ML030630314
| ML030630314 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 02/26/2003 |
| From: | Grobe J NRC/RGN-III |
| To: | Myers L FirstEnergy Nuclear Operating Co |
| References | |
| FOIA/PA-2003-0376 IR-02-013, IR-02-014 | |
| Download: ML030630314 (106) | |
See also: IR 05000346/2002013
Text
February 26, 2003
Mr. Lew 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 INSPECTION - SYSTEM HEALTH ASSURANCE - REPORTS
NO. 50-346/02-13(DRS) and 50-346/02-14(DRS)
Dear Mr. Myers:
On November 13, 2002, the NRC completed a special inspection at your Davis-Besse Nuclear
Power Station. This inspection reviewed your actions to resolve Restart Checklist Item No. 5.b,
associated with assuring the capability of safety significant structures, systems and components
to support safe and reliable plant operation. Specifically, this inspection focused on review of
activities as described in the Davis-Besse System Health Assurance Plan. The plan consisted
of three review programs: an Operational Readiness Review (ORR), a System Health
Readiness Review (SHRR), and a Latent Issues Review (LIR). Our inspection of this plan
included reviewing the plans and procedures for the ORR, SHRR, and LIR, monitoring the work
of the SHRR and LIR teams in-progress, monitoring Nuclear Oversight activities, attending
review board meetings, and reviewing Condition Reports generated by the teams as reviews
were conducted and discrepancies were identified. The inspectors also monitored training of
reviewers, conducted walkdowns of selected systems, examined emergent issues, reviewed
independent self-assessments of systems, and reviewed two SHRR reports. In addition, to
assess the quality of your staffs reviews, the NRC conducted an in-depth design and
performance capability review of the Service Water, High Pressure Injection, and 4160 Volt AC
Electrical Distribution systems. The enclosed reports document the findings of this special
inspection, which were discussed with you and other members of your staff during an exit
meeting on November 13, 2002.
Report No. 50-346/02-13(DRS) discusses the review of the plans, procedures, and
implementation of the System Health Assurance Plan. No violations of NRC rules or
regulations were identified. The inspectors concluded that the System Health Assurance Plan
was well-designed, plans and procedures were appropriate to the circumstances, the program
was rigorously implemented, and quality assurance review by the Nuclear Oversight
Department was adequate. At the close of the inspection, only two of the 36 anticipated review
reports had been completed. The inspectors reviewed the System Health Readiness Review
Report for the 125/250 Volt DC Electrical Distribution system and concluded that the review had
been performed acceptably.
L. Myers -2-
Report No. 50-346/02-14(DRS) discusses the in-depth design and performance capability
review of the Service Water, High Pressure Injection, and 4160 Volt Electrical Distribution
systems. The inspectors identified four findings, one with multiple examples, of very low safety
significance (Green) that were determined to involve violations of NRC requirements. The first
finding involved failure to complete Technical Specification surveillance requirement 4.2.5.H,
associated with High Pressure Injection pump flow following modifications that could alter
system flow characteristic. The second finding involved examples of failure to assure that
applicable regulatory requirements and the design basis for structures, systems, and
components were correctly translated into specifications, drawings, procedures, and
instructions related to a non-conservative TS value for the 90 percent degraded voltage relay, a
non-conservative relay setpoint calculation for the 59 percent undervoltage relay, an inadequate
analytical basis for the setpoint to swap the service water system discharge path, a lack of a
design basis analysis for containment isolation valve backup air supply accumulators, and
inadequate blowdown provisions for Containment Air Cooler backup air accumulators. The
third finding involved a service water surveillance test that did not use worst case values to
bound the design basis conditions. The fourth finding involved failure to take prompt corrective
actions for incorrect service water pump discharge check valve test acceptance criteria. In
addition, the inspectors identified seventeen issues where design control may have been
inadequate; however, at the close of the inspection, insufficient information was available to
draw a conclusion regarding the acceptability of these items which are identified as unresolved
items in the report. Additional analyses, in most cases by your staff, are necessary to generate
the information needed to resolve the issues.
Because of the very low safety significance of the findings and because these issues have
been entered into your corrective action program, the NRC is treating these issues as
Non-Cited Violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If
you deny these Non-Cited Violations, you should provide a response with a basis for your
denial, within 30 days of the date of this inspection report, to the Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the
Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the
Davis-Besse Nuclear Power Station.
The results of our review of the Service Water system were consistent with your Latent Issues
Review and a corporate Nuclear Oversight self-assessment. All three efforts identified a
significant number of deficiencies in calculations, analyses, and testing which will require
resolution prior to restart. We are also aware that the Latent Issues Reviews on the component
cooling, emergency diesel, auxiliary feedwater, and reactor coolant systems identified similar
deficiencies. As a result of these findings, we have concluded that the Latent Issues Reviews
were performed in a manner sufficient to reasonably determine whether or not systems were
capable of performing their safety functions during future plant operation.
Because the majority of the System Health Assurance Plan reports were not ready for review
by the close of the inspection and because the findings of the Latent Issues Review program
dictate the need to expand the scope of system reviews, Restart Checklist item 5.b will remain
open and subject to continued inspection.
L. Myers -3-
In accordance with 10 CFR Part 2.790 of the NRCs "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRCs
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
John A. Grobe, Chairman
Davis-Besse Oversight Panel
Docket No. 50-346
License No. NPF-3
Enclosures: 1. NRC Special Inspection Report
No. 50-346/02-13(DRS)
2. NRC Special Inspection Report
No. 50-346/02-14(DRS)
cc w/encls: B. Saunders, President - FENOC
Plant Manager
Manager - Regulatory Affairs
M. OReilly, FirstEnergy
Ohio State Liaison Officer
R. Owen, Ohio Department of Health
Public Utilities Commission of Ohio
President, Board of County Commissioners
Of Lucas County
President, Ottawa County Board of Commissioners
D. Lochbaum, Union of Concerned Scientists
L. Myers -3-
In accordance with 10 CFR Part 2.790 of the NRCs "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRCs
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
John A. Grobe, Chairman
Davis-Besse Oversight Panel
Docket No. 50-346
License No. NPF-3
Enclosures: 1. NRC Special Inspection Report
No. 50-346/02-13(DRS)
2. NRC Special Inspection Report
No. 50-346/02-014(DRS)
cc w/encls: B. Saunders, President - FENOC
R. Fast, Plant Manager
Manager - Regulatory Affairs
M. OReilly, FirstEnergy
Ohio State Liaison Officer
R. Owen, Ohio Department of Health
Public Utilities Commission of Ohio
President, Board of County Commissioners
Of Lucas County
President, Ottawa County Board of Commissioners
D. Lochbaum, Union of Concerned Scientists
DOCUMENT NAME: G:DRS\ML030630314.wpd
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy
OFFICE RIII E RIII N RIII RIII
NAME MFarber:sd RGardner CLipa JGrobe
DATE 01/24/03 01/24/03 02/20/03 02/26/03
OFFICIAL RECORD COPY
L. Myers -4-
ADAMS Distribution:
AJM
SPS1
RidsNrrDipmIipb
GEG
CST1
C. Ariano (hard copy)
DRPIII
DRSIII
PLB1
JRK1
DB0350
ENCLOSURE 1
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No: 50-346
License No: NPF-3
Report No: 50-346/02-013
Licensee: FirstEnergy Nuclear Operating Company
Facility: Davis-Besse Nuclear Power Station
Location: 5501 North State Route 2
Oak Harbor, OH 43449
Dates: September 3 through November 13, 2002
Inspectors: M. Farber, Senior Reactor Inspector
J. Jacobson, Senior Mechanical Engineer
G. Hausman, Senior Reactor Inspector
Approved by: Ronald N. Gardner, Chief
Electrical Engineering Branch
Division of Reactor Safety
SUMMARY OF FINDINGS
IR 05000346-02-013; FirstEnergy Nuclear Operating Company; on 09/03-11/08/02;
Davis-Besse Nuclear Power Station. System Health Assurance Plan Implementation Inspection
The report covers a special inspection, by three regional inspectors, of the Davis-Besse Nuclear
Power Station System Health Assurance Building Block. The NRCs program for overseeing
the safe operation of commercial nuclear power reactors is described in NUREG-1649,
Reactor Oversight Process, Revision 3, dated July 2000.
A. Inspector Identified Findings
None
B. Licensee Identified Findings
None
2
REPORT DETAILS
4. OTHER ACTIVITIES
4OA3 Event Follow-up (93812)
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 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 the Davis-Besse Nuclear Power Station (reference NRC
report 50-346/02-03(DRS)).
The System Health Assurance (SHA) Plan is one of seven building blocks identified as
part of the licensees Return to Service Plan. The intent of the SHA plan was to review
plant systems prior to restart to ensure that these systems were in a condition that
would support safe and reliable information. The plan consisted of three review
programs: an Operational Readiness Review (ORR), a System Health Readiness
Review (SHRR), and a Latent Issues Review (LIR). NRC inspectors reviewed the
activities as described in the SHA plan. Given the high public interest in this subject
area at Davis Besse, and therefore the need to clearly communicate the rationale for
NRC staff conclusions regarding the effectiveness of licensee extent of condition
inspections, this report documents the inspectors observations.
a. Inspection Scope
The inspectors reviewed the plans and procedures for the ORR, SHRR, and LIR,
monitored the work of the SHRR and LIR teams in-progress, monitored Nuclear
Oversight activities, attended review board meetings, and reviewed Condition
Reports (CR) generated by the teams as reviews were conducted and discrepancies
were identified. The inspectors also monitored training of reviewers, conducted
walkdowns of selected systems, examined emergent issues, reviewed independent
self-assessments of systems, and reviewed two SHRR reports.
1
b. Observations and Findings
b.1 Operational Readiness Reviews
a. Introduction
The inspectors examined the Operational Readiness Review (ORR) program, CRs
issued as a result of the reviews, and the final ORR report.
b. Description
The licensee initiated the ORR program before the NRC implemented the Manual
Chapter 0350 process for Davis-Besse. The licensee developed this program to
ensure that selected systems and programs were in a condition that would support safe
and reliable plant operation through the forthcoming operating cycle (cycle 14) and
beyond. The ORR was initiated by the Plant Manager and consisted of a panel
composed of system engineers and representatives of other site organizations.
Forty-one systems and eight programs were selected for review, based on risk
significance, Maintenance Rule performance, materiel condition, and operator burden.
The ORRs were patterned on the licensees Quarterly System Health Report and
covered the selection criteria plus significant issues or corrective actions, mode
restraints, latent issues, and operating experience.
ORRs were nearly completed when the SHA plan was in development. The ORR was
incorporated into the SHA plan to ensure that all system review efforts were captured
under one program, that findings were retained and properly documented, and that
appropriate corrective actions were specified. After the reviews were completed, a
CR was generated by the Quality Assurance (QA) Department documenting concerns
with the administration and tracking of action items identified during the ORR.
Subsequently, a rigorous validation program for ORR was conducted to ensure that the
program was adequately documented, that new issues or changes were identified, and
that issues were entered into the corrective action program. Forty-two CRs were
generated which listed the issues and related outstanding corrective actions for
40 systems and two programs.
c. Observations and Findings
No findings were identified. The ORR was a proactive effort at system assessment.
The concept of a multi-disciplined panel consisting of management and supervisory
personnel reviewing the system engineers analysis of system condition was
well-conceived. While the system engineers analyses and panel reviews appeared
thorough, the project lacked rigor in the recording, tracking, and statusing of issues and
action items which were identified by the program. The QA condition report (02-02941)
noted that action items were not documented in CRs, that action items were overdue,
with no formal tracking mechanism to ensure completion, and that ORR action items
were not screened for inclusion in the Restart Action List. The subsequent validation
effort identified issues that were not evident in the original ORR. The validation effort
2
introduced the necessary rigor to the documentation process and resulted in a
complete, concise tabulation of issues.
b.2 System Health Readiness Reviews
a. Introduction
The inspectors reviewed the plans and procedures for SHRRs, reviewed the charters for
the various panels and boards established to oversee the SHA plan, monitored reviews
in progress, interviewed reviewers, examined scoping and testing memos, walked down
systems, observed meetings of the Engineering Assessment Board, Restart Station
Review Board, and Restart Senior Management Team, reviewed CRs that were related
to SHRRs, and examined emergent issues, i.e., issues not directly related to SHRR, but
identified as a result of walkdowns or examining SHRR documents.
b. Description
b.2.1 Procedure and Process
SHRRs were performed for 31 systems categorized as risk-significant under the
licensees Maintenance Rule program. The intent of SHRRs was to assess the
material condition of the systems and to determine whether process or programmatic
issues existed that could potentially have an adverse impact on system operability or
functionality. Five, more risk-significant systems were reviewed under the LIR program
which will be discussed later in this report. SHRRs were conducted using procedures
EN-DP-01503, System Walkdown, and EN-DP-01504, System Health Readiness
Review. Revisions to these procedures were issued during the course of reviews; these
revisions are listed at the end of this report.
The inspectors reviewed both procedures noted above, along with the charters for
the Engineering Assessment Board, Restart Safety Review Board, and Restart Senior
Management Team. EN-DP-01503, System Walkdown, provided a structured process
for conducting system walkdowns and recording deficiencies, and provided lists of
potential problems and conditions as criteria for identifying deficiencies. EN-DP-01504,
System Health Readiness Review, provided training requirements, documents to be
reviewed, a structure and process for defining the scope of the reviews, establishing the
testing necessary to support safety functions, selecting data sources and conducting
data source reviews, criteria and process for expanding the review scope, and
preparation, review, and approval of the final report.
c.2.1 Observations and Findings
No findings were identified. The inspectors determined that both procedures were
well-written, logical, complete, and appropriate to the circumstances. One minor
procedural problem was identified. The inspectors learned from interviews, CRs, and
schedule reviews, that walkdowns and document reviews were being conducted in
parallel with the development of the scoping and testing letters. There was no formal
mechanism in the SHRR procedure to ensure that changes mandated by EAB to either
3
the scoping or testing memoranda would be reflected back into the walkdowns or
document reviews. This resulted in the potential that approved changes might not be
completely reviewed. The licensee issued a procedure revision to address this issue.
No other problems were identified.
b.2.2 Training
Requirements for training SHA reviewers were specified in the SHRR procedure. This
training covered system design and licensing basis, site-specific databases, Generic
Letter 91-18 (Operability Determinations), the system walkdown procedure, FirstEnergy
Principles and Expectations, and the system health readiness review process.
The inspectors reviewed training records, met with instructors, and attended a training
session for reviewers.
c.2.2 Observations and Findings
No findings were identified. The inspectors considered the training provided for SHA
reviewers to be well-developed, adequately administered, and appropriate to the
circumstances. Training records were properly maintained, and documented the
training and qualification of all SHA reviewers. Through the combination of interviews
and attending training sessions, the inspectors determined that instructors were
qualified, knowledgeable of the SHA program, and well-prepared to lead the training
sessions.
During one training session, the inspector observed that several class members were
apparently disinterested and not paying attention. At the end of the session, when the
instructor was questioning the class to assess the level of retention, these individuals
were unable to answer the instructors questions. The inspector brought this to the
attention of licensee management. The class was subsequently retrained and tested to
ensure that training objectives were met.
b.2.3 System Walkdown
Complete system walkdowns, covering the entire scope of the system, were required
under the SHRR procedure. These were conducted using EN-DP-01503, System
Walkdowns. The walkdowns were led by the SHRR team leader, generally conducted
by the entire team, and deficiencies were identified on CRs. To assess the quality of
SHRR walkdowns, the inspectors conducted a plant-wide walkdown which included
SHRR and LIR systems. The intent was to compare inspector-identified deficiencies to
those of the walkdown team. The inspectors assessment of the quality of the walkdown
was based, in part, on the number and significance of discrepancies found by the
inspectors, but not by the teams. After the inspectors walkdown was completed, the
inspectors reviewed a sample of the CRs issued to assess the number and significance
of discrepancies identified by the walkdown teams.
4
c.2.3 Observations and Findings
No findings were identified. The inspectors identified a very small number of minor
discrepancies not identified by the SHRR walkdown teams; the licensee issued CRs to
document the inspectors observations.
Among the discrepancies was inconsistency in the lubrication of manually-operated
valves. The inspectors noted that for three identical manual valve operators, one
appeared to be over-greased, one appeared to be satisfactory, and one valve operator
did not have a grease fitting installed. This became an emergent issue which is
discussed in Section b.2.6 below. Another discrepancy was inconsistency in greasing of
seismic support struts. The inspectors noted that one seismic strut near a Component
Cooling Water pump was over-greased while the grease fittings on a nearby strut were
painted over. This became an emergent issue which is also discussed in Section b.2.6
below.
The inspectors concluded that the system walkdowns conducted by the licensee using
EN-DP-01503, System Walkdowns, were thorough and appropriate to the
circumstances. This conclusion was based on the following:
- the number of deficiencies identified by the walkdown teams;
- the inspectors did not identify any significant deficiencies missed by the licensee;
and
- the number of deficiencies found by the inspectors, but not by the teams, was
very small.
b.2.4 Engineering Assessment Board (EAB)
The role of the EAB was defined in DBE-0001, Engineering Assessment Board
Role/Policy in Support of the Return to Service Plan. The EABs mission was to provide
senior level oversight and technical review of engineering products and processes.
EABs charter included:
- assist site and engineering management with oversight of Return to Service
activities;
- provide technical review of engineering products as requested by engineering
management;
- review Return to Service Building Blocks;
- ensure implementation of the FENOC Engineering Principles and Expectations;
- provide qualitative assessment of products to identify engineering progress; and
- provide feedback to engineering management and staff.
The inspectors reviewed DBE-0001 to understand the role EAB was expected to play,
interviewed the leadership and members of the EAB, examined EAB documented
reviews and comments on a large number of engineering products, and attended
several EAB meetings where SHA engineering products were reviewed.
5
c.2.4 Observations and Findings
No findings were identified. The inspectors determined that the EAB made significant
contributions to the quality of SHA engineering products. The EAB had several specific
responsibilities in both the SHRR and LIR programs. For brevity, EAB activities will only
be discussed in this section.
EAB responsibilities in the SHA included review and concurrence with:
- scope, including the identified system boundaries, the selected components, and
justification for their selection;
- identified testing or review of other information that assessed on a periodic
frequency, the systems risk significant maintenance rule functions;
- recommendations for expanding the scope of review when problems are found;
and
- final report to ensure the reviews complied with the procedure and were
complete, findings were adequately documented, and activities were in place to
address issues.
EAB membership was composed of very experienced consulting engineers; a large
percentage had in excess of 30 years of nuclear experience. EAB subcommittees were
established to oversee System Health, Program Review, and Management and Human
Performance. Early in the SHA program, through its review and comments on system
scope and boundaries, EAB established a high standard for completeness, accuracy,
and depth of detail. EAB members were provided engineering products which were
examined in detail. EAB then met with the author and the supervisor who presented the
product and responded to EAB questions and comments. In all the meetings that the
inspectors attended, EAB members were clearly well-prepared. Questions and
comments ranged from process to procedural to technical to philosophical; all were
in-depth, focused on the product, and challenging. The inspectors examination of
documented reviews of testing memos and completed reports showed that this level of
review and comment was consistent with all products.
b.2.5 Report Review
The inspectors reviewed the licensees completed System Health Readiness Review
Report for the 125/250 VDC System. The inspectors review was to verify that the
activities performed by the licensee during the SHRR reports preparation, review, and
approval were completed in accordance with EN-DP-01504, System Health Readiness
Review, Revision 2.
c.2.5 Observations and Findings
No findings were identified. However, the inspector identified two CRs that were
considered potential restart items, a fuse issue that may be generic to all electrical
systems, and several minor editorial errors.
6
The two CRs were CR 01-01232, Crack in Battery Post Seal Ring, dated June 22,
2001, and CR 02-00412, DC Voltage Drop Calculation, dated February 8, 2002.
- Condition Report 01-01232 identified a broken battery post seal nut on cell 21 of
the 2P battery. The system engineer concurred that the CR should be changed
to a recommend for restart item because the 2P battery must be taken
out-of-service to complete the CRs corrective action. Since the 2P battery was
being disassembled during the current outage for corrosion product removal
(CR 02-03354), this outage would be the appropriate time to replace the broken
battery post seal nut.
- Condition Report 02-00412, stated that DC Calculation C-EE-002.01.010 did not
adequately address small loads on the dc system. Based on the CR and SHRR
report, the inspectors could not conclude that this issue was not a restart item.
The system engineer concurred with the inspectors that the CR and the report
did not clearly indicate whether the issue involved an actual addition of loads to
the battery or was only concerned with the voltage drop of the circuits supplying
the small loads. Further review revealed that the issue involved voltage drops
and was properly classified.
The potential generic fuse issue was identified by CR 02-04586, SHRR: 1992 PCAQR
Corrective Action Not Yet Completed - Fuse Size, dated August 23, 2002, which was
identified as a recommend for restart item by the system engineer. This CR was
written following the 125/250 VDC SHRR walk-down, where several switches were
identified with a maintenance information tag (sticker) stating PCAQR 92-0030. The
PCAQR addressed several circuits throughout the plant where the installed fuse did not
match that specified by drawing E-2014. Drawing E-2014 was the licensees controlled
fuse drawing. All the fuses identified by the 1992 PCAQR were evaluated and
determined to be acceptable for continued operation with the understanding that the
fuses would be replaced upon fuse failure with the correct fuse. However, the E-2014
drawing was not annotated to identify that upon fuse failure the fuse was to be replaced
per the PCAQR. The inspectors were concerned that this issue may be generic to all
electrical systems and not just the 125/250 VDC system. The system engineer
concurred with the inspectors that the PCAQR identified fuses in other plant systems
that should be replaced and that he would ensure that the other affected systems
system engineer would be made aware of this issue.
Subsequent to the NRC inspectors inspection, the 125/250 VDC system engineer
issued Milestone #14-1, System Health Readiness Review for 125/250 VDC System,
Amendment 2, Revision 00, dated November 14, 2002, which resolved the inspectors
concerns identified above.
It was the intent of this inspection to review five completed SHRR reports. At the close
of this inspection, two reports had been issued. One of those was discussed above.
The inspectors will return to examine four additional reports when all 31 have been
formally completed; results of that inspection will be documented in a separate
inspection report.
7
b.2.6 Emergent Issues
Issues, not directly related to SHA, but needing licensee attention, were identified
throughout the course of the inspection as inspectors walked down systems, reviewed
condition reports, interviewed licensee staff, or examined other system health
documents. The inspectors monitored the licensees response to these issues to gain
insights on the licensees ability to understand the issue, determine the extent of
condition, assess significance, and identify and implement appropriate corrective
actions.
c.2.6 Observations and Findings
During the plant-wide walkdown, the inspectors noted inconsistencies in lubrication of
identical manual valve operators. A CR was issued and the licensee staff began to
examine the issue. In discussions with the staff, it was revealed that although the need
had been recognized, the station had no program for consistent maintenance of critical
manual valves. The licensees staff committed to develop such a program. During a
review of Condition Report 02-02397, the inspector noted in the description of the
condition, that the station had no preventive maintenance program for molded-case
circuit breakers. In discussions with the staff, it was revealed that the need had been
recognized, but the program had not been developed or implemented. The licensee
staff indicated plans to develop such a program. With these two issues as background,
the inspectors questioned the extent of component-based reliability or maintenance
programs and learned that the station only had a very small number. Further
discussions with the licensees staff revealed that an October 1999 self-assessment had
revealed this condition and recommended the establishment of component-based
programs. No action appeared to have been taken. This concern was presented to
licensee management, who acknowledged the concern and directed that a CR,
documenting the lack of response to the 1999 self-assessment, be issued. Resolution
of CR 02-08742 was in progress at the close of the inspection.
During the plant-wide walkdown, the inspectors identified inconsistencies in lubrication
of seismic support struts. A CR was issued and the licensee evaluated the condition.
The licensee identified that all the seismic supports supplied to the plant during
construction used a dry-film lubricant, intended to last for the life of the plant. Greasing
was unnecessary but if the strut was greased, it would then need periodic regreasing.
The licensee was unable to determine when the strut had been greased or if it had been
regreased. A condition report was issued to conduct an extent of condition and to
evaluate operability impacts of greasing and then failing to regrease these struts.
Resolution of CR 02-06765 was in progress at the close of the inspection.
During review of the licensees self-assessment conducted on the High Pressure
Injection (HPI) system, the inspectors examined a table of late commitments.
Commitment 10752, dated November 21, 1979, to submit information on HPI protection
against deadheading during a small-break loss-of-coolant accident, was listed as
pending. The licensee acknowledged that the commitment tracking system was
problematic and in need of corrective action. In response to the inspectors technical
questions on this issue, the licensee staff assembled a closure package which consisted
8
of the November 21, 1979 NRC letter requesting information on the topic, the
licensees December 28, 1979 response, and procedures involving HPI operation.
The licensees December 1979 letter did not properly address the issue of HPI
deadheading during small-break loss-of-coolant accident. Two of the procedures were
for Integrated Leak Rate Test and contained steps for leaving the HPI recirculation
valves open during the test. The current HPI operating procedure, included in the
package, contained a caution that during HPI operation taking suction on the
containment sump, the recirculation valves must be closed. This is exactly the
alignment which could lead to deadheading the HPI pumps during a protracted
small-break loss-of-coolant accident. None of the information in the closure package
properly addressed the issue. The inspectors expressed their concerns to management
regarding this inadequate response. The NRC team inspection, documented in
Inspection Report 50-346/2002014, independently raised questions about deadheading
the HPI pumps during a small-break loss-of-coolant accident. Consequently, the
licensees analysis, generated as a result of the team inspection, will address the
technical issue.
b.3 Latent Issues Reviews
a. Introduction
The inspectors reviewed the plans and procedures for LIRs, monitored reviews in
progress, interviewed reviewers, examined scoping and testing memos, walked down
systems, reviewed CRs issued that were related to LIRs, and examined emergent
issues, i.e., issues not directly related to LIR, but identified as a result of walkdowns or
examining LIR documents. LIRs were conducted on the Reactor Coolant, Auxiliary
Feedwater, Component Cooling, Emergency Diesel Generator, and Service Water
systems.
b. Description
b.3.1 Procedure and Process
LIRs were performed for five systems listed above, all of which were categorized as
risk-significant under the licensees Maintenance Rule program. The intent of LIRs,
as stated in the System Health Assurance Plan, was to provide reasonable
assurance that five systems could perform their safety and accident mitigation
functions. LIRs were conducted using procedures EN-DP-01503, System Walkdown,
and EN-DP-01505, Latent Issues Review. Revisions to these procedures were issued
during the course of reviews; these revisions are listed at the end of this report.
