ML040680070
| ML040680070 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 03/05/2004 |
| From: | Grobe J NRC/RGN-III |
| To: | Myers L FirstEnergy Nuclear Operating Co |
| References | |
| EA-04-049, EA-04-050, FOIA/PA-2004-0277 IR-03-010 | |
| Download: ML040680070 (172) | |
See also: IR 05000346/2003010
Text
March 5, 2004
EA-04-050
Mr. Lew W. Myers
Chief Operating Officer
FirstEnergy Nuclear Operating Company
Davis-Besse Nuclear Power Station
5501 North State Route 2
Oak Harbor, OH 43449-9760
SUBJECT:
DAVIS-BESSE NUCLEAR POWER STATION
NRC SPECIAL TEAM INSPECTION - CORRECTIVE ACTION PROGRAM
IMPLEMENTATION - REPORT 05000346/2003010(DRS) AND NOTICE of
VIOLATION
Dear Mr. Myers:
On January 7, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed a special
corrective action team inspection (CATI) at your Davis-Besse Nuclear Power Station to assess
the effectiveness of the implementation of your corrective action program. This inspection
represented a significant input into the NRCs Davis-Besse Oversight Panels (Panel) review of
Restart Checklist Item 3.a, "Corrective Action Program and also contributed to the Panels
review of Restart Checklist Items No. 2.c, "Structures, Systems, and Components Inside
Containment," and 5.b, "Systems Readiness for Restart." The enclosed inspection report
documents the CATI findings which were discussed with you and other members of your staff on
September 9 and November 10, 2003, and on January 7, 2004.
The CATI was accomplished by eleven NRC inspectors and contractors over a period of ten
months involving five weeks of onsite effort and multiple additional weeks of in-office review.
The CATI evaluated the effectiveness of the implementation of various aspects of your
corrective action program (CAP), including: (1) identifying and documenting plant design-related
deficiencies; (2) categorizing and prioritizing safety issues for resolution; (3) conducting
apparent and root cause analyses; (4) determining extent of condition and (5) implementing
appropriate and timely corrective actions to ensure adequate resolution of problems. Overall,
the CATI team reviewed the resolution of several hundred conditions adverse to quality. Many
of the deficiencies reviewed by the CATI involved safety system design engineering issues.
In addition, the CATI reviewed management involvement in and oversight of the implementation
of the corrective action program, including the routine performance indicators utilized to monitor
the program implementation, and the effectiveness of conditions adverse to quality trending
analyses and quality assessment audits of the CAP implementation. Finally, due to the nature
of multiple NRC inspection findings, the team focused additional effort on assessing the
adequacy of engineering work products, including analyses and calculations.
Notwithstanding a significant number of performance deficiencies identified during the
inspection, based on input from the CATI team, the Panel concluded that the corrective action
program was sufficiently acceptable for plant restart. The significance of each performance
L. Myers
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deficiency identified during the inspection was evaluated in accordance with the NRCs
Significance Determination Process and concluded to be of very low safety significance. While
the individual risk significance of each performance deficiency was low, two themes emerged
from a collective evaluation of the number and nature of the CATI findings:
A weakness in identifying and evaluating the nature and extent of issues when
performing apparent cause evaluations to identify the cause(s) and full scope of
necessary corrective actions, particularly in the area of safety system design
deficiencies; and
A weakness in the quality of engineering work products, including design calculations
and analyses, to correct conditions adverse to quality.
In addition, the CATI noted that during early part of the extended shutdown of the Davis-Besse
facility, you suspended the conditions adverse to quality trending program intended to provide
early identification of broader plant equipment and organizational concerns. Your resumption of
the trending program was not timely. Further, your corrective action program required the
review of the effectiveness of corrective action taken to address significant conditions adverse
to quality six months after implementation of those actions. Sufficient actions had not been
completed for six months for the CATI to evaluate this area.
Following the conclusion of the onsite phase of the inspection in September 2003, your staff
implemented actions to further assess the specific areas identified by the CATI and develop
improvement initiatives to address those areas. Those activities were presented publicly to the
NRC on November 12, 2003 and discussed further during a public meeting on December 10,
2003. Continuing actions to further address the areas of corrective action program
effectiveness and engineering product quality are documented in your Operational
Improvement Plan, Operating Cycle 14, Revision 3, submitted on February 19, 2003.
The CATI team has reviewed these ongoing and planned actions and concluded that, if
properly implemented, they should address the concerns identified during this inspection and
further improve the corrective action program effectiveness at Davis-Besse. However, the
effectiveness of the actions could not be evaluated by the NRC at this time due to the relatively
short implementation time of many of those corrective actions.
The team noted that, in general, the Nuclear Quality Assurance (NQA) assessments of
corrective action program effectiveness identified problems pertaining to corrective action
program implementation that were similar to the issues identified by the CATI. However,
resolution of NQAs findings was not sufficiently prompt or effective to address the identified
problems and to prevent the underlying deficiencies that led to these NRC findings. Continuing
diligence by Davis-Besse management will be necessary to assure lasting effective corrective
action program implementation. The NRC will continue to closely monitor Davis-Besses
performance to assess the effectiveness of the Davis-Besse corrective actions.
In addition to documenting the results of the CATI, this inspection report documents the closure
of Davis-Besse Restart Checklist Items 2.c, "Structures, Systems, and Components Inside
L. Myers
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Containment," and 3.a, "Corrective Action Program." Restart checklist item 5.b, Systems
Readiness for Restart, is not closed in this inspection report.
Based on the results of this inspection, the NRC identified two violations which are cited in the
enclosed Notice of Violation (Notice) and the circumstances surrounding them are described in
detail in the subject inspection report. The violations are being cited because your staff failed to
restore compliance after the violations were identified.
Additionally, the NRC identified twenty-six NRC-identified violations of very low safety
significance (Green) and one NRC-identified Severity Level IV violation. These violations are
being treated as Non-Cited Violations (NCVs) consistent with Section VI.A of the Enforcement
Policy. These NCVs are described in the subject inspection report. The violations were
evaluated 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 web site at www.nrc.gov; select What we do, Enforcement, then
You are required to respond to this letter and should follow the instructions specified in the
enclosed Notice when preparing your response. The NRC will use your response, in part, to
determine whether further enforcement action is necessary to ensure compliance with
regulatory requirements.
If you contest the severity level or significance of the NCVs described in the report, you should
also provide a response within 30 days of the date of this inspection report, with the basis for
your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, DC 20555-0001, with copies to the Regional Administrator, Region III, 801
Warrenville Road, Suite 255, Lisle, IL 60532-4351; the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission, Washington, DC 20555-001.
In accordance with 10 CFR 2.390 of the NRC's "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 NRC's
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
L. Myers
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To the extent possible, your response should not include any personal privacy, proprietary, or
safeguards information so that it can be made available to the Public without redaction.
Sincerely,
/RA/
John A. Grobe, Chairman
Davis-Besse Oversight Panel
Docket No. 50-346
License No. NPF-3
Enclosures:
2. Inspection Report No. 05000346/2003010(DRS)
cc w/encl:
The Honorable Dennis Kucinich
G. Leidich, President - FENOC
Plant Manager
Manager - Regulatory Affairs
M. OReilly, Attorney, FirstEnergy
Ohio State Liaison Officer
R. Owen, Administrator, Ohio Department of Health
Public Utilities Commission of Ohio
President, Board of County Commissioners
Of Lucas County
Steve Arndt, President, Ottawa County Board of Commissioners
D. Lochbaum, Union Of Concerned Scientists
J. Riccio, Greenpeace
P. Gunter, N.I.R.S.
L. Myers
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To the extent possible, your response should not include any personal privacy, proprietary, or
safeguards information so that it can be made available to the Public without redaction.
Sincerely,
/RA/
John A. Grobe, Chairman
Davis-Besse Oversight Panel
Docket No. 50-346
License No. NPF-3
Enclosures:
2. Inspection Report No. 05000346/2003010(DRS)
cc w/encl:
The Honorable Dennis Kucinich
G. Leidich, President - FENOC
Plant Manager
Manager - Regulatory Affairs
M. OReilly, Attorney, FirstEnergy
Ohio State Liaison Officer
R. Owen, Administrator, Ohio Department of Health
Public Utilities Commission of Ohio
President, Board of County Commissioners
Of Lucas County
Steve Arndt, President, Ottawa County Board of Commissioners
D. Lochbaum, Union Of Concerned Scientists
J. Riccio, Greenpeace
P. Gunter, N.I.R.S.
DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML040680070.WPD
To receive a copy of this document, indicate in the box: "C" = Copy without enclosure "E"= Copy with enclosure "N"= No copy
OFFICE
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DATE
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OFFICE
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NAME
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DATE
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03/05/04
OFFICIAL RECORD COPY
L. Myers
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ADAMS Distribution:
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First Energy Nuclear Operating Company
Docket No. 50-346
Davis-Besse Nuclear Power Station
License No. NPF-3
EA-04-050
During an NRC inspection conducted from March 17, 2003 through January 7, 2004, violations
of NRC requirements was identified. In accordance with the "General Statement of Policy and
Procedure for NRC Enforcement Actions," NUREG-1600, the violations are listed below:
(a)
Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that measures be
established to assure that applicable regulatory requirements and the design basis are
correctly translated into specifications, drawings, procedures, and instructions. It also
requires that measures be provided for verifying or checking the adequacy of design,
such as by the performance of design reviews, by the use of alternate or simplified
calculational methods, or by the performance of a suitable testing program.
Contrary to the above, as of August 12, 2003, the licensee failed to verify that the
design of the service water system discharge path swapover setpoints was adequate.
Specifically, the analysis performed by the licensee showed that the established
setpoints were not adequate and the evaluation of the analysis accepted the inadequate
setpoint based on non-safety-related equipment performing a safety-related function
under design basis conditions. Neither the analysis nor the evaluation corrected the
nonconforming condition previously identified in Inspection Report 05000346/2002014.
This is a violation of very low safety significance (Green).
(b)
Technical Specification Section 4.05a requires, in part, that the licensee perform
inservice testing of valves in accordance with the ASME OM Code and applicable
addenda as required by 10 CFR 50.55a.
10 CFR 50.55a(f)(4) requires that pumps and valves which are classified as ASME
Code Class 1, 2, and 3 meet the inservice test requirements set forth in the appropriate
edition and addenda of the ASME OM Code. It further requires that, during 120-month
intervals successive to the initial 120-month interval, tests must comply with the
requirements in the latest Code edition and addenda incorporated by reference in
paragraph (b) of 10 CFR 50.55a 12 months prior to the start of the 120-month interval.
Paragraph 50.55a(f)(5)(i) requires that the inservice test program be revised as
necessary to meet the requirement of paragraph 50.55a(f)(4).
The ASME OM Code, 1995 edition through the 1996 addenda, Section ISTC 4.5.1
requires, in part, that check valves be exercised nominally every three months. Section
ISTC 4.5.4(a) requires, in part, that check valves be exercised by initiating flow and
observing that the obturator traveled to its full open position. Observations shall be
made by observing a direct indicator (e.g., a position-indicating device) or by other
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positive means (e.g., changes in system pressure, flow rate, level, temperature, seat
leakage, testing, or non-intrusive testing results).
Contrary to the above, the NRC identified that on September 12, 2003, and other dates,
the licensee did not observe by a direct indicator or other positive means that the ASME
Class 3 service water pump discharge check valve obturator traveled to its full open
position during its quarterly surveillance test. Specifically, on September 12, 2003, the
licensee observed a flow rate of 9718 gpm through valve SW-19, which was less than
the test acceptance criterion of 10,000 gpm, and less than the approximately 10,300
gpm used in the licensees most recent accident analysis. Observing flow rates less
than required for the valve to perform its safety function was not a positive means to
determine that the obturator traveled to its full open position and no other direct indicator
or positive means was used. The NRC approved use of the 1995 Code edition through
the 1996 addenda for the third inservice testing 120-month interval on March 28, 2003 .
Prior to that date, the licensee was committed to the 1986 Edition (no Addenda) of the
ASME Boiler and Pressure Vessel Code,Section XI. The 1986 Code Edition contains
similar requirements.
This is a violation of very low safety significance (Green).
Pursuant to the provisions of 10 CFR 2.201, FirstEnergy Nuclear Operating Company is hereby
required to submit a written statement or explanation to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555 with a copy to the
Regional Administrator, Region III, and a copy to the NRC Resident Inspector at the
Davis-Besse Nuclear Power Plant, within 30 days of the date of the letter transmitting this
Notice of Violation (Notice). This reply should be clearly marked as a "Reply to a Notice of
Violation; EA-04-049 and EA-04-050," and should include for each violation: (1) the reason for
the violation, or, if contested, the basis for disputing the violation or severity level; (2) the
corrective steps that have been taken and the results achieved; (3) the corrective steps that will
be taken to avoid further violations; and (4) the date when full compliance will be achieved.
Your response may reference or include previous docketed correspondence, if the
correspondence adequately addresses the required response. If an adequate reply is not
received within the time specified in this Notice, an order or a Demand for Information may be
issued as to why the license should not be modified, suspended, or revoked, or why such other
action as may be proper should not be taken. Where good cause is shown, consideration will
be given to extending the response time.
If you contest this enforcement action, you should also provide a copy of your response, with
the basis for your denial, to the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001.
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from the NRCs document system (ADAMS), accessible from the
NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should
not include any personal privacy, proprietary, or safeguards information so that it can be made
available to the public without redaction. If personal privacy or proprietary information is
necessary to provide an acceptable response, then please provide a bracketed copy of your
-3-
response that identifies the information that should be protected and a redacted copy of your
response that deletes such information. If you request withholding of such material, you must
specifically identify the portions of your response that you seek to have withheld and provide in
detail the basis for your claim of withholding (e.g., explain why the disclosure of information will
create an unwarranted invasion of personal privacy or provide the information required by
10 CFR 2.390(b) to support a request for withholding confidential commercial or financial
information). If safeguards information is necessary to provide an acceptable response, please
provide the level of protection described in 10 CFR 73.21.
Dated this 5th day of March, 2004
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No:
50-346
License No:
Report No:
Licensee:
FirstEnergy Nuclear Operating Company
Facility:
Davis-Besse Nuclear Power Station
Location:
5501 North State Route 2
Oak Harbor, OH 43449
Dates:
March 17, 2003 through January 07, 2004
Inspection Team:
Z. Falevits, Lead Senior Reactor Engineering Inspector
M. Farber, Senior Reactor Engineering Inspector
P. Lougheed, Senior Reactor Engineering Inspector
A. Walker, Senior Reactor Engineering Inspector
D. Chyu, Reactor Engineering Inspector
R. Daley, Reactor Engineering Inspector
F. Baxter, Electrical Consultant
W. Bennett, Corrective Action Consultant
Dr. O. Mazzoni, Electrical Consultant
J. Panchison, Mechanical Consultant
W. Sherbin, Mechanical Consultant
Approved by:
Julio F. Lara, Chief
Electrical Engineering Branch
Division of Reactor Safety
Enclosure
TABLE of CONTENTS
Section
Page
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Inspector-Identified and Self-Revealed Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
4.
OTHER ACTIVITIES (OA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
(1)
Corrective Action Program Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
.1
Adequacy of Licensees Efforts to Identify and Document
Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
.2
Adequacy of Licensees Efforts to Categorize and Prioritize
Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
.3
Adequacy of Licensees Efforts to Evaluate Identified Conditions . . . . . 17
.4
Adequacy of Licensees Efforts to Correct Identified Problems
. . . . . . 19
.5
Review of Engineering Products and Corrective Actions . . . . . . . . . . . 20
.6
Adequacy of Licensees Efforts to Resolve Procedure Adherence
and Quality Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
(2)
Review of the Licensees Internal Assessment Activities . . . . . . . . . . . . . . . . . 21
.1
Trending, Self-Assessment, and Evaluation Program
Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
.2
Corrective Action Program Performance Indicators . . . . . . . . . . . . . . . 23
.3
Nuclear Quality Assessment Audits and Self Assessments of
Corrective Action Program Implementation . . . . . . . . . . . . . . . . . . . . . 24
(3)
Management CAP Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
4OA3 Event Response Follow-up - Special Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
(1)
Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Davis-Besse CAP Compliance Review . . . . . . . . . . . . . . . . . . . . . . . . . 27
Assessment of the Corrective Action Program Compliance Review . . . 27
(2)
Detailed Team Review of Licensee Corrective Actions Implemented to
Address Electrical Issues Previously Identified by NRC or the Licensee . . . . . 28
.1
Undervoltage Time Delay Relay Setting Did Not Account For
Instrument Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
.2
Lack of 480 Vac Class 1E Motor Thermal Overload Protection . . . . . . 30
.3
Failure to Perform Direct Current Contactor Testing to Ensure
Minimum Voltage at Motor Operated Valves
. . . . . . . . . . . . . . . . . . . . 31
Enclosure
ii
.4
Failure to Verify Adequacy of Short Circuit Protection for Direct
Current Circuits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
.5
Lack of Calculations to Ensure Minimum Voltage Availability at
Device Terminals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
.6
Raychem' Splice Removal on Containment Air Cooler Motor
Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
.7
Review of Calculation on the Electric Transient Analysis Profile . . . . . . 37
.8
Inadequate Grid Voltage Calculations . . . . . . . . . . . . . . . . . . . . . . . . . 38
(3)
Detailed Team Review of Licensee Corrective Actions Implemented to
Address Mechanical Issues Previously Identified by NRC or the Licensee
. . . 38
.1
High Pressure Injection Pump Operation Under Long Term
Minimum Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
.2
Increased Dose Consequences Due to Degraded Thermal
Performance Operation of Degraded Containment Air Coolers . . . . . . 42
.3
Containment Air Cooler Air Flow Calculation Concerns . . . . . . . . . . . . 43
.4
Accumulator Sizing Calculation Errors . . . . . . . . . . . . . . . . . . . . . . . . . 45
.5
Inadequate Blowdown Provisions for Containment Isolation Valve
Accumulators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
.6
Non-conservative Calculation Used in Design Analysis to
Determine Required Service Water Makeup Flow to Component
Cooling Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
.7
Calculation Concerns for Service Water Pump Room Ventilation
System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
.8
Inadequate Service Water System Flow Analysis . . . . . . . . . . . . . . . . . 52
.9
Inadequate Flooding Protection for the Service Water System
. . . . . . 53
.10
Inadequate Service Water System Flow Balance Testing
Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
.11
Service Water Discharge Path Swapover Setpoint . . . . . . . . . . . . . . . . 56
.12
Service Water Discharge Check Valve Test Acceptance Criteria . . . . . 59
.13
Lack of Design Basis Calculations to Support Service Water
Single Failure Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
.14
Auxiliary Feedwater System Calculation Issues With Main Steam
Safety Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
.15
Auxiliary Feedwater Strainer Mesh Size and Preconditioning of
Auxiliary Feedwater System During Testing . . . . . . . . . . . . . . . . . . . . . 64
.16
Inadequate Evaluation of System Health Condition Report on Auxiliary
Feedwater Design Bases Calculations . . . . . . . . . . . . . . . . . . . . . . . . . 67
.17
Containment Post-LOCA Trisodium Phosphate . . . . . . . . . . . . . . . . . . 68
.18
Borated Water Storage Tank Calculation Issues . . . . . . . . . . . . . . . . . 70
.19
Inadequate Evaluation of Reactor Coolant Pump Casing-to-cover
Stud Overstressing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
.20
Reactor Coolant Pump Inner Gasket Leakage . . . . . . . . . . . . . . . . . . . 74
.21
Environmental Qualification of Equipment Not Supported by Analysis
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
.22
Inadequate Justification for Downgrade of Significant Condition
Adverse to Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
.23
Inappropriate Application of 10 CFR 50.59 . . . . . . . . . . . . . . . . . . . . . . 78
Enclosure
iii
.24
Failure to Perform Comprehensive Moderate Energy Line Break
Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
(4)
Detailed Team Review of Licensee Corrective Actions Implemented to
Address Operational Issues Previously Identified by the Licensee . . . . . . . . . . 82
Repetitive Spacer Grid Strap Damage . . . . . . . . . . . . . . . . . . . . . . . . . 82
(5)
Review of Fire Protection Corrective Action Items . . . . . . . . . . . . . . . . . . . . . . 86
.1
Process Monitoring Function for Alternative Shutdown Capability . . . . 86
.2
Supporting Functions for Alternative Shutdown Capability . . . . . . . . . . 87
.3
Emergency Diesel Generator Floor Drains Design Deficiency . . . . . . . 88
(6)
Review of Licensee Event Reports
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
.1
(Discussed) LER 05000346/2002-008-00 and -01: Containment
Air Coolers Collective Significance of Degraded Conditions . . . . . . . . . 90
.2
(Closed) LER 05000346/2002-009-00: Degradation of the High
Pressure Injection Thermal Sleeves . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
.3
(Closed) LER 05000346/2003-003-00 and -01: Potential
Inadequate High Pressure Injection Pump Minimum Recirculation
Flow Following a Small Break Loss of Coolant Accident
. . . . . . . . . . . 92
4OA4 Cross-Cutting Aspects of Findings
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
(1)
Assessment of the Licensees Corrective Actions to Address Previously Identified
Findings Documented in NRC Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
.1
Follow up on Findings Documented in Report 05000346/2002012 . . . . . . . . . 95
.1
(Closed) URI 05000346/2002012-02: Potential Impact of
Corrosion on the Ground Function of Electrical Conduit in
Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
.2
(Closed) URI 05000346/2002012-03: Potential Failure to Follow
the Procedure for Raychem' Splice Removal on Electrical
Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96
.2
Follow-up on SSDI Findings Documented in Report 05000346/2002014 . . . . . 96
.1
(Discussed) NCV 05000346/2002014-01a: Lack of a Design
Basis Analysis for Containment Isolation Valve Backup Air
Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96
.2
(Discussed) NCV 05000346/2002014-01b: Inadequate Blowdown
Provisions for Containment Air Cooler Backup Air Accumulators . . . . . 96
.3
(Closed) URI 05000346/2002014-01c: Failure to Perform
Comprehensive Moderate Energy Line Break Analysis . . . . . . . . . . . . 97
.4
(Closed) URI 05000346/2002014-01d: Lifting of Service Water
Relief Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
.5
(Closed) URI 05000346/2002014-01e: Inadequate Service Water
Pump Room Temperature Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
Enclosure
iv
.6
(Closed) URI 05000346/2002014-01f: Inadequate Service Water
Pump Room Steam Line Break Analysis . . . . . . . . . . . . . . . . . . . . . . . 97
.7
(Closed) URI 05000346/2002014-01g: Inadequate Cable
Ampacity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
.8
(Closed) URI 05000346/2002014-01h: Inadequate Flooding
Protection for Service Water Pump House . . . . . . . . . . . . . . . . . . . . . . 98
.9
(Discussed) NCV 05000346/2002014-01i: Non-conservative
Technical Specification Value for 90 Percent Undervoltage Relays . . . 98
.10
(Closed) URI 05000346/2002014-01j: Poor Quality Calculation for
90 Percent Undervoltage Relays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
.11
(Discussed) NCV 05000346/2002014-01k: Non-conservative
Relay Setpoint Calculation for the 59 Percent Undervoltage
Relays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
.12
(Closed) URI 05000346/2002014-01l: Inadequate Calculations for
Control Room Operator Dose (GDC-19) and Offsite Dose (10
CFR Part 100) Related to High Pressure Injection Pump Minimum
Flow Values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99
.13
(Closed) URI 05000346/2002014-01m: Other GDC-19 and 10
CFR Part 100 Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99
.14
(Closed) URI 05000346/2002014-01n: High Pressure Injection
Pump Operation Under Long Term Minimum Flow . . . . . . . . . . . . . . . . 99
.15
(Closed) URI 05000346/2002014-01o: Some Small Break Loss of
Coolant Accident Sizes Not Analyzed . . . . . . . . . . . . . . . . . . . . . . . . . . 99
.16
(Closed) URI 05000346/2002014-01p: Inadequate Service Water
System Flow Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
.17
(Closed) URI 05000346/2002014-01q: Inadequate Service Water
System Thermal Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
.18
(Closed) URI 05000346/2002014-01r: Inadequate Ultimate Heat
Sink Inventory Analysis
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
.19
(Closed) URI 05000346/2002014-01s: No Valid Service Water
Pump Net Positive Suction Head Analysis . . . . . . . . . . . . . . . . . . . . . 100
.20
(Closed) URI 05000346/2002014-01t: Service Water Source
Temperature Analysis for Auxiliary Feedwater . . . . . . . . . . . . . . . . . . 100
.21
(Closed) URI 05000346/2002014-01u: Inadequate Short Circuit
Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
.22
(Discussed) NCV 05000346/2002014-01v: No Analytical Basis for
Setpoint to Swap Service Water System Discharge Path . . . . . . . . . . 101
.23
(Discussed) NCV 05000346/2002014-02a: Service Water
Surveillance Test Did Not Use Worst Case Values
. . . . . . . . . . . . . . 101
.24
(Closed) URI 05000346/2002014-02b: Inadequate Service Water
Flow Balance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
.25
(Closed) URI 05000346/2002014-03a: Inappropriate Service
Water Pump Curve Allowable Degradation
. . . . . . . . . . . . . . . . . . . . 101
.26
(Closed) URI 05000346/2002014-03b: Repetitive Failures of
Service Water Relief Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
.27
(Closed) URI 05000346/2002014-03c: Non-conservative
Difference in Ultimate Heat Sink Temperature Measurements . . . . . . 102
Enclosure
v
.28
(Discussed) NCV 05000346/2002014-03d: Inadequate Corrective
Actions Related to Service Water Pump Discharge Check Valve
Acceptance Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
.29
(Closed) URI 05000346/2002014-03e: Non-conservative
Containment Air Cooler Mechanical Stress Analysis . . . . . . . . . . . . . 103
.30
(Discussed) NCV 05000346/2002014-04: Failure to Perform
Technical Specification Surveillance for High Pressure Injection
Pump Following Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
.31
(Closed) URI 05000346/2002014-05: Question Regarding
Definition of a Passive Failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104
.3
Follow-up on SSDI Findings Documented in Report 05000346/2002019 . . . . 104
(Closed) URI 05000346/2002019-031: Final Evaluation of
Apparent Cause Evaluation for LER 05000346/2002-006-00 . . . . . . . 104
.4
Follow up on Augmented Inspection Team Findings Documented in the
Cover Letter of Report 05000346/2003016 . . . . . . . . . . . . . . . . . . . . . . . . . . 104
.1
(Discussed) AV 05000346/2003016-01: Technical Specification
Reactor Coolant System Pressure Boundary Leakage . . . . . . . . . . . . 104
.2
(Discussed) AV 05000346/2003016-02: Reactor Vessel Head
Boric Acid Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105
.3
(Discussed) AV 05000346/2003016-03: Containment Air Cooler
Boric Acid Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107
.4
(Discussed) AV 05000346/2003016-04: Radiation Filter Element
Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107
.5
(Discussed) AV 05000346/2003016-05: Service Structure
Modification Delay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107
.6
(Discussed) AV 05000346/2003016-06: Reactor Coolant System
Unidentified Leakage Trend . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
.7
(Discussed) AV 05000346/2003016-07: Inadequate Boric Acid
Corrosion Control Program Procedure . . . . . . . . . . . . . . . . . . . . . . . . 110
.8
(Discussed) AV 05000346/2003016-08: Failure to Follow Boric
Acid Corrosion Control Program Procedure . . . . . . . . . . . . . . . . . . . . 110
.9
(Discussed) AV 05000346/2003016-09: Failure to Follow
Corrective Action Program Procedure . . . . . . . . . . . . . . . . . . . . . . . . 112
(2)
Closure of Restart Checklist Items
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
.1
Restart Checklist Item 2.c: Structures, Systems, and
Components Inside Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
.2
Restart Checklist Item 3.a: Corrective Action Program . . . . . . . . . . . 113
.3
Restart Checklist Item 5.b: Systems Readiness for Restart
. . . . . . . 113
4OA6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114
Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A1
Enclosure
vi
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
. . . . . . . . . . . . . . . . . . . . . A2
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A7
LIST OF ACRONYMS USED
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A39
Enclosure
SUMMARY OF FINDINGS
IR 05000346/2003010(DRS); 03/17/2003 - 01/07/2004; Davis-Besse Nuclear Power Station;
Corrective Action Program Implementation Effectiveness
The inspection consisted of five weeks of on-site activities over a six month period. The
specific on-site weeks were the weeks of: March 17, March 31, May 18, August 11, and
August 25, 2003. This report documents a special corrective action program implementation
team inspection. The inspection was conducted to assess the adequacy of the licensees
implementation of the facilitys corrective action program. The inspection was conducted by
regional engineering inspectors and supplemented by consultants. Two Green findings
associated with two cited violations, one Severity Level IV Non-Cited Violation (NCV), and
twenty-six (26) Green findings associated with 26 NCVs were identified.
The significance of most findings is indicated by their color (Green, White, Yellow, Red) using
NRC Inspection Manual Chapter 0609, "Significance Determination Process." Findings for
which the significance determination process does not apply may be Green or be assigned a
severity level after NRC management review. The NRCs program for overseeing the safe
operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor
Oversight Process," Revision 3, July 2000.
A.
Inspector-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix R,
Section III.L.2.d, having very low safety significance. Specifically, the licensee failed to
provide the process monitoring function, capable of providing direct readings of the
process variables necessary to perform and control the alternative shutdown, for a
control room or cable spreading room fire. Following discovery, the licensee entered the
issue into the corrective action program and performed a modification to resolve the
issue. The primary cause of this violation was related to the cross-cutting area of
problem identification and resolution because the licensee had previously identified this
issue as an enhancement and did not recognize that it was a violation of regulatory
requirements.
This issue was more than minor because it affected the initiating events cornerstone
and, by not providing the direct indications necessary for the operators to determine the
status of the idle SG, the probability of experiencing unacceptable stresses on the SG
tubes during the limiting Appendix R scenario was increased. The team determined this
finding to be of very low significance, based upon the low probability of a serious control
room fire combined with the low probability that such a fire would affect this specific
instrumentation detrimentally. Additionally, even in the event that such a fire had
affected this instrumentation, it was likely that the operators still would have been able to
prevent these tube stresses through use of manual actions, although this was not a
credited action in the Fire Protection procedures for this scenario. (Section 4OA3(5)b.1)
Enclosure
2
Cornerstone: Mitigating Systems
Green. The team identified a Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control. Specifically, the licensee failed to provide a basis for the
setpoint to swap the service water system discharge path. This issue was previously
identified as a Non-Cited Violation in Inspection Report 05000346/2002014 and the
corrective actions taken by the licensee failed to correct the originally identified
condition. The primary cause of this violation was related to the cross-cutting areas of
problem identification and resolution and human performance, because the licensee did
not recognize that the corrective actions taken needed to restore compliance with the
identified violation of NRC requirements.
The issue was determined to be more than minor because the licensee had not
corrected a previous violation and was relying on non-safety-related equipment to
perform a safety function under design bases conditions. Because the issue was
previously determined to be of very low safety significance, NRC management
concluded that the violation could be categorized as having very low safety significance.
(Section 4OA3(3)b.11)
Green. The team identified a Cited Violation of Technical Specifications Section 4.05a
and 10 CFR 50.55a. Specifically, the licensee failed to ensure that the service water
discharge check valve was tested in accordance with the American Society of
Mechanical Engineers Code. The primary cause of this violation was related to the
cross-cutting areas of problem identification and resolution and human performance,
because the licensee did not recognize that the corrective actions taken needed to
ensure compliance with NRC requirements.
The issue was determined to be more than minor because the inadequate test
acceptance criteria allowed the licensee to accept a check valve as performing its
intended function at less than full system flow. The issue was of very low safety
significance using the Phase 1 of the significance determination process based on the
licensees determination that the system was operable but degraded.
(Section 4OA3(3)b.12)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to translate instrument uncertainties into the undervoltage time delay
setting specification for the 4160 Vac buses C1 and D1. Following discovery, the
licensee confirmed the settings were acceptable and re-evaluated the potential
temperature effects to the time delay relays.
This issue was more than minor because the licensee had to perform calculations to
show that the relays were within their allowable values, and because the licensee
determined that the increased temperature could cause the time delay to operate
outside of Technical Specifications limits. The issue was of very low safety significance
using the Phase 1 of the significance determination process since the licensee
considered the instruments to be operable. (Section 4OA3(2)b.1)
Enclosure
3
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to provide motor thermal overload protection for the Class 1E 480
alternating current voltage (Vac) distribution system. Following discovery, the licensee
physically modified approximately 53 thermal overload circuits to resolve the
discrepancy. The primary cause of this violation was related to the cross-cutting area of
human performance because the licensee did not realize the lack of thermal overload
protection was an unanalyzed condition and that the station was not in compliance with
the updated safety analysis report until identified by the team.
This issue was more than minor because the licensee failed to ensure that bypassing
the thermal overload protection would result in completion of safety functions and
subsequently had to install thermal overload protection in order to meet the design
requirement. The issue was determined to be of very low safety significance using
Phase 1 of the significance determination process because there was reasonable
assurance that the condition did not result in a loss of system function. (Section
4OA3(2)b.2)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XI, Test Control, having very low safety significance. Specifically, the
licensee failed to adequately test direct current contactors related to two safety related
motor operated steam valves associated with the auxiliary feedwater system. Following
discovery, the licensee entered the issue into the corrective action program and was
re-evaluating the basis for acceptability of these valves. The primary cause of this
violation was related to the cross-cutting area of problem identification and resolution
because, although the issue was identified in 2002, the licensee did not see the need to
take corrective action until prompted by the team in 2003.
This issue was more than minor because the licensee had relied upon an inadequate
test to show that the contactors were qualified to perform under required conditions and
because the contactors were installed in the plant during previous operating cycles. The
issue was of very low safety significance using the Phase 1 of the significance
determination process because the licensee determined that the valves were operable.
(Section 4OA3(2)b.3)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, having very low safety significance. Specifically, the
licensee failed to identify and correct inadequate short circuit protection for direct current
(DC) circuits. Following discovery, the licensee issued a condition report to document
the deficient circuit protection for valves with extremely long circuit lengths. The primary
cause of this violation was related to the cross-cutting area of problem identification and
resolution because the licensee had missed several opportunities to identify it as part of
corrective actions for previously identified DC circuit deficiencies.
This issue was more than minor because the licensee had to perform calculations to
show that the fuses would adequately protect the equipment and because modifications
to those fuses were required. The issue was of very low safety significance using
Phase 1 of the significance determination process because the licensee concluded the
equipment was operable. (Section 4OA3(2)b.4)
Enclosure
4
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to confirm operability of direct current (DC) contactors by ensuring that
minimum voltage was available at the safety related device terminals. The licensee
missed several opportunities to correct this design deficiency. Following discovery, the
licensee issued a condition report to evaluate the adequacy of available voltage. The
primary cause of this violation was related to the cross-cutting area of problem
identification and resolution because, although the issue was identified in 2002, the
licensee did not see the need to take corrective action until prompted by the team in
2003.
This issue was more than minor because the licensee had to perform calculations to
determine if the devices had sufficient voltage to perform their safety function. The
issue was of very low safety significance using Phase 1 of the significance
determination process because the licensee determined that all components were
operable. (Section 4OA3(2)b.5)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to verify that the high pressure injection pumps could operate under
design basis minimum flow requirements since initial plant startup. The primary cause
of this violation was related to the cross-cutting area of problem identification and
resolution because the licensee missed several opportunities to identify and correct the
deficiency.
This issue was more than minor because the licensee had to perform a test to
demonstrate that design basis requirements could be met and because the test results
determined that the design basis requirements needed to be changed to ensure that the
HPI pumps could perform their accident required function. The issue was of very low
safety significance because surveillance test results indicated the lowest flow rate for
either pump was slightly outside the licensee's new operability band, and therefore, it
was deemed likely that the pumps would have performed had they been called upon.
The issue screened out of Phase 1 of the significance determination process.
(Section 4OA3(3)b.1)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to consider worst case minimum pressure differential between service
water and component cooling water systems when determining required service water
makeup flow to the component cooling water system heat exchangers. Following
discovery, the licensee entered the issue into the corrective action program and
performed the necessary calculations. The primary cause of this violation was related to
the cross-cutting area of human performance because the licensee used test data
collected during normal operation rather than taking the worst case design conditions
and because there was a lack of rigor in the calculation review process.
This issue was more than minor because the licensee needed to perform a new
calculation to demonstrate that the service water flow to the component cooling water
Enclosure
5
system was adequate to perform its design function under accident conditions. The
issue was of very low safety significance because the licensee determined the system
was operable. Therefore, the issue screened out of Phase 1 of the significance
determination process. (Section 4OA3(3)b.6)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to verify the adequacy of the design of the service water (SW) pump
room ventilation system. Following discovery that the design basis calculations were
non-conservative, the licensee entered the issue into the corrective action program,
re-performed the calculations, and made appropriate modifications to correct the issues.
The primary cause of this violation was related to the cross-cutting area of corrective
action because the licensee failed to correct all of the originally identified issues until
identified by team.
This issue was more than minor because inadequacies in the calculations resulted in a
modification which was required to ensure winter operation was within the allowable
temperature range, and because the revised calculation did not include all the summer
heat loads which could potentially impair the SW pump room ventilation system to
perform its safety function. The issue was of very low safety significance because the
licensee determined that past non-procedurally-required compensatory actions had
prevented the equipment from actually being inoperable. Therefore, the issue screened
out of Phase 1 of the significance determination process. (Section 4OA3(3)b.7)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to ensure that the service water system could perform its design function
under all required conditions. Following discovery, the licensee documented the issue in
the corrective action program and performed the necessary calculations.
This issue was more than minor because the licensee did not initially have a calculation
which showed that the service water (SW) system could fulfill its design function under
design basis conditions and because, when the calculation was prepared, it identified
circumstances where the system would not be able to perform its safety function and
those circumstances were not evaluated to ensure that the safety function could be met.
The issue was of very low safety significance because the licensee concluded that the
SW system had never been unable to perform its safety function. Therefore, the issue
screened out of Phase 1 of the significance determination process.
(Section 4OA3(3)b.8)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to have provisions in place to protect the service water pump room from
flooding. Following discovery, the licensee placed the issue in the corrective action
program, evaluated the issue and established procedures to address the issue.
This issue was more than minor because the licensee had to make procedural changes
in order to ensure that safety-related equipment was capable of performing its safety
functions. The issue was of very low safety significance because the deficiency only
Enclosure
6
dealt with a lack of procedural guidance. Therefore, the issue screened out of Phase 1
of the significance determination process. (Section 4OA3(3)b.9)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XI, Test Control, having very low safety significance. Specifically, the
licensee failed to account for a number of conditions in the service water system flow
balance testing procedures. Following discovery, the licensee placed the issue in the
corrective action program, evaluated the issue and established procedures to address
the issue.
This issue was more than minor because procedural changes were necessary in order
to ensure that the safety-related service water (SW) system branch flow rates were
adequate for the system to perform its safety functions. The issue was of very low
safety significance because the licensee concluded that the system was previously
capable of meeting its design requirements. Therefore, the issue screened out of
Phase 1 of the significance determination process. (Section 4OA3(3)b.10)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to provide an analysis which addressed the service water valve single
failure assumptions described in the updated safety analysis report. Following
discovery, the licensee entered the issue in the corrective action program. The primary
cause of this violation was related to the cross-cutting area of problem identification and
resolution because the licensee had not recognized the impact of the issue on the
design basis and had not corrected it after it was identified in 2002.
This issue was more than minor because the current calculations were non-conservative
and the licensee was not able to show that the service water system could perform its
safety function under design basis conditions. The issue was of very low safety
significance because the team determined that it was unlikely that the service water
system would not function during a design basis accident, as there would need to be a
maximum service water temperature or minimum ultimate heat sink level and a specific
valve single failure. This issue was a design deficiency that would not likely result in the
loss of function; therefore, the issue screened out of Phase 1 of the significance
determination process. (Section 4OA3(3)b.13)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to ensure that design analyses showed that the auxiliary feedwater
(AFW) system could perform its safety function under design basis conditions.
Following discovery, the licensee entered the issue into the corrective action program.
The primary cause of this violation was related to the cross-cutting area of human
performance, as the licensee used the results of a vendor calculation without verifying
that it was adequate.
This issue was more than minor because the calculations were non-conservative and
the calculation of record did not demonstrate that the AFW system could perform its
safety function under design basis conditions. Based on further analysis, the licensee
concluded the AFW system was operable. Therefore, the issue screened out of
Phase 1 of the significance determination process and was of very low safety
significance. (Section 4OA3(3)b.14)
Enclosure
7
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XI, Test Control, having very low safety significance. Specifically, the
licensee failed to recognize that flushing the system and blowing down the strainers
upstream of the turbine driven pump bearing cooling water strainers prior to routine
surveillances constituted preconditioning of the auxiliary feedwater system. Following
discovery, the licensee entered the issue into the corrective action program. The
primary cause of this violation was related to the cross-cutting area of problem
identification and resolution because the licensee had failed to recognize the
consequences of the preconditioning when evaluating an earlier issue.
This issue was more than minor because there was not sufficient information to show
that test requirements would have been met had the strainers not been blown down.
The issue was of very low safety significance because the licensee considered the
system operable. Therefore, the issue screened out of Phase 1 of the significance
determination process. (Section 4OA3(3)b.15)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, having very low safety significance. Specifically, the
licensee failed to ensure that emergency core cooling system pump motors were
environmentally qualified for the stated mission time, as stated in a license amendment
request submitted to the NRC. Following discovery, the licensee entered the issue into
the corrective action program. The primary cause of this violation was related to the
cross-cutting area of human performance as the licensee did not ensure that personnel
developing license documents had the necessary information.
This issue was more than minor because, if left uncorrected, this weakness could result
in a repeat failure of the corrective action program to adequately identify, evaluate and
correct problems. The issue was of very low safety significance because the licensee
considered that the motors could be environmentally qualified. Therefore, the issue
screened out of Phase 1 of the significance determination process.
(Section 4OA3(3)b.21)
Severity Level IV. The team identified a Non-Cited Violation of 10 CFR 50.59,
Changes, Tests and Experiments. Specifically, the licensee failed to preform an
adequate evaluation of a defacto modification to the plant where the underlying change
may have required NRC approval prior to implementation. The design change involved
degraded or missing physical barriers that could result in one or more of the diesel
generators failing to fulfill their design function during a tornado. Following discovery,
the licensee entered the issue into the corrective action program and re-performed the
analysis. The licensee also repaired those barriers which were physically degraded.
The primary cause of this violation was related to the cross-cutting area of human
performance as the licensee appeared to selectively choose information from the
guidance document in order to achieve the desired outcome.
Because this issue affected the NRCs ability to perform its regulatory function, this
finding was evaluated with the traditional enforcement process. The finding was
determined to be of very low safety significance based on a significance determination
Enclosure
8
process analysis of a loss of offsite power concurrent with loss of one emergency diesel
generator. (Section 4OA3(3)b.23)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to include environmental effects of a decay heat removal pump seal
failure in the moderate energy line break analysis. Following discovery, the licensee
entered the issue into the corrective action program and re-performed the analysis.
This issue was more than minor because the licensee had to perform calculations to
show that the environmental effects were acceptable. The issue was of very low safety
significance because, upon completing the analysis, the licensee determined that the
moderate energy line break heat loads were acceptable and that the system could
perform its design function. Therefore, the issue screened out of Phase 1 of the
significance determination process. (Section 4OA3(3)b.24)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Section III.L.2.e,
having very low safety significance. Specifically, the licensee failed to provide the
process cooling and lubrication necessary to permit the operation of the equipment used
for safe shutdown functions. Following discovery, the licensee entered the issue into
the corrective action program and performed a modification to resolve the issue. The
primary cause of this violation was related to the cross-cutting area of problem
identification and resolution because the licensee had previously identified this issue as
an enhancement and did not recognize that it was a violation of regulatory requirements.
This issue was more than minor because, if left uncorrected, the finding would become
a more significant safety concern. By not providing containment air cooling as per the
governing alternative shutdown procedure, the probability of the failure of equipment
relied upon for safe shutdown was increased. This issue was screened to be of very low
safety significance because there was not a total loss of safety function for an assumed
control room fire with evacuation. (Section 4OA3(5)b.2)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50.48(a)(1), having
very low safety significance. Specifically, the licensee failed to evaluate the adequacy of
emergency diesel generator common floor drains following sprinkler system actuation in
the fire affected emergency diesel generator room. Following discovery, the licensee
entered the issue into the corrective action program and revised the fire response
procedures to address the issue.
