2
Table 1. Phase 2 Evaluation Results
Scenario
Number
Ignition
Source
Source
Description
(Fire Area)
Fire
Ignition
Frequency
Heat
Release
Rate
Severity
Factor
Probability of
Non-Suppression
Probability
of a Hot
Short
1
RP-333
Relay
Panel
(A-16)
6.00E-5
200 kW
0.9
0.35
0.02
3.78E-7
2
RP-333
Relay
Panel
(A-16)
6.00E-5
650 kW
0.1
0.35
0.02
4.20E-8
3
SK194B
Security
Panel
(A-16)
6.00E-5
200 kW
0.1
0.35
0.02
4.20E-8
4
NG01B
(A-18)
6.00E-5
200 kW
0.1
0.44
0.02
5.28E-8
5
Fire
C-21
6.26E-6
70 kW
0.9
0.26
0.02
2.93E-8
6
Fire
C-21
6.26E-6
200 kW
0.1
0.26
0.02
3.26E-9
7
Fire
C-22
5.54E-6
70 kW
0.9
1.00
0.02
9.96E-8
8
Fire
C-22
5.54E-6
200 kW
0.1
1.00
0.02
1.11E-8
Total
6.58E-7
In each of these scenarios, the conditional core damage probability (CCDP) bounds the
change in core damage frequency. The inspectors calculated the conditional core
damage probability using the following equation:
Short
Hot
n
Suppressio
Non
P
x
P
x
SF
x
FIF
=
where:
FIF denotes the fire ignition frequency
SF denotes the severity factor
n
Suppressio
Non
P
denotes the non-suppression probability
- 75 -
Enclosure 2
Short
Hot
P
denotes the probability of a hot short
The sum of the conditional core damage probabilities for each of the fire scenarios
bounded the total change in core damage frequency associated with this performance
deficiency. Since the change in core damage frequency exceeded1E-7, the inspectors
screened the finding for its potential risk contribution to a large early release frequency.
In accordance with the guidance in NRC Inspection Manual Chapter 0609, Appendix H,
the inspectors determined this finding did not involve a significant increase in the risk of
a large early release of radiation because Wolf Creek has a large, dry containment and
the accident sequences contributing to a change in the core damage frequency did not
involve either a steam generator tube rupture or an intersystem loss of coolant accident.
Since this bounding change in core damage frequency was less than 1E-6/year and the
finding did not involve a significant increase in the risk of a large early release frequency,
the inspectors determined this performance deficiency had very low risk significance
(Green). This finding was not assigned a cross-cutting aspect because it existed more
than two years and does not represent current performance.
As a compensatory measure, the licensee implemented an hourly fire watch in the
affected fire areas, with the exception of the reactor building, which is not readily
accessible during power operations. For the reactor building, the licensee is monitoring
the containment temperature as a compensatory measure.
Enforcement. License Condition 2.C.(5) states, in part, that the licensee shall maintain
in effect all provisions of the approved fire protection program as described in the
Standardized Nuclear Unit Power Plant System (SNUPPS) Final Safety Analysis Report
for the facility through Revision 17, the Wolf Creek Site Addendum through Revision 15,
and as approved in the Safety Evaluation Report through Supplement 5. The Wolf
Creek Updated Safety Analysis Report combined the SNUPPS Final Safety Analysis
Report, Revision 17, and the Wolf Creek Site Addendum, Revision 15, into one
document.
Appendix 9.5B of the Updated Safety Analysis Report provides an area-by-area analysis
of the power block that incorporated Drawing E-1F9905, Fire Hazards Analysis,
Revision 2, by reference. Drawing E-1F9905 states that the overall intent is to
demonstrate that a single plant fire will not negatively affect the post-fire safe shutdown
capability and that if a circuit damaged by a fire is protected by an individual overcurrent
protection device, that device is assumed to function to clear the fault.
Contrary to the above, prior to December 22, 2009, the licensee failed to implement and
maintain in effect all provisions of the approved fire protection program. Specifically, the
licensee prescribed mitigating actions in response to certain fire scenarios that would
result in a loss of circuit breaker coordination (i.e., disable an overcurrent protection
device from functioning to clear a fault) and could initiate secondary fires in plant
locations outside of the initial fire area that negatively affect the post-fire safe shutdown
capability. However, the plants post-fire safe shutdown capability only evaluated
damage resulting from a single fire.
- 76 -
Enclosure 2
The licensee entered this issue into their corrective action program as Performance
Improvement Request 2008-005210. Because this violation was of very low safety
significance and it was entered into the corrective action program, this violation is being
treated as a non-cited violation, consistent with the NRC Enforcement Policy:
NCV 05000482/2009005-16, Operator Actions Disable Circuit Breaker Coordination and
Could Initiate Secondary Fires.
.4
(Closed) Unresolved Item 05000482/2008010-01: Post-fire Safe Shutdown Inspection
Did Not Identify Diagnostic Information
During a triennial fire protection inspection in 2008, the inspectors identified an
unresolved item concerning the availability of diagnostic instrumentation needed to
respond to a loss of reactor coolant pump seal cooling during certain fire scenarios. The
plant design uses reactor coolant pump seal injection and thermal barrier cooling to cool
the reactor coolant pump seals. One method of seal cooling must be maintained during
reactor coolant pump operation to prevent seal failure, which, in some cases, could lead
to increased seal leakage beyond the capacity of the charging pump.
The licensee identified that fire damage in four fire areas could isolate both methods of
seal cooling. The inspectors identified that the licensee relied upon a decrease in
pressurizer level to diagnose a loss of seal cooling. The inspectors determined the fire
response procedure was inadequate since pressurizer level would not decrease until
after seal failure occurred. Since the procedure required operators to recognize the loss
of cooling and take response actions and the procedure did not identify adequate
instrumentation to be used, the inspectors could not verify that it would remain free of
fire damage for fires in these four fire areas.
In response to the unresolved item, the licensee determined the instrumentation that
would be available to diagnose a loss of seal cooling for fires in these four areas. The
licensee determined that the thermal barrier flow switches and alarms would remain
available for all four areas. The licensee also determined that seal injection flow and
temperature would remain available for most, if not all, of the trains for each fire area.
The inspectors reviewed the abnormal operating procedures used in the event of reactor
coolant pump problems. Based on this review and the licensees analysis of available
instrumentation, the inspectors concluded that it was reasonable to believe that
operators had sufficient instrumentation and guidance to promptly recognize, diagnose,
and respond to a loss of reactor coolant pump seal cooling.
The failure to establish written procedures adequately implementing the approved fire
protection program was a performance deficiency and a violation of Technical
Specification 5.4.1.d. The inspectors determined this performance deficiency was of
minor safety significance since it was not similar to any example in Manual
Chapter 0612, Appendix E, nor did it meet any of the minor questions in Manual
Chapter 0612, Appendix B. This performance deficiency constitutes a violation of minor
significance that is not subject to enforcement action in accordance with the NRCs
- 77 -
Enclosure 2
The licensee implemented an hourly fire watch as an immediate compensatory measure
and entered this issue into their corrective action program as Condition
Report 2008-005171.
.5
(Closed) Licensee Event Report 05000482/2008006-00: Entry Into Mode 4 Without An
Operable Containment Spray System
On July 3, 2008, Wolf Creek submitted LER 2008006 which described missed VT-2 weld
inspections when modifying train B containment spray recirculation line in refueling
outage 16. Wolf Creek stated that changes to shim the recirculation line inadvertently
resulted in missing the VT-2 post-maintenance test. This resulted in ascending to Mode
4 without an operable containment spray system. Wolf Creek identified this issue on
May 8, 2008, at 1:45am and entered Technical Specification 3.6.6 while in Mode 4. The
VT-2 inspections were performed satisfactorily and Technical Specification 3.6.6 was
exited at 3:13am on May 8, 2008. Enforcement aspects are discussed in Section 4OA7.
This LER is closed.
.6
(Closed) Licensee Event Report 05000482/2008-08-00, -01, -02: Potential for Residual
Heat Removal Trains to be Inoperable during Mode Change.
All three revisions of this licensee event report were discussed and enforcement action
was taken in NRC Inspection Report 05000482/2009006. This licensee event report is
closed.
.7
(Closed) Unresolved Item 2008005-02: Residual Heat Removal Suction Piping
Saturation Temperature and Pressure.
This unresolved item was inspected and enforcement action was taken in NRC
Inspection Report 05000482/2009006. This unresolved item is closed.