The inspectors reviewed both procedures noted above. EN-DP-01503, System
Walkdown, provided a structured process for conducting system walkdowns and
recording deficiencies, and provided lists of potential problems and conditions as criteria
for identifying deficiencies. EN-DP-01505, Latent Issues Review, provided training
requirements, documents to be reviewed, a structure and process for defining the scope
of the reviews, establishing the testing necessary to support safety functions, selecting
data sources and conducting data source reviews, criteria and process for expanding
9
the review scope, and preparation, review, and approval of the final report. These are
identical to the SHRR; however, the LIR went into greater detail, included a greater span
of data sources, and contained design basis inspection attributes that the SHRR did not.
The LIR was also more tightly structured to ensure consistency of review across the five
systems.
c.3.1 Observations and Findings
No findings were identified. The inspectors determined that both procedures were
well-written, logical, complete, and appropriate to the circumstances. The LIR
procedure had the same minor procedural problem as the SHRR procedure, in that
there was no formal mechanism in the LIR procedure to ensure that changes mandated
by EAB to either the scoping or testing memoranda would be reflected back into the
walkdowns or document reviews. As with the SHRR procedure, this was addressed in a
procedure revision.
b.3.2 Team Leader Meeting
The licensee held a weekly meeting with LIR team leaders to review progress, discuss
review approaches, identify common issues, and resolve problems. The inspectors
attended one meeting.
c.3.2 Observations and Findings
The meeting was attended by all team leaders, assistant team leaders, system health
assurance supervisors, and engineering management. The meeting was well organized
and conducted; there was a prepared agenda which was followed. There was a good
exchange of information, team leaders and supervisors spoke frankly about progress,
problems, and emerging issues.
b.3.3 System Walkdown
The inspectors performed a walkdown of the auxiliary feedwater system and
reviewed the results of the licensees previous walkdown efforts. The purpose of
the walkdown was to assess the physical condition of the system and verify the
quality and thoroughness of the licensees previous efforts. The licensees procedure
EN-DP-01503, Revision 2, System Walkdowns, was reviewed prior to the walkdown.
c.3.3 Observations and Findings
Overall, the licensees walkdown efforts were found to be effective. The materiel
condition of the auxiliary feedwater system appeared to have issues which required
corrective actions.
The System Walkdowns procedure provided reasonable guidance for identifying any
materiel degradations and cleanliness deficiencies in the system. The licensees
walkdown efforts identified numerous issues, especially in the areas of environmental
qualification and high energy line break. The inspector identified three conditions
10
adverse to quality which had not been previously identified by the licensees effort:
Fitting leakage and boric acid build up was found on tubing from CW-275J and sample
cooler S6B2. The licensee issued condition report CR 02-06268 to document the
leakage. Fluid leakage from a hydraulic snubber near orifice AF-4630 was noted. The
licensee issued condition report CR 02-06273 to document the leakage. Bearing lube
oil supply and return lines were found rubbing together on auxiliary feedpump 1-1. The
licensee issued condition report CR 02-06274 to document this condition.
b.3.4 Emergent Issues
As the LIRs progressed, the licensee began to analyze and trend the CRs that were
being written. This collective significance review was expanded to include
self-assessment results, EAB program reviews, SHRR issues, and the NRC team
inspection. The collective significance review revealed a number of problem areas
common to all five of the LIRs. Among these problem areas were design basis
validation, environmental qualification, high energy line break, missing or flawed
calculations, calculation control, accident analysis, system descriptions, and
configuration management.
The identification of these common problem areas resulted in the recognition by
licensee management that the scope of the SHA needed to be expanded. The
inspectors reviewed the CRs issued as a result of the collective significance review,
examined the list of common problem areas and the underlying data, and met
repeatedly with SHA staff to monitor the status of the review and development of
expansion plans.
c.3.4 Observations and Findings
No findings were identified. The licensee examined several expansion plan methods for
feasibility, effectiveness, efficiency, scope, and depth of review. At the close of this
inspection, a final plan had not been adopted. The inspectors will continue to monitor
the licensees progress on this issue.
One of the proposed expansion methods involved use of the Design Basis Document
Validation Program (DBDVP), which the licensee had committed to complete in
response to the NRCs October 1996 10 CFR 50.54.f letter on adequacy and availability
of design bases information. The licensee compared deficiencies identified during the
LIR to those identified during the DBDVP. The expectation was that if there was good
correlation on findings between the two programs, then the findings of the DBDVP
would be used as the basis for expansion. The licensees examination of the DBDVP
concluded that there was insufficient correlation between the two programs to support
using DBDVP for expansion plans. In addition, the licensees review identified problems
with the DBDVP; the program had not been completed and a portion of the deficiencies
identified had not been properly corrected.
The inspectors reviewed all of the related correspondence, the DBDVP instruction, the
Design Basis Validation Report of the Service Water System, and the Service Water
System Description. The inspectors also interviewed licensee staff members who had
11
been involved with the project. The project, though a commitment to NRC in response
to the 10 CFR 50.54.f letter, was delayed about two years due to engineering resource
considerations. The licensee, on recognizing that station resources would remain a
restraint, elected to contract for the reports. Two engineering organizations were
contracted to prepare the validation reports and work on the project was commenced.
From all of the systems validated, there were slightly more than 1000 identified
deficiencies. These were characterized as either high, medium, or low significance
and work was initiated to correct them. At the close of this inspection, approximately
200 deficiencies had not been corrected. The inspectors reviewed the deficiency
tracking list and open item log sheets for the service water and found where the
resolution of an issue assigned a high significance rating was inadequate. The issue
concerned rated flow in the service water system description that didnt include all
possible flows. The prescribed resolution for this deficiency was that it was to be
corrected in the system description. It failed to recognize that the analyses related to
rated service water flow or using rated service water flow needed to be examined. This
deficiency was noted by both the LIR team and the NRC team inspection. As corrective
action, the licensee plans to:
- establish an event time line of identified deficiencies and opportunities to improve
design information availability and adequacy;
- identify why the DBDVP was not completed;
- confirm that the DBDVP discovery phase was adequate; and
- evaluate why the DBDVP and other, prior programs and activities did not resolve
the identified discrepancies.
b.3.5 Report Review
Planning for this inspection included a detailed review of all five LIRs. This was
considered an import review effort because these were the most in-depth of all the
licensees reviews and conclusions drawn on the quality of the LIRs would be an
important considered in assessing the over quality of the SHA effort .
c.3.5 Observations and Findings
At the close of this inspection, none of the LIR reports had been reviewed or approved
by licensee management and were therefore unavailable for inspection. The inspectors
will return to examine these reports when they have been formally completed; results of
that inspection will be documented in a separate inspection report.
b.4 Quality Assessment Oversight
a. Introduction
During development of the Restart Action Plan and the related seven building blocks,
licensee management recognized the necessity of quality assurance oversight
throughout the process. Consequently, as the building block plans were being
developed, the Nuclear Quality Assessment (NQA) organization prepared a plan for
oversight of restart activities. The plan, entitled Nuclear Quality Assessment Oversight
12
of Davis-Besse Return to Service Plan, Revision 1, was approved by the Vice President
of FirstEnergy Oversight on July 22, 2002. The stated mission was to provide oversight
and verify the adequacy of activities conducted as part of the Return to Service Plan.
For each of the seven building blocks, the NQA plan contained specific objectives to be
accomplished through monitoring and assessment of key activities. The inspectors
reviewed the NQA oversight plan, met periodically with NQA staff and management,
reviewed Quality Field Observations (QFO), reviewed CRs written by NQA staff, and
reviewed the three independent system reviews performed by the NQA staff.
b. Description
b.4.1 Planning
To meet the objectives spelled out in the oversight plan, the NQA staff developed a
comprehensive program of review and monitoring during the development and
implementation of SHA processes. The program included review of training, attendance
at ORR, EAB, Restart Safety Review Board, and Restart Senior Management Team
meetings, in-line review and comment for SHRR and LIR inspection plan and procedure
development, assessment of scope and testing for SHRR and LIR, oversight of
walkdowns, independent system health readiness reviews conducted in accordance with
the SHRR procedure, and a comparison between the SHRR team and NQA results for
the selected system.
c.4.1 Observations and Findings
No findings were identified. The inspectors determined that NQA had developed a
comprehensive oversight program to assess the implementation of the SHA plan.
During initial discussion with NQA staff and management, the inspectors recognized
that while there was a provision for generation of a quarterly roll-up of QFOs, NQA had
not established how the comprehensive results of monitoring and reviews of SHA
implementation would be documented for presentation to senior licensee management.
After deliberation, NQA management elected to prepare a complete roll-up report of
assessment activities, findings and observations, and conclusions after the SHA
programs were completed. The inspectors considered this acceptable.
b.4.2 Monitoring
The NQA plan directed frequent monitoring of walkdowns, briefings, LIR and SHRR
team meetings, and review boards. These activities were documented through issuance
of QFOs, in accordance with NOP-LP-2004, Internal Assessment Process, and
issuance of CRs in accordance with NOP-LP-2001, Condition Report Process.
c.4.2 Observations and Findings
The inspectors review of CRs and QFOs confirmed the frequency and depth of NQA
involvement in process and procedure development; NQA comments and concerns
strengthened the review programs.
13
b.4.3 Independent System Review
The NQA plan for oversight directed the independent performance of three SHRRs
using EN-DP-01504, System Health Readiness Reviews. These independent reviews
were to be conducted by NQA staff and the results compared to the findings of the
SHRR teams for the selected systems, which were 125/250VDC Electrical Distribution,
Station and Instrument Air, and Decay Heat Removal/Low Pressure Injection. The
inspectors reviewed the reports of the three independently performed reviews and the
comparative analysis for the 125/250VDC Electrical Distribution system, which was
issued as a QFO.
c.4.3 Observations and Findings
No findings were identified. The inspectors found that the independent reviews had
been conducted in accordance with the SHRR procedure. The inspectors determined
that the findings between the two reviews were essentially similar; this was borne out by
the review of the comparative analysis.
b.5 Self-Assessment
a. Introduction
After being informed that the HPI, 4160VAC Electrical Distribution, and Service
Water systems had been selected for examination by the NRC design team inspection
(Inspection Report 50-346/02-14(DRS)), the licensee elected to perform
self-assessments of the three systems. NRC encourages licensees to perform
self-assessments as a means of identifying and correcting their own issues.
b. Description
The licensee conducted the self-assessments under the guidance of the FENOC
Focused Self-Assessment Guideline, Revision 0, issued December 2001. Each
system was reviewed by a separate team led by a member of the licensees staff,
and composed of licensee and consultant engineers. As is typical of these types of
self-assessments, the licensee used NRC Inspection Procedure 71111.21, Safety
System Design and Performance Capability, to conduct the system reviews.
c. Findings and Observations
No findings were identified. The inspectors reviewed the Focused Self-Assessment
Guideline, the staffing of the three review teams, and the completed reports for all three
systems. The reports were thorough and identified some significant issues with each of
the three systems.
14
4OA6 Management Meetings
Exit Meeting Summary
The inspectors presented the inspection results to Mr. L. Myers and other members of
licensee management and staff at the conclusion of the inspection on November 13,
2002. The licensee acknowledged the information presented.
15
KEY POINTS OF CONTACT
DAVIS-BESSE
D. Baker, Life Cycle Management (A) Manager
R. Cooper, Consultant
R. Fast, Plant Manager
J. Grabnar, Design Basis Engineering Manager
E. Grindahl, Quality Assurance
D. Gudger, Learning Organization Manager
D. Haskins, Human Resources Manager
S. Loehlein, Quality Assurance Manager
E. Matranga, Plant Engineering
P. McCloskey, Regulatory Affairs Manager
D. Miller, Compliance Supervisor
G. Mountain, Licensing Engineer
L. Myers, Chief Operating Officer
L. Pearce, Vice President, Oversight
J. Powers, Engineering Director
P. Roberts, Maintenance Manager
M. Roder, Operations Manager
J. Rogers, Plant Engineering Manager
C. Price, Business Manager
R. Schrauder, Services Director
B. Saunders, President, FENOC
L. Thornsberry, Plant Engineering
S. Wise, Operations Superintendent
NUCLEAR REGULATORY COMMISSION
J. Grobe, Chairman, Davis-Besse Oversight Panel
C. Lipa, Chief, Reactor Projects Branch 4
S. Thomas, Senior Resident Inspector
16
LIST OF ACRONYMS USED
AIT Augmented Inspection Team
CR Condition Report
CRDM Control Rod Drive Mechanism
DBDVP Design Basis Document Validation Program
EAB Engineering Assessment Board
HPI High Pressure Injection
LIR Latent Issues Review
NQA Nuclear Quality Assessment
NRC Nuclear Regulatory Commission
ORR Operational Readiness Review
PCAQR Potential Conditions Adverse to Quality Report
PDR Public Document Room
QA Quality Assurance
SHA System Health Assurance
SHRR System Health Readiness Review
URI Unresolved Item
17
LIST OF DOCUMENTS REVIEWED
The following is a list of licensee documents reviewed during the inspection, including
documents prepared by others for the licensee. Inclusion on this list does not imply that NRC
inspectors reviewed the documents in their entirety, but that selected sections or portions of the
documents were evaluated as part of the overall inspection effort. Inclusion on this list does not
imply NRC acceptance of the document, unless specifically stated in the inspection report.
Procedures
EN-DP-01503 System Walkdown, Revision 02, August 10, 2002
EN-DP-01504 System Health Readiness Review, Revision 00, August 21, 2002
EN-DP-01504 System Health Readiness Review, Revision 02, October 16, 2002
EN-DP-01505 Latent Issues Reviews, Revision 00, September 3, 2002
EN-DP-01505 Latent Issues Reviews, Revision 03, October 8, 2002
EN-DP-01506 Borated Water System Inspections (Outside Containment), September 3,
2002
DBE-0001 Engineering Assessment Board Role/Policy in Support of the Return to
Service Plan, Revision 0, June 28, 2002
NG-EN-00324 Boric Acid Corrosion Control, July 20, 2002
NG-VP-00100 Restart Action Plan Process, Revision 01, August 23, 2002
NG-VP-00100 Restart Action Plan Process, Revision 02, August 23, 2002
NOP-ER-2001 Boric Acid Corrosion Control Program, July 20, 2002
NOP-LP-2001 Condition Report Process, Revision 1,
System Health Readiness Review Scoping Memos
Steam Feed Rupture Control System Scope Memo, September 19, 2002
125/250 VDC System Scope Memo, August 26, 2002
High Pressure Injection System Scope Memo, September 16, 2002
Anticipatory Reactor Trip System Scope Memo, September 11, 2002
EDG Ventilation System Scope Memo, September 20, 2002
Condition Reports Generated from Inspection
02-05578 LIR Training Effectiveness
02-06565 SHRR LIR Review of Change Initiating Documents
02-06261 SHRR Boron Identified on CS17 Packing Area
02-06621 SHRR LIR Reviews Initiated before Scoping Approved
02-06723 SHRR LIR NRC Concern regarding Sites Lubrication
02-06765 Sway Strut Bushing Grease Fittings, September 26, 2002
02-07011 SHRR LIR NRC Concerns about System Review Scoping
02-07869 NRC Inspectors Concern Regarding Supervisor Comment for CR, October 11,
2002
02-08432 Containment Design Basis Calculation, October 21, 2002
02-08742 Inadequate Followup to Self Assessment 1999-0076, October 28, 2002
02-09036 Greasing of Struts, November 5, 2002
18
Condition Reports (CR)
02-02397 IPR: Breaker Reliability Program, May 31, 2002
02-03157 HELB in Turbine Building Effects on AFP Rooms, July 11, 2002
02-03369 Quality Expectations, July 17, 2002
02-03828 SHRR: ARTS Walkdown Findings from 8-7-02 for PSL4535A, B, C, D, August 7,
2002
02-03895 LIR-EDG-Two Instrument Tubing Lines Damaged, August 7, 2002
02-03923 SHRR Walkdown DH Train 1 DW143 Demin Water Valve Leakby, August 9,
2002
02-03925 SHRR Walkdown Decay Heat Train 1 Cooler Room - Scaffold Pole, August 9,
2002 02-02941 Operational Readiness Review Action Items, July 2, 2002
02-04021 SHRR Walkdown Finding During Containment System Walkdown, August 11,
2002
02-04041 SHRR Walkdown Items - RPS CTMT Press SW Sensing Line Guard, August 8,
2002
02-04033 Failure to Process Condition Reports through SRO Review in a Timely Manner,
August 12, 2002
02-04047 SHRR Walkdown Items - Outboard Electrical Penetration Cabinet Generic
Issues, August 9, 2002
02-04085 LIR-EDG - EDG 1 Air Intake Filter Can Use Paint to Overcoat Rusting,
August 11, 2002
02-04198 LIR-EDG 1 - Elec Maintenance Tag on Hand Switch (C3617), August 12, 2002
02-04473 SHRR - I&C Comment Regarding Test Points during Walkdown, August 13,
2002
02-04501 LIR - EDG 2 Cable Pull Wire Left in Place, August 17, 2002
02-04521 LIR - EDG 2 Panel C3616 Test Switch TS-3 Plastic Cover Broken, August 17,
2002
02-04543 SHRR: Battery Room 2 Deficiencies, August 20, 2002
02-04546 SHRR: Interlock for DC Panel Supply Breakers, August 20, 2002
02-04572 LIR-EDG-DO119 Piping Needs to be Cleaned and Painted, August 16, 2002
02-04578 LIR-EDG-EDG1-2 Day Tank Room Needs General Clean & Painting All Equip &
Floor, August 16, 2002
02-04581 LIR-EDG-HISNP 1951A Switch Label is Missing, Label Start/Stop, August 16,
2002
02-04635 LIR-Emergency Diesel Generator 1-2, August 17, 2002
02-04782 Potential Omission of LCO for Delay Time of Fuel Movement to Spent Fuel Pool,
August 22, 2002
02-04812 LIR CCW - Lack of Identification Tags on Instrumentation Valves, August 22,
2002
02-05066 LIR-AFW-ST138, August 23, 2002
02-05092 LIR-AFW-Service Water valve SW6392, August 23, 2002
02-05101 ORR - System Condition Report for Steam Feed Rupture Control System,
August 27, 2002
02-05103 ORR - System Condition Report for Condensate System, August 26, 2002
02-05125 ORR - System Condition Report for Non-nuclear Instrumentation, August 19,
2002
19
02-05132 ORR - System Condition Report for Integrated Control System, August 19, 2002
02-05135 ORR - System Condition Report for RPS, DSS, and NI, August 19, 2002
02-05137 ORR - System Condition Report for Decay Heat Removal/LPI System,
August 28, 2002
02-05138 ORR - System Condition Report for Radiation Monitoring System, August 27,
2002
02-05140 ORR - System Condition Report for Switchyard and Transformers, August 24,
2002
02-05141 ORR - System Condition Report for Main Feedwater Pumps/Turbines/Piping
System, August 26, 2002
02-05143 ORR - System Condition Report for 125/250 VDC System, August 17, 2002
02-05144 ORR - System Condition Report for Main Steam System, August 26, 2002
02-05146 ORR - System Condition Report for Anticipatory Reactor Trip System,
August 15, 2002
02-05147 LIR Design Basis Recovery, August 28, 2002
02-05149 ORR - System Condition Report for Motor Driven Feedwater Pumps, August 26,
2002
02-05150 ORR - System Condition Report for Emergency Diesel Generator, August 21,
2002
02-05157 BWST Level Shift Log Acceptance Criteria May Not Meet TS 3.5.4.A
Requirements, August 28, 2002
02-05191 SHRR: 480VAC MCC & MCCB Maintenance Issues, August 28, 2002
02-05408 SHRR: Testing Review - Trip Alarm Excluded from RPS Procedures,
September 4, 2002
02-05409 SHRR: Testing Review-Not Verifying Ch Trip Light on Reactor Trip Module,
September 4, 2002
02-06040 Issues Identified during SHRR Final Report Presentation, September 14, 2002
02-06259 SHRR LIR System Health Assurance Reviews, September 19, 2002
02-06313 LIR - EDG Exciter/Voltage Regulator PM May Not be Adequate, September 20,
2002
02-06398 Some Safety-Related Breakers Lacking Pms, September 20, 2002
02-06436 SSDPC Collective Significance of Issues from SW Self Assessment and LIR,
September 21, 2002
02-06582 LIR-RCS: 273R11 Does Not Reflect the As-Built Plant Configuration,
September 24, 2002
02-06770 LIR-AFW-CR 95-0703 Action to Prevent Recurrence Missing, September 26,
2002
02-06819 Inaccurate Input Provided by Contractor for NRC Correspondence,
September 26, 2002
Correspondence
Log 4928 Ltr: James M. Taylor to R. J. Farling, Request for Information Pursuant to 10
CFR 50.54(f) Regarding Adequacy and Availability of Design Bases Information,
October 9, 1996
Log 4954 Memo: Ledyard B. Marsh, Meeting with NEI and Licensees to Discuss Generic
Letter (GL) 96-06, Assurance of Equipment Operability and Containment
Integrity during Design-Basis Accident Conditions, November 22, 1996
20
Serial 2438 Ltr: Centerior Energy to USNRC, Response to NRC Request for Information
Regarding Adequacy and Availability of Design Bases Information Regarding
Adequacy and Availability of Design Bases Information, February 11, 1997
Log 5004 Ltr: Allen G. Hansen to John K. Wood, Response to October 9, 1996 Request for
Information Pursuant to 10 CFR 50.54(f) Regarding Adequacy and Availability of
Design Bases Information, Davis-Besse Nuclear Power Station, Unit No. 1
(TAC No. 97583), February 25, 1997
Log 5024 Ltr: Allen G. Hansen to John K. Wood, Planned Design Inspection, Davis-Besse
Nuclear Power Station, Unit No. 1, March 27, 1997
Serial 2455 Ltr: Centerior Energy to USNRC, Plan And Schedule for Completion of the
DBNPS Design Basis Validation Program, March 31, 1997
Log 5173 Ltr: Allen G. Hansen to John K. Wood, Davis-Besse Nuclear Power Station,
Unit 1 - Design Inspection - NRC Inspection Report No. 50-346/97-201
(TAC No. M99129), November 19, 1997
Serial 2623 Ltr: Guy G. Campbell to USNRC, Status of the Design Basis Validation Program
and the Planned Program to Convert to the Improved Standard Technical
Specifications, December 17, 1999
Other Documents
Davis-Besse Return to Service Plan, Revision 2, August 6, 2002
Nuclear Quality Assessment Oversight of Davis-Besse Return to Service,
Revision 1, July 22, 2002
RSMT Davis-Besse Restart Senior Management Team Charter, Revision 00,
June 24, 2002
Davis-Besse Restart Overview Panel Charter, Revision 0, June 7, 20002
RSRB Davis-Besse Restart Station Review Board Charter, Revision 00, June 24,
2002
Davis-Besse System Health Assurance Plan, Revision 2, August 5, 2002
Davis-Besse System Health Assurance Plan, Revision 3, September 9, 2002
System Health Assurance Discovery Action Plan, Revision 0, August 5, 2002
System Health Assurance Discovery Action Plan, Revision 2, October 15,
2002
FENOC Engineering Principles and Expectation, July 10, 2002
NED 87-10338 Memo, Sway Strut Bushing Grease Fittings, July 29, 1987
Manual Valve Component Reliability Template Basis Document
ENDP-01506 Leakage Reduction Program Manual, Revision 00, July 18, 2001
Design Basis Document Validation Program, Revision 1, August 21, 1997
SD-018 System Description for Service Water System, Revision 2, August 4, 1995
Design Basis Document Validation Report of the Service Water (SW) for
Davis-Besse Power Plant by Sargent & Lundy, LLC, December 23, 2000
Training Lesson Plan - Borated Water System Inspections (Outside
Containment), September 5, 2002
TM-108 Job Familiarization Guidelines - Mechanical Boric Acid Corrosion Control
Inspector (Applicable to EN-DP-01501 Only), July 22, 2002
Focused Self-Assessment Guideline, Revision 0, December 2001
SA 2002-0093 Davis-Besse NPS Self-Assessment Service Water System Report,
October 22, 2002
21
SA 2002-0094 Davis-Besse NPS Self-Assessment High Pressure Injection System Report,
October 22, 2002
SA 2002-0095 Davis-Besse NPS Self-Assessment 4160 VAC System Report, October 22,
2002
Quality Assurance Review of System Health Readiness Review for Decay
Heat Removal/Low Pressure Injection System, September 27, 2002
Quality Assurance Review of System Health Readiness Review for
125/250 VDC System, Revision 0, October 5, 2002
Quality Assurance Review of System Health Readiness Review for Station
and Instrument Air System, Revision 0, November 6, 2002
Davis-Besse Operation Readiness Report, Revision 0, October 29, 2002
NPE-99-0076 Plant Equipment Reliability Self-Assessment, October 22, 1999
22
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No: 50-346
License No: NPF-3
Report No: 50-346/02-14(DRS)
Licensee: FirstEnergy Nuclear Operating Company
Facility: Davis-Besse Nuclear Power Station
Location: 5501 North State Route 2
Oak Harbor, OH 43449
Dates: September 23 through November 13, 2002
Inspectors: B. Bartlett, Lead Inspector
J. Ellegood, Resident Inspector
R. Daley, Reactor Inspector
R. Deese, Resident Inspector
D. Prevatte, Mechanical Consultant
M. Shlyamberg, Mechanical Consultant
Approved by: Ronald N. Gardner, Chief
Electrical Engineering Branch
Division of Reactor Safety
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Background and Event Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R21 Safety System Design and Performance Capability (71111.21) . . . . . . . . . . . . . . . . . . 6
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
System Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Inspection Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Observations and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Lack of a Design Basis Analysis for Containment Isolation Valve Backup Air
Supply Accumulators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Inadequate Blowdown Provisions for CAC Backup Air Accumulators . . . . . . . . 9
System Condition and Capability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Inspection Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Observations and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Failure to Perform Comprehensive Moderate Energy Line Break (MELB)
Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Cracks in Other Moderate Energy Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Lifting of Service Water Relief Valves SW 3962 and SW 3963 . . . . . . . . . . . . 11
Inadequate Service Water Pump Room Temperature Analyses . . . . . . . . . . . 12
Service water Pump Room Steam Line Break . . . . . . . . . . . . . . . . . . . . . . . . . 13
Cable Ampacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Identification and Resolution of Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Inspection Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Observations and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Containment Air Coolers Nozzle Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
SW Pump Curve Allowable Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Technical Specification Surveillance Requirement for High Pressure Injection
(HPI) Following Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
SW Relief Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Non-Conservative Difference in Ultimate Heat Sink Temperature Measurements
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
System Walkdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Inspection Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Observations and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Inadequate Flooding Protection for The Service Water System . . . . . . . . . . . . 18
Design Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
1
Inspection Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Observations and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Non-Conservative TS Value for the 90 Percent Degraded Voltage Relay . . . . 21
Poor Quality Calculation for 90 Percent Degraded Voltage Relay . . . . . . . . . . 22
Non-Conservative Relay Setpoint Calculation for the 59 Percent Undervoltage
Relay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Inadequate Calculations for Control Room Operator Dose (GDC-19) and Off-Site
Dose (10 CFR Part 100) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
HPI Pump Operation Under Long Term Minimum Flow . . . . . . . . . . . . . . . . . . 28
HPI Pumps Minimum Flow, Unanalyzed SBLOCA Sizes . . . . . . . . . . . . . . . . . 28
Inadequate Service Water System Flow Analyses . . . . . . . . . . . . . . . . . . . . . . 29
Definition of Passive Failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Inadequate Service Water System Thermal Analyses . . . . . . . . . . . . . . . . . . . 30
Inadequate Ultimate Heat Sink Inventory Analyses . . . . . . . . . . . . . . . . . . . . . 32
No Valid Service Water Pump Net Positive Suction Head Analysis . . . . . . . . . 33
Inadequate Service Water System (and Other Systems) Overpressure Protection
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Service Water Source Temperature for Auxiliary Feedwater System . . . . . . . . 36
Short Circuit Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Inadequate Analytical Basis for the Setpoint to Swap Service Water System
Discharge Path . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Safety System Inspection and Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Inspection Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Observations and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
HPI Quarterly Surveillance Test Instrumentation Issues . . . . . . . . . . . . . . . . . 38
SW Surveillance Test Does Not Use Worst Case Values . . . . . . . . . . . . . . . . 39
ECCS Sump Pump Test Acceptance Criteria . . . . . . . . . . . . . . . . . . . . . . . . . 39
Inadequate Service Water System Flow Balance Testing . . . . . . . . . . . . . . . . 40
Inadequate Corrective Actions for Service Water Pump Discharge Check Valves
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4OA6 Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
2
SUMMARY OF FINDINGS
IR 05000346-02-14; FirstEnergy Nuclear Operating Company; on 09/23-11/13/2002;
Davis-Besse Nuclear Power Station. Safety System Design and Performance Capability.