This issue was more than minor because it affected the mitigating systems cornerstone
and the potential existed that a fire in one emergency diesel generator room would
potentially impact the redundant emergency diesel generator following sprinkler actuation
in the fire affected emergency diesel generator room. The finding was of very low safety
significance since this issue was a design deficiency that was confirmed not to result in
the loss if function per Generic Letter 91-18, Revision 1. Therefore, the issue screened
out of Phase 1 of the significance determination process. (Section 4OA3(5)b.3)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
Enclosure
9
licensee failed to provide for the original plant design to incorporate a safety-related
recirculation path for the high pressure injection (HPI) pumps in the high pressure
recirculation (HPR) mode of operation. Following discovery, the licensee installed an
additional minimum flow recirculation line for each HPI pump.
This issue was more than minor because the original plant design did not incorporate a
safety-related recirculation path for the HPI pumps in the HPR mode of operation and
this finding affected the mitigating systems cornerstone. The issue was of very low
safety significance because the HPR safety-function would not actually have been lost
because of existing procedure actions for feed and bleed operations in situations where
the steam generators could not be used to remove decay heat. Therefore, the finding
screened out as having very low safety significance. Section (4OA3(6)b.3)
Cornerstone: Barrier Integrity
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to correctly identify and translate the design basis requirements into the
containment air coolers airflow analyses and motor horsepower sizing calculations. The
primary cause of this violation was related to the cross-cutting area of problem
identification and resolution as the licensee had previously identified issues with the
motors, but had not reviewed the design calculation of record. Following discovery, the
licensee entered the issue into the corrective action program and performed a new
analysis for the motor.
This issue was more than minor because the licensee had to revise the associated
calculation to evaluate the existing motor to ensure the containment air coolers (CAC)
would be able to perform their design function. The issue was evaluated in a Phase 1
analysis in the significance determination process. Because the issue involved both the
mitigating system and barrier integrity cornerstones, a Phase 2 analysis was also
performed. A final evaluation was obtained that the issue was of very low safety
significance. (Section 4OA3(3)b.3)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to evaluate a potential overstressing condition on the reactor coolant
pump casing-to-cover studs. Following discovery, the licensee entered the issue into
the corrective action program. The primary cause of this violation was related to the
cross-cutting area of problem identification and resolution as the licensee closed a
condition report without recognizing that the apparent condition adverse to quality had
not been addressed.
This issue was more than minor because the NRC had to perform calculations to
determine if the reactor coolant pump studs were within ASME Code allowables. The
issue was of very low safety significance based on the NRC determination that the studs
were always functional. Therefore, the issue screened out of the Phase 1 significance
determination process as having very low safety significance. (Section 4OA3(3)b.19)
Enclosure
10
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, having very low safety significance. Specifically, the
licensee failed to take adequate corrective actions to previous events to prevent
damage to a new fuel assembly spacer grid strap during the final reload of the core in
February 2003. Following discovery, the licensee entered the issue into the corrective
action program. The primary cause of this violation was related to the cross-cutting
areas of corrective action and human performance, because, despite earlier events, the
licensee failed to adequately address the human performance issues that contributed to
this and other fuel spacer grid events.
This issue was more than minor because the licensee failed to prevent recurrence of a
significant condition adverse to quality resulting in damage occurring to previously
undamaged fuel assembly grid straps. The issue only involved the fuel barrier and it
screened out of the Phase 1 significance determination process as having very low
safety significance. (Section 4OA3(4)b)
Non-Significance Determination Process Issues
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to assess an increase in the offsite dose to the public following a
postulated design basis accident due to increased containment pressure. Following
discovery, the licensee entered the issue into the corrective action program and
performed the necessary analysis. The primary cause of this violation was related to
the cross-cutting area of problem identification and resolution, because, although the
issue had been previously identified, the licensee had failed to identify that a revised
dose assessment was needed until prompted by the NRC.
This issue was more than minor because the licensee had to perform calculations to
show that the increased time at higher containment pressures did not result in doses
being above regulatory guide allowables. The mitigating system cornerstone was not
affected since the finding pertained to offsite dose calculations rather than containment
air coolers performance. Based on this review, the team determined that the issue was
not covered by any of the revised oversight cornerstones and was, therefore, not
suitable for SDP analysis. This determination was due to the issue regarded
containment pressure and related to offsite dose consequences. Regional management
determined that this regulatory issue was of very low safety significance because
projected offsite doses remained less than Regulatory Guide 1.4 allowances.
(Section 4OA3(3)b.2)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to implement effective design control measures to check and verify the
adequacy of the design basis calculation performed for sizing the new accumulators
used to hold the service water containment isolation valves closed on a loss of
instrument air. Following discovery, the licensee entered the issue into the corrective
action program, revised calculations, and changed the accumulator medium from
compressed air to nitrogen.
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11
This issue was more than minor because the licensee had to change the modification
design from having accumulators containing pressurized air to accumulators containing
pressurized nitrogen. This finding was evaluated in Phase 1 of the significance
determination process. The mitigating system cornerstone was not affected since the
finding pertained to the sizing of accumulators associated with containment isolation
valves. Therefore, the issue was not covered by any of the revised oversight
cornerstones and was, therefore, not suitable for SDP analysis. This determination was
based on the issue affecting containment isolation valves which provide a barrier to
breach of containment and potential offsite dose consequences. Regional management
determined that this regulatory issue was of very low safety significance.
(Section 4OA3(3)b.4)
Green. The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, having very low safety significance. Specifically, the
licensee failed to translate the postulated radiological consequences of leakage from
engineered safety feature components outside containment into calculations of record
for post-accident control room dose and offsite boundary dose. Following discovery, the
licensee entered the issue into the corrective action program and provided a bounding
evaluation which demonstrated that the increase in dose was within acceptable limits.
This issue was more than minor because the licensee had to perform calculations to
show that the increased doses remained within the post accident dose level
requirements. The issue could not be assessed through the significance determination
process, because none of the cornerstone objectives addressed design issues dealing
with postulated doses following a design basis accident. After determination that the
increase in dose did not involve an issue requiring a license amendment, Regional
Management concluded the regulatory issue was of very low safety significance.
(Section 4OA3(3)b.18)
B.
Licensee-Identified Violations
No findings of significance were identified.
Enclosure
12
REPORT DETAILS
4.
OTHER ACTIVITIES (OA)
4OA2 Identification and Resolution of Problems (71152B)
Background
On March 6, 2002, Davis-Besse personnel notified the NRC of degradation (corrosion)
of the reactor vessel head material adjacent to a control rod drive mechanism (CRDM)
nozzle. This condition was caused by coolant leakage and boric acid corrosion of the
head material induced by an undetected crack in the adjacent CRDM nozzle. The
degraded area covered in excess of 20 square inches where the low-alloy carbon
structural steel was corroded away, leaving the thin stainless steel cladding layer. This
condition represented a loss of the reactor vessels pressure retaining design function,
since the cladding was not considered as pressure boundary material in the structural
design of the reactor pressure vessel. While the cladding did provide a pressure
retaining capability during reactor operations, the identified degradation represented an
unacceptable reduction in the margin of safety of one of the three principal fission
product barriers at Davis-Besse. This issue was documented in inspection report (IR)
05000346/2002003. The event was captured in the licensee's corrective action program
(CAP) as condition report (CR) 02-00891, "Failure to Identify Significant Degradation of
the Reactor Pressure Vessel Head." The root cause analysis report for the CR
documented that one of the root causes of the event was "less than adequate
implementation of the corrective action program."
As part of the licensees return to service plan and as corrective action for the
circumstances that led to the vessel head degradation, the licensee implemented the
Davis-Besse system health assurance (SHA) plan. This plan described activities to
review plant systems prior to restart to ensure that plant systems were in a condition
that would support safe and reliable operation.
In an effort to identify adverse trends and problem areas, the licensee performed a
collective review of approximately 600 relatively significant CRs and developed
approaches to correct the discrepancies, evaluate the extent of condition, address any
trends, and resolve the issues. The licensee used a three-phase corrective action
process to identify and resolve deficiencies:
Path A - Resolution of each condition identified and determination of the extent
of condition. This approach used the stations CAP to determine cause, extent
of condition, and implement specific corrective actions for discrepancies
Path B - Evaluation to provide additional assurance of significant safety function
capabilities. The collective review identified numerous deficiencies in the areas
of calculations and testing which validated or verified the capability of safety
systems to perform their functions.
Enclosure
13
Path C - Resolution of design-related programmatic issues. The collective
review identified numerous discrepancies in five design-related programmatic
areas (station flooding, high energy line break, environmental qualification,
seismic qualification, and 10 CFR Part 50, Appendix R - Safe Shutdown) within
each of the five systems selected for a detailed latent issues review. The
licensee conducted a specific detailed examination of CRs to identify,
characterize, determine the extent of condition, and correct the problems in each
of those programmatic areas.
The licensees review efforts identified numerous discrepancies involving an inadequate
CAP, inadequate configuration control, degraded hardware conditions, inconsistent and
potentially non-conservative assumptions in design basis and licensing basis
documents, deficient or unavailable calculations, and non-conservative operating and
test procedures which did not reflect design and licensing basis documents. The
identified discrepancies were documented in new CRs and these CRs were assessed
for operability impact and significance in accordance with the stations CAP.
As part of the NRCs inspection of the SHA plan, a safety system design and
performance capability inspection (SSDI) was conducted on three systems: the service
water (SW), high pressure injection (HPI), and 4160 volt alternating current (AC)
electrical distribution systems. This inspection identified numerous deficiencies, which
mirrored the licensee's findings in a number of areas. This inspection, and the resultant
findings, were documented in IR 05000346/2002014.
(1)
Corrective Action Program Implementation
a.
Inspection Scope
To assess the licensees corrective actions to adequately address the numerous plant
deficiencies identified in 2002 during the licensees and NRC reviews, the NRC
conducted an in-depth corrective action team inspection (CATI) of the CAP
implementation. This inspection was intended to assess the effectiveness of the
licensees actions to identify the deficiencies, evaluate the cause(s) and correct the
problems in order to prevent recurrence.
In order to make the above assessment, the team reviewed selected CRs which
evaluated the licensees actions to address deficiencies documented in licensee event
reports (LERs), NRC Non-Cited Violations (NCVs), and NRC unresolved items (URIs)
from previous inspections. The selected CRs also involved issues identified by the
licensee as part of their system health readiness or latent issue reviews. The team's
focus was on CRs which the licensee had identified as requiring resolution prior to the
restart of the plant, with a further emphasis on those CRs which the licensee had
determined to be "significant conditions adverse to quality (SCAQ)."
The team specifically assessed the licensee's CAP in four separate areas:
Identifying problems; including recognizing performance issues within the CAP
itself;
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14
Categorizing and prioritizing problems, with a specific emphasis on the licensee's
use of a process termed as "rollovers";
Evaluating those problems; including assessing root and apparent causes,
extent of conditions, operability and reportability;
Correcting problems, including not only the originally identified problem but any
issues identified as part of the evaluation, assessment of effectiveness of the
corrective actions and actions taken to prevent recurrence.
In addition, the team assessed two areas where a number of problems were identified.
These were:
Engineering Resolution of Design Deficiencies and
Procedure Quality and Adherence
b.
Observations and Findings
The corrective action program was described in procedure NOP-LP-2001, "Condition
Report Process." This procedure was significantly revised in March 2003, and again in
May 2003. The CAP consisted of a process to identify and resolve potential adverse or
undesirable conditions. It included issues, concerns, observations, equipment
deficiencies, human performance problems, equipment failures and programmatic
deficiencies.
The team began its inspection in March 2003. However, due to the licensee not being
ready for the inspection at that time, the inspection was delayed until May 2003, and the
most effective inspection actually occurred in August 2003, when the licensee had
completed sufficient packages for the team to review.
As described below, at the conclusion of the inspection, the team determined that,
overall, the licensee's program for identifying, prioritizing, evaluating, and correcting
performance deficiencies was acceptable. However, the team also observed that the
licensees actions to identify non-conforming issues and prevent recurrence were often
minimally effective. The team also identified evaluations which were narrowly focused
and not probing in nature. Consequently, the resulting corrective actions were also
narrowly focused. In areas where the licensee had established corrective actions, the
effectiveness of these actions could not be readily determined at the end of the
inspection due to the short time frame since implementation.
During the inspection, the team reviewed approximately 150 CRs. Of these, the team
determined that approximately 120 had weaknesses or deficiencies, of some type. As a
result of the teams findings, the licensee initiated approximately 120 additional CRs to
document and address the teams findings. Overall, the team determined that
approximately 80 percent of the CRs actually reviewed by the team had weaknesses or
deficiencies to some degree. The weaknesses and deficiencies identified by the team
resulted in the identification of findings documented in this inspection report.
Subsequent to the onsite inspection, on November 12 and December 10, 2003, the
licensee presented to the NRC, the planned actions to address the issues and concerns
identified by the CATI. As part of these meetings, the licensee made a number of
Enclosure
15
commitments to further improve the CAP as part of its Operational Improvement Plan
for Cycle 14, Revision 3. The team recognized that the improvement plan described
actions that should address the teams areas of concerns. Additionally, the licensee
implemented some improvements in the CAP. Examples included the revised CAP
procedure and the newly established CR analyst positions.
.1
Adequacy of Licensee's Efforts to Identify and Document Problems
The team determined that the licensee, overall, was adequately identifying and
documenting problems. However, a number of examples were identified where the
licensee had failed to identify or to document problems, particularly in the area of
design-related deficiencies. The team attributed these issues to a lack of attention to
detail, weak knowledge of system design basis, and a failure to follow CAP procedures.
Specific examples are listed below, and the more significant ones are discussed in
Sections 4OA3(2) and 4OA3(3) of this report.
Failure to identify the lack of thermal overload protection for safety related
motors (See Section 4OA3(2)b.2 for additional details);
Failure to identify oversized fuses in safety related motor operated circuits (See
Section 4OA3(2)b.4 for additional details);
Failure to identify the main steam safety valve (MSSV) setpoint drift and
accumulation, and the potential affect on auxiliary feedwater (AFW) pump flow
(See Section 4OA3(3)b.14 for additional details);
Failure to identify potential design problems with the containment air coolers
(CACs) (See Sections 4OA3(3)b.2 and 4OA3(3)b.3 for additional details);
Failure to write a CR for SW calculational deficiencies. (See CR 03-03977);
Failure to generate a CR to address a problem identified during the SSDI and
which was documented in that IR as NCV 02-014-01b (See Section 4OA3(3)b.5
for additional details);
Failure to identify lack of breaker coordination (CR 03-03572); and
Failure to identify configuration control discrepancies (CR 03-02699).
.2
Adequacy of Licensee's Efforts to Categorize and Prioritize Problems
The team determined that the licensee, overall, was adequately categorizing items in
regard to their safety significance and impact upon plant operation. The licensee also
generally appeared to be assigning an appropriate priority both to performing evaluations
and completing corrective actions prior to restart of the plant.
However, early in the inspections the team did identify a concern with a process the
licensee was using as part of their categorization process. This process, referred to as
"rollovers, allowed the licensee to disposition CRs by transferring either a portion or the
Enclosure
16
entire issue to one or more additional other open CRs. The licensee did place a
condition that the "rolled-into" CRs had to be of equal or greater category and had to
address the same issues. However, the issues described in the "rolled-out-of" CRs could
be broken into several different "rolled-into" CRs and "rolling" could occur on multiple
occasions (i.e., CR 1 was rolled into CR 2 which was rolled into CR 3, which then rolled
out part of CR 1s issues to CR 4...). This was especially true in regard to specified
corrective actions. As an example, the team identified that more than 25 corrective
actions were rolled over into CRs 02-00891, "Failure to Identify Significant Degradation of
the Reactor Pressure Vessel Head," and CR 02-04884, "Ineffective Corrective Action
Problem Resolution." Some problems were identified, and the extent of the rollover
process early in the inspection made it extremely difficult for the team to accurately
assess whether the overall process was adequately controlled and that corrective actions
were effectively implemented.
The team also noted that the CAP defined that a CR should only be listed as "closed"
when the evaluation was completed and all corrective actions were implemented.
However, the licensee frequently classified a "rolled out of" CR as "Closed", because the
evaluation and/or the corrective actions were transferred to another CR. This gave a
somewhat artificial characterization as to the status of resolution of identified issues.
The team was concerned that the complexity of the rollover process, the inability to
easily track resolution of identified concerns, and the lack of adequate guidance could
have resulted in inappropriate resolution of problems. Other examples of rollover
problems included: improper implementation of corrective actions, lack of cross
references and flawed cause analysis.
Specific examples of rollover problems identified by the team are listed below, and the
more significant ones are discussed in Sections 4OA3(2) and 4OA3(3) of this report.
The resolution to the trisodium phosphate (TSP) post-accident concerns were
difficult to evaluate due to the number of rollovers (See Section 4OA3(3)b.17 for
details);
Three CRs on fuel spacer grid damage were rolled into a SCAQ CR, but were
not addressed in the root cause analysis (See Section 4OA3(4)b for details);
Corrective action 13 in CR 02-05385 was not related to the identified issue.
Licensee determined that, due to rollovers, the corrective action ended up in the
wrong CR (CR 02-05385);
There were informal rollovers in CRs 02-07657, 02-05904, 02-05881, and
02-06779 (See Sections 4OA3(3)b.12, 4OA3(3)b.16, and 4OA3(3)b.19 for
further discussions regarding rollovers); and
In addition there was an inadequate rollover of overload protection concerns in
CR 03-02616 to CR 03-03572 (Section 4OA3(2)b.2).
The team identified that the licensee had issued seventeen CRs within a six month
period related specifically to licensee-identified concerns with the rollover process. As a
result of the team's review of rollover CRs, the licensee identified a specific issue, as
Enclosure
17
documented in CR 03-01955, "CR Rollover Discrepancies," regarding rollover of
concerns as part of the containment health review.
Based on both the team's and the licensees own internal findings in regard to the
rollover process, the licensee revised the CAP procedure to place limits on the number
of times an issue could be rolled and to strengthen the rollover process.
.3
Adequacy of Licensee's Efforts to Evaluate Identified Conditions
During the inspection, the team found examples where the licensee was not fully
effective in evaluating problems, particularly in regard to determining the apparent cause
of issues. The team determined that this failure to adequately evaluate issues could be
attributed to a narrow evaluation focus, weak knowledge of the design basis, and lack
of attention to detail.
At the start of the inspection, the licensee divided CR evaluations into three categories:
SCAQ CRs, which required a root cause evaluation; "CA" CRs which required an
apparent cause evaluation; and "CF" CRs which required the deficiency to be fixed and
did not require a cause evaluation.
While generally adequate, the team determined that some root cause evaluations did
not always use a formal method to arrive at a root cause. In at least one case, the root
cause did not arrive at a cause for the discrepant condition. In another, information
used to arrive at the conclusion was not discussed in the evaluation. In contrast, the
team identified that the root cause evaluation for SCAQ CR 02-00891, performed to
determine root and contributing causes of the head event, was well done.
In regard to the apparent causes, the team identified that the majority of the stated
apparent causes were one-line sentences and appeared to address the symptoms of
the deficiency and did not address why the condition happened.
The team noted that the CAP listed timeliness expectations as to when the evaluation
(either apparent or root cause) would be completed. During the inspection, the team
noted that some CR evaluations were granted multiple time extensions and that other
evaluations were overdue by several months. The team frequently was unable to
determine the basis for the extensions being granted. Additionally, the team noted that,
in some cases, the licensee did not have a documented basis for delaying evaluation of
a discrepant condition until after restart. These issues were discussed with the licensee
for resolution.
Another concern relating to the CAP identified by the team was that the licensee's
electronic system permitted previously approved CRs to be rejected and re-evaluated.
The team was concerned that the process of rejecting a previously reviewed and
accepted evaluation was a potential deficiency in the CAP. The licensee took corrective
actions to discontinue this practice.
The team also noted that, in general, the licensee did not perform extent of condition
reviews and that the few reviews done lacked thoroughness. Revision 4 of the
licensee's CAP procedure called for an assessment of generic implications on those
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18
CRs requiring an apparent cause evaluation. The team noted that the lack of such
reviews created the potential for not identifying other problem areas.
Specific examples of the above problems are listed below, and the more significant ones
are discussed in Sections 4OA3(2) and 4OA3(3) of this report.
Root Cause Findings
Root cause for CR 02-06178 didnt contain sufficient information to support
conclusions. It also failed to address three CRs which were rolled into it.
Additionally, the extent of condition review was not well documented (See
Section 4OA3(4)b for details);
Downgrade of SCAQ CRs 02-06356 and 02-06677 were not adequately justified
and, in the case of the first issue, no cause evaluation was performed at all.
(See Section 4OA3(3)b.22 for details);
Root cause was not identified for SCAQ CR 02-04673 because the finding was
historical, also the evaluation failed to identify issues of pre-conditioning and
component limitations (See Section 4OA3(3)b.15 for details);
Apparent Cause Evaluation Findings
Evaluation of the HPI pump minimum flow issue was inadequate (See Section
4OA3(3)b.1 for details);
Evaluation was inadequate in that the consequences of potentially increased
offsite doses due to the degraded condition were not addressed (See
Section 4OA3(3)b.2 for details);
Evaluation failed to address issue identified in the CR (See Section 4OA3(3)b.12
for details);
Evaluation on allowable reactor coolant pump (RCP) stud elongation was flawed
(See Section 4OA3(3)b.19 for details);
Evaluation provided weak basis for not identifying issues (See Section
4OA3(3)b.21 for details);
Evaluation contained incorrect information and inadequately assessed issue
(See Section 4OA3(3)b.20 for details);
Evaluation of the causes for missing or degraded emergency diesel generator
(EDG) tornado missile protection was poor (See Section 4OA3(3)b.23 for
details);
Evaluation for CR 02-05640 was weak and referenced corrective action
documents appeared incorrect;
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19
Inadequate evaluation for CR 02-05727;
Inadequate evaluation for CR 02-05738;
Evaluation for CR 02-05885 referenced an incorrect calculation and had a wrong
revision for other another calculation;
Cause analysis for CR 02-06723 did not address that struts were not supposed
to be greased; and
Evaluation did not address temperature increase for CR 02-06893
(Section 4OA5(1)b.2.7).
Extent of Condition Findings
Extent of condition review for CR 02-00412 was inadequate (See
Section 4OA3(2)b.4 for details); and
Required extent of condition reviews for CRs 02-01129 and 02-07188 were not
performed (See Section 4OA3(3)b.7 for details of the latter issue).
At the conclusion of the inspection, the licensee initiated a collective significance review
CR, 03-06908, to address the team's findings regarding CAP deficiencies, especially in
the area of apparent cause evaluations.
.4
Adequacy of Licensee's Efforts to Correct Identified Problems
The team identified examples where inadequate corrective actions were due to the
inadequate cause evaluations. The team also identified examples where corrective
actions were prematurely closed based on unapproved calculations; where actions were
closed without actually completing the work; and where the specified corrective actions
did not resolve the originally identified issue. The team also identified several items
where the corrective actions appeared untimely. Very few effectiveness reviews had
been done at the time of the inspection, so the team was unable to assess the overall
effectiveness of the implemented corrective actions. Most effectiveness reviews for
corrective action items that were implemented via CR 02-00891 had not been completed
by the end of the inspection.
Specific examples of the above problems are listed below, and the more significant ones
are discussed in Sections 4OA3(2) and 4OA3(3) of this report.
A hardware change for CR 02-04680 was indicated as complete when it was not
actually done;
Three examples were identified where the corrective actions were closed before
the calculations were issued (See Sections 4OA3(3)b.17, 4OA3(3)b.19 and
4OA5(1)b.2.23 for details);
Enclosure
20
The diesel driven fire pump heat load was not included in the SW ventilation
system calculation, even though the NRC identified that specific heat load as one
which been missed (See Section 4OA3(3)b.7 for details);
Corrective actions to a Nuclear Quality Assurance (NQA) finding did not address
defined problem - NQA initiated a second CR to address the issue (Section
4OA3(3)b.19);
An NRC identified issue regarding a procedure deficiency was not corrected until
the team questioned the issue (See Section 4OA3(3)b.12 for details);
Corrective action 15 to CR 02-04884 was closed even though not all required
individuals were trained;
Corrective action 30 of SCAQ CR 02-00891 was closed out prior to performing
the required operations confidence reviews.
.5
Review of Engineering Products and Corrective Actions
The team determined that the licensees effectiveness in resolving design deficiencies
was inconsistent. The most difficult area for the licensee appeared to be in regard to
quality of calculations, as many of the calculations reviewed by the team required
multiple iterations to correct team-identified problems. The team attributed this
observation to weak engineering knowledge of the design and licensing basis of the
plant and a lack of attention to detail.
Based on a review of recently approved mechanical engineering design calculations, the
team determined that about 40 percent of the calculations reviewed required generation
of a new CR to fix a calculation problem. Included in the problems were configuration
control issues where design analysis was not controlled. The team also noted use of
non-conservative assumptions, omissions, and errors in recently approved design
calculations.
In the electrical area, the team determined that the electric transient analysis profile
(ETAP) calculations which were completed in 2003, appeared to be well performed.
As a result of the numerous calculational issues identified by the team, the licensee
initiated CR 03-06907 to perform a collective significance review on calculation quality.
Additionally, the licensee initiated CR 03-06909 to perform a collective significance
review of overall engineering design control issues.
Subsequent to the onsite inspection, on November 12 and December 10, 2003, the
licensee presented to the NRC, the planned actions to address the issues and concerns
identified by the CATI. As part of these meetings, the licensee made a number of
commitments to further improve the quality of engineering products such as calculations
and cause analyses. These efforts included expanding the scope of the Engineering
Assessment Board (EAB) reviews to include calculations which supported modifications.
The process improvements were incorporated as part of the licensees Operational
Improvement Plan for Cycle 14, Revision 3.
Enclosure
21
.6
Adequacy of Licensees Efforts to Resolve Procedure Adherence and Quality
Issues
The team noted that there were several programmatic procedural improvements,
including the CAP procedure, the boric acid corrosion control (BACC) program
procedure, and the self-assessment guideline. Additionally, engineering procedures
also improved. Typically, it appeared that the licensee staff did a good job on procedure
development. The team also noted that the licensee identified a number of procedural
adherence problems. The licensee initiated a SCAQ CR in 2002 to evaluate and
address multiple procedure issues.
Many of the teams findings resulted from the licensees failure to adhere to the
corrective action procedure and other procedural requirements. Specific examples of
the above problems are listed below, and the more significant ones are discussed in
Sections 4OA3(2) and 4OA3(3) of this report.
The licensee failed to follow trending and self evaluation procedures and
guidelines (See Section 4OA2(2)b.1).
The licensee's NQA organization identified numerous problems with procedures
(See Section 4OA2(2)b.3 for detail).
(2)
Review of the Licensees Internal Assessment Activities
a.
Inspection Scope
The team examined the licensees program, and implementation thereof, to trend CRs
and analyze the results as delineated in procedures NG-NA-00711, NOBP-LP-2001 and
NOBP-LP-2004. In addition, the team examined the licensees implementation of the
self assessment program. Trending and self assessments were required by the
licensee's procedures. The team also reviewed the licensees implementation of CAP
performance indicators (PIs) to determine their intended use and adequacy in
measuring effectiveness of corrective action implementation. The team also evaluated
the effectiveness of the licensee's internal assessment capability by reviewing selected
NQA audits and available self evaluation reports, which were specifically performed to
assess the implementation of the CAP and which were conducted between January
2002 and August 2003. In addition, the team reviewed the licensees follow-up on
selected NQA findings to determine whether the licensees response was adequate and
timely, and corrective actions were properly prioritized and implemented to prevent
recurrence. The procedure for audit activities performed by the NQA organization was
described in procedure NOP-LP-2004.
b.
Observations and Findings
.1
Trending, Self-Assessment, and Evaluation Program Implementation
Introduction: The team identified that the licensee failed to perform the required CR
trending analysis and to ensure that condition reports were regularly assessed for
indications of adverse trends, generic problems, and repetitive conditions requiring
Enclosure
22
corrective actions. The licensee entered the issue into its corrective action program in
December 2002 and again in July 2003 to re-evaluate the issue, and began the required
trending at the end of the inspection.
Description: The team determined, through reviews of CRs and via interviews that the
licensee had not implemented the CR trending program which was required by
procedure NG-NA-00711. In April 2003, the team determined that trending of
equipment CRs stopped in December 2001, prior to the plant shutting down for refueling
outage (RFO). Departmental and performance improvement group trending activities
stopped in March 2002. This latter cessation was a licensee management decision
because of the number of issues which were being identified during the various
programmatic reviews. However, once the programmatic reviews were completed, the
trending program was not reinitiated in a timely fashion.
Procedure NG-NA-00711 required that CR trending analysis be performed regularly.
Section 6.2 of the procedure stated that the performance improvement manager was to
ensure that CRs were regularly assessed for indications of adverse trends, generic
problems, and repetitive conditions requiring corrective actions. The procedure also
required that indications of potential adverse conditions were to be discussed with
management of the responsible organization to ensure that generic problems, repetitive
conditions or adverse trends were classified as conditions adverse to quality. In
addition, the procedure stated that a quality trend summary was to be prepared at least
quarterly and distributed to managers, directors and the Vice President - Nuclear.
The team determined that a licensee engineer initiated CR 02-10369 on
December 19, 2002, to document that the CR trend analysis had not been reinitiated
even though the discovery phase of the various programmatic reviews was finished.
The CR identified that procedural requirements for trend analysis were not being
followed. The CR also stated that a regular review of CR issues was also required as a
corrective action to a previous audit finding. The licensees evaluation of CR 02-10369
noted that, although the procedurally required trend analysis and trend reporting had not
been resumed, other tasks enacted under the Davis-Besse return to service plan could
have identified generic problems, adverse trends and repetitive conditions. Therefore,
the licensee concluded that no immediate corrective actions were necessary to reinstate
the CR trending program.
The team noted that trend analysis and reporting should contribute to the identification
of potential adverse trends, repetitive conditions, and generic problems before those
trends become significant issues. Programmatic issues were identified by the team
during the inspection, such as inappropriate use of rollovers, calculation problems and
design issues. The team noted that the licensee initiated three condition reports to
evaluate the collective significance of the team's findings.
On July 23, 2003, NQA independently initiated CR 03-05925 which documented
concerns identical to the team's concerns in regard to weaknesses in implementation of
trending and non-compliance with trending requirements. NQA identified that, in most
organizations, activity codes and trend codes were not routinely trended or analyzed and
that management involvement with trending, in some organizations, was minimal or
nonexistent.
Enclosure
23
The team determined that the framework for an effective trending program existed, but it
was not being implemented and that management attention and focus was needed in
order to ensure that the programs were reinstated. Due to the team identifying potential
trends in several areas, the team was unable to confirm the licensees position that
reliance on processes developed for the extended shutdown could substitute for the
trending analysis process. The licensee entered the issue into its corrective action
program in December 2002 and again in July 2003 to re-assess the issue, and re-
instituted the required trending at the end of the inspection.
The team also assessed the licensees self assessment program implementation. The
need for a self assessment and evaluation program was delineated in NOBP-LP-2001,
NOBP-LP-2004, and the Davis-Besse self evaluation process guide. The purpose of
these self assessment and evaluation guidelines was to continue plant improvement
through implementation of learning organization behaviors by the Davis-Besse
management team to periodically critically assess organizational performance against
established standards/expectations of performance and industry-best practices. The
self evaluation was intended to identify organizational strengths, weaknesses,
challenges, and areas of improvements.
The self evaluation process guideline stated that each quarter, the section managers
and directors were to present the results from their self-evaluations to the Davis-Besse
Vice President. In April 2003, the team noted that the licensee stopped performing the
required self evaluations by the different plant departments after the first quarter in
2002. In July 2003, NQA identified in CR 03-05925 that most site organizations were
not actively performing self-evaluations. The licensee was in the process of replacing
the guideline and reinstating the self-evaluations at the end of the inspection.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to perform the required CR trending. Since there was a performance
deficiency, the team compared this performance deficiency to the minor questions
contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection
Reports." The team concluded that the issue was minor because the lack of CR
trending occurred while the unit was shutdown.
Enforcement: The failure to perform CR trending and department self evaluations from
March 2002 until the end of the CATI on-site inspection in September 2003, constitutes
a violation of 10 CFR Appendix B, Criterion V, which has minor significance and is not
subject to enforcement action in accordance with Section IV of the NRCs Enforcement
Policy.
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case based on the length of time
the licensee was not in compliance.
.2
Corrective Action Program Performance Indicators
During the period when the licensee was not performing trending or self-evaluations, PIs
on the restart performance and CAP effectiveness were published weekly. The CAP
effectiveness PIs included corrective action effectiveness, CR category accuracy, CR
evaluations, corrective action resolution, CR self identification, and management
Enclosure
24
observations. Restart PIs relating to CAP implementation included CR evaluations, CR
resolution, root cause evaluation quality, program and process error rate, CR category
accuracy, CR operations review, corrective action resolution and CR self-identified rate.
The team noted that the indicators generally showed improving trends and that, in most
cases, the licensee was meeting established goals. Action plans were in place for those
PIs which were not meeting their goal in order to improve performance prior to restart.
The team reviewed these PIs and determined that the PIs generally reflected CAP
performance. The team noted that, for example, PI P-01, "Corrective Action Program
Implementation," rated CAP implementation from January to September 2003 as Red
for six of the nine months and as Yellow for the remaining three months. During the
review of P-01, the team noted that the licensee has routinely determined that the
"Repeat Events" element was Green. This meant that there were no repeat SCAQ
events in the last two years. The team determined that, in 2002, the licensee initiated
six SCAQ CRs for what appeared to be a recurring trend of untimely and ineffective
CAP resolution and program implementation. These included CRs 02-02419, 02-02584,
02-03497, 02-03674, 02-04884 and 02-07328. The licensee stated that the above
SCAQ CRs could not be considered repeat events because the events did not involve
similar tasks, causes and consequences. Based on the licensees definition, SCAQ
CRs had to be identical in all three (tasks, causes and consequences) as well as
occurring within two years of each other in order for them to be considered as a repeat
event. The team considered the licensees definition to be limiting, as the above CRs
appeared to the team to document repeat events and an adverse trends. The team also
noted that, because the licensee limited the definition of repeat events to SCAQ CRs,
low level issues that were occurring on a repeat basis (such as repeat CRs) did not
show up in the PI.
The team noted that the PIs did not always provide an accurate indication of the health
of the CAP implementation. For example, the team identified a number of examples
where CRs were indicated as closed in the system when, in reality, the issues were
transferred to other CRs and may not have been either evaluated or corrected.
Finally, the team noted that the PI which assessed quality of engineering products had
shown a negative trend for five weeks from the end of July to the beginning of August
2003. Despite the negative trend, the indicator stated that engineering product quality
had significantly improved since initiation of the EAB. The team questioned the licensee
as to the positive statement on the trend report when the graph had been showing a
declining trend in quality of engineering products. After questioning by the team, the
licensee examined additional engineering products and informed the team that the
products had improved and the latest trend information reflected that improvement.
.3
Nuclear Quality Assessment Audits and Self Assessments of Corrective Action
Program Implementation
The NQA organization conducted various performance-based and program-based
audits of the CAP and its implementation. Some audits evaluated specific activities,
while other audits were broad evaluations of processes or department performance.
Generally, the team found NQA audits to be of a critical nature and to adequately
Enclosure
25
identify CAP implementation deficiencies. The NQA auditors identified conditions
adverse to quality which were documented on CRs and tracked in the CR database.
NQA used the following performance categories to rate effectiveness of the
implementation of CAP: Good Performance, Satisfactory Performance, Marginal
Performance and Unacceptable Performance. The table below documents the results
of the six NQA audits reviewed by the team:
NQA Rating of Corrective Action Program Implementation
Report Number
Date Completed
Primary Rating
Elements Rating
DB-C-02-02
August 9, 2002
Marginal
Unacceptable
DB-C-02-03
November 14, 2002
Marginal
Unacceptable
DB-C-02-04
February 19, 2003
Not Rated
Marginal
DB-C-03-01
May 28, 2003
Not Rated
Marginal
DB-C-03-02
September 1, 2003
Satisfactory1
Not Rated
DB-C-03-03
November 17, 2003
Marginal
Not Rated
1Note: The "satisfactory" rating was for the overall CAP and did not focus on
implementation.
The team noted that the selected CAP implementation areas assessed by NQA from
March 2002 to October 2003 were rated as either "marginal" or "unacceptable." For
example, a NQA CAP focused assessment was conducted between April 4 through
July 4, 2003, and identified CAP and implementation deficiencies which were similar to
those identified by the NRC CATI (NQA initiated 24 CRs). Examples included: lack of
trending activities to identify adverse to quality conditions, use of PI to assess CAP, less
than adequate cause evaluations, corrective action item implementation timeliness, poor
documentation of corrective actions, inadequate peer reviews, lack of rigor,
configuration control issues, rollovers concerns, and failure to comply with administrative
requirements of the NOP (mostly by engineering). Similar findings were noted during
the November 2003 NQA audit.
Overall, the team concluded that NQA was performing sufficiently probing assessments
of the licensees corrective action program implementation.
(3)
Management CAP Meetings
a.
Inspection Scope
One of the key building blocks in the licensees return to service plan was the
management and human performance excellence plan. The purpose of this plan was to
address the fact that, "management ineffectively implemented processes, and thus
Enclosure
26
failed to detect and address plant problems as opportunities arose." One of the primary
management contributors to this failure was the ineffective implementation of the CAP.
During this inspection, the team attended and assessed the licensee management
activities and involvement in selected corrective action related meetings. During these
meetings the licensee conducted a review and classification of CRs, evaluated and
performed a critique of root cause and engineering products, prioritized work activities,
and provided work completion schedule extensions for ongoing work activities. The
team attended and observed various corrective action management oversite meetings
including the corrective action review board (CARB), the restart station review board
(RSRB), and the management review board (MRB).
b.
Observations and Findings
Corrective Action Review Board Meetings: The purpose of the meetings was to
evaluate completed root causes performed to identify and address causes of more
significant plant related issues which were documented in CRs. The team concluded
that the CARB was comprised of experienced individuals with a wide range of
knowledge. The CARB was primarily involved in reviewing the cause analysis packages
for completeness and adequacy of technical information. The CARB also concentrated
on potential design and safety issues and ensured that the engineering
recommendations for resolution of the identified issues appeared adequate to address
the causes.
Restart Station Review Board: One of the purposes of the RSRB was to screen and
classify CRs as to whether they needed to be addressed prior to restart. The team
noted that CRs were screened and classified into one of four categories based on
whether the corrective actions: (1) were necessary to address NRC Manual Chapter
(MC) 0350, "Oversight of Operating Reactor Facilities in an Extended Shutdown as a
Result of Significant Performance Problems" issues; (2) were necessary to address
Davis-Besse restart expectations; (3) could be implemented following plant restart; or
(4) could be addressed at a time unrelated to plant restart. Once the licensee staff
developed corrective actions to address the issues documented in the CRs, the RSRB
also screened the proposed corrective actions to ensure that the underlying issues were
fully addressed. The team observed RSRB members interactions and noted good
questioning attitude and generally appropriate classification of CRs.
Management Review Board: During the MRB meetings, the licensee discussed
corrective action items including review of latest initiated CRs and the potential for
indications of adverse trends. Management appeared to be engaged in the CAP during
these meetings.
Three Day Look-Ahead Committee: This committee discussed CR status and due
dates. The team attended several meetings at the beginning of the inspection and
noted that many due dates were being extended without formal justification or
documented management approval. After the team commented on this practice, the
licensee no longer allowed informal extensions.
Enclosure
27
The team concluded that the management meetings and processes had an appropriate
approach for evaluating and characterizing newly identified issues. The members
appeared to be qualified and knowledgeable of the requirements.
4OA3 Event Response Follow-up - Special Inspection (71153 and 93812)
(1)
Background
Davis-Besse CAP Compliance Review
As part of the licensees restart action plan to identify, monitor and complete all actions
necessary for safe and reliable return to service the licensee initiated various teams
which were tasked with reviewing selected plant programs to ensure that the programs
were fulfilling required obligations and were acceptable to support plant restart. The
CAP was selected as one of the plant programs to receive a comprehensive Phase 2
review as described in the Davis-Besse program compliance plan and procedure
NG-EN-00385.
The review was conducted between June 10 and August 9, 2002. Results were
documented in the "Corrective Action Program Review" report and included numerous
concerns relative to the CAP process and implementation. The Phase 2 review team
determined that the CAP generally met regulatory requirements and that the identified
problems were primarily associated with program implementation. However, the review
team also concluded that the CAP was not consistently implemented in full compliance
with the spirit and letter of the governing and implementing documents and that the CAP
needed to be strengthened prior to restart of the plant.
The primary problem identified during this review was summarized as, "inadequate
implementation of the CAP." Examples of ineffective CAP implementation issues
identified as a result of this review included: (1) a reluctance to identify conditions
adverse to quality relating to organizational, human performance and programs in a CR;
(2) a recurring trend of inadequate CR cause evaluations and corrective actions; (3) a
recurring trend of inadequate, untimely, ineffective and improperly closed corrective
actions; (4) MRB deficiencies; (5) a need for improvement in the trending program; (6)
untimely resolution of issues and supervisory and senior reactor operator reviews; (7)
ineffective corrective action to preclude repetition; and (8) recurring trend of procedure
non-compliance. These and other findings were determined to be consistent with the
root cause analysis reports for CR 02-00891.
To resolve the identified deficiencies and to improve program implementation, the
licensee generated numerous CRs that included recommended corrective actions to
resolve and correct the noted deficiencies. The majority of the CRs from the review
were classified as requiring evaluation and resolution prior to restart, although some
were classified as post restart. Many of the corrective action items were rolled into
CR 02-04884. As part of the corrective actions to address these findings the licensee
determined that training of staff and changes to the program documents were necessary
in order to restore an effective CAP.
Enclosure
28
Assessment of the Corrective Action Program Compliance Review
The CATI team reviewed selected corrective actions to determine the effectiveness of
the licensees implementation of the specified corrective actions. The team determined
the licensees Phase 2 review of the CAP was comprehensive and in accordance with
procedure NG-EN-00385. The team concluded that the CAP appeared to contain many
of the programmatic elements needed for a successful program; however, station
personnel did not consistently identify or effectively resolve plant issues. This was
demonstrated by the team identifying many of the same issues as those identified in the
Phase 2 review.
(2)
Detailed Team Review of Licensee Corrective Actions Implemented to Address
Electrical Issues Previously Identified by NRC or the Licensee
a.
Inspection Scope
The team assessed effectiveness of the licensees CAP to identify, categorize, evaluate,
and resolve the identified equipment, human performance and/or programmatic adverse
to quality plant conditions. The team mainly focused on plant systems design and
licensing basis requirements issues which were previously identified by the NRC, the
licensee and others during various design reviews conducted in 2002. The team
assessed effectiveness of the licensees corrective actions implemented to address
previously identified electrical engineering design issues.
b.
Observations and Findings
.1
Undervoltage Time Delay Relay Setting Did Not Account For Instrument
Uncertainties
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
"Design Control," having very low safety significance (Green). Specifically, the licensee
failed to translate instrument uncertainties into the undervoltage time delay setting
specification for the 4160 Vac buses C1 and D1. Following discovery, the licensee
re-evaluated the potential temperature effects to the time delay relays.
Description: The licensee identified in CR 02-05632 that the time delay relays for the
59 percent undervoltage condition on 4160 Vac buses C1 and D1 may not have met the
allowable value of 0.5 +/- 0.1 seconds contained in technical specification (TS )
Table 3.3-4 because instrument uncertainties were not included. The licensee later
initiated CR 03-01448 to specifically determine if the TS value had been exceeded in the
past. The licensee determined that the primary cause for fluctuations in the time delays
were temperature variations in the room where the relays were located. The licensee
determined that during periods of cool weather, the room would maintain a temperature
of approximately 70 degrees Fahrenheit (F), because the fans in the room would
recirculate air from the turbine building to warm the switchgear room when the fan outlet
temperature dropped below 70F. However, the licensee stated that, during the
summer, the effects on the time delay relays would be insignificant. Specifically,
CR 03-01448 stated, "Only during summer does the room temperatures increase, and
even then it does not typically vary during the day. . . Based upon the operation of the
Enclosure
29
ventilation system, there is very little potential for the relays to experience a significant
temperature rise between the monthly tests."
