ML021060307
| ML021060307 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 04/16/2002 |
| From: | Grant G Division Reactor Projects III |
| To: | Bakken A American Electric Power Co |
| References | |
| EA-02-010 IR-02-002 | |
| Download: ML021060307 (58) | |
See also: IR 05000315/2002002
Text
April 16, 2002
Mr. A. C. Bakken III
Senior Vice President
Nuclear Generation Group
American Electric Power Company
500 Circle Drive
Buchanan MI 49107
SUBJECT: D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2
NRC INSPECTION REPORT 50-315/02-02(DRP); 50-316/02-02(DRP)
Dear Mr. Bakken:
On March 31, 2002, the NRC completed an inspection at your D. C. Cook Nuclear Power Plant,
Units 1 and 2. The enclosed report documents the inspection findings which were discussed on
April 5, 2002, with you and other members of your staff.
This inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report discusses a finding that appears to have low to moderate safety significance. As
described in Section 4OA1.1 of this report, your staff failed to take corrective action to preclude
a repetitive failure of the Unit 2 Turbine Driven Auxiliary Feedwater Pump (TDAFWP), a
significant condition adverse to quality. Specifically, the Unit 2 TDAFWP failed to start on
August 10, 2001, due to the failure of the trip throttle valve latch mechanism to remain engaged
during pump start. On December 13, 2001, your staff obtained information from the trip throttle
valve vendor identifying critical parameters for the trip hook mechanism geometry and
alignment. Your staff failed to promptly perform corrective actions to verify that the Unit 2
TDAFWP trip hook conformed to these critical parameters. Consequently, a second failure of
the Unit 2 TDAFWP occurred on January 18, 2002, due to the failure of the trip throttle valve
latch mechanism to remain engaged during pump start. Subsequent review determined that
the root cause of the August 10, 2001 and January 18, 2002 failures was due to incorrect trip
hook geometry and alignment.
The inadequate engagement of the Unit 2 TDAFWP throttle valve latch mechanism in
August 2001 resulted in a calculated "T/2" fault exposure time of 42 days. The additional failure
of the Unit 2 TDAFWP in January 2002 represented an additional 38 days of "T/2" fault
exposure. Because both of the TDAFWP failures were related, the NRC evaluated the
identified performance deficiencies, including procedure and corrective action weaknesses, as
a single problem identification and resolution issue. This finding was assessed using the
applicable Significance Determination Process as a potentially safety significant finding that
A. Bakken -2-
was preliminarily determined to be White, a finding with some increased importance to safety,
which may require additional NRC inspection. The finding has a low to moderate safety
significance because the resultant 80 day fault exposure time represented an actual loss of
safety function for a single train of auxiliary feedwater for greater than its Technical
Specification allowed outage time and the train would have been unavailable if called upon for
actual mitigation purposes.
The finding also appears to be an apparent violation of NRC requirements and is being
considered for escalated enforcement action in accordance with the "General Statement of
Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600. The
current Enforcement Policy is included on the NRCs website at http://www.nrc.gov.
Before the NRC makes a final decision on this matter, we are providing you an opportunity to
request a Regulatory Conference where you would be able to provide your perspectives on the
significance of the finding, the bases for your position, and whether you agree with the apparent
violation. If you choose to request a Regulatory Conference, we encourage you to submit your
evaluation and any differences with the NRC evaluation at least one week prior to the
conference in an effort to make the conference more efficient and effective. If a Regulatory
Conference is held, it will be open for public observation. The NRC will also issue a press
release to announce the Regulatory Conference.
Please contact Mr. Anton Vegel at (630) 829-9620 within 10 business days of the date of this
letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will
continue with our significance determination and enforcement decision and you will be advised
by separate correspondence of the results of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for this inspection finding at this time. In addition, please be advised that the number
and characterization of apparent violations described in the enclosed inspection report may
change as a result of further NRC review.
Based on the results of this inspection, one additional finding of very low safety significance
(Green) was identified (See Section 1R22). This issue was determined to be a violation of NRC
requirements. However, because of the very low safety significance and because it has been
entered into your corrective action program, the NRC is treating the issue as a Non-Cited
Violation, in accordance with Section VI.A.1 of the NRC Enforcement Policy. If you contest the
Non-Cited Violation, you should provide a response with the basis for your denial, within
30 days of the date of this inspection report, to the Nuclear Regulatory Commission,
ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional
Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory
Commission, Washington, DC 20555-001; and the NRC Resident Inspector at the D. C. Cook
facility.
A. Bakken -3-
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter
and its enclosures will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) 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).
We will gladly discuss any questions you have concerning this inspection.
Sincerely,
/RA/
Geoffrey E. Grant, Director
Division of Reactor Projects
Docket Nos. 50-315; 50-316
Enclosure: Inspection Report 50-315/02-02(DRP);
50-316/02-02(DRP)
cc w/encl: J. Pollock, Site Vice President
M. Finissi, Plant Manager
M. Rencheck, Vice President
Strategic Business Improvements
R. Whale, Michigan Public Service Commission
Michigan Department of Environmental Quality
Emergency Management Division
MI Department of State Police
D. Lochbaum, Union of Concerned Scientists
DOCUMENT NAME: G:\cook\ML021060307.wpd *See previous concurrence
To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy
OFFICE RIII E RIII E RIII E RIII E RIII E RIII
NAME DPassehl SBurgess BClayton BKemker AVegel GGrant
DATE 04/11/02 04/09/02 04/12/02 04/09/02 04/10/02 04/16/02
OFFICIAL RECORD COPY
A. Bakken -4-
ADAMS Distribution:
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-315; 50-316
Report No: 50-315/02-02(DRP); 50-316/02-02(DRP)
Licensee: American Electric Power Company
Facility: D. C. Cook Nuclear Power Plant, Units 1 and 2
Location: 1 Cook Place
Bridgman, MI 49106
Dates: February 10 through March 31, 2002
Inspectors: B. Kemker, Senior Resident Inspector
K. Coyne, Resident Inspector
J. Maynen, Resident Inspector
H. Peterson, Senior Engineer (Lead Inspector)
D. McNeil, Senior Engineer
W. Slawinski, Senior Radiation Specialist
Approved by: A. Vegel, Chief
Branch 6
Division of Reactor Projects
1
SUMMARY OF FINDINGS
IR 05000315-02-02(DRP), IR 05000316-02-02(DRP), on 02/09 - 03/31/2002, Indiana Michigan
Power Company, D. C. Cook Nuclear Power Plant, Units 1 and 2. Post Maintenance Testing,
Surveillance Testing, Performance Indicator Verification.
The baseline inspection was conducted by resident and region based inspectors. The
inspectors identified one Preliminary White finding, which was an apparent violation and
one Green finding. The significance of most findings is indicated by their color (Green,
White, Yellow, Red) using Inspection Manual Chapter 0609, "Significance Determination
Process" (SDP). The NRCs program for overseeing the safe operation of commercial
nuclear power reactors is described at its Reactor Oversight Process website at
http://www.nrc.gov/NRR/OVERSIGHT/index.html. Findings for which the SDP does not apply
are indicated by "No Color" or by the severity level of the applicable violations.
A. Inspector Identified Findings
Cornerstone: Mitigating Systems
C TBD. The inspectors identified an Apparent Violation of 10 CFR 50, Appendix B,
Criterion V, "Instructions, Procedures, and Drawings," associated with the
licensees failure to perform adequate maintenance and testing on valve
2-CS-369 (reactor coolant pump seal water heat exchanger to volume control
tank (VCT) shutoff valve). This issue was self-revealed on February 16, 2002,
when the Unit 2 west centrifugal charging pump (CCP) exhibited indications of
gas binding following swap over of the suction source from the VCT to the
refueling water storage tank (RWST).
The inspectors assessed this finding using the Significance Determination
Process. The inspectors concluded that this issue had a credible impact on
safety and was therefore more than a minor concern. In particular, the gas
intrusion into the suction of the running Unit 2 west CCP while aligned to the
RWST impacted the capability of the high head injection system to provide the
inventory and reactivity control safety functions. Additionally, the inspectors
concluded that gas intrusion affecting the west CCP could have reasonably
affected the operability and availability of the redundant Unit 2 east CCP. The
inspectors concluded that this issue degraded the licensees ability to add
inventory to the reactor coolant system with the unit shutdown. The risk
significance of this issue will be determined following completion of a Phase 2
analysis for shutdown risk. The safety significance of this issue is to be
determined (TBD) pending the completion of additional staff review.
(Section 1R19)
C Green. A Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XI, "Test
Control," was identified for the licensees failure to utilize valid acceptance
criteria for stroke time testing the Unit 2 pressurizer power operated relief valves
(PORVs). Specifically, the licensee failed to assure that the correct acceptance
2
criteria contained in the applicable design document were incorporated into the
surveillance test procedure used for testing the PORVs.
The inspectors assessed this finding using the Significance Determination
Process (SDP). The inspectors determined that this issue could become a more
significant safety concern if left uncorrected and was therefore more than a
minor concern. Specifically, the failure to adequately perform surveillance
testing with valid acceptance criteria could reasonably result in the failure to
identify degraded or inoperable safety related components. The inspectors also
concluded that this issue could credibly affect the operability of the pressurizer
PORVs, which are mitigating system components under the SDP. The
inspectors determined that, because the as-found stroke times were found within
the correct acceptance criteria, this issue was of very low safety significance.
(Section 1R22)
C Preliminary White. An Apparent Violation of 10 CFR 50, Appendix B,
Criterion XVI, "Corrective Actions," was identified for the licensees failure to take
prompt corrective actions to prevent a repetitive failure of the Unit 2 turbine
driven auxiliary feedwater pump (TDAFWP). Specifically, the Unit 2 TDAFWP
failed to start on August 10, 2001, due to the failure of the trip throttle valve latch
mechanism to remain engaged during pump start. On December 13, 2001, the
licensee obtained information from the trip throttle valve vendor identifying critical
parameters for the trip hook mechanism geometry and alignment and failed to
promptly perform corrective actions to verify that the Unit 2 TDAFWP trip hook
conformed to these critical parameters. Consequently, a second failure of the
Unit 2 TDAFWP occurred on January 18, 2002, due to the failure of the trip
throttle valve latch mechanism to remain engaged during pump start.
The inspectors and Region III Senior Reactor Analysts assessed this finding
using the Significance Determination Process (SDP). A Phase 3 SDP analysis
was performed using insights from the licensees updated Probabilistic Risk
Assessment model. Based on the results of the Phase 3 SDP analysis, the NRC
staff determined that this finding has a low to moderate safety significance
because the resultant 80 day fault exposure time represented an actual loss of
safety function for a single train of auxiliary feedwater for greater than its
Technical Specification allowed outage time and the train would have been
unavailable if called upon for actual mitigation purposes. (Section 4OA1)
B. Licensee Identified Violations
No violations of significance were identified.
3
Report Details
Summary of Plant Status:
Unit 1 operated at or near full power for the duration of the inspection period.
Unit 2 was defueled at the beginning of the inspection period for refueling outage U2C13.
Following completion of the refueling outage, the licensee synchronized the unit to the grid on
February 28, 2002 and raised power to approximately 30 percent. The licensee subsequently
reduced power that same day to approximately 2 percent to perform an emergent repair to a
steam generator main steam isolation valve. Following repair to the valve, the licensee
synchronized the unit to the grid on March 1, 2002. The unit operated at or near full power for
the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R04 Equipment Alignment (71111.04)
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
Mitigating Systems Cornerstone
C Unit 1 Turbine Driven Auxiliary Feedwater (N Train)
C Unit 1 West Component Cooling Water Train
The inspectors selected these systems based on their risk significance relative to the
mitigating systems cornerstone. The inspectors reviewed operating procedures,
Technical Specification (TS) requirements, Administrative Technical Requirements
(ATRs), system diagrams, 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 its intended functions.
b. Findings
No findings of significance were identified.
4
1R05 Fire Protection (71111.05)
.1 Routine Resident Inspector Walkdowns
a. Inspection Scope
The inspectors performed fire protection walkdowns of the following four risk-significant
plant areas:
Mitigating Systems Cornerstone
C Unit 1 Main Steam Valve Enclosure (Zone 33)
C Unit 1 Switchgear Room Cable Vault (Zone 55)
C Unit 1 Auxiliary Cable Vault (Zone 56)
C Unit 1 Refueling Water Storage Tank Pipe Tunnel (Zone 116)
The inspectors verified that fire zone conditions were consistent with assumptions in the
licensees fire hazard analysis. The inspectors walked down fire detection and
suppression equipment, assessed the material condition of fire control equipment, and
evaluated the control of transient combustible materials.
b. Findings
No findings of significance were identified.
.2 Temporary Instruction 2515/146, Hydrogen Storage Locations
a. Inspection Scope
The inspectors walked down the licensees bulk hydrogen storage locations to verify that
the licensee was complying with applicable codes and to ensure that unrecognized
conditions do not exist. Additionally, the inspectors reviewed documents and discussed
hydrogen storage locations with engineering personnel.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
.1 Facility Operating History
a. Inspection Scope
The inspectors reviewed the plants operating history from January 2001 through
January 2002, to assess whether the Licensed Operator Requalification Training
(LORT) program had addressed operator performance deficiencies noted at the plant.
5
b. Findings
No findings of significance were identified.
.2 Licensee Requalification Examinations
a. Inspection Scope
The inspectors performed a biennial inspection of the licensees LORT program. The
inspectors reviewed the annual requalification operating and written examination
material to evaluate general quality, construction, and difficulty level. The operating
portion of the examination was inspected during March 27-28, 2002. The operating
examination material consisted of two dynamic simulator scenarios and five job
performance measures (JPMs). The biennial written examination was administered on
March 28, 2002. The biennial written examination consisted of 37 open reference
multiple choice questions. The inspectors reviewed the methodology for developing the
examinations, including the LORT program two year sample plan, probabilistic risk
assessment (PRA) insights, level of difficulty, and previously identified operator
performance deficiencies. The inspectors assessed the level of examination material
duplication during the current year annual examinations and with last years annual
examinations. The inspectors also interviewed members of the licensees management,
and training staff and discussed various aspects of the examination development.
b. Findings
No findings of significance were identified.
.3 Licensee Administration of Requalification Examinations
a. Inspection Scope
The inspectors observed the administration of the requalification operating test to
assess the licensees effectiveness in conducting the test and to assess the facility
evaluators ability to determine adequate performance using objective, measurable
performance standards. The inspectors evaluated the performance of 12 licensed
operators for one operating shift crew during two dynamic simulator scenarios in parallel
with the facility evaluators. The operating shift was divided into three simulator shift
crews for evaluation purposes. Each evaluation crew consisted of two Senior Reactor
Operators, two Reactor Operators, and a Shift Technical Advisor. In addition, the
inspectors observed licensee evaluators administering five JPMs on a select number of
operators. The inspectors observed the training staff personnel administering the
operating test, including pre-examination briefings, observations of operator
performance, individual and crew evaluations after dynamic scenarios, techniques for
JPM cuing, and the final evaluation briefing. The inspectors noted the performance of
the simulator to support the examinations. The inspectors also reviewed the licensees
overall examination security program.