This was a special inspection of the design and performance capability of the service water
system, high pressure injection system, and the safety-related portions of the 4,160 volt
AC system. It was conducted by regional engineering specialists, resident inspectors and two
consultants. The inspection identified four NCVs, three of which had multiple examples, and
two unresolved items. The significance of most findings is indicated by their color (Green,
White, Yellow, Red) using IMC 0609 Significance Determination Process (SDP). Findings for
which the SDP does not apply are indicated by No Color or be assigned a severity level after
USNRC management review. The USNRCs program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 3, dated July 2000.
A. Inspector Identified Findings
Cornerstone: Mitigating Systems
- Green. The inspectors identified a Non-Cited Violation (NCV) of Technical
Specification surveillance requirement 4.2.5.H, associated with failure to re-verify
High Pressure Injection pump flow following modifications that could alter system
flow characteristics.
This finding was determined to be more than minor because it affected the
mitigation systems cornerstone objective. This finding screened as Green in
the SDP phase 1, since this issue was not an actual loss of a safety function.
Because the finding was of very low safety significance, and was captured in
the licensees corrective action system this finding is being treated as an NCV
consistent with Section VI.A.1 of the NRC Enforcement Policy (Section 1R21.3).
- Green. The inspectors identified an example of a Non-Cited Violation of 10 CFR
Part 50, Appendix B, Criterion III, associated with a non-conservative TS value
for the 90 percent degraded voltage relay.
This finding screened as Green in the SDP phase 1, since this issue was a
design deficiency that was confirmed not to result in loss of function in
accordance with Generic Letter 91-18 (Revision 1). Because the finding was of
very low safety significance, and was captured in the licensees corrective action
system this finding is being treated as an NCV consistent with Section VI.A.1 of
the NRC Enforcement Policy (Section 1R21.5).
Green. The inspectors identified an example of a Non-Cited Violation of 10 CFR
Part 50, Appendix B, Criterion III, associated with non-conservative relay setpoint
calculation for the 59 percent undervoltage relay.
3
This finding screened as Green in the SDP phase 1, since this issue does not
contribute to the likelihood of a Primary or Secondary system Loss of Coolant
Accident (LOCA) initiator, does not contribute to both the likelihood of a reactor
trip and the likelihood that mitigation equipment or functions will not be available,
and does not increase the likelihood of a fire or internal/external flood. Because
the finding was of very low safety significance, and was captured in the
licensees corrective action system, this finding is being treated as an NCV
consistent with Section VI.A.1 of the NRC Enforcement Policy (Section 1R21.5).
Green. The inspectors identified an example of a Non-Cited Violation of 10 CFR
Part 50, Appendix B, Criterion III, associated with an inadequate analytical basis
for the setpoint to swap service water system discharge path.
The inspectors considered this finding was more than minor because it could
affect the mitigating systems cornerstone objective of ensuring the capability of
systems that respond to initiating events to prevent undesirable consequences
attributable to design control. Using the significance determination process, the
safety significance was determined to be very low (Green) because the finding
did not screen as potentially risk significant due to a seismic, fire, flooding, or
severe weather event. Because the finding was of very low safety significance,
and was captured in the licensees corrective action system, this finding is being
treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy
(Section 1R21.5).
- Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50,
Appendix B, Criterion XI, associated with a service water surveillance test that
did not use worst case values.
This finding screened as Green in the SDP phase 1, since this issue was a
testing deficiency that was confirmed not to result in loss of function in
accordance with GL 91-18 (Revision 1). Because the finding was of very low
safety significance, and was captured in the licensees corrective action system
this finding is being treated as an NCV consistent with Section VI.A.1 of the NRC
Enforcement Policy (Section 1R21.6).
- Green. The inspectors identified a Non-Cited Violation of 10 CFR 50,
Appendix B, Criterion XVI, associated with inadequate corrective actions for
service water pump discharge check valves test acceptance criteria.
This finding screened as Green in the SDP phase 1, since the finding did not
screen as risk significant due to a seismic, fire, flooding, or severe weather
event. Because the finding was of very low safety significance, and was
captured in the licensees corrective action system this finding is being treated
as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy
(Section 1R21.6).
4
Cornerstone: Barrier Integrity
- Green. The inspectors identified an example of a Non-Cited Violation of 10 CFR
Part 50, Appendix B, Criterion III, associated with the lack of a design basis
analysis for containment isolation valve backup air supply accumulators.
This finding screened as Green in the SDP phase 1, since this issue did not
represent an actual open pathway in the physical integrity of reactor
containment. Because the finding was of very low safety significance, and was
captured in the licensees corrective action system this finding is being treated as
an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy
(Section 1R21.1).
- Green. The inspectors identified an example of a Non-Cited Violation of 10 CFR
Part 50, Appendix B, Criterion III, associated with inadequate blowdown
provisions for Containment Air Cooler (CAC) backup air accumulators.
This finding screened as Green in the SDP phase 1, since this issue did not
represent an actual open pathway affecting the physical integrity of reactor
containment. Because the finding was of very low safety significance, and was
captured in the licensees corrective action system, this finding is being treated
as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy
(Section 1R21.1).
5
REPORT DETAILS
Background and Event Overview
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 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 the Davis-Besse Nuclear Power Station (reference
NRC report 50-346/02-03(DRS)).
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 Plan (DBSHAP). 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. To assess the quality of the licensees reviews, the NRC conducted an in-depth
design and performance capability inspection of three of the systems reviewed by the licensee.
Given the high public interest in this subject area at Davis-Besse, and therefore the need to
clearly communicate the rationale for NRC staff conclusions regarding the effectiveness of
licensee extent of condition inspections, this report documents the inspectors observations.
1. REACTOR SAFETY
Cornerstones: Mitigating Systems and Barrier Integrity
1R21 Safety System Design and Performance Capability (71111.21)
Introduction
Inspection of safety system design and performance verifies the initial design of the
Davis-Besse plant as well as subsequent modifications of the plant, and provides
monitoring of the capability of the selected systems to perform design bases functions.
As plants age, the design bases may be lost and important design features may be
altered or disabled. The plant risk assessment model is based on the capability of the
as-built safety system to perform the intended safety functions successfully. This
inspectable area will verify aspects of the mitigating systems and barrier integrity
cornerstones for which there are no indicators to measure performance.
The objective of the safety system design and performance capability inspection was to
assess the adequacy of calculations, analyses, other engineering documents, and
operational and testing practices that were used to support the performance of the
service water, high pressure injection, and the safety-related portions of the 4,160 volt
6
AC systems during normal, abnormal, and accident conditions. The inspection was
performed by a team of inspectors that consisted of a team leader, two Region III
inspectors, one Region IV inspector, and two consultants.
The service water, high pressure injection, and 4,160 volt AC systems were selected for
review during this inspection. This selection was based upon:
- having a high probabilistic risk analysis ranking;
- selecting one system from the licensees list of 5 systems receiving a Latent
Issues Review;
- selecting two systems from the licensees list of 31 systems receiving System
Health Readiness Reviews and;
- not having received recent NRC review.
The criteria used to determine the systems performance included:
- applicable Technical Specifications;
- applicable Updated Final Safety Analysis Report sections; and
- the systems design documents.
.1 System Requirements
a. Inspection Scope
The team reviewed the following attributes for the service water (SW) system, high
pressure injection (HPI) system, and the safety-related portions of the 4,160 Vac
system: (1) process medium (water, steam, and air); (2) energy sources; (3) control
systems; and (4) equipment protection. The team verified that procedural instructions to
operators were consistent with the operator actions required to meet, prevent, and/or
mitigate design basis accidents. The teams review considered requirements and
commitments identified in the Updated Final Safety Analysis Report (UFSAR), Technical
Specifications (TS), design basis documents, and plant drawings. This review further
verified that the required support functions for the selected systems would be available.
The team verified that the system needs for the selected systems were met. The supply
of air, water, steam, and electrical power required by the TS were verified through a
review of the design of the selected systems, and those systems providing support
functions.
The team verified equipment for the selected systems required to operate and/or change
state during accidents and events would have control power available. The team further
reviewed the adequacy of alarm setpoints and verified that necessary instrumentation
and alarms were available to operators for making necessary decisions in coping with
postulated accident conditions. In addition, the team verified that the systems standby
alignments were consistent with assumptions in the operating procedures as well as
design and licensing basis assumptions.
7
b. Observations and Findings
Lack of a Design Basis Analysis for Containment Isolation Valve Backup Air Supply
The inspectors identified a Green finding that is an example of a Non-Cited Violation of
10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with a failure to
assure that applicable regulatory requirements and the design basis for structures,
systems, and components were correctly translated into specifications, drawings,
procedures, and instructions. Service water (SW) system valves SW-1356, SW-1357,
and SW-1358 are the containment air cooler (CAC) outlet containment isolation valves.
They are air-operated valves that fail open on a loss of instrument air. Since the plants
instrument air system was nonsafety-related, the containment isolation valves were
provided with a safety-related backup air system with accumulators to assure that they
could be isolated and held closed for containment isolation under accident conditions.
However, no viable design basis description or analyses could be found for the backup
air system or for the size of the accumulators. Additionally, no acceptance criteria,
basis, or analysis could be found to support the surveillance test which leak-tested this
system. Therefore, the ability of the safety-related backup air supplies to perform their
safety-related functions of enabling the closure of these valves upon demand for
containment isolation could not be verified.
The procedures acceptance criterion was that the accumulators are capable of stroking
the valves and holding them shut for 30 minutes. Discussions with licensee engineers
determined that the 30-minute criterion was based on the expectation that instrument air
would be restored in this time and that the operators could manually shut the valves if
necessary. However, for design basis analysis credit should not be given for restoration
of the non-safety instrument air system. In addition, the ability of the plant operators to
manually close the air-operated containment isolation valves in an area that could have
very high post-accident radiation levels had not been demonstrated.
The licensee informed the inspectors that the lack of a design basis had been identified
prior the inspectors arrival on site. However, condition report (CR) 02-06546 only
identified that the basis for the 30-minute test acceptance time could not be located, and
this was deemed as only an administrative inadequacy.
The licensee missed at least two opportunities to have identified and corrected these
concerns. The first was when Generic Letter (GL) 88-14, Instrument Air Supply
Problems Affecting Safety-Related Equipment, dated August 8, 1988, was issued to
all licensees. The licensees docketed response letter stated, in part, Additionally,
safety-related accumulators were verified to be sized correctly and to perform as
required during a loss of instrument air and other design-basis events.
The second missed opportunity was when these service water valves and operators were
replaced with components of completely different design (Modification 99-0039-00, CAC
Temperature Control Valve Replacement, dated June 29, 1999). The modification effort
should have prompted a review of the backup air system design bases and capabilities to
verify that they were adequate for the new equipment.
8
10 CFR Part 50, Appendix B, Criterion III, Design Control, requires that Measures shall
be established to assure that applicable regulatory requirements and the design
basis...are correctly translated into specifications, drawings, procedures, and
instructions. Contrary to this requirement, the licensee failed to correctly translate the
design basis requirements for sizing of the safety-related backup air supplies for service
water containment isolation valves SW-1356, SW-1357, and SW-1358 into the design.
This finding was determined to be more than minor because it affected the barrier
integrity cornerstone objective. This finding screened as Green in the Significance
Determination Process (SDP) phase 1 because the issue did not represent an actual
open pathway in the physical integrity of reactor containment. Because the finding was
of very low safety significance, and was captured in the licensees corrective action
system as CR 02-07750, this finding is being treated as an example of a Non-Cited
Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, consistent with
Section VI.A.1 of the NRC Enforcement Policy (NCV 50-346/2002-014-01a).
Inadequate Blowdown Provisions for Containment Air Cooler Backup Air Accumulators
The inspectors identified a Green finding that is being treated as an additional example of
a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control,
associated with a failure to assure that applicable regulatory requirements and the design
basis for structures, systems, and components were correctly translated into
specifications, drawings, procedures, and instructions. The inspectors determined that
the CAC containment isolation valve backup air accumulators were not equipped with
blowdown valves or other provisions to allow removal of condensation as described in
Updated Safety Analysis Report (USAR) Section 9.3.1.5, which stated, Regular
maintenance of the equipment is performed to ensure cleanliness. This includes regular
blowing down of receivers....
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.
10 CFR Part 50, Appendix B, Criterion III, Design Control, requires that Measures shall
be established to assure that applicable regulatory requirements and the design
basis...are correctly translated into specifications, drawings, procedures, and
instructions. Contrary to this requirement, the licensee failed to include blowdown
valves or other provisions to allow removal of condensation as described in Updated
Safety Analysis Report (USAR) Section 9.3.1.5.
This finding was determined to be more than minor because it affected the barrier
integrity cornerstone objective. This finding screened as Green in the SDP phase 1
since this issue did not represent an actual open pathway in the physical integrity of
reactor containment. Because the finding was of very low safety significance, and was
captured in the licensees corrective action system as CR 02-07750, this finding is being
treated as an additional example of a Non-Cited Violation of 10 CFR Part 50, Appendix
B, Criterion III, Design Control, consistent with Section VI.A.1 of the NRC Enforcement
Policy (NCV 50-346/2002-014-01b).
9
.2 System Condition and Capability
a. Inspection Scope
The team reviewed the periodic testing procedures for the selected systems to verify that
the design requirements were adequately demonstrated. The team reviewed the
environmental qualification of a sample of system components to verify the capability to
operate under design environmental conditions and the assumed operating parameters
including: voltage, speed, power, flow, temperature, and pressure. The team also
reviewed recent instrument setpoint changes to verify that the design basis or capability
for the selected systems had not been affected by the setpoint change process.
The team reviewed the systems operations by conducting system walkdowns; reviewing
normal, abnormal, and emergency operating procedures; and reviewing the Updated
Final Safety Analysis Report, technical specifications, design calculations, drawings, and
procedures. In addition, the team reviewed the list of active and closed standing orders
and operator work-arounds to ensure no design assumptions were invalidated by past or
current operator daily practices.
b. Observations and Findings
Failure to Perform Comprehensive Moderate Energy Line Break (MELB) Analysis
Pump Seal Leakage
The inspectors identified an unresolved item associated with a failure to evaluate the
environmental effects of a postulated Decay Heat Removal (DHR) pump seal failure.
Following a review of the USAR description of a postulated DHR pump seal failure
following a postulated Loss of Coolant Accident (LOCA) (Section 3.6.2.7.1.11), and
discussions with the licensee, the inspectors determined that only the effects of flooding
had been evaluated. The environmental effects of the assumed 120 gallons per minute
(gpm) seal failure on the equipment in the area, such as pressurization, increase of
humidity and temperature, jet impingement, etc, had not been evaluated.
Due to the interconnection of rooms in the Auxiliary Building, the environmental effects
could impact the other emergency core cooling system (ECCS) pump room and the
remaining ECCS train. The licensee issued CR 02-07757 to document the inspectors
finding.
The inspectors were unable to fully evaluate the effects of the assumed seal failure on
licensee equipment in order to assess whether the finding represented a design or
qualification deficiency that would result in a loss of function. At the close of the
inspection, the licensee was re-evaluating the effects of a postulated DHR pump seal
failure on the operation of plant equipment. This issue will remain as unresolved pending
the licensees evaluation and the NRCs review (URI 50-346/2002-014-01c).
10
Cracks in Other Moderate Energy Lines
The teams review of USAR Section 3.6.2.7, Protection Against Environmental Effects
Outside the Containment Vessel, and discussions with the licensee identified that critical
cracks at selected locations during normal plant shutdown cooling mode for the low
pressure injection/decay heat removal (DHR) system had not been evaluated. The
effects of those cracks on safety related Structures, Systems, or Components (SSCs)
(e.g., pressurization, increase of humidity and temperature, jet impingement) had not
been evaluated. Due to the interconnection of rooms in the Auxiliary Building, this
environment could potentially reach the other ECCS Pump Room and affect the
remaining DHR train. The licensee issued CR 02-07777 to document this teams finding.
Lifting of Service Water Relief Valves SW-3962 and SW-3963
The inspectors identified an unresolved item in that the service water supply header relief
valves, SW-3962 and SW-3963, had a history of lifting and not reseating after expected
plant transients. The resultant diversion of flow away from the systems safety-related
heat exchangers could have, under some conditions, prevented one or both trains of the
SW system from performing its safety function.
The service water system was protected against overpressure from the pumps by 6"x 8"
relief valves, SW-3962 and SW-3963, on each of the respective supply headers. Since
initial plant startup in 1977, a chronic problem existed with these valves lifting during
normal system transients that produced pressure pulses in the supply headers. These
included pump swaps, system lineup changes, load changes, and high system pressures
during winter months when system flows were restricted. Additionally, due to the
steady-state operating header pressure often being close to the valves reseat pressure,
they have frequently experienced chatter, resultant damage, and failure to fully reseat. In
this condition, the valves could divert substantial flow from the systems heat exchangers
that is not accounted for in the system analyses or flow balance tests. Therefore, for this
condition, the ability of the system to provide the required design basis flows to the
safety-related heat exchangers in both divisions could not be verified. This design also
did not meet the requirements of American Society of Mechanical Engineering (ASME)
Code,Section III, 1971, Article NB-7400, Paragraph NB-7614.1, Anti-Chattering and Life
Requirements, which stated, Safety valves shall be designed and constructed to
operate without chattering...
This has been a significant concern for the licensee as evidenced in CRs 00-2478 and
01-0350. One of the licensees responses has been to structure the system operating
procedure, DB-OP-06261, Service Water System Operating Procedure, with steps to
intentionally lower header pressure, such as by opening the strainer blowdown valves,
before performing any activities likely to cause the valves to lift. Although this allowed
the system to be operated with lowered potential for valve actuations, it did not
eliminate the problem, even for normal operations. More important, it did not address
the systems safety function and accident-induced pressure transients, such as the
automatic isolation of the non-safety portion of the system by the closing of either valve
SW-1395 or SW-1399, depending on which division was supporting the turbine building
loads at the time, which would produce a relatively large pressure transient. A single
failure on the opposite division would render the system unable to perform its safety
11
function. Other events alone, such as loss-of-offsite-power (LOOP) without an accident
could cause such a transient with pump restart after starting of the diesel generators.
Based on actual plant experience, these appeared to be high probability transient
responses.
Therefore, as a result of the systems supply header overpressure protection design,
there was a high potential that the SW system could not adequately perform its safety
function for design basis accidents and other design basis events. Although the licensee
formally identified this concern with respect to operations impact, the safety implications
were never formally recognized and documented.
The inspectors determined that the design of the SW system relief valves which could
result in a loss of flow to safety-related components was a performance deficiency
warranting a significance evaluation. At the close of the inspection, the licensee was
re-evaluating the effects of leaking SW relief valves on the operation of plant equipment.
The licensee entered the issue into its corrective action program as CR 02-07879. The
licensee screened the CR as requiring resolution prior to the mode in which SW was
required by plant TS (Mode 4). This item will remain unresolved pending the licensees
evaluation and the NRCs review (URI 50-346/2002-014-01d).
Inadequate Service Water Pump Room Temperature Analyses
The inspectors identified an unresolved item associated with assurance that applicable
regulatory requirements and the design basis for structures, systems, and components
were correctly translated into specifications, drawings, procedures, and instructions. The
inspectors questioned whether the licensee correctly translated the USAR commitments
regarding the service water pump room temperature limits into analyses that
demonstrated these limits would not be violated for design basis conditions.
USAR Section 9.4.5.1, Service Water Pump Room Ventilation System Design Bases,
stated, The system is designed to maintain the service water pump room and
diesel-driven fire pump room between 40EF and 104EF year-round for all modes of
operation including post-accident. Calculation 67.005, Service Water Pump Room
Ventilation System Capacity, analyzed the heat loads in the service water pump room
and the ability of the ventilation system to maintain the pump room temperatures within
this range. The inspectors determined that calculation 67.005 contained multiple
non-conservative attributes:
For summer, with an assumed 95EF outside design temperature:
- The calculation did not fully consider accidents without a LOOP, in which case, all
of the non-1E-powered loads in the rooms, such as the two cooling tower makeup
(CTMU) pumps, could remain energized, adding to the heat load.
- The calculation did not consider a seismic event that could start the diesel fire
pump as a result of fire system water losses, thereby adding this large heat load.
12
For winter, with an assumed -10EF outside design temperature:
- The calculation modeled the room temperature as uniform. However, for worst
case conditions, the only significant heat source could be one operating service
water motor at one end of the room, with vulnerable components at the opposite
end. There is approximately 44 feet of separation and an intervening wall with an
opening in the approximate center, and there would be no ventilation fans
operating.
- The calculation evaluated only heat transfer by conduction through the walls, roof,
and floor; it did not account for the fixed open ventilation roof inlets. Heated air
from the operating pump would rise and exit the room at the nearer opening and
be replaced by -10EF outside air entering the room at the farther opening.
At the close of the inspection, the licensee was re-evaluating the issue of correctly
translating the USAR commitments regarding the service water pump room
temperature limits into analyses that demonstrated these limits would not be violated
for design basis conditions. The licensee entered the issue into its corrective action
program as CR 02-07188. The licensee screened the CR as requiring resolution prior
to the mode in which SW was required by plant TS (Mode 4). This item will remain
as unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01e).
Service Water Pump Room Steam Line Break
The inspectors identified an unresolved item associated with assurance that applicable
regulatory requirements and the design basis for structures, systems, and components
were correctly translated into specifications, drawings, procedures, and instructions. The
inspectors questioned whether the licensee correctly translated the USAR commitments
regarding the service water pump room environmental limits into analyses that
demonstrated these limits would not be violated for design basis conditions.
The inspectors reviewed Calculation C-NSA-085.00-002, Auxiliary Steam Blowdown in
the Intake Structure, that addressed a postulated auxiliary steam line break in the
service water pump room. The inspectors determined that the calculation failed to
account for any steam condensation in safety-related electrical equipment in the room.
Such condensation could render this equipment or equipment powered by or through
these components inoperable. Such equipment could include the service water pump
motors, the safety-related motor control centers, and pull/junction boxes in the room.
USAR Section 3.11.1.2, Environmental Conditions, stated, Environmental conditions
have been developed for all safety-related areas of the plant...The environmental
conditions include temperature, pressure, relative humidity...