The team questioned this logic, because it was not apparent that temperature effects,
particularly in the summer when outside temperatures could regularly exceed 90F,
would not affect the time delay relays, especially when past experience, which showed
that some room temperatures could exceed 120F on hot days, was considered. Based
upon the team questions, the licensee re-evaluated the potential temperature effects to
the time delay relays. After performing additional calculations, the licensee determined
that increased temperature could cause the time delay to operate outside of its TS
limits. Also, the licensee determined that in the past, there was at least one occasion
where the temperature in the room was so high that the time delay could have been
outside of its TS allowed value. The team was informed by the licensee that, even if the
allowable value requirement had been exceeded, the additional time delay would have
had negligible effect on the capability to achieve timely emergency core cooling system
(ECCS). As the licensee concluded that the relay would have been able to function
even though it did not meet its TS allowable value, the licensee did not consider the
relay to have been inoperable. The team did not independently verify this conclusion.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to translate instrument uncertainty into the specification for undervoltage
time delay relays for the 4160 Vac buses C1 and D1. Since there was a performance
deficiency, the team compared this performance deficiency to the minor questions
contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection
Reports." The team concluded that the issue was more than minor because this was a
design issue which affected the mitigating system cornerstone. The licensee had to
perform calculations to show that the relays were within the TS allowable values and the
licensee determined that the increased temperature could cause the time delay to
operate outside of TS limits. Although the licensee acknowledged that there had been
at least one occasion where inclusion of instrument uncertainties into the allowable
value would have resulted in an instrument being technically inoperable, the licensee
believed the instrument would still have performed its safety function. Therefore, the
licensee did not consider the instrument to have been inoperable. The team reviewed
this finding in accordance with IMC 0609, "Significance Determination Process, and
answered no to all five screening questions in the Phase 1 Screening Worksheet
under the Mitigating Systems column. The team concluded the issue was of very low
safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to assure that the regulatory requirements and
the design basis of the plant were accurately translated into specifications. Specifically,
the instrument uncertainty was not translated into specification for the undervoltage time
Enclosure
30
delay relays for the C1 and D1 4160 Vac buses. The licensee had previously entered
the issue into its CAP as CRs 02-05632 and 03-01448. Because this violation was of
very low safety significance and because it was entered into the licensees CAP, this
violation is being treated as a NCV, consistent with Section VI.A of the NRC
Enforcement Policy. (NCV 05000346/2003010-03)
.2
Lack of 480 Vac Class 1E Motor Thermal Overload Protection
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to provide
motor thermal overload protection for the Class 1E 480 Vac distribution system.
Following discovery, the licensee physically modified approximately 53 thermal overload
circuits to resolve the discrepancy. The primary cause of this violation was related to
the cross-cutting area of human performance because the licensee did not identify the
lack of thermal overload protection was an unanalyzed condition and that the station
was not in compliance with the updated safety analysis report until identified by the
team.
Description: The team reviewed the design criteria manual for the 480 Vac distribution
system. Section 5.4.3.2, "460V Motors Fed from Motor Control Centers," of this design
criteria stated that, "Starters should be equipped with overload relays to provide motor
overload protection. For Class 1E motor operated valves, dampers, pumps, and fans,
the thermal overload relays should be bypassed to avoid tripping during emergency
conditions." This design criteria contradicted Updated Safety Analysis Report (USAR)
Section 8.3.1.2.11, "Protection Systems," which stated, "Protection systems are
provided and designed to initiate automatically the operation of the appropriate
equipment. Necessary protective devices are provided to isolate failed equipment and
to identify the equipment that has failed. For the protection system related to
engineered safety features and essential functions, complete redundancy,
independence, and inservice testability is maintained."
The team determined that as a consequence of following the design criteria manual
guidance, the licensee had failed to ensure that the 480V Class 1E circuits were
designed so that the protection systems would automatically initiate appropriate
equipment, including motor operated valves, dampers, pumps, and fans, as required by
the USAR.
The team asked the licensee to provide verification that each circuit fed by a Class 1E
480V motor control center which had its overload protection bypassed or inactivated
would be capable of carrying overloads ranging from full load amperes to locked rotor
amperes on a continuous basis, or until interrupted, without exceeding the ratings of the
circuit breaker, the contactor, the bypassed overload device, or the cable. The team
also asked the licensee to assure that when overload protection was bypassed, it did not
result in jeopardizing the safety function, or in degrading other safety systems.
As a result of the team's questioning, the licensee identified that, despite the numerous
programmatic design reviews that were completed, engineering had not identified this
discrepancy and there were many circuits where completion of the safety function could
not be demonstrated due to bypassing the thermal overload protection. An overload
Enclosure
31
condition in a single circuit could result in opening of the upstream circuit breaker to the
bus, thus removing 480V power to all other Class 1E equipment connected to that bus.
The team also identified additional bypassing of thermal overload protection on Class 1E
480V loads, where the design criteria did not allow such bypassing.
The licensee characterized this issue as having "potential for a significant impact on
safety" and wrote numerous CRs to address the issue. Subsequently, the licensee
modified approximately 53 thermal overload circuits as part of the issue resolution.
There was reasonable assurance that the condition did not result in a loss of system
function
During review of this issue, the team also noted an example of an ineffective roll-over in
that some of the concerns identified in CR 03-02616 were rolled over to CR 03-03572
and were not adequately addressed. The team was concerned about this issue
because it had occurred after the licensee had revised its roll-over process to address
concerns expressed by the team earlier in the inspection.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to provide protective devices, such as thermal overloads, for 480V Class
1E circuits as specified in design documents. Since there was a performance
deficiency, the team compared this performance deficiency to the minor questions
contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection
Reports." The team concluded that the issue was more than minor because this was a
design issue which affected the mitigating systems cornerstone. The licensee failed to
ensure that bypassing the thermal overload protection would result in completion of
safety functions and subsequently had to install thermal overload protection in order to
meet the design requirements. The team reviewed this finding in accordance with IMC
0609, "Significance Determination Process, and answered no to all five screening
questions in the Phase 1 Screening Worksheet under the Mitigating Systems column.
The team concluded the issue was of very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis are correctly translated into specifications, drawings, procedures, and
instructions. USAR Section 8.3.1.2.11, "Protection Systems," stated, in part, that,
protective devices are provided to isolate failed equipment and to identify the equipment
that has failed. Furthermore, for the protection system related to engineered safety
features and essential functions, complete redundancy, independence, and inservice
testability is maintained.
Contrary to the above, the licensee failed to correctly translate the design basis into
specifications. Specifically, the licensee failed to provide the necessary protective
devices, such as thermal overload protection for the for 480V Class 1E circuits. The
protection was required to isolate failed equipment and limit fault propagation. The
licensee entered the issue into its CAP as CRs 03-02597, 03-02616, 03-03572,
03-04264, 03-04303, 03-04375, 03-06475, 03-06567 and 03-07031. Because this
violation was of very low safety significance and because it was entered into the
licensees CAP, the violation is being treated as a NCV, consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000346/2003010-04)
Enclosure
32
.3
Failure to Perform Direct Current Contactor Testing to Ensure Minimum Voltage
at Motor Operated Valves
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion XI,
Test Control, having very low safety significance (Green). Specifically, the licensee
failed to adequately test direct current (DC) contactors related to two safety related
motor operated steam valves associated with the AFW system. Following discovery, the
licensee entered the issue into the corrective action program and was re-evaluating the
basis for acceptability of these valves. The primary cause of this violation was related to
the cross-cutting area of problem identification and resolution because, although the
issue was identified in 2002, the licensee did not take corrective action until prompted by
the team in 2003.
Description: The team reviewed CR 01-03059,which documented the issue of minimum
voltage available at two safety related motor operated steam valves associated with the
AFW system. One of the valves was normally closed and was required to be opened
under certain conditions to allow the AFW system to perform its intended function. It
had a cable conductor circuit length of 6,814 feet for the automatic opening function.
The licensees corrective action to the issue was to revise calculation C-EE-002.02-010
to include the valves which had not been previously addressed in the calculation. This
corrective action was implemented in April 2002. In review of the calculation, the team
noted that Attachment 27 of the calculation included the test data used to establish a
minimum voltage for the DC contactors. The team ascertained that the testing was
based on a single device and lacked sufficient basis to conclude that other contactors
would actuate under similar conditions. In addition, the test used an uncalibrated meter
to collect data. The team also noted that no adjustment had been made to factor plant
environmental conditions into the results. The licensee issued CR 03-07069 during the
inspection to document this deficiency in testing methodology.
As a result of the deficiencies in the testing methodology, the team could not conclude
that the valves had sufficient minimum voltage at the component to perform their safety
function. The team also noted that the licensee's evaluation of the team-identified
deficiency was that it was acceptable because of the single failure criteria (i.e., that even
if one valve failed, the other train would be available because the single failure had
already occurred). The team informed the licensee that this appeared to be an
inappropriate application of the single failure criteria.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to ensure proper testing of DC contactors. Since there was a
performance deficiency, the team compared this performance deficiency to the minor
questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor
Inspection Reports." The team concluded that the issue was more than minor because
the licensee had relied upon an inadequate test to demonstrate that the contactors were
qualified to perform under required conditions and because the contactors were installed
in the plant during previous operating cycles. The licensee determined that the valves
had always been operable. This was a design qualification issue which affected the
mitigating systems cornerstone. The team reviewed this finding in accordance with IMC
0609, "Significance Determination Process, and answered no to all five screening
Enclosure
33
questions in the Phase 1 Screening Worksheet under the Mitigating Systems column.
The team concluded the issue was of very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XI 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 procedures. Test procedures shall include
provisions for assuring that all prerequisites for the given test have been met, that
adequate test instrumentation is available and used, and that the test is performed
under suitable environmental conditions.
Contrary to the above, during the testing for establishing a minimum voltage for DC
contactors, the licensee failed to: ensure the components would perform satisfactorily in
service; failed to use adequate test instrumentation; and failed to ensure the test was
performed under suitable environmental conditions. Specifically, the licensee used a
sample size of one DC contactor to justify pick-up voltages of other DC contactors in the
plant. In addition, the licensee used uncalibrated instrumentation and failed to consider
actual plant environment to which the DC contactors would be subject.
The licensee entered the issue into its CAP as CR 03-07069. Because this violation
was of very low safety significance and because it was entered into the licensees CAP,
the violation is being treated as a NCV, consistent with Section VI.A of the NRC
Enforcement Policy. (NCV 05000346/2003010-05)
.4
Failure to Verify Adequacy of Short Circuit Protection for Direct Current Circuits
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion XVI,
"Corrective Action," having very low safety significance (Green). Specifically, the
licensee failed to identify and correct inadequate short circuit protection for DC circuits.
Following discovery, the licensee issued Condition Report 03-06944 to document the
deficient circuit protection for valves having extremely long circuit lengths. The primary
cause of this violation was related to the cross-cutting area of problem identification and
resolution because the licensee had missed several opportunities to identify it as part of
corrective actions for previously identified DC circuit deficiencies.
Description: While reviewing CRs 01-03059 and 02-00412 and calculation
C-EE-002.01-010, the team questioned the adequacy of DC circuit protection for long
DC circuits, such as the one described in Section 4OA3(2)b.3, which had a cable
conductor circuit length of 6,814 feet. Subsequently, the licensee evaluated the
adequacy of the fuse sizing and identified that, in the case of short circuits, the circuit
resistance could be high enough to preclude operation of the fuses protecting circuit,
i.e., the fuses protecting the circuits were oversized for the application. Thus, a short
circuit current could be allowed to flow for an indeterminate length of time. The short
circuit current would only be interrupted after considerable damage had been made to
safety related equipment and could result in damaging fires which could affect
redundant safety related trains. The licensee issued CR 03-06944 to document the
deficient circuit protection for valves having extremely long circuit lengths. Subsequent
to the inspection, the licensee developed an engineering package to replace the fuses in
March 2004. The inspectors reviewed the licensees engineering package and
Enclosure
34
concluded that the projected completion date appears reasonable and commensurate
with the safety significance of the issue.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to verify the adequacy of short circuit protection for DC circuits. Since
there was a performance deficiency, the team compared this performance deficiency to
the minor questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power
Reactor Inspection Reports." The team concluded that the issue was more than minor
because the licensee had to perform calculations to determine if the fuses would
adequately protect the equipment and because modifications to those fuses were
required. This was a design issue which affected the mitigating systems cornerstone.
The team reviewed this finding in accordance with IMC 0609, "Significance Determination
Process, and answered no to all five screening questions in the Phase 1 Screening
Worksheet under the Mitigating Systems column. The team concluded the issue was of
very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XVI requires, in part, that
conditions adverse to quality be promptly identified and corrected.
Contrary to the above, as of August 25, 2003, the licensee did not promptly identify and
correct a condition adverse to quality in that DC circuits were not adequately protected
against short circuits, a condition adverse to quality. Specifically, the licensee missed
several opportunities in 2001 and 2002 to identify that there was no basis ensuring
adequate short circuit protection for DC circuits and did not initiate corrective actions to
ensure that fuse sizing was adequate for long DC circuits such as those for motor
operated valves MV0106 and MV3870. The licensee entered this issue into its
corrective action as CR 03-06944. Because this violation was of very low safety
significance and because it was entered into the licensees CAP, this violation is being
treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy.
.5
Lack of Calculations to Ensure Minimum Voltage Availability at Device Terminals
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to confirm
operability of DC contactors by ensuring that minimum voltage was available at the
safety related device terminals. The licensee missed several opportunities to correct
this design deficiency. Following discovery, the licensee issued Condition Report
03-06956 and evaluated the issue. The primary cause of this violation was related to
the cross-cutting area of problem identification and resolution because, although the
issue was identified in 2002, the licensee failed to take appropriate corrective action to
thoroughly evaluate the problem until prompted by the team in 2003.
Description: As a part of CR 01-03059, the licensee performed an extent of condition
evaluation and identified that the DC voltages in calculation C-EE-002.01-010 evaluated
available voltage to the panel terminals only. The calculation did not confirm sufficient
voltage at device terminal for proper operation. The licensee issued CR 02-00412 to
document this deficiency. In response to this CR, the licensee issued a revision to the
calculation.
Enclosure
35
During review of calculation C-EE-002.01-010, the team determined that the lowest
voltage was 106.38V, which would occur during the first one minute discharge period.
The calculation was potentially non-conservative because it failed to address resistance
of contacts and fuses which would contribute to additional voltage drop in the circuits.
Conservatism existed in the calculation since all loads were assumed to run
continuously and simultaneously during the first minute of battery discharge. Additional
conservatism was identified during service testing of the battery with the plant
anticipated loads. Nevertheless, the team could not conclude that the conservatism was
sufficient to bound the undetermined voltage drop in part of the circuits. Therefore, it
was not known whether the device terminal voltage present under the design basis
conditions would be sufficient to ensure proper operation of safety related devices.
Upon determination that the actual voltage at the devices had not been evaluated in the
calculation, the licensee identified a potential SCAQ because potential operability
concerns were raised that could have affected numerous pieces of safety related
equipment, the licensee did not take actions to ensure operability. Specifically, the
licensee did not have a documented basis for resolving the operability concern for
equipment which might not have sufficient voltages to ensure proper operation. The CR
stated that, "preliminary reviews indicate that there are no operability concerns" and the
due date for the corrective action to evaluate the loads connected to the panels was
assigned as a post-restart action. After the operability issue was raised by the team, the
licensee issued CR 03-06956 for the lack of basis for deferring corrective action. The
licensee performed additional analysis and extent of condition reviews. The licensee
determined that there were no operability issues based on the results of the re-analysis.
The team reviewed these re-analyses and concluded there is reasonable assurance that
the affected components are operable.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to ensure the availability of minimum voltage at the safety related device
terminals. Specifically, the licensee had not performed design analyses or calculations
to demonstrate that end devices would have sufficient voltage available to perform the
design function. Since there was a performance deficiency, the team compared this
performance deficiency to the minor questions contained in Appendix B, "Issue
Screening," of IMC 0612, "Power Reactor Inspection Reports." The team concluded
that the issue was more than minor because the licensee had to perform calculations to
demonstrate that the devices had sufficient voltage to perform their safety function.
Based on the evaluation performed as a corrective action to CR 03-06956, the team had
reasonable assurance that affected components were operable. This was a design
issue which affected the mitigating systems cornerstone. The team reviewed this
finding in accordance with IMC 0609, "Significance Determination Process, and
answered no to all five screening questions in the Phase 1 Screening Worksheet
under the Mitigating Systems column. The team concluded the issue was of very low
safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis are correctly translated into specifications, drawings, procedures, and
instructions. measures be established to assure that applicable regulatory requirements
and the design basis were correctly translated into specifications, drawings, procedures,
Enclosure
36
and instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee had failed to ensure that minimum voltage would be
available at the safety related device terminals. The calculation performed by the
licensee did not confirm that sufficient voltage would exist at the device terminals for
proper operation of safety related components during design basis events. The licensee
issued CR 03-06956 to address this deficiency. Because this violation was of very low
safety significance and because it was entered into the licensees CAP, this violation is
being treated as a NCV consistent with Section VI.A of the NRC Enforcement Policy.
.6
Raychem' Splice Removal on Containment Air Cooler Motor Cables
Introduction: The team identified a performance deficiency involving the failure to
properly remove Raychem' splices during the CACs motor replacement. Following
discovery, the licensee entered the issue into its corrective action process. After NRC
identified the cause of the condition, the licensee took corrective actions. This was a
minor violation.
Description: During CAC motor replacement, the licensee identified splitting of the
motor cable insulation as documented in CR 02-05459. The cable jacket and insulation
to the three CAC motor high speed windings were found to be split at the ends which
were normally covered by Raychem' heat shrink sleeves. The damage was observed
after the Raychem' sleeves were removed for de-terminating the motors. In 2002, the
NRC examined this issue and concluded that the CAC cable had apparently been cut by
a sharp instrument, rather than the result of an aging or contamination related
mechanism as initially assumed by the licensee. The NRC determined that the splitting
was in fact a deep gash and the licensee subsequently determined the gash was
inflicted by a contractor when removing the Raychem' sleeves with a knife. To
address this concern, the licensee initiated work orders to replace the section of the high
speed cable of the three CAC motors between the motor and the penetrations with an
equivalent cable. The work procedures were revised, and the workers received training
on the revised procedures.
The approved method for removal of Raychem' sleeves was prescribed in
maintenance procedure DB-ME-09500, "Installation and Termination of Electrical
Cables," which required that Raychem' sleeves be removed by lightly scoring the
sleeve with a knife and then applying heat to remove the sleeve. During the licensee
investigation of the issue, the contractor performing this activity stated that he was not
trained on the Raychem' removal technique and was not aware of the applicable
procedure. However, the licensees cause analysis determined that the contractor
performing the task had been trained and qualified. Nevertheless, the contractor did not
perform the Raychem' sleeve removal in accordance with appropriate and applicable
procedures. At the time of the inspection, the team noted that the licensee had not
documented whether an extent-of-condition review was performed to determine if other
maintenance activities were incorrectly performed. On March 2, 2004, the licensee
Enclosure
37
informed the team that the individual had not removed any other Raychem' splices in
the past and the subject work activity was limited to this individual only.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to follow the maintenance procedure for removing Raychem' sleeves.
Since there was a performance deficiency, the team compared this performance
deficiency to the minor questions contained in Appendix B, "Issue Screening," of IMC
0612, "Power Reactor Inspection Reports." The team concluded that the issue was
minor because it was identified while the system was out of service, and it was corrected
before the system was returned to service.
Enforcement: The failure to follow the maintenance procedure for removing Raychem'
sleeves constituted a violation of 10 CFR Appendix B, Criterion V, which has minor
significance and is not subject to enforcement action in accordance with Section IV of
the NRCs Enforcement Policy. The licensee entered the issue into its CAP as
CR 02-05459.
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case since the licensee had not
documented whether any extent-of-condition review had been performed and the
underlying cause is similar to that of other findings in this report.
.7
Review of Calculation on the Electric Transient Analysis Profile
Introduction: The team reviewed ETAP calculation C-EE-015.03-008, Revision 2, to
evaluate technical adequacy.
Description: A third revision to the calculation was under way during the inspection and
was not scheduled to be completed until after the inspection was over. The fact that the
licensee was continuing to revise the calculation hampered the team's overall ability to
assess its acceptability. However, the calculation appeared to be generally well
performed and did successfully resolve a multitude of issues. The licensee also
performed a very good self-assessment with an industry group comprised of outside
independent consultants. However, the team considered the ETAP calculation
development to be very slow in regards to implementation of corrective actions. For
example, changes in auto transfer functions and the EDG calculation which were
completed in January 2003 had not yet been incorporated into the main ETAP
calculation. The team also observed that the calculation was performed by contractors
and that the licensee's internal knowledge of the calculation appeared limited.
Analysis: As a minor issue, the team noted that procedure NOP-CC-3002 required that
calculations be entered into the calculation database prior to issuing of a new revision.
However, the team identified that document control was not notified upon issuance of a
new revision to calculation C-EE-015.03-008 (Revision 2).
Enforcement: The failure to enter the revision of a procedure into the database prior to
its issuance 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 documented the issue in CR 03-06989.
Enclosure
38
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case it represented an example
of calculation weakness and the underlying cause is similar to that of other findings in
this report.
.8
Inadequate Grid Voltage Calculations
Introduction: The team identified that the licensee failed to consider the worst case grid
voltages in the short circuit analyses. Following discovery, the licensee entered the
issue into their corrective action program and performed new calculations to address the
issue.
Description: The licensee initiated CR 02-06302 to document that the licensee had not
considered the worst case grid voltage. This CR described the issue as being
administrative in nature and having no effect on the results. This conclusion was
incorrect and was so recognized in CR 02-06837.
The team ascertained that the maximum grid voltage was an important parameter which
affected the accuracy of the short circuit calculations. The postulated short circuit
current would proportionally increase for higher grid voltage, therefore, calculations
performed for lower grid voltages would be non-conservative. The team reviewed this
item and determined that calculation C-EE-015.03-003 was superseded with calculation
C-EE-015.03-008, which utilized the ETAP program described in Section 4OA3(2)b.7.
The new calculation had taken into account the worst grid voltage conditions.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to analyze the grid voltage under worst case design conditions. Since
there was a performance deficiency, the team compared this performance deficiency to
the minor questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power
Reactor Inspection Reports." The team concluded that the issue was minor because
although the licensee had to perform calculations, the new calculation had taken into
account the worst grid voltage conditions and the results were acceptable.
Enforcement: The failure to translate the worst case grid voltage into calculations of
record constituted a violation of 10 CFR Appendix B, Criterion III, which has minor
significance and is not subject to enforcement action in accordance with Section IV of
the NRCs Enforcement Policy. The licensee entered the issue into its CAP as
CRs 02-06302 and 02-06837.
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case it represented an example
of calculation weakness and the underlying cause is similar to that of other findings in
this report.
Enclosure
39
(3)
Detailed Team Review of Licensee Corrective Actions Implemented to Address
Mechanical Issues Previously Identified by NRC or the Licensee
a.
Inspection Scope
The team assessed effectiveness of the licensees CAP to identify, categorize, evaluate,
and resolve the identified equipment, human performance or programmatic adverse to
quality plant conditions. The team mainly focused on plant systems design and
licensing basis requirements issues which were previously identified by the NRC, the
licensee and others during various design reviews conducted in 2002. The team
assessed effectiveness of the licensees corrective actions implemented to address
previously identified mechanical engineering design issues.
b.
Observations and Findings
.1
High Pressure Injection Pump Operation Under Long Term Minimum Flow
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to verify
that the HPI pumps could operate under design basis minimum flow requirements since
initial plant startup. Following discovery that the design basis minimum flow
requirements were significantly below industry standards, the licensee entered the issue
into its corrective action program, performed a test which demonstrated satisfactory
pump operation for an extended period of time at a higher flow rate, and began the
steps to change the design basis minimum requirement. The primary cause of this
violation was related to the cross-cutting area of corrective action because although this
issue was identified by the NRC in Information Notice (IN) 87-59, "Potential RHR Pump
Loss," in 1987 and in Bulletin 88-04, "Potential Safety-Related Pump Loss," in 1988, the
licensee failed to take action to correct it until it was specifically identified as applying to
Davis Besse during the SSDI in 2002, and yet again during the CATI in 2003.
Description: On November 17, 1987, the NRC issued an information notice describing
two concerns identified by a Nuclear Safety System Supply vendor which had the
potential to impact safety operation of ECCS pumps. Specifically, IN 87-59 described
two concerns, the second of which involved the adequacy of the minimum flow
recirculation line capacity even for single pump operation. The IN noted that the vendor
specifically stated that these concerns might also be applicable to high pressure safety
injection pumps. On May 5, 1988, the NRC followed the IN with an NRC Bulletin
addressing the same concerns. Item 3 of the bulletin requested that licensees evaluate
the adequacy of the minimum flow bypass lines for safety-related centrifugal pumps with
respect to damage resulting from operation and testing in the minimum flow mode. It
stated that the evaluation should include consideration of both the effects of cumulative
operating hours in the minimum flow mode over the lifetime of the plant and during the
postulated accident scenario involving the largest time spent in the minimum
recirculation flow mode. It also requested that the evaluation include verification from the
pump suppliers that current minimum flow rates were sufficient to ensure that there will
be no pump damage from low flow operation.
Enclosure
40
During the SSDI, the NRC reviewed the HPI pump minimum flow capacity and raised
two concerns related minimum flow and no flow conditions. The NRC determined that
the adequacy of the minimum recirculation flow value of 35 gallons per minute (gpm)
was questionable and that there was a potentially unanalyzed condition during a small
break loss of coolant accident (LOCA). For certain small break LOCAs, the NRC
determined that the HPI pumps potentially could be required to operate under conditions
where the reactor coolant system (RCS) pressure would be very close to or possibly
greater than the pressure under which the HPI pumps could inject. During the
recirculation phase, after the contents of the borated water storage tank (BWST) were
injected, the return line to the BWST was procedurally required to be manually isolated
from the control room to prevent an unmonitored release of radiation. The HPI pumps
had a defined mission time of 30 days (720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />) where the pumps were required to
remain operable. The licensee issued CRs 02-07684 (for the adequacy of the 35 gpm)
and 02-06702 (on the potentially unanalyzed lack of flow condition) to evaluate these
concerns.
The licensee resolved the issue of not having a minimum flow recirculation path during
the sump recirculation phase by implementing a modification to provide a new minimum
recirculation flow path for the HPI pumps via a connection through the decay heat
removal (DHR) injection line. This modification was designed to the same 35 gpm flow
rate as the original recirculation line because, in evaluating CR 02-07684, the licensee
concluded that the 35 gpm was adequate. During the 2003 CATI, the team again
questioned the adequacy of the 35 gpm minimum flow, especially in light of the 1988
Bulletin. Although the licensee had not reviewed the Bulletin response as part of their
evaluation of CR 02-07684, they resurrected the document in response to team
questions. The team determined that the licensees response to the Bulletin was based
on the results from three 10-minute vibration runs; these tests showed no appreciable
increase in vibration. The licensee also had contacted the pump vendor, who was
unable to confirm that the 35 gpm flow was adequate to ensure that HPI pumps would
not experience degradation as a result of hydraulic instability or impeller recirculation.
The team noted that industry experience indicated that long term pump minimum flow
value should be close to 25 percent of flow at the pumps best efficiency point. For the
HPI pumps, the flow at the best efficiency point was 600 gpm, which would indicate that
a minimum flow on the order of 150 gpm would be appropriate as compared to the 35
gpm which was in the licensee's design specification at the time of the inspection.
In response to the team again raising the issue on the adequacy of the HPI pump
minimum flow value of 35 gpm, the licensee wrote CRs 03-06526 and 03-06519. As
part of the investigation summary in CR 03-06526, the licensee provided evaluations by
three pump experts. These evaluations appeared to only justify continued operation
based on the effects of cumulative operating hours in the minimum flow mode over the
experienced lifetime of the plant. The team was unable to find any evaluation of the
ability of the HPI pumps to function on minimum flow during the licensee's stated
mission time of 30 days; this included any evaluation by the licensee that a shorter
mission time was appropriate for operating entirely on minimum flow. The team noted
that this issue was assigned a priority of "CF" which meant that the licensee did not
believe that any cause evaluation was required, just that the issue had to be resolved.
The licensee's basis for designating the CR as a "CF" was that the pump only had to
operate "occasionally" in the minimum flow configuration - which did not recognize the
Enclosure
41
pumps safety function. At the end of the on-site inspection, the licensee was still
evaluating the issue.
In December 2003, the team performed a limited review of the licensees evaluation of a
test performed on one of the HPI pumps. This test was run for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> at a flow of 53
gpm. The basis for establishing a test duration of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> appeared to be that the pump
shaft would experience a million cycles of operation and that, if pump failure was going
to occur, it should occur within that time period. However, the licensee did not either
extrapolate the number of cycles to the stated mission time of 30 days nor did they
provide any basis statement as to why 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> would be the maximum time that the
pump would spend on minimum flow. The basis for establishing the flow of 53 gpm was
that it was the actual flow through the installed orifice. However, the licensee did not
extrapolate the flow back to the design basis minimum or take steps to change the
design basis. While it was highly unlikely that the pump would experience flows below
the 53 gpm for the current orifice, the team noted that this test was run on only one of
four recirculation lines (including the two new ones installed during the 13th refueling
outage). The team noted that the newly installed lines had throttle valves which could
be adjusted to a flow rate anywhere in the acceptance criteria band, including a value
well below the demonstrated flow rate. The team also noted that the surveillance test
data for the 1-2 HPI pump (the one not tested) showed the recirculation flow rates on
this pump were closer to the high end of the acceptance criteria band where the
licensee was supposed to evaluate replacement of the orifice.
As a result of the teams questions, on February 8, 2004, the licensee provided an
operability determination which addressed pump operability under the design conditions.
The licensee concluded that the HPI pumps are capable of providing the necessary flow
over the mission time of 30 days with extended periods at minimum recirculation flow.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to demonstrate that the pump could successfully perform its safety
function for the stated mission time of 30 days and under the initial design minimum flow
rate of 35 gpm by either test or evaluation prior to 2004. Since there was a performance
deficiency, the team compared this performance deficiency to the minor questions
contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection
Reports." The team concluded that the issue was more than minor because the
licensee had to perform a test to demonstrate that design basis requirements could be
met and because the test results determined that the design basis requirements needed
to be changed to ensure that the HPI pumps could perform their accident required
function. This was an issue which affected the mitigating systems cornerstone. The
team reviewed this finding in accordance with IMC 0609, "Significance Determination
Process. Although the pumps had not been tested at the minimum design flow valve,
the team was unable to conclude that the safety function of the pumps had actually
been lost. This was based on a review of surveillance test results from June 2001
through December 2003. These test results showed the lowest flow rate for either pump
to be 49 gpm. Although this was slightly outside the licensee's new operability band, the
team deemed it likely that the pumps would have performed had they been called upon.
Therefore, the team answered no to all five screening questions in the Phase 1
Screening Worksheet under the Mitigating Systems column. The team concluded the
issue was of very low safety significance (Green).
Enclosure
42
The performance deficiency of not having any recirculation lines once the BWST
emptied is addressed in Section 4OA3(6)b.3.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to verify the adequacy of the design of the
minimum recirculation line flow rate of 35 gpm. Specifically, on December 23, 2003, the
licensee determined that the minimum flow rate of 35 gpm could not be verified and the
minimum value which had been verified by a suitable testing program was 53 gpm.
Because this violation was of very low safety significance and because it was entered
into the licensees CAP as CRs 03-11268, 03-11431 and 04-01050, this violation is
being treated as an NCV consistent with Section VI.A of the NRC Enforcement Policy.
.2
Increased Dose Consequences Due to Degraded Thermal Performance
Operation of Degraded Containment Air Coolers
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance. Specifically, the licensee failed to assess an
increase in the offsite dose to the public following a postulated design basis accident
due to increased containment pressure. Following discovery, the licensee entered the
issue into its corrective action process and performed the necessary analysis. The
primary cause of this violation was related to the cross-cutting area of problem
identification and resolution, because, although the issue had been previously identified,
the licensee had failed to identify that a revised dose assessment was needed until
prompted by the NRC.
Description: In 2002, the licensee identified that the CACs were significantly degraded
and required replacement. In December 2002, the licensee issued LER
05000346/2002-008-00, which discussed the degradation. During the review of
CR 03-00120 and LER 05000346/2002-008-00 and -01, the team noted that the issue of
potentially increased offsite doses due to the degraded CACs was not addressed with a
technical basis in the evaluation of CR 03-00120. In particular, the time to reach half
containment design pressure after a design basis LOCA increased from 16.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> to
58.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> because of degraded CAC performance. The specified acceptance criteria
was that the containment pressure be reduced to 50 percent of the containment design
pressure within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as recommended by Regulatory Guide 1.4, "Assumptions
Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant
Accident for Pressurized Water Reactors." The analyses performed for the degraded
CAC operability assessment did not meet this requirement. However, the licensee
concluded in CR 03-00120 that exceeding the half containment design pressure rating
within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> had no impact on dose consequences analyzed in accordance with
Regulatory Guide 1.4 assumptions, without documenting any basis for the statement.
Enclosure
43
When first questioned by the team, the licensee acknowledged that there was no formal
dose assessment to support the conclusion documented in CR 03-00120. The licensee
then performed a calculation which indicated that, although the offsite radiological doses
increased, they were still less than the Regulatory Guide 1.4 allowables when
accounting for the increase in containment pressure. The team did not review this
calculation.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to verify that increased containment pressure due to degraded CAC
performance would not result in unacceptable offsite dose consequences. Since there
was a performance deficiency, the team compared this performance deficiency to the
minor questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power
Reactor Inspection Reports." The team concluded that the issue was more than minor
because the licensee had to perform calculations to show that the increased time at
higher containment pressures did not result in doses being above regulatory guide
allowables. The team reviewed this finding in accordance with IMC 0609, "Significance
Determination Process.
The team reviewed the SDP questions for reactor safety, occupation radiation safety
and public radiation safety contained in MC 0612, Appendix B, Issue Screening. The
team assessed the finding through Phase 1 of the SDP. According to the Davis-Besse
Risk-informed Inspection Notebook, the CACs had both a barrier integrity and mitigating
system cornerstone function. However, the team determined that the issue was not
covered by any of the revised oversight cornerstones and was not suitable for SDP
analysis since the finding pertained to offsite dose calculations rather than CAC
performance. Therefore, this finding was reviewed by Regional Management, in
accordance with IMC 0612. The finding was determined to be of very low safety
significance (Green) because the issue regarded increased containment pressure,
related to offsite dose consequences, and although the offsite radiological doses
increased, the values were still less than the Regulatory Guide 1.4 allowables.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to implement design control measures to
verify the adequacy of design basis calculations. Specifically, the licensee failed to
demonstrate that increased containment pressure due to degraded CAC performance
did not result in unacceptable offsite dose consequences. The licensee entered this
issue into its CAP as CR 03-03980. Because this violation was of very low safety
significance and because it was entered into the licensees CAP, this violation is being
treated as an NCV consistent with Section VI.A of the NRC Enforcement Policy. (NCV
Enclosure
44
.3
Containment Air Cooler Air Flow Calculation Concerns
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to correctly
identify and translate the design basis requirements into the CACs airflow analyses and
motor horsepower sizing calculations. Following discovery, the licensee entered the
issue into its corrective action program and performed a new analysis for the motor.
The primary cause of this violation was related to the cross-cutting area of problem
identification and resolution as the licensee had previously identified issues with the
motors, but had not reviewed the design calculation of record.
Description: During review of CR 03-00120, which was the licensees collective
significance review in regard to the degraded condition of the CACs, the team also
reviewed calculation 28.003. This calculation was used to size the existing CAC motor.
The team determined that the calculation was performed in 1970 and applied design
information from the Oconee Nuclear Power Plant to Davis-Besse without correction for
actual Davis-Besse conditions. The NRC team questioned the design values for system
resistance, airflow, and density used in the calculation for sizing CAC motors since there
was no reference to Davis-Besse equipment or systems.
Calculation 28.003 specified a requirement for a 45 horsepower motor, whereas at
Davis-Besse, a 40 horsepower motor was actually installed. In addition, the density
used in calculation 28.003 was different than that used for the postulated breaks
analyzed in calculation C-NSA-060.05-010. For example, C-NSA-060.05-010, the
computed density profile remained at or below 0.132 pounds per cubic foot (lb/ft3) for
the first 6 seconds, increased to 0.152 lb/ft3 from 7 to 16 seconds, then dropped to
0.132 lb/ft3 at approximately 250 seconds. In contrast, calculation 28.003 used the less
conservative density profile of 0.132 lb/ft3 throughout. Following the teams questioning,
the licensee performed a new calculation which showed that the CAC motors were
appropriately sized.
The team also noted that the vendor who supplied the CAC motors had submitted a
Part 21 notice to the licensee in May 2002. According to LER 05000346/2002-008, this
issue was entered into the CAP but was determined to not be of significance due to the
CAC motors being refurbished as part of the overall CAC refurbishment. The team
considered this to be an example of poor engineering response to an issue specifically,
the licensee had determined that the CAC motors needed to be refurbished, but had
either not looked at the design basis calculation for the motors prior to beginning the
refurbishment, or had not performed an adequate review.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to analyze CAC fan sizing with respect to actual airflow, air density,
pressure drop, and motor size. Since there was a performance deficiency, the team
compared this performance deficiency to the minor questions contained in Appendix B,
"Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The team
concluded that the issue was more than minor because the licensee had to revise the
associated calculation to evaluate the existing motor to ensure the CACs would be able
to perform their design function. The team assessed the finding through Phase 1 of the
SDP. According to the Davis-Besse Risk-informed Inspection Notebook, the CACs had
both a barrier integrity and mitigating system function. The team determined that this
Enclosure
45
issue affected both functions. Because the issue involved both the mitigating system
and barrier integrity cornerstones, the team entered Phase 2 of the reactor safety SDP.
The team completed the Phase 2 worksheets for the following scenarios: Transients,
Transients with Loss of the Power Conversion System, Small LOCA, Loss of Offsite
Power (LOOP), Steam Generator (SG) Tube Rupture (SGTR), Main Steam Line Break
(MSLB), Loss of Instrument Air, Loss of a 4 kilovolt (kV) Bus, Loss of DC Buses D1P
and D2P and Loss of One Emergency AC Train. Completion of these worksheets
resulted in two sequences rated as "12", three sequences rated as "11", four sequences
rated as "10", two sequences rated as "9", and three sequences rated as "8". This
information was entered into the "Counting Rule Worksheet" and a final evaluation was
obtained that the issue was of very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to this requirement, the licensee failed to correctly translate the design basis
into specifications, drawing, procedures, and instructions. Specifically, the licensee
failed to correctly identify and translate the design basis requirements such as actual
airflow, air density, pressure drop, and motor size, into the CAC airflow analyses and
motor horsepower sizing calculations that demonstrated the ability of the safety-related
CACs to deliver the required design basis air flow rate to the containment during an
accident. The licensee entered this issue into its CAP as CR 03-07009. Because this
violation was of very low safety significance and because it was entered into the
licensees CAP, this violation is being treated as an NCV consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000346/2003010-10)
.4
Accumulator Sizing Calculation Errors
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to
implement effective design control measures to check and verify the adequacy of the
design basis calculation performed for sizing the new accumulators used to hold the SW
containment isolation valves closed on a loss of instrument air. Following discovery, the
licensee entered the issue into its corrective action program, revised the calculations,
and changed the accumulator medium from compressed air to nitrogen.
Description: In 2002, SSDI team identified a NCV for failing to correctly translate the
design basis requirements for sizing of the safety-related backup air supplies for
containment isolation valves SW-1356, SW-1357, and SW-1358 into the design. The
licensees corrective action was to install new accumulators sized to hold the valves
closed. The team reviewed several revisions of calculation C-ME-011.06-007 which
sized the new accumulators.
Enclosure
46
The team identified numerous errors in the calculation which required the calculation to
be revised. For example, in Revisions 0 and 1 of the calculation, the new accumulators
were intended to be filled with air as the licensee thought the valves only had to remain
closed for 30 minutes. The licensee initially did not appear to recognize that the valves
had a containment isolation design function which required the valves to remain closed
for 30 days until questioned by the team during the inspection. Following the teams
questions, the licensee changed the design to require that the new accumulators be
filled with nitrogen rather than air. In the last revision reviewed, the calculation
erroneously used the ideal gas law equations when sizing the nitrogen bottles without
consideration of the compressibility of nitrogen at a pressure of 2000 pounds per square
inch (psig). The calculation also indicated that the valve actuators were double acting
when other documents indicated that actuators were single acting. Additionally, the
calculation could not stand alone without recourse to the author because certain
calculation steps were missing. The licensee revised the calculation to correct the
errors identified by the team. The team noted that the licensee was addressing past
operability of the accumulators separately as part of LER 05000346/2003-001. This
LER will be addressed in a separate IR.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to verify the adequacy of the design basis calculation performed for
sizing the accumulators prior to approving the calculation. Since there was a
performance deficiency, the team compared this performance deficiency to the minor
questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor
Inspection Reports." The team concluded that the issue was more than minor because
the licensee had to re-perform calculations and had to change the modification design
from having accumulators containing pressurized air to accumulators containing
pressurized nitrogen. The team reviewed this finding in accordance with IMC 0609,
"Significance Determination Process.
The team reviewed the SDP questions for reactor safety, occupation radiation safety
and public radiation safety contained in MC 0612, Appendix B, Issue Screening. The
team assessed the finding through Phase 1 of the SDP. However, the team determined
that the issue was not covered by any of the revised oversight cornerstones and was,
therefore, not suitable for SDP analysis. This determination was based on the issue
affecting containment isolation valves which provide a barrier to breach of containment
and potential offsite dose consequences. Therefore, this finding was reviewed by
Regional Management, in accordance with IMC 0612. The finding was determined to be
of very low safety significance (Green) because the issue regarded increased
containment pressure and related to offsite dose consequences.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Enclosure
47
Contrary to the above, the licensee failed to implement design control measures to
check and verify the adequacy of the design basis calculation performed for sizing the
accumulators used to hold containment isolation valves closed on a loss of instrument
air. The licensee entered the issue into its CAP as CR 03-06556. Because this violation
was of very low safety significance and because it was entered into the licensees CAP,
this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC
Enforcement Policy. (NCV 05000346/2003010-11)
.5
Inadequate Blowdown Provisions for Containment Isolation Valve Accumulators
Introduction: The team identified a performance deficiency involving the licensee's
failure to initiate a CR or to implement corrective actions to address a previously
identified NRC finding. Following discovery, the licensee entered the issue into its
corrective action program.
Description: Non-Cited Violation 05000346/2002014-01b was issued by the NRC during
the 2002 SSDI to document that there were no provisions to blow down the SW
containment isolation valve accumulators although USAR Section 9.3.1.5 stated that the
accumulators contained a provision to allow removal of excessive moisture. IR
54-346/2002014 documented that this NCV was captured in the licensee's CAP as
CR 02-07750. When the CATI team reviewed CR 02-07750, the team determined that
the CR did not document this concern. The licensee was unable to identify any CR
which addressed the NCV and could not find any indication that corrective actions had
been taken to address the issue.
The valves discussed in the NCV were containment isolation valves equipped with
backup air accumulators (air volume tanks). These valves had dual safety functions in
that they were required to open during a LOCA to provide maximum SW flow through
the CACs as well as being required to close to provide containment isolation. The team
noted that, although the licensee was in the process of designing the new accumulators,
they had not specifically considered or addressed providing accumulator blowdown
capability. The failure to include blowdown provisions meant that any moisture intrusion
into the accumulator would not be identifiable and would not be removable. This would
result in the reduction in the amount of air available to maintain the containment
isolation valves closed and would result in rust and other debris in the accumulator.