6
b. Findings
No findings of significance were identified.
.4 Licensee Training Feedback System
a. Inspection Scope
The inspectors assessed the methods and effectiveness of the licensees processes
for revising and maintaining its LORT program up to date, including the use of feedback
from plant events and industry experience information. The inspectors interviewed
licensee personnel (operators, instructors, training management, and management) and
reviewed the applicable licensees procedures. In addition, the inspectors reviewed the
licensees quality assurance/quality control oversight activities, including licensees
training and department self-assessment reports, to evaluate the licensees ability to
assess the effectiveness of its LORT program and to implement appropriate corrective
actions.
b. Findings
No findings of significance were identified.
.5 Licensee Remedial Training Program
a. Inspection Scope
The inspectors assessed the adequacy and effectiveness of the remedial training
conducted since the previous annual requalification examinations and the training
planned for the current examination cycle to ensure that they addressed weaknesses in
licensed operator or crew performance identified during training and plant operations.
The inspectors reviewed remedial training procedures and individual remedial training
plans, and interviewed licensee personnel (operators, instructors, and training
management). In addition, the inspectors reviewed the licensees current examination
cycle remediation packages for unsatisfactory operator performance on the written
examination and operating test to ensure that remediation and subsequent re-
evaluations were completed prior to returning individuals to licensed duties.
b. Findings
No findings of significance were identified.
.6 Conformance with Operator License Conditions
a. Inspection Scope
The inspectors evaluated the facility and individual operator licensees' conformance with
the requirements of 10 CFR Part 55. The inspectors reviewed the facility licensees
program for maintaining active operator licenses and to assess compliance with
10 CFR 55.53(e) and (f). The inspectors reviewed the procedural guidance and the
7
process for tracking on-shift hours for licensed operators and which control room
positions were granted credit for maintaining active operator licenses. The inspectors
also reviewed eight licensed operators medical records maintained by the facilitys
contracted medical staff for ensuring the medical fitness of its licensed operators and to
assess compliance with medical standards delineated in ANSI/ANS-3.4 and with
10 CFR 55.21 and 10 CFR 55.25. In addition, the inspectors reviewed the licensees
LORT program to assess compliance with the requalification program requirements as
described by 10 CFR 55.59(c).
b. Findings
No findings of significance were identified.
.7 Written Examination and Operating Test Results
a. Inspection Scope
The inspectors reviewed the overall pass/fail results of individual written tests, JPM
operating tests, and simulator operating tests (required to be given per
10 CFR 55.59(a)(2)) administered by the licensee during calender year 2002.
b. Findings
No findings of significance were identified.
.8 Resident Inspector Quarterly Review
a. Inspection Scope
The inspectors assessed licensed operator performance and the training evaluators'
critique during a licensed operator annual requalification evaluation in the D. C. Cook
Plant operations training simulator on March 6, 2002. The inspectors focused on alarm
response, command and control of crew activities, communication practices, procedural
adherence, and implementation of emergency plan requirements.
b. Findings
No findings of significance were identified.
1R12 Maintenance Rule Implementation (71111.12)
a. Inspection Scope
The inspectors evaluated the licensee's implementation of 10 CFR 50.65 (the
Maintenance Rule). The inspectors assessed: (1) functional scoping in accordance
with the Maintenance Rule, (2) characterization of system functional failures, (3) safety
significance classification, (4) 10 CFR 50.65 (a)(1) or (a)(2) classification for system
functions, and (5) performance criteria for systems classified as (a)(2) or goals and
8
corrective actions for systems classified as (a)(1). The inspectors reviewed the
following risk-significant systems and components:
Initiating Events Cornerstone
Barrier Integrity Cornerstone
C Hydrogen Ignitor System
Mitigating Systems Cornerstone
C Compressed Air System
C Component Cooling Water System
In addition, the inspectors reviewed the issues that the licensee entered into its
corrective action program to verify that identified problems were being entered into the
program with the appropriate characterization and significance. The inspectors also
reviewed the licensees corrective actions for Maintenance Rule related issues that were
documented in selected condition reports (CRs).
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed the licensees evaluation and management of plant risk for
maintenance activities on the following equipment:
Mitigating Systems Cornerstone
C Unit 1 East Essential Service Water (ESW) Pump Replacement
C Unit 2 East Centrifugal Charging Pump (CCP) Oil Change and Relay Calibration
C Unit 2 West Component Cooling Water Pump Oil Change
C Unit 1 CD Diesel Generator Outage Maintenance Work Window
These activities were selected based on their potential risk significance relative to the
mitigating systems cornerstone. As applicable for each of the above activities, the
inspectors reviewed the scope of maintenance work, discussed the results of the
assessment with the licensees probabilistic risk analyst or shift technical advisor, and
verified that plant conditions were consistent with the risk assessment. The inspectors
also reviewed TS and ATR requirements and walked down portions of redundant safety
systems, when applicable, to verify that risk analysis assumptions were valid and
applicable requirements were met.
9
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed the following CRs to ensure that either: (1) the condition did
not render the involved equipment inoperable or result in an unrecognized increase in
plant risk, or (2) the licensee appropriately applied TS limitations and appropriately
returned the affected equipment to an operable status.
Mitigating Systems Cornerstone
C CR 02047050, "Unit 2 West CCP Showed Signs of Air Entrainment"
C CR 02050022, "Control Switch 1-101-NRV-152 May Not Be in the Automatic
Position Fully"
C CR 02057005, "Inability to Test 112 Percent Main Turbine Overspeed Trip
Device"
The inspectors also reviewed the licensees justification for not correcting existing
degraded and nonconforming conditions during refueling outage U2C13 consistent with
the timeliness guidance contained in Generic Letter 91-18, "Information to Licensees
Regarding NRC Inspection Manual Section on Resolution of Degraded and
Nonconforming Conditions," Revision 1.
In addition, the inspectors reviewed the issues that the licensee entered into its
corrective action program to verify that identified problems were being entered into the
program with the appropriate characterization and significance. The inspectors also
reviewed the licensees corrective actions for issues potentially affecting the operability
of structures, systems, and components that were documented in selected CRs.
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications (71111.17)
a. Inspection Scope
The inspectors reviewed the engineering analyses, modification documents and design
change information associated with the following permanent plant modification:
Barrier Integrity Cornerstone
C Design Change 2-DCP-4821, "Install New Impellers In the Containment Spray
Pumps (2-PP-9E & W)"
10
The inspectors verified the design adequacy of the modification and focused the
inspection activities on the following parameters associated with the design change:
heat removal, equipment protection, operations, flowpaths, process media, licensing
basis, and failure modes.
Completed activities associated with the implementation of the modification were also
inspected and the inspectors discussed the modification with the responsible engineers
and operations staff. In addition, the inspectors reviewed the applicable sections of the
TS, Updated Final Safety Analysis Report (UFSAR), and CRs associated with the
design change packages and the installation of the modification.
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed the post maintenance testing requirements associated with the
following scheduled maintenance activities:
Mitigating Systems Cornerstone
C Job Order (JO) 01094018, "Replace Diaphragm in Reactor Coolant Seal Return
to Volume Control Tank Isolation Valve 2-CS-369"
C JO 01262081, "Rebuild the Unit 1 East ESW Pump 1-PP-7E"
C JO 020309004, "Troubleshoot and Repair 2-OME-150-CD, Unit 2 CD Diesel
Generator"
C JO 02049054, "Troubleshoot and Repair 600 Volt Supply Breaker to the Unit 2
CD2 Battery Charger That Tripped Twice"
The inspectors reviewed test methodology and acceptance criteria to assess the
appropriateness of assigned post maintenance testing for the scope of work performed.
Documented test data was reviewed to verify that the testing was complete and that the
equipment was able to perform the intended safety functions.
In addition, the inspectors reviewed the issues that the licensee entered into its
corrective action program to verify that identified problems were being entered into the
program with the appropriate characterization and significance. The inspectors also
reviewed the licensees corrective actions for post maintenance testing related issues
that were documented in selected CRs.
11
b. Findings
b.1 Failure to Perform Adequate Maintenance and Testing on Valve 2-CS-369 Resulted in
Gas Binding the Unit 2 West CCP
The inspectors identified an Apparent Violation of 10 CFR 50, Appendix B, Criterion V,
"Instructions, Procedures, and Drawings," associated with the licensees failure to
perform adequate maintenance and testing on valve 2-CS-369 (reactor coolant pump
seal water heat exchanger to volume control tank (VCT) shutoff valve). This issue was
self-revealed on February 16, 2002, when the Unit 2 west CCP exhibited indications of
gas binding following swap over of the suction source from the VCT to the refueling
water storage tank (RWST). Pending additional evaluation, the safety significance of
this issue is "To Be Determined" (TBD).
Description
On February 16, 2002, while performing a vacuum refill of the reactor coolant system
(RCS), control room operators aligned the RWST as the CCP suction source and
isolated the VCT. Following isolation of the VCT, the Unit 2 west CCP exhibited
indications of gas binding, including a drop in pump motor amperage and a reduction of
charging system flow to near 0 gallons per minute (gpm). After operators unisolated the
VCT, the CCP amperage and flow recovered to normal values. Operators then made a
second attempt to swap the CCP suction source from the VCT to the RWST; but again,
the gas binding symptoms returned when the VCT was isolated. Based on the
unexpected system response, the licensee declared the Unit 2 RWST boration flowpath
inoperable and initiated CR 02047050.
The licensee determined that the cause of this event was the failure to have 2-CS-369
fully closed, which, due to the pressure difference between the VCT and the RWST,
allowed gas to vent from the top of the VCT directly to the CCP suction line. The
reactor coolant pump seal return flow can be directed either to the CCP suction via
2-CS-370 or directly to the VCT via 2-CS-369. During normal operation, 2-CS-369 is
sealed closed to prevent VCT cover gas intrusion directly to the CCP suction. On
February 1, 2002, the licensee performed preventative maintenance to replace the
2-CS-369 valve diaphragm under JO 01094018. Because the valve was completely
disassembled to replace the diaphragm, JO 01094018 included instructions for valve
stem stop nut adjustment to ensure that the valve stroke would be correct. Proper
adjustment of the stem stop nut allows full closure of the diaphragm valve without
excessive crushing force on the valve diaphragm. The licensee later identified that the
stem stop nut was incorrectly adjusted, which prevented full closure of the valve.
The inspectors reviewed the maintenance work instructions for the 2-CS-369 diaphragm
replacement and determined that the work instructions were not correctly implemented.
Specifically, maintenance personnel failed to adequately perform the instructions for
valve stop nut adjustment contained in procedure 12 MHP 5021.001.023, "Manual
Diaphragm Valve Maintenance," Revision 6. Steps 6.6.3, 6.6.4, and 6.6.5 of
12 MHP 5021.001.023 required that the stem stop nut be locked in position by
tightening the stem lock nut after the valve was turned clockwise 1/8 of a turn beyond
the closed seat contact point. The purpose of these steps was to ensure that the
12
position of the stop nut would allow full closure of 2-CS-369. On February 16, 2002, the
licensee identified that the stem lock nut was loose and that the position of the stop nut
prevented full closure of 2-CS-369. The licensee performed several corrective actions
for this condition, including: (1) adjustment of the stop nut and closing of 2-CS-369;
(2) venting of the safety injection (SI) pump and CCP suction headers; and, (3) testing
of the Unit 2 west CCP in accordance with procedure 02 OHP 4030.STP.052W, "West
Centrifugal Charging Pump Operability Test." The licensee subsequently declared the
RWST boration flowpath operable on February 17, 2002.
In addition, the inspectors determined that the post maintenance testing performed
following diaphragm replacement was not adequate to identify the potential
mis-positioning of the stem stop nut. The post maintenance testing requirements in
JO 01094018 specified only an external leakage inspection. The inspectors noted that
although full closure of 2-CS-369 was required to prevent gas intrusion into the suction
of the CCPs, no testing was performed on 2-CS-369 immediately following diaphragm
replacement to verify valve seat leak tightness. The inspectors determined that the
failure to correctly implement maintenance instructions for valve stem stop nut
adjustment and the failure to perform an adequate post maintenance test constituted a
violation of NRC requirements.
Analysis
The inspectors assessed this issue using the Significance Determination Process
(SDP). The inspectors concluded that this issue had a credible impact on safety and
was therefore more than a minor concern. In particular, the gas intrusion into the
suction of the running Unit 2 west CCP while aligned to the RWST impacted the
capability of the high head injection system to provide inventory and reactivity control
safety functions. Additionally, the inspectors concluded that gas intrusion affecting the
west CCP could have reasonably affected the operability and availability of the
redundant Unit 2 east CCP. Consequently, the inspectors determined that this issue
was associated with the mitigating systems cornerstone. The inspectors concluded that
2-CS-369 was degraded when the diaphragm was replaced (February 1, 2002) until
completion of the corrective action to adjust the valve stem stop nut
(February 16, 2002). Therefore, the inspectors concluded that this issue should be
reviewed using the guidance provided in Inspection Manual Chapter (IMC) 0609,
Appendix G, "Shutdown Operations Significance Determination Process." The
inspectors considered the following during the initial risk assessment:
C The 2-CS-369 diaphragm was replaced on February 1, 2002 with Unit 2
defueled. Unit 2 entered Mode 6 (Refueling) on February 10, 2002 and
completed core reload on February 12, 2002. Because the degraded condition
of 2-CS-369 was identified and corrected on February 16, 2002, the safety
function provided by the CCPs was degraded for approximately 6 days with fuel
in the reactor vessel.
C Based on the observed Unit 2 west CCP performance during the gas intrusion
event on February 16, 2002 (decreased pump amperage and near 0 gpm
flowrate), the inspectors concluded that the degraded condition of 2-CS-369
would render the CCPs unavailable when aligned to the RWST.
13
C The licensee determined that both SI pumps were available during the period,
except for 2-1/2 hours on February 12, 2002. During the time that the SI pumps
were unavailable, the unit was in Mode 6 with refueling cavity level greater than
23 feet above the active fuel level.
C To support low temperature over-pressure protection (LTOP) requirements, the
breakers for both SI pumps were racked out. The licensee estimated that
approximately 30 minutes would be required to restore an SI pump to service.
Use of the SI pumps to restore RCS inventory during a loss of inventory was
addressed in abnormal procedure 02 OHP 4022.017.001, "Loss of RHR
[Residual Heat Removal] Cooling."