This concern was also identified by the licensee in the Latent Issues Review and
documented in CR 02-05966; however, this CR only addressed pull/junction boxes. In
order to resolve the issue, the licensee will need to assess the impact of steam
condensation on the operation of the SW system.
13
At the close of the inspection, the licensee was re-evaluating the impact of steam
condensation following a postulated heating steam line break. The licensee entered the
issue into its corrective action program as CR 02-07475. The licensee screened the CR
as requiring resolution prior to the mode in which SW was required by plant TS (Mode 4).
This item will remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01f).
Cable Ampacity
The inspectors identified an unresolved item associated with assurance that applicable
regulatory requirements and the design basis for structures, systems, and components
were correctly translated into specifications, drawings, procedures, and instructions. The
inspectors determined the licensee failed to correctly translate the USAR commitments
regarding the cable ampacity analysis for electrical cable passing through ECCS pump
room number 115.
ECCS pump room number 115 had an analysis for cable de-rating /ampacity for
temperatures up to 120EF, however; the peak calculated temperature in the room is now
124.2EF and the licensee has not performed a derate for the extra 4.2 degrees.
At the close of the inspection, the licensee was re-evaluating the impact of steam
condensation following a postulated heating steam line break. The licensee entered the
issue into its corrective action program as CR 02-06893. The licensee screened the CR
as requiring resolution prior to the mode in which this equipment was required by plant
TS (Mode 4). In order to resolve the item, the Licensee will need to assess the impact of
the revised temperature analysis on cable ampacity and its effect on safety-related
cables passing through room 115. This issue will remain unresolved pending the
licensees evaluation and the NRCs review (URI 50-346/2002-014-01g).
.3 Identification and Resolution of Issues
a. Inspection Scope
The team reviewed a sample of problems identified by the licensee in the corrective
action program to evaluate the effectiveness of corrective actions related to design
issues. The sample included open and closed condition reports going back three years
that identified issues related to or affecting the systems and safety-related setpoint
issues. The specific corrective action documents that were sampled and reviewed by
the team are listed in the attachment to this report. Inspection Procedure 71152,
Identification and Resolution of Problems, was used as guidance to perform this part of
the inspection.
The issues addressed by the condition reports reviewed included:
- The disposition of technical specification interpretations to address system and
component operability;
- The identification and correction of configuration control events and errors;
- The identification and correction of issues related to testing failures;
14
- The identification and corrective action associated with personnel errors, primarily
in the operations area;
- The identification and correction of safety-related setpoint issues; and
- The identification and correction of apparently degraded equipment.
b. Observations and Findings
Containment Air Coolers Nozzle Loading
On September 5, 2002, the licensee identified a non-conservatism in their analysis of
CAC mechanical stresses. This analysis evaluated the connection of the service water
system to the CACs. During a LOCA, the service water piping will expand as the water
temperature increases. The amount of stress applied to the CAC nozzle is partially
determined by the flexibility of the nozzle. In the analysis, the licensee overestimated
nozzle flexibility by a factor of one thousand. As a result, the calculated stresses on the
nozzle were significantly lower than would actually be experienced during a postulated
LOCA or other transient. By reducing nozzle flexibility to more realistic values, the
licensee determined that the coolers could exceed code allowable values under either a
LOCA or water hammer event. In the case of a LOCA, this would be a common mode
failure that could render all three trains of containment air coolers inoperable. The
licensee had at least one prior opportunity to identify this error. In 1997, the licensee
performed a water hammer analysis to respond to Generic Letter 96-06. This analysis
included use of the CAC stress calculations as a base model for the analysis. During
development of this analysis, the licensee failed to identify the erroneous nozzle flexibility
assumption.
As of the close of this inspection, the licensee had yet to complete the re-analysis
using the proper nozzle flexibility. The licensee entered the issue into its corrective
action program as CR 02-05563. The licensee screened the CR as requiring
resolution prior to the mode in which SW was required by plant TS (Mode 4). This
item will remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-03e).
SW Pump Curve Allowable Degradation
The inspectors identified an unresolved item associated prompt corrective action to
resolve an identified condition where the allowable degradation of the SW pumps did
not match the design basis required flow rate from the SW pumps.
In the Latent Issues Review (LIR), the licensee re-identified a condition where the total
head across the SW pumps could degrade by as much as 7 percent before corrective
action was required under ASME Section XI. The flow balance procedures (DB-SP-3000
and DB-SP-3001) did not adjust the available SW pump head for the maximum possible
SW pump degradation.
This issue was documented in CR 02-05369. The teams review of this CR identified
that this CR was approved, yet it did not identify a need to evaluate possible generic
implications. When questioned about the extent of condition and applicability to other
systems, e.g., component cooling system, the licensee agreed that the extent of
15
condition should have been considered and issued CR 02-06863 to document a lack of
the extent of condition evaluation. The CR was noted as ...needs to be considered for
restart.
At the close of the inspection, the licensee had yet to determine if the SW pumps were
performing at a level that would supply the needs of the SW system during all required
accident conditions. The licensee entered the issue into its corrective action program as
CR 02-07468. The licensee screened the CR as requiring resolution prior to the mode in
which SW was required by plant TS (Mode 4). This item will remain unresolved pending
the licensees evaluation and the NRCs review (URI 50-346/2002-014-03a).
Technical Specification Surveillance Requirement for High Pressure Injection (HPI)
Following Modifications
The inspectors identified one Green finding that is being treated as a Non-Cited Violation
of TS 4.5.2.H which requires re-verification of HPI pump flow following modifications that
could alter system flow characteristics.
The inspectors review of the HPI pump surveillances, design basis calculation, and the
TS requirements determined that TS 4.5.2 H had not been implemented. The TS
required verification that the HPI pump is capable of delivering a total of 750 gpm at
400 pounds per square inch gage (psig) at the Reactor Coolant System (RCS) nozzle
...following completions of modifications to the HPI ... subsystems that alter the
subsystem flow characteristics... Calculations and surveillance test procedures address
flow rates of about 400 gpm (HPI pump flow test region). Thus, there were no tests or
calculations to demonstrate that the HPI pumps complied with TS requirements. The
inspectors questioned the licensee about this discrepancy. The licensee stated that the
HPI self-assessment conducted in parallel with the teams inspection also identified this
issue and was documented in CR 02-06996. The basis for closure of this CR stated:
The bottom line of all this is that T.S. 4.5.2 H and the calculations
that support it are not well aligned. However, it appears that past
testing and acceptance criteria was sufficient to support that the
implied requirement is met. This issue should be cleaned up prior
to restart to absolutely assure alignment and that testing is in full
compliance with requirements.
This CR failed to address that the HPI system was modified such that system flow
characteristics were altered. CR 02-06996 was the second CR issued by the licensee
to address this failure to comply with the TS requirements. The first CR which identified
the failure to comply with the TS requirements was CR 02-03331; however; this CR
was being tracked as an administrative issue. When questioned by the team if the
required TS 4.5.2 H verification was performed, the licensee was not able to verify the
TS required verification was done. Based on this question, the licensee issued
CR 02-07468.
The inspectors determined that flow testing was performed following replacement of the
HPI impellers and that this flow testing confirmed that the new impellers performed
similarly to the old impellers.
16
This finding was determined to be more than minor because it affected the mitigation
systems cornerstone objective. This finding screened as Green in the SDP phase 1,
since this issue was not an actual loss of a safety function. Because the finding was of
very low safety significance, and was captured in the licensees corrective action system
as CR 02-07468, this finding is being treated as an NCV consistent with Section VI.A.1 of
the NRC Enforcement Policy (NCV 50-346/2002-014-04).
SW Relief Valves
The inspectors identified an unresolved item associated with safety-related service water
relief valves which failed and malfunctioned due to poor design, potentially preventing the
system from performing its safety function, and the licensee had not corrected this
condition.
At the close of the inspection, the licensee was re-evaluating the effects of leaking SW
relief valves on the operation of plant equipment. The licensee entered the issue into
its corrective action program as CR 02-07995 and screened the CR as requiring
resolution prior to the mode in which SW was required by plant TS (Mode 4). To
resolve this issue the Licensee will need to assess the ability of the licensees SW
system to withstand a loss of SW flow due to the partially open relief valves. This issue
will remain as unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-03b).
Non-Conservative Difference in Ultimate Heat Sink Temperature Measurements
The inspectors identified an unresolved item associated with plant staff awareness of the
non-conservative mismatch between the Ultimate Heat Sink (UHS) temperature, as
indicated by the difference between the TS temperature instrument readings, and the
2EF higher actual service water heat exchanger inlet temperatures, and the failure to
promptly correct this condition.
The licensee entered the issue into its corrective action program as CRs 02-05372,
02-06177, 02-06332, 02-06336, 02-06370, 02-07004, and 02-07716 and screened
the CRs as requiring resolution prior to the mode in which the SW system was
required by plant TS (Mode 4). In order to resolve this issue, the licensee and the
NRC will need to assess the service water system thermal requirements. This issue
will remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-03c).
.4 System Walkdowns
a. Inspection Scope
The team performed walkdowns of the accessible portions of the selected systems, as
well as the required support systems. The walkdowns focused on the installation and
configuration of power supplies, piping, components, and instruments. During the
walkdowns, the team assessed:
- The placement of protective barriers and systems;
17
- The susceptibility to flooding, fire, or environmental conditions;
- The physical separation of trains and the provisions for seismic concerns;
- Accessibility and lighting for any required local operator action; and
- The materiel condition and preservation of systems and equipment.
Finally, the team assessed the conformance of the currently installed system
configurations to the current design and licensing bases.
b. Observations and Findings
Inadequate Flooding Protection for The Service Water System
The inspectors identified an unresolved item associated with correctly translating the
USAR commitments regarding flood protection for the service water pump room.
USAR Section 2.4.8.2 stated, The Probable Maximum Flood Water is elevation
583.7 feet... Section 9.2.1.3 stated, In the event of high water levels,...the
[service water] pump room is sealed to prevent flooding. Section 3D.1.4, [GDC]
Criterion 4 - 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.
Contrary to these commitments, the service water system was not 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 follows:
(1) The three service water pumps were located in a single sealed room in the
service water pump house. Also located in the same room, immediately adjacent
to and staggered between the service water pumps, were two cooling tower
makeup (CTMU) pumps, each capable of pumping up to about 15,000 gallons per
minute. Neither the CTMU pumps nor the associated piping and equipment were
seismically qualified or mounted. The inspectors determined that during a
seismic event, the pumps could be dislodged from their mountings. If this were to
occur then the CTMU pumps could impact the adjacent service water pump
columns and pump motors, resulting in their failure. Additionally, failure of a
CTMU pump casing or its associated piping could produce flooding rates which
could completely fill the room in approximately two minutes. The service water
pump motors would begin to flood at a water level of about five feet above the
floor in significantly less time, and the safety-related motor control centers
(MCCs) located in this room at approximately one foot off the floor in just
seconds. These MCCs provided power for service water system motor operated
valves, the safety-related room ventilation fans, the service water strainer motors,
and other equipment. Therefore, a seismic event that could cause structural
failure of the CTMU pumps or piping could result in rapid loss of both divisions of
service water due to mechanical impact or room flooding.
18
The concern with the seismic qualification of the CTMU piping was identified by
the licensee in the LIR and documented on CRs 02-06297 and 02-06139. The
issue of the seismic qualification of the CTMU pumps with respect to impact on
the adjacent service water pumps and the issue of flooding as a result of the
movement of the seismically non-qualified CTMU pumps causing their own casing
failure or the failure of the attached piping had not been identified or documented
by the licensees LIR.
(2) The CTMU pumps were equipped with a feature intended to provide protection for
the service water system components in the room in the event of cracks or breaks
in the CTMU components in the room. The feature was a pressure switch located
in the discharge piping of each CTMU pump that was designed to shut down the
pump whenever discharge pressure decreased to 20 psig from normal operating
pressure, about 50 psig. However, informal evaluations performed by the
inspectors and subsequently by the licensee, indicated that break flows of several
thousand gallons per minute would be required to reduce the pressure to the
shutdown setpoint. At this rate the vital equipment in the room would be flooded
in seconds. Therefore, the inspectors concluded that this device was incapable
of performing its intended purpose. Additionally, this feature was non-safety,
non-1E powered, non-environmentally qualified, and not designed for single
failure. Therefore, it did not meet the fundamental design requirements for
equipment required to perform a safety function.
(3) The diesel fire pump was located in a space adjacent to the service water pump
room but within the same sealed enclosure, and the spaces were connected by a
non-watertight door and a ventilation opening in the wall between the rooms. The
floor elevation of this enclosure was 576'. The fire pump room contained a drain
sump with two non-safety related sump pumps, each equipped with a single
non-safety related discharge check valve. A common four-inch discharge line
downstream of the check valves penetrated the west wall below the maximum
lake flood level (583.7') and was connected to the plant storm drains. These
valves were not in any test or inspection program; therefore, they could be
considered failed open. Therefore, a design basis flood from the lake could
cause backflooding of both rooms through these valves.
An extent-of-condition review, performed at the inspectors request, in the service
water valve room and pipe tunnel located just outside the sealed service water
pump room revealed a similar condition. This area, at a floor elevation of 566'-3",
was connected to an adjacent water treatment building by a non-watertight door
and another ventilation wall opening. This review identified three sumps
containing a total of seven sump pumps, each equipped with an unqualified,
untested check valve that connected with the storm drains. In this area and
below flood elevation, were the safety-related service water valves SW-1395 and
SW-1399, which were required to provide isolation of the non-safety related
portion of the system for accident conditions. Such flooding could also preclude
operator access to these valves for manual isolation.
- USAR Section 3.4.1 stated, The Seismic Class l service water tunnel may be
flooded due to postulated failures of either water treatment structures and
19
systems or failure of Seismic Class II pipe within the tunnel. It goes on to say
that, The Seismic Class I systems within the tunnel are designed to remain
operational while flooded. As a result of questions by the inspectors, the
licensee identified several non-seismic pipes and components in the service water
pipe tunnel/valve room and the connected water treatment structure that had not
been evaluated in the flooding analyses; no documentation could be provided that
demonstrated the ability of the service water isolation valves SW-1395 and
SW-1399 to operate while flooded.
- In response to inspector questions, the licensee performed a review of the service
water pump room penetrations that were below the external flood elevation. This
review revealed that conduits that terminated at junction boxes below the flood
level were not sealed against flooding; the sealing of these junction boxes had
been credited for flood protection. However, these boxes were not rated for flood
conditions (internal flooding of the box), and their seals could not be reliably
assured.
- The inspectors walkdown of the service water system identified another potential
external flood source in the service water pump room. CTMU pump number
116-2 was out of service, and the two-inch drain valve from its strainer was
danger tagged open. This formed a direct communication between the room and
the intake bay through the pump column, the discharge piping, and the strainer.
For an external flood, this valve would have allowed the room to be flooded. The
Senior Reactor Operator accompanying the walkdown was asked what actions
with regard to valve lineup in the room would be required for an external flood,
and the response was none. The inspectors then reviewed the plants external
flood procedure, RA-EP-02830, Emergency Plan Off Normal Occurrence
Procedure, Flooding, Revision 00, and found that it had no guidance with respect
to verifying proper valve lineup for flood protection, and the licensees clearance
order tagging procedure also did not address this condition.
- One of the documents provided to the inspectors in response to these concerns
was Safety Evaluation 96-0078, which addressed potential flooding of electrical
duct banks. This document addressed the fact that the then-current USAR
indicated that three of the duct banks were enveloped in a waterproof membrane
up to the 577'-10" elevation, but in fact, those three, along with the other plant
duct banks, were only protected up to 575'. However, the maximum lake flood
level was 583.7', and the safety evaluation addressed only the effect that such a
flood would have on groundwater table seepage. The safety evaluation
incorrectly concluded that groundwater would not exceed 574.5', and therefore,
the duct banks were protected. It also incorrectly appeared to assume that the
breakwater dike at elevation 591' would protect the general site from the static
lake level during such a flood, and therefore it did not address the potential for
direct flooding of the duct banks from this source.
The licensee entered the issue into its corrective action program as CRs 02-07714,
02-07782, 02-07760, 02-07569, 02-07746, 02-06297, 02-06139 and screened the CRs
as requiring resolution prior to the mode in which SW was required by plant TS (Mode 4).
In order to resolve the issue, the licensee will need to perform additional analyses to
20
assess the ability of the licensees SW pumphouse to withstand internal and external
flooding. This issue will remain unresolved pending the licensees evaluation and the
NRCs review (URI 50-346/2002-014-01h).
.5 Design Review
a. Inspection Scope
The team reviewed the current as-built instrument and control, electrical, and mechanical
design of the selected systems. These reviews included a review of design assumptions,
calculations, required system thermal-hydraulic performance, electrical power system
performance, protective relaying, and instrument setpoints and uncertainties. The team
also performed a single failure review of individual components to determine the effects
of such failures on the capability of the systems to perform their design safety functions.
The inspectors reviewed the selected systems including a review of calculations,
drawings, specifications, vendor documents, Updated Final Safety Analysis Report, TS,
emergency operating procedures, and temporary and permanent modifications.
b. Observations and Findings
Non-Conservative TS Value for the 90 Percent Degraded Voltage Relay
The inspectors identified a Green finding that is being treated as an additional example of
a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control,
associated with assurance that applicable regulatory requirements and the design basis
for structures, systems, and components were correctly translated into specifications,
drawings, procedures, and instructions. Specifically, the inspectors determined that the
TS allowable value for the 4160 VAC, 90-percent Degraded Voltage function as stated in
TS Table 3.3-4 was non-conservative.
This table established an allowable setpoint value of $ 3558 Volts for the 90 percent
Degraded Voltage Relay at Davis-Besse Nuclear Plant. Licensee calculation
C-EE-004.01-049 established an allowable value for Degraded Voltage at 90 percent of
the nominal bus voltage of 4160 V, or 3744 V. The calculation determined this value
based upon the minimum voltage value that motor operated valves (MOVs) require to
successfully operate. Based upon voltage drop analysis of the Davis-Besse electrical
distribution system, the calculation determined that 88.5 percent (3682 V) was the
minimum acceptable short-term degraded voltage at the safety related 4160 V buses.
The calculation allowed for uncertainties and established additional margin for future
application against plant modifications and minor changes. Based upon the calculation,
the analytical limit was determined to be 3690 V and the resulting allowable value was
established as 3744 V.
While the value calculated appeared to be sufficiently conservative, the inspectors noted
that the licensee had not established administrative controls in relation to this issue.
While CR 02-06243, documenting the discrepancy between the TS allowable value and
the value determined by the calculation, had been issued four days prior to the inspection
team arriving on site, the CR concluded that no immediate action was required at that
21
time. Further, the CR recommended that the calculation procedure should be revised to
permit calculation preparers to place calculations that require an event to take place prior
to permitting use in Restricted-Hold status. To date, there is no mechanism that
permits a calculation to be performed and issued without approving it. This makes it part
of the design basis and could have severe ramifications if the calculation data were used
in the field. In lieu of having the requirements in the calculation procedure that permit
issuance of Restricted-Hold calculations, this calculation should be revised to reflect the
current licensing basis in the TS.
The inspectors communicated to the licensee that while they had identified the
discrepancy between the TS allowable value and the value determined by the calculation,
the actions that they had proposed in CR 02-06243 appeared to be inadequate. The
inspectors noted that since the value in the calculation was the correct value,
administrative actions should be taken to make the operations staff aware that the TS
allowable value was incorrect and non-conservative.
Without administrative controls in place to identify the non-conservative TS allowable
value for the 90 percent Degraded Voltage Relay, a condition could exist in which the
voltage setting for this relay could have been set non-conservatively and still declared
operable. With a lower setpoint, motor-operated-valves required for post-accident
operation may not have been able to operate when called upon.
10 CFR Part 50, Appendix B, Criterion III, Design Control, requires that Measures shall
be established to assure that applicable regulatory requirements and the design
basis...are correctly translated into specifications, drawings, procedures, and
instructions. Contrary to this requirement, the licensee failed to correctly establish the
TS allowable value for the 90 percent Degraded Voltage Relay setpoint.
This finding was determined to be more than minor because it affected the mitigation
systems cornerstone objective. This finding screened as Green in the SDP phase 1,
since this issue was a design deficiency that was confirmed not to result in loss of
function in accordance with GL 91-18 (Revision 1). Because the finding was of very low
safety significance, and was captured in the licensees corrective action system as
CR 02-07766, this finding is being treated as an NCV consistent with Section VI.A.1 of
the NRC Enforcement Policy (NCV 50-346/2002-014-01i).
Poor Quality Calculation for 90 Percent Degraded Voltage Relay
The inspectors identified an unresolved item associated with use of insufficiently justified,
non-conservative uncertainty values in the calculation for the 90 percent Undervoltage
Relays.
The inspectors questioned why the licensee did not use vendor-supplied numbers for
uncertainties for the 90 percent Undervoltage Relays. Instead, the licensee used
uncertainty values associated with a vendor test report for the relay. This test report,
however, only provided test data for one tested relay and not for a batch of relays. This
resulted in the licensee using smaller uncertainty values in their calculation. The use of
these smaller uncertainty values resulted in non-conservative results in the setpoint
calculation for the 90 percent Undervoltage Relays.
22
The licensee entered the issue into its corrective action program as CR 02-07633.
In order to resolve the issue, the licensee will need to perform additional analysis
to assess the impact of using non-conservative uncertainty values. This issue will
remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01j).
Non-Conservative Relay Setpoint Calculation for the 59 Percent Undervoltage Relay
The inspectors identified a Green finding that is being treated as an additional example of
a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control,
associated with assurance that applicable regulatory requirements and the design basis
for structures, systems, and components were correctly translated into specifications,
drawings, procedures, and instructions. Specifically, the inspectors identified that
uncertainties associated with the 59 percent Undervoltage Relay TS allowable setpoint
value were non-conservative. Based upon the as-left values and the tolerance band
used in the calibration procedures for the relays, this allowed the relays to be calibrated
to an upper band that, with the true uncertainties taken into account, allowed the TS
upper setpoint to be exceeded.
TS Table 3.3-4 established an allowable setpoint value of $ 2071 to # 2450 Volts for the
59 percent Undervoltage Relay at Davis-Besse Nuclear Plant. Therefore, the relays
should have been calibrated to a value that, with uncertainties factored in, was within the
allowable values band. Calculation C-EE-004.01-051 established a value for calibration.
In the calculation, uncertainty values for M&TE equipment, Potential Transformer (PT)
accuracy, drift, and tolerance (band allowed for technician setting the relay) were used to
determine the nominal setpoint for the relays.
Since electrical undervoltage relays operate at voltage levels much less than the voltage
seen at the 4160 VAC bus, the voltage is stepped down through a PT to allow relay
operation. The PT ratio used at Davis-Besse corresponds to a 35 to 1 primary to
secondary turns ratio. Thus, at 2450 Volts on the primary side of the PT, the relay would
experience a voltage of 70 Volts. With uncertainties taken into account, the relays would
need to have been set at a voltage less than 70 volts; however, the relay (type NGV)
used at Davis-Besse was not rated for operation below 70 volts. The NGV relay is rated
for operation within a band of 70 volts to 120 volts. Since the relay could be physically
set below 70 volts, the licensee still used the relay, with a lower setting. The inspectors
noted that it is uncertain how this would have affected the relays operation; however,
since operation below rated values could cause additional inaccuracies in the relay, the
inspectors determined that an evaluation would need to be performed to determine the
effects of operating below the relays established vendor ratings. This evaluation had not
been performed by the licensee.
Additionally, the drift value used by the licensee was based upon observed calibration
data performed on relays prior to 1992. The value that was established (+/- 0.5V) was
based upon monthly as-found values. Based upon review of monthly functional results
on the relays from the past three years, the inspectors discovered that the drift actually
exceeded the +/- 0.5V value used in the calculation. In fact, one as-left value showed a
drift of 0.9V in the positive direction. Based upon this, the inspectors determined that the
23
drift value that was used by the licensee was poorly established and resulted in the use
of a non-conservative drift. Condition Report 02-06737 documented this issue.
The inspectors also questioned the absence of a value for uncertainties associated with
temperature effects on the relay. Since temperature effects for the most part were also
in the positive direction, the absence of such a value again would be non-conservative.
The licensee acknowledged this concern in CR 02-07646.
Additionally, the vendor manual for the NGV relay established an accuracy value for
dropout of the relay on undervoltage. Vendor documentation stated, On any dropout
operation, the voltage range from the beginning of the action to its completion is about
one percent of rated voltage. The rated voltage for the NGV relays is 120 volts.
Consequently, the accuracy of these relays is 1.2 volts. This meant that if an
undervoltage condition were to occur, the relay was not guaranteed to dropout until
the voltage reached 1.2 volts below the relay setting. Calculation C-EE-004.01-051 did
not account for this accuracy. The absence of this value again resulted in a
non-conservative value for the 59 percent Undervoltage Relays.
In accordance with Davis-Besse maintenance/testing procedures for these relays, the
upper band for the 59 percent Undervoltage Relay was 68 volts. If the more conservative
values had been accounted for in the calculation, and the NGV relay vendor-provided
accuracy had been accounted for, this value would have been lower. Additionally, had
temperature effects and the operation of the relay outside of its rated band been taken
into account, the upper voltage value could have been even lower. By not accurately
factoring in all the uncertainties, the licensees upper voltage limit allowed the setpoint for
the 59 percent Undervoltage Relay to be above the allowable value of 70 volts.
In addition, the results in calculation C-EE-004.01-051 established a Dropout Setting
Range for the relay as 65 to 69 volts. The calculation also stated that for operability
purposes, an undervoltage relay whose as-found operating voltage if found to be
greater than (>) 69.64 volts (2437.4 volts primary) will be considered to be outside the
bound of the Technical Specification allowable values. These conclusions were clearly
incorrect.