.8
(Closed) Licensee Event Report 05000482/2008-004-01: Loss of Power Event When
the Reactor was Defueled.
Licensee Event Report 05000482/2008-004-00 was closed in NRC Inspection
Report 05000482/2008004 as a Green finding. In NRC Inspection
Report 05000482/2009004, the inspectors identified a violation of 10 CFR 50.73
associated with this event report. Wolf Creek subsequently submitted revised Licensee
Event Report 2008-004-01 in response to the Severity Level IV violation. The submittal
of Licensee Event Report 05000482/2008-004-01 restores compliance with
10 CFR 50.73. This licensee event report is closed.
4OA6 Meetings
Exit Meeting Summary
On October 22, 2009, the radiation protection inspectors presented the inspection results
to Mr. M. W. Sunseri and other members of the licensee staff. The licensee
- 78 -
Enclosure 2
acknowledged the issues presented. The inspector asked the licensee whether any
materials examined during the inspection should be considered proprietary. No
proprietary information was identified.
On October 30, 2009, the in-service inspection inspectors debriefed the inspection
results to Mr. M. W. Sunseri, and other members of the licensee staff. The licensee
acknowledged the issues presented. The inspectors acknowledged review of proprietary
material during the inspection which had been or will be returned to the licensee.
On December 17 and 22, the fire protection inspectors conducted telephonic exit
meetings and presented the results of the staffs closure of fire protection unresolved
items. The inspectors presented the results to L. Ratzlaff, Manager Support
Engineering, on December 17 and M.W. Sunseri, on December 22. The licensee
acknowledged the issues presented. The inspectors asked the licensee whether any of
the material examined during the inspection should be considered proprietary. No
proprietary information was identified.
On January 14, 2010, the resident inspectors presented the inspection results of the
resident inspections to Mr. M.W. Sunseri, and other members of the licensee's
management staff. The licensee acknowledged the findings presented. The inspectors
noted that while proprietary information was reviewed, none would be included in this
report.
4OA7 Licensee-Identified Violations
The following violations of very low safety significance (Green) were identified by the licensee
and are violations of NRC requirements which meet the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600, for being dispositioned as noncited violations.
.1
On October 22, 2009, at 12:06 p.m., the Wolf Creek control room received trouble
annunciators for emergency diesel generator A. Emergency diesel generator B was out
of service for planned maintenance. 10 CFR 50.47(b)(4) requires that a standard
emergency classification action level scheme be used by the licensee. Wolf Creek
EAL 6, Loss of Electrical Power/Assessment Capability, requires, in part, that when
both emergency diesel generators are out of service for greater than 15 minutes, a
Notice of Unusual Event be declared. Contrary to the above, on October 22, 2009, Wolf
Creek did not declare a Notice of Unusual Event until 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after both emergency
diesel generators were out of service. This issue is of very low safety significance
(Green) because it is associated with failure to report a Notification of Unusual Event.
Wolf Creek initiated Condition Report 21058 regarding the late declaration.
.2
On July 3, 2008, Wolf Creek submitted Licensee Event Report LER 2008006 which
described missed VT-2 weld inspections when modifying train B containment spray
recirculation line in Refueling Outage 16, requiring the train to be declared inoperable.
This issue has been entered in to the corrective action program as Condition
Report 2008-2197. Technical Specification 3.0.4, states, in part, that when a limiting
condition of operation is not met, that mode changes shall only be made: when actions
to be entered permit continued operation for an unlimited period of time, after a risk
- 79 -
Enclosure 2
assessment, or when an allowance is stated in the specification. Technical Specification
Limiting Condition of Operation 3.6.6 requires, in part, two operable trains of
containment spray in Modes 1 through 4. Contrary to the above, on May 8, 2008, Wolf
Creek entered Mode 4 with only one operable containment spray system. This issue is
of very low safety significance (Green) because there was no loss of function of the
containment spray system.
A-1
Attachment 1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
R. D. Benham, Integrated Plant Scheduling
T. D. Card, Engineering
B. E. Dale, Manager Maintenance
T. M. Damashek, Superintendent, Operations Support
T. F. East, Manager, Emergency Planning
D. L. Fehr, Manager Information Systems
R. L. Gardner, Manager, Quality
S. E. Hedges, Vice President Oversight
D. M Hooper, Supervisor Licensing
J. K. Kent, Finance Management
W. R. Ketchum, Supervisor, Plant Safety Assessment
S. R. Koenig, Corrective Actions
W. T. Muilenburg, Licensing
P. J. Bedgood, Superintendent, Chemistry/Radiation Protection
C. L. Palmer, Major Modifications
J. M. Pankaskie, Supervisor, Design Engineering
E. M. Peterson, Ombudsman
D. Phelps, Owners Representative
B. Poteat, Piedmont
L. Ratzlaff, Manager, Support Engineering
E. A. Ray, Manager Chemistry/Health Physics
K. Scherich, Director Engineering
A. F. Stull, Vice President & Chief Administrative Officer
M. W. Sunseri, President and Chief Executive Officer
B. J. Vickery, Supply Chain
B. Walters, Supervisor, Security
M. J. Westman, Manager, Training
K. Frederickson, Licensing
J. Suter, Fire Protection
NRC Personnel
D. Loveless, Senior Reactor Analyst
A-2
Attachment 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed 05000482/2009005-02
Control of Transient Ignition Sources (Section 1R05)05000482/2009005-03
Failure to Identify Sources of Boron Leakage
(Section 1R08)05000482/2009005-04
Failure to Incorporate Requirements of Regulatory
Guide 1.182 into Daily Shutdown Risk Assessment
(Section 1R13.1)05000482/2009005-05
Mode Change Under Technical Specification 3.0.4.b
Without Required Risk Management Actions
(Section 1R13.2)05000482/2009005-06
Failure to Follow Corrective Action Procedure
(Section 1R13.3)05000482/2009005-07
Failure to Follow Procedure Results in Draining of
Emergency Core Cooling System Pump Oil
(Section 1R13.4)05000482/2009005-08
Inadequate Operability Evaluation of Essential Service
Water Pumps (Section 1R15.1)05000482/2009005-09
Positive Reactivity Addition Prohibited by Technical
Specifications while in Mode 2 (Section 1R15.2)05000482/2009005-10
Failure to Obtain Vendor Data Necessary for Plant