C The inspectors determined that gas intrusion into the suction of the CCPs would
not be expected to cause a similar failure for the SI pumps. Although the SI
pumps share a common suction with the CCPs from the RWST, check valve
2-SI-185 would prevent migration of gas to the suction of the SI pumps. The
licensee seat leak tested 2-SI-185 on February 8, 2002 and measured a seat
leakage rate of 0 gpm.
C Based on a review of the Unit 2 shutdown risk status sheets during the period of
February 15 and 16, 2002, the inspectors determined that the minimum time to
boil upon a loss of core cooling was 13 minutes. The time to boil with the reactor
coolant not in a reduced inventory condition was estimated to be approximately
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
C The licensee entered a mid-loop reduced inventory condition on
February 15, 2002 to support vacuum refill of the RCS. The licensee exited the
mid-loop condition on February 16, 2002. The inspectors estimated that the unit
was in reduced inventory condition for approximately 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />.
C Because the reactor coolant had not been fully refilled prior to the event, the
steam generators were unavailable for core cooling.
C The remote unit has the capability to provide high head injection via unit cross-tie
valves. Although procedure 02 OHP 4025.001.001, "Emergency Remote
Shutdown," addresses use of the charging system cross-tie during certain
Appendix R fire protection events, it did not include specific instructions for
inventory control during loss of shutdown cooling events.
Based on the above information, the inspectors concluded that the most appropriate
IMC 0609, Appendix G checklist to use for this issue was the checklist for "Pressurized
Water Reactor Cold Shutdown and Refueling Operation - Reactor Coolant System
Closed and No Inventory in Pressurizer, Time to boiling less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />." Because of
the unavailability of the high pressure injection CCPs due to the degraded condition of
2-CS-369, the inspectors concluded that the minimum equipment specified in
Section II.C were not met from February 14, 2002 (when the unit entered Mode 5) to
February 16, 2002 (when the licensee identified and corrected the degraded condition of
2-CS-369). Consequently, the inspectors concluded that this issue degraded the
licensees ability to add inventory to the RCS and therefore required a Phase 2 analysis.
14
The risk significance of this issue will be determined following completion of a Phase 2
analysis for shutdown risk. The inspectors discussed the safety significance of this
issue with the Regional Senior Reactor Analysts (SRAs), and, pending the completion of
additional evaluation, the safety significance of this issue is to be determined (TBD).
Enforcement
10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires
that activities affecting quality shall be prescribed by documented instructions,
procedures, or drawings, of a type appropriate to the circumstances and shall be
accomplished in accordance with these instructions, procedures, or drawings.
Instructions, procedures, or drawings shall include appropriate quantitative or qualitative
acceptance criteria for determining that important activities have been satisfactorily
accomplished. Contrary to the above, the licensee failed to (1) correctly accomplish the
instructions provided in 12 MHP 5021.001.023, Section 6.6, for valve stroke adjustment
of 2-CS-369, an activity affecting quality, and (2) provide appropriate acceptance criteria
to ensure that valve stop nut adjustment was satisfactorily accomplished. Specifically,
steps 6.6.3, 6.6.4, and 6.6.5, which were performed on February 1, 2002, required that
the handwheel for 2-CS-369 be turned clockwise 1/8 of a turn beyond the point where
the valve made closed seat contact, and the stem stop nut be turned clockwise until it
made contact with the handwheel and then locked in position by tightening the stem lock
nut. On February 16, 2002, the licensee identified that the stem stop nut was not locked
and its position prevented full closure of 2-CS-369, which allowed VCT cover gas to flow
to the CCP suction header. In addition, the instructions provided in JO 01094018 did
not include appropriate acceptance criteria to ensure that 2-CS-369 valve stroke
adjustment had been satisfactorily accomplished after valve maintenance.
Consequently, on February 16, 2002, the Unit 2 west CCP became gas bound following
alignment of the pump suction to the RWST. This issue is considered to be an
Unresolved Item pending a final safety significance determination
1R20 Refueling and Outage Activities (71111.20)
a. Inspection Scope
The inspectors continued their evaluation of the licensees conduct of Unit 2 refueling
outage activities during this inspection period to assess the licensees control of plant
configuration and management of shutdown risk. The inspectors reviewed configuration
management to verify that the licensee maintained defense-in-depth commensurate with
the shutdown risk plan and reviewed major outage work activities to ensure that correct
system lineups were maintained for key mitigating systems. Other major outage
activities evaluated included the licensees control of the following:
C Containment penetrations in accordance with the TS
C Systems, structures, and components (SSCs) which could cause unexpected
reactivity changes
C Flow paths, configurations, and alternate means for RCS inventory addition and
control of SSCs which could cause a loss of inventory
C RCS pressure, level, and temperature instrumentation
15
C Switchyard activities and the configuration of electrical power systems in
accordance with the TS and shutdown risk plan
C SSCs required for decay heat removal
The inspectors also observed portions of the restart activities to verify that requirements
of the TS and administrative procedure requirements were met prior to changing
operational modes or plant configurations. Major restart inspection activities performed
included:
C Verification that RCS boundary leakage requirements were met prior to entry into
Mode 4 (Cold Shutdown) and subsequent operational mode changes
C Verification that containment integrity was established prior to entry into Mode 4
C Inspection of the Containment Building to assess material condition and search
for loose debris, which if present could be transported to the containment
recirculation sumps and cause restriction of flow to the emergency core cooling
system (ECCS) pump suctions during loss-of-coolant accident conditions
C Verification that the material condition of the Containment Building ECCS
recirculation sumps met the requirements of the TS and was consistent with the
design basis
C Observation and review of reactor physics testing to verify that core operating
limit parameters were consistent with the core design so that the fuel cladding
barrier would not be challenged
The inspectors interviewed operations, engineering, work control, radiological protection,
and maintenance department personnel and reviewed selected procedures and
documents.
In addition, the inspectors reviewed the issues that the licensee entered into the
corrective action program to verify that identified problems were being entered into the
program with the appropriate characterization and significance. The inspectors also
reviewed the licensees corrective actions for refueling outage issues documented in
selected CRs.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
For the surveillance test procedures listed below, the inspectors observed selected
portions of the surveillance tests and reviewed the test results to determine whether risk
significant systems and equipment were capable of performing their intended safety
functions and to verify that testing was conducted in accordance with applicable
procedural and TS requirements:
16
Barrier Integrity Cornerstone
C 02 OHP 4030.STP.007E, "East Containment Spray System Operability Test"
Mitigating Systems Cornerstone
C 02-OHP-4030-202-060, "Pressurizer Relief Valve Testing"
C 02-OHP 4030.001.002, "Containment Inspection Tours"
C 02-OHP-4030-232-217A, "DG2CD Load Sequencing & ESF Testing"
The inspectors reviewed the test methodology and test results in order to verify that
equipment performance was consistent with safety analysis and design basis
assumptions. The inspectors also reviewed CRs concerning surveillance testing
activities to verify that identified problems were appropriately characterized.
b. Findings
b.1 Failure to Use Valid Acceptance Criteria for Stroke Time Testing the Unit 2 Pressurizer
Power Operated Relief Valves (PORVs)
The inspectors identified a finding of very low safety significance (Green) associated
with the licensees failure to utilize valid acceptance criteria for stroke time testing the
Unit 2 pressurizer PORVs. This finding was dispositioned as a Non-Cited Violation of
10 CFR 50, Appendix B, Criteria XI, "Test Control."
Description
The inspectors examined the results of stroke time testing of the Unit 2 pressurizer
PORVs (2-NRV-152 and 2-NRV-153), which was performed on February 12, 2002 to
obtain new in-service testing baseline stroke time values for the valves following
maintenance and to demonstrate operability of the valves for LTOP prior Unit 2 entering
Mode 5 (Cold Shutdown) upon completion of refueling activities. The two air-operated
valves are provided with backup air supply bottles that are designed to provide sufficient
air to cycle the PORVs for 10 minutes without operator action during an LTOP event.
The minimum backup air supply bottle pressure (900 pound per square inch) and the
minimum valve stroke cycle (open and closed) are therefore critical parameters. The
licensee had previously had difficulty meeting the minimum stroke time acceptance
criteria when testing the valves at the beginning of the Unit 2 refueling outage and
revised the acceptance criteria based on its review of the original design calculation for
sizing the backup air supply bottles. The inspectors compared the acceptance criteria in
the completed surveillance test procedure (02-OHP-4030-202-060, "Pressurizer Relief
Valve Testing," Revision 0, Change 0) with the approved acceptance criteria in Design
Information Transmittal (DIT)-B-02327 and noted that the licensee had failed to correctly
use the revised acceptance criteria. Specifically, DIT-B-02327 determined the following
minimum valve stroke time requirements for both 2-NRV-152 and 2-NRV-153:
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Open Closed
2.39 seconds minimum 1.33 seconds minimum
or
Open Closed Open + Closed
2.0 seconds minimum 1.0 second minimum 3.72 seconds minimum
The second set of minimum stroke time values were provided in DIT-B-02327 as an
alternative set of acceptance criteria with the stipulation that the sum of the minimum
open and closed times be equal to or greater than 3.72 seconds. Based on the sizing
calculation, the PORVs would not be considered operable if the sum of the minimum
open and closed times was less than 3.72 seconds.
The acceptance criteria used in 02-OHP-4030-202-060 for 2-NRV-152 was:
Open Closed
2.8 seconds minimum 1.0 second minimum
The acceptance criteria used in 02-OHP-4030-202-060 for 2-NRV-153 was:
Open Closed
2.6 seconds minimum 1.0 second minimum
The inspectors first noted that the acceptance criteria used in the surveillance test
procedure for both valves did not match the acceptance criteria specified in
DIT-B-02327. This could be considered acceptable provided the sum of the minimum
open and closed acceptance criteria values for each valve is less than 3.72 seconds.
The inspectors then identified that although the sum of the minimum open and closed
acceptance criteria values used in the surveillance test procedure for 2-NRV-152
(3.8 seconds) was greater than 3.72 seconds, the sum of the minimum open and closed
acceptance criteria values for 2-NRV-153 (3.6 seconds) was less than 3.72 seconds. It
was therefore possible to meet the acceptance criteria used in the surveillance test
procedure for 2-NRV-153 with unacceptable test results and to consider an inoperable
valve to be operable. The inspectors compared the as-found stroke times for the two
valves with the correct acceptance criteria from DIT-B-02327 and concluded that the
valves were operable.
Analysis
The inspectors assessed the licensees failure to utilize valid acceptance criteria for
testing the Unit 2 pressurizer PORVs using the SDP. The inspectors determined that
this issue could become a more significant safety concern if left uncorrected and was
therefore more than a minor concern. The inspectors reviewed the licensees corrective
action program database and were concerned that there were several additional
examples captured in the licensees corrective action program, wherein incorrect
acceptance criteria had been utilized for testing. Specifically, the failure to adequately
perform surveillance testing with valid acceptance criteria could reasonably result in the
failure to identify degraded or inoperable safety related components. The inspectors
18
also concluded that this issue could credibly affect the operability of the pressurizer
PORVs, which are mitigating system components under the SDP. The inspectors
determined that, because the as-found stroke times were found within the correct
acceptance criteria, this issue was of very low safety significance (Green).
Enforcement
10 CFR Part 50, Appendix B, Criterion XI, "Test Control," requires, in part, that a test
program shall be established to assure that all testing required to demonstrate that
structures, systems, and components will perform satisfactorily in service is identified
and performed in accordance with written test procedures which incorporate the
requirements and acceptance limits contained in applicable design documents.
Contrary to the above, the licensee failed to assure that 02-OHP-4030-202-060,
"Pressurizer Relief Valve Testing," Revision 0, Change 0, incorporated the requirements
and acceptance criteria contained in the applicable design document (i.e., Design
Information Transmittal B-02327, "Stroke Time Acceptance Criteria for
1/2-NRV-152, 153," February 1, 2002). This is considered to be a violation of
10 CFR Part 50, Appendix B, Criterion XI. Because of the very low safety significance,
this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the
NRC Enforcement Policy (NCV 50-316-02-02-02(DRP)). This violation is in the
licensee's corrective action program as CR 02046050.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors reviewed the temporary modification listed below to verify that the
installation was consistent with design modification documents and that the modification
did not adversely impact system operability or availability:
C 2-TM-00-54-R1 Installation of Noise Filtering Resistors on Cables
2-4450PB-2 for 2-ILA-111 and 2-5658PB-2 for 2-ILA-121
The temporary modification installed a 1000 ohm resistor between the shield and
ground on each cable to alleviate unstable indication and spurious alarms for two
SI system accumulator level channels. The inspectors verified that configuration control
of the modification was correct by reviewing design modification documents and
confirmed that appropriate post-installation testing was accomplished. The inspectors
reviewed the design modification documents and the 10 CFR 50.59 evaluation against
the applicable portions of the UFSAR.
b. Findings
No findings of significance were identified.
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2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1 Plant Walkdowns and Radiological Boundary Verification
a. Inspection Scope
The inspector conducted walkdowns of selected radiologically controlled areas to verify
the adequacy of radiological boundaries and postings. The inspector reviewed the
administrative controls for access to radiologically significant areas, as specified in
radiation protection (RP) procedures and in radiation work permits (RWPs), and the
physical controls established over those areas walked-down were assessed through
direct observation. Specifically, the inspector walked-down several radiologically
significant work area boundaries (high and locked high radiation areas) in the Unit 1 and
Unit 2 Auxiliary Building and in the Unit 2 Containment Building and performed
confirmatory radiation measurements in the Auxiliary Building to verify that these areas
and selected radiation areas were properly posted and controlled in accordance with
10 CFR Part 20 and the licensees TS.
b. Findings
No findings of significance were identified.
2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls (71121.02)
.1 Radiation Dose Goals and Trending
a. Inspection Scope
The inspector reviewed the stations historical outage exposure data for the last several
refueling outages to establish its prior performance relative to the industry. Job specific
and cumulative exposure performance and exposure trends for the first 20-days of the
approximate 40-day Unit 2 refueling outage (U2C13) were reviewed to assess the
licensees current dose performance compared to pre-outage exposure projections.
The inspector also reviewed the licensees dose forecasting practices for those
radiologically significant jobs that were being performed during the outage to determine
if adequate technical bases for outage dose estimates existed. Dose forecasting
practices were also reviewed to determine if outage experiences, craft work group
defined job scope, resource estimates, and industry operating experiences were used to
establish reasonable estimates. Additionally, the inspector reviewed the effectiveness of
the RP organizations exposure tracking for the outage to verify that the licensee could
identify problems with its exposure performance and take actions to address identified
deficiencies.
20
b. Findings
No findings of significance were identified.
.2 Radiological Work Planning
a. Inspection Scope
The inspector reviewed the licensees procedures for ALARA planning and evaluated
several U2C13 ALARA plans to verify consistency with the procedure and to assess
their overall adequacy relative to both current licensee practices and industry standards.