In response to the teams finding, the licensee issued CR 03-02475 on March 28, 2003,
to document this concern and ensure that it was included in the Davis-Besse CAP. The
licensee informed the team that MOD 99-0039, Revision 1 should address this concern,
when completed. In November 2003, the team reviewed the corrective actions
generated for CR 03-02475 and determined that the specified modification had been
canceled and a new modification package generated. Based on the wording in the
corrective action cancellation, it was not apparent that the blowdown issue was
reassessed as part of the new modification.
The team independently determined that, due to the change in accumulator medium
from air to nitrogen, that there was no longer any need for blowdown provisions. While
the NRC concluded that the lack of blowdown no longer presented a safety issue.
Enclosure
48
Analysis: The team determined that a performance deficiency existed because the
licensees program required it to initiate a CR and implement corrective actions to
address NRC identified NCVs. Since there was a performance deficiency, the team
compared this performance deficiency to the minor questions contained in Appendix B,
"Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The team
concluded that the issue was minor because the licensee changed the accumulator
medium to one which would not contain moisture, such that the failure to take corrective
actions had no consequences.
Enforcement: The failure to take corrective actions for an identified condition adverse to
quality constituted a violation of 10 CFR Appendix B, Criterion XVI, which has minor
significance and is not subject to enforcement action in accordance with Section IV of
the NRCs Enforcement Policy.
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case due to the issue not initially
being in the CAP and then due to the corrective actions being canceled without
reconciliation of the original issue. Additionally, the underlying cause is similar to that of
other findings in this report.
.6
Non-conservative Calculation Used in Design Analysis to Determine Required
Service Water Makeup Flow to Component Cooling Water
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance. Specifically, the licensee failed to consider worst
case minimum pressure differential between SW and component cooling water (CCW)
systems when determining required SW makeup flow to the CCW system heat
exchangers. Following discovery, the licensee entered the issue into its corrective
action process and performed the necessary calculations. The primary cause of this
violation was related to the cross-cutting area of human performance because the
licensee used test data collected during normal operation rather than taking the worst
case design conditions and because there was a lack of rigor in the calculation review
process.
Description: Hydraulic calculation C-ME-011.01-140 was developed as part of a
corrective action to CR 02-07378. This calculation determined the pressure differential
required in the SW line for makeup to the CCW system to create a minimum flow of
30 gpm. This flowrate was used to estimate the stay time and exposure rate while using
SW to makeup to the CCW system. The NRC team reviewed the calculation, and
determined that it was non-conservative in that it did not consider worst-case minimum
pressure differential between SW and CCW systems during accident conditions, but
used test data collected during normal operation. In addition, the calculation assumed a
fully turbulent fouling factor for clean piping. Finally, there was a minor math error in the
calculation. Although the math error did not appreciably affect the results of the
calculation, it indicated a lack of rigor in the calculation review process. In response to
the NRC's questions, the licensee performed additional calculations. The licensee
stated that these new calculations showed that, even with the lower predicted differential
pressures while in the accident alignment, the makeup capability of SW to CCW
Enclosure
49
exceeded the acceptance criteria. The team did not review these additional
calculations.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to verify the adequacy of the design basis calculation performed for the
SW and CCW system interface. Since there was a performance deficiency, the team
compared this performance deficiency to the minor questions contained in Appendix B,
"Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The team
concluded that the issue was more than minor because the licensee had to perform a
new calculation to demonstrate that the SW flow to CCW was adequate to perform its
design function. This finding was considered a design deficiency which affected the
mitigating systems cornerstone. The licensee determined that the SW flow was
adequate to perform its design function and was operable The team reviewed this
finding in accordance with IMC 0609, "Significance Determination Process, and
answered no to all five screening questions in the Phase 1 Screening Worksheet
under the Mitigating Systems column. The team concluded the issue was of very low
safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to implement design control measures to
check and verify the adequacy of the design basis calculation performed for the
SW/CCW system crosstie hydraulic analyses for all postulated accidents. The licensee
entered the issue into its CAP as CR 03-04010. Because this violation was of very low
safety significance and because it was entered into the licensees CAP, the violation is
being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy.
.7
Calculation Concerns for Service Water Pump Room Ventilation System
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to verify the
adequacy of the design of the SW pump room ventilation system. Following discovery
that the design basis calculations were non-conservative, the licensee entered the issue
into its corrective action program, re-performed the calculations, and made appropriate
modifications to correct the issues. The primary cause of this violation was related to
the cross-cutting area of problem identification and resolution because the licensee
failed to correct all of the originally identified issues until identified by team.
Description: During the SSDI inspection in 2002, the NRC identified a concern
regarding calculation 67.005. The calculation analyzed the heat loads in the SW pump
room and the ability of the ventilation system to maintain the pump room temperatures
within a required operating range. The team determined that the calculation contained
Enclosure
50
multiple non-conservative attributes, including failing to analyze heat loss through open
penthouse louvers during the winter, and failing to account for heat load contribution of
diesel driven fire pump during the summer. The licensee initiated CR 02-07188 to
document this issue.
The calculation was revised to address these concerns and was issued as Revision 4 in
early 2003. At the same time, another CR, 02-08281, was issued because
CR 02-07188 failed to do an extent of condition review to verify the adequacy of the SW
ventilation system for all operating conditions. The extent of condition review was
reported to have included a walkdown of the SW pump room and review of the revised
SW ventilation calculation.
Upon review of the revised calculation in 2003, the team noted that the summer
maximum analyzed temperature in the pump house did not include the heat load
contribution of the diesel driven fire pump, which was one of the deficiencies noted in
the earlier revision to the calculation. This deficiency was not addressed in the new
revision to the calculation, either by including it or by providing a rationale for excluding
the heat load. The team noted that the licensee had previously had to take actions to
open the diesel generator room doors and provide alternate ventilation during the
summer months. The new calculation also concluded that the penthouse louvers had to
be modified (blocked) for winter operation. The NRC team noted that past operability
had been assured for winter operation by regularly recording pump room ambient
temperature.
Calculation C-NSA-085.00-002, Auxiliary Steam Blowdown in the Intake Structure,
concluded that the maximum temperature within the SW pump room was 109
degrees F. This temperature was not considered a significant difference from the
normal operating temperature in the room. Additionally, the safety related equipment in
the room was specified for operation in an environment with 100 percent relative
humidity, which would be experienced in the room during a postulated steam break. An
evaluation performed in CR 02-05262 concluded that the amount of condensing
moisture would fill the smallest electrical junction box by only 0.05 inches. Therefore,
the functionality of the cables and connections was not likely to be affected. The team
also noted that the licensee had initiated engineering change request (ECR) 02-0682 to
remove the auxiliary steam line from the SW pump room, although it stated that this
modification was an enhancement which was not required.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to verify the adequacy of the SW pump room ventilation system for all
operating conditions. Since there was a performance deficiency, the team compared this
performance deficiency to the minor questions contained in Appendix B, "Issue
Screening," of IMC 0612, "Power Reactor Inspection Reports." The team concluded that
the issue was more than minor because inadequacies in the calculations identified during
the 2002 SSDI resulted in a modification to ensure winter operation was within the
allowable temperature range, and because the revised calculation did not include all the
summer heat loads which could potentially impair the SW pump room ventilation system.
This was a design issue which affected the mitigating systems cornerstone. The team
reviewed this finding in accordance with IMC 0609, "Significance Determination Process,
and answered no to all five screening questions in the Phase 1 Screening Worksheet
Enclosure
51
under the Mitigating Systems column. The team concluded the issue was of very low
safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to implement design control measures to
check and verify the adequacy of the design. Specifically, the licensee failed to verify
the adequacy of the SW pump room ventilation system for all operating conditions.
The licensee entered this issue into its CAP as CRs 02-07188 and 03-06870. Because
this violation was of very low safety significance and because it was entered into the
licensees CAP, this violation is being treated as a NCV consistent with Section VI.A.1 of
the NRC Enforcement Policy. (NCV 05000346/2003010-13)
.8
Inadequate Service Water System Flow Analysis
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance. Specifically, the licensee failed to ensure that the
SW system could perform its design function under all required conditions. Following
discovery, the licensee entered the issue into its corrective action program and
performed the necessary calculations.
Description: In IR 05000346/2002014, several URIs were identified dealing with the SW
system and ultimate heat sinks. These deficiencies included failure to account for the
lowest acceptable performance of the SW pumps, failure to consider the USAR
described single failure of the forebay return valve to open, failure to include the design
basis strainer resistance, and strainer blowdown losses. Additionally, the design basis
lowest ultimate heat sink level was not used and the flow diverted to the AFW was not
considered. Because of these deficiencies, the ability of the system to provide the
required design basis flows to the safety-related heat exchangers could not be verified.
In response to the issues identified by the SSDI, as well as other issues identified
internally, the licensee determined that there was not sufficient design basis
documentation to demonstrate operability of the SW system under all required
conditions. The licensee had a consultant perform two new calculations,02-113 and
02-123, to address a large number of SW flow issues, including those issues discussed
above.
The team reviewed these calculations and noted that the calculations determined that,
under a certain combination of design basis conditions, design basis flow rates and
pump net positive suction head (NPSH) were not achievable. The specific combination
included having design basis low ultimate heat sink levels, design basis high SW
temperatures and the SW strainers going into backwash while the system was
Enclosure
52
responding to a design basis accident. The team determined that the strainer operation
was automatic such that this set of circumstances was one which the licensee should
have included as part of its design basis.
The team noted that the licensee had reviewed and approved the calculation without
comment. This issue negatively reflected on the adequacy of the licensees engineering
department to oversee the engineering contractor performing the calculations and on
the engineering staffs ability to identify engineering issues and non-conforming
conditions. The team independently evaluated the issue and determined that the
system would most likely be able to perform its design function as the inadequate
conditions would only exist for short periods of time. The licencee initiated CR 03-03977
to revise the calculations. Following evaluation of CR 03-03977, the licensee concluded
that the SW system was able to perform its safety related function. The team agreed
with the licensees conclusions.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to ensure the adequacy of the SW system to supply required flow rate to
safety related components and failed to ensure the required NPSH for the SW pumps.
Since there was a performance deficiency, the team compared this performance
deficiency to the minor questions contained in Appendix B, "Issue Screening," of IMC
0612, "Power Reactor Inspection Reports." The team concluded that the issue was
more than minor because the licensee did not initially have a calculation which
demonstrated that the SW system could fulfill its design function under design basis
conditions and when a calculation was subsequently prepared, system deficiencies were
not evaluated to ensure that the safety function could be met. This was a design issue
which affected the mitigating systems cornerstone. The licensee concluded that the SW
system had been able to perform its safety function. The team reviewed this finding in
accordance with IMC 0609, "Significance Determination Process, and answered no to
all five screening questions in the Phase 1 Screening Worksheet under the Mitigating
Systems column. The team concluded the issue was of very low safety significance
(Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to ensure that design requirements were
correctly translated into specifications, drawings, procedures, and instructions.
Specifically, the licensee did not have design calculations to show the SW system could
perform its required safety function under design basis conditions.
The licensee entered the issue into its CAP as CRs 02-06337, 03-07006, and 03-07042.
Because this violation was of very low safety significance and because it was entered
into the licensee CAP, this violation is being treated as a NCV, consistent with
Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000346/2003010-14)
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.9
Inadequate Flooding Protection for the Service Water System
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to have
provisions in place to protect the SW pump room from flooding. Following discovery,
the licensee placed the issue in its corrective action program, evaluated it and put
procedures in place to address the issue.
Description: During the SSDI in 2002, the NRC identified that no procedures were in
place to isolate equipment open for maintenance in the SW pump room that could flood
the room in the event of high lake water level. USAR Section 2.4.8.2 stated, "The
Probable Maximum Flood Water is elevation 583.7 feet..." USAR Section 9.2.1.3
stated, "In the event of high water levels,...the pump room is sealed to prevent flooding."
Finally USAR Section 3D.1.4, "[General Design Criteria (GDC)] Criterion IV -
Environmental and Missile Design Basis," stated, "These [safety-related] structures,
systems, and components are appropriately protected against dynamic effects...and
discharging fluids, that may result from equipment failures and from events and
conditions outside the nuclear power unit." Therefore, the NRC questioned whether the
SW system was adequately protected against flooding effects that could result from
high lake water levels, from internal flooding, and from other threats to the system that
could result from failure of non-seismically qualified equipment, as described in the
USAR.
In response to this concern, the licensee determined that operator actions were
necessary in order to ensure that the USAR statements were met. In order to ensure
that the operator actions occurred, several changes to operating procedures were
required. These procedural actions were taken. During the 2003 CATI, the team
verified that the corrective actions were implemented and appropriately resolved.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to translate design basis requirements into procedures for flood
protection in the SW pump room. Since there was a performance deficiency, the team
compared this performance deficiency to the minor questions contained in Appendix B,
"Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The team
concluded that the issue was more than minor because the licensee had to make
procedural changes in order to ensure that safety-related equipment was capable of
performing its safety functions. This was a procedural deficiency which affected the
mitigating systems cornerstone. The licensee determined that the system remained
operable since the deficiency only dealt with a lack of procedural guidance. The team
reviewed this finding in accordance with IMC 0609, "Significance Determination
Process, and answered no to all five screening questions in the Phase 1 Screening
Worksheet under the Mitigating Systems column. The team concluded the issue was of
very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
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use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to correctly translate the design basis into
procedures. Specifically, the licensee failed to have procedures in place to isolate
equipment opened during maintenance in the SW pump room that could potentially
flood the room in the event of rising lake water level.
The licensee had previously entered this issue into its CAP as CR 02-07714. Because
this violation was of very low safety significance and because it was entered into the
licensees CAP, the violation is being treated as a NCV, consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000346/2003010-15)
.10 Inadequate Service Water System Flow Balance Testing Procedure
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion XI,
having very low safety significance (Green). Specifically, the licensee failed to account
for a number of conditions in the SW system flow balance testing procedures. Following
discovery, the licensee placed the issue in its corrective action program, evaluated it and
put procedures in place to address the issue.
Description: Surveillance procedures DB-SP-03000 and 03001, "Service Water
Integrated Train I (II) Flow Balance Procedure," were performed every refueling outage
to balance the system flows. During the 2002 SSDI, the NRC identified that this
procedure did not establish flows to the safety-related heat exchangers based on
worst-case design basis conditions, such as degraded SW pumps, lowest ultimate heat
sink (UHS) level, highest resistance SW system lineup, or system resistance
degradation. Further, no analyses existed that established the test acceptance criteria
for design basis conditions. Therefore, the flow balance procedure did not verify that
the system was capable of providing the required flows to its safety-related heat
exchangers under design basis conditions.
The licensee performed SW flow model calculations that conservatively predicted the
required flow to each safety-related load. The model addressed all SW branch lines in
service during various accident scenarios and accounted for the flow rate issues
described in CR 02-06337. Separately, the licensee computed the required instrument
inaccuracies for the instrumentation used during the SW flow balance.
However, the licensee's design organization did not ensure that this information was
properly transmitted to the plant engineering group in a format that would ensure that
the procedures had adequate acceptance criteria. The design engineering organization
did not perform a formal calculation which documented the minimum acceptance criteria
to ensure that the test procedure would demonstrate that the SW flows met their design
basis requirements. Instead, design engineering transmitted the design information in
two separate evaluations which then had to be combined by plant engineering and
corrected for the instrument measurement uncertainty. Because the plant engineering
department had to interpret the results from design engineering, the plant engineering
personnel applied considerable conservatism when establishing the test acceptance
Enclosure
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criteria. The licensee issued CR 03-07006 to provide a design record file for test
acceptance criteria.
During SW testing performed in the summer and fall 2003, the licensee determined that
the newly established test acceptance criteria could not be met for some components.
This resulted in numerous CRs being written and the design engineering organization
having to prepare a number of operability evaluations justifying the use of lower
acceptance criteria. The team determined that the design engineering failure to
establish appropriate acceptance criteria prior to the SW testing occurring contributed to
the number of CRs and subsequent operability evaluations.
The team determined that the licensee planned to perform a flow balance twice each
refueling outage, once on as found basis, and once on an as-left basis. Collecting
as-found data would provide evidence that the SW system branch flows were adequate
during the previous operating cycle to remove the design basis heat loads. The team
considered this a positive step by plant engineering to ensure operability of the SW
system.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to properly account for a number of required conditions in the SW system
flow balance testing procedure. Since there was a performance deficiency, the team
compared this performance deficiency to the minor questions contained in Appendix B,
"Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The team
concluded that the issue was more than minor because procedural changes were
necessary in order to ensure that the safety-related SW system branch flow rates were
adequate for the system to perform its safety functions. The team assessed the finding
through Phase 1 of the SDP. This was a design issue which affected the mitigating
systems cornerstone. At the end of the inspection, the licensee was performing a new
flow balance. The licensee concluded that the system was previously capable of
meeting its design requirements. The flow balance test results were reviewed by the
resident inspectors and document in IR 2003025. The team reviewed this finding in
accordance with IMC 0609, "Significance Determination Process, and answered no to
all five screening questions in the Phase 1 Screening Worksheet under the Mitigating
Systems column. The team concluded the issue was of very low safety significance
(Green).
Enforcement: Title 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 the written test procedures which
incorporate the requirements and acceptance limits contained in the applicable design
documents.
Contrary to the above, the licensee failed to adequately test the SW system because
the licensees SW system flow balance testing procedure failed to account for a number
of required conditions. The testing failed to verify that adequate flow was provided to
safety related components under all accident conditions.
Enclosure
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The licensee entered the issue into its CAP as CRs 02-06064 and 03-07006. Because
this violation was of very low safety significance and because it was entered into the
licensees CAP, this violation is being treated as a NCV consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000346/2003010-16)
.11 Service Water Discharge Path Swapover Setpoint
Introduction: The team identified a violation of 10 CFR Part 50, Appendix B, Criterion III,
involving the licensee's failure to provide a basis for the setpoint to swap the service
water system discharge path. This issue was previously identified as an NCV in IR
05000346/2002014 and the corrective actions taken by the licensee failed to correct the
originally identified condition. The primary cause of this violation was related to the
cross-cutting areas of problem identification and resolution and human performance,
because the licensee did not recognize that the corrective actions taken needed to
restore compliance with the identified violation of NRC requirements.
Description: The 2002 SSDI identified a Green finding and NCV of 10 CFR Part 50,
Appendix B, Criterion III, regarding the licensee's failure to provide a calculational basis
for the 50 psig setpoint to swap SW system discharge path. The licensee did not
contest the violation and entered the issue into the corrective action system as
CR 02-07802. During the CATI, the team reviewed the evaluation and corrective
actions taken for this NCV. The team determined that the licensee had evaluated the
condition and confirmed that no analysis initially existed. The evaluation reviewed by
the team was initially approved on March 9, 2003 and had a corrective action also
accepted on March 9, 2003. This evaluation focused on the fact that no setpoint
calculation existed which showed that instrument uncertainty values had been properly
incorporated, not on providing the calculational basis for the 50 psig setpoint itself. The
team determined that this evaluation and proposed corrective action were not
responsive to the violation identified during the SSDI.
On November 10, 2003, the licensee provided the team a revised copy of CR 02-07802.
The originally approved condition report was apparently rejected and replaced with a
new evaluation and new corrective actions on March 30, 2003. The new evaluation
documented a vendor calculation which showed that with the 50 psig setpoint, there
would be inadequate flow to certain safety related components under design basis
conditions. The new evaluation also concluded that the setpoint was adequate if a
failure of the non-seismically qualified discharge piping did not have to be postulated
during a loss of coolant event. Relying upon this latter conclusion, the licensee
determined that the 50 psig setpoint was acceptable. The team did not agree with the
licensees reliance on non-seismically qualified piping to ensure that safety related
components had adequate flow. Therefore, the team determined that the revised
evaluation still did not address the SSDI violation in that the calculational basis for the
50 psig issue still did not exist.
The team noted that the evaluation contained in the revised CR 02-07802 was similar to
that documented in CR 02-05748. Both CRs articulated a view that, unless there was a
seismic event, non-seismic lines did not have to be assumed to have failed. The team
questioned this premise, based on the information in 10 CFR Part 50, Appendix A,
GDC. The team noted that the licensee had committed to following the draft version of
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these criteria, as documented in NUREG 0153, and committed to in the USAR. Draft
General design criteria 2, in that NUREG, stated, in part, that components important to
safety were to be designed to withstand the effects of natural phenomena without loss
of their safety function.
The team presented this information to the licensee engineers as part of the review of
CR 02-05748. The engineers sought the advice of the regulatory assurance department
via CR 03-04018. The regulatory assurance department responded, in part, that, "It
was not appropriate to apply the single failure criterion to non-safety systems,"
confirming the team position. The licensee then wrote a new CR (03-06507) and took
compensatory measures to close the SW discharge valve leading to the cooling tower.
The licensee also stated in CR 03-06507 that the issue involved application of single
failure assumptions for existing systems. The team noted that this appeared to be a
continuation of the misunderstanding of application of design basis assumptions.
Following the inspection, the licensee performed a PRA study on the likelihood of failure
of the non-safety-related piping and then applied the results of this analysis to justify the
issue described in CR 02-07802. As this analysis was performed significantly after the
end of the inspection, it was not reviewed by the team, and the team was not able to
evaluate the impact of this analysis on the licensing basis of the plant.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to correct a previously identified violation of NRC requirements. Since
there was a performance deficiency, the team compared this performance deficiency to
the minor questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power
Reactor Inspection Reports." The team concluded that the issue was more than minor
because the licensee had not corrected a previous violation and was relying on
non-safety-related equipment to perform a safety function under design bases
conditions.
The previously identified violation was evaluated in IR 05000346/2002014 as having
very low safety significance (Green). This assessment has not changed. This finding
was reviewed by Regional Management, in accordance with IMC 0612. The finding was
determined to be of very low safety significance and concluded that the violation could
be categorized as Green.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, as of August 12, 2003, the licensee failed to verify that the
design of the SW system discharge path swapover setpoints were adequate.
Specifically, the analysis performed by the licensee showed that the established
setpoints were not adequate and the evaluation of the analysis accepted the inadequate
setpoint based on non-safety-related equipment performing a safety-related function
Enclosure
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under design basis conditions. Neither the analysis nor the evaluation corrected the
non-conforming condition previously identified in IR 05000346/2002014.
This is a violation of 10 CFR Part 50, Appendix B, Criterion III. The NRC Enforcement
Policy,Section VI.A.1, provides guidance on dispositioning of violations. Normally,
violations of very low safety significance are not cited. However, the Enforcement Policy
notes four conditions under which an issued notice of violation with a reply will be
considered. The first of these conditions is, "The licensee failed to restore compliance
within a reasonable time after a violation was identified." As the corrective action
generated in response to the NCV did not restore compliance, this condition has been
met. (VIO 05000346/2003010-01)
.12 Service Water Discharge Check Valve Test Acceptance Criteria
Introduction: The team identified a violation of TS 4.05a an 10 CFR 50.55a, having very
low safety significance. Specifically, the licensee failed to ensure that the service water
discharge check valve was tested in accordance with ASME Code. The primary cause
of this violation was related to the cross-cutting areas of problem identification and
resolution and human performance, because the licensee did not recognize that the
corrective actions taken needed to ensure compliance with NRC requirements.
Description: The 2002 SSDI described a Green finding and NCV of 10 CFR Part 50,
Appendix B, Criterion XVI, regarding the licensees failure to adequately correct the SW
pump discharge check valve acceptance criteria. This was entered into the licensees
corrective action system as CR 02-07657. The team determined that the licensee
evaluated the concern in the NCV and determined that the valves were full open at flow
rates greater than 7270 gpm. Therefore, the licensee concluded that no corrective
actions to the procedure were necessary. The CR evaluation stated that CR 02-05784
would address the differences in the stated flow rates in the USAR and system
description. No formal calculation was prepared to support the 7270 gpm value and no
corrective actions were generated for the CR. This CR was accepted as being ready for
closure on January 28, 2003.
The team noted the licensees evaluation of the flow rate at which the valves were full
open could not be reproduced as it relied on oral information provided by the valve
vendor. The team identified that numerous check valve failures had been identified in
the industry which were not detected during inservice testing of check valves to values
less than the required accident flow rate. Furthermore, the evaluation did not follow any
of the methods listed in GL 89-04, "Guidance on Developing Acceptable Inservice
Testing Programs" or NUREG 1482, "Guidelines for Inservice Testing Programs at
Nuclear Power Plants" for ensuring that the valves were full open.
The team reviewed the licensees technical specification 4.05a and confirmed that the
licensee was required to test their check valves in accordance with the ASME Code for
Operation and Maintenance of Nuclear Power Plants (ASME OM Code) as required by
10 CFR 50.55a. The team confirmed that the licensee was committed to the 1996
Addenda of the OM Code. Section ISTC 4.5.4a of this addenda stated that check
valves which had a safety function to open were to be tested by initiating flow and
observing that the valve had traveled to the full open position or to the position required
Enclosure
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to perform its intended function. Using the guidance in GL 89-04, the team ascertained
that "the position required to perform its intended function" would be one which passed
the required accident flow rate.
The team noted that the GL provided guidance for cases where a full flow test on a
check valve could not be performed. For these cases, the licensee should submit a
relief request from the ASME requirements to the NRC and have the request granted
prior to implementing the requested relief.
Based on the above, the team concluded that the licensees evaluation in CR 02-07657
was inadequate in it did not demonstrate that 7270 gpm flow would ensure that the
check valve was in the full open position. Because of this inadequate evaluation, the
licensee did not take appropriate corrective actions to bring the surveillance procedure
acceptance criteria into compliance with the requirements.
The team further reviewed CR 02-05784 and noted that it did not contain any references
to CR 02-07657 and did not address the corrective actions which CR 02-05784 had
stated would be addressed by the CR. Specifically, there were no corrective actions
addressing the USAR and system description issues as stated by CR 02-07657.
Furthermore, the implementing organization had determined that the initially
recommended corrective actions to 02-05784 were not necessary and had
recommended that they be canceled, although this recommendation had not been
formally accepted by the end of the inspection. The team ascertained that the accident
analyses of record required a SW flow rate of approximately 10,300 gpm in order to
ensure sufficient cooling of safety related systems.
Following the on-site inspection, the team performed a limited review of CR 03-07656.
This CR noted that the SW pump #3 discharge check valve had not met the
procedurally required acceptance criteria. The operability evaluation for this CR
accepted the deficiency as operable based on the inadequate evaluation in CR 02-
07657. Use of the evaluation from CR 02-07657 to justify operability resulted in the
licensee using an alternate means of verifying that the check valve was full open without
obtaining the necessary NRC approval for relief from the Code requirements.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to demonstrate that the check valve could perform its intended function in
accordance with NRC requirements. The team concluded that the issue was more than
minor because the inadequate test acceptance criteria allowed the licensee to accept a
check valve as performing its intended function at less than full system flow. The
licensee did not request NRC approval to use an alternate means of demonstrating the
valve was capable of performing its intended function. The team concluded that the
issue involved traditional enforcement because the licensee had not sought NRC
approval prior to using an alternate means of demonstrating that a check valve could
perform its intended function.
In 2002, the issue was determined to be of very low safety significance. However,
because the licensee accepted a valve as being full open with less than the accident
required flow rate, the team re-evaluated the safety significance. The team determined
that the licensee had an operability determination which concluded that the SW system
Enclosure
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was operable but degraded, as it could not achieve design flow rates. This operability
determination was reviewed by the resident inspectors and determined to be
acceptable, as documented in IR 05000346/2003025. The team concluded that, as the
valve was part of the SW system, it was covered by this operability determination. As
the licensee concluded the system was operable, the issue screened out of the Phase 1
worksheet (Green).
Enforcement: Technical specification 4.05a requires, in part, that the licensee perform
inservice testing of valves in accordance with the ASME OM Code and applicable
addenda as required by 10 CFR 50, Section 50.55a.
Title 10 CFR 50.55a(f)(4) requires, in part, that, during successive 120 month intervals,
a licensee must comply with the requirements in the latest edition and addenda listed in
paragraph (b) of 10 CFR 50.55a 12 months prior to the start of the 120 month interval.
Paragraph 50.55a(f)(5)(i) requires that the inservice test program be revised as
necessary to meet the requirement of paragraph 50.55a(f)(4). Paragraph
50.55a(f)(5)(iii) requires that if a licensee determines that conformance with certain code
requirements is impractical, the licensee is to submit information to support the
determination, in accordance with 10 CFR 50.4.
The ASME OM Code, 1996 addenda, Section ISTC 4.5.4(a) requires, in part, that check
valves be exercised by initiating flow and observing that the obturator traveled to its full
open position. The NRC approved use of the 1995 Code edition through the 1996
addenda for the third inservice testing 120-month interval on March 28, 2003 . Prior to
that date, the licensee was committed to the 1986 Edition (no Addenda) of the ASME
Boiler and Pressure Vessel Code,Section XI. The 1986 Code Edition contains similar
requirements.
Contrary to the above, on September 12, 2003, and other dates, the licensee did not
observe by a direct indicator or other positive means that the ASME Class 3 service
water pump discharge check valve obturator traveled to its full open position during its
quarterly surveillance test. Specifically, on September 12, 2003, the licensee observed
a flow rate of 9718 gpm through valve SW-19, which was less than the test acceptance
criterion of 10,000 gpm, and less than the approximately 10,300 gpm used in the
licensees most recent accident analysis. Observing flow rates less than required for the
valve to perform its safety function was not a positive means to determine that the
obturator traveled to its full open position and no other direct indicator or positive means
was used.
This is a violation of TS 4.05a and 10 CFR 50.55a. The NRC Enforcement Policy,
Section VI.A.1, provides guidance on dispositioning of violations. Normally, violations of
very low safety significance are not cited. However, the Enforcement Policy notes four
conditions under which an issued notice of violation with a reply will be considered. One
of these conditions is, "The licensee failed to restore compliance within a reasonable
time after a violation was identified." As the CR addressing this issue was accepted for
closure without restoring compliance by either revising the test acceptance criteria or
submitting a license amendment to the NRC to use an alternate means of verifying that
the valves were full open, this condition has been met. At the time of the exit, no new
CR had been written to address this issue. (VIO 05000346/2003010-02)
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.13 Lack of Design Basis Calculations to Support Service Water Single Failure
Assumptions
Introduction: The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance. Specifically, the licensee failed to provide an
analysis which addressed the service water valve single failure assumptions mentioned
in the updated safety analysis report. Following discovery, the licensee entered the
issue in its corrective action program. The primary cause of this violation was related to
the cross-cutting area of problem identification and resolution because the licensee had
not recognized the impact of the issue on the design basis and had not corrected it after
it was identified in 2002.
Description: In IR 05000346/2002014, two URIs were identified dealing with the
ultimate heat sinks temperature and level analyses. A concern expressed in both URIs
dealt with single failure assumptions of the SW discharge path valves to redirect flow in
the most conservative manner. These single failure assumptions were described in the
USAR as being the most limiting events for the SW system. For example, for the
maximum ultimate heat sink temperature case, a single failure of the forebay return
valve (SW 2930) to open would result in the SW discharge being directed approximately
17 feet from the intake, rather than some 500 feet away. This would increase the SW
temperature returning to the plant. For the minimum level case, a single failure of the
cooling water makeup valve (SW 2931) to close would result in water being diverted to
the cooling towers instead of being returned to the ultimate heat sink, which would lower
the available level.
Both valves were butterfly valves, and the licensee determined that the only credible
failure was an electrical failure of the valve to change position. The licensee did have
procedures which addressed the operators opening (or closing) the valves manually as
needed. The team noted that the USAR stated that the operators needed to close the
valves within three hours. However, the calculations for the ultimate heat sink maximum
temperature and minimum water level started with the valves already opened (or
closed). Because these calculations did not account for the three hour time delay, and
because the licensee did not have any calculation to support a different time period, the
team considered them to be non-conservative in regard to both maximum temperature
and minimum level. As an interim measure the licensee implemented changes to
operations procedures to control the position of the valves to address the issue. The
licensee is also performing additional review and evaluations of the facilitys
conformance with design and licensing basis documents. The actions resolved any
immediate operability concerns regarding postulated single failures with maximum
system temperatures and minimum heat sink level conditions.
The ultimate heat sink calculations supported a change to the TSs (amendment 242). The
team identified other problems with this submittal, as discussed in Section 4OA3(3)b.21.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to analyze the effects on the ultimate heat sink of the forebay return valve
not opening or of the cooling water makeup valve not closing for the time period
necessary for an operator to take action. Since there was a performance deficiency, the
team compared this performance deficiency to the minor questions contained in
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Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The
team concluded that the issue was more than minor because the current calculations
were non-conservative and the licensee was not able to demonstrate that the SW
system could perform its safety function under design basis conditions. This was a
design issue which affected the mitigating systems cornerstone. The team determined
that it was unlikely that the SW system would not function during a design basis
accident, as there would need to be the unlikely combination of both the "right" single
failure along with the maximum temperature or minimum level conditions. The team
reviewed this finding in accordance with IMC 0609, "Significance Determination
Process. The finding screened as Green in the SDP Phase 1, since this issue was a
design deficiency that would not likely result in the loss of function per Generic Letter
(GL) 91-18, Revision 1. Therefore, the issue was determined to have a very low safety
significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, as of August 29, 2003, the ultimate heat sink maximum
temperature and minimum level design basis, as described in the USAR had not been
correctly translated into a specification. Specifically, the USAR described a limiting
single failure for both the maximum temperature and minimum level condition, and the
design basis calculations did not address the time necessary for the operators to
recover from the single failure.
This issue was entered into the licensee's CAP as CRs 02-05372, 02-05986, 02-06337,
03-06507, and 03-07042. Because this issue was of very low safety significance and
because it was entered into the licensees CAP, this violation is being treated as a NCV
consistent with Section VI.A.1 of the Enforcement Policy (NCV 05000346/2003010-17).
.14 Auxiliary Feedwater System Calculation Issues With Main Steam Safety Valves
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to ensure
that design analyses showed that the AFW system could perform its safety function
under design basis conditions. Following discovery, the licensee entered the issue into
its corrective action system. The primary cause of this violation was related to the
cross-cutting area of human performance, as the licensee used the results of a vendor
calculation without verifying that it was adequate.
Description: The team reviewed CR 02-07236 and the licensees calculation
C-NSA-050.03-013 for AFW system hydraulic characteristics, which included calculating
the hydraulic resistance of flow to the steam generators. When determining the
hydraulic system resistance, it was noted that the calculation did not consider the
increased backpressure caused by allowable MSSV drift and safety valve accumulation.
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This could have a negative affect on analyzed AFW pump flow because the higher
backpressure would decrease AFW flow to the steam generators and reduce heat
removal capability for the AFW system. In resolving this issue, the licensee reviewed
the loss of feedwater analysis of record, 32-1171148-00, and determined that the MSSV
drift and accumulation had not been considered in this vendor calculation. The vendor
calculation was used as an input to calculation C-NSA-050.03-013 for determining the
AFW system resistance curve. Since the vendor calculation was in error, the licensees
calculation was in error as well.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to assess the effect of increased back pressure in the AFW system.
Since there was a performance deficiency, the team compared this performance
deficiency to the minor questions contained in Appendix B, "Issue Screening," of IMC
0612, "Power Reactor Inspection Reports." The team concluded that the issue was more
than minor because the calculations were non-conservative and because the calculation
of record did not demonstrate that the AFW system could perform its safety function
under design basis conditions. Based on further analysis, the licensee concluded the
AFW system was operable. This was a design issue which affected the mitigating
systems cornerstone. The team reviewed this finding in accordance with IMC 0609,
"Significance Determination Process, and answered no to all five screening questions
in the Phase 1 Screening Worksheet under the Mitigating Systems column. The team
concluded the issue was of very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to implement effective design control
measures to check and verify the adequacy of the design basis calculation performed by
the vendor of the AFW system hydraulic analyses for all postulated accidents. This
issue negatively reflected on the adequacy of the licensees oversight of the engineering
contractor performing the calculations. The licensee entered the issue into its CAP as
CR 03-02651. Because this issue was of very low safety significance and because it
was entered into the licensees CAP, this violation is being treated as a NCV, consistent
with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000346/2003010-18)
.15 Auxiliary Feedwater Strainer Mesh Size and Preconditioning of Auxiliary
Feedwater System During Testing
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion XI,
having very low safety significance (Green). Specifically, the licensee failed to
recognize that flushing the system and blowing down the strainers upstream of the
turbine driven pump bearing cooling water strainers prior to routine surveillances
constituted preconditioning of the AFW system. Following discovery, the licensee
entered the preconditioning issue into the corrective action program. The primary cause
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of this violation was related to the cross-cutting area of problem identification and
resolution, because the licensee had failed to recognize the consequences of the
preconditioning when evaluating an earlier issue and determining that a larger mesh
size could be installed in the strainers.
Description: The licensee designated CR 02-04673 as a SCAQ CR which described
discovery that the strainers in the SW supply to the turbine driven pump bearings had a
smaller mesh size than that of the main SW strainers. It also addressed the possibility
of blockage of the restricting orifices in the AFW system due to debris within the SW
system. The following CRs were rolled into CR 02-04673: 02-05639 and 02-06861.
Both an operability evaluation and a root cause report were required for CR 02-04673.
In addition, an engineering change package was initiated to add new strainers upstream
of the restricting orifices and to increase the mesh size in the existing strainers.
OPERABILITY DETERMINATION: Because the licensee had extensively cleaned the SW
system piping during the outage, the team did not disagree with the conclusion reached
in the operability determination that the AFW system was operable. However, the
following non-conservatisms in the analysis were noted:
The operability determination assumed that the AFW system would run on
minimum recirculation flow until all of the SW in the "dead leg" leading to the
pumps has passed through the lines. However, under the postulated seismic
event causing a loss of offsite power (LOOP), AFW would be required to function
since the main feedwater pumps would be unavailable. The accident analysis
assumed that AFW flow to the steam generators would be supplied within
60 seconds. The starting sequence for the pumps would have the flow
immediately being directed through the pumps and into the steam generators.
In the short term, 100 percent of the AFW flow would be directed into the steam
generators. Only after a period of time would the pumps be throttled back or the
recirculation lines opened to divert water. Therefore, the team did not agree that
this assumption was reasonable. Furthermore, it appeared that the licensees
analysis had not considered the actual design basis for the system.
The operability determination noted that the bearing strainers had not shown any
sign of clogging during periodic testing with SW. However, the licensee failed to
note that this was because the procedures required the line to be flushed and
the strainers to be blown down prior to and after each test, thus eliminating the
potential for any clogging.
ROOT CAUSE REPORT: The licensee issued a root cause analysis in March 2003 which
determined the cause of the limiting particle size for the AFW strainers. At that time, the
licensee's CAP did not require use of a formal root cause process. Therefore, even
though the issue was determined to be a SCAQ, the licensee did not determine the root
cause because the issue was, as stated in the root cause report, "historical." The team
ascertained that because the root cause report did not follow a formalized process, the
report was actually more like an apparent cause analysis than a root cause evaluation.
Similar to the operability determination, the cause evaluation noted that the strainers to
the coolers were periodically flushed and blown down during testing. However, the
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evaluation failed to recognize that this constituted preconditioning of the test. The report
did not evaluate the beneficial impact that the pre-test flushing and strainer blowdown
would have in regard to required maintenance of the coolers.
The modification history developed in the cause evaluation showed that the licensee
had significantly increased the strainer mesh sizes in 1985 without discussion of the
bearing oil cooler strainers. However, the evaluation did not address whether these
modifications resulted in changes to the testing procedures, such as the currently
imposed pre and post test flushing and strainer blowdown.
The evaluation did not address whether the cooler for the pump bearings could handle
the increased particle size. There was no documentation in the evaluation which
addressed the acceptability of the increased strainer mesh size on the components
which the strainer was designed to protect. Although the evaluation discussed the need
for operator attention to an alarm for a blocked strainer, it did not recognize that the
larger particles could cause blockage of a downstream component that could not be
cleared by back-washing of the strainer.
ENGINEERING CHANGE PACKAGE: The engineering change package, ECR 03-0074,
stated that a conceptual design was not necessary due to the simplicity of the design
and the great deal of study that went into producing the initiation report. The package
acknowledged that the strainers were in the lines which supply cooling water to the
pump and turbine bearing oil coolers, the turbine governor oil cooler and the pump
mechanical seals. However, it did not discuss why the increased strainer size would not
affect any of these components.
In response to the teams questions, the licensee provided the team with a vendor
manual which contained a single line which stated that the bearing oil coolers had
openings greater than 0.0625 inches such that they could handle the larger size
particles if the strainer mesh size was increased. The licensee engineers stated these
coolers were the limiting components. However, this information was not documented
and there was no evidence that the licensee had considered this information prior to the
team's questions.
Further discussions with the licensee determined that the bearing oil coolers had never
been opened for inspections and were not included in the GL 89-13 heat exchanger
program. The team concluded this had not been a problem in the past because of the
very small mesh strainer. The licensee wrote CR 03-06576 to address this issue.
Nonetheless, the team concluded that the modification was a work in progress as it had
not been implemented by the end of the inspection.
REVIEW OF PERIODIC TEST PROCEDURE: As discussed above, the issue of flushing the
lines and blowing down the strainers both prior to and following a periodic surveillance
was reviewed by the team. This issue was raised based on a review of periodic
procedure DB-SP-04152, which used SW as the source of cooling water for the test
duration. The licensee investigated the issue and determined that other AFW
surveillance tests also flushed the lines and blew down the strainers prior to the test
being performed. The team determined that the flushing of the lines blowing down of
the strainers constituted pre-conditioning of the turbine driven AFW pumps because it
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masked any performance problems which could occur during an actual event. The
availability and reliability of the system was intended to be ensured through the periodic
testing. The team noted that the licensee had stated that no problems with the strainers
had occurred as part of the justification for increasing the strainer mesh size. However,
the team concluded that the licensees procedural actions would have masked any
problems. A violation of NRC requirements was identified.
Analysis: The team determined that a performance deficiency existed because the
licensees practice, as prescribed in site procedures, prevented the AFW system from
being tested in its as-found condition. Since there was a performance deficiency, the
team compared this performance deficiency to the minor questions contained in
Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The
team concluded that the issue was more than minor because there was not sufficient
information to demonstrate that test requirements would have been met had the
strainers not been blown down. This was a procedural issue which affected the
mitigating systems cornerstone. Because the licensee's practices prevented a true
assessment of previous operability, the team could not determine if the turbine driven
pumps would have been inoperable if the strainers were not blown down. However,
discussions with the licensee did not indicate that a large amount of material was seen
during the system flushes and strainer blowdowns. Therefore, the licensee considered
the system to be operable. The team reviewed this finding in accordance with IMC
0609, "Significance Determination Process, and answered no to all five screening
questions in the Phase 1 Screening Worksheet under the Mitigating Systems column.
The team concluded the issue was of very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XI requires, in part, that a test
program be established to demonstrate that components will perform satisfactorily in
service. Contrary to the above, as of September 29, 2003, the test procedures for the
AFW turbine high speed stop and overspeed trip did not demonstrate that the system
would perform satisfactorily in service because the test included a step to flush the
cooling water lines and blow down the strainers prior to performing the test. These
actions prevented any adverse effects due to strainer blockage from being discovered.
Failure to adequately test the system was a violation of Appendix B, Criterion XI. This
issue has been entered into the licensee's CAP as CR 03-06520. This violation is being
treated as a NCV consistent with Section VI.A.1 of the NRC Enforcement Policy.
.16 Inadequate Evaluation of System Health Condition Report on Auxiliary Feedwater
Design Bases Calculations
Introduction: The team identified a performance deficiency involving the licensee's
failure to adequately evaluate a condition report written as part of the licensee's internal
system health assessment. Following discovery, the licensee made corrections to the
existing condition report evaluation. This was a minor violation.
Description: During review of CR 02-05904, the team identified that the cause
evaluation was not adequately performed. This CR addressed a system health report
issue on whether certain AFW design basis calculations existed or were outdated. The
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evaluation determined that all the questioned calculations did exist and that no further
action was needed. The following deficiencies in the evaluation were identified:
The evaluation listed an incorrect calculation number and an incorrect revision
for another calculation.
The evaluation identified a calculation for maximum steam pressure in the AFW
system; however, it failed to recognize that the calculation was incorrect (this
issue is discussed in Section 4OA3(3)b.14).