Not exceeding the upper voltage limit is important, because the undervoltage relay
should actuate at a value low enough so that inadvertent power supply transfers can be
prevented. Since both divisional sets of undervoltage relays were affected, this could
have potentially led to a premature loss of offsite power. However, since each division
had four relays for each safety-related 4160-Volt bus, and since the likelihood of an
occurrence of the type of limited undervoltage transient that would cause the relays to
drop out prematurely is small, the risk significance of this issue is very low.
10 CFR Part 50, Appendix B, Criterion III, Design Control, requires that Measures shall
be established to assure that applicable regulatory requirements and the design
basis...are correctly translated into specifications, drawings, procedures, and
instructions. Contrary to this requirement, the licensee failed to correctly calculate the
59 percent Undervoltage Relay TS allowable setpoint value.
24
This finding was determined to be more than minor because it affected the initiating
events cornerstone objective. This finding screened as Green in the SDP phase 1, since
this issue does not contribute to the likelihood of a Primary or Secondary system LOCA
initiator, does not contribute to both the likelihood of a reactor trip and the likelihood that
mitigation equipment or functions will not be available, and does not increase the
likelihood of a fire or internal/external flood. Because the finding was of very low safety
significance, and was captured in the licensees corrective action system, this finding is
being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy
(NCV 50-346/2002-014-01k).
Inadequate Calculations for Control Room Operator Dose (GDC-19) and Off-Site Dose
High Pressure Injection Pump Minimum Flow Valves HP31 and HP32
The inspectors identified an unresolved item associated with correctly translating the
USAR commitments regarding calculations for General Design Criteria (GDC)19 and
10 CFR Part 100 requirements. The design of the HPI system has a single isolation
valve on each of the minimum flow return isolation lines to the borated water storage tank
(BWST). The teams review identified inadequate analysis of a single failure of the
minimum flow valve return check valve HP31/32 to close during the recirculation phase of
a postulated LOCA.
Note 1 of USAR Table 6.3-6 entitled Single Failure Analysis - Emergency Core Cooling
System, stated the following: The dose rate at the site boundary due to shine from
the Borated Water Storage Tank (BWST) has been evaluated for this case and found to
be 300 mr/hr. This was based on a site boundary minimum distance of 737 meters. The
flow through the line to the BWST was assumed to be 500 gallons (expected flow rate is
35 gpm). The activity entering the BWST was the activity in the Containment Vessel
Emergency Sump water, containing 50 percent of the core saturation inventory
consistent with licensee specifications. This activity was based on an assumed decay for
90 minutes, the time at which the recirculation mode is initiated, based on the worst RCS
break (0.1 ft2) for which the piggyback mode may be required. The dose rate was
determined by considering the BWST as a point source conservatively neglecting
self-attenuation of the water in the tank and not taking any credit for dilution with water
already in the lower portion of the tank.
Assumption 5, Sheet 3 of calculation 35.25, Dose Rate from BWST, states the
following: The input of the CTMT sump water into the BWST starts at 90 min after the
LOCA and lasts 10 min. Input rate is 50 GPM... This assumption of the total release
based on the 500 gallons did not appear to be conservative for the following reasons:
- Use of an assumed 10 minutes for operator action could not be supported
because the most limiting single active failure for this scenario is a spurious
reopening of one of the minimum flow valve return check valves after valve
closure. Due to the lack of a safety grade alarm which indicates mispositioned
valves, the basis for the 10-minute assumption could not be validated by the
licensee.
25
- Review of surveillance test procedure DB-SP-03218/03219 showed that the
indicated flow was approximately 50 gpm. However, the test configuration is
different from the post-LOCA recirculation phase. The test configuration
simulated the injection phase, where the HPI pump suction was aligned to the
BWST tank. The release configuration takes place in the recirculation, piggyback
mode, where the HPI pump suction is aligned to the discharge of the low head
injection (LPI) pumps. The discharge head of the LPI/DHR pumps would add to
HPI pumps, greatly increasing the discharge pressure, resulting in a significantly
higher flow than 50 gpm.
- The assumption of a 90-minute delay was also non-conservative. Emergency
procedure DB-OP-02000 stated that the piggyback mode would be used for all
LOCAs which result in LPI flows less than 1100 gpm. The 90-minute assumption
appears to be based on the no LPI flow time calculation. USAR Section 6.3.2.11,
Reliability Considerations, states: Since LPI injection is not flowing in this
situation, it will take at least 100 minutes to empty the BWST with both HPI and
Containment Spray pumps running at design capacity, which gives the operator
an ample amount of time to determine the need for, and to perform the required
actions. Motor operators on the valves and hand switches in the control room are
installed to allow alignment from the control room. Based on the usable BWST
volume of 360,000 gallons and combined LPI flow of 2,200 gpm, the time at
which recirculation will take place is estimated to be approximately 60 minutes or
less (depending on the level and LPI flow instrument accuracy, actual
containment spray flow vs. the design flow, etc). Thus, a 90-minute delay is not
conservative.
- The miniflow return line is located near the top of the BWST. During the event of
interest, the BWST level is significantly below the point of the return pipe entry.
The jet of a high pressure liquid at the temperature of about 200EF exiting the
pipe nozzle inside the tank will have an appreciable fraction of its liquid flash to
vapor along with the entrained gases. The remaining liquid could have a large
surface area as it travels downwards, liberating the remaining gases which have
partial pressures below the tank atmosphere. Thus the USAR statement and
calculation assumptions of iodine coming out of solution are correct and not
overly conservative, contrary to the statement made in the calculation.
Therefore, the critical inputs used for dose calculation (the assumed volume and the
activity decay time) appear to be non-conservative.
The calculation was silent on the impact on the GDC 19 limits. Part B of the calculation
dealt with the gaseous release.
The licensee issued CR 02-06701 to document the teams concern. This CR noted that,
...this issue involves past operability issues and must be considered a restart issue.
The inspectors questioned the licensee if the site boundary release described in Note 1
of USAR Table 6.3-6 was incorporated in the 10 CFR 100 or the GDC 19 calculations.
Based on this question and other related team questions, the licensee issued
26
CRs 02-07701 & 02-07713, which identified problems related to GDC 19 and 10 CFR
Part 100 calculations (see discussion below).
The licensee screened the three CRs as requiring resolution prior to the mode in which
ECCS was required by plant TS (Mode 4). In order to resolve the issues, the NRC
will need to assess the licensees reevaluation and the impact of the calculational
deficiencies on the GDC-19 and 10 CFR Part 100 regulatory limits. This issue will
remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01l).
Other GDC 19 and 10 CFR 100 Issues
The inspectors identified an unresolved item associated with correctly translating USAR
commitments regarding calculations for GDC-19 and 10 CFR Part 100 requirements.
The inspectors review of the surveillance test procedures, USAR, calculations and
discussions with the licensee determined that the USAR calculated offsite dose was
based on an ECCS leakage rate of 1.6 gallons per hour (gph) while the allowable
leakage rate was based on 40 gph.
USAR Section 3.6.2.7.1.11 discusses a pump seal failure 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after a LOCA with an
assumed leak rate of 120 gpm. However, offsite dose calculations and control room
dose calculations for this postulated passive failure were not calculated. Some of the
(iodine) releases from this postulated leak would be in the ECCS pump rooms, which
were ventilated through safety grade charcoal filters. However, the iodine remaining in
the solution could come out of the system after it has been pumped to the radwaste
system. A leak in this area would be through a path outside of the ECCS pump room
ventilation filters. Also, the radwaste storage tank is not seismic and releases from the
area would not be filtered. It should be noted that calculation 36.28, ECCS - Pump Seal
Failure, Revision 0, determined the maximum acceptable leakage rate through the pump
seal as 82.7 gpm based on the control room dose (GDC 19). In response to the teams
question as to whether this calculation was current or superceded, the licensee
responded that no calculation that superceded calculation 36.28 could be located.
In response to the teams concerns described above, the licensee issued CR 02-07713.
This CR documented the above concerns and also stated the following:
In general, the dose contributions expected from these sources is
not large compared to other accident dose. However, in a fairly
short review time, the above issues were all identified. Therefore,
as noted above, a thorough extent of condition review should be
performed to look for identification of all required accident dose
contributors and consistent treatment of accident dose
contributions.
Additionally, CR 02-07713 documented that the control room operator doses evaluated
in USAR Section 15.4.6 were based on only the containment leakage contribution. The
doses resulting from expected fluid leakage from the ECCS post-LOCA were not
addressed. NRC Regulatory Guide 0737 requires such an evaluation to be performed.
27
The licensee screened CR 02-07713 as requiring resolution prior to the mode in which
ECCS was required by plant TS (Mode 4). In order to resolve the issue, the licensee will
need to assess the impact of the calculational deficiencies on the GDC-19 and 10 CFR
Part 100 regulatory limits This issue will remain unresolved pending the licensees
evaluation and the NRCs review (URI 50-346/2002-014-01m).
HPI Pump Operation Under Long Term Minimum Flow
The inspectors identified an unresolved item associated with adequately assessing HPI
pump operation under long term minimum flow. The team reviewed the licensees
response to NRC Bulletin 88-04 which directed licensees to evaluate the capability of
safety related pumps to run at minimum recirculation flow rates. For the HPI pumps, the
licensee had concluded that the supplied minimum recirculation flow was adequate. The
licensee had contacted the HPI pump vendor for information and the vendor responded
that, while there was no definitive data that would raise doubts concerning the HPI pump
miniflow, they were unable to confirm that these flows were adequate to ensure that HPI
pumps would not experience degradation as a result of the impeller recirculation. The
vendor further recommended that a pump test to verify the endurance be conducted
under actual miniflow conditions.
The licensee subsequently performed a test, which indicated low vibration readings when
in the minimum recirculation mode. The teams review of the test determined that the
test conditions appeared to be non-conservative. The test had been performed at normal
ambient temperature using BWST water which simulated the injection phase of the
accident rather than the recirculation phase which would experience significantly higher
fluid temperatures and possibly debris. Additionally, this was a one-time-only test,
hence, the effects of degradation, wear, and tear were not addressed. The licensees
assessment also did not address the allowable duration of operation at a minimum flow
condition. Based on the teams questions, the licensee issued CR 02-07684. This CR
noted that ...due to the importance of the pumps to perform their functions, and the
potential for extended periods of operation on minimum recirculation mode, this issue
should be considered a mode 3 restart constraint.
The licensee screened CR 02-07684 as requiring resolution prior to the mode in which
ECCS was required by plant TS (Mode 4). In order to resolve the issue, the licensee will
need to assess the ability of the HPI pumps to perform as intended during extended
operation on minimum flow. This issue will remain unresolved pending the licensees
evaluation and the NRCs review (URI 50-346/2002-014-01n).
HPI Pumps Minimum Flow, Unanalyzed SBLOCA Sizes
The inspectors identified an unresolved item associated with analyzing some small break
LOCA (SBLOCA) sizes. The inspectors review of the USAR and discussions with the
licensee determined that the SBLOCA analysis covered a spectrum of breaks starting at
0.01 sq. ft. USAR Sections 15.3.1.1 states Depending on the break location and
imposed boundary conditions, a break area can be identified for which the HPI or normal
makeup system is capable of matching the leak rate ensuring an orderly shutdown. For
example, the leak rate resulting from the rupture of a 3/4" schedule 160 instrument line
(0.002 ft2) is matched by the normal makeup system about 1000 seconds into a
28
postulated accident without a complete loss of the pressurizer liquid level. The HPI
pump minimum flow recirculation valves are closed prior to transferring to the
containment emergency sump following a loss of coolant accident (LOCA). If the HPI
pumps are not assured of injecting sufficient water into the Reactor Coolant System, the
pump flow may not be adequate for thermal protection (reference NRC Bulletin 88-04
minimum flow issues).
An example condition where this could be problematic is for very small break LOCAs that
later repressurize the RCS above the HPI shut-off head. An additional issue involves
performance of the water lubricated outboard bearing when on containment sump
recirculation. The concern is that at low flow rates, the bearing load may be higher and
the bearing could be less tolerant of debris.
The licensee contacted the NSSS vendor for discussion of smaller break sizes, between
the capacity of the makeup system and up to the 0.005 ft2 range, which were not covered
by the existing SBLOCA analyses. For these breaks, the vendor could not discount the
possibility of intermittent repressurization that would challenge the minimum HPI pump
flow requirements for both HPI trains.
In summary, the spectrum of the SBLOCA breaks from 0.002 to 0.01 sq. ft. breaks was
not analyzed and the impact on the HPI pumps ability to perform their safety-related
function was unknown prior to the inspectors questions. This scenario could
simultaneously affect both HPI trains, without any additional postulated single failures.
This CR noted that This issue needs to be resolved prior to restart.
Based on the inspectors questions, the licensee issued CR 02-06702 and screened the
CR as requiring resolution prior to the mode in which ECCS was required by plant TS
(Mode 4). In order to resolve the issue, the licensee will need to assess the ability of the
HPI pumps to perform as intended during extended operation on minimum flow. This
issue will remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01o).
Inadequate Service Water System Flow Analyses
The licensee and the inspectors identified an unresolved item associated the licensees
SW system flow analysis in properly accounting for a number of required conditions. The
latest service water system flow calculation of record that was intended to demonstrate
the ability of the system to deliver the design basis flows to the various service water
system safety-related loads was C-NSA-000.00-017, PROTO-FLO Service Water
System Model. The inspectors reviewed this calculation and found that it non-
conservatively did not account for the following:
- The lowest acceptable service water pump performance (the calculation utilized
the original vendor performance curves with no degradation margin).
- Single failure of the forebay return valve SW-2930 to open, which required
opening SW-2929 in order to use deicing return flowpath, which was the highest
resistance pathway.
- Design basis strainer resistance.
- Strainer blowdown losses.
29
- Back leakage through service water pump discharge check valves (test
acceptance criterion for these valves was that back flow would not cause idle
pump rotation which, in fact, would require flows of several hundred gpm).
- Design basis lowest ultimate heat sink (UHS) level.
- Providing the safety-related water source for the auxiliary feedwater system.
- Removal of various check valve internals (valves were modeled as straight pipe).
Therefore, the ability of the system to provide the required design basis flows to the
safety-related heat exchangers could not be verified.
All of these deficiencies except for the pump discharge check valve leakage were also
identified by the licensee in the LIR and documented in CR 02-06438. Some were also
re-identified in the licensees Safety System Design and Performance Capability (SSDPC)
self-assessment and documented in CRs 02-6333 and 02-07745.
The licensee screened the three CRs as requiring resolution prior to the mode in
which the SW system was required by plant TS (Mode 4). In order to resolve the issue,
the licensee will need to assess the service water system flow requirements against the
yet-to-be-performed analyses that demonstrate the ability of the system to provide the
required flows to safety-related loads under design basis conditions. This issue will
remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01p).
Definition of Passive Failure
During the review of the single-failure effects in the SW system, the inspectors postulated
a passive failure in valve SW-82. The inspectors requested the licensees analysis for
assuming that valve SW-82 failed closed and could not be reopened; for example, if the
valve had a stem-to-disc separation. The licensee stated that other failures of valve
SW-82 had been assessed previously and documented in PCAQR 91-0611, but that they
did not consider a stem-to-disc separation as either credible or required to be assumed as
part of a passive failure analysis.
The inspectors disagreed with the licensees position that stem-to-disc separation was not
credible and also disagreed with the licensees position that stem-to-disc separation was
not required to be assumed as part of a passive failure analysis.
This matter will be referred to the Office of Nuclear Reactor Regulation. Pending the
results of that deferral this item will remain unresolved (URI 50-346/2002-014-05).
Inadequate Service Water System Thermal Analyses
The inspectors identified an unresolved item associated with the licensees SW system
thermal analysis properly accounting for a number of required conditions. The inspectors
reviewed several calculations that were intended to establish the design basis
temperature profile for the Ultimate Heat Sink (UHS). The UHS temperature profile
information generated in these calculations was required as an input to the SW heat
exchanger thermal performance calculations, which were intended to demonstrate their
30
ability to remove their design basis heat loads without exceeding their individual design
temperature limits.
The inspectors identified a number of non-conservatisms (listed below) in the UHS
calculations and in the measurement of service water temperatures. As a result, the
calculated time-dependent service water temperature profile, which was input to all of the
SW system heat exchanger performance analyses, was determined to be
non-conservative:
- The UHS analyses did not consider a postulated single failure-to-open of the
forebay return valve, SW-2930. Failure of valve SW-2930 to open is the worst
case system lineup with respect to SW system temperature profile, since it would
redirect service water to the forebay through the deicing line. This flowpath
returned the heated service water directly in front of the service water pump house
trash bars rather than at the opposite end of the forebay, which was the normal
post-accident return discharge point. Therefore, the returned water had a much
lower heat rejection opportunity than from the normal return point.
- The licensee had analyzed the deicing flowpath and determined a higher UHS
temperature profile would result. The forebay return path resulted in a peak of
112.6EF instead of 107.6EF for the normal accident flowpath; however; only the
lower value was used as input for all service water heat exchanger calculations.
An additional non-conservatism was that the calculation only considered the clean
pond condition, (i.e., with no silting).
- Calculation 12501-M-00004, UHS Pond Performance Analysis - Max Evaporation
- Silting, addressed the UHS thermal performance and volume for 1.5 feet of
silting in the forebay; however, it did not consider the deicing return flowpath.
- The design basis initial service water temperature used for all heat exchanger
analyses was 90EF. This was reflected by TS 3.7.5.1.b, which limited the UHS
temperature (not service water temperature) to an average of #90EF. A single
instrument was used for determining compliance with this TS. It was located in
front of the service water pump house trash bars, approximately two feet above
the pond bottom. However, as early as 1995, the service water system supply
header temperature had been measured with very accurate measurement and
testing instrumentation (M&TE) at approximately 1.5EF to 2EF warmer than the
readings from the TS instrument. This information indicated three non-
conservatisms with the service water heat exchanger analyses and the UHS
thermal analyses as follows:
- With the indicated UHS temperature at the TS 90EF limit, the actual
temperature entering the heat exchangers could be as much as 2EF higher
than the analyzed condition, significantly reducing their performance,
potentially below design basis values.
- All UHS pond analyses started with an assumed uniform pond temperature of
90EF. The observed temperature offset during normal operation between the
31
UHS pond temperature near the bottom and the service water header
temperature indicated that the service water delivered to the heat exchangers
was a mixture of warmer, upper-strata pond water with the cooler near-bottom
water. Therefore, the temperature as read from the TS instrument was also
not indicative of the average [UHS] water temperature as required by the TS.
Rather the true average UHS temperature was somewhat higher than the
monitored temperature at the TS instrument. Therefore, the UHS analyses
contained non-conservative initial temperatures with respect to the indicated
TS value.
- The UHS analyses were based on a time-dependent model that started with
uniform pond temperature at 90EF, and the hotter returning service water
entering the pond near the surface and displacing the uniform temperature
water downward toward the entrance to the intake structure. However, this
was a non-conservative model with respect to the actual stratification indicated
by the temperature observations. With stratification existing during normal
operation, hotter water would reach the service water intakes sooner than the
model predicted for accident conditions.
which is initially shed from the component cooling water (CCW) system (cooled by
service water) early in an accident, but must be restored by operator action at a
later time to prevent exceeding the SFP design temperature, 150EF. The design
basis analyses indicated that the fuel pool would not only exceed 150EF very
quickly, but would reach boiling within ten hours of loss-of-cooling (SFP heat load
was significantly increased with the high density fuel storage modifications). There
were no analyses that addressed the structural or leak-tight integrity of the SFP,
the thermal-hydraulic capability, e.g., restart capability of the SFP cooling system,
or the ability to provide makeup to the SFP for conditions beyond its design basis
temperature. The inspectors estimated this additional heat load at eight to ten
million BTUs per hour.
- The inspectors also identified that the ECCS pump room temperature analyses,
Calculation 12501-M-003, ECCS Pump Room Temperature, did not consider the
probable worst-case heat loads from pump motors and piping that would be
associated with the high pressure injection (HPI) pumps operating in the piggyback
mode.
Therefore, the ability of the service water system to provide the required design
basis heat transfer thermal conditions for the safety-related heat exchangers could
not be verified.
The licensee entered the issue into its corrective action program as CRs 02-05372,
02-06177, 02-06332, 02-06336, 02-06370, 02-07004, and 02-07716 and screened the
CRs as requiring resolution prior to the mode in which the SW system was required by
plant TS (Mode 4). In order to resolve the issue, the licensee will need to assess the
service water system thermal requirements. This issue will remain unresolved pending
the licensees evaluation and the NRCs review (URI 50-346/2002-014-01q).
32
Inadequate Ultimate Heat Sink Inventory Analyses
The inspectors identified an unresolved item associated with the licensees UHS inventory
analysis properly accounting for a number of required conditions. USAR Section 9.2.5.1,
Loss of Intake Canal, stated, The water stored in the intake forebay below elevation
562 feet will provide sufficient cooling surface to continue cooling the station by
evaporation for at least 30 days. The inspectors determined that the plants UHS water
inventory analysis of record, Calculation 12501-M-00004, UHS Pond Performance
Analysis - Max Evaporation - Silt, did not adequately account for the following water loss
pathways:
- During normal operation the service water system return water is routed through
valve SW-2931 to the plant cooling tower to provide its makeup (this routing does
not return the water to the UHS). In order to preserve UHS water inventory during
accident conditions, this valve is closed, and the water is returned to the UHS
(either through the forebay return valve SW-2930, or if it has failed to open,
through the deicing return valve SW-2929). However, the single failure of the
cooling tower return valve to close on demand would cause a substantial water
loss from the UHS through this pathway (30 inches diameter) that was not
accounted for in the calculation.
USAR Section 9.2.1.2 stated that for this condition, the operator could manually
close SW-2931 within three hours. However, this statement was valid only for an
electrical failure where the operator could manually close the valve, but would not
necessarily be valid for a mechanical failure. Additionally, the existing analyses did
not account for even this three-hour water loss.
- The only safety-related water supply for the auxiliary feedwater (AFW) system was
the service water system. However, the licensee did not account for UHS water
loss through this pathway for events that would require AFW operation. For such
events, it was assumed that the non-seismically qualified condensate storage tank
(CST) would supply AFW, with no decay heat or reactor coolant system (RCS)
sensible heat rejected to the UHS for thirteen hours. This was a non-conservative
assumption; there would be more net inventory loss from the UHS with the AFW
supply from the service water system than from the CST.
- Evaporation losses were based on the incorrect UHS temperatures described
earlier in the report. With higher actual UHS surface temperatures, evaporation
losses would be higher than calculated.
Therefore, the ability of the UHS to provide the required design basis inventory to support
operability of the service water system for the required 30 days could not be verified.
The licensee entered the issue into its corrective action program as CRs 02-05986,
02-06332, 02-06336, and 02-07692 and screened the CRs as requiring resolution prior
to the mode in which the SW system was required by plant TS (Mode 4). In order to
resolve the issue, the licensee will need to assess the impact of the calculational
deficiencies on the ability of the UHS to perform its intended function. This issue will
33
remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01r).
No Valid Service Water Pump Net Positive Suction Head Analysis
The licensee identified an unresolved item associated with a lack of a valid net positive
suction head analysis for the SW pumps. USAR Section 9.2.5.1 contained a discussion
of the adequacy of the service water pumps net positive suction head (NPSH) for all
design basis conditions. However, the licensee could provide no valid design basis
analysis that demonstrated this adequacy and the adequacy of the pump submergence
with respect to vortex prevention. Additionally, even if such an analysis had been
available, it would have likely been rendered non-conservative by the previously described
issues related to non-conservative UHS water inventory and temperature analyses.
Therefore, the ability of the system to perform its design basis safety function for all
conditions of reduced available NPSH and pump submergence within the design bases
could not be verified.
This concern was also identified by the licensee in the LIR, documented on CR 02-05923,
and screened as requiring resolution prior to the mode in which the SW system was
required by plant TS (Mode 4). In order to resolve the issue, the licensee will need to
assess the impact of the licensees failure to correctly translate the USAR commitments
with respect to adequacy of service water pumps NPSH and vortex margin into analyses
demonstrating adequacy. This issue will remain unresolved pending the licensees
evaluation and the NRCs review (URI 50-346/2002-014-01s).
Inadequate Service Water System (and Other Systems) Overpressure Protection
The design of the service water system was performed under the requirements of
ASME Code,Section III, Article NB-7000, Protection Against Overpressure.
Paragraph NB-7155 required that Individual pressure-relief devices shall be installed
for the overpressure protection of components which are isolable from the normal system
overpressure protection. Contrary to this requirement, none of the service water system
individual heat exchangers and associated piping that were isolable from the system were
provided with individual overpressure protection. Other safety-related system heat
exchangers, such as the decay heat removal and diesel generator jacket water heat
exchangers, were also found to not be provided with individual overpressure protection
devices.
Paragraph NB-7153, Provisions When Stop Valves are Used, required, No stop valve or
other device shall be placed relative to a pressure-relief device so that it could reduce the
overpressure protection below that required by these rules, unless such stop valves are
constructed and installed with positive controls and interlocks so that the relieving-capacity
requirements of NB-7400 are met under all conditions of operation of both the system and
the stop valves. Contrary to this requirement, many of the safety-related components in
the plant that were provided with relief devices also had manual isolation valves between
the components and the relief devices.
These conditions were identified by the inspectors as a result of review of
Modification 94-0009, Service Water Thermal Relief Valve Replacement for
34
Containment Air Coolers [CACs], which removed these valves from the CACs and did
not replace them. These valves had been initially installed by Modification 88-0234,
Overpressure Protection for the Containment Air Coolers, when it was determined that
the coolers were not originally provided with relief valves and, therefore, did not meet
Code requirements, as documented in PCAQR Number 88-0737. Discussions with
licensee engineers determined that this condition extended to other plant systems and
also that some of the relief valves that were installed had the prohibited isolation valves.
The licensee maintained that these conditions were acceptable based on their
interpretations of the Code. These interpretations and the inspectors responses follow:
On the concern of relief protection not provided:
- The licensee maintained that the heat exchangers in question were not designed
to the Code. However, the attached non-isolable piping was; therefore, by default,
in the inspectors view, they were required to meet Code requirements.