Specifically, the inspector selected the following outage jobs that were projected to
accrue cumulative doses in excess of 3.5 rem and assessed the adequacy of the
radiological controls and the work planning for each:
C Temporary Shielding
C Insulation Activities in Containment
C Scaffold Erection/Removal in Containment
C Steam Generator Manway & Diaphragm Activities
C Steam Generator Primary Work and Platform Activities
C Control Rod Drive Mechanism Inspections
C Reactor Head Control Rod Drive Mechanism Penetration Weld Inspections
C Modify/Replace Pressurizer Spray Line Temperature Sensors
The inspector reviewed the RWP and the ALARA plan developed for each job and
assessed the radiological engineering controls and other dose mitigation information
specified in these documents to verify that plans included appropriate controls to reduce
dose. These documents were also reviewed to determine if job history files, licensee
lessons learned, and industry operating experiences were adequately integrated into
each work package. The inspector discussed ALARA planning with several RP staff to
verify that adequate interface existed between contractors, station work groups, and the
ALARA staff during job planning. Additionally, plans to improve ALARA planning
through more detailed task analysis were discussed with RP management and ALARA
staff.
a. Findings
No findings of significance were identified.
.3 Implementation of ALARA Controls and Radiological Oversight of Work
a. Inspection Scope
The inspector selected the following high exposure or high radiation area jobs
conducted during the outage and reviewed the execution of the ALARA program:
C Install, Modify and Remove Scaffolds in Containment (RWP # 022136)
C Shielding Activities in Containment (RWP # 022119)
C Modify/Replace Pressurizer Spray Line Temperature Sensor (RWP # 022170)
21
The inspector discussed job performance with involved RP staff, and total effective dose
equivalent (TEDE) ALARA evaluations completed for these and a variety of other
outage work activities, including steam generator work, were assessed for technical
adequacy. Work in progress reports and radiological survey data for these and other
selected jobs, as applicable, were also reviewed to assess their adequacy and
consistency with licensee procedures. The pre-job brief for a transfer canal dive to
repair a valve was attended to verify that the work activity was adequately planned and
that radiological control information was exchanged effectively. The inspector evaluated
the licensees radiological engineering controls utilized at selected work locations to
determine if the controls were consistent with those specified in the ALARA plans. The
inspector also observed and questioned both RP staff that provided job coverage for
various outage activities and radiation workers (radworkers) involved in outage work to
verify that they had adequate knowledge of radiological work conditions and ALARA
controls. Additionally, the inspector reviewed measurements and calculations
completed by the RP staff to assess worker dose from skin contaminations and intakes
to determine if the methodology was technically sound and if the results were accurate.
b. Findings
No findings of significance were identified.
.4 Verification of Exposure Estimates and Exposure Tracking Systems
a. Inspection Scope
The inspector reviewed the methods and assumptions used by the ALARA group to
develop U2C13 dose estimates and compared collective outage and individual job dose
performance and trends during the first 2 weeks of the outage to assess dose
performance and to determine the accuracy of pre-outage projections. The inspector
reviewed job dose history files, dose reductions anticipated through ALARA initiatives,
and task specific breakdown analyses employed for certain jobs to verify that they were
appropriately used to forecast outage doses. In particular, the inspector reviewed
containment scaffolding work, which was anticipated to expend greater than 25 rem of
exposure and to exceed original dose projections by more than 50 percent, and
discussed its dose performance with ALARA staff. The review was conducted to
determine whether the licensee had identified those factors that contributed to additional
dose and/or inaccurate dose estimates. The inspector also reviewed the licensees
process used to revise dose estimates and capture lessons learned to verify compliance
with the licensees ALARA procedure. As of February 7, 2002, the licensee had
recorded a collective outage exposure of approximately 105 rem, compared to its
original estimate of about 95 rem for that stage of the outage. Selected work in
progress reports were examined to evaluate the licensees ability to assess the
effectiveness of a job, to execute its ALARA plan, and to institute changes in work plans,
if warranted. The licensees exposure tracking system was also reviewed to determine if
the level of exposure tracking detail, exposure report timeliness, and report distribution
were sufficient to support the control of outage exposures.
22
b. Findings
No findings of significance were identified.
.5 Source Term Reduction and Control
a. Inspection Scope
The inspector reviewed the licensees source term reduction activities, focusing on
recent initiatives including those taken for the outage such as flushing, installation of
shielding and changes in plant operations during the Unit 2 cool-down process. The
inspector also evaluated the licensees water chemistry control program implemented
during the Unit 2 shutdown and its impact on source term reduction to determine
whether the program was implemented consistent with station procedure and industry
practices. First time water chemistry initiatives, which included a revised de-lithiation
initiative to achieve acidic conditions earlier during cool-down and a revised RCS degas
process to maintain corrosion products in soluble form, were reviewed by the inspector.
These initiatives were reviewed to verify that the licensee implemented adequate
practices for corrosion and source term control. The licensees overall source term
reduction program was assessed to verify that other initiatives such as cobalt reduction
through stellite control were being pursued and to determine if a viable, progressive
source term control program was in place.
b. Findings
No findings of significance were identified.
.6 Identification and Resolution of Problems
a. Inspection Scope
The inspector reviewed the results of an RP self-assessment completed as part of an
ALARA outage planning readiness review and CRs generated by the RP staff during the
outage to evaluate the effectiveness of the RP organizations ability to identify and
correct problems. The inspector also reviewed outage related Performance Assurance
Department field observations, RP program related CRs generated by other station
departments, and investigation reports related to outage RP issues to verify that the
licensee adequately identified individual problems and trends, determined contributing
causes and extent of condition, and developed appropriate corrective actions.
a. Findings
On January 28, 2002, the licensee identified that a contract worker failed to stop work
and leave the radiologically controlled area (RCA) as instructed by a radiation protection
technician (RPT). The worker was instructed to leave the area because the individuals
dose approached the RWP administrative limit established at 200 mrem for the day.
The worker was conducting accumulator check valve testing in the Unit 2 lower
containment. The test utilized an acoustic monitoring device, and the individual was an
expert in setup and data results analysis. The RPT initially instructed the individual to
23
leave containment just prior to the start of the data acquisition portion of the test. When
the worker did not comply with the instruction, the RPT informed an RP supervisor of the
problem, returned to the job site minutes later and heard the workers electronic
dosimetry (ED) accumulated dose alarm. The RPT then instructed the worker to leave
the area a second time. The worker again failed to comply with the RPTs instructions,
but shortly thereafter completed the data acquisition portion of the test, confirmed that
good data was obtained, and then vacated the area.
After learning of the incident, radiation protection supervision immediately suspended
the workers access to the RCA and documented the occurrence in CR 02029016. The
worker was counseled and coached by the licensee and allowed to return to work about
an hour later to complete the testing. After the work was complete, the individual did not
reenter the RCA. The licensee investigated the incident and on January 29, 2002,
released the individual from the site because the licensee concluded that the individual
chose not to comply with RP procedures. According to the licensees preliminary
investigation, the worker failed to obey the RPTs instructions because the individual:
(1) spent considerable time setting-up the test equipment and was about to start the
test; (2) anticipated completing the data acquisition portion of the test in a short time
without significant additional dose; and (3) was an expert in the testing operation which
involved "critical path" work that the worker felt pressure to complete without further
delay. According to the licensees preliminary investigation, the individual was aware of
the requirement to comply with RP instructions and to immediately leave the work area
upon receiving an ED alarm but decided not to comply for the reasons specified above.
On January 31, 2002, the D. C. Cook station newspaper included an article that
summarized the incident and reminded workers to follow RP procedures.
The dose received by the worker for the day was 201 mrem, just above the 200 mrem
administrative dose limit established on the RWP that governed the check valve test
work. The inspector reviewed area survey information to assess the radiological safety
significance of the incident and determined that a potential for an overexposure did not
exist had the worker continued to remain in the area longer. Work area radiation levels
ranged from about 20 to 250 mrem/hour, depending on the workers location relative to
the valve being tested. At the time of the incident, the worker was positioned near the
test equipment which was set-up in a lower radiation field. The worker accumulated a
dose of about 3 mrem from the time he was initially instructed by the RPT to leave the
area and several minutes later when he complied. Based on inspector discussions with
members of the RP staff and review of the licensees preliminary investigation, the
inspector concluded that the workers actions appeared to be in violation of
RP procedure PMP-6010-RPP-001, "General Radiation Worker Instructions." This
incident is considered to be an URI pending further NRC review to determine potential
enforcement actions (URI 50-316-02-02-03(DRS)).
24
4. OTHER ACTIVITIES (OA)
4OA1 Performance Indicator Verification (71151)
.1 Unit 2 Turbine Driven Auxiliary Feedwater Pump (TDAFWP) Fault Exposure
(Closed) URI 50-316-01-19-03: "Apparent Violation of 10 CFR 50, Appendix B,
Criterion V for the Failure to Incorporate Adequate Quantitative Acceptance Criteria in
TDAFWP Maintenance Instructions."
a. Inspection Scope
On August 10, 2001, the Unit 2 TDAFWP failed to start during three successive start
attempts. The inspectors documented a preliminary evaluation of this issue in NRC
Inspection Report 50-315/316-01-019(DRP), Section 4OA1.1. To support additional risk
evaluation of the TDAFWP failure in accordance with the SDP, the inspectors identified
this issue as URI 50-316-01-19-03. Prior to the completion of the NRC staffs risk
significance evaluation for this issue, an additional failure of the Unit 2 TDAFWP
occurred on January 18, 2002. The inspectors reviewed the circumstances of this
subsequent TDAFWP failure to fully assess the adequacy of the licensees previous
apparent cause evaluation and to evaluate the risk significance of the repetitive failure.
b. Findings
The inspectors identified an Apparent Violation of low to moderate risk significance
(White) associated with failure of the licensee to take appropriate corrective actions to
prevent a repetitive failure of the Unit 2 TDAFWP.
Description
On January 18, 2002, the Unit 2 TDAFWP failed to start during performance of time
response testing. The licensee determined that the failure was due to the unlatching of
the TDAFWP trip throttle valve (2-QT-506). A similar TDAFWP failure occurred on
August 10, 2001. Following the January 18, 2002 failure, the licensee declared the
TDAFWP inoperable but reset the trip latch mechanism to align the TDAFWP for
auto-start capability. Although no corrective maintenance was performed on the
TDAFWP, the pump started satisfactorily on January 19, 2002 following a pre-planned
reactor trip to support the Cycle 13 refueling outage.
Following the January 18, 2002 TDAFWP failure, the licensee initiated CR 02018064
and performed a root cause evaluation to determine the cause of the repetitive pump
failures. The licensee concluded that incorrect machining of the trip throttle valve trip
hook, resulting in inadequate alignment of the trip hook and latching up lever faces, was
the root cause of the repetitive failure. In order to open the trip throttle valve, the trip
hook engages the latching up lever to permit admission of steam to the turbine. During
a turbine trip, the trip hook would rotate on the trip hook pin and release the latching up
lever to close the trip throttle valve. Incorrect machining of the trip hook resulted in a
rotational force on the trip hook that would cause the latching mechanism to disengage.
25
A contributing cause to the pump failure was an the incorrect alignment specification for
engagement between the trip hook and latching up lever previously discussed in NRC
Inspection Report 50-315/316-01-19(DRP). Proper machining of the trip hook would
result in a parallel alignment of the trip hook face and the latching up lever face (this
would allow adequate surface area engagement to prevent inadvertent unlatching of the
trip throttle valve).
Following the January 18, 2002 pump failure, the licensee performed a visual inspection
of the trip throttle valve and determined that the faces of the trip hook and latching up
lever were not in parallel alignment, a condition which would cause the trip hook to
disengage the latching up lever under load. The licensee determined that the latch face
of the trip hook had been machined at an incorrect angle, resulting in the failure to
obtain parallel alignment between the faces of trip hook and latching up lever. The result
of this defect was that the trip hook and latching up lever did not engage with full latch
face surface contact, but instead engaged along a line at the edge of the latching up
lever. The defective trip hook mechanism was originally purchased from the Terry
Steam Turbine Company in 1985 under the vendors quality assurance program. The
trip hook was installed on the Unit 2 TDAFWP following a pump failure in June 14, 2000.
The licensee determined that, because the critical dimensions and characteristics of the
trip hook mechanism were not provided to D.C. Cook, it was previously unable to
identify the condition. Because the trip hook and latching up lever engaged along a line
at the end of the latching up lever rather than full surface area contact (due to the
incorrect trip hook latch face angle), it would not have been possible to obtain a
75 percent surface contact during an alignment blue check. Consequently, the licensee
determined that use of the incorrect blue check contact alignment acceptance criteria in
trip throttle valve maintenance procedure 12-MHP 5021.056.007 (i.e., 75 percent line
contact vice 75 percent surface area contact) may have delayed identification of this
condition. Specifically, with the incorrect contact angle between the trip hook and
latching up lever, a 75 percent surface area blue check contact alignment acceptance
criteria would not have been attainable and the installation of the defective trip hook
could have been discovered in June 2000. The Unit 2 TDAFWP was repaired and
retested satisfactorily on February 24, 2002. After the second failure of the Unit 2
TDAFWP, the licensee performed a visual inspection of the Unit 1 TDAFWP and
determined that the contact angle between the trip hook and latching up lever appeared
acceptable. The inspectors concluded that the licensees root cause evaluation was
thorough and reasonable.
Because of the repetitive TDAFWP failures, the inspectors reviewed the effectiveness of
the licensees corrective actions for the August 10, 2001 TDAFWP failure. The
inspectors determined that the licensees failure to promptly evaluate information
obtained during the investigation of the August 2001 TDAFWP failure contributed to the
January 2002 pump failure. On December 13, 2001, the licensee received information
from the trip throttle valve vendor regarding the required specifications for alignment
between the trip hook and the latching up lever. Specifically, the vendor identified the
necessary geometry of the trip hook to avoid generation of a force that would tend to
unlatch the trip mechanism. Additionally, the vendor clarified that the 75 percent blue
check acceptance criteria for alignment between the trip hook and latching up lever
referred to a surface area contact rather than a line criteria. Because the correct blue
check contact alignment criteria (i.e., line contact vice area contact) was not known to
26
the licensee immediately following the August 10, 2001 TDAFWP failure, the licensee
had previously aligned the trip mechanism using a 75 percent line contact acceptance
criteria in August 2001. On December 20, 2002, the licensee performed an operability
evaluation under CR 01354104 to evaluate the use of the line contact trip throttle
mechanism engagement criteria and concluded that both the Unit 1 and Unit 2
TDAFWPs were operable based, in part, on previous successful testing of the pumps.
