ML032120360
| ML032120360 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 07/30/2003 |
| From: | Grobe J NRC/RGN-III |
| To: | Myers L FirstEnergy Nuclear Operating Co |
| References | |
| EA-03-131 IR-03-015 | |
| Download: ML032120360 (53) | |
See also: IR 05000346/2003015
Text
July 30, 2003
Mr. Lew W. Myers
Chief Operating Officer
FirstEnergy Nuclear Operating Company
Davis-Besse Nuclear Power Station
5501 North State Route 2
Oak Harbor, OH 43449-9760
SUBJECT:
DAVIS-BESSE NUCLEAR POWER STATION NRC INTEGRATED
INSPECTION REPORT 50-346/2003-015 - PRELIMINARY YELLOW FINDING
Dear Mr. Myers:
On June 30, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Davis-Besse Nuclear Power Station. The enclosed inspection report documents the
inspection findings which were discussed on July 9, 2003, with you and other members of your
staff. The inspection was an examination of activities conducted under your license as they
relate to safety and to compliance with the Commissions rules and regulations and with the
conditions of your license. Within these areas, the inspection consisted of a selective review of
procedures and representative records, observations of activities, and interviews
with personnel. Since April 2002, the Davis-Besse Nuclear Power Station was under the
Inspection Manual Chapter (IMC) 0350 Process. The Davis-Besse Oversight Panel assessed
inspection findings and other performance data to determine the required level and focus of
followup inspection activities and any other appropriate regulatory actions. Even though the
Reactor Oversight Process has been suspended at the Davis-Besse Nuclear Power Station, it
was used as guidance for conducting inspection activities and to assessing findings.
This report discusses a finding that appears to have substantial safety significance and is being
considered for escalated enforcement action in accordance with the General Statement of
Policy and Procedure for NRC Enforcement Actions (Enforcement Policy), NUREG-1600.
The current Enforcement Policy is included on the NRCs website at
http://www.nrc.gov/reading-rm/adams.html. As described in Section 4OA3.2 of this report, the
finding involved the failure to promptly identify and correct significant conditions adverse to
quality regarding unqualified coatings and uncontrolled fibrous material and other debris inside
containment. This finding was assessed based on the best available information using the
Significance Determination Process and was preliminarily determined to be a Yellow finding.
The preliminary significance of the finding is based on the increased likelihood of the
emergency core cooling systems to fail following a loss of coolant accident. After injecting
additional cooling water into the reactor following an accident, those systems begin recirculating
cooling water to the reactor from the containment sump. The unqualified coatings, fibrous
material and other debris could clog the screen on the sump blocking the water supply to the
emergency core cooling system pumps. This increased likelihood of emergency core cooling
system failure increases the probability of damage to the reactor following an accident. The
L. Myers
-2-
increased probability was evaluated initiating Revision 3i of the Davis-Besse Standardized Plant
Analysis Risk Model. The results of the evaluation indicated an increase in reactor core
damage frequency of about 4 times in 100,000. Under the NRCs Significance Determination
Process, this represents a Yellow finding. This increased risk existed from the time the facility
began operation in 1977 until early 2002. The enclosure to this letter details the basis for the
NRCs preliminary significance determination.
This finding does not present an immediate safety concern based on your immediate
compensatory and corrective actions. These actions included a complete re-design of your
emergency core cooling system sump strainer, and the reduction of potential debris sources in
containment by recoating selected surfaces with approved coatings and the removal of other
debris.
Before the NRC finalizes this significance determination, we are providing you an opportunity
(1) to present to the NRC your perspectives on the facts and assumptions used by the NRC to
arrive at the finding and its significance at a Regulatory Conference; or (2) submit your position
on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held
within 30 days of the receipt of this letter and we encourage you to submit supporting
documentation at least one week prior to the conference in an effort to make the conference
more effective. If a Regulatory Conference is held, it will be open for public observation. If you
decide to submit only a written response, such submittal should be sent to the NRC within 30
days of the receipt of this letter.