Modification (Section 1R18)05000482/2009005-12
Unevaluated Scaffold Against Component Cooling Water
Piping (Section 1R20)05000482/2009005-13
Failure to Maintain Administrative Control of Keys to
Locked High Radiation Areas (Section 2SO1)05000482/2009005-14
Failure to Identify Inoperable P-6 Interlock and
Intermediate Range Detector (Section 4OA2)05000482/2009005-15
Failure to Report a Condition that Could Have Prevented
Fulfillment of a Safety Function (Section 4OA3)05000482/2009005-16
Operator Actions disable Circuit Breaker Coordination and
Could Initiate Secondary Fires (Section 4OA5.1)
A-3
Attachment 1
Opened 05000482/2009005-01
Failure to Correct Discolored Boric Acid Deposits
(Section 1R05)05000482/2009005-11
Failure to Correct Vessel Head Vent Path (Section 1R20)
Discussed 05000482/2009002-07
Failure to correct component cooling water valve closures
(EA-09-110) (Section 1R18)
05000482/2009-005-00
LER
Loss of both Diesel Generators with all fuel in the Spent
Fuel Pool (Section 4OA3)
Closed 05000482/2008010-01
Post Fire Safe Shutdown Procedure Did Not Identify
Diagnostic Information (Section 4OA5.4)05000482/2008010-04
Operator Actions May Create the Potential for Secondary
Fires (Section 4OA5.3)
05000482/2008-006-00
LER
Entry Into Mode 4 Without An Operable Containment
Spray System (4OA5.5)
05000482/2008-008-00
05000482/2008-008-01
05000482/2008-008-02
LER
Potential for Residual Heat Removal Trains to be
Inoperable during Mode Change (Section 4OA5.6)05000482/2008005-02
Residual Heat Removal Suction Piping Saturation
Temperature and Pressure (Section 4OA5.7)
05000482/2008-004-01
LER
Loss of Power Event When the Reactor was Defueled
(Section 4OA5.8)
LIST OF DOCUMENTS REVIEWED
Section 1RO1: Adverse Weather Protection
MISCELLANEOUS
NUMBER
TITLE
REVISION
FL-01
Flooding of Auxiliary Building
01
CR 22801
Auxiliary Building Flooding Question
3.4.1
Updated Safety Analysis Report, Flood Protection
19
A-4
Attachment 1
Section 1RO4: Equipment Alignment
PROCEDURES
NUMBER
TITLE
REVISION
M-12EC01
Fuel Pool Cooling and Clean-up System
19
SYS EC-120
Fuel Pool Cooling and Clean-up System Startup
44
CKL EC-120
Fuel Pool Cooling and Clean-up System Normal
Valve Lineup/Breaker Checklist
14A
CKL JE-120
Emergency Fuel Oil System Lineup
19
STS NB-005
Breaker Alignment Verification
18
CKL KJ-121
Diesel Generator NE01 and NE02 Valve Checklist
28A
FPPM-015
Fuel Building Elevation 2000
7
Section 1RO5: Fire Protection
PROCEDURES
NUMBER
TITLE
REVISION
FPPM-009
Control Bldg El. 2000
2
AP 10-106
Fire Preplans
7
Fppm-015
Fuel Building Elevation 2000
7
Section 1RO6: Flood Protection Measures
MISCELLANEOUS
NUMBER
TITLE
ALR 00-095C
AFP Sump Room Level Hi
FL-14
Feed Pump Room Maximum Flood Level
LE-M-002
Auxiliary Building Room 1206, 1207 Maximum Flood
Level
WORK ORDER
WO 08-304475-000
A-5
Attachment 1
Section 1RO7: Heat Sink Performance
PROCEDURES
NUMBER
TITLE
REVISION
STN PE-038
Containment Cooler Performance Test
10
EPRI NP-7552
Heat Exchanger Performance Monitoring Guidelines
1991
Section 1RO8: Inservice Inspection Activities
CONDITION REPORTS
00003599
00011297
00011954
00018217
00018785
00019248
00020993
00021274
2008-004840
CONDITION REPORT GENERATED FOR THIS INSPECTION
00020993, Fire Watches
DRAWINGS
NUMBER
TITLE
REVISION
E 11173-171-005
Westinghouse Electric corporation General Arrangement
Plan
001
E 11373-101-005
Westinghouse Electric Corporation Closure Head
Assembly
002
E 1455E85,
Sheet 1
Westinghouse Electric Corporation Closure Head (SAP)
General Assembly
001
E 6467E69
Wolf Creek Simplified Head Assembly Radiation Shield
Assembly
006
M 164-00043
Mirror Insulation
W008
M-189-50EJ-02-04
Residual Heat Removal B Train RHR Pump Suction
00
PROCEDURES
NUMBER
TITLE
REVISION
AI 16F-001
Evaluation of Boric Acid Leakage
5
AI 16F-002
Boric Acid Leakage Management
5
Boric Acid Corrosion Control Program
5
A-6
Attachment 1
NUMBER
TITLE
REVISION
Steam Generator Management
AP-10-100
14
AP-10-101
Control of Transient Ignition Sources
12
AP-10-102
Control of Combustible Materials
13
AP-21I-001
8
APF 28D-001
Self-Assessment Process
11
PDI-ISI-254-SE-
NB
Remote Inservice Examination of Reactor Vessel
Nozzle to Safe End, Nozzle to Pipe, and Safe end to
Pipe Welds Using the Nozzle Scanner
1
PDI-UT-1
PDI Generic Inspection Procedure for the Ultrasonic
Examination of Ferritic Pipe Welds
D
PDI-UT-2
PDI Generic Inspection Procedure for the Ultrasonic
Examination of Austenitic Pipe Welds
C
PDI-UT-6
PDI Generic Inspection Procedure for the Ultrasonic
Examination of Reactor Pressure Vessel Welds
F
QCP-20-501
8
QCP-20-502
8
QCP-20-503
UT Thickness-Wall Thin
3
QCP-20-504
UT For Flaw Detection
5
QCP-20-508
4
QCP-20-510
Ultrasonic Instrument Linearity Verification
3
QCP-20-511
1B
QCP-20-514
ET Testing
5B
QCP-20-516
PT/NON-STD Temp
05
QCP-20-517
RT Wall Thinning
2A
QCP-20-521
UT Profile and Plotting
1B
QCP-20-522
Ultrasonic Examination of Ferritic Piping Welds
1B
QCP-20-523
Ultrasonic Examination of Austenitic Piping Welds
1B
QCP-20-527
UT- Soldering
1
QCP-20-540
VT-1 Exam
0B
QCP-20-541
VT-3 Exam
2
QCP-20-543
Fluorescent Dye PT Exam
1
A-7
Attachment 1
NUMBER
TITLE
REVISION
SG-CDME-08-15
Wolf Creek RF16 Condition Monitoring Assessment and
Operational Assessment, April 2008
1
SG-SGMP-09-9
Steam Generator Degradation Assessment for Wolf
Creek, RF17 Refueling Outage, October 2009
0
STN PE-040D
RCS Pressure Boundary Integrity Walkdown
3
STN PE-040G
Transient Event Walkdown
0
STS PE-040E
RPV Head Visual Inspection
2
UT-95
Ultrasonic Examination of Austenitic Piping Welds
3
WCRE-18
Boric Acid Corrosion Control Program Plan
1
WORK ORDERS
08-304695-000
09-313385-000
09-320908-000
09-320918-000
08-310117-000
09-318982-001
09-320910-000
09-320918-001
08-310119-000
09-319416-002
09-320910-001
09-320919-000
08-310136-000
09-320490-000
09-320911-000
09-321389-000
08-311159-000
09-320505-000
09-320912-000
08-311161-000
09-320891-000
09-320913-000
WORK REQUESTS
09-076556
09-076676
09-076711
09-076707
09-076561
09-076307
09-076705
09-076712
09-076710
09-076706
MISCELLANEOUS
NUMBER
TITLE
REVISION / DATE
Steam Generator data Analysis Desktop
Instruction
4
SGAMP Self Assessment, Steam Generator Asset
Management Program
October 17, 2008
Boric Acid Corrosion Control Program 2009 3rd
Quarter Inspection/Monitoring Report
October 13, 2009
A-8
Attachment 1
NUMBER
TITLE
REVISION / DATE
Boric Acid Leakage Screening/Evaluation for
Component EMHV8888
October 8, 2008
Boric Acid Leakage Screening/Evaluation for
Component BGHCV0182
January 5, 2009
Boric Acid Leakage Screening/Evaluation for
Component EP8956C
October 19, 2009
Boric Acid Leakage Screening/Evaluation for
Component EMHV8924
October 20, 2009
Boric Acid Leakage Screening/Evaluation for
Component BBPV8702A
October 14, 2009