Although the licensee planned to perform maintenance on the Unit 2 TDAFWP trip
throttle valve during the Cycle 13 refueling outage, no corrective maintenance was
performed on the Unit 2 TDAFWP to evaluate and correct these potential failure
mechanisms prior to the January 18, 2002 failure. Subsequent evaluation by the
licensee following the January 18, 2002 failure identified that the 75 percent area blue
check contact alignment was not met and that the trip hook did not conform to the
required geometric specifications. The inspectors concluded that timely corrective
actions to verify trip hook alignment and geometry consistent with vendor
recommendations could have prevented the January 18, 2002 pump failure.
Based on this corrective action weakness, the inspectors concluded that the licensee
failed to take timely and appropriate corrective action to prevent a repetitive failure of the
Unit 2 TDAFWP. As discussed in NRC Inspection Report 50-315/316-01-19(DRP), the
inspectors previously determined that the licensee failed to specify the correct trip
throttle valve alignment criteria in maintenance procedure 12-MHP 5021.056.007,
"Turbine Driven Auxiliary Feed Pump Trip and Throttle Valve Linkage Adjustment,"
Revision 2. The inspectors concluded that the circumstances and issues associated
with the failure to implement appropriate acceptance criteria in 12-MHP 5021.056.007
were closely related to these corrective action weaknesses. Because the failure to take
timely corrective action for known deficiencies associated with the trip throttle valve
alignment criteria resulted in a repetitive failure of the Unit 2 TDAFWP, the inspectors
considered the corrective action weaknesses to be a more significant regulatory
concern. Consequently, the inspectors evaluated the identified licensee performance
deficiencies, including procedure and corrective action weaknesses, as a single problem
resolution issue.
Analysis
The inspectors assessed this issue using the SDP. The inspectors concluded that the
failures of the Unit 2 TDAFWP and associated fault exposure unavailability time had a
credible impact on safety and was therefore more than a minor concern. Specifically,
the TDAFWP provides secondary decay heat removal capability during certain accidents
including transients, loss of electrical power events, and some losses of primary coolant
events. Consequently, the repetitive failures of the Unit 2 TDAFWP resulting in the
unavailability of a train of auxiliary feedwater was associated with the mitigating systems
cornerstone. The inspectors performed an SDP Phase 1 assessment and determined
that the fault exposure time represented an actual loss of safety function for a single
train of auxiliary feedwater for greater than its TS allowed outage time. As discussed
below, the inspectors estimated that the August 2001 and January 2002 TDAFWP
failures represented approximately 80 days of fault exposure unavailability.
Consequently, the fault exposure time exceeded the TS 3.7.1.2 allowed outage time of
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for a single train of auxiliary feedwater. Based on the results from the Phase 1
27
SDP assessment, the inspectors determined that a Phase 2 SDP assessment was
required.
Because of concerns regarding the accuracy of the D. C. Cook Phase 2 worksheets,
especially with respect to crediting the motor driven auxiliary feedwater pump cross-tie
capability from the other unit, it was determined that it would be more appropriate to
perform a Phase 3 SDP assessment using insights from the licensees updated PRA
model. In coordination with the Region III SRA, the following factors were considered
for this risk evaluation:
C Because the inspectors were unable to determine the exact time that the
TDAFWP became incapable of fully performing its safety function during each of
the two fault exposure periods, the inspectors used the "T/2" fault exposure
methodology (i.e., one half the time between the pump failure and the previous
demonstrated successful operation) to assess this issue. Several factors could
degrade the ability of the trip throttle valve to remain engaged during the fault
exposure period and result in the inability to determine an exact failure time,
including: mechanism wear due to ambient vibration, latch face surface
condition, and trip latch mechanism friction. Use of the "T/2"methodology was
also consistent with the guidance provided in the response to Frequently Asked
Question 291 documented in NEI 99-02, "Regulatory Assessment Performance
Indicator Guideline," Revision 2.
C The inspectors did not consider the ability to recover the TDAFWP following an
unsuccessful start attempt. This conclusion was based on the inability of the
licensee to achieve a successful TDAFWP start during three successive start
attempts on August 10, 2001 and the nature of the repair activities required to
restore the pump to an available status. The inspectors noted that the
successful auto-start of the Unit 2 TDAFWP pump following the
January 18, 2002 failure indicated that the TDAFWP could have potentially been
recovered following this failure. However, due to the similarity of the root cause
for the August 2001 and January 2002 pump failures, the inspectors determined
that recovery credit was not warranted.
C Because the August 2001 and January 2002 TDAFWP pump failures shared a
common root cause, the inspectors concluded that the fault exposure associated
with these failures should be combined to appropriately characterize the risk
significance of the issue. The inspectors determined that the last successful
TDAFWP start attempt prior to the January 18, 2002 failure occurred on
November 2, 2001. Therefore, the January 18, 2002 failure represented an
additional 38 days of "T/2" fault exposure for the Unit 2 TDAFWP. Combining
this fault exposure with the previous 42 days of "T/2" fault exposure from the
August 10, 2001 failure resulted in a total "T/2" fault exposure of approximately
80 days. Based on six successful TDAFWP quarterly surveillance test starts
between June 2000 and January 2002 (including a successful surveillance test
between the August 2001 and January 2002 failures), the application of a single,
longer, fault exposure period for this issue was not considered to be reasonable.
28
C Based on the licensees PRA, the TDAFWP had a risk achievement worth value
of 1.41 and the plant had a baseline core damage frequency (CDF) of 4.85E-5
per reactor year.
Using the methodology and assumptions stated above, the SRA determined that
80 days of fault exposure unavailability resulted in an increase in CDF due to internal
events to be approximately 4.4E-6 with a very small risk impact due to external initiating
events.
Evaluating the impact of this issue on the large early release frequency (LERF), the
SRA focused on dual station blackout transients where hydrogen ignitors would not be
available. (The ignitors are designed to burn hydrogen at low concentrations and thus
reduce the potential for large detonations that could challenge containment integrity.)
The SRA reviewed the licensees Level 2 evaluation, which provided a more refined tool
than IMC 0609, Appendix H, "Containment Integrity Significance Determination
Process." Review of the licensees cutsets determined that the contribution of the dual
unit station blackout was small and the probability of such an event was very low. The
final review determined that the change in LERF was approximately 6E-7.
Based on all the contributing factors, the analyst concluded that the risk significance of
the inspection finding due to the change in CDF due to internal, external and LERF
considerations to be of low to moderate risk significance (White).
Enforcement
10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," states, in part, that measures
shall be established to assure that conditions adverse to quality, such as failures,
malfunctions, deficiencies, deviations, defective material and equipment, and
nonconformances are promptly identified and corrected. In the case of significant
conditions adverse to quality, the measures shall assure that the cause of the condition
is determined and corrective action taken to preclude repetition. Contrary to the above,
the licensee failed to take corrective action to prevent repetition of the failure of the
Unit 2 TDAFWP, a significant condition adverse to quality. Specifically, the Unit 2
TDAFWP failed to start on August 10, 2001 due to the failure of the trip throttle valve
latch mechanism to remain engaged during pump start. On December 13, 2001, the
licensee obtained information from the trip throttle valve vendor identifying critical
parameters for the trip hook mechanism geometry and alignment. The licensee failed to
promptly perform corrective actions to verify that the Unit 2 TDAFWP trip hook
conformed to these critical parameters. Consequently, a second failure of the Unit 2
TDAFWP occurred on January 18, 2002 due to the failure of the trip throttle valve latch
mechanism to remain engaged during pump start. Subsequent investigation determined
that the cause of the August 10, 2001 and January 18, 2002 failures was due to
incorrect trip hook geometry and alignment. This issue was determined to be of low to
moderate risk significance (White) after a Phase 3 SDP review. Consequently, this
issue is identified as Apparent Violation (AV 50-316-02-02-04(DRP)) and is in the
licensees corrective action program as CR 02018064. URI 50-316-01-19-03 is closed.
29
4OA3 Event Followup
.1 (Closed) Licensee Event Report (LER) 50-316-2000-012-01: "Failure to Perform
Increased Frequency Surveillance on 2 East Containment Spray Pump," Supplement 1.
The inspectors reviewed the original LER and determined that the licensees failure to
perform increased frequency surveillance testing on the containment spray pump as
required by TS 4.0.5 was a minor issue. The licensee submitted Supplement 1 to
LER 50-316-2000-012 to revise the root cause evaluation for the event. The inspectors
determined that the information provided in Supplement 1 to LER 50-316-2000-012 did
not raise any new issues or change the conclusions of the initial review, which were
documented in NRC Inspection Report 50-315/316-00-20(DRP). This LER is closed.
.2 (Closed) LER 50-315-2001-002-00: "Power Range Nuclear Instrumentation Calibration
Procedure Not in Conformance with TS". On June 22, 2001, the power range nuclear
instrumentation (PRNI) channel functional test for the Unit 1 quarterly calibration was
not conducted in accordance with TS 3.3.1.1, Table 3.3-1, Action 2a. This TS requires
placing the inoperable PRNI channel in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. To meet the
TS requirement, the PRNI channel is placed in trip before the detectors are
disconnected. Contrary to the TS , the calibration procedure for the PRNI directed that
the bistables for the PRNIs be returned to an untripped state while the detectors are still
disconnected and after the channel has been inoperable for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. On
August 8, 2001, the licensee received NRC approval of a license amendment to revise
TS 3.3.1.1, Table 3.3-1, Action 2a to increase the amount of time allowed to place an
inoperable PRNI channel in the tripped condition from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. On
August 9, 2001, the licensee revised the functional test and calibration procedures to
implement this TS change. The inspectors reviewed the LER and the licensees
corrective actions and did not identify any significant findings. Although this issue was
corrected, it constitutes a violation of minor significance that is not subject to
enforcement action in accordance with Section IV of the NRCs Enforcement Policy.
The licensee entered this violation into its corrective action program as CR 01192045.
This LER is closed.
4OA6 Meetings
.1 Interim Exits
The results of the Occupational Radiation Safety - Access Controls for Radiologically
Significant Areas and ALARA Planning Inspection were presented to Mr. J. Pollock and
other members of licensee management at the conclusion of the inspection on
February 8, 2002. The licensee acknowledged the findings presented. The inspector
asked the licensee whether any materials examined during the inspection should be
considered proprietary. No proprietary information was identified.
The results of the Licensed Operator Requalification Program Inspection were
presented to Mr. B. Wallace and other members of licensee management at the
conclusion of the inspection on March 29, 2002. The licensee acknowledged the
findings presented. The inspectors asked the licensee whether any materials examined
during the inspection should be considered proprietary. No proprietary information was
identified.
30
.2 Resident Inspectors Exit
The inspectors presented the inspection results to Mr. C. Bakken and other members of
licensee management at the conclusion of the inspection on April 5, 2002. The licensee
acknowledged the findings presented. The inspectors asked the licensee whether any
materials examined during the inspection should be considered proprietary. Proprietary
information was examined during this inspection but is not specifically discussed in this
report.