Please contact Christine Lipa at 630-829-9619 within 10 business days of the date of this
receipt of this letter to notify the NRC of your intentions. If we have not heard from you within
10 days, we will continue with our significance determination and enforcement decision and you
will be advised by separate correspondence of the results of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for the inspection finding at this time. In addition, please be advised that the
characterization of the apparent violation described in the enclosed inspection report may
change as a result of further NRC review.
This report also documents one finding concerning a design deficiency in the emergency core
cooling system high pressure injection pumps. That deficiency could result in damage or failure
of the pumps following an accident. This is considered an apparent violation and the potential
safety significance has not yet been determined. This finding does not present an immediate
safety concern because the equipment is not required to be operable to support the current
operational Mode of the plant. Additional review is necessary to determine the risk significance
of this finding.
In addition, the enclosed report documents three self revealing violations of very low safety
significance (Green). These findings were determined to involve violations of NRC
requirements. However, because of the very low safety significance and because they are
entered into your corrective action program, the NRC is treating these three findings as
non-cited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you
L. Myers
-3-
contest any of the NCVs in this report, you should provide a response within 30 days of the date
of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the
Regional Administrator Region III, 801 Warrenville Road, Lisle, IL 60532-4351; the Director,
Office of Enforcement, United States Nuclear Regulatory Commission, Washington DC 20555-
001; and the NRC Resident Inspector at Davis-Besse.
Since the terrorist attacks on September 11, 2001, NRC has issued five Orders and several
threat advisories to licensees of commercial power reactors to strengthen licensee capabilities,
improve security force readiness, and enhance controls over access authorization. The NRC
issued Temporary Instruction 2515/148 on August 28, 2002, that provided guidance to
inspectors to audit and inspect licensee implementation of the interim compensatory measures
(ICMs) required by order. Phase 1 of TI 2515/148 was completed at all commercial nuclear
power plants during calendar year 2002, and the remaining inspection activities at Davis-Besse
are scheduled for completion in September 2003. The NRC will continue to monitor overall
safeguards and security controls at Davis-Besse.
In accordance with 10 CFR 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
Enclosure:
Inspection Report 50-346/03-015
See attached distribution
L. Myers
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cc w/encl:
The Honorable Dennis Kucinich
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
Steve Arndt, President, Ottawa County Board of Commissioners
D. Lochbaum, Union Of Concerned Scientists
DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML032120360.wpd
To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy
OFFICE
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DATE
07/29/03
07/30/03
07/30/03
07/30/03
OFFICIAL RECORD COPY
L. Myers
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ADAMS Distribution:
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Enclosure
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No:
50-346
License No:
Report No:
50-346/2003-015
Licensee:
FirstEnergy Nuclear Operating Company (FENOC)
Facility:
Davis-Besse Nuclear Power Station
Location:
5501 North State Route 2
Oak Harbor, OH 43449-9760
Dates:
May 18 through June 30, 2003
Inspectors:
S. Thomas, Senior Resident Inspector
J. Rutkowski, Resident Inspector
R. Gibbs, Senior Reactor Analyst
Approved by:
C. A. Lipa, Chief
Branch 4
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1.
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R01
Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R05
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
.1
High Pressure Injection Pump Rotating Element Disassembly . . . . . . . . 5
.2
Reactor Coolant Pump Seal Resistance Temperature Detector (RTD)
Installation Rework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
.3
High Pressure Injection Pump Installation of Modified Rotating Assembly
for Special Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R13
Maintenance Risk Assessment and Emergent Work Evaluation . . . . . . . . . . . . 8
1R14
Personnel Performance During Nonroutine Plant Evolutions . . . . . . . . . . . . . . . 9
.1
Circulating Water System Fill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
.2
High Pressure Injection Pump 1 Enhanced Baseline Testing in Piggyback
Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
.3
Reactor Coolant Drain from level of 80 inches to 54 inches above hot leg
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
1R15
Operability Evaluations
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
1R22
Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
1R23
Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
4.