The evaluation stated that CR 02-06356 identified the causes for the condition;
therefore, no additional action needed to be taken. However, CR 02-06356,
which had been evaluated three months prior to CR 02-05904, did not actually
identify the causes, but rather assumed that the causes were known and that all
appropriate corrective actions had been identified (this issue is discussed in
Section 4OA3(3)b.22).
Analysis: The team determined that a performance deficiency existed because the
licensee failed to evaluate a condition adverse to quality regarding calculations on the
AFW system. Since there was a performance deficiency, the team compared this
performance deficiency to the minor questions contained in Appendix B, "Issue
Screening," of IMC 0612, "Power Reactor Inspection Reports." Because the team
independently identified the deficiencies which the licensee had failed to assess, the
failure to properly evaluate an identified condition adverse to quality had no safety
impact. Therefore, the team concluded this performance deficiency was minor.
Enforcement: The failure to perform an adequate cause evaluation for a condition
adverse to quality constitutes a violation of 10 CFR Part 50, Appendix B, Criterion XVI,
which has minor significance and is not subject to enforcement action in accordance with
Section IV of the NRCs Enforcement Policy.
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case due to the licensee's
inadequate evaluation. Additionally, the underlying cause is similar to that of other
findings in this report.
.17 Containment Post-LOCA Trisodium Phosphate
Introduction: The team identified a performance deficiency involving the licensee failing
to approve a calculation prior to relying on the results of the calculation. The calculation
addressed the capability of the TSP in baskets in the lower level of containment to
control the pH of sump water following a postulated design basis accident. Following
discovery, the licensee entered the issue into its corrective action program and
approved and issued the calculation.
Description: The team reviewed CRs 02-02943, 02-05300 and 02-05304. These CRs
questioned the adequacy of the TSP design from three aspects:
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Capability of the TSP baskets to perform their function in light of a new
calculation for containment flood level which revealed that the baskets would not
be fully submerged;
Two different calculations provided conflicting conclusion regarding the time
when sump pH would be greater than 7.0; and
Whether the amount of TSP in the baskets was sufficient to neutralize sump
water with acidification from other post-LOCA sources such as degraded
coatings and insulation.
Concerns were also raised regarding the impact of the additional boric acid in the
containment during the previous operating cycle on the capability of the TSP baskets to
fulfill its safety function.
The licensee addressed the concerns of all three CRs through the corrective actions
specified for CR 02-05300. Re-analysis of the containment flood level and the TSP
basket contents was performed in calculations C-NSA-059.01-019 and 86-5024418-01.
These calculations demonstrated that, with the recalculated flood level, the amount of
TSP in the baskets was sufficient to meet the sump pH-control requirements of the
USAR. Analysis of the impact of the additional boric acid inside the containment was
performed in calculation C-NSA-040.01-006. This calculation evaluated the amount of
TSP needed to neutralize the boric acid deposited in the containment from a variety of
RCS leakage scenarios, including RCS unidentified leakage over the previous three
operating cycles plus the boric acid deposited as the result of head leakage. This
calculation demonstrated that for the identified level of leakage, with the amount of boric
acid deposited from the head leakage (conservatively assumed to be entirely dissolved
into the sump), the TS required amount of TSP would neutralize all of the boric acid.
The team found the issue difficult to evaluate as a result of the number of rollovers
involved in the resolution of these issues. The issues were ultimately consolidated into
three corrective actions under CR 02-05300; all three corrective actions involved the
completion of vendor calculation 86-5024418-01. The team determined that the three
corrective actions had been marked as completed although one calculation had not
been approved and had, in fact, been remanded to the vendor for revisions. This was
not in accordance with the licensees CAP procedure. Specifically, procedure
NOP-LP-2001, Condition Report Process, Revisions 3 and 4, required that corrective
actions be completed prior to the corrective action being accepted and closed. The
revisions to the calculation were determined to be minor and did not affect the results,
and the licensee formally approved the calculation. The team did not review the final
calculation results.
The team determined that a performance deficiency existed because the issue involved
the licensees failure to approve a calculation prior to relying on the results of the
calculation and this issue was not identified during the corrective action closure process.
Since there was a performance deficiency, the team compared this performance
deficiency to the minor questions contained in Appendix B, "Issue Screening," of IMC
0612, "Power Reactor Inspection Reports." The team concluded that the performance
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deficiency was minor because the changes to the unapproved calculation were minor
and did not affect the overall results.
Enforcement: The closure of all the corrective actions for CR 02-05300, contingent upon
completion of vendor calculation 86-50244181-01, which had not been owner accepted,
was considered a violation of 10 CFR Appendix B, Criterion V, which has minor
significance and is not subject to enforcement action in accordance with Section IV of
the NRCs Enforcement Policy. The licensee entered the issue into its CAP as
CR 03-07420.
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case due to the rollover issues
which were identified and the underlying cause is similar to that of other findings in this
report.
.18 Borated Water Storage Tank Calculation Issues
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance. Specifically, the licensee failed to translate the
radiological consequences of leakage from engineered safety feature components
outside containment into calculations of record for post-accident control room dose and
offsite boundary dose. Following discovery, the licensee entered the issue into its
corrective action program and provided a bounding evaluation which demonstrated that
the increase in dose was within acceptable limits.
Description: During the SSDI, the NRC identified that the radiological consequences of
leakage from engineered safety features components outside the containment were not
included in the calculation of offsite dose for 10 CFR Part 100 nor in the calculation for
control room dose per GDC 19. The concerns involved the impact on control room dose
as a result of an airborne release from the assumed 500 gallons of containment sump
water deposited in the BWST and the impact on both offsite and control room dose as a
result of ECCS system pump seal leakage. The licensee wrote CRs 02-06701,
02-07713, and 02-07701 to address these issues.
The licensee performed an informal calculation in the cause analysis for CR 02-07701 to
determine the increase in dose in the control room from the 500 gallons deposited in the
BWST. The calculation was based on the site boundary base dose listed in the USAR
which resulted from the airborne release associated with the 500 gallons of post-LOCA
water deposited in the BWST. This dose was determined by the Bechtel calculation of
record as 2.72 rem. Using control room ventilation system parameters and the site
boundary dose, the control room dose was calculated as 0.07 rem. The licensee
extrapolated the dose for the 40 gallon per hour pump seal leakage from the USAR
dose rate for normal valve system leakage of 5890 cubic centimeters per hour (1.56
gallons per hour). The result was an additional control room dose of 0.5 rem and an
additional site boundary dose of 1.5 rem.
The licensee then calculated that the total offsite dose, resulting from the USAR value of
232 rem accident dose plus the BWST dose of 2.72 rem plus the pump seal dose of
1.5 rem, was a total of 236.22 rem. The total control room dose was similarly summed:
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USAR accident dose of 19.8 rem plus BWST dose of 0.066 rem plus pump seal leak
dose of 0.5 rem for a total of 20.366 rem.
As a result of these calculations, the licensee specified post-restart corrective actions to
update the Bechtel calculation of record and the USAR to incorporate these doses.
Because the corrective actions had not yet been completed, the licensee had not
completed a screening or evaluation under 10 CFR 50.59. The team performed a
limited evaluation of the acceptability of the increased dose under 10 CFR
50.59(c)(2)(iii), "Result in more than a minimal increase in the consequences of an
accident previously evaluated in the final safety analysis report (as updated)." The team
reviewed the guidance provided in Nuclear Energy Institute (NEI) standard 96-07,
"Guidelines for 10 CFR 50.59 Implementation," Revision 1, which NRC endorsed in
Based on this guidance, the team determined the revised dose calculations did not
result in more than a minimal increase in the consequences of an accident previously
evaluated in the USAR. The team determined that a more than minimal increase would
have occurred if:
The increase in dose was more than or equal to ten percent of the difference
between the previously calculated dose value and the regulatory guideline value
(10 CFR Part 100 or GDC 19); and
The increased dose exceeded the current standard review plan guideline value
for the particular design basis event.
The team calculated that ten percent of the difference between the previously calculated
dose total and the 10 CFR Part 100 and GDC 19 limits were 6.8 rem for the offsite dose
increase and 1.02 rem for the control room dose. The team confirmed that the total
increases in dose of 4.2 and 0.57 rem were below the guidance values in NEI 96-07;
therefore, the first part of the guidance was satisfied. The team concluded that the
second part of the guidance was met because the total offsite dose was less than the
Part 100 limit of 300 rem and the control room dose was less than the GDC 19 limit of
30 rem. The team, therefore, deemed that the licensee had an acceptable rationale for
delaying issuance of the formal calculations until after restart.
Analysis: The team determined that a performance deficiency existed because the
licensee had not recognized that the radiological consequences of leakage from
engineered safety features components outside the containment were not included in
the calculation of offsite dose for 10 CFR Part 100 nor in the calculation for control room
dose per GDC 19. Since there was a performance deficiency, the team compared this
performance deficiency to the minor questions contained in Appendix B, "Issue
Screening," of IMC 0612, "Power Reactor Inspection Reports." The team concluded
that the issue was more than minor because the licensee had to perform calculations to
show that the increased doses remained within the post accident dose level
requirements.
The team reviewed the SDP questions for reactor safety, occupation radiation safety
and public radiation safety contained in MC 0612, Appendix B, Issue Screening, and
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also consulted with the senior reactor analysts (SRAs). Based on this review, the team
determined that the issue was not covered by any of the revised oversight cornerstones
and was, therefore, not suitable for SDP analysis. This determination was based on the
issue being a design issue that dealt with postulated doses following a design basis
accident. The team also determined that the increase in dose did not involve an issue
requiring a license amendment. Therefore, this finding was reviewed by Regional
Management, in accordance with IMC 0612. The finding was determined to be of very
low safety significance (Green) because the preliminary calculations concluded that the
increased doses remained within the post accident dose level requirements and there
were no actual releases.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to translate the radiological consequences of
leakage from engineered safety feature (ESF) components outside containment into
calculations of record for post-LOCA control room dose and offsite boundary dose.
The licensee entered the issue into its CAP as CRs 02-06701, 02-07713, and 02-07701.
Because this violation was of very low safety significance and because it was entered
into the licensees CAP, this violation is being treated as a NCV consistent with
Section VI.A of the NRC Enforcement Policy. (NCV 05000346/2003010-20)
.19 Inadequate Evaluation of Reactor Coolant Pump Casing-to-cover Stud
Overstressing
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance. Specifically, the licensee failed to evaluate a
potential overstressing condition on the reactor coolant pump casing-to-cover studs.
Following discovery, the licensee entered the issue into its corrective action program.
The primary cause of this violation was related to the cross-cutting area of problem
identification and resolution as the licensee closed a condition report without recognizing
that the apparent condition adverse to quality had not been addressed.
Description: The team reviewed CR 02-08759. This CR questioned whether the RCP
casing-to-cover studs had been overstressed when the studs on all four pumps were
retensioned in 1996. The RCP casing-to-cover studs are part of the reactor coolant
pressure boundary (RCPB).
The team identified the following deficiencies with the licensees handling of this CR:
The CR was closed based on a draft revision of a vendor calculation, SR-0964,
Revision 1, which was not accepted by the licensee until after the CR was
closed.
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The discrepant condition (possible overstressing of the studs) was neither
analyzed as not being a concern nor field verified to not be a problem before the
CR was closed. Instead the corrective action was canceled on the basis that the
studs on pumps 1-1 and 1-2 had relaxed to within acceptable limits, therefore,
the studs on the other two pumps were also deemed acceptable.
The draft calculation only addressed the allowable stud tension for pumps 1-1
and 1-2, based on the new gaskets installed; it did not address the condition
from 1996 for all four pumps or the continuing condition on pumps 2-1 and 2-2.
When questioned by the NRC team the licensee had to go back to the vendor
and obtain a new calculation to show that the previous stud elongation was
acceptable. However, no new CR was written to address the fact that 02-08759
had been closed without addressing the concern for which it had been written.
Instead of being provided with a new calculation, the vendor provided the
licensee with a letter providing the maximum allowable stud elongation for the
1996 configuration.
The actual 1996 as-left elongation values for some of the studs were greater
than the 24 mils specified in the vendor letter, although they were within the 26
mils specified in 1996. The licensee verbally evaluated the condition, but did not
actually document the acceptability of the 1996 condition.
The vendor letter was appended to the CR file four months after the CR was
closed and only after the team questioned why no CR was written about the
issue.
Because of this sequence of events, the team performed a limited, independent
verification of both the formal and informal calculation results, and then verified the
actual installed stud elongation against the calculated allowable. The team determined
that some studs were elongated to 25 mils; however, the quadrant average in all cases
was between 23.2 and 23.4 mils. The team determined that an average elongation of
24.3 mils would keep the stress levels below the maximum American Society of
Mechanical Engineers (ASME) boiler and pressure vessel code (the Code) allowable of
23.6 kilo-pounds per square inch (ksi). Based on this independent evaluation, the team
concluded that the casing-to-cover studs on RCPs 2-1 and 2-2 were not overstressed
and that none of the studs on any of the four RCPs not been overstressed in the past.
The team also noted that the licensee did not have a design basis calculation that
supported the increased tensioning of the studs on all four reactor pumps in 1996 and
still did not have such a calculation for RCPs 2-1 and 2-2 in 2003. However, the
licensee planned to replace the gaskets on these pumps by no later than RFO 14 in
2005; once the gaskets are replaced, the stud tensioning would be addressed by
calculation SR-0964.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to evaluate the acceptability of the RCP studs prior to closing the CR.
Additionally, when the issue was brought to their attention, the licensee did not write a
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new CR to document the failure of the CAP. Since there was a performance deficiency,
the team compared this performance deficiency to the minor questions contained in
Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The
team concluded that the issue was more than minor because the licensee had to
perform calculations to determine if the RCP studs were within ASME Code allowables.
The team reviewed this finding in accordance with IMC 0609, "Significance
Determination Process. The team assessed the finding through Phase 1 of the SDP.
The issue involved the barrier integrity cornerstone because it dealt with the
acceptability of the RCPB. There was only one question related to the RCPB. The
licensee had not evaluated the functionality of RCP studs for past operation or for
current operation on two of the four pumps. Therefore, the team assessed the issue
based on the team's evaluation described above. Based on this assessment, the RCP
studs were always functional and the SDP RCPB question was answered as "no".
Therefore, the finding screened out as having very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, in March 2003, the licensee closed CR 02-08759 without
ensuring that the ASME Code requirements were correctly translated into the torquing
values for the RCP casing-to-cover studs and without ensuring that previous
maintenance activities had not resulted in the studs being overstressed.
After being identified as a potential violation at the end of the inspection, the licensee
wrote CR 03-07047 to enter the issue into the CAP. Since the issue was of very low
safety significance and was captured in the licensee's CAP, it is being treated as a NCV,
consistent with Section VI.A.1 of the NRC Enforcement Policy.
.20 Reactor Coolant Pump Inner Gasket Leakage
The team reviewed CRs 02-01523, 02-03668, and 03-04018, and associated
evaluations, which documented an apparent continuing problem with RCP inner gasket
leakage. The team determined that the licensee failed to adequately analyze the results
of an apparent continuing leak past the inner gasket on the RCPs. Specifically, minor
leakage past the inner gasket was noted on all four pumps during previous outages and
the documented evaluation did not address why it was acceptable to not repair the
gaskets. Furthermore, the licensee's analysis did not provide technical justification for
either replacing or not replacing all four RCP gaskets.
The team performed extensive evaluation of the as-left leakages for all pumps by
reviewing test results and test log books. The responsible test engineers were also
interviewed by the team. The team determined that the licensees evaluations were
based on leak testing that: (1) did not use the same methodology from outage to
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outage; (2) did not attempt to normalize the data from outage to outage; (3) did not
consider the impact of reactor coolant pressure and temperature conditions on the test
results; and (4) was only intended to verify that the leak detection lines were open and
not blocked. The team was concerned that the licensee did not recognize these
inconsistencies in performing and approving the evaluation.
The team determined that the design of both the inner and outer gaskets was to seal
against full reactor pressure. While normally the inner gasket provided the seal, the
outer gaskets was also designed for this purpose. Only if the outer gasket failed would
the RCPB, provided by the casing-to-cover studs, be affected.
The team also noted that leakage past either the inner or outer gasket was not pressure
boundary leakage, per the ASME Code. The Code specifically excluded gaskets from
RCPB leakage. Instead, any leakage past the outer gasket would be categorized as
either identified or unidentified reactor coolant leakage, and would be subject to TS
limits. Leakage past the inner gasket was not considered to be a safety concern.
Neither the inner or the outer gasket was considered to be important to safety and
neither component was credited with having a safety function in the USAR.
The team determined that a catastrophic failure of the inner gasket during an
operational cycle should have no consequences, as the outer gasket should continue to
provide a seal. If the outer gasket also failed, then the licensee would have to comply
with the TS limiting conditions for operation and shut down the plant.
The team noted that the normal operating pressure and temperature (NOP/NOT) test
performed by the licensee included inspections of the RCPs: both at the gasket leakoff
lines and at the studs. These inspections were conducted prior to, during and following
reaching NOP/NOT. This NOP/NOT test showed that there was no outer gasket
leakage and that the inner gasket leakage was minor, occurred primarily during the
pressurization period and stopped, or significantly slowed, once the pumps reached an
equilibrium temperature.
Notwithstanding that the licensee failed to adequately analyze the results of an apparent
continuing leak past the inner gasket on the RCPs, the team concluded that this did not
present a safety issue since the inner gasket leakage would not affect the RCPB. No
violation of NRC requirements were identified.
.21 Environmental Qualification of Equipment Not Supported by Analysis
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion XVI,
having very low safety significance (Green). Specifically, the licensee failed to ensure
that emergency core cooling system pump motors were environmentally qualified for the
stated mission time, as stated in a license amendment request (LAR) submitted to the
NRC. Following discovery, the licensee entered the issue into its corrective action
program. The primary cause of this violation was related to the cross-cutting area of
human performance as the licensee did not ensure that personnel developing license
documents had the necessary information.
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Description: The team examined CR 02-05732, which was issued during the licensees
latent issues review of the SW system. The fundamental concern discussed in the CR
was that LAR 96-0008, submitted to NRC by the licensee on July 28, 1999, contained
statements that were unsupported by analyses.
The CR identified three specific concerns:
Some equipment in the ECCS pump rooms was not qualified to higher
temperatures, as stated in the request;
There was no analysis to support a statement in the request that two room
coolers were adequate even with substantially degraded flow rates; and
The request stated that no changes were made in AFW flow, yet a calculation of
record showed that the flow rate was changed from 1600 gpm to 800 gpm.
The team reviewed the condition description, immediate actions, and cause analysis.
The cause analysis examined the three concerns and concluded that there was no
discrepant condition, no apparent cause, and no corrective actions required.
The team disagreed with this conclusion based on a review of CR 02-05593 which
identified a block of components that were not included in a calculation evaluating
environmental qualification (EQ) qualification of equipment in the ECCS pump rooms.
This CR also noted that no reference for qualification of the HPI and DHR pump motors
existed and recommended that the EQ calculation be revised to address qualification of
all these components.
The team identified that the first concern in CR 02-05732 was correct, in that two pieces
of equipment in an ECCS pump room, the containment spray (CS) and HPI pump
motors, were not environmentally qualified for the service time of 30 days which was
stated in the LAR. Based on a review of the EQ folder, the team determined that the
motors could most likely be qualified as required. CR 03-06588 was written to address
this issue. However, the team later determined that the licensee had evaluated
CR 03-06588 and concluded that no corrective actions needed to be taken as far as
environmentally qualifying the ECCS motors.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to establish the environmental qualification of two ECCS motors at the
time the license amendment request was submitted. Since there was a performance
deficiency, the team compared this performance deficiency to the minor questions
contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection
Reports." The team concluded that the failure to adequately evaluate the motor
environmental qualification issue was more than minor because it reflected a weakness
in the licensees CAP in regard to correctly assessing issues. The team concluded that,
if uncorrected, this continuing weakness could result in a repeat failure of the CAP to
adequately identify, evaluate and correct problems. This was an equipment qualification
issue which affected the mitigating systems cornerstone. Although the licensee had not
qualified the equipment, the team deemed that the motors more likely than not could be
qualified. Therefore, the team considered it reasonable that the motors would perform
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their safety function, if required to operate. The team reviewed this finding in
accordance with IMC 0609, "Significance Determination Process. The finding was
screened in the SDP Phase 1 as a qualification deficiency that was confirmed not to
result in the loss of function per Generic Letter 91-18, Revision 1. Therefore, the issue
was determined to have a very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that
conditions adverse to quality be promptly identified and corrected, commensurate with
their safety significance.
Contrary to the above, in November 2003, the licensee evaluated CR 03-06588, which
described a condition adverse to quality, and concluded that no corrective actions were
necessary. The condition adverse to quality described in the CR dealt with LAR 96-008
which documented that the HPI and DHR pump motors were environmentally qualified
for 30 days, when, in fact, those motors were not so qualified.
After being identified as a potential violation at the end of the inspection, the licensee
wrote CR 03-06588 to enter the issue into the CAP. Since the issue was of very low
safety significance and was captured in the licensee's CAP, it is being treated as a NCV,
consistent with Section VI.A.1 of the NRC Enforcement Policy.
.22 Inadequate Justification for Downgrade of Significant Condition Adverse to
Quality
Introduction: The team identified a performance deficiency involving the licensee's
failure to evaluate an issue initially determined to be a significant condition adverse to
quality prior to downgrading the issue. Following discovery, the licensee entered the
issue into its corrective action program. This was a minor violation.
Description: Prior to the safety system design inspection in October 2002, and following
completion of the system health reviews, the licensee initiated CR 02-06356 to
document a repetitive concern regarding a difficulty in determining the status or location
of design basis calculations. This CR was determined to be a SCAQ, primarily because
a number of design basis calculations were discovered to be outdated or non-existent.
Issues such as those discussed in Section 4OA3(3)b.16 exemplified the reason that the
CR originally was rated as a significant condition.
The team reviewed CR 02-06356 and noted that it had been downgraded to a routine
CR with minimal investigation or justification. The evaluator assumed that his
department had the bulk of the calculations and that he knew the status of those
calculations. The evaluator then concluded that there was not really a problem, based
on these assumptions and apparently without considering other design engineering
departments. Additionally, the team determined that the extent of condition review was
based entirely on a word search for the word "calculation" in the title of CRs. This
eliminated many of the CRs written on superceded or historical calculations and resulted
in many of the CRs on design basis calculational issues not being found.
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Analysis: The team determined that a performance deficiency existed because the
licensee failed to adequately assess and justify the downgrade of a condition adverse to
quality as required by procedure NOP-LP-2001. Since there was a performance
deficiency, the team compared this performance deficiency to the minor questions
contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection
Reports." The team concluded that the performance deficiency was minor because the
team did not identify other examples where downgrades were performed without
adequate justification and because no specific calculation deficiencies which resulted in
inoperable equipment were associated with the CR.
Enforcement: The failure to provide adequate justification when downgrading a SCAQ
constitutes a violation of 10 CFR Part 50, Appendix B, Criterion V. However, this
violation was determined to have minor significance and is not subject to enforcement
action in accordance with Section IV of the NRCs Enforcement Policy. The licensee
documented the issue in CR 03-06948.
While minor violations are not normally documented in inspection reports, the team
determined that documentation was appropriate in this case due the underlying cause is
similar to that of other findings in this report.
.23 Inappropriate Application of 10 CFR 50.59
Introduction: The team identified a NCV of 10 CFR 50.59, Changes, Tests and
Experiments. Specifically, the licensee failed to preform an adequate evaluation of a
defacto modification to the plant where the underlying change may have required NRC
approval prior to implementation. Following discovery, the licensee entered the issue
into its corrective action program and re-performed the evaluation; the licensee also
repaired those barriers which were physically degraded. The primary cause of this
violation was related to the cross-cutting area of human performance as the licensee
appeared to selectively choosing information from the guidance document.
Description: In IR 05000346/2002019, LER 05000346/2002-006 was closed and an URI
was opened to track resolution of safety related structures which were unprotected
against tornado missiles; specifically that six feet of the EDG exhaust stacks were
unprotected and that portions of a concrete barrier were degraded. This issue was
being tracked in the licensee's corrective action system under CRs 02-04146, 02-04147,
02-04700 and 02-05590. The team determined that the licensee had evaluated the
non-conforming conditions using a computer code (TORMIS) discussed in Electric
Power Research Institute (EPRI) Topical Report NP-2005, "Tornado Missile Risk
Evaluation Methodology," Volumes I and II, August 1981. Based on use of this code,
the licensee determined the probability of the unprotected areas being struck by a
tornado missile was relatively low.
The licensee revised the USAR to incorporate the TORMIS methodology, including a
provision which allowed it to be used to accept degraded or non-conforming conditions.
On that basis, the licensee declared the diesel generators operable and determined that
repairs were not needed for the non-conforming structures until 2004. In regard to the
unprotected stacks, the licensee determined that no modifications were necessary.
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Prior to the USAR change, Section 3.5.1 of the USAR stated that, "Protection against a
potential missile may be provided by, but not necessarily limited to, any one or
combination of the following protection methods: compartmentalization, barriers,
separation, distance, restraints, strategic orientation and equipment design." The team
noted that all these methods involved physical protection of the equipment, rather than
methods of evaluation. Under change notice 02-063, the licensee changed this
statement to add tornado missile probability as a protection method.
As part of the USAR change, the licensee performed an evaluation as required by
10 CFR 50.59. During review of this evaluation, the team questioned whether the
licensee had appropriately followed the guidance in Nuclear Energy Institute standard
NEI 96-07, which NRC endorsed in Regulatory Guide 1.187. Specifically, the licensee
appeared to be incorporating use of the TORMIS methodology, using the methodology
to accept a defacto change to the plant (where the plant did not match the description in
the USAR) and then justifying the methodologys use for future non-conforming or
degraded conditions all in the same 50.59 evaluation. The team noted that these
differing applications affected how the 10 CFR 50.59, Section c.2, questions were
answered in the licensees 10 CFR 50.59 evaluation. The team also noted that the
questions were answered based on the standard review plan, rather than on the
Davis-Besse USAR.
The team consulted with the Office of Nuclear Reactor Regulation (NRR) and
determined that the licensee should have evaluated the change from protecting
equipment from tornado generated missiles by means of physical protection to relying
upon analysis to demonstrate that such protection was not needed through use of a
probabilistic computer methodology.
In discussions, the licensee stated that the above approach was not necessary because
the TORMIS methodology was an "approved methodology and, therefore, wasnt a
departure from a method of evaluation described in the FSAR (as updated) used in
establishing the design bases or in the safety analyses" as defined in 10 CFR 50.59.
However, the team noted that there was not an existing method of evaluation that
applied to protection of the EDGs. Instead, the change was from "protection by means
of a physical barrier," to "protection by means of a probabilistic approach," which
appeared to have introduced a new failure mode not previously evaluated for the EDGs.
The introduction of this new failure mode did not appear to be addressed by the
licensees 50.59 evaluation.
Specifically, the USAR previously stated that the diesel generators were not affected by
tornado generated missiles due to physical features. Inclusion of the TORMIS
methodology introduced the possibility that the diesels could be affected by tornado
generated missiles. The licensee answered this question in its 10 CFR 50.59 evaluation
by stating that "the probability of a tornado generated missile was incredible, that NRC
accepted use of probability for Davis-Besse in analyzing the probability that turbine
missile would penetrate containment, and by stating that the Davis-Besse acceptance
criteria was the same as that licensed at other plants."
However, the team noted the following guidance in NEI 96-07, Section 4.3.6:
"Malfunctions of SSCs are generally postulated as potential single failures to evaluate
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plant performance with the focus being on the result of the malfunction rather than the
cause or type of malfunction. A malfunction that involves an initiator or failure whose
effects are not bounded by those explicitly described in the USAR is a malfunction with a
different result..."
Based on this description, because possibility for the diesel generators to be damaged
by tornado missiles involved both an initiator and effects which were not bounded by
those explicitly described in the USAR, the team deemed that this question should have
been answered "yes" and prior NRC review of this change sought.
At the end of the inspection, the licensee had written a new CR, 03-06561, and was
revising the 10 CFR 50.59 evaluation to address the above issues. The revised 10 CFR
50.59 analysis was not reviewed by the team.
The team also noted that the licensee had to physically repair the degraded concrete to
restore its tornado protection capability. The licensee had not considered these physical
changes necessary until the team identified the concern regarding inappropriately using
10 CFR 50.59 to correct non-conforming or degraded conditions. However, new
physical barriers for tornado missile protection were not added to those areas which
initially lacked such barriers.
Analysis: This issue was determined to involve a performance deficiency because the
licensee misapplied the criteria of 10 CFR 50.59 and concluded that prior NRC approval
was not required when such a conclusion could not be supported by the documented
50.59 evaluation. Because violations of 10 CFR 50.59 are considered to be violations
that potentially impede or impact the regulatory process, they are dispositioned using
the traditional enforcement process instead of the SDP. Typically, the Severity Level
would be assigned after consideration of appropriate factors for the particular regulatory
process violation in accordance with the NRC Enforcement Policy. However, the SDP is
used, if applicable, in order to consider the associated risk significance of the finding
prior to assigning a severity level. Using IMC 0612, Appendix B, "Issue Screening," the
team determined that the finding was more than minor because physical barriers were
degraded or missing and because those barriers being degraded could result in one or
more of the diesel generators failing to fulfill their design function during a tornado. This
was a design issue which affected the mitigating systems cornerstone.
The team reviewed this finding in accordance with IMC 0609, "Significance Determination
Process. The consequence of the design was assessed through Phase 1 of the SDP.
The team answered the question, "Does this issue involve an actual loss of safety
function," as "Yes," because under a design basis tornado, the diesel generator exhaust
stacks were not physically protected. Based on this premise, the team entered Phase 2
of the SDP.
The team determined that the only event tree affected was LOOP concurrent with loss
of one EDG. This was based on the assumption that a tornado missile hitting both EDG
exhaust stacks would be an incredible event. The team decreased the initiating event
frequency from a "5" (once in 100,000 years) to a "3" (once in 1,000 years) based on the
fact that the Davis-Besse switchyard was struck by a tornado in 1998 (in this event,
EDG 1 did not start from the control room and was declared technically inoperable due
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to the room design basis temperature of 120F being exceeded). In reviewing the 1998
event, the team determined that one turbine driven AFW pump was out of service for
maintenance. Therefore, the team assumed that a turbine driven AFW pump was out of
service for purposes for the Phase 2 analysis. Based on these credible assumptions,
the technical issue was determined to have very low safety significance and the violation
is categorized as Severity Level IV.
Enforcement: Title 10 CFR 50.59(d)(1) requires that the licensees maintain records of
changes in the facility, of changes in procedures, and of tests and experiments made
pursuant to 10 CFR 50.59(c). It further requires that these records include a written
evaluation which provides the bases for the determination that the change, test or
experiment does not require a license amendment pursuant to 10 CFR 50.59(c)(2).
Contrary to the above, on November 7, 2002, the licensee approved a 50.59 evaluation
incorporating a change in the design basis to accept not physically protecting the EDG
exhaust stacks from tornado missiles. However, the evaluation did not provide the basis
for why a possibility for a malfunction of the diesel generators due to impact on the
diesel generator exhaust stacks by a tornado missile did not produce a different result
than any previously evaluated in the final safety analysis report.
The failure to provide a written evaluation which described the basis for concluding a
license amendment was not needed was a violation of 10 CFR 50.59(d)(1). This issue
has been entered into the licensees CAP as CR 03-06561. This Severity Level IV
violation is being treated as an NCV consistent with Section VI.A.1 of the NRC
Enforcement Policy. (NCV 05000346/2003010-23)
.24 Failure to Perform Comprehensive Moderate Energy Line Break Analysis
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to include
the environmental effects of a DHR pump seal failure in its moderate energy line break
analysis. Following discovery, the licensee entered the issue into its corrective action
program and performed the analysis.
Description: The licensee initiated CR 02-07757 to document the failure to perform a
comprehensive moderate energy line break analysis. This CR was rolled over into
CR 02-06370, which required that the concerns of additional heat generation caused by
the moderate energy line break (DHR pump seal) be addressed in the new calculation
being performed in response to CR 02-06370. The team determined that the heat load
caused by failure of the DHR pump seal (an additional 21,000 btu/hr) was included in
calculation C-NSA-032.02-006 and that the discrepant condition was adequately
resolved.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to have a design analysis to demonstrate the ability to withstand
moderate energy line breaks as specified in design documents. Since there was a
performance deficiency, the team compared this performance deficiency to the minor
questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor
Inspection Reports." The team concluded that the issue was more than minor because
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the licensee had to perform calculations to show that the environmental effects were
acceptable. This was a design issue which affected the mitigating systems cornerstone.
The team reviewed this finding in accordance with IMC 0609, "Significance
Determination Process, and, based on the determination that the moderate energy line
break heat loads were acceptable and that the system could perform its design function,
answered no to all five screening questions in the Phase 1 Screening Worksheet
under the Mitigating Systems column. The team concluded the issue was of very low
safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to translate the consequences of leakage from
the DHR pump seals into calculations of record for moderate energy line breaks. The
licensee entered the issue into its CAP as CRs 02-07757 and 02-06370. Because this
violation was of very low safety significance and because it was entered into the
licensees CAP, this violation is being treated as an NCV consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000346/2003010-24)
(4)
Detailed Team Review of Licensee Corrective Actions Implemented to Address
Operational Issues Previously Identified by the Licensee
a.
Inspection Scope
The team assessed effectiveness of the licensees CAP to identify, categorize, evaluate,
and resolve the identified equipment, human performance or programmatic adverse to
quality plant conditions. The team mainly focused on plant systems design and
licensing basis requirements issues which were previously identified by the NRC, the
licensee and others during various design reviews conducted in 2002. The team
assessed effectiveness of the licensees corrective actions implemented to address
previously identified operational issues.
b.
Findings
Repetitive Spacer Grid Strap Damage
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion XVI,
having very low safety significance (Green). Specifically, the licensee failed to take
adequate corrective actions to previous events to prevent damage to a new fuel
assembly spacer grid strap during the final reload of the core in 2003. Following
discovery, the licensee entered the issue into its corrective action program. The primary
cause of this violation was related to the cross-cutting areas of corrective action and
human performance, because, despite earlier events, the licensee failed to adequately
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address the human performance issues that contributed to this and other fuel spacer
grid events.
Description: The licensee designated CR 02-06178 as a SCAQ CR. This CR described
repetitive damage to fuel assembly grid straps and rolled in the following CRs:
02-05645, 02-05895, 02-05896, 02-06343, and 02-09829. A root cause report was
required for CR 02-06178 as part of a NQA stop work order on fuel movements.
REVIEW OF ROOT CAUSE REPORT: The licensee issued a root cause analysis in
January 2003 which determined the cause of the repetitive grid strap damage. At this
time, the licensees CAP did not require use of a formal root cause process; however, a
formal TAPROOT process was used. Also, in May 2002, the licensee had completed a
root cause of fuel damage identified earlier in the outage. In reviewing the
January 2003 root cause report, the team noted several deficiencies:
The discussion on what occurred appeared to rely extensively on the previous
root cause, performed in May 2002, and on a 1999 Babcock and Wilcox (B&W)
root cause. The explanations for the statements made in the January 2003
report required understanding of the earlier studies in order to comprehend their
applicability.
The January 2003 root cause primarily focused on the new fuel assembly which
was discovered to be damaged in September 2002. It limited its discussion of
the other fuel assemblies discovered to be damaged in the September 2002 time
frame to listing the damage in a table and describing the disposition. This was
despite these CRs for these fuel assemblies being "rolled into" the root cause
report and a corrective action entry being closed with a statement that the root
cause report addressed the damage to the fuel assemblies.
The team noted that ten fuel assemblies were discovered to be damaged in
September through December 2002. This was in addition to the seven fuel
assemblies discovered to be damaged in March 2002. In one place in the
January 2003 root cause report, the licensee stated that the damage had to
occur during RFO 12, because there was no oxidation on fuel assemblies. The
team ascertained that, if the first statement was true, then the extent of condition
for the May 2002 root cause report must have been deficient in that it failed to
identify a number of damaged fuel assemblies.
In another section, the root cause report stated that review of the core loading
sequence determined that assembly NJ125Y, "and a number of other
assemblies," were loaded in a sequence that exposed those assemblies to
undesired corner to corner interactions. This second statement implied that the
damage might well have occurred during the fuel shuffle in March 2002.
However, the root cause report did not specifically identify which assemblies
were so loaded or otherwise follow up on this comment. The team determined
that a possible contributing cause was not identified or corrected.
The team noted that eight of the ten fuel assemblies discovered to be damaged
in September through December had only been burned once, and two were new
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fuel assemblies. Thus, the assemblies should not have been overly "bowed and
twisted," although this was listed as a possible reason for the damage.
In regard to the extent of condition, the team noted that the licensee provided an
extensive list of damage which occurred at other B&W sites. However, the only
Davis-Besse information from previous outages was from cycle 11. Data from
cycle 12 was missing from the table.
Based on the information in the extent of condition table, the team noted that,
approximately the same number of fuel assemblies were involved in both RFO
11 and 13. However, in RFO 11 the damaged fuel was mostly burned multiple
times and to have damage to only one or two grid strap locations. In RFO 13
(the current outage), the damaged fuel was primarily unburned or burned only
once and had damage to multiple grid strap locations.
The discussion on the December grid strap damage gave little credence to the
report that the fuel assembly was undamaged in September. Instead a
statement was made that because spacer grid 2 was damaged, and it hadn't
entered the pool, the damage must have occurred earlier. Given the extent of
the damage to the fuel assembly, the information provided in the CR initiation
statement from the personnel present, and the fact that only the northeast corner
face was damaged, the team considered it more likely that the damage occurred
all at one time.
The root cause report did not provide any discussion of the impact that occurred
during the December re-insertion. The team considered it unlikely that the
impact would not have caused any damage. The team noted that CR 02-09829
stated that the assembly visibly moved to the south. The team also noted that all
the damage occurred on the northeast corner. This indicated to the team that
the damage likely occurred during the re-insertion since a deflection to the south
would be an expected result if the northeast corner of the fuel assembly
impacted the cell. The failure to address why the impact occurred and the result
of the impact appeared to be a significant weakness in the root cause.
The team determined that no mention was made in the root cause report of
items such as whether the fuel handling personnel had the mast in fast or slow
speed or what the routine practice was regarding the fuel insertion rate.
Additionally, items such as length of time the crew had been working, schedule
pressures, and other factors which would address human performance were not
discussed, although these all could play a role in fuel handling mishaps.
FEBRUARY DAMAGE TO NEW FUEL ASSEMBLY: On February 24, 2003, during the final
reload of the cycle 14 core, another new fuel assembly was damaged. This was
documented in CR 03-01492. The licensee did an apparent cause evaluation for this
event and concluded that the damage to this fuel assembly was likely due to the less
than adequate design of the fuel assemblies. The team noted a number of issues that
did not appear to have been adequately considered in reaching the apparent cause
conclusion. For example:
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The damage occurred after the majority of the fuel assemblies were loaded and
only a few remained; this was not addressed in the apparent cause analysis.
The fuel handlers had spent approximately two hours unsuccessfully trying to
load another fuel assembly into place before deciding to change the loading
sequence to load another assembly in a potential corner to corner interaction
pattern. There was no indication that anyone suggested stopping the process
and evaluating the condition, before agreeing to the change in the loading
sequence.
Over the next three hours, multiple problems were experienced as the licensee
attempted to load the fuel assembly, including multiple overload conditions and
cable oscillations. The licensee reset the overload setpoints to the least limiting
condition at least twice, and even this setpoint was reached. Again, when
problems were encountered, the decision was to keep on trying to insert the
assembly, rather than stopping and evaluating what was happening.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to take adequate corrective actions in response to previous events and
as a result, a new fuel assembly spacer grid strap was damaged during the final reload
of the core in February 2003. Since there was a performance deficiency, the team
compared this performance deficiency to the minor questions contained in Appendix B,
"Issue Screening," of IMC 0612, "Power Reactor Inspection Reports." The team
concluded that the issue was more than minor because the licensee failed to prevent
recurrence of a significant condition adverse to quality as evidenced by damage to
previously undamaged fuel assembly grid straps. The team reviewed this finding in
accordance with IMC 0609, "Significance Determination Process. The barrier integrity
cornerstone was affected as failure of the grid straps has led to fuel leaks. No other
cornerstones were affected. There was one SDP Phase 1 worksheet question relating
to the fuel barrier. As this issue related to fuel barrier, the team concluded the issue
was of very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that
measures be established to ensure that conditions adverse to quality, such as
non-conformances, are promptly identified and corrected. For significant conditions
adverse to quality, it further requires that the cause is determined and corrective action
is taken to prevent recurrence.
Contrary to the above, as of February 5, 2003, the licensee had failed to take corrective
actions which prevented recurrence of grid strap damage, a significant condition
adverse to quality. Specifically on September 20, 2002, the licensee issued a stop work
order and a SCAQ was identified and documented in CR 02-06178. The root cause for
this report was completed in January 2003, prior to core reloading being allowed to
recommence. On February 5, a new fuel assembly was damaged after the licensee
made multiple unsuccessful attempts to insert the assembly into the core.
This issue was entered into the licensees CAP as CR 03-06996 at the end of the
inspection. Because this violation was of very low safety significance and because it
Enclosure
85
was entered into the licensees CAP, this violation is being treated as a NCV consistent
with Section VI.A of the NRC Enforcement Policy. (NCV 05000346/2003010-25).
(5)
Review of Fire Protection Corrective Action Items
a.
Inspection Scope
The team reviewed the licensees CAP to identify and address 10 CFR Part 50,
Appendix R, related deficiencies.
b.
Findings
.1
Process Monitoring Function for Alternative Shutdown Capability
Introduction: The team identified a Non-Cited violation of 10 CFR 50, Appendix R,
Section III.L.2.d having very low safety significance. Specifically, the issue regarded the
failure to provide necessary process monitoring readings for safe shutdown of the plant
during a fire event. The primary cause of this violation was related to the cross-cutting
area of problem identification and resolution because the licensee had previously
identified this issue as an enhancement and did not recognize that it was a violation of
regulatory requirements.
Description: During a review of the fire protection program, the licensee issued
CR 03-01648 identifying at failure to provide necessary process monitoring readings for
steam generator (SG) level and pressure necessary for safe shutdown of the plant
during a fire event. For the limiting Appendix R scenario (control room or cable
spreading room fire) where alternative shutdown was required, SG instrumentation
would not have been available for the idle SG during safe shutdown of the plant.
Without this SG level and pressure instrumentation, licensee operators would not have
been able to support the shell-tube differential temperature determination which was
required by the alternative shutdown procedure. This could have potentially resulted in
the loss of the thermal communication between the tubes and shell of the idle SG
resulting in unacceptable stresses on the tubes.
Even though the alternative shutdown procedures did not contain the necessary
procedural steps to prevent this condition if a fire in these areas were to occur,
operators could have taken temperature readings using a volt-meter to record the
temperatures locally at the penetration room. While these actions could not be credited
for the Appendix R analysis, they would be available. Additionally, after this
non-conformance was identified, the licensee performed a modification (ECR
03-0267-00) to provide level and pressure indication for the idle SG on the auxiliary
shutdown panel to support Appendix R safe shutdown.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to provide SG level and pressure indication required for alternative
shutdown. Since there was a performance deficiency, the team compared this
performance deficiency to the minor questions contained in Appendix B, "Issue
Screening," of IMC 0612, "Power Reactor Inspection Reports." The team concluded
that the issue was more than minor because it affected the initiating events cornerstone
Enclosure
86
and, by not providing the direct indications necessary for the operators to determine the
status of the idle SG, the probability of experiencing unacceptable stresses on the SG
tubes during the limiting Appendix R scenario was increased.
The team reviewed this finding in accordance with IMC 0609, "Significance
Determination Process. The team determined this finding to be of very low
significance, based upon the low probability of a serious control room fire combined with
the low probability that such a fire would affect this specific instrumentation
detrimentally. Additionally, even in the event that such a fire had affected this
instrumentation, it was likely that the operators still would have been able to prevent
these tube stresses through use of manual actions, although this was not a credited
action in the Fire Protection procedures for this scenario. The team concluded the issue
was of very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix R, Section III.L.2.d states, in part, that the
process monitoring function for the alternative shutdown capability shall be capable of
providing direct readings of the process variables necessary to perform and control the
alternative shutdown.