- The licensee stated that heat exchangers in operation were not isolated and thus
could not be thermally overpressurized; therefore, they were not required to be
protected. The licensee also stated that heat exchangers not in operation, i.e.,
not performing their cooling function but still filled with water, were not required by
the Code to be protected. Therefore, per these interpretations, relief protection
was never required for heat exchangers and associated piping under any
condition, whether in operation or not. The only other condition that could exist
was - not in operation and not filled with water, in which case, relief protection was
not required. Therefore, there was no condition - in operation, out of operation, or
completely disabled - for which the Code was applicable, which defied the obvious
intent of the Code. As reflected in Paragraph NB-7155, a heat exchanger is in
operation when it is completely filled with water, regardless of whether it is in
service or not, or isolated or not. The Codes only concern is whether the
component is isolable, because that was the only condition when the potential
to be overpressurized by isolation exists.
The conditions of concern for which the Code requirements were created were
for when heat exchangers and associated piping were filled with liquid
(incompressible), when they were isolated or could be required to be isolated, for
instance, as part of their operational mission, and therefore, when they could be
subjected to heating that could cause overpressurization. Many safety-related
heat exchangers and associated piping fell into these categories because they
could be in standby and fully isolated during normal operation, or partially isolated
and could be required by accident conditions to become fully isolated, such as the
CACs, which may be required to be fully isolated for containment isolation.
Additionally, isolation of the CACs for maintenance could subject them to
undetected overpressure that could compromise their leak tightness, which is one
of their safety functions as a containment barrier.
- The licensee maintained that heat exchangers were protected from overpressure
by plant procedures that prevented them from being isolated when they were filled.
However, the Code made no allowances for such administrative controls. The
35
licensee, however, stated that Paragraph NB-7153's allowance of positive
controls permitted the use of administrative controls in lieu of protection devices.
The inspectors disagreed for two reasons: first, that paragraph was applicable only
to the use of stop valves between relief devices and the components being
protected (which is addressed with the next concern), not valves that isolate the
components from the system. Second, in the context of that paragraph and all of
Article NB-7000, controls clearly refers to instrumented control devices, not
administrative controls. For example, the last sentence in this Code paragraph
discussed verification testing of such controls, which could not be appropriately
applied to administrative controls.
- The licensee stated that not having such devices could, at worst, result in slight
yielding of the components. Such yielding is not allowed by the Code for design
conditions for such components.
- The licensee stated that isolated heat exchangers other than the CACs could not
be subjected to temperatures nearly as high as the CACs, and therefore, would
not experience high stresses. Contrary to this, industry experience has shown that
heat exchangers filled solid with water can be subjected to very high stresses and
failure with relatively small temperature changes.
Regarding the concern of isolation valves between the protected components and the
relief devices:
- The licensee stated that isolation valves were allowed between the relief devices
and the components being protected by Paragraph NB-7153, as long as they were
administratively controlled. However, as discussed above, the only controls
allowed by this paragraph were control devices that were constructed and
installed. In common parlance, administrative controls cannot be constructed
and installed and their operability cannot be verified by test, as also required
by this paragraph.
In response to the inspectors concerns, the licensee generated CR 02-06860.
The licensee disagreed with the inspectors observations and stated that to their
knowledge they were in compliance with all code requirements. This matter will be
referred to the Office of Nuclear Reactor Regulation. Pending the results of that deferral
this item will remain unresolved (URI 50-346/2002-014-06).
Service Water Source Temperature for Auxiliary Feedwater System
The inspectors identified an unresolved item associated with the licensees analysis for
the elevated temperature effects on the AFW system. Section 9.2.1.1, of the USAR
[Service Water System] Design Basis, states that, The service water system also
provides a backup source of water to the auxiliary feedwater [AFW] system... Although
the condensate storage tank was the preferred water source because of its high water
quality, this tank was not seismically qualified. The service water system, therefore,
provided the seismically-qualified, safety-related backup water source. The inspectors
determined that the service water source for AFW had not been analyzed with respect to
36
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 steam
generators and inadequate cooling of AFW lubricating oil. Therefore, the ability of the
AFW system to perform its safety function using the service water source for all design
basis events for which it may be required could not be verified.
Elements of this concern were identified by the licensees LIR in CR 02-06107. The
licensee entered the entire issue into its corrective action program as CR 02-05923 and
screened the CR as requiring resolution prior to the mode in which the SW system was
required by plant TS (Mode 4). In order to resolve the issue, the licensee will need to
assess the impact of the increased SW temperature on the operability of the AFW pumps.
This issue will remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01t).
Short Circuit Calculations
The inspectors identified an unresolved item associated with the licensees analysis for
postulated short circuits. During the performance of the original calculations the licensee
used normal operating voltages instead of maximum voltages. At the higher voltages
some results may no longer be acceptable (e.g., if rated for 25,000 amps (25 kva) it may
now see 26 kva). This could result in some breakers not tripping and causing the fault to
propagate upwards to the 13.8 kv buses. The licensee had identified this issue about a
year ago, but the observation was being treated as an administrative issue only. In fact, if
a fault propagated upward, the fault could end up resulting in a loss of both normal power
supplies.
The licensee entered the issue into its corrective action program as CRs 02-06837
and 02-06302 and screened the CRs as requiring resolution prior to the mode in which
the 4160VAC was required by plant TS (Mode 4). In order to resolve the issue, the
licensee will need to assess the impact of the higher voltages on the licensees short
circuit calculations and the effect upon the safety-related 4160VAC buses. This issue
will remain unresolved pending the licensees evaluation and the NRCs review
(URI 50-346/2002-014-01u).
Inadequate Analytical Basis for the Setpoint to Swap Service Water System Discharge
Path
The inspectors identified a Green finding that is being treated as an additional example
of a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control,
associated with assurance that applicable regulatory requirements and the design basis
for structures, systems, and components were correctly translated into specifications,
drawings, procedures, and instructions when licensee personnel could not find an
analytical basis for the setpoint to swap service water system discharge path.
The service water system discharges into one of four paths. Two of these paths (cooling
tower makeup and the collection box) were not seismically qualified and provisions were
made in the design of the system to automatically divert flow to the seismically qualified
discharge lines (intake forebay and intake structure) in the event of obstruction of one of
37
the non-seismic lines. The setpoint for the swapover is 50 psig. The inspectors asked
licensee personnel for the calculational bases for this setpoint. Licensee personnel could
not locate an analysis.
Not having an analytical basis is of concern for two reasons. First, the plant could have
experienced a seismic event which did not fully obstruct the discharge path for service
water such that pressure would have been slightly less than the 50 psig setpoint and flow
would have been choked down. This extent of flow reduction should have previously been
evaluated to demonstrate the ability of the service water system to provide sufficient
cooling capability to survive a safe shutdown earthquake. Second, a passive failure
causing a similar flow reduction as above could have gone undetected during an event
which required design service water flow and design service water flow would not have
been demonstrated to be available. A suitable analysis which demonstrates acceptability
in these conditions was needed. The inspectors determined that the failure to have an
analysis which demonstrates acceptability of conditions with service water discharge
header pressure elevated higher than normal and up to the swapover setpoint could affect
the design function of the service water system.
10 CFR Part 50, Appendix B, Criterion III, Design Control, requires that Measures shall
be established to assure that applicable regulatory requirements and the design
basis...are correctly translated into specifications, drawings, procedures, and instructions.
Contrary to this requirement, the licensee failed to provide a basis for the setpoint to swap
the service water system discharge path.
The inspectors considered this finding more than minor because it could affect the
mitigating systems cornerstone objective of ensuring the capability of systems that
respond to initiating events to prevent undesirable consequences attributable to design
control. Using the significance determination process, the safety significance was
determined to be very low (Green) because the finding did not screen as potentially risk
significant due to a seismic, fire, flooding, or severe weather event. This violation is being
treated as a Non-Cited Violation (NCV 05000346/2002-014-01v) because of the very low
safety significance of this condition and because licensee personnel entered this finding in
the corrective action program as CR 02-07802. This condition report documents licensee
personnels intentions to check the adequacy of the setpoint.
.6 Safety System Inspection and Testing
a. Inspection Scope
The team reviewed the program and procedures for testing and inspecting designated
components of the selected systems. The review included the results of TS required
surveillance tests and ASME Code required quarterly in service tests conducted since
1994.
38
b. Observations and Findings
HPI Quarterly Surveillance Test Instrumentation Issues
The inspectors identified a minor Violation of 10 CFR 50, Appendix B, Criterion XI, Test
Control. Specifically, the inspectors review of the HPI pump quarterly tests identified that
the procedures specified M&TE instrumentation to be installed to improve the accuracy
of the test. The procedures specified three allowable instrument ranges for HPI pump
discharge pressure; however, two of the three specified instrument ranges (0-2500 psig,
0-3000 psig) were non-conservative when compared to the instrumentation range
(0-2000 psig) and readability specified in calculation C-NSA-052.01-003, HPI Pump
Acceptance Criteria, prepared in support of the above test procedures. Based on this
discrepancy, the licensee issued CR 02-07466.
10 CFR 50, Appendix B, Criterion XI, requires, in part, that adequate test
instrumentation is available and used. Contrary to this requirement, the licensee
specified non-conservative instrumentation ranges in the HPI quarterly surveillance test
procedure.
This finding screened as minor because the impact of the non-conservative test
instruments upon the readings was minimal. Although the failure to specify the
appropriate test instrumentation will be corrected, it constitutes a violation of minor
significance that is not subject to enforcement action in accordance with Section IV of the
SW Surveillance Test Does Not Use Worst Case Values
The inspectors identified a Green finding that is being treated as a Non-Cited Violation of
10 CFR Part 50, Appendix B, Criterion XI, Test Control. Specifically, the inspectors
identified that the service water train valve test did not appear to demonstrate that worst-
case post-accident conditions were bounded. Based on the teams questions, the
licensee issued CR 02-07781 which provided a detailed discussion of the shortcomings of
the procedure which included lack of trending, failure to declare the valve(s) inoperable,
etc.
10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that testing be
performed in accordance with written test procedures which incorporate the requirements
and acceptance limits contained in applicable design documents. Contrary to this
requirement, the service water train valve test did not appear to demonstrate that worst-
case post-accident conditions in design documents were bounded.
This finding was determined to be more than minor because it affected the mitigation
systems cornerstone objective. This finding screened as Green in the SDP phase 1,
since this issue was a testing deficiency that was confirmed not to result in loss of function
in accordance with GL 91-18 (Rev. 1). Because the finding was of very low safety
significance, and was captured in the licensees corrective action system as CR 02-07781,
this finding is being treated as an NCV consistent with Section VI.A.1 of the NRC
Enforcement Policy (Section 1R05.02) (NCV 50-346/2002-014-02a).
39
ECCS Sump Pump Test Acceptance Criteria
The inspectors identified a minor violation of 10 CFR Part 50, Appendix B, Criterion XI,
Test Control. USAR Section 3.6.2.7.1.14 states that the capacity of each ECCS room
sump pump is approximately 75 gpm. USAR Sections 3.6.2.7.1.8 and 3.6.2.7.1.10 state
that the submersible duplex sump pumps in rooms number 105, 113, and 115 have a total
capacity of approximately 150 gpm (75 gpm per pump). This is greater than the assumed
120 gpm DHR seal leakage. The teams review of the ECCS Sump Pump Flow Check,
DB-SP-04162 identified that its acceptance criterion was 50 gpm per pump. In addition,
the test does not verify whether water is pumped from sump to sump (via leaking check
valves) or to the intended tank. Based on the teams questions the licensee issued
CR 02-07741, which stated that this issue should be considered a restart issue.
10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that testing be
performed in accordance with written test procedures which incorporate the requirements
and acceptance limits contained in applicable design documents. Contrary to this
requirement, the acceptance criteria for the ECCS Sump Pump Flow Check was incorrect.
This finding screened as minor because the actual ECCS sump pump performance was
determined to be approximately 75 gpm. This was greater than the largest assumed
ECCS leakage in the drainage area. Although the failure to utilize an appropriate test
acceptance criterion will be corrected, it constitutes a violation of minor significance that is
not subject to enforcement action in accordance with Section IV of the USNRCs
Inadequate Service Water System Flow Balance Testing
The inspectors identified an unresolved item associated with the licensees SW system
flow balance testing procedure properly accounting for a number of required conditions.
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. The inspectors identified that this procedure did not establish flows to the safety-
related heat exchangers based on worst-case design basis conditions, such as degraded
service water pumps, lowest UHS level, highest resistance SW system lineup, system
resistance degradation, etc. 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.
Additionally, the inspectors noted that standard plant practice was to inspect the system at
the beginning of each refueling outage and to perform maintenance as required to remove
sediment, clean heat exchangers, and other system performance-improvement
maintenance activities prior to performing the flow balance. No analyses had been
performed of the as-found conditions. Therefore, the flow balances demonstrated the
systems operability only in the newly cleaned, groomed condition.
The licensee entered the issue into its corrective action program as CR 02-06064 and
screened the CR as requiring resolution prior to the mode in which the SW system was
required by plant TS (Mode 4). In order to resolve the issue, the licensee will need to
40
assess the impact of the as-found SW flow balance against the revised analysis being
performed by the licensee. This issue will remain unresolved pending the licensees
evaluation and the NRCs review (URI 50-346/2002-014-02b).
Inadequate Corrective Actions for Service Water Pump Discharge Check Valves
The inspectors identified a Green, Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XVI when licensee personnel failed to take proper corrective action to correctly
change the acceptance criterion for the inservice full flow test for the service water pump
discharge check valves to a proper value when it was determined to be non-conservative.
The ASME Code requires check valves to be tested to either the full open position or to
the position required to perform their safety function. Prior to 2002, licensee personnel
were testing the service water pump discharge check valves for their inservice test for the
forward flow direction with an acceptance criterion which required system flow to exceed
9300 gpm to pass the test. An internal audit by Quality Assurance personnel noted that
this acceptance criterion was non-conservative. As a result, the acceptance criterion was
changed to 10,000 gpm in February 2002.
The inspectors questioned licensee personnel about the basis for the acceptance criterion
since in the USAR a design flow of 10,250 gpm was specified. Licensee personnel
acknowledged the discrepancy and initiated condition report CR 02-07657 to address it.
The explanation was that when licensee personnel made the initial change to the
acceptance criterion for flow, they had not taken all available information into account
when choosing the new setpoint. The inspectors determined that the failure to choose a
proper acceptance criterion for the inservice full flow test for the service water pump
discharge check valves could lead licensee personnel to accept test results which would
not ensure that the check valve was capable of passing its safety function flow.
10 CFR Part 50, Appendix B, Criterion XVI requires in part that measures shall be
established to ensure that conditions adverse to quality, such as non-conformances were
promptly identified and corrected. Contrary to the above, in February 2002, licensee
personnel did not properly correct the acceptance criterion for the service water pump
discharge check valves inservice full flow test when they first recognized it was not
correct.
This finding was more than minor because it could affect the mitigating systems
cornerstone objective of ensuring the capability of systems that respond to initiating
events to prevent undesirable consequences attributable to poor maintenance procedure
quality. Using the significance determination process, the safety significance was
determined to be very low (Green) because the finding did not screen as risk significant
due to a seismic, fire, flooding, or severe weather event. This violation is being treated as
a Non-Cited Violation (NCV 05000346/2002-014-03d) because of the very low safety
significance of this condition and because licensee personnel entered this finding in the
corrective action program as CR 02-07657.
41
4OA6 Meetings
Exit Meeting Summary
The NRC inspectors presented the results of this inspection during exit meetings with
Mr. L. Myers and other members of licensee management on November 13, 2002. The
licensee acknowledged the findings presented. Inspectors asked the licensee whether
any materials examined during the inspection should be considered proprietary. No
proprietary information was identified.
42
KEY POINTS OF CONTACT
Davis-Besse
L. Myers, Chief Operating Officer
R. Fast, Plant Manager
T. Chambers, Work Week Manager
J. Powers, Engineering Director
P. Roberts, Maintenance Manager
M. Roder, Operations Manager
J. Rogers, Plant Engineering Manager
R. Slyker, Licensing Staff Engineer
H. Stevens, Quality Assurance Manager
G. Wolf, Licensing Staff Engineer
Nuclear Regulatory Commission
J. Grobe, Chairman, Davis-Besse Oversight Panel
C. Lipa, Chief, Reactor Projects Branch 4
S. Thomas, Senior Resident Inspector
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-346/02-14-01a NCV Lack of a design basis analysis for containment isolation
valve backup air supplies
50-346/02-14-01b NCV Inadequate blowdown provisions for CAC backup air
50-346/02-14-01c URI Failure to perform comprehensive Moderate Energy Line
Break analysis
50-346/02-14-01d URI Lifting of Service Water Relief Valves
50-346/02-14-01e URI Inadequate SW pump room temperature analysis
50-346/02-14-01f URI Inadequate SW pump room steam line break analysis
50-346/02-14-01g URI Inadequate cable ampacity analysis
50-346/02-14-01h URI Inadequate flooding protection for the SW pump house
50-346/02-14-01i NCV Non-conservative TS value for 90 percent undervoltage
relays
43
50-346/02-14-01j URI Poor quality calculation for 90 percent undervoltage relays
50-346/02-14-01k NCV Non-conservative relay setpoint calculation for the 59
percent undervoltage relays
50-346/02-14-01l URI Inadequate calculations for control room operator dose
(GDC-19) and offsite dose (10 CFR Part 100) related to HPI
pump minimum flow valves
50-346/02-14-01m URI Other GDC-19 and 10 CFR Part 100 issues
50-346/02-14-01n URI HPI Pump Operation Under Long Term Minimum Flow
50-346/02-14-01o URI Some small break LOCA sizes not analyzed
50-346/02-14-01p URI Inadequate SW flow analysis
50-346/02-14-01q URI Inadequate SW thermal analysis
50-346/02-14-01r URI Inadequate UHS inventory analysis
50-346/02-14-01s URI No Valid Service Water Pump Net Positive Suction Head
Analysis
50-346/02-14-01t URI SW source temperature analysis for AFW
50-346/02-14-01u URI Inadequate short circuit calculations
50-346/02-14-01v NCV No analytical basis for the setpoint to swap service water
system discharge path
50-346/02-14-02a NCV SW surveillance test did not use worst case values
50-346/02-14-02b URI Inadequate SW system flow balance testing
50-346/02-14-03a URI Inappropriate SW pump curve allowable degradation
50-346/02-14-03b URI Repetitive failures of SW relief valves
50-346/02-14-03c URI Non-Conservative Difference in UHS Temperature
Measurements
50-346/02-14-03d NCV Inadequate corrective actions related to SW pump discharge
check valve acceptance criteria
50-346/02-14-03e URI Non-conservative containment air cooler mechanical stress
analysis
44
50-346/02-14-04 NCV Failure to perform TS surveillance requirement for HPI pump
following maintenance
50-346/02-14-05 URI Question regarding the definition of a passive failure
50-346/02-14-06 URI Question regarding licensee compliance with code relief
valve requirements
Closed
None
Discussed
None
45
LIST OF ACRONYMS USED
AC Alternating Current
ASME American Society of Mechanical Engineers
B&W Babcock and Wilcox
BWST Borated Water Storage Tank
CAC Containment Air Cooler
CFR Code of Federal Regulations
CR Condition Report
CST Condensate Storage Tank
CTMU Cooling Tower Makeup
ECCS Emergency Core Cooling System
GDC General Design Criteria
GL Generic Letter
gpm Gallon Per Minute
HPI High Pressure Injection
LER Licensee Event Report
LIR Latent Issues Review
LOCA Loss of Coolant Accident
LOOP Loss of Off-Site Power
LPI Low Pressure Injection
MCC Motor Control Center
MELB Moderate Energy Line Break
M&TE Measurement and Testing Instrumentation
MOV Motor Operated Valve
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
PCAQR Potential Conditions Adverse to Quality Report
PDR Public Document Room
psig pounds per square inch gage
PT Potential Transformer
SBLOCA Small Break Loss of Coolant Accident
SDP Significance Determination Process
SSCs Systems, Structures and Components
SSDPC Safety System Design and Performance Capability
SFP Spent Fuel Pool
TS Technical Specifications
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
USNRC United States Nuclear Regulatory Commission
VAC Volts Alternating Current
VDC Volts Direct Current
46
LIST OF DOCUMENTS REVIEWED
The following is a list of licensee documents reviewed during the inspection, including documents
prepared by others for the licensee. Inclusion on this list does not imply that NRC inspectors
reviewed the documents in their entirety, but that selected sections or portions of the documents
were evaluated as part of the overall inspection effort. Inclusion on this list does not imply NRC
acceptance of the document, unless specifically stated in the inspection report.