Boric Acid Leakage Screening/Evaluation for
Component BGHCV0128
July 9, 2009
Boric Acid Leakage Screening/Evaluation for
Component EMV0175
April 8, 2009
Boric Acid Leakage Screening/Evaluation for
Component BBC5413
April 7, 2009
Boric Acid Leakage Screening/Evaluation for
Component HETCV0250
January 13, 2009
Boric Acid Leakage Screening/Evaluation for
Component ECV0048
January 13, 2009
Boric Acid Leakage Screening/Evaluation for
Component ECV0157
January 12, 2009
Boric Acid Leakage Screening/Evaluation for
Component BBHV8351B
January 12, 2009
Boric Acid Leakage Screening/Evaluation for
Component EJ8730A
January 12, 2009
Boric Acid Leakage Screening/Evaluation for
Component EJV0128
January 12, 2009
Boric Acid Leakage Screening/Evaluation for
Component EJFE0619
January 12, 2009
Boric Acid Leakage Screening/Evaluation for
Component BG8405A
January 9, 2009
Boric Acid Leakage Screening/Evaluation for
Component ENV0115
January 9, 2009
Boric Acid Leakage Screening/Evaluation for
Component BGV0526
January 8, 2009
A-9
Attachment 1
NUMBER
TITLE
REVISION / DATE
Boric Acid Leakage Screening/Evaluation for
Component BBV0357
January 5, 2009
Boric Acid Leakage Screening/Evaluation for
Component BGFCV0110A
January 59, 2009
Boric Acid Leakage Screening/Evaluation for
Component BBV0007
October 15, 2009
Ultrasonic Instrument Calibration Data Record and
Certification for Panametrics, Epoch 4,
SN 081574401
September 2, 2009
Transducer Certification for Krautkramer, 113-222-
591, SN 00V0JM
April 26, 2002
Transducer Certification for Krautkramer, 113-222-
591, SN 00V49N
May 16, 2002
Thermometer Certification for PTC, 312F,
SNs 265095, 265109, 265113
January 6, 2009
Krautkramer Transducer Certification, 113-224-
5591, SN SC0123
January 11, 2008
Krautkramer Transducer Certificate of Conformity,
113-234-591, SN SD0172
December 3, 2007
Ultrasonic Instrument Calibration Data Record and
Certification for Krautkramer, USN 60 SW, SN
01R5NW
August 24, 2009
APF 28D-001-02
Self Assessment Report SEL 04-038 , Steam
Generator Program
4
APF-10-102-01
Transient Combustible Materials Permit
3
AWJ003
Ultrasonic Calibration/Examination Sheet for RPV
Meridonal Weld, ISI Number CH-101-104-C
October 22, 2009
AWJ004
Ultrasonic Calibration/Examination Sheet for RPV
Meridonal Weld, ISI Number CH-101-104-B
October 22, 2009
ET 05-0014
Docket 50-482: 10 CFR 50.55a Request Number
I3R-03 for the Third Ten-Year Interval Inservice
Inspection (ISI) Program - Request for Relief to
Allow Use of Alternate Requirements for Snubber
Inspection and Testing
September 28, 2005
ET 06-0010
Docket 50-482: Inservice Inspection Program Plan
for the Third Ten-Year Interval and 10 CFR 50.55a
Requests I3R-01, I3R-02, and I3R-04
March 2, 2006
A-10
Attachment 1
NUMBER
TITLE
REVISION / DATE
ET 06-0021
Docket No. 50-482: 10 CFR 50.55a Request I3R-
05, Installation and Examination of Full Structural
Weld Overlays for Repairing/Mitigating Pressurizer
Nozzle-to-Safe End Dissimilar Metal Welds and
Adjacent Safe End-to-Piping Stainless Steel Welds
May 19. 2006
ET 06-0042
Docket 50-482: Wolf Creek Nuclear Operating
Corporations Response to the September 20,
2006 NRC Request for Additional Information
Regarding 10 CFR 50.55a Request I3R-05
September 27, 2006
ET 06-0043
Docket 50-482: Wolf Creek Nuclear Operating
Corporations Response to NRC Request for
Additional Information Regarding 10 CFR 50.55a
Request I3R-01
October 5, 2006
ET 06-0044
Docket 50-482: Wolf Creek Nuclear Operating
Corporations Revised Commitment Regarding 10
CFR 50.55a Request I3R-05
October 2, 2006
ET 06-0058
Docket No. 50-482: Wolf Creek Nuclear Operating
Corporations Response to the Second NRC
Request for Additional Information Regarding 10
CFR 50.55a Request I3R-01
December 20, 2006
ET 08-0044
Docket No. 50-482: 10 CFR 50.55a Request I3R-
06, Alternative to Examination Requirements of
ASME Section XI for Class 1 Piping Welds
Examined from the Inside of the Reactor Vessel
September 16, 2008
ET 09-0016
Docket No. 50-482: Revision to Technical
Specifications 5.5.9, Steam Generator (SG)
Program, and TS 5.6.10, Steam Generator Tube
Inspection Report, for a Permanent Alternate
Repair Criterion
June 2. 2009
ET 09-0021
Docket No. 50-482: Response to Request for
Additional Information Related to License
Amendment Request for a Permanent Alternate
Repair Criterion to Technical Specification 5.5.9,
Steam Generator (SG) Program
August 25, 2009
ET 09-0023
Docket No. 50-482: Response to Request for
Additional Information Related to License
Amendment Request for a Permanent Alternate
Repair Criterion to Technical Specification 5.5.9,
Steam Generator (SG) Program
September 3, 2009
A-11
Attachment 1
NUMBER
TITLE
REVISION / DATE
ET 09-0024
Docket No. 50-482: Response to Request for
Clarifications in Response to Application for
Withholding Proprietary Information from Public
Disclosure (TAC NO. ME1393)
September 3, 2009
ET 09-0025
Docket No. 50-482: Revision to Technical
Specification (TS) 5.5.9, Steam Generator (SG)
Program, and TS 5.6.10, Steam Generator Tube
Inspection Report
September 15, 2009
I-ENG-023
Steam Generator Data Analysis Guidelines
8
JEW014
Ultrasonic Calibration/Examination Sheet for RHR
Pipe to Pipe Weld , ISI Number EJ-04-F019
October 22, 2009
JEW015
Ultrasonic Calibration/Examination Sheet for
SI/HPCI Pipe to Elbow Weld, ISI Number EM-03-
S015-B
October 22, 2009
M-12KJ04
Piping and Instrumentation Diagram Standby
Diesel Generator B Lube Oil System
13
M-12KJ06
Piping and Instrumentation Diagram Standby
Diesel Generator B Lube Oil System
13
M-13EF08
Piping Isometric Essential Service Water- Diesel
Generator Bldg.
1
QCF 20-510-01
Ultrasonic Instrument Linearity Form
2
QCF-20-100-01
Contractor Certification Review
2
QCF-20-504-02
Ultrasonic Flaw Detection Data Sheet
2
QCF-20-504-06
Ultrasonic Flaw Detection Calibration Data Sheet
0
SAP-+PT-09
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
SAP-+PTUB-09
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
A-12
Attachment 1
NUMBER
TITLE
REVISION / DATE
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
Steam Generator Eddy Current Inspection Multi-
Frequency Eddy Current Parameters
0
SEL 04-038
Steam Generator Program
4
SG-CDME-08-15
Wolf Creek RF16 Condition Monitoring
Assessment and Operational Assessment, April
2008
1
SG-CDME-09-1
Wolf Creek Steam Generator Secondary Side
Condition Monitoring and Operational Assessment
for Fuel Cycle and Refueling Outage 17
0
SG-SGMP-09-9
Steam Generator Degradation Assessment for
Wolf Creek, RF17 Refueling Outage, October 2009
0
WDI-LTR-
ENG-09-0016
Technical Justification of the Impact of Using
Tap/Demineralized Water for UT System
Calibration and Borated Reactor Cavity Water for
RVISI UT Examinations.