Contrary to the above, the licensee did not provide SG level and pressure indication that
was required for the alternative shutdown scenario for the control room or cable
spreading room fire. The licensee entered the issue into its CAP as CR 03-01648.
Because this violation was of very low safety significance and because it was entered
into the licensees CAP, the violation is being treated as a NCV, consistent with
Section VI.A of the NRC Enforcement Policy. (NCV 05000346/2003010-26)
.2
Supporting Functions for Alternative Shutdown Capability
Introduction: The team identified a Non-Cited violation of 10 CFR Part 50, Appendix R,
Section III.L.2.e having very low safety significance. Specifically, the licensee failed to
provide the process cooling and lubrication necessary to permit the operation of the
equipment used for safe shutdown functions. The licensee entered the issue into its
corrective action program and performed a modification to resolve the issue. The
primary cause of this violation was related to the cross-cutting area of problem
identification and resolution because the licensee had previously identified this issue as
an enhancement and did not recognize that it was a violation of regulatory requirements.
Description: During a control room fire scenario, the governing procedure,
DB-OP-02519, Serious Control Room Fire, could not have been performed as written.
During this scenario, the procedure directed the operator to restore containment cooling
by resetting the #1 and #3 CACs. However, because of a modification to the control
circuitry of these CACs, the reset button on the outside of the CAC switchgear cabinet
was rendered non-functional.
Since the CACs were needed to ensure an acceptable containment atmosphere, without
them the potential existed that Appendix R credited equipment might not be functional
during a control room fire scenario due to heightened temperatures in the containment.
However, since the heatup in the containment was not instantaneous and since the
equipment would have to be subject to the heightened temperatures for a relatively long
Enclosure
87
period of time, the team considered it unlikely that the plant would have progressed to
an unrecoverable condition prior to the operators being able to recover containment
cooling. The licensee implemented a modification (ECR 03-0243-00) that rewired the
control circuitry for CAC fan 1-1 such that, in the case of a control room fire, this fan
could be started in slow speed to provide cooling to the containment.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to provide containment air cooling for alternative shutdown. Since there
was a performance deficiency, the team compared this performance deficiency to the
minor questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power
Reactor Inspection Reports." The team concluded that the issue was more than minor
because, if left uncorrected, the finding would become a more significant safety
concern. By not providing containment air cooling as per the governing alternative
shutdown procedure, the probability of the failure of equipment relied upon for safe
shutdown was increased. The team reviewed this finding in accordance with IMC 0609,
"Significance Determination Process. The team assessed the finding through Phase 1
of the reactor safety mitigating systems SDP. This issue was screened to be of very low
safety significance (Green) because there was not a total loss of safety function for an
assumed control room fire with evacuation. This was evaluated using the transient
without the secondary steam plant (TPCS) Phase 2 worksheet. Within the Phase 2
TPCS worksheet, the CAC supports the feed and bleed operation of the power operated
relief valve (PORV) for decay heat removal if the SGs are not available. Given this fire
scenario, the PORV block valve would be closed by procedure and the PORV not used,
so there was no effect on a safety function.
Enforcement: Title 10 CFR Part 50, Appendix R, Section III.L.2.e, states, in part, that
supporting functions shall be capable of providing the process cooling, lubrication, etc.,
necessary to permit the operation of the equipment used for alternative safe shutdown
functions.
Contrary to the above, the licensee did not adequately provide containment air cooling,
because the governing procedure did not reflect a recent modification that disabled the
Appendix R reset buttons for the #1 and #3 CACs. The CACs were required to support
operation of Appendix R equipment credited equipment. The licensee entered the issue
into its CAP as CR 03-02699 and 03-04341. Because this violation was of very low
safety significance and because it was entered into the licensees CAP, the violation is
being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy.
.3
Emergency Diesel Generator Floor Drains Design Deficiency
Introduction: The team identified a NCV of 10 CFR Part 50.48(a)(1), having very low
safety significance (Green). Specifically, the licensee failed to evaluate the adequacy of
EDG common floor drains following sprinkler system actuation in the fire affected EDG
room. Following discovery, the licensee entered the issue into its corrective action
process and revised the fire response procedures to address the issue.
Description: The team determined that the floor drains between the two EDG rooms
were common, and that they had insufficient drainage capacity. Preliminary calculations
Enclosure
88
by the licensee showed that the drains had a maximum capacity of 100 gpm, whereas
the sprinkler system actuation resulted in 303 gpm in Room 318, and 286 gpm in
Room 319.
Terminal blocks in both EDG control cabinets were located approximately seven inches
above floor level. The common drain lines between the EDG rooms would have allowed
suppression system water from a fire in one EDG room to enter and affect the integrity
of the redundant EDG room. As a consequence of a fire in one EDG room with
sprinkler system actuation, water would have backed up in both EDG rooms and would
have increased above the elevation of the terminal blocks within approximately 30
minutes. Furthermore, no operator or fire brigade instructions were in place to facilitate
drainage by opening of the doors to prevent equipment submergence. The licensee
initiated CRs 03-02577, 03-06901, and 03-07256 to document, evaluate, and disposition
these deficiencies in their CAP. As part of the corrective action, the licensee revised
pre-fire plans AB-318 and AB-319 to provide compensatory measures to prevent
flooding of the EDG rooms.
Analysis: The team determined that a performance deficiency existed because the
licensee failed to evaluate the adequacy of EDG common floor drains following sprinkler
system actuation. Since there was a performance deficiency, the team compared this
performance deficiency to the minor questions contained in Appendix B, "Issue
Screening," of IMC 0612, "Power Reactor Inspection Reports." The team concluded
that the issue was more than minor because the finding affected the mitigating system
cornerstone. This was a design deficiency that was confirmed not to result in the loss of
function per Generic Letter 91-18, Revision 1. The team reviewed this finding in
accordance with IMC 0609, "Significance Determination Process, and determined that
the issue was of very low safety significance (Green).
Enforcement: Title 10 CFR 50.48(a)(1) requires, in part, that each operating nuclear
power plant have a fire protection plan that satisfies Criterion III of 10 CFR Part 50,
Appendix A. Criterion III, requires, in part, that fire-fighting systems shall be designed to
assure that their rupture or inadvertent operation does not significantly impair the safety
capability of these structures, systems, and components.
Contrary to the above, because the EDG common floor drains were not evaluated by the
licensee, nor verified for adequacy following sprinkler system actuation, the potential
existed for an inadvertent sprinkler system actuation or rupture to adversely affect the
capability of the EDGs to perform their safety function. The licensee entered this issue
into its CAP as CRs 03-02577, 03-06901, and 03-07256. Because this violation was of
very low safety significance and because it was entered into the licensees CAP, the
violation is being treated as an NCV, consistent with Section VI.A of the NRC
Enforcement Policy. (NCV 05000346/2003010-28)
(6)
Review of Licensee Event Reports
a.
Inspection Scope
The team reviewed the licensees CAP to identify and address problems previously
identified and documented in licensee event reports.
Enclosure
89
b.
Findings
.1
(Discussed) LER 05000346/2002-008-00 and -01: Containment Air Coolers
Collective Significance of Degraded Conditions
Introduction: The team reviewed this LER which related to the operability of the CACs
during previous operating cycles.
Description: Following unit shutdown in 2002, various degraded conditions were
identified associated with the CACs, which were documented in several CRs. The
issues were related to thermal performance degradation, and structural issues
(CR 02-05563) related to seismic adequacy, boric acid corrosion, and post accident
thermal stress. Thermal performance issues caused by cooling coil fouling conditions
on the air (cooling fin) side, and water (inside tube) side were identified. Additionally,
foreign material (plywood) was found in the SW supply piping to CAC # 2. In addition,
two 10 CFR Part 21 reports were issued by the CAC control vendor and the motor
vendor. The overall corrective action to resolve the physical degradation of the CAC
units was the refurbishment of the units prior to plant restart. New CAC units were
installed.
An engineering evaluation was performed to assess the effects of the degraded
conditions on heat transfer capability from which past operability was determined. The
licensee concluded that the effects of the degraded conditions (including foreign
material in the cooling water line) on heat transfer capability of the CACs, when
operating in conjunction with the CS system, would not have rendered the CACs
inoperable with respect to the long term post-accident containment heat removal
capability. These evaluations included containment pressure reduction, increased sump
temperature effects on ECCS pumps NPSH, ECCS pump room heatup, equipment
environmental qualification, and radiological release. A NCV was identified in Section
4OA3(3)b.3, for failure to implement effective design control measures to check and
verify the adequacy of the design basis calculation performed for offsite dose
consequences of degraded CACs.
The licensee performed an engineering evaluation of the structural issues and
concluded that the issues resulted in a degraded condition, but the CACs were not
rendered inoperable. The licensee stated that, while corrosion and pitting were
observed, the "as found" condition would not have been sufficiently degraded to prevent
the CACs from performing as seismically designed.
The licensee determined that the station had no safety related parts applicable to the
10 CFR Part 21 notification made by the controls vendor. At the time of receipt of the
Part 21 notification from the motor vendor, the licensee stated that the plant was in
Mode 6 and the CAC motors were being refurbished as part of the overall CAC
refurbishment. The notification reported a deficiency with a stator winding, which could
result in motor winding failure. According to the licensee, no winding failures or
anomalies were experienced during fan operation.
During review of the LER, the team identified several concerns with the licensees
evaluation. For example:
Enclosure
90
The licensee stated in the LER that "Since the service conditions for CACs #1
and #2 are similar to CAC #3, the degraded conditions on CAC #3 were
considered to be representative of the other CAC cooling coils." However, the
team determined that the #3 CAC was normally in standby, with CACs 1 and 2
being in operation. Therefore, the team could not agree that the condition in
CAC 3 was representative of the condition of the other two CACs.
The licensee noted that "a piece of plywood measuring approximately 5 inches
by 7 inches was discovered in the 8-inch diameter supply line upstream of the
transition to two 6-inch pipes, each of which supplies SW to one of two
independent cooling coil manifolds." The licensee stated that the presence of
the plywood was believed to be an isolated condition that occurred during RFO
12 in 2000. However, the licensee did not provide any information as to work
performed during RFO 12 which would have resulted in leaving a piece of
plywood behind. The licensee also noted that there were no intervening pipe
fittings or valves between the as-found location of the foreign material and the
two 6-inch transitions; however, the licensee did not provide any further
justification why the SW flow to this CAC would not be disrupted during a design
basis event.
In the thermal performance analysis section the licensee stated that, "Air side
degradation consisted of boric acid residue and dirt which may impede the heat
transfer characteristic of the cooling fins." However, in the preceding section on
structural issues, the air side was characterized as having "moderate to severe
corrosion" and noted that "corrosion and pitting" were observed. The licensee
did not explain why the two sections differed, much less explain difference in
heat transfer characteristic impact from "residue and dirt" to that obtained from
"corrosion and pitting."
The LER also stated that, "operation of the CAC units was directly into high fan
speed for normal operation." This statement did not address the fact that during
response to an accident, the two operating fans would shift from high to low
speed. Shifting from high to low speed was one of the factors mentioned in the
Part 21 report on the motors as causing motor failures. It also did not mention
that the motor on the normally operating CAC 1 was replaced during a mid-cycle
outage in 1999.
The licensee's conclusion that the effects of the degraded conditions on the heat
transfer capability of the CACs, when operating in conjunction with the CS
system did not address the fact that the CS system was also degraded due to
the previously identified sump issues.
During the review of this LER, the team identified additional issues concerning the
original motor sizing calculation and the lack of thermal relief valves on the CAC SW
piping inside containment as described in Sections 4OA3(3)b.3. Because of the overall
deficiencies in the licensee's evaluation, especially in regard to the thermal performance
issue, the team was unable to agree with the licensee's conclusion that the CACs were
operable during previous cycles.
Enclosure
91
The team determined that this LER will remain open pending further review of the CAC
degradation; specifically the extent of degradation and effect on the safety function of
the CACs. For this particular LER, the additional reviews will provide information as to
the ability of the CACs to provide cooling for the PORVs during feed and bleed
operations. The LER will remain open pending resolution of this issue.
.2
(Closed) LER 05000346/2002-009-00: Degradation of the High Pressure
Injection Thermal Sleeves
On November 29, 2002, with the reactor defueled, it was discovered that the thermal
sleeve connected to the 2-2 HPI /makeup nozzle had an axial crack. Inspection of the
2-1 HPI/makeup thermal sleeve also revealed a cracked thermal sleeve. No cracking
was observed during the inspection of the remaining two HPI thermal sleeves. The
licensee reported that the nozzles with undamaged thermal sleeves had not been used
for RCS makeup. The licensee determined that the axial cracks identified in the thermal
sleeves did not affect the ability of the HPI system to perform its design function nor did
either crack provide a source for RCS pressure boundary leakage. Furthermore, since
no loss of material occurred, this condition had no impact on the integrity of the fuel
cladding.
Upon discovery of the cracks in both thermal sleeves, the sleeves were removed and
new ones were installed. The licensee determined that high cycle thermal fatigue was
the root cause of the identified cracking. A contributing cause was the rate and
oscillation of makeup flow through the primary makeup nozzle. The licensee stated that
the appearance of the cracked sleeves was consistent with cases observed at other
B&W plants.
The remedial action was to replace the thermal sleeves. Inservice inspection
procedures were developed to ensure proper inspection techniques were used in the
future to verify the integrity of the HPI/makeup thermal sleeves. The licensee stated
that the visual inspections will include the use of high resolution video equipment and
verification that the video equipment was applied in accordance with ASME Section XI,
sub-article IWA 2210, Visual Exam for VT-1 Examination. The licensee stated that the
frequency of inspection would be every other refueling outage. This issue was entered
into the licensees CAP as CRs 02-09739, 02-9928, and 03-02445.
The team reviewed the licensee's corrective actions and determined them to be
acceptable. No violation of regulatory requirements was identified. This item is closed.
.3
(Closed) LER 05000346/2003-003-00 and -01: Potential Inadequate High
Pressure Injection Pump Minimum Recirculation Flow Following a Small Break
Loss of Coolant Accident
Introduction: The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion III,
having very low safety significance (Green). Specifically, the licensee failed to provide
for the original plant design to incorporate a safety-related recirculation path for the HPI
pumps in the HPR mode of operation. Following discovery, the licensee entered the
issue into its corrective action process.
Enclosure
92
Description: Following the questioning during the 2002 NRC SSDI inspection of a
potential deadhead condition of the HPI pumps and the adequacy of thermal protection
(minimum flow) for the pumps, the licensee performed a study, 86-5022260-00, to
determine whether HPI pump operability during post-LOCA sump recirculation could be
assured for all break sizes and transient scenarios.
This study identified a range of small break sizes from 0.00206 ft2 (leak-to-LOCA
transition area) to 0.0045 ft2, which would result in RCS re-pressurization cycles that
could continue following HPI pump realignment to the containment emergency sump
and closure of the minimum flow recirculation valves. The study concluded that for this
newly analyzed range of break sizes, past operability of the HPI pumps was a concern.
This was because the re-pressurization cycles would result in a higher RCS pressure
than the shut-off head of the HPI pumps, resulting in pump dead heading (no flow),
when HPI pump suction was from the sump. The licensee documented this condition in
CR 02-06702 and LER 05000346/2003-003. The condition existed since the original
design of Davis-Besse. The NRC had previously highlighted the potential for this
concern as part of Information Notice (IN) 85-94.
Based on the results of the evaluation, several corrective actions were implemented. An
additional minimum flow recirculation line was installed during RFO 13 for each HPI
pump. For one pump, the line tapped off the previously existing minimum flow line and
for the other a completely new recirculation line was installed. For both pumps, the new
lines contained two isolation valves and a non-cavitating pressure breakdown orifice and
connected to the low pressure injection (LPI) pump discharge upstream of its respective
decay heat cooler for the corresponding safety train. These additional recirculation lines
were designed to provide the original minimum flow protection of the HPI pumps,
35 gpm, when aligned to the emergency sump in "piggyback" operation with the DHR
pumps. In this lineup, the decay heat coolers would provide cooling for the respective
HPI Pumps without loss of sump inventory.
Operator action would be required to open the valves on these additional recirculation
lines prior to pump realignment from the BWST to the emergency sump. Because the
postulated transient was a very slow developing scenario, the team determined that
ample time would be available for operators to take this action. Additionally, the team
confirmed that this action did not replace any existing automatic action. The licensee
revised the emergency procedures to provide direction on establishing the HPI alternate
minimum recirculation flowpath and provided training to the operators on its use.
These corrective actions were deemed to be sufficient to resolve the concern addressed
in the LER. See Section 4OA3(3)b.1, for further discussion regarding the adequacy of
the 35 gpm minimum recirculation flow.
Analysis: The team determined that a performance deficiency existed because the
original design did not incorporate a safety-related recirculation path for the HPI pumps
in the high pressure recirculation (HPR) mode of operation. Since there was a
performance deficiency, the team compared this performance deficiency to the minor
questions contained in Appendix B, "Issue Screening," of IMC 0612, "Power Reactor
Inspection Reports." The team concluded that the issue was more than minor because
the licensee failed to provide for the original plant design to incorporate a safety-related
Enclosure
93
recirculation path for the HPI pumps in the HPR mode of operation and this finding
affected the mitigating systems cornerstone. The team reviewed this finding in
accordance with IMC 0609, "Significance Determination Process.
The Region III SRAs, evaluated this issue within Phase 1 of the SDP. Based on the
review, the SRAs determined that the HPR safety-function would not actually have been
lost because of reliance on procedure actions for feed and bleed operation of the PORV
in situations where the SGs could not be used to remove decay heat. Specifically, for
initiating events where RCS leakage was not sufficient to remove decay heat
(transients, small LOCAs) the Phase 2 SDP plant specific notebook for Davis-Besse
takes credit for opening of the non-safety-related PORV to remove decay heat from the
RCS. Opening of the PORV would allow sufficient HPR flow to ensure adequate
minimum flow to ensure pump cooling. Therefore, the finding screened out as having
very low safety significance (Green).
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis were correctly translated into specifications, drawings, procedures, and
instructions. Furthermore, it requires that measures be provided for verifying or
checking the adequacy of design, such as by the performance of design reviews, by the
use of alternate or simplified calculational methods, or by the performance of a suitable
testing program.
Contrary to the above, the licensee failed to provide for the original plant design to
incorporate a safety-related recirculation path for the HPI pumps in the HPR mode of
operation. The licensee documented this condition in CR 02-06702. These corrective
actions were deemed to be sufficient to resolve the concern addressed in the LER.
Since the issue was of very low safety significance and was captured in the licensee's
CR, it is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement
Policy. (NCV 05000346/2003010-29)
4OA4 Cross-Cutting Aspects of Findings
The teams findings and observations, as documented in this report, revealed numerous
examples where the licensees corrective action program exhibited implementation
weaknesses and a general lack of engineering rigor in the conduct of engineering
activities. These concerns further represent deficiencies relating to the cross-cutting
areas of human performance and corrective actions. Specific deficiencies and concerns
supporting this conclusion are documented in sections listed below.
Findings Affecting Human Performance
4OA3(2)b.2
Lack of 480 Vac Class 1E Motor Thermal Overload Protection
4OA3(3)b.6
Non-conservative Calculation Used in Design Analysis to Determine
Required Service Water Makeup Flow to Component Cooling Water
4OA3(3)b.11 Service Water Discharge Path Swapover Setpoint
4OA3(3)b.12 Service Water Discharge Check Valve Test Acceptance Criteria
4OA3(3)b.14 Auxiliary Feedwater System Calculation Issues With Main Steam Safety
Valves
Enclosure
94
4OA3(3)b.21 Environmental Qualification of Equipment Not Supported by Analysis
4OA3(3)b.23 Inappropriate Application of 10 CFR 50.59
4OA3(4)b
Repetitive Spacer Grid Strap Damage
Findings Affecting Corrective Action Program
4OA3(2)b.3
Failure to Perform Adequate Direct Current Contactor Testing to Ensure
Minimum Voltage at Motor Operated Valves
4OA3(2)b.4
Failure to Verify Adequacy of Short Circuit Protection for Direct
Current Circuits
4OA3(2)b.5
Lack of Calculations to Ensure Minimum Voltage Availability at
Device Terminals
4OA3(3)b.1
High Pressure Injection Pump Operation Under Long Term Minimum
Flow
4OA3(3)b.2
Increased Dose Consequences Due to Degraded Thermal Performance
Operation of Degraded Containment Air Coolers
4OA3(3)b.3
Containment Air Cooler Air Flow Calculation Concerns
4OA3(3)b.7
Calculation Concerns for Service Water Pump Room Ventilation System
4OA3(3)b.11 Service Water Discharge Path Swapover Setpoint
4OA3(3)b.12 Service Water Discharge Check Valve Test Acceptance Criteria
4OA3(3)b.13 Lack of Design Basis Calculations to Support Service Water Single
Failure Assumptions
4OA3(3)b.15 Auxiliary Feedwater Strainer Mesh Size and Preconditioning of Auxiliary
Feedwater System During Testing
4OA3(3)b.19 Inadequate Evaluation of Reactor Coolant Pump Casing-to-cover Stud
Overstressing
4OA3(4)b
Repetitive Spacer Grid Strap Damage
4OA3.(5)b.1
Process Monitoring Function for Alternative Shutdown Capability
4OA3.(5)b.2
Supporting Functions for Alternative Shutdown Capability
4OA5 Other Activities
(1)
Assessment of the Licensees Corrective Actions to Address Previously Identified
Findings Documented in NRC Reports
a.
Inspection Scope
The team conducted a review of previously identified items to determine effectiveness of
identification, evaluation and resolution of issues.
b.
Findings
.1
Follow up on Findings Documented in Report 05000346/2002012
.1
(Closed) URI 05000346/2002012-02: Potential Impact of Corrosion on the
Ground Function of Electrical Conduit in Containment
During a previous inspection conducted in October 2002, the NRC team noted that
corrosion appeared to be particularly concentrated in areas where moisture and boric
Enclosure
95
acid from the containment atmosphere had condensed and dripped onto electrical
components. In particular, the NRC team noted substantial corrosion and deposits of
crystallized boric acid on conduits. Based on this observation, the NRC team identified
a concern that boric acid corrosion of conduit may create a high electrical resistence
and challenge the ground function of the electrical conduit.
This condition was documented by the licensee in CR 02-06788. The CR described a
condition where boric acid corrosion of conduits in the containment could inhibit the flow
of ground fault currents through the conduits (conduits provide a supplementary
grounding path for smaller motors).
The cause analysis for CR 02-06788 determined that, as a general rule, up to 50
percent loss of conduit cross sectional area was acceptable without loss of function as
an electrical ground path. The conduits in question were determined to have only
surface corrosion amounting to less than 25 percent reduction in cross sectional area
and were therefore, deemed acceptable.
Subsequently, CR 03-05239 was issued stating that no loss in wall thickness was
acceptable for1/2-inch and 3/4-inch conduits. Ultrasonic testing was performed to
determine the wall thickness of corroded conduits; however, no decision had been made
as to resolution of this issue. Following questions by the team, the licensee determined
that all conduits were acceptable as-is. Based on this conclusion, the team determined
that no violation of NRC requirements existed. This URI is considered closed.
.2
(Closed) URI 05000346/2002012-03: Potential Failure to Follow the Procedure
for Raychem' Splice Removal on Electrical Cables
During CAC motor replacement, the licensee identified splitting of the motor cable
insulation as documented in CR 02-05459. The resolution of this issue is discussed in
Section 4OA3(2)b.6. The URI is closed.
.2
Follow-up on SSDI Findings Documented in Report 05000346/2002014
.1
(Discussed) NCV 05000346/2002014-01a: Lack of a Design Basis Analysis for
Containment Isolation Valve Backup Air Supplies
This violation was written to document an issue regarding the CAC outlet SW valves
reliance on the availability of the non-seismic instrument air system to maintain pressure
on the air operated valves so that they could perform their containment isolation function
to remain closed. The resolution of this issue is discussed in Section 4OA3(3)b.4.
.2
(Discussed) NCV 05000346/2002014-01b: Inadequate Blowdown Provisions for
Containment Air Cooler Backup Air Accumulators
This violation was written to document that there was no provisions to blow down the
CACs to remove excessive moisture as required by the USAR. The acceptability of the
corrective actions to this issue is discussed in Section 4OA3(3)b.5.
Enclosure
96
.3
(Closed) URI 05000346/2002014-01c: Failure to Perform Comprehensive
Moderate Energy Line Break Analysis
This item dealt with the licensees failure to perform a comprehensive moderate energy
line break analysis. The resolution of this issue is discussed in Section 4OA3(3)b.24.
The URI is closed.
.4
(Closed) URI 05000346/2002014-01d: Lifting of Service Water Relief Valves
This URI dealt with a continuing operating condition when the relief valves on the tube
(SW) side of the CCW heat exchangers would open when the licensee changed which
pump was operating under low flow conditions such as winter operation with low heat
loads. The licensee resolved the problem of inadvertent openings by changing the
operating procedures. The team concluded that relief valve lifting was not a concern
during a design basis event because there would be an increased heat load. This would
prevent the underlying pressure surge from occurring. No violation of NRC
requirements was identified. This item is closed.
.5
(Closed) URI 05000346/2002014-01e: Inadequate Service Water Pump Room
Temperature Analysis
This URI concerned non-conservatisms in the analysis which analyzed the heat loads in
the SW pump room and the ability of the ventilation system to maintain the pump room
temperatures within a required operating range. The resolution of this issue is
discussed in Section 4OA3(3)b.7. The URI is closed.
.6
(Closed) URI 05000346/2002014-01f: Inadequate Service Water Pump Room
Steam Line Break Analysis
This item dealt with the effects of a postulated auxiliary steam line break in the SW
pump room and whether the licensee correctly translated the USAR commitments
regarding the SW pump room environmental limits into analyses that demonstrated
these limits would not be violated for design basis conditions. This issue is discussed in
Section 4OA3(3)b.7. The URI is closed.
.7
(Closed) URI 05000346/2002014-01g: Inadequate Cable Ampacity Analysis
On September 24, 2002, the licensee issued CR 02-06893 to document an increase
from 95F to 124F in Rooms 105 and 115 temperature as a result of an increase of
SW temperature. The CR identified the need to reevaluate cable ampacity as a result of
the higher room temperature. The team discussed the ampacity issue with the licensee,
and determined there actually was not an ampacity concern. Therefore, this item is
considered closed.
Enclosure
97
.8
(Closed) URI 05000346/2002014-01h: Inadequate Flooding Protection for
Service Water Pump House
This URI dealt with deficiencies in correctly implementing USAR commitments regarding
flood protection for the SW pump room. The resolution of this issue is discussed in
Section 4OA3(3)b.9. The URI is closed.
.9
(Discussed) NCV 05000346/2002014-01i: Non-conservative Technical
Specification Value for 90 Percent Undervoltage Relays
The licensee initiated CR 02-07766 to address the issue that the trip set point specified
in calculation C-EE-004.01-049 was greater than the TS allowable value shown in Table
3.3-4. Therefore, the postulated TS allowable value could be violated for plant operating
conditions where the voltage was just above the relay set point value. The team
reviewed the issue and determined that the new calculation, C-EE-015.03-008, which
utilized the ETAP program, properly addressed all issues included in the CR. Therefore,
the corrective actions to this issue were deemed acceptable. Another issue related to
allowable values is discussed in Section 4OA3(2)b.1.
.10 (Closed) URI 05000346/2002014-01j: Poor Quality Calculation for 90 Percent
Undervoltage Relays
The licensee entered the issue into its CAP as CR 02-07633 which subsequently was
rolled over to CR 02-07646. In order to resolve the concern, the licensee performed a
new calculation, C-EE-015.03-008, to address this and other electrical issues. Review
of the calculation is discussed in Sections 4OA3(2)b.7 and 4OA5(1)b.2.11. This item is
closed.
.11 (Discussed) NCV 05000346/2002014-01k: Non-conservative Relay Setpoint
Calculation for the 59 Percent Undervoltage Relays
The licensee initiated CR 02-06737 and CR 02-07646 to evaluate issues affecting the
relay uncertainty in calculation C-EE-004.01.051. The postulated inconsistencies could
have rendered the operation of the 59 percent relay inconsistent with requirements for
continuous operation under-voltage transient conditions imposed by the motor inrush
current.
The team reviewed CR 02-07646 and determined that calculation C-EE-015.03-008,
which used the ETAP program described in Section 4OA3(2)b.7, had properly
addressed the postulated inconsistencies and non-conservative assumptions in the
uncertainty analysis. Therefore, the corrective actions to this issue were deemed
acceptable.
Enclosure
98
.12 (Closed) URI 05000346/2002014-01l: Inadequate Calculations for Control Room
Operator Dose (GDC-19) and Offsite Dose (10 CFR Part 100) Related to High
Pressure Injection Pump Minimum Flow Values
This URI addressed concerns with the dose calculations for operators and the general
public following a design basis accident. The resolution of this issue is discussed in
Section 4OA3(3)b.18. The URI is closed.
.13 (Closed) URI 05000346/2002014-01m: Other GDC-19 and 10 CFR Part 100
Issues
This URI addressed concerns with the dose calculations for operators and the general
public following a design basis accident. The resolution of this issue is discussed in
Section 4OA3(3)b.18. The URI is closed.
.14 (Closed) URI 05000346/2002014-01n: High Pressure Injection Pump Operation
Under Long Term Minimum Flow
This item dealt with the ability of the HPI pumps to perform as intended during extended
operation on minimum flow. This issue is discussed in Sections 4OA3(3)b.1 and
4OA3(6)b.2. This URI is closed.
.15 (Closed) URI 05000346/2002014-01o: Some Small Break Loss of Coolant
Accident Sizes Not Analyzed
This URI addressed concerns with the HPI pump potentially not having a flow path upon
the suction being switched from the BWST to the sump. This issue is discussed in
Section 4OA3(6)b.3. This URI is closed.
.16 (Closed) URI 05000346/2002014-01p: Inadequate Service Water System Flow
Analyses
This URI dealt with deficiencies in the assumptions used in SW system flow
calculations. The resolution of this issue is discussed in Section 4OA3(3)b.8. The URI
is closed.
.17 (Closed) URI 05000346/2002014-01q: Inadequate Service Water System
Thermal Analyses
This URI dealt with deficiencies in the maximum temperatures used in SW system and
ultimate heat sink calculations. The resolution of this issue is discussed in Sections
4OA3(3)b.8 and 4OA3(3)b.13. The URI is closed.
.18 (Closed) URI 05000346/2002014-01r: Inadequate Ultimate Heat Sink Inventory
Analysis
This URI dealt with deficiencies in the SW system flow and ultimate heat sink minimum
level calculations. The resolution of this issue is discussed in Sections 4OA3(3)b.8 and
4OA3(3)b.13. The URI is closed.
Enclosure
99
.19 (Closed) URI 05000346/2002014-01s: No Valid Service Water Pump Net
Positive Suction Head Analysis
This URI dealt with the licensee not having a calculation which showed that the SW
pumps had adequate NPSH under all operating conditions. The resolution of this issue
is discussed in Section 4OA3(3)b.8. The URI is closed.
.20 (Closed) URI 05000346/2002014-01t: Service Water Source Temperature
Analysis for Auxiliary Feedwater
This item dealt with SW source for AFW which had not been analyzed with respect to its
potentially higher temperature condition for various design basis events and the possible
impact on the ability of the AFW system to perform its safety function. Such effects
could include reduced heat absorption capability for AFW injected into the SGs and
inadequate cooling of AFW lubricating oil. The licensees evaluation concluded that
temperature of AFW (seismic event with long term AFW supplied by SW) was lower
than the design AFW temperature of 120F as noted in the system description. In
addition, the licensee determined that AFW equipment temperature limits were greater
than 120F. Therefore, the licensee concluded that there was no discrepant condition.
The team agreed with this assessment. This URI is closed.
.21 (Closed) URI 05000346/2002014-01u: Inadequate Short Circuit Calculations
This URI was written to document that the licensee had not considered the worst case
grid voltage. The resolution of this issue is discussed in Section 4OA3(2)b.8. The URI
is closed.
.22 (Discussed) NCV 05000346/2002014-01v: No Analytical Basis for Setpoint to
Swap Service Water System Discharge Path
There was no analytical basis for the setpoint used to swap the SW system discharge
path from the normally used, but non-seismic lines, to a seismically qualified path. The
setpoint for the swapover was 50 psig; however, there was no calculational bases for
this setpoint. The acceptability of the corrective actions to this issue is discussed in
Section 4OA3(3)b.11.
.23 (Discussed) NCV 05000346/2002014-02a: Service Water Surveillance Test Did
Not Use Worst Case Values
This violation addressed the fact that a surveillance test did not demonstrate that
worst-case post-accident conditions were bounded for the CAC discharge valves in the
SW system.
The licensee was replacing these valves, due to a number of problems with them. The
proposed corrective actions appeared to include appropriate acceptance criteria. The
team identified a concern with the original evaluation and corrective action wording in
CR 02-07781. The NCV writeup mentioned that the licensees procedure did not
declare the valves inoperable and write a CR if the valves failed the valve closure test.
This issue was not originally addressed in the licensees corrective actions. However,
Enclosure
100
when it was brought to the licensees attention, appropriate changes were made in the
procedure to address declaring the valve inoperable and writing CRs when necessary.
In responding to a team request for supporting calculations, the licensee also noted that
a corrective action for the CR 02-07781 was closed prior to a calculation being reviewed
and approved. Other examples where corrective actions were closed prior to the
calculations being approved are discussed in Sections 4OA3(3)b.17 and 4OA3(3)b.19.
.24 (Closed) URI 05000346/2002014-02b: Inadequate Service Water Flow Balance
Testing
This URI was written to document concerns with the flow balance testing for the SW
system. The resolution of this issue is discussed in Section 4OA3(2)b.10. This URI is
closed.
.25 (Closed) URI 05000346/2002014-03a: Inappropriate Service Water Pump Curve
Allowable Degradation
In the 2002 NRC SSDI, the team identified an item associated with prompt corrective
action to resolve a the licensee identified condition where the allowable degradation of
the SW pumps did not match the design basis required flow rate for the SW pumps. In
particular, the pump curve was allowed to degrade by 7 percent in accordance with IST
acceptance criteria, without evaluating the required design basis flow requirement.
Vendor calculations02-123 and 02-113 were performed to address all SW hydraulic
issues. The allowable SW pump degradation was included in the new calculations. The
team did not identify any violation. This URI is closed.
.26 (Closed) URI 05000346/2002014-03b: Repetitive Failures of Service Water
Relief Valves
This URI, URI 02-14-01d, and URI 02-14-06 all dealt with a continuing operating
condition where the relief valves on the tube (SW) side of the CCW heat exchangers
were opening under routine operating conditions, were failing due to the frequent
opening, and to the licensee's stated plans to resolve the problem by removal of the
valves from the system, contrary to the requirements of the ASME Code.
At the time of the inspection, the licensee had not yet removed the relief valves;
therefore, the issues raised by the URI still existed. The licensee had taken a number of
actions to reduce the frequency of undesired relief valve openings, primarily through
changes in the operating procedures. The licensee stated that these procedural
changes greatly decreased the times that the valves opened unexpectedly. The
reduction in inadvertent openings also resulted in a reduction of valve failures.
The team considered The licensees plans to remove the relief valves to be
inappropriate as the team did not believe the ASME Code allowed for the valves to be
removed. The team reviewed the applicable sections of both ASME Section III (the
Code section applicable to the SW piping) and ASME Section VIII (the Code section
under which the heat exchangers were purchased). Both sections clearly indicated that
overpressure protection was required for any piping where heat was being introduced
into the system. As the SW system was the cooling mechanism for the CCW heat
Enclosure
101
exchangers, heat was being introduced into the system, and overpressure protection
was required. The team also noted that the licensee had manual valves downstream of
the relief valves on the CCW heat exchangers; another area which was not in strict
compliance with the Code. Subsequent to the inspection, the licensee informed the
team that a decision had not been made to replace the subject valves. Since the
licensee has not removed the valves from service, this URI is closed.
The issues regarding URI 50-345/2002014-06 will be addressed in a separate report.
.27 (Closed) URI 05000346/2002014-03c: Non-conservative Difference in Ultimate
Heat Sink Temperature Measurements
This URI dealt with a potential non-conservative temperature measurement for ultimate
heat sink temperatures. The concern was that the temperature instrument used to
measure the ultimate heat sink temperature might not be the most conservative and
might contain up to 2F of error, which was not accounted for in the SW design basis
calculations.
The licensee performed a test which measured the temperature of the ultimate heat sink
in two different locations - the normal input for the computer point, and a second one
which had been reading higher during the October inspection - using sensitive,
calibrated measuring and test equipment. Based on this test, the licensee determined
that the two locations were reading the same temperature, at least at the time of the
test. The licensee also noted that the normal temperature instrument had a much
tighter accuracy band (0.75F) as compared to the other instrument (3F) such that,
even if the second instrument appeared to be reading higher, it might actually be below
the actual ultimate heat sink temperature.
The team determined that the licensees procedures had been revised to incorporate the
temperature instruments uncertainty calculation results into them, and that the
procedures required the plant to take appropriate actions should it appear that the
ultimate heat sink temperature was being approached (such as measuring the
temperature locally with sensitive measuring and test equipment). Therefore, the team
determined that no violation existed. This URI is closed.
.28 (Discussed) NCV 05000346/2002014-03d: Inadequate Corrective Actions
Related to Service Water Pump Discharge Check Valve Acceptance Criteria
This violation addressed an inadequate corrective action in that the acceptance criterion
for the inservice full flow test for the SW pump discharge check valves was determined
to be non-conservative, was corrected, and the new value was still not the full design
flow rate. The acceptability of the corrective actions to this issue is discussed in Section
4OA3(2)b.12.
.29 (Closed) URI 05000346/2002014-03e: Non-conservative Containment Air
Cooler Mechanical Stress Analysis
This item dealt with overestimation of nozzle flexibility by a factor of one thousand when
analyzing the connection of the SW system to the CACs. This item was also briefly
discussed in the section for LER 05000346/2002-008-00 and -01.
Enclosure
102
Stress analyses concluded that the CACs were operable in the past regarding structural
concerns identified in CR 02-05563. The structural report concluded that, "...Based on
the lack of significance or the continued structural acceptability identified with the
numerous finding associated with the CAC coil modules and their support structure, the
CAC operability assessment is considered to be unaffected by the composite findings of
all currently identified, structural-related CAC concerns. The team determined that the
licensee appropriately used ASME Code F stress criteria in the structural analysis. This
item is closed.
.30 (Discussed) NCV 05000346/2002014-04: Failure to Perform Technical
Specification Surveillance for High Pressure Injection Pump Following
Maintenance
This item dealt with the failure to perform a surveillance in accordance with TS 4.5.2.H
for HPI pump following maintenance. This TS could not be directly verified by test since
system pressure could not be easily held at 400 pounds per square inch, absolute
during full HPI injection. The licensee requested a TS amendment (No. 256) to relocate
the surveillance requirement pertaining to flow balance testing of the HPI and LPI
subsystems following system modifications to the technical requirement manual. Also,
the amendment added ECCS pump operability conditions to the TS. The new
surveillance requirement would require verifying each ECCS pumps developed head to
be greater than or equal to the required developed head, when tested pursuant to TS
4.0.5 with regards to inservice testing requirements of the ASME Code. The team had
no further concerns and did not identify other new issues.
.31 (Closed) URI 05000346/2002014-05: Question Regarding Definition of a
Passive Failure
This URI dealt with the question on whether stem-to-disc separation of SW valve SW-82
was credible and whether stem-to-disc separation was required to be assumed as part
of a passive failure analysis. The team determined that valve SW82 was a butterfly
valve. Even if stem-to-disc separation occurred, it was extremely unlikely that flow
would be blocked. Therefore, the team determined that this failure mode was not
credible and did not need to be considered as part of a passive failure analysis. As
discussed in Sections 4OA3(3)b.11 and 4OA3(3)b.13, the team identified other
concerns with the licensee's consideration of passive failure assumptions; these
concerns are addressed separately. This URI is closed.
.3
Follow-up on SSDI Findings Documented in Report 05000346/2002019
(Closed) URI 05000346/2002019-031: Final Evaluation of Apparent Cause
Evaluation for LER 05000346/2002-006-00
This URI was opened to track the licensee's resolution of the issues identified in LER
05000346/2002-006 on EDG exhaust stack tornado protection. This issue is discussed
in Section 4OA3(3)b.23, of this report. This URI is closed.
Enclosure
103
.4
Follow up on Augmented Inspection Team Findings Documented in the Cover
Letter of Report 05000346/2003016
In the cover letter of IR 05000346/2003016, a number of URIs identified in IR
05000346/2002008 were converted from URIs to apparent violations (AVs). The
numbering of the individual items remained the same. The team reviewed the status of
each of the AVs, as documented below.
.1
(Discussed) AV 05000346/2003016-01: Technical Specification Reactor Coolant
System Pressure Boundary Leakage
Introduction: The NRC team examined corrective actions for an AV of the Davis-Besse
TS associated with operation of the plant with pressure boundary leakage from
through-wall cracks in the RCS.
Description: The team determined that this AV was a product of the licensees cultural
and programmatic breakdowns. Operation with pressure boundary leakage beyond the
TS action statement was a direct result of the licensees failure to identify the control rod
drive mechanism leakage. The cultural issues involved the failure to take appropriate
corrective actions, to follow procedures, and to have appropriate procedures; issues that
were identified in the subsequent findings of the AIT follow-up report. The specific
programmatic issues were identified in LER 05000346/2002-002-00 as an inadequate
BACC program and inadequate implementation of the ISI program.
Corrective actions for the cultural failures were addressed by globally by the licensees
management and human performance improvement plan and the program compliance
plan. Corrective actions for the failure to take appropriate action were specified under
CR 02-00891 and directed a complete overhaul and re-institution of the CAP. The
NRCs assessment of the effectiveness of those actions is discussed in Sections 4OA2
and 4OA3 of this report.
Corrective action for the inadequate BACC program is discussed below in Section
4OA5(1)b.4.8. Inadequate implementation of the ISI program was addressed through
licensee self-assessment 2002-081 and a Phase 2 program review by the project review
committee (PRC).
Analysis: This issue represented a licensee performance deficiency because the
licensee had multiple opportunities over a period of years to identify the leakage;
consequently it was considered a finding. This finding was of more than minor safety
significance because the RCPB and resultant cavity in the reactor vessel head
represented a loss of the design basis barrier integrity. Two cornerstones were
impacted by this issue. The barrier integrity cornerstone was affected because the
through-wall CRDM cracks compromised the RCPB and the initiating events
cornerstone was impacted because cracking of the CRDM nozzles resulted in an
increase in the likelihood of a LOCA.
Enforcement: Davis-Besse TS, "Limiting Condition for Operation for Reactor Coolant
System Operational Leakage," Paragraph 3.4.6.2, stated, in part, that RCS leakage
shall be limited to no pressure boundary leakage, and that with any pressure boundary
Enclosure
104
leakage, the unit was to be in cold shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This issue was properly
addressed by the licensees CAP; however, corrective actions were only one of the
inputs into the final characterization and resolution of this item. The NRCs investigation
into the cause of this AV, which was referred to the Office of Investigations (OI), is still
ongoing. The results of that investigation will be factored into the final enforcement
deliberations. As a result, this item remains open.
.2
(Discussed) AV 05000346/2003016-02: Reactor Vessel Head Boric Acid
Deposits
Introduction: The NRC team examined corrective actions for three AVs involving failure
to take appropriate corrective actions for continuing or recurrent deficiencies associated
with boric acid deposits on the reactor vessel head, boric acid deposits on the CACs,
and clogging of radiation element filters.
Description: The team determined that these AVs were a product of the licensees
cultural and programmatic breakdowns. To understand the licensees approach to
correcting these problems, the team examined the licensees root cause analysis report
on failure to identify significant degradation of the reactor pressure vessel head. The
causal factors for these issues were addressed in the root cause report and included:
Less than adequate safety focus;
Less than adequate implementation of the CAP; and
No safety analysis performed for the existing condition.