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
.1
(Discussed) Licensee Event Report (LER) 50-346/03-002 . . . . . . . . . . . . . . . . 14
.2
(Discussed) Licensee Event Report (LER) 50-346/02-005-00, 50-346/02-005-01,
50-346/02-005-02 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
.1
Inappropriately Lowering Shutdown Risk Category During Reduced Inventory
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
.2
Negative Trend in the Number of Engineering Change Request Administrative
Errors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
.3
Classification, Categorization, and Resolution of Restart Related Issues . . . . . 25
.4
Safety Conscious Work Environment (SCWE) and Safety Culture Observations
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA6 Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Enclosure
ATTACHMENT: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
LIST OF DOCUMENTS REVIEWED
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Enclosure
1
SUMMARY OF FINDINGS
IR 05000346/2003-015; 5/18/2003 - 6/30/2003; FirstEnergy Nuclear Operating Company,
Davis-Besse Nuclear Power Station; Event Followup, Maintenance Effectiveness, Personnel
Performance During Nonroutine Plant Evolutions.
This report covers a 6-week period of resident inspection. The inspection was conducted by
resident inspectors. One preliminary Yellow Apparent Violation, one Unresolved Item with
safety significance to be determined, and three Green Non-Cited Violations were identified.
The significance of most findings is indicated by their color (Green, White, Yellow, Red) using
Inspection Manual Chapter 0609 Significance Determination Process (SDP). Findings for
which the SDP does not apply may be Green or be assigned a severity level after NRC
management review. The NRCs program for overseeing the safe operation of commercial
nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3,
dated July 2000.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
Yellow. An Apparent Violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective
Action, was identified for the failure to promptly identify and correct significant
conditions adverse to quality regarding the implementation of corrective actions for
design control issues related to deficient containment coatings, uncontrolled fibrous
material and other debris. This impacted the ability of the emergency core cooling
system sump to perform its function under certain accident scenarios due to clogging of
the sump screen by unqualified coatings, fibrous materials, and various other debris.
The issue is more than minor because the failure to implement appropriate corrective
actions resulted in an actual loss of safety function of the ECCS system. The
significance determination evaluation for this finding is documented in this report.
(Section 4OA3.2)
TBD. An apparent violation of 10 CFR Part 50, Appendix B, Criterion III, Design
Control," was identified for the failure to adequately implement design control measures
for verifying and checking the adequacy of the original design of the high pressure
injection pumps for all postulated accidents.
The finding is Unresolved pending completion of a significance determination. The
finding is more than minor because it: (1) involves the design control attribute of the
Mitigating Systems cornerstone; and (2) affects the cornerstone objective of ensuring
the availability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Because the finding described above represents a potential
loss of safety function of the HPI system, a Significance Determination Process (SDP)
Phase 2 analysis was required. The inspectors utilized SDP worksheets for the Davis-
Besse Nuclear Power Station to perform a Phase 2 evaluation of the finding. Based on
this evaluation, the finding was determined to have potential safety significance greater
than very low safety significance. (Section 4OA3.1)
Enclosure
2
Green. A self-revealing Non-Cited Violation of Technical Specification 6.8.1.a was
identified for failing to provide adequate procedural guidance for tightening fasteners
internal to the high pressure injection pump. As a direct result, five socket head cap
screws, located near the discharge of the pump, failed during pump testing.
The finding is greater than minor because it: (1) involves the procedure quality attribute
of the Mitigating System cornerstone; and (2) affects the cornerstone objective of
ensuring the availability, and capability of systems that respond to initiating events to
prevent undesirable consequences. The finding is of very low safety significance
because no actual loss of a safety function occurred due to the failure of the cap
screws. (Section 1R12)
Cornerstone: Initiating Events
Green. A self-revealing Non-Cited Violation of Technical Specification 6.8.1.a was
identified for failing to properly implement system procedures during the filling of the
circulating water system. Since three drain valves were improperly left open during the
fill, approximately three inches of water flooded the 565' elevation of the turbine building.