Calculations
C-EE-003.02-012 Protective Relay Setpoint for Transformer BD (Bkr Revision 2
HBBD)
C-EE-004.01-001 Protective Relay Setpoint for Service Water Pump Revision 4
Motor 1-1 (AC107)
C-EE-004.01-002 Protective Relay Setpoint for Service Water Pump Revision 4
Motor 1-2 (AD107)
C-EE-004.01-003 Protective Relay Setpoint for Service Water Pump Revision 2
Motor 1-3 (AC 109)
C-EE-004.01-004 Protective Relay Setpoint for Service Water Pump Revision 2
Motor 1-3 (AD109)
C-EE-004.01-009 Protective Relay Setpoint Calculation for High Pressure Revision 2
Injection Pump Motor 1-1 (AC111)
C-EE-004.01-010 Protective Relay Setpoint Calculation for High Pressure Revision 1
Injection Pump Motor 1-2 (AD111)
C-EE-004.01-030 Protective Relay Setpoint Calculation for 4.16 kV Revision 3
Feeder Ground Relays
C-EE-004.01-031 Protective Relay Setpoint Calculation for Ground Fault Revision 3
Protection - 4.16 kV Buses C1 & C2
C-EE-004.01-032 Protective Relay Setpoint for Incoming to Transformer Revision 2
DF1-1 (Bkr AD1DF11)
C-EE-004.01-033 Protective Relay Setpoint for Incoming to Transformer Revision 4
DF1-2 (Bkr AD1DF12)
C-EE-004.01-038 Protective Relay Setpoint Calculation for Incoming Revision 4
Transformer CE1-1
C-EE-004.01-039 Protective Relay Setpoint Calculation for Incoming to Revision 2
Transformer CE1-2 (Bkr AC1CE12)
C-EE-004.01-043 Protective Relay Setpoints for Ground Fault Protection Revision 3
- 4.16 kV Buses D1 & D2
47
C-EE-004.01-046 4.16 kV Short Circuit Calculations July 8, 1991
C-EE-004.01-047 Protective Relay Setpoint Calculation for Phase Fault Revision 2
Protection - 4.16 kV Buses C1 & C2
C-EE-004.01-048 Protective Relay Setpoint Calculation for Phase Fault Revision 3
Protection - 4.16 kV Buses D1 & D2
C-EE-004.01-049 4.16 Kv Bus Degraded Voltage (90 percent November 7,
Undervoltage) Relay Setpoint 2001
C-EE-004.01-050 4.16 kV Bus Motor Residual Voltage Calculation Revision 0
C-EE-004.01-051 59 percent Undervoltage (Loss of Station Power) Revision 3
Setpoint Calculation
C-EE-004.01-055 Motor Damage Data Extrapolation for Schulz HPI Pump Revision 0
Motor
C-EE-006.01-026 Voltage Drop for GL 89-10 Valve Operators November 9,
1992
C-EE-015.03-003 Steady State Analysis - Electrical Load Management Revision 23
System ELMS
C-EE-015.7-001 Power Cable Ampacity May 7, 1992
Calculation No. Calculate Temperature -vs- Time for Loss of Ventilation Revision 1
24.001 in Room 323, 324, and 325
C-NSA-011.01- Allowable Service Water Flow Diversion During Cold Revision 1
003 Weather
C-NSA-016.04- Allowed CCW System Essential Header Integrated Revision 0
007 Leakage
67.005 Service Water Pump Room Ventilation System Revision 2
Capacity
67.004 Service Water Pump Maximum Allowable Outside Air Revision 1
Temperature to Dissipate Entire Room Heat Load with
One Ventilation Fan C99 1, 2, 3, or 4 Operable
Calculation Maximum Allowable Service Water Temperature w/ Revision 4
C-NSA-032.02- Inoperable ECCS Room Cooler
003
Calculation HPI Pump Acceptance Criteria Revision 4
C-NSA-52.01-003
Calculation Maximum Allowable Leak Rate through HP31/32 or Revision 0
C-NSA-52.01-012 ECCS Systems
48
Calculation 25.006 ECCS Rooms - Cooling System Revision 1
Calculation 35.25 Dose Rate from BWST Revision 0
Calculation 36.28 ECCS - Pump Seal Failure Revision 0
C-NSA-011.01- Service Water Pump Startup/Coastdown Time for CAC Revision 0
004 Water Hammer Input
C-NSA-011.01- Replacement of SW1356, SW1357 and SW1358 Revision 0
008
SAROS/92-02 Identification of Flood Initiating Events for the Davis-
Besse Individual Plant Examination
C-NSA-011.01- Service Water Discharge Through SW 2929 February 6,
007 2001
C-CSS-011.01- Service Water Return Line to Forebay from SW 2929 December 19,
170 2000
C-NSA-085.00- Auxiliary Steam Blowdown in the Intake Structure October 30,
002 1993
12501-M-001 UHS Thermal Performance for Pond Water Area and July 14, 1998
Volume to Station 10+00
H&H-1 Thermal Performance Analysis for Ultimate Heat Sink December 26,
(UHS) Pond 1995
NOPS99-464 UHS Silting Study October 20,
1999
C-NSA 011.01-010 Maximum Service Water Pressure to AFW System April 2, 2002
C-NSA-60.05-008 Containment Post LOCA Response with Variable SW October 20,
Temperature 2001
C-NSA-000.00- PROTO-FLO Service Water System Model December 19,
017 2001
C-NSA-011.01- Allowable Service Water Flow Diversion During Cold March 21,
003 Weather 1997
C-CSS-011.01- Seismic Evaluation For Control Appurtenances On
172 Valves SW 1356, SW 1357, and SW 1358
C-ICE-011-01-001 Service Water Pump Discharge Pressure Switches September 2,
1986
C-NSA-60.05-007 CAC Heat Duty At Elevated SW Inlet Temperatures August 10,
1998
12501-M-003 ECCS Room Temperatures with Initial 90F Forebay May 27, 1999
49
67.005 Service Water Pump Room Ventilation System August 30,
Capacity 2002
67.007 Service Water Pump Room Ventilation System - August 30,
Pressure Drop 2002
C-CSS-11.01-169 Containment Air Cooler Evaluation For Generic Letter October 1,
96-06 1997
C-CSS-011.01- Structural Analysis of Service Water Strainer Internals November 30,
171 2000
12501-M-00004 UHS Pond Performance Analysis - Max Evaporation - March 15,
Silt 2001
Condition Reports Reviewed
CR 02-02658 Inadequate Ventilation for Rooms 323, 324, 325 June 18, 2002
CR 02-06120 SHRR - Testing Review - Maintenance Burden September 18,
Associated with Undervoltage Relays 2002
CR 02-06243 SSDPC Issue - Calculation Approved Prior to Receipt September 19,
of LAR 2002
CR 02-06428 SSDPC - Review of Calculation C-EE-004.01-051, 59 September 22,
percent Undervoltage, Revision 3 2002
CR 02-06430 SSDPC - Review of Calculation C-EE-004.01-049, September 21,
Revision 10, 90 percent Degraded Voltage 2002
CR 2000-2428 No title October 9,
2000
CR 01-0005 SW2930 Stroke Time Increase January 1,
2001
CR 01-0053 Screenwash to Circ. Water Pump Chlorine Diffuser January 8,
Pipe Rupture 2001
CR 01-0059 Water Treatment Building Sump Pumps Removed January 9,
2001
CR 01-0340 Degrading Trend of Service Water Butterfly Manual February 5,
Isolation Valves 2001
CR 01-0350 Inadequate Design of Service Water Header Relief February 5,
Valves 2001
CR 01-0429 Service Water Pump 1 has Rain Water Leaking on Its February 14,
Motor 2001
50
CR 01-0459 HPI Pump 1 D/P Trending Down February 16,
2001
CR 01-0512 Traveling Screen #3- Failed to Start February 21,
2001
CR 01-0676 Tubing Configuration on Instrumentation March 8, 2001
CR 01-0679 SW 2945 Bent Position Indicator March 8, 2001
CR 01-0842 DB-SC-4146, Quarterly Functional of RE8434 Failed March 24,
Low Flow Alarm Function 2001
CR 01-0871 HPI 2 AC Oil Pump Motor Bearing Degradation March 17,
2001
CR 01-0934 Missing P111-B Fastener April 2, 2001
CR 01-1002 Unexpected Service Water Motor Temperature April 9, 2001
Increase
CR 01-1267 ECCS Cooler Operability Justification May 14, 2001
CR 01-1716 Lack of Service Water Chlorination July 10, 2001
CR 01-1724 Service Water Pump 3 Test Data Problems July 10, 2001
CR 01-1787 M&TE Accuracies in Six I&C Data Packages Outside July 18, 2001
Calculation Allowed Accuracies
CR 01-1788 M&TE Used in Two Calibrations Did not Meet July 18, 2001
Applicable Accuracy Requirements
CR 01-1789 Design Database Errors for Service Water Pump July 18, 2001
Discharge Pressure Switches
CR 01-2532 Testing of Service Water Pump Cables September 26,
2001
CR 01-2763 P58-1 & P58-2 Bolting Non-Compliance with ASME October 18,
Code 2001
CR 01-3115 HPI Recirc Flow November 20,
2001
CR 01-3261 Service Water Pump 1 Motor Identified Problems December 6,
2001
CR 01-3292 SW-1356 Closing Stroke Time Increase December 10,
2001
CR 02-00754 Scheduling Conflict on HPI Pumps 1 and 2 February 23,
2002
51
CR 02-00899 Improvements Required in DB-OP-06904 February 25,
2002
CR 02-01058 Mod 99-0039 Calc Basis Determination Concerns March 5, 2002
CR 02-01419 Chlorination of the Service Water System March 29,
2002
CR 02-01450 Modification 99-0039 Does not Adequately Address April 3, 2002
New Valve Design
CR 02-01589 Some Floor Drains on East Side of CTMT 565 Level April 18, 2002
are Plugged
CR 02-01848 Inspection Plan IP-M-029 Extent of Condition Area 565- May 2, 2002
3P
CR 02-01937 Inspection Plan IP-M-029 Containment Area Inspection May 6, 2002
Findings
CR 02-01998 Inspection Plan IP-M-029 Area 565-1P, Room 216-East May 13, 2002
D-ring, Interior Findings
CR 02-02016 Pipe Support 33A-HCB-2-H13 Removal/Reinstallation May 13, 2002
CR 02-02038 Inspection Plan IP-M-028 Findings Component HP57 May 14, 2002
CR 02-02040 Inspection Plan IP-M-028 Findings Component HP56 May 14, 2002
CR 02-02041 Inspection Plan IP-M-028 Findings Component HP48 May 14, 2002
CR 02-02056 Post Loca Boron Precipitation Design Issues May 15, 2002
CR 02-02088 Inspection Plan IP-M-029 Area 585-5E Findings May 15, 2002
CR 02-02294 Degradation of Containment Air Cooler #1 Due to Boric May 28, 2002
Acid Corrosion
CR 02-02391 Intake Chlorine Pump Will Not Maintain Its Prime June 2, 2002
CR 02-02394 Degradation of Service Water Piping in Containment June 3, 2002
CR 02-02432 SW Pump 3 Flowrate Limited by Strainer Blowdown June 5, 2002
CR 02-02478 PR/PSA: Improvements in the CCW System Need to June 7, 2002
be Considered
CR 02-02749 Boric Acid on Equipment in the Aux Building June 24, 2002
CR 02-02764 Service Water Piping Inside Containment Unqualified June 24, 2002
Paint
CR 02-02943 Containment Air Cooler Boric Acid Corrosion July 2, 2002
52
CR 02-03028 HPI Stop Check Valves May Not be Oriented Correctly July 8, 2002
CR 02-03224 Boric Acid on HP4BB Due to Body to Bonnet Leak July 15, 2002
CR 02-03235 SW1434 Did Not Respond as Expected During Post July 15, 2002
Maintenance Testing
CR 02-03256 Degradation of Circulation Water Chlorination Supply July 16, 2002
Lines
CR 02-03383 Problems with HP 48 July 22, 2002
CR 02-03655 High Pressure Injection Boron Corrosion August 8, 2002
CR 02-03972 Degradation of Service Water Supply Piping to August 10,
Auxiliary Feed Water Pumps 2002
CR 02-04173 SHRR Walkdown of HPI Train 1, Corrosion Issues August 10,
2002
CR 02-04419 Biofouling of Containment Air Cooler E37-3 August 16,
2002
CR 02-04697 MCC Bucket for BF1281 August 21,
2002
CR 02-04760 BF 1281 Loose Terminal August 21,
2002
CR 02-05011 SHRR Walkdown of HPI Train 2: Insulation Issues August 16,
2002
CR 02-05528 LIR-SW:ECCS Room Cooler Material Deficiencies August 14,
2002
CR 02-05563 Nozzle Flexibility Assumed in Calculation 65A/B (Part September 5,
II) is Non-Conservative 2002
CR 00-1779 No test to verify flow from Service Water System to July 13, 2000
Component Cooling Water System for Makeup
CR 01-2928 Intake Structure Flooding Issue with Pumps Removed November 1,
2001
CR 02-04514 Inadequate Interface Between the IST Program and August 19,
Design Basis Information 2002
CR 02-05784 Service Water Strainer Design Flow
CR 02-06370 SSDPC: ECCS Pump Room Heat Load Calculation is September 20,
Non-conservative 2002
CR 02-06388 SSDPC: Issues with DB-OP-06261 Guidance for September 20,
Inoperable ECCS Room Coolers 2002
53
CR 02-07232 LIR CCW - Non-conservative CCW Leakage October 2,
Calculation 2002
CR 02-07378 LIR CCW - Service Water to CCW Makeup Line Flow October 3,
Verification Test Discrepancies 2002
CR 00-0096 Failure to Perform Off-site AC Sources Line Up as January 17,
Required by Tech Spec 2000
CR 00-4035 Closing Springs Failed to Charge December 18,
2000
CR 00-4113 ACD2 Would Not Close When Placing #3 CCW in December 24,
Service As 1 2000
CR 00-4116 ACD3 Breaker Closed When the Springs Discharged December 24,
While Racking Out 2000
CR 01-0043 Maintenance Rule (a)(1) Corrective Action Plan for February 4,
Breakers may Need Re-evaluating 2001
CR 01-0138 Some Inhouse Refurb Breakers Have Different Stock January 2,
Code Arcing Contact Mt 2001
CR 01-0413 Circuit Breaker ACD3 Did Not Pass Post-Maintenance February 12,
Checks 2001
CR 01-0823 AC113 Failed Resistance Checks per Standing Order March 22,
99-09 2001
CR 01-1049 Breaker Could Not Be Tested per DB-OP-01000 April 21, 2001
CR 01-1104 C1 Low Voltage Alarms April 22, 2001
CR 01-1721 DC Bus 1 Ground July 10, 2001
CR 01-2120 AC113 Thermography Noted Warm Relay Not Noted in August 16,
Other Breakers 2001
CR 01-2158 High Voltage Switchgear Room Temperature Concerns August 21,
2001
CR 02-00817 Inadequate Clearance on AD 111 Trip Plunger February 26,
2002
CR 02-01161 59 percent UV Relay Failure May 9, 2002
CR 02-01526 Unexpected AC Transformer Lockout April 11, 2002
CR 02-01550 Unexpected AC Transformer Lockout April 15, 2002
CR 02-02658 Inadequate Ventilation for Rooms 323, 324, 325 June 18, 2002
CR 02-03845 Loose Termination in AC 113 August 8, 2002
54
CR 02-04999 SHRR - Testing Review for 4.16 kV System August 26,
2002
CR 02-05000 SHRR - Testing Review for 4.16 kV System August 26,
2002
CR 02-03331 Noteworthy Items from Test Control Program Self July 19, 2002
Assessment
CR 02-04514 Inadequate Interface Between the IST Program and August 19,
Design Basis Information 2002
CR 02-05369 LIR of Inadequate Service Water System Flow Balance September 2,
Procedure 2002
CR 00-2478 Service Water Relief Valves Lifted and Failed to Reseat October 13,
2000
CR 01-2182 Bench Testing SW 3963 Relief Valve During 13RFO August 23,
2001
CR 01-2407 #1 Service Water Pump Strainer Leak September 18,
2001
CR 01-0350 Inadequate Design Of Service Water Header Relief February 5,
Valves 2001
CR 02-04514 Inadequate Interface Between The IST Program And August 19,
Design Basis Information 2002
CR 02-05372 LIR of Service Water System Design Flow Rates to the September 2,
ECCS Room Coolers 2002
CR 02-05640 No Design Basis/Flow verification Testing of SW Flow September 7,
to AFW System 2002
CR 02-05923 No Design Basis For Service Water Pump NPSH September 13,
Available 2002
CR 02-05966 LIR-SW-EQ Walkdown August 30,
2002
CR 02-06139 SSDPC Self Assessment Identified Seismic II/I September 18,
Concern for CTMU Pumps 2002
CR 02-06177 CREVS Calculation Not Updated To Address 90F September 18,
Temperature Increase 2002
CR 02-06297 Cooling Tower Makeup and Service Water Pumps September 19,
2002
CR 02-06436 Collective Significance of Issues From SW Self September 21,
Assessment and LIR 2002
55
CR 02-06438 Evaluate Worst Case (Highest Flow) for the Service September 21,
Water System 2002
CR 02-06546 Design Basis Validation Open Items - Containment Air September 23,
Coolers 2002
CR 02-06791 ECCS Room Cooler Common Outlet Isolation Valve September 26,
2002
CR 02-07004 Heat Added by SW Pumps Not Accounted For In September 29,
Containment Response Analysis 2002
Condition Reports Written As a Result of Inspection
CR 02-06571 Calculation Inadequacy September 24,
2002
CR 02-06737 SSDPC - Calc C-EE-004.01-051 Uncertainty Treatment September 25,
2002
CR 02-06837 Inadequate Supervisors Review of CR 02-06302 September 27,
2002
CR 02-06893 Unevaluated Temperature Increase Because of LAR September 24,96-008 2002
CR 02-07633 SSDPC/Uncertainties Treatment in C-EE-004.01-049 October 8,
R10 Is Non-Conservative 2002
CR 02-07646 SSDPC - Calc C-EE-004.01-051 Temperature Variation October 8,
Not Considered 2002
CR 02-07766 Non-Conservative Value for 90 percent Volt in Table October 9,
3.3-4 2002
CR 02-06618 Appendix R Disconnect Switch Cabinet Found Open September 24,
During NRC Walkdown 2002
CR 02-06674 HP 209 Was Found Out of Expected Position September 24,
2002
CR 02-06726 Leakage Collection Devices and Their Usage in RRA September 25,
Clarification 2002
CR 02-06749 NRC Inspection of Top of BWST Tank September 26,
2002
CR 02-06750 NRC Walkdown of the BWST September 26,
2002
56
CR 02-06571 Calculation Inadequacy September 24,
2002
CR 02-06855 NRC Walkdown of HPI in Containment September 27,
2002
CR 02-06801 Corrosion in Room 115 September 26,
2002
CR 02-07611 NRC Walkdown of HPI October 7,
2002
CR 02-07643 Improvements to DB-OP-02003, For HPI Flow Alarm October 8,
Response 2002
CR 02-07753 Failure to Require TS 4.5.2.H HPI Flow Testing September 9,
Following Maintenance 2002
CR 02-07779 Cable Seal for CCW Rad Monitor September 24,
2002
CR 02-07791 NRC Question On HPI System Modifications October 10,
2002
CR 02-07475 Instrument Inaccuracy for Air Temperature Not October 4,
Considered in Service Water Ventilation Calculation 2002
CR 02-07657 Service Water Pump Design Flow Rate in Question October 8,
2002
CR 02-07762 Questions on Mounting for CCW Heat Exchangers October 9,
2002
CR 02-07764 Calculation/Test May Not Consider Actual Plant October 9,
Conditions 2002
CR 02-07770 Security Equipment October 9,
2002
CR 02-07802 Calculational Basis for PSH 2929 and PSH 2930 October 10,
setpoint could not be found 2002
CR 02-07820 Bent Anchor Bolt on the CCW Ht Exchanger #1 Sliding October 10,
Connection 2002
CR 02-06615 Work Area in MPR #1 Unsatisfactory September 24,
2002
CR 02-06701 Post Loca Dose from BWST with Inadvertent September 25,
HP31/HP32 Failure 2002
CR 02-06702 Potential for Inadequate HPI Pump Minimum September 25,
Recirculation Following LOCA 2002
57
CR 02-06571 Calculation Inadequacy September 24,
2002
CR 02-06863 Extent of Condition of CR 02-05369 September 26,
2002
CR 02-06996 HPI Flow Test Acceptance Criteria Versus T.S. 4.5.2.h September 28,
2002
CR 02-07338 High Pressure Injection System Description (SD-038) October 2,
2002
CR 02-07466 HPI Pumps Test Procedures Deficiency with Required October 4,
Test Instrumentation Accuracy 2002
CR 02-07468 SSDP: Unverified Calculations in SW Qtrly Tests October 4,
DB-PF-03017, -03023, -03030 2002
CR 02-07684 HPI Pump Capability to Run at Minimum Flow October 8,
2002
CR 02-07701 Control Room Operator Dose Due to ECCS Leakage October 9,
Post-LOCA 2002
CR 02-07713 Post Accident Control Room Dose Calculations October 9,
2002
CR 02-07741 Acceptance Criteria of ECCS Sump Test below USAR October 9,
Assumption 2002
CR 02-07757 Environmental Conditions for Decay Heat Pump Seal October 4,
Leak Not Evaluated 2002
CR 02-07777 DHR System Needs Critical Crack Evaluation October 9,
2002
CR 02-07781 Weaknesses in Testing SW Outlet Valves to CAC October 9,
Coolers (SW - 1356, 1357, 1358) 2002
CR 02-05986 UHS Water Inventory Analysis Does Not Consider All September 14,
Water Losses 2002
CR 02-06064 SW Flow Balance Margins and Need For Additional September 15,
Recorded Data 2002
CR 02-06332 Potential Weaknesses Service Water Single Failure September 20,
Analysis 2002
CR 02-06333 Concerns With Calculation C-NSA-011.01-001 September 20,
2002
CR 02-06336 UHS Analyses Do Not Document That Worst-Case September 20,
Conditions are Enveloped 1992
58
CR 02-06571 Calculation Inadequacy September 24,
2002
CR 02-06344 Design Basis Concerns Regarding Service Water September 20,
Strainer Backwash Function 2002
CR 02-06370 ECCS Pump Room Heat Load Calculation Is Non- September 20,
Conservative 2002
CR 02-06379 ECCS Pump Room Heat Load Calculation Is Non- September 20,
Conservative 2002
CR 02-06860 Review of the Need for Relief Valves for Several Heat September 27,
Exchangers 2002
CR 02-07188 Non-Conservative Assumptions in Calc 76.005, SW October 2,
Ventilation Capacity 2002
CR 02-07286 Enhance RA-EP-02880, Internal Flooding Procedure October 2,
2002
CR 02-07569 Station Sump Pump Check Valves Not Tested October 7,
2002
CR 02-07427 Drainage Systems - Aux Building Dwg 173, Note 8 October 4,
Requires Clarification 2002
CR 02-07692 USAR Section 9.2.5.1 Concerning Placing SWP(s) Into October 8,
Operation After 13 Hours 2002
CR 02-07714 Lack of Procedures to Isolate SWP Room Equipment October 8,
During Flooding 2002
CR 02-07716 Wrong instrument May Be Used To Verify Ultimate October 9,
Heat Sink Temperature 2002
CR 02-07745 No Allowance for Flow Diversion in Calc C-NSA-00.00- October 9,
17 2002
CR 02-07746 Building Drainage Failure Criteria Question October 9,
2002
CR 02-07750 Basis For Air Operated Containment Isolation Valve Air October 9,
Volume Tanks 2002
CR 02-07752 NRC Inspection of SW, Transient Spikes in CTMT SW October 9,
Pressure Lines 2002
CR 02-07760 Flood Analysis Discrepancies in the Service Water Pipe October 9,
Tunnel and Valve Rooms 2002
CR 02-06108 AFW Pumps and H2 Dilution Blower Not Evaluated for September 17,
Maximum SW Temperature 2002
59
CR 02-06571 Calculation Inadequacy September 24,
2002
CR 02-07781 Weaknesses In Testing SW Outlet Valves to CAC October 9,
Coolers 2002
Drawings
E-1 SH. 1, 2, 3 AC Electrical System One Line Diagrams Revisions 21,
31, 2
E-3 4.16 kV Metering and Relaying One Line Diagram Revision 30
E-39 B SH. 11 Misc Control Schemes - Medium Voltage SWGR Revision 3
Rooms Lighting
E-52B SH. 63 HPI Pump AC Lube Oil Pump Revision 3
E-52B SH. 64 HPI Pump DC Lube Oil Pump Revision 5
DWG 033A High Pressure Injection Revision 3
DWG 041A Service Water Pumps and Secondary Service Water Revision 23
DWG 041B Service Water Pumps and Secondary Service Water Revision 54
DWG 041C Service Water Pumps and Secondary Service Water Revision 25
DWG OS-020 Operational Schematic Service Water System Revision 55
DWG 030A Reactor Coolant System Revision 52
DWG 363 Sprinkler System SW Pump Rm 52 Intake Structure Revision 2
Elev. 576'-0"
Operational High Pressure Injection System Revision 19
Schematic OS-003
P&ID M-033A High Pressure Injection Revision 30
Goulds Pumps Backup Service Water Pump, October 6,
Drawing Q307249 1981
Goulds Pumps Service Water Pumps September 18,
Drawing 1992
N300214401
Goulds Pumps Dilution Pump P180 November 1,
Drawing 301231 1973
Goulds Pumps Dilution Pump August 9, 1973
Drawing D-1375
60
P&ID M-041A Service Water Pumps and Secondary Service Water Revision 23
System
P&ID M-041B Primary Service Water System Revision 54
P&ID M-041C Service Water System for Containment Air Coolers Revision 25
P&ID M-006D Auxiliary Feedwater System Revision 47
Piping System Intake Structure Revision 17
Composite M-
251F
Goulds Pumps Service Water Pump P3-1 Pump Curves March 15,
Drawing T74-082 1974
Goulds Pumps Service Water Pump P3-2 Pump Curves March 15,
Drawing T74-084 1974
Goulds Pumps Service Water Pump P3-3 Pump Curves March 2, 1974
Drawing T74-090
C-1595 Penetration Schedule Revision 7
Equipment Intake Structure & Water Treatment Building Plans Revision 29
Locations Dwg
135
M-473-A Low Density Silicone Foam Penetration Seal Typical Revision 1
Details
M-473-B High Density Silicone Elastomer Penetration Seal Revision 0
Typical Details
M-473-C Grout or Ceramic Fiber and Caulk Penetration Seal Revision 1
Typical Details
A-2110 Barrier Penetration Drawing Barrier Identification Plan Revision 0
Rm 52 Intake Structure Elev. 576'-0"
A-2112 Barrier Penetration Drawing Barrier Identification Plan Revision 1
Rm 53 Intake Structure Elev. 566'-0"
A-2111 Barrier Penetration Drawing Barrier Identification Plan Revision 0
Rm 52-E Intake Structure
C-1594 Barrier Functional List Revision 2
Procedures
DB-OP-02001 Electrical Distribution Alarm Panel 1 Alarm Procedure Revision 3
61
DB-OP-02103 Transformer AC Alarm Panel 103 Annunciators Revision 1
DB-OP-02104 Transformer BD Alarm Panel 104 Annunciators Revision 1
DB-OP-02521 Loss of AC Bus Power Sources Revision 2
DB-OP-06315 4160 Volt Switching Procedure Revision 2
DB-OP-06316 Diesel Generator Operating Procedure Revision 2
DB-OP-06334 Station Blackout Diesel Generator Operating Procedure Revision 3
DB-OP-06904 Shutdown Operations Revision 6
DB-OP-02000 RPS, SFAS, SFRCS Trip, or SG Tube Rupture Revision 6
DB-OP-00008 Operation and Control of Locked Valves Revision 1
DB-OP-02511 Loss of Service Water Pumps/Systems Revision 2
DB-OP-03007 Miscellaneous Instruments Daily Check Revision 3
DB-OP-06016 Containment Air Cooling System Procedure Revision 4
DB-OP-06261 Service Water System Operating Procedure Revision 2
DB-OP-06262 Component Cooling Water System Operating Revision 2
Procedure
DB-OP-06904 Shutdown Operations Revision 6
DB-OP-06913 Seasonal Plant Preparation Checklist Revision 4
DB-MM-03006 Inspection of Tech Spec Hydraulic Snubbers Revision 1
DB-PF-03017 Service Water Pump 1 Quarterly Test Revision 2
DB-PF-03020 Service Water Train 1 Quarterly Valve Test Revision 4
DB-PF-03023 Service Water Pump 2 Quarterly Test Revision 2
DB-PF-03026 Service Water Manual Valve Test Revision 0
DB-PF-03027 Service Water Train 2 Quarterly Valve Test Revision 4
DB-PF-03100 Component Cooling Water Valve Test Revision 4