Corrective actions for the cultural failure associated with the inadequate safety focus
were addressed by globally by the licensees management and human performance
improvement plan and the program compliance plan. These were spelled out as
corrective actions to CR 02-00891. Among the corrective actions for these safety
culture issues were:
Corrective Action 22: Development of a management field
presence/involvement plan to improve management oversight;
Corrective Action 41: Formal assessment of the safety conscious work
environment at the plant based on criteria and attributes derived from NRC policy
and guidance;
Corrective Action 42: Changes in corporate and plant senior management;
Corrective Action 45: Development of a management monitoring process to
monitor and trend the performance of specific management oversight activities;
Corrective Action 46: Case study training for site personnel to include how the
event happened, what barriers broke down, and what must be different in the
future;
Enclosure
105
Corrective Action 74: Realignment of management incentives to place more
reward for safety and safe operation of the station; and
Corrective Action 75: Establish corporate-wide policy emphasizing the stations
industrial and nuclear safety philosophy.
Corrective actions for the failure to properly implement the CAP or to perform requisite
safety analyses were specified under CR 02-00891. These directed a complete
overhaul and re-institution of the CAP. To ensure that safety analyses were performed
as needed, corporate standards for analyses of safety issues were established and the
use of a safety precedence sequence for root cause analyses was mandated. This was
confirmed by the team and considered adequate.
The root cause report also identified other, more discrete, issues associated with these
AVs. These included:
Addressing symptoms rather than causes;
Performing less than adequate cause determinations; and
Having less than adequate corrective actions.
These were also addressed through corrective actions associated with CR 02-00891.
Some of the corrective actions included a case study of this event with an emphasis on
the need to find and address the causes of adverse conditions and the potential
consequences of failure to do so, implementation of the CARB to assess adequacy of
actions and enforce higher standards for cause evaluations and corrective actions,
mandating the use of formal root cause techniques coupled with independent reviews
and self-assessments of cause evaluations, and improvements in effectiveness reviews
with emphasis on verifying that causes have been properly addressed. These were
confirmed by the team.
The NRCs assessment of the licensees effectiveness in implementing the revised CAP
and the specific actions noted above is discussed in Sections 4OA2 and 4OA3 of this
report.
Analysis: This issue represented a performance deficiency because the licensee failed
to properly address, either individually or collectively, the cause for the continuing
accumulation of large amounts of boric acid on the reactor head, the recurrent
deposition of boric acid on CAC fins, and the repeated clogging of radiation element
filters. This lack of adequate corrective action on the licensees part contributed to their
failure to detect existing through-wall CRDM nozzle cracks and the reactor pressure
vessel head corrosion. This finding is more than minor because it affected the initiating
events cornerstone objective in that cracking of CRDM nozzles represented an increase
in the likelihood of a LOCA. The barrier integrity cornerstone was also affected in that
CRDM cracks resulted in leakage through the RCPB.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that
conditions adverse to quality be promptly identified and corrected, commensurate with
Enclosure
106
their safety significance. Criterion XVI also requires that, for significant conditions
adverse to quality, the measures assure that the cause of the condition is determined
and that corrective actions were taken to preclude repetition.
The team determined that the failure to properly address the continuing accumulation of
large amounts of boric acid on the reactor head, the recurrent deposition of boric acid
on CAC fins, and the repeated clogging of radiation element filters, significant conditions
adverse to quality, contributed to the corrosion of the reactor head. These issues have
been properly addressed by the licensees CAP; however, corrective actions were only
one of the inputs into the final resolution of this item.
The NRCs investigation into the cause of this AV, which was referred to OI, is still
ongoing. The results of that investigation will be factored into the final enforcement
deliberations. As a result, these items remain open.
.3
(Discussed) AV 05000346/2003016-03: Containment Air Cooler Boric Acid
Deposits
This issue is included as part of the discussion in Section 4OA5(1)b.4.2 above.
.4
(Discussed) AV 05000346/2003016-04: Radiation Filter Element Deposits
This issue is included as part of the discussion in Section 4OA5(1)b.4.2 above.
.5
(Discussed) AV 05000346/2003016-05: Service Structure Modification Delay
Introduction: The NRC team examined corrective actions for the licensees failure to
implement a modification that would have permitted complete inspection and cleaning of
the reactor vessel head and control rod drive mechanism nozzles.
Description: This issue addressed the licensees repeated deferral of the modification to
install multiple access ports in the service structure to permit cleaning and inspection of
the reactor head. Modification 90-0012 was initiated in March 1990 to accomplish this
but was deferred twice and then canceled in 1993. The modification was reinitiated in
May 1994 as 94-0025 and subsequently deferred four times before the head
degradation was identified in 2002.
The licensee resolved one portion of the issue through installation of the modification.
The repeated deferral was broadly addressed through the management and human
performance improvement plan and the program compliance plan as part of the
licensee's itinerary to improve safety culture. The specific issue of deferring
modifications for economic reasons was addressed by corrective actions under
CR 02-00891 for a revision to the PRC charter. The revision incorporated a requirement
to include nuclear safety in the considerations when reviewing a plant modification.
Analysis: This issue represented a performance deficiency because the licensee failed
to take corrective action (install the access port modification) for a condition adverse to
quality. As of February 16, 2002, the modification had not been performed, the head
had not been completely inspected, and the head had not been completely cleaned.
Enclosure
107
This lack of action on the licensees part, contributed to their failure to detect existing
through-wall CRDM nozzle cracks.
This finding is more than minor because it affected the initiating events cornerstone
objective in that cracking of CRDM nozzles represented an increase in the likelihood of
a LOCA. The barrier integrity cornerstone was also affected in that CRDM cracks
resulted in leakage through the RCPB. Furthermore, the failure to provide for adequate
inspection and cleaning of the head was a contributing factor to the head degradation.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that
conditions adverse to quality be promptly identified and corrected. Criterion XVI also
requires that for significant conditions adverse to quality, the measures shall assure that
the cause of the condition is determined and that corrective actions were taken to
preclude repetition.
The licensee failed to correct the condition identified on April 21, 1996 (inability to fully
inspect the head and CRDM nozzles), in that, as of February 16, 2002, the corrective
action (modification of the service structure) had not been accomplished. Although
corrective actions were completed prior to the end of the inspection, corrective actions
were only one of the inputs into the final characterization and resolution of this item.
The NRCs investigation into the cause of this AV, which was referred to OI, is still
ongoing. The results of that investigation will be factored into the final enforcement
deliberations. As a result, this item remains open.
.6
(Discussed) AV 05000346/2003016-06: Reactor Coolant System Unidentified
Leakage Trend
Introduction: The NRC team examined corrective actions for a finding involving failure
to follow the corrective action procedure and complete a prescribed corrective action for
adverse trends in RCS unidentified leakage.
Description: This URI addressed the licensees cancellation of a Mode 3 walkdown that
was the proposed corrective action for an adverse trend in RCS unidentified leakage.
Several months prior to the shutdown for the 2002 refueling outage the licensee had
been examining increases in RCS leakage and as part of an extensive investigation, a
walkdown of the containment while the plant was at NOP/NOT had been specified. The
reason for canceling the walkdown was schedule-driven; a special Mode 3 walkdown
would have delayed cooldown and entry into the lower modes required to begin
refueling.
The team concluded that the root cause for this was the licensees cultural and
programmatic breakdowns. The licensees root cause analysis report pointed to the
following causal factors:
Less than adequate safety focus;
Less than adequate implementation of the CAP; and
Less than adequate corrective actions.
Enclosure
108
Corrective actions for the cultural failure associated with the inadequate safety focus
were addressed globally by the licensees management and human performance
improvement plan and the program compliance plan and are discussed in Section
4OA5(1)b.4.2 above. Corrective actions for the failure to properly implement the CAP
were specified under CR 02-00891. These directed a complete overhaul and
re-institution of the CAP. The NRCs assessment of the licensees effectiveness in
implementing the revised CAP and the specific actions noted above is discussed in
Sections 4OA2 and 4OA3 of this report.
Analysis: This issue represented a the licensee performance deficiency because
elimination of a key component of what was an adequate proposed corrective action
rendered the proposal inadequate. Consequently, this was considered a finding
because it was reflective of other corrective action deficiencies which contributed to the
cavity in the reactor vessel head. This finding was of more than minor safety
significance because the corrosion of the reactor head and the resulting cavity
represented a significant loss of the design basis barrier integrity.
Enforcement: The licensee failed to follow the corrective action procedure and
implement an effective corrective action for adverse trends in RCS unidentified leakage.
Although corrective actions have now been completed, corrective actions were only one
of the inputs into the final characterization and resolution of this item.
The NRCs investigation into the cause of this finding, which was referred to OI, is still
ongoing. The results of that investigation will be factored into the final enforcement
deliberations. As a result, this item remains open.
.7
(Discussed) AV 05000346/2003016-07: Inadequate Boric Acid Corrosion
Control Program Procedure
Introduction: The NRC team examined corrective actions for the licensees failure to
have a BACC program procedure appropriate to the circumstances.
Description: The AIT follow-up inspection and the licensees root cause report identified
multiple deficiencies in the licensee's BACC program procedure which contributed to the
degradation of the reactor head. As part of the licensees program compliance plan, the
BACC program procedure was completely revised and subjected to a phase 2 PRB
review. The program compliance plan, the PRC review, and the revised BACC program
procedure were inspected and accepted by NRC; this inspection was documented in IR 05000346-03-09;05000346-03-11.
Analysis: This issue represented a the licensee performance deficiency because the
weaknesses in the procedure contributed to the failure, over a period of years, by the
licensees engineering staff to properly identify and evaluate the leaking CRDM nozzle
and the expanding cavity in the reactor head. This finding is more than minor because it
affected the initiating events cornerstone objective in that cracking of CRDM nozzles
represented an increase in the likelihood of a LOCA. The barrier integrity cornerstone
was also affected in that CRDM cracks resulted in leakage through the RCPB.
Enclosure
109
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V, states, in part, 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.
NG-EN-00324, "Boric Acid Corrosion Control Program," Revisions 0 through 2, were
classified as a quality procedure under the licensees procedure administrative system
and were not appropriate to the circumstances in that deficiencies in the procedure
contributed to the failure to detect and address corrosion of the reactor head. Although
corrective actions have now been completed, corrective actions were only one of the
inputs into the final characterization and resolution of this item.
The NRCs investigation into the cause of this AV, which was referred to OI, is still
ongoing. The results of that investigation will be factored into the final enforcement
deliberations. As a result, this item remains open.
.8
(Discussed) AV 05000346/2003016-08: Failure to Follow Boric Acid Corrosion
Control Program Procedure
Introduction: The NRC team examined corrective actions for two AVs involving failure to
follow the boric acid corrosion control program procedure and the corrective actions
program procedure.
Description: These URIs involved failure by the licensee engineering staff to follow:
A number of requirements of the BACC program procedure, most notably the
requirement to remove all boric acid and examine the base metal underneath for
signs of corrosion; and
The guidance and examples for characterization of CRs as significant, important,
routine, or non-conditions adverse to quality and, as a result, repeatedly
mis-characterized the conditions on the reactor head as routine.
The team reviewed the sections of the licensees root cause report which acknowledged
these two issues, the section of the root cause report which outlined corrective actions,
and the corrective action specified under CR 02-00891. To correct the failure to follow
the boric acid corrosion control program procedure, the licensee developed these
specific actions:
Provide training to applicable personnel and mangers on the need to remove
boric acid from components, to inspect for signs of corrosion, and to perform
inspections for signs of boric acid in component internals; and
Reinforce standards and expectations for procedure compliance and the need
for work practice rigor.
These were part of the licensees global approach to the safety culture issue as part of
the management and human performance improvement plan and the program
compliance plan.
Enclosure
110
In the root cause, the licensee acknowledged that CRs associated with the reactor head
and other boric acid conditions were categorized as relatively low, which resulted in the
use of superficial cause analysis techniques. To address this, the licensee developed
two corrective actions:
Establish and ensure that criteria for categorization of the significance of repeat
equipment failures were appropriate and used by station personnel. Criteria
were to be sufficient to elevate repeat problems to higher levels, which require
use of more robust analyses; and
Review existing long-standing issues for possible elevation to significant
condition status, thus engaging formal root cause evaluation techniques to
obtain resolution of the issues.
As part of the program compliance inspection and the corrective actions team
inspection, both of these actions were verified to have been satisfactorily completed.
Analysis: This issue represented a performance deficiency because the recurrent
failures, by the licensees engineering staff, to follow the BACC program and CAP
procedures resulted in the perpetuation of the CRDM nozzle leak and the development
of the expanding cavity in the reactor head. This finding was of more than minor safety
significance because the cavity in the reactor vessel head represented a loss of the
design basis barrier integrity.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V states, in part, 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.
The licensees engineering staff failed, on multiple occasions, to adhere to both the
BACC program and the CAP procedures. Although corrective actions have now been
completed, corrective actions were only one of the inputs into the final characterization
and resolution of this item.
The NRCs investigation into the cause of this AV, which was referred to OI, is still
ongoing. The results of that investigation will be factored into the final enforcement
deliberations. As a result, this item remains open.
.9
(Discussed) AV 05000346/2003016-09: Failure to Follow Corrective Action
Program Procedure
This item is included as part of the discussion in Section 4OA5(1)b.4.8 above.
(2)
Closure of Restart Checklist Items
.1
Restart Checklist Item 2.c: Structures, Systems, and Components Inside
Containment
As part of the corrective actions resulting from the reactor vessel head degradation, the
licensee established a return to service plan to identify, monitor, and control all actions
Enclosure
111
necessary for the safe and reliable return to service of Davis-Besse. The plan consisted
of seven building blocks designed to support safe and reliable restart of the plant and to
ensure sustained performance improvements. One of the building blocks, "Containment
Extent of Condition Program," was tasked with evaluating and dispositioning the extent
of condition throughout the RCS and containment systems, structures, and components
relative to the degradation mechanisms that occurred on the reactor vessel head.
IR 05000346/2002009 reviewed the licensees plan for inspections, including methods,
control of walkdown boundaries, resolution of obstructed examinations, and control of
inspection records. Two findings of very low safety significance were identified. The
first was associated with lack of acceptance criteria and the second was associated with
inadequate training and certification of inspection personnel. Weaknesses were
identified in the licensees implementation of the containment inspection program.
IR 05000346/2002012 focused on evaluating corrective actions for the issues previously
identified. This inspection concluded that the above issues were adequately resolved
and that the inspections were effectively implemented. Three URIs associated with
corrective actions for corrosion of electrical conduit, potential leakage of reactor vessel
bottom head incore instrumentation penetrations, and failure to follow the procedure for
Raychem' splice removal on electrical cable were identified. Restart Checklist Item 2.c
was held open pending review of these URIs.
Unresolved item 05000346/2002012-01 was discussed and closed in IR 05000346-03-23. The NRC reviewed the licensees activities to resolve the potential
leakage of reactor vessel bottom head incore instrumentation penetrations. The
licensee performed chemical analysis of the deposits found on the reactor vessel sides
and bottom, and in a July 30, 2003, letter to the NRC, concluded that the deposits did
not result from leakage from the penetrations. Additionally, the bottom head was
inspected for signs of leakage after completion of the seven day NOP/NOT leak test.
This test provided reasonable assurance that the bottom head penetrations were not
leaking.
Unresolved item 05000346/2002012-02 concerning corrosion of electrical conduit is
discussed and closed in Section 4OA5(1)b.1.1 of this report.
Unresolved item 05000346/2002012-03 concerning removal of Raychem' splices from
electrical cable is discussed in Section 4OA3(2)b.6 and the URI is closed in Section
4OA5(1)b.1.2.
On November 18, 2003, the Davis-Besse Oversight Panel met to discuss this issue and
concluded that Restart Checklist Item 2.c is closed.
.2
Restart Checklist Item 3.a: Corrective Action Program
As part of the corrective actions resulting from the reactor vessel head degradation, the
licensee established a return to service plan to identify, monitor, and control all actions
necessary for the safe and reliable return to service of Davis-Besse. A key element of
the return to service plan was for the licensee to reestablish and reinvigorate the CAP to
ensure that future conditions adverse to quality were properly identified, evaluated and
Enclosure
112
corrected. The NRC performed a review of the CAP which was documented in NRC
Inspection Report Nos. 50-346/02-11 and 50-346/03-09 and found the program to be
acceptable. Restart Checklist item 3.a was left open following these inspections,
pending completion of the CATI.
The main function of the CATI inspection, described in the report above, was to evaluate
the licensees effectiveness in correcting the deficiencies in the CAP. As noted in the
previous sections of the report, the team identified numerous deficiencies still existing
within the CAP. Nevertheless, the team concluded that the licensees corrective actions
were acceptable to support plant restart.
These deficiencies were discussed with the licensee during two public meetings, one on
November 12, and a second on December 10, 2003. As part of these meetings, the
licensee made a number of commitments to further improve the CAP as part of its
Operational Improvement Plan for Cycle 14, Revision 2.
The team presented the results of this inspection to the NRC Davis-Besse Oversight
Panel on February 5, 2004. The panel concluded that, based upon the licensees
improvement plans, Restart Checklist Item 3.a could be closed.
.3
Restart Checklist Item 5.b: Systems Readiness for Restart
As part of the corrective actions resulting from the reactor vessel head degradation, the
licensee established a return to service plan to identify, monitor, and control all actions
necessary for the safe and reliable return to service of Davis-Besse. One of the key
elements of this return to service plan was a systematic review of a number of
safety-related systems.
Concurrent with the licensees initial evaluation of the systems, the NRC performed a
SSDI as documented in IR 05000346/2002014. This inspection identified a large
number of NCVs and URIs which required resolution to ensure system operability prior
to restart. As part of this inspection effort, the team evaluated the adequacy of the
licensees corrective actions to address and resolve the identified deficiencies.
The teams findings and conclusions documented in this report revealed weaknesses in
the licensees implementation of corrective actions and in the engineering rigor to
address and resolve identified deficiencies. Throughout the inspection, the team also
made observations and reached conclusions regarding the safety significance of the
identified deficiencies and ability of affected components to perform the intended design
function. Concerns and issues were presented to the licensee for entry into their
corrective action program and final implementation of corrective actions. The teams
inspection did not reach a conclusion regarding the readiness of systems to support
restart since during the teams inspection, the licensee was still in the process of
returning systems to functional and operational status. Therefore, restart checklist item
5.b remains open, and will be further addressed in a separate NRC inspection report.
Enclosure
113
4OA6 Management Meetings
Exit Meeting Summary
The team presented the inspection results to Mr. L. Myers and other members of
licensee management and staff at the conclusion of the inspection on September 9,
2003. The licensee acknowledged the information presented.
Per the licensees request, on November 10, 2003, the team presented the latest
inspection results, during a telephone conference, to Mr. L. Myers and other members of
the licensee management and staff. The licensee acknowledged the information
presented.
On January 7, 2004, the team held a telephone exit with the licensee in regard to the
HPI minimum flow issue discussed in Section 4OA3(3)b.1.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
M. Bezilla, Site Vice President
B. Boles, Manager, Plant Engineering
K. Byrd, Supervisor, Design Engineering
L. Dohrmann, Manager, Performance Improvement
J. Grabnar, Manager, Design Engineering
L. Griffith, Manager, Employee Concern Program
D. Gudger, Supervisor, Regulatory Affairs
J. Hagan, Senior Vice President, FENOC
G. LeBlanc, Supervisor, Design Engineering
S. Loehlein, Manager, Nuclear Quality Assurance
W. Marini, Regulatory Interface
M. Marler, Training Manager
L. Myers, Chief Operating Officer, FENOC
K. Ostrawski, Manager, Regulatory Affairs
W. Pearce, Vice President, Oversight
J. Powers, Director, Nuclear Engineering
C. Price, Manager, Business Services
J. Rinckez, Director, Nuclear Fuel
R. Schrauder, Director, Support Services
L. Strauss, Analyst, Regulatory Affairs
J. Sturdavant, Regulatory Affairs
Nuclear Regulatory Commission
R. Gardner, Senior Project Manager, Division of Reactor Safety
J. Grobe, Chairman, Davis-Besse Oversight Panel
J. Lara, Branch Chief, Electrical Engineering Branch, Division of Reactor Safety
C. Lipa, Chief, Reactor Projects Branch 4
W. Ruland, Senior Project Manager, NRR
J. Rutkowski, Resident Inspector
S. Thomas, Senior Resident Inspector
Attachment
A2
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
Failure to Take Corrective Actions for a Previous NCV
Concerning SW Discharge Path Swapover Setpoints
(Section 4OA3(3)b.11)05000346/2003010-02
Failure to Take Corrective Actions for a Previous NCV
Concerning SW Pump Discharge Check Valve
Acceptance Criteria (Section 4OA3(3)b.12)
Open and Closed in This Report
Undervoltage Time Delay Relay Setting Did Not Account
For Instrument Uncertainties (Section 4OA3(2)b.1)05000346/2003010-04
Lack of 480 Vac Class 1E Motor Thermal Overload
Protection (Section 4OA3(2)b.2)05000346/2003010-05
Failure to Perform Adequate Direct Current Contactor
Testing to Ensure Minimum Voltage at Motor Operated
Valves (Section 4OA3(2)b.3)05000346/2003010-06
Failure to Verify Adequacy of Short Circuit Protection for
Direct Current Circuits (Section 4OA3(2)b.4)05000346/2003010-07
Lack of Calculations to Ensure Minimum Voltage
Availability at Device Terminals (Section 4OA3(2)b.5)05000346/2003010-08
Failure to Verify Adequacy of HPI Minimum Recirculation
Line Design (Section 4OA3(3)b.1)05000346/2003010-09
Increased Dose Consequences Due to Degraded Thermal
Performance Operation of Degraded CAC (Section
4OA3(3)b.2)05000346/2003010-10
Containment Air Cooler Air Flow Calculation Concerns
(Section 4OA3(3)b.3)05000346/2003010-11
Accumulator Sizing Calculation Errors (Section
4OA3(3)b.4)05000346/2003010-12
Non-conservative Calculation Used in Design Analysis to
Determine Required Service Water Makeup Flow to
Component Cooling Water (Section 4OA3(3)b.6)05000346/2003010-13
Calculation Concerns for Service Water Pump Room
Ventilation System (Section 4OA3(3)b.7)
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED, cont
Attachment
A3
Inadequate Service Water System Flow Analysis (Section
4OA3(3)b.8)05000346/2003010-15
Inadequate Flooding Protection for the Service Water
System (Section 4OA3(3)b.9)05000346/2003010-16
Inadequate Service Water System Flow Balance Testing
Procedure (Section 4OA3(3)b.10)05000346/2003010-17
Lack of Design Basis Calculations to Support Service
Water Valve Single Failure Assumptions (Section
4OA3(3)b.13)05000346/2003010-18
Auxiliary Feedwater System Calculation Issues With Main
Steam Safety Valves (Section 4OA3(3)b.14)05000346/2003010-19
Preconditioning of Auxiliary Feedwater System During
Testing (Section 4OA3(3)b.15)05000346/2003010-20
Borated Water Storage Tank Calculation Issues (Section
4OA3(3)b.18)05000346/2003010-21
Inadequate Evaluation of Reactor Coolant Pump
Casing-to-cover Stud Overstressing (Section
4OA3(3)b.19)05000346/2003010-22
ECCS Motors Not Qualified for Service Time (Section
4OA3(3)b.21)05000346/2003010-23
Inappropriate Application of 10 CFR 50.59 (Section
4OA3(3)b.23)05000346/2003010-24
Failure to Perform Comprehensive Moderate Energy Line
Break Analysis (Section 4OA3(3)b.24)05000346/2003010-25
Repetitive Spacer Grid Strap Damage (Section 4OA3(4)b)05000346/2003010-26
Process Monitoring Function for Alternative Shutdown
Capability (Section 4OA3(5)b.1)05000346/2003010-27
Supporting Functions for Alternative Shutdown Capability
(Section 4OA3(5)b.2)05000346/2003010-28
Emergency Diesel Generator Floor Drains Design
Deficiency (Section 4OA3(5)b.3)
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED, cont
Attachment
A4
Failure to Provide HPI Recirculation Line (Section
4OA3(6)b.3)
Closed
05000346/2002-009-00
LER
Degradation of the High Pressure Injection Thermal
Potential Impact of Corrosion on the Ground Function of
Electrical Conduit in Containment
Potential Failure to Follow the Procedure for Raychem'
Splice Removal on Electrical Cables
05000346/2002014-01c
Failure to Perform Comprehensive Moderate Energy Line
Break Analysis
05000346/2002014-01d
Lifting of Service Water Relief Valves
05000346/2002014-01e
Inadequate Service Water Pump Room Temperature
Analysis
05000346/2002014-01f
Inadequate Service Water Pump Room Steam Line Break
Analysis
05000346/2002014-01g
Inadequate Cable Ampacity Analysis
05000346/2002014-01h
Inadequate Flooding Protection for Service Water Pump
House
05000346/2002014-01j
Poor Quality Calculation for 90 Percent Undervoltage
Relays
05000346/2002014-01l
Inadequate Calculations for Control Room Operator Dose
(GDC-19) and Offsite Dose (10 CFR Part 100) Related to
High Pressure Injection (HPI) Pump Minimum Flow Values
05000346/2002014-01m
Other GDC-19 and 10 CFR Part 100 Issues
05000346/2002014-01n
High Pressure Injection Pump Operation Under Long Term
Minimum Flow
05000346/2002014-01o
Some Small Break Loss of Coolant Accident Sizes Not
Analyzed
05000346/2002014-01p
Inadequate Service Water System Flow Analysis
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED, cont
Attachment
A5
05000346/2002014-01q
Inadequate Service Water System Thermal Analyses
05000346/2002014-01r
Inadequate Ultimate Heat Sink Inventory Analysis05000346/2002014-01s
No Valid Service Water Pump Net Positive Suction Head
Analysis
05000346/2002014-01t
Service Water Source Temperature Analysis for Auxiliary
05000346/2002014-01u
Inadequate Short Circuit Calculations
05000346/2002014-02b
Inadequate Service Water System Flow Balance Testing
05000346/2002014-03a
Inappropriate Service Water Pump Curve Allowable
Degradation
05000346/2002014-03b
Repetitive Failures of Service Water Relief Valves
05000346/2002014-03c
Non-conservative Difference in Ultimate Heat Sink
Temperature Measurements
05000346/2002014-03e
Non-conservative Containment Air Cooler Mechanical
Stress Analysis05000346/2002014-05
Question Regarding the Definition of a Passive Failure
Final Evaluation of Apparent Cause Evaluation for LER 05000346/2002-06-00
05000346/2003-03-00
LER
Potential Inadequate High Pressure Injection Pump
and -01
Minimum Recirculation Flow Following a Small Break Loss
of Coolant Accident
Discussed
05000346/2002-08-00
LER
Containment Air Coolers Collective Significance of
and -01
Degraded Conditions
05000346/2002014-01a
Lack of a Design Basis Analysis for Containment Isolation
Valve Backup Air Supplies
05000346/2002014-01b
Inadequate Blowdown Provisions for CAC Backup Air
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED, cont
Attachment
A6
05000346/2002014-01i
Non-conservative TS Value for 90 Percent Undervoltage
Relays
05000346/2002014-01k
Non-conservative Relay Setpoint Calculation for the 59
Percent Undervoltage Relays
05000346/2002014-01v
No Analytical Basis for Setpoint to Swap Service Water
System Discharge Path
05000346/2002014-02a
SW Surveillance Test Did Not Use Worst Case Values
05000346/2002014-03d
Inadequate Corrective Actions Related to SW Pump
Discharge Check Valve Acceptance Criteria
Failure to Perform TS Surveillance Requirement for HPI
Pump Following Maintenance
Reactor Operation with Pressure Boundary Leakage (URI
Reactor Vessel Head Boric Acid Deposits (URI
Containment Air Cooler Boric Acid Deposits (URI
Radiation Element Filters (URI 05000346/2002008-04)
Service Structure Modification Delay (URI
Reactor Coolant System Unidentified Leakage Trend (URI
Inadequate Boric Acid Corrosion Control Program
Procedure (URI 05000346/2002008-07)
Failure to Follow Boric Acid Corrosion Control Program
Procedure (URI 05000346/2002008-08)
Failure to Follow Corrective Action Program Procedure
Attachment
A7
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC team reviewed the documents in their entirety but rather that selected
sections of portions of the documents were evaluated as part of the overall inspection effort.
Inclusion of a document on this list does not imply NRC acceptance of the document or any part
of it, unless this is stated in the body of the inspection report.
Bulletins 88-04; Potential Safety-Related Pump Loss; May 5, 1988
03-01; Potential Impact of Debris Blockage on Emergency Sump Recirculation at
Pressurized-Water Reactor; June 9, 2003
Calculations
C-CSS-009.03-002; Assessment of Safety Related Structures from the Effects of Intake
Structure Gantry Fall During a Tornado Event; Revision 0
C-CSS-099.20-026; Probability of Tornado Missile Damage to Davis-Besse Missile
Exposed Targets; Revision 1; January 6, 2003
C-EE-002.01-010; Battery Load Profile; Revision 29; September 18, 2002
C-EE-004.01-049; 4.16 kV Bus Degraded (90 Percent Undervoltage) Relay Setpoint
Relay Setting Table Bus C1; Revision 2
C-EE-004.01-049; 4.16 kV Bus Degraded (90 Percent Undervoltage) Relay Setpoint
Relay Setting Table Bus D1; Revision 7
C-EE-015.03-008; Electric Transient Analysis Profile; Revisions 0 and 2
C-EE-024.01-008; Evaluation of Davis-Besse EDG Voltage Frequency Response During
Design Basis LOOP/LOCA Transient Loading MPR 0200-0049-08-01; Revision 1
C-ICE-011.01-002; Service Water Flow/Pressure Indications; Revision 0
C-ICE-048.01-004; SFAS BWST Low Level Setpoint; Revision 7; April 22, 2003
C-ME-011.01-131; Service Water Relief Valve Setpoint and Capacity; Revision 0;
Addendum A01
C-ME-011.01-137; Service Water Pump NPSH; Revision 0
C-ME-011.01-140; SW/CCW Makeup Line 1 HBC-35 Flow Rate; Revision 0;
March 6, 2003
Attachment
A8
C-ME-011.06-007; Accumulator Sizing for Service Water Valves SW1356, SW1357 and
SW1358; Revisions 0, 1, and 2
C-ME-024.02-002; Maximum Outside Temperature for EDG Operability; Revision 1;
April 2, 2002
C-ME-030.01-008; Operability for Rooms 323, 324, and 325 with Loss of Normal
Ventilation; Revision 0; February 4, 2003
C-ME-060.05-003; TP 850.31.01 Acceptance Criteria; Revision 0; November 13, 1986
C-ME-060.05-014; Containment Air Cooler System Fan Performance; Revision 0;
September 9, 2003
C-NSA 000.00-017; PROTO-FLO Service Water System Model; December 19, 2001
C-NSA 000.00-019; GOTHIC Model Inputs for DB Primary Containment; Revision 0;
February 4, 2003
C-NSA 011.01-010; Maximum Service Water Pressure to AFW System; Revision 0;
April 2, 2002
C-NSA-032.02-006; ECCS Pump Room Heatup During Post LOCA; Revisions 0 and 1
C-NSA-040.01-006; TSP Volume Increase due to RCS Leakage; Revision 1;
November 4, 2002
C-NSA-050.03-009; Auxiliary Feedwater Flow as a Function of Decay Heat; Revision 0
C-NSA-050.03-013; Auxiliary Feedwater System Curve; Revision 1
C-NSA-050.03-015; Auxiliary Feedwater Pump Turbine Steam Pressure Drop and Low
End Pump Operation; Revisions 2 and 3
C-NSA-050.03-022; Acceptance Criteria for Auxiliary Feed Pump Quarterly Surveillance
Test; Revision 2
C-NSA-050.03-023; Auxiliary Feedwater Pump Turbine Operation with Open or Broken
11/2-Inch Minimum Flow Line for Modification 95-060; Revisions 0 and 1
C-NSA-059.01-019; Water Level Inside Containment Post-LOCA; Revision 2;
March 28, 2003
C-NSA-060.05-008; Containment Post LOCA Response with Variable SW Temperature;
Revision 3; October 20, 2001
C-NSA-060.05-010; Containment Analysis; Revision 2; February 1, 2003
Attachment
A9
E-ECS-099.16-146; Thermal Aging Effect of ECCS Room Post LOCA Temperature;
Revision 0; February 26, 1992
FANP86-5024418-01 DB-1; Post-LOCA pH Analysis; Revision 1; March 19, 2003
SR-0964; Flowserve Cover Gasket Upgrade Verification for Davis-Besse Primary
Coolant Pumps; Revision 1; February 3, 2003
02-113; Service Water System Design Basis Flow Analysis; Revision A
02-123; Service Water System Model Development and Benchmark; Revision B
02-124; Service Water System NPSH; Revision A
03-011; SW System Performance Following an Appendix R Event; Revision A;
March 13, 2003
03-013; Service Water System Test Acceptance Criteria Correction Factors; Revision A
12501-00004; UHS Pond Thermal Performance; Revision 0
12501-M-002; LOCA and MSLB Containment Analysis with Increase of Allowable
Service Water Temperature to 90 Degrees F; Revision 0; January 26, 1999
12501-M-003; ECCS Pump Room Temperatures with Initial 90 Degrees F Forebay;
Revision 0; May 27, 1999
24.001; Calculated Temperature -vs.- Time in Rooms 323, 324, and 325; Revisions 1
and 3; July 24, 2003
28.003; Bechtel CAC Fan Motor; Revision 0
28.004; Containment Cooling System Pressure Drop; Revision 2; September 7, 2003
32-1171148-00; Loss of Feedwater Analysis; Revision 0
51-5023378-00; February 20, 2003
67.004; Service Water Pump Maximum Allowable Outside Air Temperature to Dissipate
Entire Room Heat Load with One Ventilation Fan C99 1, 2, 3, or 4 Operable; Revision 1
67.005; Service Water Pump Room Ventilation System Capacity; Revision 4;
November 20, 2002
67.007; Service Water Pump Room Ventilation System - Pressure Drop;
August 30, 2002
86-5007079-00; SG Over-Pressure Protection Report; Revision 0
Attachment
A10
86-5022260-00; Determination of HPI Pump Operability During Post-LOCA Sump
Recirculation For All Break Sizes And Transient Scenarios; Revision 0
86-5024418-01; DB-1 Post-LOCA pH Analysis Report; Revision 0
Condition Reports Generated as a Result of this Inspection
03-02191; Corrective Action Approval Without Supporting Documentation Finalized;
March 19, 2003
03-02195; Ambiguous Description in CRA No.8 to CR 02-07646; March 19, 2003
03-02298; Failure to Generate CR for Unresolved Issues in NRC Inspection Report;
March 19, 2003
03-02445; Incorrect Processing of CR 02-09928 and CR 02-0939; March 27, 2003
03-02475; Inadequate Blowdown Provisions for CAC Air Accumulators; March 28, 2003
03-02577; Appendix R Safe-Shutdown Concerns with EDG Floor Drains; April 1, 2003
03-02597; Bypassed Overload Heaters in Class 1E 480V Motors; April 2, 2003
03-02616; RFA - Bypassing Overload Heater Trips on 1E 480V Motors; April 2, 2003
03-02651; Framatome AFW Issues with MSSV; April 3, 2003
03-02654; Cable Ampacity on Containment Spray Pump Motor; April 2, 2003
03-02730; Lack of Vendor Data for High Voltage Switchgear at High Temperature;
March 19, 2003
03-03184; Administrative Issues with CR 02-05640; April 25, 2003
03-03572; Lack of Coordination of Protective Devices on Bus E1 and F1; May 7, 2003
03-03891; EDG Room Heater Non-Q Yet Credited in USAR; May 19, 2003
03-03977; SW Calculations Do Not Provide Sufficient Documentation of Results;
May 22, 2003
03-03979; CR 02-00891 CA-30 Operation Confidence Review Closed Out Early;
May 22, 2003
03-03980; Past CAC Operability Determination Lacks Adequate Technical Justification;
May 22, 2003
03-03986; Rating of the Containment Air Cooler Fan Motors; May 22, 2003
Attachment
A11
03-04010; NRC Review of SW/CCW Interface Calculation; May 22, 2003
03-04018; NRC Pointed out Discrepancy in Mode Hold Resolution for CR 02-01523;
May 23, 2003
03-04035; Trending CR - Timeliness of the Evaluation of SCAQ CR 02-02943;
May 22, 2003
03-04225; Response Team Communications Self-Identified During Inspection;
May 28, 2003
03-04264; Non-Q Motor Loads Without Overload Heaters; May 30, 2003
03-04303; CR 03-02597 (O/L HTR Bypass) Evaluation Concerns By NRC; June 2, 2003
03-04341; Past Operability/Reportability Review of Previous CR 03-02699;
dated June 3, 2003
03-04375; SR Potential Current Overloads on Load Center Breakers Feeding MCCs;
June 4, 2003
03-04423; Passive Failure Assumptions; June 5, 2003
03-04435; Preliminary Davis-Besse AC System Analysis Results; June 6, 2003
03-04668; No Guidance/Criteria for a Collective Significance Review; June 13, 2003
03-04684; Isolated Occurrences of Staff Not Trained to NOP-LP-2001 Revision 4;
June 13, 2003
03-05681; Inadequate Operability/Reportability Determination; July 15, 2003
03-05715; SBODG Does Not Have a Load Table; July 16, 2003
03-05739; Deficiencies in Component Evaluation for EDG Room High Temperature;
July 17, 2003
03-05917; Concern Regarding Containment Spray Pump Overload Protection;
July 23, 2003
03-05919; Concerns Regarding 480V Breaker Coordination for Appendix R Compliance;
July 23, 2003
03-05920; Basis Not Defined for all the Appendix R DC and 120 Vac Circuits;
July 23, 2003
03-06153; Timeliness of Changes to the USAR; July 31, 2003
03-06338; Discrepancies in CR 02-06773 Response; August 8, 2003
Attachment
A12
03-06375; Concerns with Motor Overload Protection for Non-Essential Service Motors;
August 8, 2003
03-06383; Revise C-ME-011.06-007 Nitrogen Bottle Sizing for SW1356, SW1357 and
SW1358; August 8, 2003
03-06418; Interdependencies of Calculations Associated with EDG Rating and Capacity
Self-Identified In Preparation for Inspection; August 9, 2003
03-06421; Lack of Corrective Action for Cause Identification CR 02-05262 Self-Identified
In Preparation for Inspection; August 9, 2003
03-06427; Lack of Corrective Action for Cause Identification CR 02-07110 Self-Identified
In Preparation for Inspection; August 9, 2003
03-06428; Lack of Corrective Action for Cause Identification CR 02-09027 Self-Identified
In Preparation for Inspection; August 9, 2003
03-06457; Discrepancies Between Quality and Seismic Classifications;
August 11, 2003
03-06458; Invalid Information Restored to Procedure During Alteration Self-Identified In
Preparation for Inspection; August 11, 2003
03-06474; Containment Spray Pump Current Values are Non-conservative;
August 11, 2003
03-06475; Evaluation of Overloads on Motor Operated Valves; August 11, 2003
03-06485; Installed Equipment Size Differs From that Shown in the Calculation;
August 12, 2003
03-06492; EDG Water Jacket Heat Exchanger PM Enhancement; August 12, 2003
03-06497; CATI: The NRC Team Disagrees With CR 03-03891 Resolution;
August 12, 2003
03-06499; Item 0292 - 50.59 Evaluation Using NRC Pre-approved Methodologies;
August 12, 2003
03-06507; Tracking CR for Actions Recommended By CR 03-04423; August 12, 2003
03-06519; Periodic Vibration Testing of LPI Pumps on Minimum Flow; August 13, 2003
03-06520; Potential Concern for Pre-Conditioning Prior to Surveillance Test;
August 13, 2003