31
KEY POINTS OF CONTACT
Licensee
G. Arent, Manger, Regulatory Affairs
C. Bakken, Senior Vice President, Nuclear Generation
R. Brown, Manager, Operations Training
L. Dean, ALARA Supervisor
S. Freeman, Administrative Assistant, Training Department
R. Gaston, Regulatory Compliance Manager
J. Gebbie, Manager, System Engineering
S. Greenlee, Director, Nuclear Technical Services
N. Jackiw, Regulatory Affairs
E. Larson, Director, Operations
J. Mathis, Regulatory Affairs
R. Meister, Regulatory Affairs
D. Moul, Assistant Manager, Operations
W. Nichols, Supervisor, Operator Requalification Training
D. Noble, Manager, Radiation Protection
T. Noonan, Director, Performance Assurance
J. Pollock, Site Vice President
B. Robinson, General Supervisor, Radiation Protection Support
R. Smith, Assistant Director, Plant Engineering
B. Wallace, Manager, Training
D. Wood, Manager, RadChem Environmental
T. Woods, Regulatory Affairs
NRC
A. Vegel, Chief, Reactor Projects Branch 6
S. Burgess, Senior Reactor Analyst
H. González, Nuclear Safety Intern
D. Rivera-Martinez, Nuclear Safety Intern
32
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-316-02-02-01 URI Failure to perform adequate maintenance and testing on
valve 2-CS-369 resulted in gas binding the Unit 2 west
centrifugal charging pump (Section 1R19)
50-316-02-02-02 NCV Failure to use valid acceptance criteria for stroke time testing
the Unit 2 pressurizer power operated relief valves
(Section 1R22)
50-316-02-02-03 URI Contract worker failed to comply with radiological protection
instructions and to immediately vacate a work area upon
receiving an electronic dosimeter alarm (Section 2OS2.6)
50-316-02-02-04 AV Failure to take prompt corrective action to prevent repetitive
failure of the Unit 2 turbine driven auxiliary feedwater pump
(Section 4OA1)
Closed
50-316-02-02-02 NCV Failure to use valid acceptance criteria for stroke time testing
the Unit 2 pressurizer power operated relief valves
(Section 1R22)
50-316-01-19-03 URI Apparent violation of 10 CFR Appendix B, Criterion V for the
failure to incorporate adequate quantitative acceptance
criteria in turbine driven auxiliary feedwater pump
maintenance instructions (Section 4OA1)
50-316-2000-012-01 LER Failure to perform increased frequency surveillance on 2 east
containment spray pump (Section 4OA3)
50-315-2001-002-00 LER Power range nuclear instrumentation calibration procedure
not in conformance with technical specifications
(Section 4OA3)
Discussed
50-316-2000-012-00 LER Failure to perform increased frequency surveillance on 2 east
containment spray pump (Section 4OA3)
33
LIST OF ACRONYMS USED
ADAMS Agency-wide Documents and Management System
AEP American Electric Power
ALARA As Low As Is Reasonably Achievable
ATR Administrative Technical Requirement
AV Apparent Violation
CCP Centrifugal Charging Pump
CCW Component Cooling Water
CDF Core Damage Frequency
CFR Code of Federal Regulations
CR Condition Report
CRDM Control Rod Drive Mechanism
DC Direct Current
DCP Design Change Package
DIT Design Information Transmittal
DRP Division of Reactor Projects
DRS Division of Reactor Safety
ECCS Emergency Core Cooling System
ED Electronic Dosimeter
EHP Engineering Head Procedure
ESW Essential Service Water
gpm or GPM Gallons Per Minute
IHP Instrumentation Head Procedure
IMC Inspection Manual Chapter
JO Job Order
KV Kilo-volt
LER Licensee Event Report
LERF Large Early Release Frequency
LOR Licensed Operator Requalification
LORT Licensed Operator Requalification Training
LTOP Low Temperature Over-pressure Protection
MHP Maintenance Head Procedure
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
NUMARC Nuclear Management and Resources Council
OA Other Activities
OHP Operations Head Procedure
ORAM Outage Risk Assessment and Management
OSHA Occupational Safety and Health Administration
PARS Publically Available Records
PMI Plant Managers Instruction
PMP Plant Managers Procedure
PORV Power Operated Relief Valve
PRA Probabilistic Risk Assessment
PRNI Power Range Nuclear Instrument
Radworker Radiation Worker
34
RCA Radiological Controlled Area
RO Reactor Operator
RP Radiation Protection
RPT Radiation Protection Technician
RWP Radiation Work Permit
RWST Refueling Water Storage Tank
SDP Significance Determination Process
SI Safety Injection
SOER Significant Operating Event Report
SRA Senior Reactor Analyst
SRO Senior Reactor Operator
SSC Structures, Systems, and Components
STP Surveillance Test Procedure
TBD To Be Determined
TDAFWP Turbine Driven Auxiliary Feedwater Pump
TDB Technical Data Book
TEDE Total Effective Dose Equivalent
TS Technical Specification
U2C13 D.C. Cook Unit-2, 13th Refueling Outage
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
VCT Volume Control Tank
35
LIST OF DOCUMENTS REVIEWED
1R04 Equipment Alignment
Plant Managers Restraint of Transient Material Revision 1
Procedure (PMP)
5020.RTM.001
12-MHP-5021.SCF.001 Scaffolding Guidelines Revision 0b
01-OHP-5030.001.001 Operations Plant Tours Revision 19b
01-OHP-4021.016.003 Operation of the Component Cooling Revision 15a
Water System During System Startup and
Power Operation
Flow Diagram CCW [Component Cooling Water] Pumps Revision 40
OP-1-5135-40 and CCW Heat Exchangers
Flow Diagram CCW Safety Related Loads Revision 41
OP-1-5135A-41
Flow Diagram CCW Miscellaneous Services Auxiliary Revision 3
OP-1-5135C-3 Building
Flow Diagram Auxiliary Feedwater Unit 1 Revision 50
OP-1-5106A-50
Condition Report (CR) NRC Identified That Procedure March 8, 2002
02067020 01-OHP-4023-SUP-002, "Restoration of
Reserve Power to 4KV [Kilovolt] Buses"
Needs to Be Revised to Correct
Typographical Error
CR 02084028 1-CFA-421 (West CCP [Centrifugal March 24, 2002
Charging Pump] Coolers CCW Outlet Low
Flow Alarm Switch) Indicates High
Off-scale and Greater Than Limit of 80
Gallons Per Minute (GPM) Specified in
01-OHP-5030-001-001
CR 02085001 NRC Identified Several Scaffolding March 25, 2002
Installations That Were Contacting Safety
Related Equipment
CR 02089018 NRC Identified Packing Leak on March 30, 2002
1-CCW-404W
CR 02089019 NRC Identified Conduit From 1-CMO-420 March 30, 2002
Has Pulled Out of the Junction Box
36
CR 02089020 NRC Identified Packing Leak on March 30, 2002
1-CCW-187W
CR 02089023 NRC Identified Packing Leak on March 30, 2002
1-CCW-197S
1R05 Fire Protection
Updated Final Safety Fire Protection System
Analysis Report,
Section 9.8.1
D. C. Cook Nuclear Plant Fire Hazards Revision 8
Analysis, Units 1 and 2
D. C. Cook Nuclear Plant Units 1 and 2 February 1995
Probabilistic Risk Assessment, Fire
Analysis Notebook
National Fire Protection Standard for Gaseous Hydrogen at
Association 50A Consumer Sites
Branch Technical Storage of Flammable Gases
Position 9.5-1,
Appendix A,
Section D.2
PMP 2270.CCM.001 Control of Combustible Materials Revision 1
PMP 2270.FIRE.002 Responsibilities for Cook Plant Fire Revision 0
Protection Program Document Updates
PMP 2270.WBG.001 Welding, Burning and Grinding Activities Revision 0
Plant Managers Fire Protection Revision 26
Instruction (PMI) 2270
12-QHP-4030-STP.009 Inspection of Fire Dampers Protecting Revision 0
Safety-Related Areas
12-PPP-4030-066-021 Inspection of Fire Dampers Protecting Revision 1
Safety-Related Areas
Design Change Relocate Main Generator Hydrogen Bulk Revision 0a
Package (DCP) Storage Tanks from the Unit 1 Side to the
12-DCP-5012 Unit 2 Side
Job Order (JO) Perform 18 Month Surveillance of August 20, 1999
R0084548 Administrative Technical Requirements
Fire Dampers
37
JO R0096948 Perform 18 Month Surveillance of April 2, 2001
Administrative Technical Requirements
Fire Dampers
Drawing 12-5717-15 Heating and Ventilating Auxiliary Building Revision 15
Center North, South & West Plan Floor
Elevation 609-0"
CR 99-18790 OSHA [Occupational Safety and Health July 17, 1999
Administration] Requirement Not Being Met
for Reactor Hydrogen System
CR 02053067 NRC Identified That Cable Separation in February 22, 2002
the Unit 1 West CCP Room Did Not
Conform to D. C. Cook Specification
CR 02064061 List of NRC Identified Issues in the March 5, 2002
Switchgear Cable Vault
CR 02064067 NRC Identified Issue, 1-EIC3 Cable Tray March 5, 2002
Missing Screws
CR 02064070 NRC Identified Excessive Combustible March 5, 2002
Trash in the Unit 1 Auxiliary Cable Vault
1R11 Licensed Operator Requalification Program
Licensed Operator Requalification Training
(LORT) Simulator Evaluation Scenarios for
March 6, 2002
LORT Plan D. C. Cook Licensed Operator 2001-2002
Requalification (LOR) 2 Year Training Plan
Written Exam 2002 Licensed Operator Requalification March 14, 2002
RQ2526 A-R, Biennial Written Exam - Crew A
RQ2526 A-S Week Six - Reactor Operator (RO) and
Senior Reactor Operator (SRO)
Operating Exam 2002 Two Simulator Scenarios: March 15, 2002
Simulator Scenarios RQ-E-1712A, RQ-E-2008A
Operating Exam 2002 Five JPMs: RO-O-E235 (Revision 3), Various
Job Performance RO-O-E026 (Revision 7), RO-O-S001
Measures (JPMs) (Revision 3), AE-O-E217 (Revision 10),
AE-O-N001 (Revision 6)
TI-TROP-01 Training Program Examination Revision 8,
Requirements February 22, 2002
38
TAP-400 Systematic Approach to Training Revision 2,
Implementation September 25, 2001
TAP-400-040 Conduct of Training Revision 0,
October 8, 1999
TIF (IMP 03) Weekly Training Attendance Sheets Year 2001
(Year 25 (2001), Crews B, C, D, and
Validation)
TIF (IMP 10) Remediation Qualification Attempt Reports Year 2002
TIF (IMP 27) Simulator Crew Evaluation Standards Revision 5,
February 21, 2002
TIF (IMP 29A) SRO Individual Simulator Performance March 27-29, 2002
Evaluations - Crew A - Week Six
TIF (IMP 29B) RO Individual Simulator Performance March 27-29, 2002
Evaluations - Crew A - Week Six
TIF (IMP 29D) Shift Manager Simulator Evaluations - March 27-29, 2002
Crew A - Week Six
TIF (IMP 29E) JPM Summary Sheets - Crew A March 27-29, 2002
TIF (IMP 47) Missed Scheduled Training Notifications Year 2001-Various
TAP-600-030 Simulator Configuration Control Revision 1,
July 27, 2001
TPD-600-EPT Emergency Plan Training Program Revision 1,
Description December 20, 2001
TPD-600-LOR LORT Program Description Revision 5,
October 31, 2001
LORT Task List Task List Review for LOR Years 26 and 27 2001/2002
(RO/SRO Requal years 2001/2002)
LORT 2 Year Matrix 2 Year Training Cycle (2001/2002) Matrix 2001/2002
Listing Period, Theme, Dominant Accident
Sequence from IPE, Selected Tasks,
Topics, and Procedures
Feedback Forms Ten LOR Crew Training Assessment January 2001
Debrief Completed Forms through
December 2001
OHI-2070 Training and Qualification Revision 14,
June 06, 2001
39
OHI-2070, Operator License/Shift Technical Advisor 1st Quarter 2002
Attachment 8 Status Report
OHP-4025.001.001 Emergency Remote Shutdown Revision 3,
May 15, 2001
PMP 2070.600 Training Administration and Qualification Revision 0,
May 30, 2001
SA-2000-TRN-001 Training Comprehensive Self Assessment September 22, 2000
SA-2001-TRN-009 Training Comprehensive Self Assessment January 11, 2002
PA-01-16 Performance Assurance Audit on Training February 9, 2001
through
March 9, 2001
Computer Listing Classroom Attendance Computer Listing June 2000
for RQ-C-2534 (Technical Specifications through
and Bases for 3/4.1 & 3/4.2), RQ-C-2544 July 2001
(Emergency Diesel Generator), RQ-C-2573
(Emergency Plan Procedures)
Action Time Matrix Operator Action Time Requirements by November 28, 2000
Procedure Based on DIT-B-01061-05
Medical Records Selection of Eight Licensed Operator Various
Medical Records (Four SROs and Four
ROs)
Medical Records Computer Print Out - Periodic Report on Various
License Medical Data (Medical Exam Due
Dates)
Watch Proficiency Log Licensed Operator Proficiency Watch 1st Quarter 2002 -
Record Various
CR P-00-09097 Condition Report Concerning Inconsistent June 23, 2000
Procedure Use
CR 01046023 Condition Report Concerning Repeat February 15, 2001
Failure to Properly Store Training Records
CR 01047027 Condition Report Concerning Apparent February 16, 2001
Cause and Extent of Condition Evaluation
Not Conducted In Accordance With
Requirements
CR 02052065 Discrepancies on Annual LOR Examination February 21, 2002
Material for the First Week of Examinations
40
CR 01054050 Condition Report Concerning Actions February 23, 2001
Taken for Apparent Cause Not
Documented
CR 01057044 Condition Report Concerning Failure to February 26, 2001
Include Cross Reference to Condition
Reports
CR 01067028 Condition Report Concerning Training March 08, 2001
Department Compliance with Procedure
Requirements
CR 02074043 Lack of Validation for a New or Significantly March 13, 2002
Modified Scenarios
CR 02074044 Potential Examination Compromise During March 14, 2002
Written Exam Administration
CR 02087034 Incorrect Emergency Plan Classification March 27, 2002
Number Referenced in a Simulator
Evaluation Scenario - RQ-E-2008A
CR 02088010 Requirement to Notify the NRC of Possible March 29, 2002
10 CFR 55.25 Condition Based on
Medication Prescribed to an Operator
CR 02092037 Adequacy of Completing the Plant Accident April 2, 2002
Notification Forms for Emergency Plan
Notifications in Real Time
CR 02092039 Appropriateness of Scheduling and April 2, 2002
Administering the Biennial Written
Examination During the First Year of the
2-Year Plan
CR 02092042 JPMs Selected During the Annual April 2, 2002
Operating Examination Having Greater
Than 50 Percent Repeatability
CR 02092044 Emergency Remote Shutdown Procedure April 2, 2002
Inconsistencies
1R12 Maintenance Rule Implementation
12-EHP-5035-MRP-001 Maintenance Rule Program Administration Revision 4
NUMARC 93-01 Industry Guideline for Monitoring the Revision 2
Effectiveness of Maintenance at Nuclear
Power Plants
41
Donald C. Cook Probabilistic Risk April 13, 1992
Assessment
Hydrogen Ignitor (DIS) System Notebook
Maintenance Rule Scoping Document for October 11, 2001
the Hydrogen Ignitor System
Maintenance Rule Scoping Document for Revision 1