0
A-13
Attachment 1
Section 1R12: Maintenance Effectiveness
MISCELLANEOUS
NUMBER
TITLE
REVISION /
DATE
EG-01
Maintenance Rule Database - Component Cooling
Water - Engineered Safety Features System Cooling
n/a
EG-03
Maintenance Rule Database - Component Cooling
Water System - RCP Thermal Barrier Cooling
n/a
EG-07
Maintenance Rule Database - Component Cooling
Water System - ESW Frazil Ice Prevention
n/a
M-11EG02
System Flow Diagram Component Cooling Water
System
2
M-762-001-02
Nuclear Instrumentation System Source Range N-31
Functional Block Diagram
7
PIR 2004-1625
Two Source Range Channels are Required to
Perform Core Alterations During a Refueling Outage
June 22,
2004
Maintenance Rule Database - Source Range
Nuclear Instrumentation
n/a
Maintenance Rule Database - Intermediate Range
Nuclear Instrumentation
n/a
OFN PK-029
Loss of Non-Vital 125 VDC Bus PK01, PK02, PK03,
PK4, and Annunciators
15
STS IC-232
Channel Operational Test Nuclear Instrumentation
System Source Range N-32 Protection Set II
15
AI 28A-023
Evaluation of Maintenance Rule Functional Failure
1
7
EDI 23M-050
Establishing Performance Criteria for Structures,
Systems and Components with the Scope of the
Maintenance Rule
3
WCN-7328
Report on ECAD Testing at Wolf Creek Generating
Station
October 28,
2009
Functional Failure Determination (EDI 23M-050)
April 24,
2005
Maintenance Rule Expert Panel Meeting Minutes
February 18
, 1999
A-14
Attachment 1
NUMBER
TITLE
REVISION /
DATE
Maintenance Rule Expert Panel Meeting Minutes
April 10,
2000
Maintenance Rule Expert Panel Meeting Minutes
April 24,
2000
WORK ORDERS
NUMBER
TITLE
REVISION /
DATE
WO 07-293925-000
Replace Electrolytic Capacitors or Replace Power
Supply NIS Source Range Hi Voltage Power Supply
March 31,
2008
WO 08-302634-000
Perform STN IC-031 Source Range N-31 High Flux
at Shutdown Alarm Calibration
January 12,
2008
WO 08-302635-000
Perform STN IC-032 Source Range N-32 High Flux
at Shutdown Alarm Calibration
January 12,
2008
WO 08-305403-000
Refuel 16 Perform STN IC-031 Source Range N-31
High Flux at Shutdown Alarm Calibration
April 11,
2008
WO 08-305404-000
Refuel 16 Perform STN IC-032 Source Range N-32
High Flux at Shutdown Alarm Calibration
April 11,
2008
WO 08-310573-000
Replace Electrolytic Capacitors or Replace Power
Supply
August 13,
2009
WO 09-314187-000
Retorque CCW Pump to Motor Coupling Bolts
February
12, 2009
WO 09-316487-000
Troubleshoot IR SE NI-36 to Determine Why it Hung
Up Following RX Trip on 4/28 and Repair as
Necessary
April 28,
2009
WO 09-318691-000
Troubleshoot CCW Return from RCP Thermal
Barrier High Flow Setpoint
September
22, 2009
WO 09-320716-000
Refuel 17. Perform Detector and Cable Integrity
Checks for SR, IR, and PR NIS Channels
October 10,
2009
WO 09-320874-000
Troubleshoot Source Range Channel 31 to
Determine Why it Failed After it was Energized
October 10,
2009
WO 09-320874-001
Replace High Voltage Power Supply (NQ101) in
N-31 Source Range during partial STS IC-431
October 10,
2009
WO 09-320874-005
Replace R150 in N-31
October 10,
2009
A-15
Attachment 1
NUMBER
TITLE
REVISION /
DATE
WR 09-076482
During the Performance of STS IC-432 the Two-Phi
Meter Failed to Alarm Annunciator
October 24,
2009
WORK ORDERS
WO 05-270366-000
WO 05-270366-006
WO 06-288260-000
CONDITION REPORTS
CR 20052
CR 01880
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
MISCELLANEOUS
NUMBER
TITLE
REVISION /
DATE
Outage Risk Management
11
Operational Risk Assessment Program
14A
7
APF 22B-001-02
Daily Shutdown Risk Assessments for RFO 17
8
AI-07A-008
Lake Water Chemical Treatment Program
16
Lake Water Systems Corrosion and Fouling
Mitigation Program
2
SYS EF-300
ESW/Service Water Macrofoul Treatment
22
WCEM-06-005
Zebra Mussel Monitoring - 2008 Report and 2009
Plan
9
RNT 745679/0
Assessment of the Potential Impact of Zebra
Mussels on the Wolf Creek Power Plant and
Recommendations for Control
July 20, 2009
900030
Customer Assembly Neutron Flux Monitor System,
SNUPPS Generating Stations, Callaway 1 (Union
Elec Co) and Wolf Creek (Kansas Gas & Electric)
F
CCP 013096
Instrument Setpoints for RCP Thermal Barrier
Isolation and EGHV0062 Valves
1
A-16
Attachment 1
NUMBER
TITLE
REVISION /
DATE
EQDP-ESE-47A
Boron Dilution Fix: Source/Intermediate Range
Neutron Detector
0
M-762-00018-W03
Source and Intermediate Range Detector Assembly
August 19,
1988
NY-10042
Class 1E Qualified Proportional Counter and
Compensated Ionization Chamber Insulated
Assembly
September
1990
NY-10044
Qualified* Class 1E BF3 Proportional Counter
Assembly
September
1990
Source Range Nuclear Instrument SEN0031
00
Source Range Nuclear Instrument SEN0032
00
USAR 9.4.6
Containment HVAC
19
STS AE-205
Feedwater System Inservice Valve Test
November 120
09
Wolf Creek Technical Specifications
November 182
009
APF 22C-003-01
Operational Risk Assessment
November 172
009
n/a
Wolf Creek Operations Logs: Control Room Log
n/a
n/a
Wolf Creek Operations Logs: Equipment Out of
Service Log
n/a
n/a
Technical Specification LCO 3.0.4 Mode Change
Review Form - TDAFWP Inoperable
November 17,
2009
CONDITION REPORTS
NUMBER
TITLE
REVISION /
DATE
CR 19528
SOER 09-1: Shutdown Safety
September 1,
2009
CR 21286
ESW Self Cleaning Strainer Tubes Retain Debris
October 28,
2009
CR 19282
Source Range N31 Indication During Loss of Cavity
Cooling
August 20,
2009
A-17
Attachment 1
NUMBER
TITLE
REVISION /
DATE
CR 20208
Source Range Detector Operability Question
September 30,
2009
CR 20325
Effect on Cavity Components with Loss of Cavity
Cooling
October 6,
2009
CR 21906
T/S Log Entries Related to Entering Mode 3 with
TDAFWP OOS
November 19,
2009
CR 21926
Inconsistent Directions for Protected Train Signs in
Mode 3
November 19,
2009
CR 21286
ESW Self Cleaning Strainer Tubes Retain Debris
October 28,
2009
WORK ORDERS
NUMBER
TITLE
REVISION /
DATE
WO 09-322198-000
Create a RM/Repetitive Task to Open the ESW Self
Cleaning Strainers and Clean the Porous Strainer
Tubes
November 12,
2009
WO 09-319411-001
Source Range NI 31 Indication is Trending Up.
Evaluate Condition to Determine Cause
August 22,
2009
Section 1R15: Operability Evaluations
MISCELLANEOUS
NUMBER
TITLE
REVISION /
DATE
Source Range Nuclear Instrument SEN0031
00
AI-07A-008
Lake Water Chemical Treatment Program
16
Lake Water Systems Corrosion and Fouling
Mitigation Program
2
AP 28-001
Operability Evaluations
17
Technical Specification Operability
January 13,
2010
SYS EF-300
ESW/Service Water Macrofoul Treatment
22
WCEM-06-005
Zebra Mussel Monitoring - 2008 Report and 2009
Plan
9
A-18
Attachment 1
NUMBER
TITLE
REVISION /
DATE
RNT 745679/0
Assessment of the Potential Impact of Zebra
Mussels on the Wolf Creek Power Plant and
Recommendations for Control
July 20,
2009
900030
Customer Assembly Neutron Flux Monitor System,
SNUPPS Generating Stations, Callaway 1 (Union
Elec Co) and Wolf Creek (Kansas Gas & Electric)
F
CCP 013096
Instrument Setpoints for RCP Thermal Barrier
Isolation and EGHV0062 Valves
1
EQDP-ESE-47A
Boron Dilution Fix: Source/Intermediate Range
Neutron Detector
0
M-762-00018-W03
Source and Intermediate Range Detector Assembly
August 19,
1988
NY-10042
Class 1E Qualified Proportional Counter and
Compensated Ionization Chamber Insulated
Assembly
September
1990
NY-10044
Qualified* Class 1E BF3 Proportional Counter
Assembly
September
1990
Source Range Nuclear Instrument SEN0031
00
Source Range Nuclear Instrument SEN0032
00
USAR 9.4.6
Containment HVAC
19
STS AE-205
Feedwater System Inservice Valve Test
November
9, 2009
n/a
Wolf Creek Operations Logs: Control Room Log
n/a
n/a
Wolf Creek Operations Logs: Equipment Out of
Service Log
n/a
Wolf Creek Technical Specifications
November
18, 2009
n/a
Technical Specification LCO 3.0.4 Mode Change
Review Form - TDAFWP Inoperable
November
17, 2009
APF 22C-003-01
Operational Risk Assessment
November
17, 2009
M-089-K027-06
Byron Jackson Report DC-1104
3
EF-S-043
Determine the Stress in the Essential Service Water
Pump (PEF01A) column housing using specified
maximum deflection
0
A-19
Attachment 1
CONDITION REPORTS
CR 19282
CR 20208
CR 20325
CR 21906
CR 22798
CR 21574
CR 21400
CR 21572
CR 21926
WORK ORDERS
NUMBER
TITLE
REVISION /
DATE
WO 09-319411-001
Source Range NI 31 Indication is Trending Up.