03-06524; EDG Conduit Installation for Cabinet C3615; August 2, 2003
Attachment
A13
03-06526; Adequacy of HPI Pump Minimum Flow Rate; August 13, 2003
03-06547; Potential for Supervisor/SRO Comments to Influence CR Outcome;
August 13, 2003
03-06556; NRC Questions/Issues In AOV C-ME-011.06.007; August 14, 2003
03-06561; 50.59 Evaluation 02-01740 Concerns; August 14, 2003
03-06567; Accuracy of SRO Comments on 03-02597; August 14, 2003
03-06576; Auxiliary Feedwater Components Should be in GL89-13 Program;
August 14, 2003
03-06578; Concern Over AFW Strainer Limiting Particle Size Report; August 14, 2003
03-06585; Inaccurate Investigation of CR 02-07547 Self-Identified In Preparation for
Inspection; August 14, 2003
03-06586; Clarification to CR 02-06661; August 13, 2003
03-06588; Item 0352, LAR 96-0008 Incomplete Statements, EQ Questions;
August 14, 2003
03-06656; NSA Calculations May Not Have Been Revised Properly; August 18, 2003
03-06809; Improvements to 10 CFR 50.9 Completeness and Accuracy Training;
August 21, 2003
03-06837; Item 0375 - Potential Thermal Overpressurization of the SW Sys. to CACS;
August 22, 2003
03-06870; NRC Unresolved Issues, Concerns with SW Pump Room HVAC 67.005;
August 23, 2003
03-06901; Error Found in Flooding Calculation 15.50 Revision 1; August 25, 2003
03-06907; Quality Collective Significance Review; August 23, 2003
03-06908; Corrective Action Program Implementation Collective Significance Review;
August 23, 2003
03-06909; Design Control Collective Significance Review; August 23, 2003
03-06941; Recommended SW Balance Procedural Enhancement; August 26, 2003
03-06944; Fuse Sizing for MV0106 and MV38700; August 25, 2003
03-06948; Downgrade of CR 02-06356; August 26, 2003
Attachment
A14
03-06956; 0300 - DC Voltage Drop LC - Lack of Basis for Deferring Corrective Action;
August 26, 2003
03-06984; Questions on NOP-CC-2003, Engineering Changes; August 26, 2003
03-06989; ETAP Revision 2 Number was not Attained in Accordance with
NOP-CC-3002; August 27, 2003
03-06990; Possible Enhancement to NOP-CC-3002 as Identified During TI-0409;
August 27, 2003
03-06996; Root Cause for 02-06178 Spacer Grid Damage Needs Improvement;
August 27, 2003
03-07006; Translation of Flow Balance Acceptance Criteria Should Be Formalized;
August 27, 2003
03-07009; CAC Motor Sizing; August 27, 2003
03-07031; Inadequate Rollover from CR 03-02616 to CR 03-03572; August 28, 2003
03-07033; Inadequate Past Operability Evaluation for CR 03-03572; August 28, 2003
03-07035; Performance Improvement Involvement in MCTM; August 28, 2003
03-07042; UFSAR Needs to Be Clarified on Use of Safety Related Equip and Seismic;
August 28, 2003
03-07047; NRC Concerns with CR Evaluations Failure to Answer the Identified Issue;
August 28, 2003
03-07053; Evaluation for Operability and USAR Update Timeliness; August 28, 2003
03-07067; Observation of Proposed Service Water Relief Valve Removal EWR 01-0306;
August 29, 2003
03-07069; Adequacy of Electrical DC Contactor Testing Methodology; August 29, 2003
03-07112; Collective Significance Review of Recent Operability Evaluation Revisions;
August 28, 2003
03-07121; NRC Non-Cited Violation Issues; August 30, 2003
03-07124; NRC Concerns with CR Evaluations Not Including Applicable References;
August 30, 2003
03-07256; Questions on Applicability of 50.59 for Manual Actions in Fire Preplans;
September 2, 2003
Attachment
A15
03-07420; Restart CRs Closed Prior to All CAs Being Completed; September 6, 2003
03-07922; Thermal Overload #2 EDG Air Compressor; September 21, 2003
03-09548; New Motor Operated Valve Terminal Voltage; November 5, 2003
Condition Reports Reviewed During the Inspection
99-01109; Conversion of PCAQR 1998-0126 to Condition Report; June 28, 1999
00-00669; Potential Non-Compliance Against the ASME Code; April 1, 2000
00-00699; Steady State Leakage from Three of Four Reactor Coolant Pump Gasket
Drain Lines; April 2, 2000
00-00869; Leakage at the Bolted Connection on Reactor Coolant Pump 1-1;
April 10, 2000
00-01089; Relaxation of Reactor Coolant Pump Casing Studs since Refueling Outage
11; April 20, 2000
00-02033; Reactor Coolant System Flow Rate Test Acceptance Criteria Not Met;
August 11, 2000
00-02304; Performance of DB-SP-04360 In Modes 1 and 2; September 21, 2000
00-02418; Zebra Mussel Particles in Service Water Lines Might Restrict Flow Through
the Auxiliary Feedwater Restriction Orifices; October 6, 2000
01-00540; Dose Calculations for Post Accident Sampling System Samples Outside of
Updated Safety Analysis Report 9.3.2.2.3; February 23, 2001
01-00890; Reactor Coolant System Leak Rate Data Scatter; March 28, 2001
01-01102; Letdown Diverting Valve, MU11, Is Possible Source of Reactor Coolant
System Unidentified Leakage; April 20, 2001
01-01335; CAC Air Side Fouling Criteria; May 22, 2001
01-01857; RCS Leakage Anomalies; July 25, 2001
01-02019; Initial Results of Investigation into NRC Information Notice 2000-20;
August 7, 2001
01-02820; Procedures Not Updated to Support Modification Implementation;
October 23, 2001
01-02862; Potential Adverse Trend in Unidentified Reactor Coolant System Leakage;
October 25, 2001
Attachment
A16
01-03025; Reactor Coolant System Leakage; November 12, 2001
01-03059; Minimum Voltage for AFW Valves MV0106 and MV3870; November 2001
02-00164; ASME Relief Request for the 13th Refueling Outage; January 16, 2002
02-00412; DC Voltage Drop Calculation; February 8, 2002
02-00576; Small Oil Leak Discovered on Reactor Coolant Pump Motor 2-2;
February 18, 2002
02-00695; Latent Issues Review (LIR) - EDG Engine Derating; February, 2002
02-00835; LIR - RCS: RCS Validation Document Contains Outdated Information;
February, 2002
02-00890; Control Rod Drive Nozzle Crack Indication; February 27, 2002
02-00891; Failure to Identify Significant Degradation of the Reactor Pressure Vessel
Head (Selected Corrective Actions Only); February 2002
02-01129; Valve MU66C As-found Close Stroke Time Exceeded Maximum Allowable;
February 2002
02-01139; Corrosion of Containment Air Cooler 3 Flange Faces; March 8, 2002
02-01517; Containment Inspection Plan Not Fully Implemented; April 10, 2002
02-01523; Reactor Coolant Pump 1-1 and 1-2 Leakage at Gasket Drain Lines;
February 16, 2002
02-01691; Inspection Plan IP-M-028 Findings; April 25, 2002
02-01915; Inspection Plan IP-M-028 (Extent of Condition) Examination Findings;
May 6, 2002
02-02143; Inspection Plan IP-M-028 (Extent of Condition) Examination Findings;
May 17, 2002
02-02419; Untimely Corrective Action to Address Corrective Action Program
Weaknesses; June 4, 2002;
02-02584; Implementation of Corrective Action Program by Site Personnel;
June 13, 2002
02-02585; Management and Supervisory Oversight and Ownership of Plant Activities;
June 13, 2002
02-02658; Inadequate Ventilation for Rooms 323, 324 and 325
Attachment
A17
02-02848; Fuel Assembly Spacer Grid Impressions in Core Baffle Plates; June 27, 2002
02-02943; Containment Air Cooler Boric Acid Corrosion; July 2, 2002
02-03027; Emergency Diesel Generator Jacket Water Heat Exchanger Tubeside (CCW)
Flow Rates Exceed Limits; July 8, 2002
02-03157; High Energy Line Breaks in Turbine Building Effects on AFW Pump Rooms;
July 11, 2002
02-03337; Documentation Could Not be Located; July 19, 2002
02-03497; Overall Failure to Take Action to Correct Identified Deficiencies in CAP;
July 27, 2002
02-03674; Recurring Trend of Untimely and Ineffective Corrective Actions;
August 3, 2002
02-03668; Reactor Coolant Pump Casing-to-cover Joint Leakage; August 3, 2002
02-03673; Recurring Trend of Less Than Adequate CR Evaluations; August 3, 2002
02-03674; Recurring Trend of Untimely and Ineffective Corrective Actions; August 3
2002
02-03676; Coding and Trending; August 3, 2002
02-03960; CAC Operability; August 9, 2002
02-03963; Zebra Muscle Shells in Containment Air Cooler Cooling Coils; August 9, 2002
02-04083; LIR - EQ: 36 inch Main Steam Line Analysis; August 10, 2002
02-04146; EDG 2 Missile Shield Support Plates Have Broken and Cracked Concrete;
August 11, 2002
02-04147; Missile Protection on Stacks about Six Feet Short of Completely Effective;
August 11, 2002
02-04202; Oxidation on Fuses and Fuse Holders; August 12, 2003
02-04211; Performance Indicator Weakness Collective Review; August 14, 2002
02-04292; Inadequate Cause Evaluations and Corrective Actions; August 15, 2002
02-04630; LIR - Emergency Diesel Generator 1-2; August 18, 2002
02-04668; LIR - AFW-EQ Equipment Sealing; August 21, 2002
Attachment
A18
02-04673; Auxiliary Feedwater Strainers Limiting Particle Size; August 22, 2002
02-04680; No Documentation To Assure Compliance With GE SIL-44 For HFAs;
August 21, 2002
02-04700; Tornado Missile Protection; August 21, 2002
02-04716; Recurring Trend of Procedural Non-Compliance; August 21, 2002
02-04740; Refer to DB-OP-01200 for Step Changes in Unidentified RCS Leakage;
August 22, 2002
02-04810; LIR - AFW-W-PSL 4929A and B; August 17, 2002
02-04884; Ineffective Corrective Action Problem Resolution; August 23, 2002
02-05039; LIR - EDG System Does Not Meet IEEE-STD-387-1972 Requirements;
August 26, 2002
02-05079; LIR - AFW-SFRCS High Level Isolation; August 26, 2002
02-05096; Reinspection of RCP21OUT-5-RI (Pump 220, Reactor Coolant Pump 2-1
Discharge); August 26, 2002
02-05159; Reinspection of Reactor Coolant Pump 2-1 Casing Closure Studs and
Bolting; August 26, 2002
02-05165; LIR - AFW-EQ Overall Assessment; August 27, 2002
02-05262; LIR of Environmental Qualification of SW Pump Room Equipment (IR
02-14-01f); August 29, 2002
02-05296; Containment Analysis Documentation Requirements; August 30, 2002
02-05298; Limiting Containment Temperature May Not Have Been Used in System
Design; August, 30, 2002
02-05300; Ensure That the Containment Spray TSP Baskets are Fully Submerged on
LOCA; August 30, 2002
02-05304; TSP Design Bases; August 30, 2002
02-05322; Additional Review of the Containment is Warranted; August 30, 2002
02-05323; Clarification Required re Containment Vessel Design Pressure;
August 30, 2002
02-05356; Service Water Technical Specification Instruments; September 10, 2002
Attachment
A19
02-05364; LIR - EDG Electrical Capacity C-EE-024.01-005, R8, is to Be Revised;
September 3, 2002
02-05383; LIR EDG-EDG Electrical Capacity C-EE-015.03-002; August 30, 2002
02-05385; LIR - EDG Loading Table Step 1 Block Loading Inadequate; August 30, 2002
02-05390; CR Rollover Exceeds Max Default Times Without Proper Approvals;
September 3, 2002
02-05446; LIR - EDG Loading Could Exceed the EDGs Electrical Capability When
Paralleled; September 4, 2002
02-05459; Split CAC Motor Cables; August 6, 2002
02-05514; System Health Readiness Review (SHRR) Assessment of Testing
Containment Spray Valves - Locked Closed; September 5, 2002
02-05516; LIR - SW Possible Inaccurate Consideration of Design Bases CAC Fouling
Factor; September 5, 2002
02-05559; Inadequate CAP Review of Operating Experience; September 6, 2002
02-05563; Nozzle Flexibility Assumed in Calculations 65A/B is Non-conservative;
September 6, 2002
02-05590; Tornado Missile Protection of Emergency Diesel Generators;
September 6, 2002
02-05593; Thermal Aging Effect of Emergency Core Cooling System Room Post Loss of
Coolant Accident Temperature; September 6, 2002
02-05627; LIR - 59 Percent Undervoltage Relay Logic Shown in EC128AI Is Incorrect;
September 7, 2002
02-05628; LIR - 59 Percent Undervoltage Relay Logic Shown in SD-003A Is Incorrect;
September 7, 2002
02-05632; LIR - Tech Spec Table 3.3-4 Trip Setpoint Tolerance Is Inadequate;
September 7, 2002
02-05633; USAR Discrepancy with LOOP Timing; September 7, 2002
02-05639; Updated Safety Analysis Report Description of Limiting Strainer Size;
September 10, 2002
02-05640; LIR - No Design Bases/Flow Verification Testing of SW Flow to AFW
System; September 10, 2002
Attachment
A20
02-05645; Fuel Assembly NJ10KK Spacer Grid Damage; September 6, 2002
02-05691; LIR - Minimum Temperature to the AFW System SG Nozzles;
September 12, 2002
02-05727; Design Capacity of Ultimate Heat Sink; September 14, 2002
02-05732; License Amendment Request 96-0008 Not Supported by Analysis;
September 10, 2002
02-05738; Relief Valve Set Point Not Conservative; September 11, 2002
02-05748; Lack of Service Water and Ultimate Heat Sink Design Basis for Seismic
Event and Single Active Failure; September 14, 2002
02-05749; LIR - CCW Non-Seismic Piping Over Safety Related Components;
September 12, 2002
02-05784; Service Water Strainer Design Flow; September 11, 2002
02-05848; LIR - EDG High Temperature Evaluation Internal Temperature Rise for
Cabinets; September 12, 2002
02-05870; LIR - EQ List of 10 CFR 50.49 Components; September 12, 2002
02-05881; Reactor Coolant Pump 2-2 Casing Closure Studs and Bolting;
September 12, 2002
02-05885; No Emergency Core Cooling System Air Cooler Inspection Acceptance
Criteria; September 14, 2002
02-05895; Fuel Assembly NJ10LC Spacer Grid Damage; September 13, 2002
02-05896; Fuel Assembly NJ10KL Spacer Grid Damage; September 13, 2002
02-05904; Auxiliary Feedwater Design Basis Calculations Not Located;
September 14, 2002
02-05914; LIR - EDG Lube Oil Procedure Guidance; September 12, 2002
02-05922; LIR - Discrepancy in EDG Voltage and Frequency During Loading;
September 12, 2002
02-05923; No Design Basis for Service Water Pump Net Positive Suction Head
Available; September 16, 2002
02-05925; LIR - EDG Transient Analysis During Loading Sequence - Calculations;
September 12, 2002
Attachment
A21
02-05986; Ultimate Heat Sink Water Inventory Analysis Does Not Consider All Water
Losses; September 14, 2002
02-06062; LIR - EDG: Fuel Filter Inlet Operating Pressure Exceeds Vendor Limits for
Change; September 14, 2002
02-06064; SSDI Item - SW Flow Balance Margins and Need for Additional Recorded
Data; September 14, 2002
02-06100; SSDI Assessment Identified Incorrect Information in OJ 2000-14
(SW Valve Issue); September 14, 2002
02-06108; LIR - AFW Pumps and H2 Dilution Blower Not Evaluated for High Pressure
Injection System; September 14, 2002
02-06134; Service Water Dead Leg Inspection and Cleaning; September 18, 2002
02-06160; Debris Other than Paint Chips Identified in Fuel Assemblies;
September 18, 2002
02-06166; LIR - SW Flow Balance Testing of Alternate Safety Related Return Flow
Paths; September 18, 2002
02-06178; Spacer Grid Damage Observed During Fuel Inspections;
September 18, 2002
02-06215; Excessive Indicated Total RCS Flow Error in SP-03358; September 18, 2002
02-06275; Degraded Makeup Valve MU11 Hardware; September 19, 2002
02-06305; SSDI Item - C-EE-015.03-003, Steady-State Analysis: ELMS;
September 19, 2002
02-06333; Inadequate SW Thermal Analysis; September 19, 2002
02-06337; SSDI Item - SW C-NSA-011.01-007, Revision 1 Concerns (Pump Curves);
September 19, 2002
02-06341; LIR - SW: Review of Industry Experience; September 20, 2002
02-06343; Nuclear Quality Assurance Stop Work on Nuclear Fuel Movements;
September 20, 2002
02-06356; Calculational Process Concerns; September 20, 2002
02-06370; SSDI Item - ECCS Pump Room Heat Load is Non-conservative;
September 20, 2002
Attachment
A22
02-06384; SSDI Item - Enhancement to Calculation 50.20 Flooding of ECCS Rooms
Due to a Feedwater Line Break; September 20, 2002
02-06407; SSDI Item - Instrument Uncertainty in Calibration and Surveillance of
Instrumentation; September 16, 2002
02-06438; Inadequate SW Thermal Analysis; September 2002
02-06439; LIR - SW Service Water Pump Run Out; September 2002
02-06477; SSDI Item - HPI Pump Performance Not Evaluated For Expected Input
Power Variations; September 2002
02-06536; LIR - RCS: PZR Vent Flow Capacity Has No Design Basis; September 2002
02-06547; Design Basis Validation - Pressurizer Vent Orifice Sizing; September 2002
02-06564; Service Water System Cleanliness for Restart; October 5, 2002
02-06677; Ineffective Corrective Action for Locked High Radiation Area Access Control;
September 25, 2002
02-06701; Post-LOCA Dose from BWST with Inadvertent HP31/HP32 Failure;
September 25, 2002
02-06702; Potential for Inadequate HPI Pump Minimum Recirculation Following LOCA;
September 25, 2002
02-06723; LIR - NRC Concern Regarding Sites Lubrication Program;
September 26, 2002
02-06725; Sway Strut Bushing Grease Fittings; September 26, 2002
02-06737; SSDI Item - C-EE-004.01-051 Uncertainty Treatment; September 25, 2002
02-06757; LIR - EDG Potential Overload Condition; September 26, 2002
02-06767; LIR - AFW (JCO) Inputs Not Bounding; September 26, 2002
02-06773; LIR - AFW CR 95-0906 Deficiencies; September 26, 2002
02-06779; Voltage Reading Exceeded Tolerance and Evidence of Heat Damage;
September 26, 2002
02-06821; LIR - AFW Pump Surveillance Testing; September 26, 2002
02-06860; Review of the Need for Relief Valves for Several Heat Exchangers;
September 27, 2002
Attachment
A23
02-06861; Bearing Oil Cooler Strainer Fouling; September 27, 2002
02-06885; Reactor Coolant System Flow Uncertainty May Be Higher than Assumed;
September 27, 2002
02-06893; Effect of Room 105, and 115 Temp Increase; September 24, 2002
02-06951; LIR - EDG Engine Derating; September 27, 2002
02-06986; Relay Testing; September 26, 2002
02-06996; HPI Flow Test Acceptance Criteria Versus T.S. 4.5.2.H; September 27, 2002
02-07110; Unqualified Splice in MOV; October 1, 2002
02-07148; LIR CCW - Lack Of Functional Testing Of Letdown Cooler And RCP
Interlocks; October 1, 2002
02-07153; LIR - EDG Appendix R Load Calculation; October 1, 2002
02-07159; Lack of Valve Position Alarm; October 1, 2002
02-07188; Non-conservative Assumptions in 67.005, Service Water Ventilation
Capacity; October 1, 2002
02-07236; LIR - AFW SG Accident Pressure versus AFW Pump Flow; October 1, 2002
02-07278; RC2 Pressurizer Spray Valve Design; October 1, 2002
02-07328; Lack of Timeliness for Radiation Protection Action Implementation;
October 3, 2002
02-07378; LIR - SW to CCW Makeup Line Flow Verification Test Discrepancies;
October 3, 2002
02-07402; Reactor Coolant Pump Vendor Technical Manual Closure Stud Elongation
Specification Should be Updated; October 3, 2002
02-07468; Inappropriate SW Pump Curve Allowable Degradation; October 3, 2002
02-07475; Instrument Inaccuracy for Air Temperature Not Considered in SW Vent
Calculations; October 3, 2002
02-07516; LIR - CAC SW Flow Tests Indicate Adverse Trend; September 9, 2002
02-07524; LIR - AFW Pump Curves; October 2002
02-07559; LIR - RCS: Lack of Response to Request For Assistance for Design Basis
Validation Information; October 2002
Attachment
A24
02-07596; EDG High Temperature Overall; October 17, 2002
02-07599; LIR - EDG High Temperature - Determine Capability to Function;
October 2002
02-07600; LIR - RCS Inappropriate Cancellation of Mod 90-0012; October 7, 2002
02-07609; Cable Separation of Hi Point Valves; October 7, 2003
02-07640; No Overpressure Protection Evaluation for Isolable Components;
October 8, 2002
02-07646; SSDI Item - Calc C-EE-004.01-051 Temperature Variation Not Considered
October 8, 2002
02-07657; Service Water Pump Design Flow Rate in Question; October 8, 2002
02-07684; HPI Pump Operation Under Long Term Minimum Flow; October 8, 2002
02-07692; USAR Section 9.2.5.1 Concerning Placing SW Pumps into Operation After
13 Hours; October 8, 2002
02-07701; Control Room Operator Dose Due to ECCS Leakage Post-LOCA;
October 9, 2002
02-07706; Multiple Open Work Orders to Install Inspection Opening in Service
Structure; October 9, 2002
02-07713; Post Accident Control Room Dose Calculations; October 9, 2002
02-07714; Inadequate Flooding Protection for the SW Pump House; October 9, 2002
02-07716; Wrong Instrument May Be Used to Verify Ultimate Heat Sink Temperature;
October 9, 2002
02-07750; Lack of a Design Basis Analysis for Containment Isolation Valve Backup Air
Supplies (IR 02-14-01a); October 9, 2002
02-07757; Environmental Conditions for Decay Heat Pump Seal Leak Not Evaluated;
October 9, 2002
02-07760; Flood Analysis Discrepancies in the Service Water Pipe Tunnel and Valve
Rooms; October 9, 2002
02-07766; Non-conservative Value for 90 Percent Volt in Table 3.3-4; October 9, 2002
02-07781; Weaknesses in Testing Service Water Outlet Valves to Containment Air
Coolers; October 9, 2002
Attachment
A25
02-07802; Basis for PSH 2929 and PSH 2930 Not Found; October 10, 2002
02-07889; Open Item for Screen Wash and Service Water Systems; October 11, 2002
02-07981; Intake Gantry Crane; October 14, 2002
02-07986; HGA Relay Failures; October 14, 2002
02-08010; GE SBM Switch Failures; October 14, 2002
02-08183; Differential Pressure Switch Error; October 16, 2002
02-08251; Concerns with Ultimate Heat Sink Analysis Post Loss of Coolant Accident;
October 17, 2002
02-08278; Maximum Allowable Pressurizer Level Should be 228 inches, Not 305 inches;
October 17, 2002
02-08281; Additional Errors in SW Ventilation Calculation 67.005; October 17, 2002
02-08331; System Improvement: AFW - Clarify SSE+ LOCA Licensing Basis;
October 20, 2002
02-08482; EDG Rating and Capacity; October 22, 2002
02-08759; Potential Overstress Condition in Reactor Coolant Pump Casing Joint;
October 28, 2002
02-09027; Unqualified Splice in MOV; November 4, 2002
02-09036; Greasing of Struts; November 5, 2002
02-09314; Untimely Determination of Condition Reportability; November 13, 2002
02-09405; SHRR Containment Air Cooler Review; November 2002
02-09737; Reactor Coolant Pump 1-1 Shaft Assembly Has Linear Indications on Upper
and Lower Faces of Journal Support Hub; November 29, 2002
02-09739; 2-2 HPI Thermal Sleeve Degradation; November 29, 2002
02-09829; Damaged Fuel Assembly NJ126J; December 12, 2002
02-09870; EN-DP-01501, RCP22OUTI-1, Reactor Coolant Pump 2-2 and Outlet Pipe;
December 5, 2002
02-09928; HPI Thermal Sleeve 2-1 Degradation; December 2002
02-09947; Inadequate Tracking of Condition Report Rollovers; December 14, 2002
Attachment
A26
02-10369; Condition Report Trend Analysis Not Performed Regularly;
December 19, 2002
02-10425; 15 Ton Capacity Hoist Trolley on the Gantry Crane; December 20, 2002
03-00120; CAC Thermal Performance Roll-up; January 2003
03-00131; RCS DB-OP-2003 Procedure Enhancements for RCS Leakage Identification;
January 9, 2003
03-00418; Foreign Material Discovery in 2 CAC SW Piping; January 11, 2003
03-00473; Boric Acid Corrosion Control Program - Mode 3 Walkdowns;
January 15, 2003
03-00496; Minor Discrepancies; January 21, 2003
03-00501; Lack of Documentation Confirming Pump DHR/LPI P42-1 Will Not Runout
During Recirculation Phase Operation; January 21, 2003
03-00519; Incorrect Allowable Value Indicated in Conclusion of C-ICE-083.03-004
Revision 2; January 21, 2003 and January 23, 2003
03-00561; MSLB Analysis Credits MSIV Closure Under Reverse Flow; January 23, 2003
03-00563; MSIVs MS100 and MS101 Surveillance Testing/Flowserve Vendor
Documentation; January 23, 2003
03-00568; Bases for Main Steam Safety Valve Relief Capacity Listed in Technical
Specifications Could Not Be Located; January 23, 2003
03-00575; Incorrect Statement in Breaker Setting Calculations; January 2003
03-00770; Three Rollover Errors; January 2003
03-00937; Concern Regarding Intra System Leakage; February 3, 2003
03-00938; Concern Regarding Reactor Coolant Pump Motor 2-2 Oil Lift System;
February 3, 2003
03-00940; Concern Regarding Reactor Coolant Pump Motor Maintenance Program;
February 3, 2003
03-01022; Two Rollover Issues; February 2003
03-01448; EDG Tech Spec Table 3.3-4 Trip Setpoint May Have Been Exceeded;
February 21, 2003
03-01492; Fuel Assembly NJ1271 Damaged Spacer Grid; February 24, 2003
Attachment
A27
03-01648; Unacceptable SG Tube Stresses in Appendix R Cooldown;
February 28, 2003
03-01870; PR/BACC: CR/CA; March 8, 2003
03-01955; CR Rollover Discrepancies; March 12, 2003
03-02220; Emergency Diesel Generator Component Cooling Water Flows Inconsistent
with Modification 97-0029 Requirements; March 20, 2003
03-02699; DB-OP-02519 Does Not Match Plant Configuration; April 4, 2003
03-05925; Weaknesses in Conduct of Trending; July 23, 2003
03-06296; Boric Acid Identified on Reactor Coolant Pump 2-2; August 5, 2003
03-06655; Superceded Calculations Were Not Tracked According to EN-DP-0140;
August 18, 2003
03-07656; Forward Flow Rate of 10,000 Gpm Not Attained for SW19 During
DB-PB-03232; September 12, 2003
03-08196; Mode 3A System Leakage Test; RCP 2-1 Boric Acid Deposits;
September 26, 2003
03-08249, Classification of CR 02-05590 for LER 2002-006 on Tornado Missile
Protection; September 28, 2003
Drawings
E-1037P; Electrical Grounding Details; Sheet 2; Revision 1
E-1037P; Electrical Grounding Details; Sheet 3; Revision 1
E-1037P; Electrical Grounding Details; Sheet 10; Revision 0
E-1037P; Electrical Grounding Details; Sheet 11; Revision 0
E-1042; Emergency Diesel Generator 1-1 Loading Table; Sheet 1; Revision14
E-1042; Emergency Diesel Generator 1-1 Loading Table; Sheet 2; Revision16
E-1043; Emergency Diesel Generator 1-2 Loading Table; Sheet 1; Revision 1 4
E-1043; Emergency Diesel Generator 1-2 Loading Table; Sheet 2; Revision 15
M-006D; Auxiliary Feedwater System; Revision 47
M-017A; Diesel Generators; Revision 1
Attachment
A28
M-017C; Diesel Generators Fuel Oil; Revision 22
M-033A; High Pressure Injection; Revision 30
M-036A; Component Cooling Water System; Revision 24
M-036B; Component Cooling Water System; Revision 30
M-036C; Component Cooling Water System; Revision 25
M-041A; Service Water Pumps and Secondary Service Water System; Revision 25
M-041B; Primary Service Water System; Revision 54
M-041C; Service Water System for Containment Air Coolers; Revision 25
M-096D; Auxiliary Feedwater System; Revision 47
7749-M-508-74-8; Byron-Jackson Reactor Coolant Pump; Sheets 1 and 2; Revision D
7M-017B; Diesel Generators Air Start; Revision 32
Engineering Change Packages and Requests
99-0039-00; Replacement of Containment Air Cooler Service Water Discharge Valves;
Revision 1
01-0306A; At Risk Change: Component Cooling Water Heat Exchanger Bolt
Replacement and Deletion of Relief Valves SW3962 and SW3963; April 18, 2003
01-0306B; At Risk Change: Component Cooling Water Heat Exchanger Bolt
Replacement and Deletion of Relief Valves SW3962 and SW3963; April 22, 2003
03-0074-00; Install Larger Mesh in Strainer Baskets on Service Water Inlet to Auxiliary
Feedwater Pumps and New Strainers Upstream of the Restricting Orifices;
June 19, 2003
03-0243-00; Rewire the Control Circuitry for CAC Fan 1-1 Such That in the Case of a
Control Room Fire, This Fan Can Be Started in Slow Speed to Provide Cooling to the
Containment; July 2003
03-0267-00; Provide Level and Pressure Indication for the Idle SG on the Auxiliary
Shutdown Panel to Support Appendix R Safe Shutdown; July 2003
Engineering Work Requests
01-0306-00; Remove Service Water Header Relief Valves; December 10, 2001
Attachment
A29
01-0378-00; Provide Larger Access Holes to Enable Removal of Boric Acid;
August 30, 2001
02-0138-00; RV Service Structure Support Skirt Openings; April 11, 2002
02-0217-00; Replace Existing Reactor Vessel Head; June 4, 2002
Evaluations
Basic Cause Analysis Report for CR 02-09314
Root Cause Analysis for CR 03-00425
Root Cause Analysis for CR 02-04673; March 18, 2003
Root Cause Analysis for CR 02-06178; February 1, 2003
Root Cause Analysis for CR 03-02597
Operability Evaluation 02-0036; Tornado Missile Protection Issues; December 17, 2002
Operability Evaluation 03-0009; Revision 1 for CR 03-00949
Information Notices
80-13; General Electric Type SBM Control Switches - Defective Cam Follower;
April 4, 1980
85-94; Potential for Loss of Minimum Flow Paths Leading to ECCS Pump Damage
During a LOCA; December 13, 1985
97-12; Potential Armature Binding in General Electric Type HGA Relays;
March 24, 1977
98-19; Shaft Binding in General Electric Type SBM Control Switches; June 3, 1978
Inspection Manual Chapters
0305; Operating Reactor Assessment Program; February 19, 2003
0350; Oversight of Operating Reactor Facilities in an Extended Shutdown as a Result of
Significant Performance Problems; March 6, 2001
0609; Significance Determination Process; April 21, 2003
Appendix A; Significance Determination of Reactor Inspection Findings for
At-Power Situations; March 18, 2002
Attachment
A30
Appendix C; Occupational Radiation Safety Significance Determination Process;
June 24, 2003
Appendix D; Public Radiation Safety Significance Determination Process; July
24, 2003
Appendix F; Fire Protection Significance Determination Process;
February 27, 2001
Appendix H (Draft) Containment Integrity Significance Determination Process;
July 8, 2003
0612; Power Reactor Inspection Reports; June 20, 2003
Inspection Reports
05000346/1995007; Routine Inspection Report; September 29, 1995
05000346/1999001; Routine Inspection Report; March 5, 1999
05000346/1999004; Routine Inspection Report; June 7, 1999
05000346/2002003; Augmented Inspection Team - Degradation of the Reactor
Pressure Vessel Head; May 3, 2002
05000346/2002012; Special Inspection - Boric Acid Corrosion Extent of Condition;
November 29, 2002
05000346/2002014; Safety System Design and Performance Capability Inspection;
February 26, 2003
05000346/2002017; Integrated Inspection Report; December 9, 2002
05000346/2002019; Integrated Inspection Report; January 31, 2003
Intra-Company Memoranda
NPE 01-00071; OE 12074 - Boric Acid Corrosion of Carbon Steel Components at the
Reactor Coolant System Pressure Boundary; April 27, 2001
NPE 02-00227; Reactor Coolant Pump Issues; August 9, 2002
NPE 03-00047; Reactor Coolant Pump Status to August 9, 2002, White Paper;
April 3, 2003
Generic Letters 89-13; Service Water System Problems Affecting Safety-Related Equipment;
July 18, 1989 and Supplement 1; April 4, 1990
Attachment
A31
91-18; Information to Licensees Regarding Two NRC Inspection Manual Sections on
Resolution of Degraded and Non-Conforming Conditions and on Operability; Revision 1,
October 8, 1997
96-06; Assurance of Equipment Operability And Containment Integrity During
Design-Basis Accident Conditions; September 30, 1996 and Supplement 1; November
13, 1997
Letters
Amendment 33 to Facility Operating License NPF-3 for Davis-Besse Nuclear Power
Station Unit No.1, NRC to Toledo Edison; October 1, 1980
Amendment 45 to Facility Operating License NPF-3 Cycle 3 Operation, NRC to Toledo
Edison; July 28, 1982
Amendment 80 to Facility Operating License NPF-3 Cycle 5 Operation, NRC to Toledo
Edison; December 13, 1984
Component Cooling Water System, First Energy S/N 2949; May 21, 2003
Davis-Besse Nuclear Power Station, Unit 1 - Requests For Relief for the Third 10-year
Interval Inservice Inspection Program Plan (TAC MB1607), NRC to First Energy;
September 30, 2002
Davis-Besse Reactor Coolant Pump Casing Joint Analysis, Flowserve to First Energy;
April 24, 2003
Davis-Besse Reactor Coolant Pump Shaft Bearing Cracking, MPR Associates to First
Energy; February 7, 2003
Evaluation of Ultimate Heat Sink Pond Thermal Performance, Bechtel to First Energy;
May 19, 2002
Exemption from Certain Requirements of Appendix R to 10 CFR Part 50, NRC to Toledo
Edison; August 23, 1984
Inspection of Davis-Besse Reactor Coolant Pumps 2-1 and 2-2, Flowserve to First
Energy; September 16, 2002
Issuance of Amendment 11 to Facility Operating License NPF-3 for Davis-Besse
Nuclear Power Station Unit 1, NRC to Toledo Edison; June 16, 1978
Reactor Coolant Pump Inter-Gasket Leakoff, Flowserve to First Energy; July 2, 2002
Return to Service of Davis-Besse Reactor Coolant Pumps 2-1 and 2-2, Flowserve to
First Energy; February 4, 2003
Attachment
A32
Licensee Event Reports (LERs)
LER 2002-006; EDG Exhaust Piping Not Adequately Protected From Potential Tornado-
Generated Missiles; November 5, 2002
LER-2002-008; Review and Evaluate Containment Air Coolers Collective Significance
LER; Revisions 0 and 1
LER-2002-009; Degradation of High Pressure Injection Thermal Sleeves;
February 3, 2002
LER 2003-007; AC System Analysis Shows Potential Loss of Off-Site Power Following
Design Basis Event; August 5, 2003
Maintenance Work Orders
1-87-3304-00; Check Stud Elongation on All Four Reactor Coolant Pumps;
July 21, 1988
1-97-0553-00; Check P36-1 Casing Studs; May 14, 1998
1-97-0553-01; Check P36-2 Casing Studs; May 14, 1998
1-97-0553-02; Check P36-3 Casing Studs; May 14, 1998
1-97-0553-03; Check P36-4 Casing Studs; May 14, 1998
1-97-0817-04; Reactor Coolant Pump Motor 2-2; April 15, 1998
7-96-0650-01, -02, and -05; Enclosure 7 of DB-MM-09117, R0, Tensioning Data Sheet
from Work Orders for Reactor Coolant Pumps 1-1, 1-2, and 2-1, Respectively
7-96-0650-06; Work in Progress Log, Reactor Coolant Pump 2-2
02-002724-000; Replace Upper Shaft Labyrinth Seal on Reactor Coolant Pump 2-2;
May 6, 2002
02-007012-000; Service Water Pumps and Piping; March 7, 2003
02-007451-000; Temperature Indicator at Service Water Header 1; March 5, 2003
Miscellaneous Documents
Basic Cause Categories Chart; February 27, 1996
Component Parameter Scoping Sheet for Reactor Coolant Pump Vibration Monitoring
1012; Revision 3
CNRB Loss Prevention Subcommittee Meeting; April 23, 2003
Attachment
A33
Condition Report Trending Presentation; August 13, 2003
Corrective Action Program Performance Indicators; various dates
CR Summary Report for Managers Meeting Discussion; August 13, 2003
Davis-Besse EAB August 2003 Monthly Meeting; August 26, 2003
Davis-Besse AC Electrical Distribution Systems, Summary of Issues and Approach for
Resolution; May 15, 2003
Davis-Besse Self Evaluation Process Guide; April 25, 2001
EPRI Topical Report NP-2005; Tornado Missile Risk Evaluation Methodology, Volumes I
and II; August 1981
License Amendment Request 96-0008;Increasing Ultimate Heat Sink Temperature;
July 28, 1999
License Amendment Request 03-0002; to Revise TS 3/4.5.2 ECCS Subsystems - Tavg
> 280F; Revision 25
Managers Communication and Teamwork Meeting; August 26 and 28, 2003
NEI 96-07; Guidelines for 10 CFR 50.59 Implementation; Revision 1
NRC SER; EPRI Topical Reports Concerning Tornado Missile Probabilistic Risk
Assessment (PRA) Methodology; 1983
Photographs Showing Results of Non-Destructive Testing of the 1-1 Pump Shaft Journal
Support Hub; January 14, 2003
Plant Engineering Policy PE-17 Trending; Revision 1
Pre-fire Plans for Rooms AB-318 and AB-319
PR-IAP-3A-01; CAP Implementation Issues Resolution and Restart Readiness;
Revision 2
Quality Trend Summary, First Quarter 2002 Condition Reports; June 3, 2002
Request for Modification 94-0025; Install Service Structure Inspection Openings; Voided
August 31, 1999
Resolution of System Health Assurance Plan Design Issues; December 18, 2002
Restart Performance Indicators; August 3, 2003
Taproot Root Cause Tree Chart; February 27, 1996
Attachment
A34
Technical Specification Table 3.3-4
Three Day CA Look Ahead; March, 19, 2003
Time Line for Reactor Coolant Pump Casing Stud Tension Evaluation; August 15,2003
USAR Change 02-063; Revise Safety Analysis Report to Reflect Use of TORMIS;
November 22, 2002
USAR Chapter 8; Electrical
USAR Figure 9.3-16; Functional Drawing Makeup and Purification System; Revision 20
NQA Audits and Self Assessment Reports
DB-C-02-02; NQA Assessment Report; August 9, 2002
DB-C-02-03; NQA Assessment Report; November 14, 2002
DB-C-02-04; NQA Assessment Report; February 19, 2003
DB-C-03-01; NQA Assessment Report; May 28, 2003
DB-C-03-02; NQA Assessment Report; September 1, 2003
DB-C-03-03; NQA Assessment Report; November 17, 2003
2002-0085; Self Assessment Report, Operating Experience Program; October 3, 2002
Self Evaluation Report; June 2002
Self Assessment Report, Electrical Transient Analysis Program (ETAP) June 2-6, 2003;
Revision 1
0800; Standard Review Plan for the Review of Safety Analysis Reports for Nuclear
Power Plants; Revision 1
1649; Reactor Oversight Process; Revision 3; July 2000
CR 6762; GSI-191 Technical Assessment: Parametric Evaluations for Pressurized
Water Reactor Recirculation Sump Performance; August 2002
Potential Condition Adverse to Quality Reports
1991-0173; ECCS Room Cooling Units; May 14, 1991
1993-0256; Potential Condition Adverse to Quality Report; April 19, 1993
Attachment
A35
1998-0126; Post Accident Sampling Pump P-218 Has Seal Design Which Is Not Leak
Tight; January 25, 1998
Procedures
Self Evaluation Process Guidelines; April 25, 2001
DBBP-LP-2000; Condition Report Process Implementation Expectations; April 4, 2003
DBBP-PI-2005; Cause Analysis Review Group; February 7, 2003
DB-ME-03002; Station Battery Service and Performance Discharge Test; Revision 4
DB-ME-09500; Installation and Termination of Electrical Cables
DB-MM-09320; Jacket Water Heat Exchanger Maintenance; Revision 5
DB-OP-01200; Reactor Coolant System Leakage Management; Revision 5
DB-OP-02037; Emergency Diesel Generator Alarm Panel 37 Operating Procedure;
Revision 2
DB-OP-06016; Containment Air Cooler System Operating Procedure; Revision 2
DB-OP-06261; Service Water System Operating Procedure; Revision 2
DB-OP-06406; Steam and Feedwater Rupture Control System Operation Procedure;
Revision 4
DB-PF-03008; Containment Local Leakage Rate Tests; Revision 5
DB-PF-03020; Service Water Train 1 Valve Test; Revision 5
DB-PF-03027; Service Water Train 2 Valve Test; Revision 5
DB-PF-03117; Baseline and Comprehensive Testing of Service Water Pump 1;
Revision 3
DB-PF-03123; Baseline and Comprehensive Testing of Service Water Pump 2;
Revision 5
DB-PF-03130; Baseline and Comprehensive Testing of Service Water Pump 3;
Revision 5
DB-PF-04152; Auxiliary Feedwater Pump Turbine 1 High Speed Stop and Overspeed
Trip Test; Revision 5
DB-SC-03023; Off-site AC Sources Lined Up and Available; Revision 6
Attachment
A36
DB-SP-03000; Service Water Integrated Train I Flow Balance Procedure
DB-SP-03001; Service Water Integrated Train II Flow Balance Procedure
DB-SP-04152; Auxiliary Feedwater Pump Turbine 1 High Speed Stop and Overspeed
Trip Test
EN-DP-01080; Calculations; Revision 0
NG-EN-00327; RCS Integrated Leakage Program; Revision 0
NG-EN-00385; Program Compliance Review; Revision 0
NG-NA-00711; Quality Trending; March 1, 2003
NG-VP-00100; Restart Action Plan Process; February 6, 2003
NOBP-LP-2007; Condition Report Process Effectiveness Review; March 1, 2003
NOBP-LP-2001; FENOC Focus Self Assessment Guideline; Revisions 0 and 1
NOBP-LP-2004; FENOC Ongoing Self Assessment Guideline; Revision 0
NOBP-LP-2008; Corrective Action Review Board; Revision 0
NOBP-LP-2010; Crest Trending Codes; Revision 0
NOP-CC-3002; Nuclear Operating Administrative Procedure; Revision 0
NOP-ER-1001; Continuous Equipment Performance Improvement; Revision 1
NOP-ER-3001; Problem Solving and Decision Making Process; Revision 0
NOP-LP-2001; Condition Report Process; Revisions 3 and 4
NOP-LP-2004; Internal Assessment Process; Revision 1
RA-EP-02830; Emergency Plan Off Normal Occurrence Procedure; Revision 1
Regulatory Guides
1.4; Assumptions Used for Evaluating the Potential Radiological Consequences of a
Loss of Coolant Accident for Pressurized Water Reactors; Revision 2
1.187; Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and
Experiments; November 2000.
Attachment
A37
Reports
Corrective Action Program Review Summary Report; September 2002
Collective Significance Report Containment Air Cooler Thermal Performance;
March 21, 2003
Assessment of Thermal Performance for the Containment Air Coolers; April 22, 2003
Assessment of Thermal Performance for the Containment Air Coolers; August 9, 2003
Emergency Diesel Generator 1 Jacket Water Cooler Eddy Current Test Report;
July 31, 2002
Emergency Diesel Generator 2 Jacket Water Cooler Eddy Current Test Report;
July 9, 2003
Operating Experience Report 15262; Byron Jackson Reactor Coolant Pump
Casing-to-cover Leakage; January 23, 2003
Operating Experience Report 15383; Preliminary Linear Indications on the Reactor
Coolant Pump 1-1 Shaft Assembly; January 21, 2003
Surveillances
DB-ME-03002; Battery Service Test; completed March 2002
DB-PF-03065; Pressure and Augmented Leakage Test; completed April 2, 2000,
August 27, 2002, and August 28, 2002
DB-PF-04152; Auxiliary Feedwater Pump Turbine 1 High Speed Stop and Overspeed
Trip Test; completed May 10, 2002
DB-SP-03357; Reactor Coolant System Water Inventory Balance; completed
May 3, 1993, November 21, 1994, May 29, 1996, May 23, 1998, and May 22, 2000
DB-SP-03358; Reactor Coolant System Flow Rate Test; completed August 25, 2000
DB-SP-04360; Reactor Coolant System Flow Test; completed August 11, 2000
DB-SP-04363; Reactor Coolant Pumps Hand Rotation; completed August 19, 2003,
September 23, 2003, and October 23, 2003
10 CFR 50.59 Applicability Determination, Screen and Evaluations
02-01740; TORMIS Methodology for Tornado Missile Risk Evaluation;
November 13, 2002
Attachment
A38
03-00087; Screen Use of Fuel Assemblies with Spacer Grid Damage in the Cycle 14
Core - Modes 3, 4, 5, 6; February 1, 2003
Vendor Manual
03-5001383-01; Reactor Coolant Pump Motor Bearing Maintenance, Pages 89AA
through 105; completed April 17 through May 6, 1998
M-001-1; Westinghouse Product Update: Recommended 1-Year, 5-Year, and 10-Year
Reactor Coolant Pump Motor Inspection and Maintenance; November 1991
Attachment
A39
LIST OF ACRONYMS USED
Alternating Current
Agency-wide Document Access and Management System
Augmented Inspection Team
American Society of Mechanical Engineers
Apparent Violation
BACC
Boric Acid Corrosion Control
BWST
Borated Water Storage Tank
Babcock and Wilcox
Containment Air Cooler
Corrective Action Review Board
Corrective Action Program
CATI
Corrective Action Team Inspection
Component Cooling Water
CFR
Code of Federal Regulations
CR
Condition Report
Control Rod Drive Mechanism
Direct Current
EAB
Engineering Assessment Board
Engineering Change Request
Electric Power Research Institute
Environmental Qualification
Engineered Safety Feature
Electric Transient Analysis Profile
FirstEnergy Nuclear Operating Company
Finding
GDC
General Design Criteria
GL
Generic Letter
GPM
Gallons per Minute
High Pressure Injection
HPR
High Pressure Recirculation
IMC
Inspection Manual Chapter
IN
Information Notice
IR
Inspection Report
In-service Inspection
In-service Testing
KSI
Kilo (1000) Pounds per Square Inch
kV
Kilo Volt (1000 volts)
License Amendment Request
lb/ft3
Pounds per Cubic Foot
LER
Licensee Event Report
LIR
Latent Issues Review
Loss of Coolant Accident
Attachment
A40
LIST OF ACRONYMS USED, contd.
Low Pressure Injection
Management Review Board
Non-Cited Violation
NEI
Nuclear Energy Institute
NOBP
Nuclear Operations Business Practice
NOP/NOT
Normal Operating Pressure and Normal Operating Temperature
Net Positive Suction Head
NQA
Nuclear Quality Assessment
NRC
United States Nuclear Regulatory Commission
Office of Nuclear Reactor Regulation
Office of Investigations
Publicly Available Records
Performance Indicator
Power Operated Relief Valve
Project Review Committee
Pounds Per Square Inch Gauge
Reactor Coolant Pressure Boundary
Reactor Coolant Pump
Refueling Outage
RSRB
Restart Station Review Board
Significant Condition Adverse to Quality
Significance Determination Process
SHA
System Health Assurance
Senior Reactor Analyst
SRB
Station Review Board
Structures, Systems, Components
SSDI
Safety System Design and Performance Capability Inspection
the Code
ASME Boiler and Nuclear Pressure Vessel Code
Transient without Power Conversion System
TS
Technical Specifications
Tri-Sodium Phosphate
Unresolved Item
Updated Safety Analysis Report
V
Volts
Vac
Volts (alternating current)
Vdc
Volts (direct current)
Violation
Work Order
F
Degrees Fahrenheit