Maintenance Rule Scoping Document for Revision 1
the Compressed Air System
Maintenance Rule (a)(1) Action Plan No Date
Briefing Sheet for the Unit 1 Circulating
Water System
Maintenance Rule (a)(1) Action Plan for the Revision 0
Unit 1 Circulating Water System August 3, 2001
Maintenance Rule (a)(1) Action Plan for the Revision 1
Unit 1 Circulating Water System March 5, 2002
Maintenance Rule Performance Monitoring February 27, 2000
Data for the Compressed Air System through
February 27, 2002
Maintenance Rule Reliability Failures March 18, 2002
(3/18/00 to 3/18/02) for All Systems Where
Failures Have Exceeded Performance
Criteria By 50 Percent or Greater
EP 01-086 Maintenance Rule Expert Panel Meeting May 17, 2001
Minutes
System Health Report for the Unit 1 October 1, 2001
Circulating Water System through
December 31, 2001
System Health Report for the Unit 2 October 1, 2001
Circulating Water System through
December 31, 2001
System Health Report for the Compressed October 1, 2001
Air System through
December 31, 2001
JO 01079034-01 2-HE-10E Inspect Condenser 24 Inch January 23, 2002
Supply Piping
Work Request 2-HE-10W Inspect Condenser 24 Inch February 9, 2002
01088050 Supply Piping
42
CR 00-8322 Low Voltage and Current on Unit 2 Trains June 7, 2000
A and B Lower Ignitors
CR 00-8410 Voltage Regulator 2-VR-LDISA-2 Voltage June 8, 2000
Cannot Be Adjusted
CR 00-8412 Voltage Regulator 2-VR-LDISB-4 Output June 8, 2000
Voltage Cannot Be Adjusted
CR 00-9307 The Glow Plug for Hydrogen Ignitor June 28, 2000
2-UDISA-A6 Was Replaced but Post
Maintenance Testing Was Not Performed
as Specified in the JO
CR 00-10893 Unit 2 Plant Air Compressor Surged and August 4, 2000
Could Not be Reloaded to Provide Plant
and Control Air
CR 00-11711 Expert Panel Approved (a)(1) Status for the August 23, 2000
Hydrogen Ignitor System Based on
Exceeding the Performance Criteria for
Unavailability
CR 00256041 2-VR-LDISB-4 Output Voltage out of September 12, 2000
Specification High 122.56 Volts (118 - 122
Volts)
CR 00310018 Distributed Ignition Voltage Regulator November 4, 2000
Transformers Are Defective
CR 01012015 The Unit 2 Containment Hydrogen Glow January 12, 2001
Plugs Are Obsolete and must Be Replaced
CR 01046054 A Manual Reactor Trip Was Performed February 15, 2001
Upon Recognition That the East Main
Feedwater Pump Had Tripped on High
Back Pressure
CR 01047054 Lower Containment Train B Voltage February 16, 2001
Regulator-4 (2-LDISB-4) Reading High Out
of Specification at 230 Volts
CR 01061036 Installed Breaker Has Incorrect Size March 2, 2001
Current Transformers
CR 01159049 Re-perform a Maintenance Rule Evaluation June 8, 2001
for the Condition Described in CR 00-8322
CR 01163041 Problem Identified with Maintenance Rule June 12, 2001
Evaluation for CR 00-8321 Involving a
Failure of Glow Plug A6
43
CR 01163043 Discrepancies Identified in Maintenance June 12, 2001
Rule Evaluation for CR 00256041
CR 01171032 CR 00-8412 Maintenance Rule Evaluation June 20, 2001
Is Inadequate
CR 01184053 Hydrogen Ignitor System Maintenance July 3, 2001
Rule Scoping Document Has No "Trigger
Value"
CR 01207075 The Maintenance Rule Evaluation July 26, 2001
Performed Under CR 00-10893 Was
Inadequate
CR 01277005 Review of Previously Completed October 4, 2001
Maintenance Rule Evaluation for
CR 00330032 Indicates the Evaluation May
Be Lacking in Detail, Incorrect, or the
Conclusions Not Fully Supported
CR 01310021 2-VR-LDISB-4 Will Not Maintain November 6, 2001
Acceptable Voltage Value
CR 02080014 NRC Identified That Maintenance Rule March 21,2002
Evaluation of CR 01163041 for a Glow
Plug Failure Incorrectly Concluded That the
Failure Was Not a Functional Failure
CR 02080016 NRC Identified Inconsistency in March 21, 2002
Maintenance Rule Scoping Document for
the Distributed Ignition System Regarding
System PRA Risk Significance
Maintenance Rule Scoping Document Revision 1
Component Cooling Water System
System Health Report Period 10/31/01 to
Component Cooling Water 12/31/2001
CR 00356032 Component Cooling Water Maintenance December 21, 2000
Rule History Review
CR 01186039 Maintenance Rule Evaluation for CR July 5, 2001
00323052 associated with low CCW flow to
a CTS pump was inadequate
CR 01101073 2-CCR-440 failed to indicate closed during April 11, 2001
IST testing
CR 00241011 CCW Surge Tank Level Indicator August 28, 2000
2-CLR-410 failed
44
CR 01268056 Indications Found in Welds for CCW Heat September 25, 2001
Exchanger Divider Plate
CR 01277001 1-CCR-440 Failed IST Stroke Time Testing October 4, 2001
1R13 Maintenance Risk Assessments and Emergent Work Control
PMP-2291-OLR-001 On-Line Risk Management Revision 2
NUMARC 93-01 Industry Guideline for Monitoring the Revision 2
Effectiveness of Maintenance at Nuclear
Power Plants, Section 11, "Assessment of
Risk Resulting From Performance of
Maintenance Activities"
PMP 2291-OLR-001 On-Line Risk Management Work Schedule March 10-16, 2002
Data Sheet 1 Review and Approval Form
Cycle 40, Week 9
PMP 2291.OLR.001 On-Line Risk Management Work Schedule March 24 - 30, 2002
Data Sheet 1 Review and Approval Form
Cycle 40, Week 11
Unit 2 Control Room Logs March 23-24, 2002
Unit 1 and 2 Supervisors Turnover Logs March 14, 2002
Clearance Log, Units 1 and 2 March 14, 2002
JO R0214681 2-PP-10W, Change Oil in Bearing August 16, 2001
Reservoir
JO R0220047 2-PP-10W, Change Oil in Bearing March 24, 2002
Reservoir
CR 02075007 NRC Identified Several Issues Involving March 14, 2002
Housekeeping, Scaffolding, and Restraint
of Transient Material
CR 02082003 Failure of Main Turbine Control Valves March 23, 2002
During Testing
CR 02082006 Unit 2 Control Rods Withdrew Continuously March 23, 2002
Without Temperature Error Mismatch
CR 02098031 NRC Identified That Post Maintenance April 8, 2002
Testing for the 2 West CCW Pump on
March 24, 2002 Was Not Performed In
Accordance With the Associated Job Order
45
1R15 Operability Evaluations
D.C. Cook Nuclear Plant Unit 2 Technical
Specifications
D. C. Cook Nuclear Plant Updated Final
Safety Analysis Report
NRC Safety Evaluation Report for Cook September 1, 1995
Nuclear Plant Unit 2 Amendment 185
Generic Letter 91-18 Information to Licensees Regarding NRC Revision 1
Inspection Manual Section on Resolution of
Degraded and Nonconforming Conditions
PMP-7030-ORP-001 Operability Determinations Revision 6
02 OHP 5030.050-001 Main Turbine Oil Overspeed Operability Revision 1
Check
02 OHP 5030-050-002 Main Turbine Overspeed Test Revision 0
Letter AEP NRC 1168A Technical Specification Change Request to February 15, 1994
Delete Turbine Overspeed Protection
Requirements
Cook Plant Operations Review Committee February 16, 2002
Meeting Minutes
Unit 2 Caution Tag Log March 18, 2002
CR 98-06995 Unit 1 West Essential Service Water November 13, 1998
(ESW) Pump Room Supply Fans Are
Freewheeling Opposite of the Direction for
Rotation Indicated by Rotation Arrow
Mounted on Fan Housing
CR 99-02455 Residual Heat Removal Pumps May Be February 11, 1999
Experiencing Cavitation
CR 99-07602 Calculation PS-4KVD-002 Shows That the April 5, 1999
Momentary Ratings on the 4 KV Circuit
Breakers Are Exceeded for Fault
Conditions
CR 99-15072 4 KV Degraded Voltage Relay Technical June 9, 1999
Specification Lower Allowable Limit Is Not
Adequate to Protect Connected Safety
Related Motors
46
CR 99-17063 The Acceptance Criteria for Filter Maximum June 28, 1999
Allowable Pressure in Procedure
01-OHP-5030.001.001 Is Not Consistent
With Maximum Pressure Considered in
Calculation DCCHV12FH01S
CR 99-29182 A Revised Control Room Dose Analysis December 15, 1999
From Westinghouse Will Be Submitted to
the NRC for Their Approval
CR 00-01079 The Supply Air to the Valve Actuators of January 20, 2000
1/2-CCR-460, 1/2-CCR-462, 1/2-CRV-412
Exceeds the Manufacturer's Maximum
Allowable Casing Pressure
CR 00-01973 Existing Unit 2 Small Bore Piping Concerns February 2, 2000
That Resulted in Post Restart Design
Changes Based on Operability Criteria
CR 00-02125 Unit 2 Large Bore Piping Modifications February 4, 2000
Which Were Identified in the 02-DCP-0164
and 02-DCP-0647 and Most of These
Modifications Will Be Implemented Post
Restart
CR 00-03032 Some of the Small Bore CCW Piping February 22, 2000
Attached to the Reactor Coolant Pump
Thermal Barrier Is Not Adequately
Supported to Accommodate the Thermal
Movement of the Pumps
CR 00-07070 Calculation MD-12-CCW-818-N, May 16, 2000
Revision 0, Does Not Evaluate the Outside
of Containment Forged Head Assembly
CR 00279011 The Evaluation for CR 00-6696 Improperly October 5, 2000
Evaluated the Possibility of Hydraulic
Locking in Non-essential Service Water
Containment Isolation Valves
CR 01032027 Current Procedures Preferentially Align February 1, 2001
Residual Heat Removal System to
Flowpaths That Do Not Have the Required
Ventilation From the Hot Sleeve Ventilation
System
CR 01275031 During Unit 2 ESW Flow Verification October 2, 2001
Testing, ESW Flow to the Unit 2 West
CCW Heat Exchanger Was 30.4 GPM
Below the Acceptance Limit of 5520.6 GPM
47
CR 02036021 Document an Aggregate Operability February 5, 2002
Determination Evaluation to Support Unit 2
Restart Following the February 2002
Refueling Outage
CR 02050022 Control Switch 1-101-NRV-152 May Not Be February 19, 2002
in the Automatic Position Fully
CR 02057005 During Performance of February 22, 2002
02-OHP-5030-050-001, an Actual Turbine
Trip Occurred on the Second Attempt at
Overspeed Operability Checks
1R17 Permanent Plant Modifications
2-DCP-4821 Install New Impellers in the Containment Revision 0
Spray Pumps (2-PP-9E&W)
Design Change East Containment Spray Pump Revision 0
Package Procedure Performance and Flow Test
02-DCP-4821-TP.1
Calculation Unit 2 Emergency Core Cooling System Revision 1
MD-02-ECCS-005-N Pumps Net Positive Suction Head Analysis
Calculation Spray Additive Eductor Performance Revision 3
MD-12-CTS-117-N
Calculation Minimum Operability Limits for Revision 1
MD-12-CTS-135-N Containment Spray Pumps
JO 01102007 2-DCP-4821: 2-PP-9E, Install 5 Vane February 19,2002
Impeller
CR 02040037 During Pump Performance Run of 2-PP-9E February 9, 2002
East Containment Spray Pump Per
2-DCP-4821-TP.1, the Pump Developed
Head Was less than the Acceptance
Criteria
1R19 Post Maintenance Testing
Administrative Emergency Diesel Generators
Technical Requirement
2-EDG-1
01 OHP 4030-119-022E East Essential Service Water System Test Revision 2
48
12 IHP 6030-RLY-008 ABB Solid State Differential Relay Type Revision 0,
87M Series 419M Calibration and Change 0
Maintenance
12 IHP 6030-RLY-009 ABB Solid State Differential Relay Type Revision 2a,
87T Series 419 Calibration and Change 0
Maintenance
12 MHP 5021-001-023 Manual Diaphragm Valve Maintenance Revision 6,
Change 12
PMP 4043.SLV.001 Sealed/Locked Valves Revision 4
PMP 2291.PMT.001 Work Management Post Maintenance Revision 2
Testing Matrices
PMP 2291.TRS.001 Troubleshooting Plan for 2 CD Diesel February 8, 2002
Data Sheet 1 Generator Speed Variations
(CR 02039004)
Vendor Manual ITT Engineered Valves Maintenance and Revision 0
VTD-ITEV-0016 Instruction Manual for Handwheel
Operated Diaphragm Valves
Vendor Manual DIA-FLO Diaphragm Valves Installation, Revision 0
VTD-ITEV-0017 Operation, and Maintenance Manual
Vendor Manual DIA-FLO Handwheel Operated Diaphragm Revision 2
VTD-ITEV-0027 Valves
Engineering Programs Safety Related Pump In-service Test Revision 73
Technical Data Book, Hydraulic Reference
Figure 1-15.1
Engineering Programs Safety Related Pump In-service Test Revision 65
Technical Data Book, Vibration Reference
Figure 1-15.2
JO 01094018 2-CS-369, Replace Diaphragm February 22, 2002
JO 01225007 2 CD Diesel Generator Returned Fuel February 11, 2002
Injection Linkage to Approved
Configuration
JO 01262081 Rebuild the Unit 1 East ESW Pump March 13, 2002
1-PP-7E
JO 01323026 Investigate Motor Electrical Short of March 13, 2002
1-PP-7E
JO 02032010 Perform Overcurrent Testing on February 20, 2002
2-EZC-C-2B
49
JO 02039004 Troubleshoot/Repair 2-OME-150-CD February 12, 2002
Control Circuitry
JO 02047020 Replace 24 Volt DC [Direct Current] Power January 2, 2002
Supply PS2 at 2-PS-CGC-19
JO 02049054 Troubleshoot and Repair 600 Volt Supply February 21, 2002
Breaker to the Unit 2 CD2 Battery Charger
That Tripped Twice
JO 02049080 Investigate, Calibrate, Replace Relay February 19, 2002
2-87-DGCD-3 As Required
JO 02050025 Investigate, Calibrate, Replace Relay February 20, 2002
2-87-T21C-1 As Required
JO 02050026 Investigate, Calibrate, Replace Relay February 20, 2002
2-87-T21D-1 As Required
JO R0208707 Calibrate East ESW Header Pressure March 12, 2002
Switch
JO R0209205 Calibrate Time Delay Relays for East ESW March 12, 2002
Pump Strainer
Dedication Plan Inspection and Refurbishment of Revision 7
HP-0035 Emergency Diesel Generator Governor or
Procurement of New Governor
CR 97-3562 SOER [Significant Operating Event Report] December 10, 1997
97-1, Potential to Gas Bind Pumps
Providing Safety Boron Injection Function
CR 02039033 Between February 2, 2002 and February 3, February 8, 2002
2002 There Were Ten CRs Initiated to
Document Snubbers Installed Backwards
CR 02042009 Dedication Plan HP-0035 Needs to Be February 11, 2002
Revised
CR 02047050 The Unit 2 West CCP Showed Signs of Air February 16, 2002
Entrainment During Attempts to Swap
CR 02047051 Check Stem Nut Setting on 2-CS-369 February 16, 2002
CR 02049054 The CD2 Battery Charger Failed to Control February 18, 2002
Bus Voltage Resulting in Multiple Control
Room Annunciators and a Large Current
Loading on the Charger
CR 02049057 CD Battery Ground February 18, 2002
CR 02049063 Observed Electrical Flash From 2-RPST-B February 18, 2002
50
CR 02049080 During Investigation for 2-BC-CD-2, Found February 18, 2002
2-87-DGCD-3 Relay As a Possible Issue
for Repairs
CR 02049081 Per 2-BC-CD-2 Battery Charger February 18, 2002
Troubleshooting, Need to Investigate Unit 2