Evaluate Condition to Determine Cause
August 22,
2009
WO 09-322198-000
Section 1R18: Plant Modifications
NUMBER
TITLE
REVISION
AP 05-010
Design Drawings
6
Calculations
12
Design Inputs
1
AP 05-002
Dispositions and Change Packages
8
AP 05-005
Design, Implementation & Configuration of
Modifications
13
WCRE-01
Total Plant Setpoint Document
32
CCP 013096
Instrument Setpoints for RCP Thermal Barrier
Isolation and EGHV0062 Valves
01
AP 05-013
Review of Vendor Technical Documents
7A
NP 92-0996
Interoffice Correspondence from C. R. Morris, CCW
Low Transient (PMR 03580) Meeting
5/21/92
EG-M-016
Time Delay for Isolation of CCW High Flow to RCP
Thermal Barriers
1
M-738-0032-02
Functional Requirements and Design Criteria
Standard Single and Twin Units 212, 312, 412 Plants
Component Cooling System
3
CONDITION REPORT
CR 16243
A-20
Attachment 1
Section 1R19: Postmaintenance Testing
NUMBER
TITLE
REVISION
STN EF-201
ESW System Valve Test
2A
Post Maintenance Testing Development
8
Motor Operated Valve Program
2
STS IC-608A
Slave Relay Test K608A Train A Safety Injection
18
CONDITION REPORT
CR 19670
WORK ORDERS
06-291566-001
06-291566-012
09-316118-001
Section 1R20: Refueling and Other Outage Activities
NUMBER
TITLE
REVISION
WCRE-16
Inservice Inspection Program Plan Wolf Creek
Generating Station Interval 3
4
WCRE-23
Inservice Inspection Classification Basis Document
Wolf Creek Generating Station Interval 3
3/24/09
SYS BB-112
Vacuum Fill of the RCS
27
GEN 00-008
Reduced Inventory Operations
19
GEN 00-009
Refueling
23
GEN 00-003
Hot Standby to Minimum Load
73
SYS BB-215
RCS Drain Down with Fuel in Reactor
23A
STS RE-002
Determination of Estimated Critical Position
18
APF 19C-002-01
Wolf Creek Generating Station Fuel Transfer
Authorization
0
APF 22B-001-02
Daily Shutdown Risk Assessment
8
RWP 092602
Radiation Work Permit
1
RWP 092602
ALARA Review Package
7
RWP 091102
Radiation Work Permit
0
RWP 091102
ALARA Review Package
7
A-21
Attachment 1
NUMBER
TITLE
REVISION
RWP 091102
Radiation Work Permit
0
EID-0003
Refuel Level Indications
2
M-19BG24
Hanger Location DWG. Small Pipe CVCS Auxiliary
Spray Reactor Building
7
M-15BG21
Hanger Location DWG. Small Pipe CVCS - Normal
& Alternate Charging Reactor Building
12
M-12BG01
Piping & Instrumentation Diagram Chemical and
Volume Control System
14
M-12BB02
Piping & Instrumentation Diagram Reactor Coolant
System
16
n/a
Investigation into the Extent of Condition Related to
Linear Indications Discovered on Pressurizer
Auxiliary Spray Line at Wolf Creek Generating
Station
November 4,
2009
CONDITION REPORTS
CR 20528
CR 20628
CR 21366
CR 21387
CR 21719
CR 20622
CR 20893
WORK ORDERS
WO 09-321462-015
WO 08-303356-004
WO 09-321902-001
WO 08-303356-001
Section 1R22: Surveillance Testing
MISCELLANEOUS
NUMBER
TITLE
REVISION
STS AL-210A
MDAFW Pump A inservice check valve test
10
WCOP 02
Inservice Testing Program for Pumps and Valves
14
ASME code testing of pumps and valves
7
Surveillance Testing
10
IST Basis Document
3
A-22
Attachment 1
STS AL-212
MD AFP Comprehensive Pump Testing Flow Path
Verification & Check Valve Testing
14
ASME Section XI System Pressure Testing
7
QCP 20-520
Pressure Test Examination
8A
STS PE-007
Periodic Verification of Motor Operated Valves
3
AI 23D-002
MOV Calculation Guidelines
2
AI 23D-003
MOV Trending and Periodic Verification Program
1
Program Plan for Containment Leakage
Measurement
12
NEI Guideline for Implementing the Performance
Based Guideline of Appendix J
M-12AL01
Piping and Instrumentation Drawing Auxiliary
10
M-12AE01
Piping and Instrumentation Drawing Feedwater
37
M-12EF01
Piping and Instrumentation Drawing Essential
21
M-12EF02
Piping and Instrumentation Drawing Essential
25
M-724-00784
EJHV8811A/B Pressure Locking Bypass
W02
M-724-00696
Motor Operated Gate Valve
W06
M-12EJ01
Piping and Instrumentation Drawing Residual Heat
Removal System
43
CONDITION REPORTS
CR 1994-0881
CR 1998-0422
CR 2001-2237
CR 2005-1899
CR 2005-3545
CR 20723
CR 21308
CR 21343
WORK ORDERS
WO 05-278104-012
WO 09-321637-000
WO 09-321637-002
WO 09-321637-001
A-23
Attachment 1
Section 2OS1: Access Controls to Radiologically Significant Areas
CORRECTIVE ACTION DOCUMENTS
20878
15485
14874
19405
19409
21004
20973
20987
10196
9627
2008-1576
21029
20976
5633
PROCEDURES
NUMBER
TITLE
REVISION
Use of Temporary Shielding or Locked High Radiation Areas
and Very High Radiation Area Barricades
10
RPP 02-105
33
AP 22-01
Conduct of Pre-Job and Post-Job Briefs
9A
Access to Locked High or Very High Radiation Areas
20
SEC 01-206
High Security Key Control and Issue
32
Radiography Guidelines
12
RADIATION WORK PERMITS
93021
9220
92602
93230
Section 4OA2: Identification and Resolution of Problems
MISCELLANEOUS
NUMBER
TITLE
REVISION
SYS AF-200
High Pressure Heater Operations
8
AP 21-001
Conduct of Operations
43
Reactivity Management Program
13
CONDITION REPORTS
CR 18034
CR 04293
CR 2001-2255
A-24
Attachment 1
Section 40A5: Other Activities (TI-172 Dissimilar Metal Welds)
MISCELLANEOUS
NUMBER
TITLE
REVISION
UT-95
Ultrasonic Examination of Austenitic Piping Welds
3
WCRE-24
WESDYNE Year 2009 Reactor Vessel Nozzle Safe-
end Examinations Program Plan
0
WDI-CAL-102
Calibration Inspection Procedure for PCI Eddy
Current Card
1
WDI-EQPT-1021
Installation and Removal of the WESDYNE Nozzle
Scanner (SQUID)
4
WDI-EQPT-1022
Reactor Vessel Nozzle Scanner Setup and Checkout
2
WDI-STD-146
ET Examination of Reactor Vessel Pipe Welds Inside
Surface
9
A2-1
Attachment 2
Attachment 2
Significance Determination Process for Noncited Violation 2009005-16: Operator Actions
Disable Circuit Breaker Coordination and Could Initiate Secondary Fires
Introduction
This attachment discusses the risk significance of Noncited Violation 2009005-16. This
document discusses the methods, assumptions, and results of the significance determination
process.
Methods
The significance of this finding was evaluated using the significance determination process in
Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process,
because it affected fire protection defense-in-depth strategies involving post-fire safe shutdown
systems.
This finding was associated with the post-fire safe shutdown category. Specifically, the
performance deficiency resulted in loss of power to equipment assumed affected in the safe
shutdown analysis and could initiate secondary fires in plant locations outside of the initial fire
area. The inspectors assigned this finding a high degradation rating since the affected circuit
breakers would not provide any fire protection benefit and would receive no fire protection
credit.
The inspectors assigned a duration factor of 1.00 since the performance deficiency existed for
greater than 30 days. The inspectors performed a Phase 1 quantitative screening using generic
fire ignition frequencies for the 13 fire areas of concern. The results of this Phase 1 screening
concluded that a Phase 2 evaluation was needed.
The inspectors followed the guidance in Manual Chapter 0609, Appendix F, Fire Protection
Significance Determination Process, to perform the Phase 2 evaluation. In accordance with
Appendix F, the inspectors used several spreadsheets from NUREG-1805, Fire Dynamics
Tools (FDTs) Quantitative Fire Hazard Analysis Methods for the U.S. Nuclear Regulatory
Commission Fire Protection Inspection Program. The inspectors used the following
spreadsheets in the Phase 2 evaluation:
02.1_Temperature_NV
02.2_Temperature_FV
05.1_Heat_Flux_Calculations_Wind_Free
9_Plume_Temperature_Calculations
10_Detector_Activation_Times
The inspectors used these spreadsheets to determine the temperature of the plume, the
temperature of the hot gas layer, and the activation time of the detection systems.