DB-PF-03154 AFW Train 1 Valve Testing Revision 4
DB-PF-03163 AFW Train 2 Valve Testing Revision 4
DB-PF-03205 ECCS Train 1 Valve Test Revision 4
DB-PF-03206 ECCS Train 2 Valve Test Revision 3
DB-PF-03811 Miscellaneous Valves Test Revision 6
62
DB-PF-03812 Miscellaneous Valves Cold Shutdown and Refueling Revision 6
Test
DB-PF-03813 Miscellaneous Augmented Valve Test Revision 0
DB-PF-04704 Performance Test - Component Cooling Water Heat Revision 4
Exchanger 1
DB-PF-04705 Performance Test - Component Cooling Water Heat Revision 3
Exchanger 2
DB-PF-04706 Performance Test - Component Cooling Water Heat Revision 3
Exchanger 3
DB-PF-04729 Containment Air Cooler Monitoring Test Revision 6
DB-PF-04736 ECCS Room Cooler Monitoring Test Revision 0
DB-SC-03114 SFAS Integrated Time Response Test Revision 1
DB-SC-03122 SFAS Components Test Revision 1
DB-SP-03018 Service Water Pump 1 Refueling Test Revision 2
DB-SP-03019 Service Water Valve Verification Monthly Test Train 1 Revision 1
DB-SP-03024 Service Water Pump 2 Refueling Test Revision 2
DB-SP-03026 Service Water Valve Verification Monthly Test Train 2 Revision 1
DB-SP-03032 Service Water Pump 3 Refueling Test Revision 2
DB-SS-03041 Control Room Emergency Ventilation System Train 1 Revision 3
Monthly Test
DB-SS-03042 Control Room Emergency Ventilation System Train 2 Revision 3
Monthly Test
DB-SS-04021 Backup Service Water Pump Quarterly Test Revision 2
DB-SC-03020 13.8 KV System Bus A & B Transfer Test Revision 3
DB-SC-03022 Off-site AC Sources Bus Transfer Test Revision 2
DB-SC-03023 Off-site AC Sources Lined Up and Available Revision 3
DB-SC-03041 On-site AC Bus Sources Lined Up, Available and Revision 2
Isolated (Modes 1, 2, 3, and 4)
DB-SC-03042 On-site AC Bus Sources Lined Up and Available Revision 2
(Modes 5 and 6)
DB-SC-04052 4160V System Transfer and Lockout Test - Buses D1 Revision 1
and D2
63
DB-SC-04053 4160V System Transfer and Lockout Test - Buses C1 Revision 1
and C2
DB-SC-10000 Main Transformer Backfeed Test Revision 0
Emergency RPS, SFAS, SFRCS Trip, OR SG Tube Rupture Revision 06
Procedure
DB-OP-02000
Systems ECCS Sump Pump Flow Check Revision 01
Procedure
DB-SP-04162
Surveillance Test ECCS Integrated Train 1 Leakage Rate Test Revision 00
Procedure
DB-PF-03011
Surveillance Test ECCS Integrated Train 2 Leakage Rate Test Revision 00
Procedure
DB-PF-03012
Surveillance Test Service Water Pump 1 Testing Revision 03
Procedure
DB-PF-03017
Surveillance Test HPI Train 1 Pump and Valve Test Revision 04
Procedure
DB-SP-03218
Surveillance Test HPI Train 2 Pump and Valve Test Revision 05
Procedure
DB-SP-03219
Surveillance Test Service Water Train 1 Valve Test Revision 04
Procedure
DB-PF-03020
Surveillance Test Service Water Train 2 Valve Test Revision 04
Procedure
DB-PF-03027
Periodic Test HPI Pump 1 Baseline Test Revision 00
Procedure
DB-PF-04207
Mechanical Torquing Revision4
Maintenance
Procedure DB-
MM-09266
RA-EP-02880 Internal Flooding October 14,
1998
64
DB-OP-02011 Heat Sink Alarm Panel 11 Annunciators September 16,
2002
DB-OP-06261 Service Water System Operating Procedure June 6, 2002
DB-PF-03272 Post Maintenance Valve Test Revision 2
DB-SP-03152 AFW Train 1 Level Control, Interlock and Flow Revision 6
Transmitter Test
DB-SP-03161 AFW Train 2 Level Control, Interlock and Flow Revision 6
Transmitter Tes
DB-OP-02000 Emergency Procedure Bases and Derivation Document Revision 11
DB-OP-02000 Emergency Procedure May 14, 2001
RA-EP-02830 Emergency Plan Off Normal Occurrence Procedure, Revision 00
Flooding
Surveillances and Tests
DB-MM-03006 Inspection of Tech Spec Hydraulic Snubbers January 28,
2002
DB-PF-03017 Service Water Pump 1 Quarterly Test February 8,
2000
Service Water Pump 1 Quarterly Test May 8, 2000
Service Water Pump 1 Quarterly Test September 8,
2000
Service Water Pump 1 Quarterly Test February 23,
2001
Service Water Pump 1 Quarterly Test April 29, 2001
Service Water Pump 1 Quarterly Test August 7, 2001
Service Water Pump 1 Quarterly Test October 30,
2001
Service Water Pump 1 Quarterly Test January 23,
2002
DB-PF-03020 Service Water Train 1 Quarterly Valve Test January 26,
2000
Service Water Train 1 Quarterly Valve Test July 11, 2000
Service Water Train 1 Quarterly Valve Test March 7, 2001
65
Service Water Train 1 Quarterly Valve Test December 27,
2001
Service Water Train 1 Quarterly Valve Test January 23,
2002
DB-PF-03023 Service Water Pump 2 Quarterly Test October 19,
2000
Service Water Pump 2 Quarterly Test January 8,
2001
Service Water Pump 2 Quarterly Test April 6, 2001
Service Water Pump 2 Quarterly Test June 29, 2001
Service Water Pump 2 Quarterly Test September 17,
2001
Service Water Pump 2 Quarterly Test November 11,
2001
DB-PF-03027 Service Water Train 2 Quarterly Valve Test November 13,
2001
Service Water Train 2 Quarterly Valve Test December 11,
2001
Service Water Train 2 Quarterly Valve Test January 9,
2002
DB-PF-04704 Performance Test - Component Cooling Water Heat September 16,
Exchanger 1 1999
Performance Test - Component Cooling Water Heat June 19, 2001
Exchanger 1
DB-PF-04705 Performance Test - Component Cooling Water Heat September 29,
Exchanger 2 1999
Performance Test - Component Cooling Water Heat August 2, 2000
Exchanger 2
DB-PF-04706 Performance Test - Component Cooling Water Heat September 29,
Exchanger 3 1999
Performance Test - Component Cooling Water Heat August 29,
Exchanger 3 2000
DB-PF-04729 Containment Air Cooler Monitoring Test March 15,
1999
Containment Air Cooler Monitoring Test March 9, 2000
66
Containment Air Cooler Monitoring Test June 8, 2000
Containment Air Cooler Monitoring Test June 9, 2000
Containment Air Cooler Monitoring Test March 20,
2001
Containment Air Cooler Monitoring Test June 13, 2001
Containment Air Cooler Monitoring Test June 20, 2001
Containment Air Cooler Monitoring Test August 8, 2001
Containment Air Cooler Monitoring Test August 14,
2001
Containment Air Cooler Monitoring Test November 1,
2001
Containment Air Cooler Monitoring Test November 6,
2001
Containment Air Cooler Monitoring Test January 22,
2002
Containment Air Cooler Monitoring Test January 29,
2002
DB-PF-04736 ECCS Room Cooler Monitoring Test July 21, 2000
ECCS Room Cooler Monitoring Test October 13,
2000
ECCS Room Cooler Monitoring Test April 11, 2001
ECCS Room Cooler Monitoring Test January 15,
2001
DB-SC-03114 SFAS Integrated Time Response Test May 6, 1998
SFAS Integrated Time Response Test May 4, 2000
DB-SC-03122 SFAS Components Test May 13, 1998
SFAS Components Test May 7, 2000
DB-SP-03032 Service Water Pump 3 Refueling Test May 9, 2000
Service Water Pump 3 Refueling Test June 26, 2000
DB-SS-04021 Backup Service Water Pump Quarterly Test April 18, 2002
Backup Service Water Pump Quarterly Test July 11, 2002
67
Other Documents
ISA-S67.04 Setpoints for Nuclear Safety-Related Instrumentation September
1994
DB-ME-03045 R00 C1 Bus Undervoltage Units Monthly Functional Test Revision 00
DB-ME-05319 GE NGV13B Voltage Relay Maintenance and Revision 00
Calibration
RFM 89-0011 Obsolete M-2 Valve Actuator January 17,
1989
SCR 92-5013 Increase the Upper Bound of the Allowable Setpoint June 16, 1992
Range for the 59 percent Relays from 67 Volts to 69
Volts
FCR 83-063 Replace HPI Pump 1-2 AC Lube Oil Pump May 2, 1983
Operability Operability Justification 01-0015 for Condition Report August 22,
Justification 01- 01-2158, High Voltage Switchgear Room Temperature 2001
0015 Concerns
E-005-00154-4 Instr Man-I-T-E Single Phase Voltage Relays 35891
USAR Change Safety Evaluations Associated with LAR 89-0017 and January 8,
Notice (UCN) 90- MOD 88-0234 1990
001
Davis-Besse Letter Response to NRC Regarding Davis-Besse Unit No. 1 July 18, 1977
- Serial No. 293 Grid Stability
Davis-Besse Letter License Amendment Application to Clarify that Decay June 13, 1989
- Serial No. 1667 Heat Removal Valve DH23 Is not Subject to Type C
Test Requirements (TAC Number 73244)
Davis-Besse Letter License Amendment Application to Remove Technical December 22,
- Serial No. 1737 Specification Table 3.6-2, Containment Isolation Valves 1989
(TAC Number 75235)
Davis-Besse Letter Revision 11 to the Updated Safety Analysis Report May 31, 1990
- Serial No. 1794
Davis-Besse Letter Withdrawal of License Amendment Applications to June 1, 1990
- Serial No. 1812 Revise Technical Specification 3/4.6.3.1, Containment
Isolation Valves (TAC Numbers 66008 and 73244)
License Amendment No. 147 to Facility Operating License No. April 13, 1990
Amendment No. NPF-3 (TAC No. 75235)
147
68
EPRI TR-103335 Guidelines for Instrument Calibration March 1994
Extension/Reduction Programs
DB-OP-02000 RPS, SFAS, SFRCS or SG Tube Rupture Revision 06
Basis and Deviation Document for DB-OP-02000 Revision 11
Design Report for Modification 99-0039-00 Replace Revision 0
Valves SW 1356, SW 1357, and SW1358
Spec. 7749-M-319 Design Specification for Nuclear Ball and Butterfly Revision 4
Control Valves for The Toledo Edison Company and
the Cleveland Electric Illuminating Company Davis-
Besse Nuclear Power Station Unit No. 1
Spec. M-319CQ Technical Specification for Operational Phase Service Revision 0
Water Nuclear Ball Control Valves SW 1356, SW 1357,
and Sw 1358 for Davis-Besse Nuclear Power Station
SD-038 System Description for High Pressure Injection System Revision 2
SD-003A System Description for the 4160 volt Auxiliary System Revision 3
SD-018 System Description for Service Water System Revision 2
High Pressure Injection Pump 1 Inservice Testing Data October 8,
2002
High Pressure Injection Pump 2 Inservice Testing Data October 8,
2002
High Pressure Injection Valve Inservice Testing Data October 8,
2002
DB-OP-06011 High Pressure Injection System Revision 02
DB-OP-02003 ECCS Alarm Panel 3 Annunciators Revision 02
DB-PF-03205 ECCS Train 1 Valve Test Revision 04
DB-OP-06331 Freeze Protection and Electrical Heat Trace Revision 03
DB-PF-03207 HPI Pump Comprehensive and Check Valve Forward Revision 02
Flow Tests
EN-DP-01080 Calculations Revision 01
DB-PF-03969 HPI System Pressure Isolation Integrity test Back-to Revision 04
Back Check Valves
DB-PF-03069 Check Valve reverse Flow Tests Revision 04
Calc 67A Pipe Stress Analysis Revision 05
69
50-346/89-201 Interfacing System LOCA Inspection December 22,
1989
50-346/92010 Announced Safety Inspection of the Licensees August 20,
Response to Generic Letter 89-10 1992
SN 1793 Response to Inspection Report 50-346/89-201- April 27, 2002
Interfacing System Loss of Coolant Accident
UCN 98-022 U Seismic Qualification of Valves SW-1424, SW-1429, February 18,
and SW-1434 2002
PCAQR 95-0681 T413 May Read Low August 17,
1995
PCAQR 97-1174 Decay Heat Exchangers Overstressed September 4,
1997
USAR 6.3 Emergency Core Cooling Systems Revision 22
TS 3/4.5 Emergency Core Cooling Systems
SD003A System Description for the 4160 Volt Auxiliary System Revision 3
Standing Order Interim Guidance on High Voltage Switchgear Room July 13, 2002
02-005 Ventilation
4160 VAC Maintenance Rule Scoping Documents
Davis-Besse Materiel Condition Report - Essential and 4th Quarter
Miscellaneous AC 1999
Davis-Besse Materiel Condition Report - Essential and 2nd Quarter
Miscellaneous AC 2000
Davis-Besse Materiel Condition Report - Essential and 3rd Quarter
Miscellaneous AC 2000
Davis-Besse Materiel Condition Report - Essential and 4th Quarter
Miscellaneous AC 2000
Davis-Besse Materiel Condition Report - Essential and 1st Quarter
Miscellaneous AC 2001
Davis-Besse Materiel Condition Report - Essential and 2nd Quarter
Miscellaneous AC 2001
Davis-Besse Materiel Condition Report - Essential and 3rd Quarter
Miscellaneous AC 2001
Davis-Besse Materiel Condition Report - Essential and 4th Quarter
Miscellaneous AC 2001
70
Davis-Besse Materiel Condition Report - Medium 1st Quarter
Voltage AC 2002
Davis-Besse Weekly Maintenance Risk Summary February 12,
2002
M-45-18-4 Goulds Pumps Service Water Pumps Vendor Manual October 30,
1987
MPR-876 Davis-Besse Auxiliary Feed Pumps Evaluation of October 1985
Automatic Transfer of Suction to the Service Water
System
OS-020 SH 1 Service Water System Operational Schematic - Sheet 1 Revision 55
OS-020 SH 2 Service Water System Operational Schematic - Sheet 2 Revision 24
PFP-IS-52 Protected Area Pre-fire Plan for Service Water Pump Revision 2
Room, Room 52, Fire Area BF
SD-018 System Description for Service Water System Revision 2
TM 02-0019 Temporary Modification - Install temporary flood barrier August 27,
in place of Cooling Tower Makeup Pump #1 2002
Service Water Pump 1 IST Trend Data September
2000 - present
Service Water Valve Test Data January 1992 -
present
Letter Serial No. 1- Response to Generic Letter 89-13, Service Water January 30,
904 System Problems Affecting Safety-Related Equipment 1990
Letter Serial No. 1- Final Response to Generic Letter 89-13, Service Water December 23,
966 System Problems Affecting Safety-Related Equipment 1991
Letter Serial No. 1- Supplemental Response to Generic Letter 89-13, September 9,
1022 Service Water System Problems Affecting Safety- 1993
Related Equipment
Letter Serial No. Commitment Change Summary Report November 20,
2575 1998
NRC Bulletin No. Potential Safety Related Pump Loss May 5, 1988
88-04
Toledo Edison Subject: Response to NRC Bulletin No. 88-04: Potential September 8,
Letter Serial No. 1- Safety Related Pump Loss 1988
823
71
Toledo Edison Subject: Final Response to Nuclear Regulatory April 14, 1989
Letter Serial No. 1- Commission (NRC) Bulletin No. 88-04: Potential Safety
871 Related Pump Loss (TAC 69906)
Toledo Edison Subject: Update on Activities Relating to NRC Bulletin December 16,
Letter Serial No. 1- No. 88-04: Potential Safety Related Pump Loss 1988
849
Mod 94-0009 Service Water Thermal Relief Valve Replacement for April 1995
Containment Air Coolers
SCR 93-5016 Change PSL 1377, Service Water Strainer Discharge January 12,
Pressure Switch to 55 PSIG 1994
Mod 87-1076 Remove ECCS Room Coolers Service Water Return January 12,
Check Valves Internals 1988
Mod 87-1290 Remove Internal of Valve SW-329 July 6, 1990
Mod 88-0234 Overpressure Protection for the Containment Air November 11,
Coolers 1988
FCR 84-0147 Service Water Pump Room Ventilation Upgrade November 23,
1985
Mod 99-0039-00 CAC Temperature Control Valve Replacement June 29, 1999
FCR 78-039 Change Setpoints on SW-PSH-2917 and SW-PSH- January 23,
2917A 1978
SE 87-0366 Remove Internals of Check Valves SW - 217 & SW - January 12,
218 1988
SE 95-0056 Remove Relief Valves SW - 10210, SW - 10211, & SW September 9,
-10212 From Containment Air Coolers 1995
SE 84-147 Service Water Pump Room Ventilation Upgrade November 23,
1985
SE 01-0008 CAC Temperature Control Valve Replacement June 2, 2001
72
List of Documents Requested by USNRC
Document Request (Bob Daley)
Please provide a copy of the following documents (Items in Bold should be higher priority):
SCR 92-5028 Revise Setting 4.16 KV Bus 2/23/95
SCR 92-5029 Rev Trip Timer for 4.16 KV Loads 6/2/95
MOD 89-0011-00 Obsolete Type M-2 Vlv Actuators 8/23/01
MOD 97-0002-00 LM-Replace PDS 3886 7/17/98
C-EE-004.01-001 Protective Relay Setpoints for Service Water 5/12/98
Pump Motor 1-1 (AC107)
C-EE-004.01-003 Protective Relay Setpoints for Service Water 10/27/92
Pump Motor 1-3 (AC109)
C-EE-004.01-009 Protective Relay Setpoints High Pressure 1/22/02
Injection Pump Motor 1-1 (AC111)
C-EE-004.01-010 Protective Relay Setpoints High Pressure 6/21/91
Injection Pump Motor 1-2 (AD111)
C-EE-004.01-046 4.16 KV Short Circuit Calculations 7/8/91
C-EE-004.01-049 4.16 KV Bus Degraded Voltage (90 percent 6/27/02
Undervoltage) Relay Setpoint
C-EE-004.01-051 59 percent Undervoltage (Loss of Station Power) 8/23/93
Setpoint Calculation
C-EE-006.01-026 Voltage Drop for GL 89-13 Valve Operators 5/21/02
C-EE-006.01-027 SFAS Control Ckt Voltage Drop 5/4/92
C-EE-015.07-001 4.16 & 13.8 KV Cable Ampacity 5/7/92
C-ICE-048.01-002 SFAS Reactor Coolant Pressure Actuation 10/14/97
Setpoints
C-ICE-011.01-001 Service Water Pump Discharge Pressure 4/19/01
Switches
Op Eval 2000-0012 HPI Flow Indicating Switches
of CR 2000-2382
73
Op eval 2001-0003 4160 Breakers
of CR 01-0138
Op eval 2001-0015 HV SWGR Room HVAC
of CR 01-2158
Op eval 2001-0025 SFAS Sequencer
of CR 01-2919
Please provide one line electrical schematics for the following:
13. Service Water Pumps
14. HPI Pumps
15. MOVs SW 1382, SW 1383, SW 5421, SW 5422, SW 5423, SW 5424, SW 5425, SW 2927,
SW 2928
Please provide the nameplate data for the following pumps:
1. Service Water Pumps
2. HPI Pumps
Please provide the coordination calculations for all loads and feeder breakers for Buses AC and
BD.
Please have available:
1. NEC Code
2. IEEE Std 242, IEEE Recommended Practice for Protection and Coordination of Industrial
and Commercial Power Systems. (IEEE Buff Book)
3. IEEE Std 141, IEEE Recommended Practice for Electric Power Distribution for Industrial
Plants. (IEEE Red Book)
4. Nuclear IEEE Standards, Volume 1 and 2
74
DOCUMENTS REQUEST FOR D. C. PREVATTE, 9/17/02
Please provide the latest revisions of the following documents.
In order to minimize unnecessary copying, for modification packages that are very large, please
provide only the basic package front-end materials that describe the modification, its bases,
etc., the 10CFR50.59 safety evaluation and/or screening, and the post modification testing
documents, but not the detailed construction and installation documents. Likewise, for
calculations that are very large, please provide only the basic front-end portions of the
calculations, e.g., the purpose, assumptions, inputs, references, and results and conclusions
sections, but not the large appendices.
Thank you for your support.
Modifications:
Modification # Modification Title/Subject
For Service Water System:
FCR 78-0039-2917 Change setpoints on PSH-2917
FCR 80-0225-00 Delete auto close SW 1395, 1399
FCR 80-0252-00 Replace valve bodies
FCR 80-0054-00 Back-up service water capability
FCR 84-0151-00 SWS valve & anchor modification
FCR 84-0111-00 Setpoint change - SW pump
FCR 84-0115-00 Changed SW valves locked position
FCR 84-0147-00 SW pump room ventilation upgrade
MOD 87-1072-00 Service water check valve
MOD 87-1075-00 Remove check valves SW-130, 134
MOD 87-1076-00 Remove check valves SW-217, 218
MOD 87-1290-00 Remove internals of SW-329
SCR 93-5016 Change PSL 1377 setpoint
FCR 80-0221-00 Piping change/service water
MOD 88-0234-00 Containment air coolers
MOD 94-0009-00 SW thermal relief valve replacement
For HPSI System:
FCR 78-0414-00 Change Tech Spec 4.5.2.6
FCR 78-0498-00 Correct determination of FSAR
FCR 86-0291-00 Mod high pressure injection line
75
Calculations:
(Please note that some of these calculations appear from the title to address the same subject. If
any of these are more current versions of the same analysis, or if any of these have been
superceded by calculations not listed here, please provide only the most current calculations that
address the subject.):
Calculation # Calculation Title/Subject
For Service Water System:
Mech 11.036 Traveling water screens
Struct 59 SW pipe stress analysis w/supports
Nucl 12501-M-001 UHS pond thermal performance analysis...
Nucl 12501-M-003 ECCS room temperature with initial 90 degree F forebay
Nucl 12501-M-004 UHS heat sink analysis of maximum evaporation period
Mech 59.001 UHS input
Mech 59-009 Davis Besse UHS
Mech 59-011 UHS analysis
Mech 59-016 UHS - Loss of intake canal - cooling pond calc
Mech 67.004 SW pump room - max allowable outside air temp to...
Mech 67.005 SW pump room ventilation capacity
Mech 67.006 SW pump room fan flow requirements
Mech 67.007 SW pump room ventilation system - pressure drop
Mech 67.008 SW pump room ventilation system - new penthouse...
Struct C-CSS-11.01-169 Containment air cooler eval for GL 96-06
Struct C-CSS-11.01-171 SW strainer internals analysis
Mech C-ME-011.01-130 SW system hydraulic calculation
Mech C-ME-011.06-003 Cont. cooler control valve travel
Nucl C-NSA-000.00-017 Service water system model
Nucl C-NSA-011.01-003 Allowable SW flow diversion during cold weather
Nucl C-NSA-011.01-004 SW pump start/coastdown time, CAC water hammer input
Nucl C-NSA-011.01-007 SW discharge through valve located at the intake struct.
Nucl C-NSA-001.01-008 Replacement of CAC flow control valves
Nucl C-NSA-001.01-010 Maximum SW pressure to AFW system
Nucl C-NSA-060.05-006 Revised containment response with 90 degree F SW
Nucl C-NSA-060.05-007 CAC duty at elevated SW inlet temperatures
Nucl C-NSA-060.05-008 Cont post-LOCA response w/variable SW temperature
Nucl ESM-99-002 Effect of UHS pond siltation on SW intake temperature
For HPSI System:
Mech 25.006 ECCS Rooms - Cooling System
Mech 25.013 ECCS Pump Room Heat Load
Mech 25.014 ECCS Pump Room Heat Load
Mech 32-1106901 MU/HP flow rates vs. reactor pressure...
Nucl 32-1159853 HPI flow vs. RCS pressure
Mech 36.010 LPI, HPI, CS pump NPSH from BWST
76
Mech 36.028 ECCS seal failure
Mech 36.031 HPI pump NPSH at a possible 1020 gpm
Mech 36.032 HPI pump test flow line
Mech 58.020 Flooding of ECCS pump rooms due to FW line break
Nucl 86-5006232 LOCA summary report
Mech C-ME-052.01-110 Reverse engineer HPI pump casing studs & casing nuts
Nucl C-NSA-032-02-003 Max allowable SW temp with inop ECCS room cooler
Nucl C-NSA-049.01-002 Adequacy of BWST for feed and bleed
Nucl C-NSA-049.01-004 Vortex formation with ECCS pump suction from the BWST
Nucl C-NSA-052.01-003 HPI pump acceptance testing
Nucl C-NSA-052.01-004 HPI system resistance curves
Nucl C-NSA-052.01-011 HPI NPSH on containment emergence sump recirc
Nucl C-NSA-052.01-012 Max. allowable leak rate through HP31/32
Nucl C-NSA-052.01-014 HPSI flow vs. RCS pressure for LOCA analysis input
Nucl C-NSA-052.01-016 Add T to HPI pump 2 discharge line
Nucl C-NSA-052.01-015 HPI pump curve based on system curve in LOCA analysis
Nucl C-NSA-063.01-008 Verification of HPI system performance during a SGTR
Nucl C-NSA-065.01-008 Makeup and HPI NPSH
77
Request for Documents Part III
Service Water Strainer
a. Drawings
b. Procedures, (surveillance, PMs, operating, abnormal, )
c. Maintenance history
d. Operational history (clogging events, identification of debris making it past the strainers,
damage to the strainers, etc)
e. Last time opened for inspection, inspection results
f. Vendor Manual
g. Ultimate heat sink inspections, inspection results, maintenance and operational history,
h. Lay out drawing for the Service Water intake building (where the SW pumps are located)
i. For HPI pump #1 and SW pump #1 need the breaker relay vendor technical manual, the
motor start curves and for HPI #1 motor need the name plate data
j. Do you have copies of the TS and UFSAR available on CDs?
Backup air supplies to the Containment Air Cooler (CAC) valves
k. Calculations for sizing
l. Basis calculation for the test acceptance criteria
m. Last two completed surveillance tests
78
Request for Documents Part IV
a. List of all work orders (preventive, corrective, troubleshooting, etc) for 4160 for the last
two years.
b. Same as above except for service water system
c. Copy of Tech Spec Basis
d. Copy of annunciator response procedures for local and control room annunciators for
service water and 4160
e. SBO D/G operating procedure DB-OP-06334
f. Implementing procedures for the following Tech Spec surveillance requirements:
a. 4.8.2.1 - Onsite power dist systems
b. 4.8.2.2 - Onsite power dist systems
c. 4.6.3.1.2.a - containment iso valves
d. 4.6.3.1.3 - containment iso valves
e. 4.7.4.1.a - Service water system
f. 4.7.4.1.b - Service water system
g. 4.7.5.1 - UHS
h. 4.8.1.1.1.a - Elect Power Systems
i. 4.8.1.1.1.b - Elect Power Systems
g. The procedure performing and the last results for any snubbers in the service water
system governed by SR 4.7.7
h. All IST procedures for the Service Water system components
i. One additional set of P&IDs for SW (sheets A, B, C)
j. Operability justifications and their associated CRS
a. 2001 - 0003 01-0138
b. 2001 - 0015 01-2158
c. 2002 - 0009 02-01157
d. 2002 - 0023 02-02658
k. Description of operability justification 2002 - 0027
79
l. EWR 02-0247-00 and CR 02-1459 and CR 02-2372 all dealing with operator work-around
for intake chlorination
m. Copies of all other surveillance procedures preventive maintenance procedures and
operator logs for SW and 4160.
80