Solid State Protection System Equipment
for Possible Damage
CR 02050025 Test, Repair, or Replace as Necessary, the February 19, 2002
Differential Relays for Transformer TR21C
Following the 250 Volt DC System Anomaly
on February 18, 2002
CR 02050026 Test, Repair, or Replace as Necessary, the February 19, 2002
Differential Relays for Transformer TR21D
CR 02050050 Verify Correct Stem Nut Setting on Valve February 19, 2002
1-CS-369
CR 02072061 During the Coupled Run on the 1E ESW March 13, 2002
Pump the Instantaneous Overcurrent
Alarm Came in and Smoke Was Noted at
the Motor Termination Box
CR 02080039 NRC Identified That Post Maintenance March 21, 2002
Testing Specified in JO 02039004 Did Not
Incorporate the Guidance Contained in
PMP 2291.PMT.001 for Post Maintenance
Testing Following Actuator Replacement
1R20 Refueling and Outage Activities
D.C. Cook Nuclear Plant Unit 2 Technical
Specifications
D. C. Cook Nuclear Plant Updated Final
Safety Analysis Report
02-OHP-4021-001-001 Plant Heatup From Cold Shutdown to Hot Revision 26, C3
Standby
02-OHP-4021-001-002 Reactor Start-Up Revision 22, C0
02-OHP-4021-001-006 Power Escalation Revision 19, C0
2-OHP-4030-STP-041 Refueling Integrity Revision 8
12-EHP-4030-002-356 Lower Power Physics Testing With Revision 0A, C1
Dynamic Rod Worth Measurement
51
12-MHP-4030.031.001 Inspection of Lower Containment and Revision 0, C1
Recirculation Sumps
PMP 4100-SDR-001 Plant Shutdown Safety and Risk Revision 5, C1
Management
Daily Shift Managers Logs February 10, 2002
through
February 28, 2002
Memo From R.W. Unit 2 Time to 200EF and Time to Boil January 4, 2002
Hennen to Shift Figures for the Refueling Outage
Technical Advisors
U2C13 Outage Schedule Shutdown Risk
Review
D. C. Cook Unit 2 2000 Final Core Map
D. C. Cook Unit 2 Cycle 13 Final Core Map
D. C. Cook Unit 2 Cycle XII - XIII Core
Unload Fuel Handling Movement Sequence
D. C. Cook Unit 2 Cycle XII - XIII Core
Reload Fuel Handling Movement Sequence
D. C. Cook Unit 2 Cycle 13 Core Operating Revision 0
Limits Report
JO R0203029 549 Day Surveillance for Unit 2 February 13, 2002
Containment Sumps
Drawing 12-3902A-0 Recirculation Sump & Screen Repair Revision 0
Containment Building Unit No. 1 & 2
Drawing 12-3902-9 Unit 1 & Unit 2 Containment Building Revision 9
Miscellaneous Frames
CR 02044004 NRC Identified Coating Degradation on February 13, 2002
Nuts Holding Level Instrumentation Well
Lateral Support Brackets
CR 02044006 NRC Identified Screens Had a Gap Larger February 13, 2002
Than the 1/4 Inch Requirement Allowed
Per Procedure 12-MHP-4030.031.001
CR 02044060 JO 195371-02 Was Taken to Complete February 13, 2002
Status Without Performing the Required
Protective Coatings in the Recirculation
52
CR 02058037 Corrupted Computer File Results in February 27, 2002
Incorrect Measured Control Rod Worth
During Low Power Physics Testing
1R22 Surveillance Testing
D.C. Cook Nuclear Plant Unit 2 Technical
Specifications
D. C. Cook Nuclear Plant Updated Final
Safety Analysis Report
Updated Final Safety Emergency Power System Revision 17
Analysis Report,
Section 8.4
Technical Specification Engineered Safety Feature Actuation Amendment 187
3.3.2.1 System Instrumentation
Administrative Emergency Diesel Generators Revision 10
Technical Requirement
2-EDG-1
Rapid Event Response Report for January 21, 2002
CR 02020031
02-OHP 4030-001-002 Containment Inspection Tours Revision 13
02-OHP 4030-202-060 Pressurizer Relief Valve Testing Revision 0, C0
02-OHP DG2CD Load Sequencing & ESF Testing Revision 3
4030-232-217A
02-OHP East Containment Spray System Revision 16
4030.STP.007E Operability Test
Design Information Test Procedure Acceptance Criteria for Revision 6
Transmittal (DIT) Containment Spray Pumps (1(2)-PP-9E,
B-00770 &9W)
DIT-B-01542 Acceptable Back-leakage Flow Rate Revision 0
Through 2-CTS-120E with Regards to
Containment Spray and Recirculation
Sump pH Analysis
DIT-B-01544 Acceptable Back-leakage Flow Rate Revision 1
Through Spray Additive Tank Check
Valves with Regards to Containment Spray
and Recirculation Sump pH Analysis
53
DIT-B-02327 Stroke Time Acceptance Criteria for Revision 0
1(2)-NRV-152, -153
Calculation Determination of Available Pressurizer Revision 1
MD-12-CA-004-S Power Operated Relief Valve Strokes
Using the Auxiliary Air Supply
Calculation Spray Additive Eductor Performance Revision 3
MD-12-CTS-117-N
Calculation Minimum Operability Limits for Revision 1
MD-12-CTS-135-N Containment Spray Pumps
Engineering Programs Safety Related Pump In-service Test Revision 59
Technical Data Book, Hydraulic Reference
Figure 2-15.1
Engineering Programs Power Operated Relief Valve Stroke Time Revision 52
Technical Data Book, Limits
Figure 2-19.1
Engineering Programs Power Operated Relief Valve Stroke Time Revision 53
Technical Data Book, Limits
Figure 2-19.1
Engineering Programs Diesel Generator Pot Settings Revisions 30 & 31
Technical Data Book,
Figure 2-19.9
Flow Diagram Containment Spray Unit 2 Revision 50
OP-2-5144
Clearance Order Isolate West Containment Spray Pump February 16, 2002
2012025
CR 01173001 The Vibration Alert Limits Are Higher Than June 21, 2001
the Action Limits for the #2 Boric Acid
Transfer Pump
CR 01255059 TDB Figure 2-15.1 Allows CCP Interaction September 12, 2001
Delta Pressure In Excess of Design Basis
Calculation
CR 01270017 Untimely Engineering Evaluation, Resultant September 27, 2001
Re-baseline Determination, and TDB
Change for Power Operated Relief Valve
(PORV) 1-MRV-213 Delayed the Unit 1
Ascension to Mode 4
CR 01292027 Non-conservative Acceptance Criteria in October 19, 2001
TDB Figure 2-15.1 for 2-PP-26N
54
CR 01324040 Non-conservative Acceptance Criteria in November 20, 2001
TDB Figure 2-15.1 for 2-PP-10E
CR 02046013 Containment Annulus Pipe Tunnel Sump February 15, 2002
Pump 2-PP-61A Did Not Meet Acceptance
Criteria at Step 5.1.5 of Surveillance
Procedure 2-EHP-4030-231-240 for GPM
CR 02046050 NRC Identified Unit 2 Pressurizer PORVs February 15, 2002
2-NRV-152 & 153 Were Retested Using
TDB Stroke Times and a Testing
Procedure That Had Not Been Revised to
Contain the Corrective Actions to Ensure
Operability In Accordance With Information
Contained in DIT-B-02327-00
CR 02050067 NRC Identified Minor Quantities of Debris February 19, 2002
in Lower Ice Condenser Following Unit 2
Refueling Outage
CR02051076 Resident Inspector Identified Dry Boric Acid February 20, 2002
on 2-IRV-120
CR 02051077 NRC Identified Dry Boric Acid at the Pipe February 20, 2002
Caps of Valves 2-CS-441-1 and
2-CS-441-2
CR 02051078 NRC Identified Dry Boric Acid on February 20, 2002
Transmitter 2-NFP-212
CR 02052001 NRC Identified Dry Boric Acid on Valve February 21, 2002
2-NPI-110-V1
CR 02052002 NRC Identified Dry Boric Acid on Valve February 21, 2002
2-IMO-54
CR 02052003 NRC Identified Dry Boric Acid on Valve February 21, 2002
2-CS-450-4
CR 02052008 NRC Identified Dry Boric Acid on February 21, 2002
Containment Spray Header Piping
CR 02052010 NRC Identified Containment Inspection February 21, 2002
Tour Deficiencies Following Unit 2
Refueling Outage
CR 02052039 NRC Identified That Abandoned Conduit February 21, 2002
Left in Containment Contrary to Design
Change Instructions
CR 02053063 NRC Identified Minor Equipment Storage February 22, 2002
Deficiencies in the Auxiliary Building
55
1R23 Temporary Plant Modifications
D. C. Cook Nuclear Plant Updated Final
Safety Analysis Report
Temporary Modification Installation of Noise Filtering Resistors on November 16, 2001
2-TM-00-54-R1 Cables 2-4450PB-2 for 2-ILA-111 and
2-5658PB-2 for 2-ILA-121
12-EHP-5040-MOD-001 Temporary Modifications Revision 9
JO 01320005 Install Temporary Modification November 17, 2001
2-TM-00-54-R1 on Cable 2-4450PB-2 for
2-ILA-111
10 CFR 50.59 Safety Original Revision of 2-TM-00-54-R0, September 19, 2000
Screening Installation of Noise Filtering Resistor on
2000-1940-00 Cable 2-5658PB-2 for 2-ILA-121
10 CFR 50.59 Revision to Temporary Modification November 16, 2001
Applicability 2-TM-00-54-R1 to Include Cable
Determination 2-4450PB-2 for 2-ILA-111
2001-1408-00
Memo from T. Craven Waiver of Design Review Board for November 16, 2001
to D. Hafer 2-TM-00-54-R1
CR 01355035 Replace the Currently Installed Foxboro December 21, 2001
Accumulator Level Alarm Transmitter With
an Equivalent Rosemont Transmitter
CR 02086013 Lost Implementation Checklist (Data March 27, 2002
Sheet 8 of Temporary Modification
Procedure 12-EHP-5040-MOD-001,
Revision 8) for Temporary Modification
2-TM-00-54, "Installation of Noise Filtering
Resistors on Cable 2-4450PB-2 for
2-ILA-111"
2OS1 Access Controls For Radiologically Significant Areas
PMP-6010-RPP-003 High, Locked High, and Very High Revision 10
Radiation Area Access
CR 02029056 Unit-2 Reactor Head Set High Radiation January 29, 2002
Area Posting
56
CR 02025007 Access to Restricted Areas Poorly January 25, 2002
Controlled During RCS [Reactor Coolant
System] Cleanup Post Shutdown
2OS2 ALARA [As Low As Reasonably Achievable] Planning and Controls
U2C13 RWP [Radiation Work Permit] Dose January 20, 2002
Totals Reports and Cook Plant Daily through
ALARA Reports February 7, 2002
Listing of Outage Generated CRs Coded to January 19, 2002
RP [Radiation Protection] Issues through
February 7, 2002
PMP-6010.ALA.001 ALARA Program - Review of Plant Work Revision 11
Activities
12-THP-6010.RPP.006 Radiation Work Permit Processing Revision 17
12-THP-6010-RPP-018 Controls for Radiological Risk Significant Revision 0
Work Activities
RWP # 022136 and Scaffold Activities in the Containment and RWP Revision 05
Associated ALARA Plan Auxiliary Buildings
RWP # 022170 and U2C13 DCP 525 - Modify/Replace RWP Revision 05
Associated ALARA Plan Pressurizer Spray Line Temperature
Sensor
RWP # 022119 and Temporary Shielding RWP Revision 02
Associated ALARA Plan
RWP # 022152 and CRDM [Control Rod Drive Mechanism] RWP Revision 00
Associated ALARA Plan Inspections
RWP # 022134 and Containment Insulation RWP Revision 02
Associated ALARA Plan
RWP # 022140 and Steam Generator & Diaphragm Activities RWP Revision 00
Associated ALARA Plan
RWP # 022141 and Steam Generator Primary Work - Platform RWP Revision 08
Associated ALARA Plan Activities
PMP-6010.ALA.001 ALARA In-Progress Review for Scaffold January 22, 24 and
Support Activities February 1, 2002
PMP-6010.ALA.001 ALARA In-Progress Review for Pressurizer February 5, 2002
Spray Line Temperature Sensor
Replacement
57
PMP-6010.ALA.001 ALARA In-Progress Review for Steam February 4, 2002
Generator Primary Activities
CR 02019069 Reactor Flood Up Specification - Shutdown January 19, 2002
Chemistry
CRs 02022024, Radworker [Radiation Worker] January 19, 2002
02029013, 02019072, Performance Related Issues through
02020020, 02020021, February 7, 2002
02022024, 02021064,
02021065, 02023006,
02023008, 02024011,
02023043, 02028039,
02029013, 02029016,
02033063, 02033066,
02034034, 02035008,
02038002
CR 02031019 Additional Dose During Scaffold Work January 31, 2002
CR 02025001 Scaffold Activities January 25, 2002
TEDE [Total Effective Relocate Temperature Sensor; Under Various dates
Dose Equivalent] Reactor Head Inspections; Insulation between
ALARA Evaluations For Removal; Steam Generator Manway November 28, 2001
RWP #s 02-2170; Activities; and Steam Generator Eddy and January 24,
02-2152; 02-2134; Current Activities 2002
02-2140; and 02-2141
Rad/Chem - Readiness of ALARA Outage Planning for August 2001
Environmental U2C13
Department
Self-Assessment
Report
SA-2001-RPS-009
Performance Field Observations # 01-L-043, 02 A-003, Various dates
Assurance Field 01-L-036, 01-K-061, 01-F-032, 01-K-040, between
Observations 02-A-072, 02-A-112, 02-A-081, 02-A-107, November 14, 2001
02-A-117, 02-B-005, 02-A-109, 02-A-130, and February 4,
02-A-026, 02-A-122, 02-A-124 2002
CR 02029016 and Individual Disregarded RP Technician January 29, 2002
related preliminary Directive and ED Dose Alarm While and related
investigation Working in U2 Lower Containment information through
information January 31, 2002
12-THP-6020-CHM-110 RCS Chemistry - Shutdown/Refueling Revision 8(c)
D.C. Cook Nuclear Power Plant 2001 Dose December 2001
Reduction Five Year Plan
58
4OA1 Performance Indicator Verification
02 OHP 4025.001.001 Emergency Remote Shutdown Revision 3
02 OHP 4022-055-003 Loss of Condensate to Auxiliary Feedwater Revision 6a
Pumps
02 OHP 4025.LS-2 Start-Up AFW [Auxiliary Feedwater] Revision 0
02 OHP 4025.LS-3 Steam Generator 2/3 Level Control Revision 1
JO 02018064 2-PP-4 TDAFWP [Turbine Driven Auxiliary February 19, 2002
Feedwater Pump] Tripped Shortly After
Startup
DIT-S-01037 Auxiliary Feedwater Pump Steam Turbine Revision 1
Drive Trip and Throttle Valve Latch Hook
Linkage Machining Information
Receipt Inspection Report May 27, 1986
Purchase Order/Contract 03157-821-5X
CR 01222001 While Performing Fill and Vent Procedure August 10, 2001
for the TDAFWP, the Pump Failed to Start
CR 01354104 Prompt Operability Determination for Both December 20, 2001
Units TDAFWPs. Trip Throttle Valve Latch
Faces Have Not Been Maintained as Per
Vendor Information
CR 02018064 TDAFWP Trip Throttle Valve Tripped January 18, 2002
Shortly after Start of the Pump During
Performance of Time Response Test
CR 02019071 Performance Assurance Identified That January 19, 2002
Operability Determination for CR 02018064
and CR 01354104 for the TDAFWP Were
Inadequate
4OA3 Event Followup
D.C. Cook Nuclear Plant Unit 1Technical
Specifications
D.C. Cook Nuclear Plant Unit 2 Technical
Specifications
59
Licensee Event Report Failure to Perform Increased Frequency
(LER) Surveillance on 2 East Containment Spray
50-316-2000-012-00 Pump
LER Failure to Perform Increased Frequency
50-316-2000-012-01 Surveillance on 2 East Containment Spray
Pump, Supplement 1
LER Power Range Nuclear Instrumentation
50-315-2001-002-00 Calibration Procedure Not in Conformance
with Technical Specifications
60