A2-2
Attachment 2
Assumptions
The inspectors used the following assumptions during the Phase 2 evaluation:
1. The inspectors assumed that the smoke detectors were located at the maximum possible
distance from the ignition source given the spacing of detectors in each fire area.
2. The inspectors assumed that the detection systems worked properly to detect the fire.
3. The inspectors assumed that the fixed suppression systems would fail to suppress the fire.
The inspectors assumed the only method of suppressing the fire was manual fire fighting by
the fire brigade.
4. The inspectors assumed that operators would take the prescribed mitigating actions during
any fire scenario that progressed to the point where the power-operated relief valve
spuriously opened and its block valve failed to close. These mitigating actions include steps
for the operators to remove the 125 Vdc control power to the train affected by the fire.
5. The licensee concluded that an inter-cable hot short in thermoset cables was needed for a
power-operated relief valve to spuriously open. Using guidance in Appendix F, Table 2.8.3,
PSP Factors Dependent on Cable Type and Failure Mode, the inspectors assumed the
conditional probability of an inter-cable hot short given a fire scenario that damaged the
thermoset cables was 0.02.
6. The licensee performed an evaluation of the equipment affected by the loss of 125 Vdc
control power. The inspectors reviewed the evaluation and concluded that the loss of
125 Vdc control power did not directly affect the equipment relied upon for post-fire safe
shutdown in each of the fire areas.
7. Without any additional knowledge of the cable routing for the set of affected equipment, the
inspectors assumed that cables for the affected equipment were routed in the same cable
trays as cables for the power-operated relief valves or the associated block valves.
8. The inspectors assumed that any equipment that experienced a loss of dc control power
would experience a short to ground that would lead to a secondary fire in another plant
location.
9. The inspectors assumed that a secondary fire in another plant location would damage the
equipment relied upon for safe shutdown in the original fire area and would lead to core
damage. As such, the inspectors provided no credit for the designated post-fire safe
shutdown equipment.
10. The inspectors assumed that the change in core damage frequency associated with the
performance deficiency resulted from the increased likelihood of secondary fires because of
the loss of circuit breaker protection.
A2-3
Attachment 2
Evaluation
During the inspection, the licensee provided information for each of the 13 fire areas, with the
exception of the reactor building, which is not readily accessible during power operations. The
information provided included the location of the power-operated relief valve cables (targets); a
description and photographs of the nearest set of ignition sources near each target; and a
discussion of the room dimensions, ventilation, and fire protection features.
The inspectors performed a field walkdown to verify the information provided by the licensee. In
particular, the inspectors verified the spatial arrangement of the fire sources and targets as well
as the distances between each source and target. The inspectors used the zone of influence
described in Appendix F, step 2.3, Fire Scenario Identification and Ignition Source Screening,
to determine the fire sources that could lead to fire scenarios that damaged the power-operated
relief valves. These scenarios involved cases where the initial fire directly damaged the cables
as well as situations where the fire propagated through a set of cable trays that contained the
power-operated relief valve cables.
The inspectors reviewed the Wolf Creek Generating Station Individual Plant Examination of
External Events, the fire hazards analysis, and drawings showing the cable routing for the
power-operated relief valves and their associated block valves inside containment. The
inspectors screened out fire scenarios involving the reactor building given the lack of ignition
sources located under the power-operated relief valve cables.
The inspectors used the Fire Dynamics Tools to calculate the temperature of the hot gas layer
in each fire area. The inspectors concluded that the hot gas layer would never reach a high
enough temperature to damage the thermoset cables. Therefore, the inspectors screened out
all fire scenarios involving a hot gas layer that would damage the power-operated relief valve.
Based on the walkdown and hot gas layer evaluations, the inspectors created an initial set of
five fire sources involving nine fire scenarios that could lead to core damage. The scenarios are
listed in the following table. The categories assigned to components and values determined
related to the Source Category, Fire Ignition Frequency, Heat Release Rate, and Severity
Factor used to characterize the fire scenarios in the significance determination process are
described in Manual Chapter 0609, Appendix F. The inspectors summarized the fire scenarios
in Table 1, Initial Fire Scenarios.
Fire Scenarios
The detailed evaluation of each ignition source is provided below. In each of these scenarios,
the inspectors used the Fire Dynamics Tools to calculate the time to damage the
power-operated relief valve and block valve cables and the time to detect the fire. As noted
above, the inspectors assumed that the fixed suppression systems failed to suppress the fire
and the only method of suppression resulted from manual fire fighting from the fire brigade.
The inspectors used Manual Chapter 0609, Appendix F, Attachment 8, Table A8.1,
Non-Suppression Probability Values for Manual Fire Fighting Based on Fire Duration Time to
Damage after Detection) and Fire Type Category to calculate the non-suppression probability
for manual fire fighting. The results are different for each scenarios based on the type of fire
and the length of time between the detection of the fire and damage to the cables.
A2-4
Attachment 2
Table 2. Initial Fire Scenarios
Scenario
Number
Ignition
Source
Source
Description
(Fire Area)
Source
Category
Initial Fire
Ignition
Frequency
Heat
Release
Rate
Severity
Factor
Fire
Targets
Nearest
Distance
1
RP-333
Relay
Panel
(A-16)
General
Control
Cabinet
6.00E-5
200 kW
0.9
4U3B
4U3A
4.8 ft
2
RP-333
Relay
Panel
(A-16)
General
Control
Cabinet
6.00E-5
650 kW
0.1
4U3B
4U3A
4.8 ft
3
SK194B
Security
Panel
(A-16)
General
Electrical
Cabinet
6.00E-5
200 kW
0.1
4U3B
4U3A
5.0 ft
4
NG01B
(A-18)
General
Electrical
Cabinet
6.00E-5
70 kW
0.9
1U3J
1U3K
3.3 ft
5
NG01B
(A-18)
General
Electrical
Cabinet
6.00E-5
200 kW
0.1
1U3J
1U3K
3.3 ft
6
C-21
(Medium)
1.70E-4
70 kW
0.9
1C8H
1C8J
1.3 ft
7
C-21
(Medium)
1.70E-4
200 kW
0.1
1C8H
1C8J
1.3 ft
8
C-22
(Medium)
1.70E-4
70 kW
0.9
4C8E
4C8F
0.0 ft
9
C-22
(Medium)
1.70E-4
200 kW
0.1
4C8E
4C8F
0.0 ft
1. Source RP-333
Panel RP-333 is a relay panel located against a wall in Fire Area A-16. The top of the cabinet is
7 10 from the floor. The inspectors treated the relay panel as a general control cabinet with a
fire ignition frequency of 6.00E-5 and heat release rates of 200 kW and 650 kW.
The power-operated relief valve cables are located in cable tray 4U3B and the power-operated
relief valve block valve cables are located in cable tray 4U3A. Cable tray 4U3B is the third tray
and cable tray 4U3A is the fourth tray from the bottom of a stack of cable trays. The lowest
cable tray is located 11 8 from the floor.
Fire Area A-16 is protected by a single zone smoke detection system with a maximum distance
of 25 feet between detectors. Areas of cable tray concentration contain preaction sprinkler
systems for fixed fire suppression.
A2-5
Attachment 2
Scenario 1 - Heat Release Rate (200 kW)
The inspectors calculated a plume temperature of 1178°F, corresponding to a damage time of 1
minute for the lowest cable tray and a damage time of 10 minutes for the target set. The
inspectors calculated a detection time less than 1 minute. The inspectors assigned a
non-suppression probability for manual fire fighting of 0.35 for an electrical fire with 9 minutes
between the time to detection and time to damage.
Scenario 2 - Heat Release Rate (650 kW)
The inspectors calculated a plume temperature exceeding 2000°F, corresponding to a damage
time of 1 minute for the lowest cable tray and a damage time of 10 minutes for the target set.
The inspectors calculated a detection time less than 1 minute. The inspectors assigned a
non-suppression probability for manual fire fighting of 0.35 for an electrical fire with 9 minutes
between the time to detection and time to damage.
2. Source SK194B
Panel SK194B is a security panel located against a wall in Fire Area A-16. The top of the
cabinet is 7 8 from the floor. The inspectors treated the security panel as a general electrical
cabinet with a fire ignition frequency of 6.00E-5 and heat release rates of 70 kW and 200 kW.
Using a zone of influence, the inspectors screened out the lower heat release rate during the
plant walkdown.
The power-operated relief valve cables are located in cable tray 4U3B and the power-operated
relief valve block valve cables are located in cable tray 4U3A. Cable tray 4U3B is the third tray
and cable tray 4U3A is the fourth tray from the bottom of a stack of cable trays. The lowest
cable tray is located 11 8 from the floor.
Fire Area A-16 is protected by a single zone smoke detection system with a maximum distance
of 25 feet between detectors. Areas of cable tray concentration contain preaction sprinkler
systems for fixed fire suppression.
Scenario 3 - Heat Release Rate (200 kW)
The inspectors calculated a plume temperature of 1103°F, corresponding to a damage time of 1
minute for the lowest cable tray and a damage time of 10 minutes for the target set. The
inspectors calculated a detection time less than 1 minute. The inspectors assigned a
non-suppression probability for manual fire fighting of 0.35 for an electrical fire with 9 minutes
between the time to detection and time to damage.
3. Source NG01B
Panel NG01B is a 600V motor control center located in the open in Fire Area A-18. The top of
the cabinet is 7 8 from the floor. The inspectors treated the motor control center as a general
electrical cabinet with a fire ignition frequency of 6.00E-5 and heat release rates of 70 kW and
200 kW.
A2-6
Attachment 2
The power-operated relief valve cables are located in cable tray 1U3J and the power-operated
relief valve block valve cables are located in cable tray 1U3K. Cable tray 1U3J is the third tray
and cable tray 1U3K is the second tray from the bottom of a stack of cable trays. The lowest
cable tray is located 9 11 from the floor.
Fire Area A-18 is protected by a cross zone smoke detection system with a maximum distance
of 5 feet between detectors. A total flooding halon system provides fixed fire suppression.
Scenario 4 - Heat Release Rate (70 kW)
The inspectors calculated a plume temperature of 421°F. Since this is less than the damage
threshold of 625 °F for thermoset cables, the inspectors screened out this scenario from further
consideration.
Scenario 5 - Heat Release Rate (200 kW)
The inspectors calculated a plume temperature of 1019°F, corresponding to a damage time of 1
minute for the lowest cable tray and a damage time of 8 minutes for the target set. The
inspectors calculated a detection time less than 1 minute. The inspectors assigned a
non-suppression probability for manual fire fighting of 0.44 for an electrical fire with 7 minutes
between the time to detection and time to damage.
4. Transient Combustibles in Fire Area C-21 (Lower Cable Spreading Room)
Fire Area C-21 has a length of 88 and a width of 66. The area is protected by a single zone
smoke detection system with a maximum distance of 15 feet between detectors. A preaction
sprinkler system provides fixed fire suppression.
The power-operated relief valve cables are located in cable tray 1C8H and the power-operated
relief valve block valve cables are located in cable tray 1C8J. Cable tray 1C8H is the fifth tray
and cable tray 1U3K is the fourth tray from the bottom of a stack of cable trays. The lowest
cable tray is located 3 4 from the floor.
The inspectors determined that the cables for both valves were located in the same cable tray
stack for approximately 107 feet and the same cable tray for approximately 8 feet. For the
Phase 2 evaluation, the inspectors conservatively assumed that the cables for both valves were
located in the lower tray through the entire area. The inspectors assumed that the cables trays
were 2 feet wide.
For the following two scenarios, the inspectors adjusted the fire ignition frequency to account for
the limited areas where a fire could damage the targets. The inspectors modified the transient
combustible fire ignition frequency by multiplying the initial fire ignition frequency by a weighting
factor. The inspectors calculated the weighting factor by dividing the surface area of the cables
trays containing cables for both valves by the area of the fire area. The inspectors calculated a
modified fire ignition frequency for transient combustibles of 6.26E-6.
Scenario 6 - Heat Release Rate (70 kW)
The inspectors calculated a plume temperature of 943°F, corresponding to a damage time of 1
minute for the lowest cable tray and a damage time of 11 minutes for the target set. The
inspectors calculated a detection time less than 1 minute. The inspectors assigned a
A2-7
Attachment 2
non-suppression probability for manual fire fighting of 0.26 for transient fires with 10 minutes
between the time to detection and time to damage.
Scenario 7 - Heat Release Rate (200 kW)
The inspectors calculated a plume temperature exceeding 2000°F, corresponding to a damage
time of 1 minute for the lowest cable tray and a damage time of 11 minutes for the target set.
The inspectors calculated a detection time less than 1 minute. The inspectors assigned a
non-suppression probability for manual fire fighting of 0.26 for transient fires with 10 minutes
between the time to detection and time to damage.
5. Transient Combustibles in Fire Area C-22 (Upper Cable Spreading Room)
Fire Area C-22 has a length of 88 and a width of 67. The power-operated relief valve cables
are located in cable trays 4C8E, 4C8F, and 4C8G and the power-operated relief valve block
valve cables are located in cable trays 4C8F and 4C8G. These cable trays transition into the
control room through the floor of the upper cable spreading room.
The inspectors determined that cables for both valves were located in the same cable tray stack
for approximately 96 feet. For the Phase 2 evaluation, the inspectors conservatively assumed
that the cables for both valves were located in the same cable tray through the entire area and
that the cable tray was located on the floor. The inspectors assumed that the cables trays were
2 feet wide.
The inspectors did not credit the detection or suppression systems for the following two
scenarios since the fire was assumed to damage the target set immediately.
For the following two scenarios, the inspectors adjusted the fire ignition frequency to account for
the limited areas where a fire could damage the targets. The inspectors modified the transient
combustible fire ignition frequency by multiplying the initial fire ignition frequency by a weighting
factor. The inspectors calculated the weighting factor by dividing the surface area of the cables
trays containing cables for both valves by the area of the fire area. The inspectors calculated a
modified fire ignition frequency for transient combustibles of 5.54E-6.
Scenario 8 - Heat Release Rate (70 kW)
The inspectors postulated that the transient fire was located on the cable tray containing the
cables for both valves, corresponding to immediate damage for the target set. The inspectors
assigned a non-suppression probability for manual fire fighting of 1.00 for transient fires with no
time between detection and damage.
Scenario 9 - Heat Release Rate (200 kW)
The inspectors postulated that the transient fire was located on the cable tray containing the
cables for both valves, corresponding to immediate damage for the target set. The inspectors
assigned a non-suppression probability for manual fire fighting of 1.00 for transient fires with no
time between detection and damage.
A2-8
Attachment 2
Results
The inspectors used the Phase 2 evaluation to perform a bounding analysis and determine an
upper limit for the change in core damage frequency. In each of the scenarios described above,
the change in core damage frequency was bounded by the conditional core damage probability
(CCDP). The inspectors calculated the conditional core damage probability using the following
equation:
Short
Hot
n
Suppressio
Non
P
x
P
x
SF
x
FIF
=
where:
FIF denotes the fire ignition frequency
SF denotes the severity factor
n
Suppressio
Non
P
denotes the non-suppression probability
Short
Hot
P
denotes the probability of a hot short
The sum of the conditional core damage probabilities for each of the fire scenarios bounded the
total change in core damage frequency associated with this performance deficiency. The
inspectors calculated a bounding value of 6.58E-7 for the change in core damage frequency for
this performance deficiency. The results from the nine scenarios described above are
contained in the following table:
A2-9
Attachment 2
Table 3. Phase 2 Evaluation Results
Scenario
Number
Ignition
Source
Fire Ignition
Frequency
Severity
Factor
Probability of
Non-Suppression
Probability of
1
RP-333
6.00E-5
0.9
0.35
0.02
3.78E-7
2
RP-333
6.00E-5
0.1
0.35
0.02
4.20E-8
3
SK194B
6.00E-5
0.1
0.35
0.02
4.20E-8
4
NG01B
6.00E-5
0.9
N/A
N/A
N/A
5
NG01B
6.00E-5
0.1
0.44
0.02
5.28E-8
6
Transient Fire
(C-21)
6.26E-6
0.9
0.26
0.02
2.93E-8
7
Transient Fire
(C-21)
6.26E-6
0.1
0.26
0.02
3.26E-9
8
Transient Fire
(C-22)
5.54E-6
0.9
1.00
0.02
9.96E-8
9
Transient Fire
(C-22)
5.54E-6
0.1
1.00
0.02
1.11E-8
Total
6.58E-7