The finding is greater than minor because it: (1) involves the configuration control
attribute of the Initiating Event Cornerstone; and (2) affects the cornerstone objective of
limiting the likelihood of those events that upset plant stability and challenge critical
safety functions during shutdown as well as power operations. The finding is of very low
safety significance because the event was terminated prior to actual loss of a equipment
important to plant safety. (Section 1R14)
Cornerstone: Barriers
Green. A self-revealing Non-Cited Violation of Technical Specification 6.8.1.a was
identified for failing to perform work in accordance with approved maintenance
procedures during the installation of reactor coolant pump mechanical seal RTDs. As a
direct result, the RTD tubing nuts were not installed to a sufficient tightness to provide a
leak tight joint at normal operating pressure.
The finding is greater than minor because if left uncorrected, it would become a more
significant safety concern. Investigation by the licensee revealed that the RTD tubing
nuts were not installed to a sufficient tightness to provide a leak tight joint at normal
operating pressure. The finding is of very low safety significance because the current
operational Mode does not challenge the integrity of the RTD mechanical joints.
(Section 1R12)
B.
Licensee-Identified Violations
A violation of very low safety significance, which was identified by the licensee has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees corrective action program. This violation and corrective
actions are listed in Section 4OA7 of this report.
Enclosure
3
REPORT DETAILS
Summary of Plant Status
The plant was shutdown on February 16, 2002 for a refueling outage. During scheduled
inspections of the control rod drive mechanism nozzles, significant degradation of the reactor
vessel head was discovered. As a direct result of the need to resolve many issues surrounding
the Davis-Besse reactor vessel head degradation, NRC management decided to implement
IMC 0350, Oversight of Operating Reactor Facilities in a Shutdown Condition With
Performance Problems. The fuel was removed from the reactor on June 26, 2002, and the
plant remained shut down. The plant entered operational Mode 6 on February 19, 2003 and
fuel reload was completed on February 26, 2003. The plant entered operational Mode 5 on
March 12, 2003. For the entire inspection period, the Davis-Besse Nuclear Power Station was
under the IMC 0350 Process. As part of this Process, several additional team inspections
continued. The subjects of these inspections included: Containment Health/Extent of Condition,
System Health Assurance, Management and Human Performance, and Program Compliance.
The status of these inspections will not be included as part of this inspection report, but upon
completion, each will be documented in a separate inspection report which will be made publicly
available on the NRC website.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01
Adverse Weather Protection
.1
Annual Inspections (71111.01)
a.
Inspection Scope
The inspectors verified that the licensee had established procedures and had
implemented actions to mitigate the potential adverse effects from the annual mayfly
swarms. The inspectors verified that there were regular operator tours to inspect
equipment that could be impacted by mayfly swarms blocking cooling mechanisms or
affecting electrical resistance. Additionally, the inspectors verified that operators
conducting tours were familiar with established tour requirements, could identify
potential problems from mayfly swarms, and that procedural requirements had been
appropriately inputted to the handheld devices used by the operators for recording tour
data. A majority of the inspectors time was spent performing walkdown inspections with
operations personnel while they conducted tours. Key aspects of the walkdown
inspections included:
checking ventilation filters free from excessive buildup of mayflies and other
material that could impair ventilation flow;
verifying that potentially effected switchgear and pump ventilation inlets were not
clogged or did not have severely restricted passages;
verifying lake facing doors and dampers were closed during the night hours, if
permitted by plant conditions, to reduce mayfly influx to buildings; and
Enclosure
4
verifying that lighting, not necessary for security or other plant conditions, was
adjusted as practical to reduce attraction of mayflies.
During the walkdowns, the inspectors also observed the material condition of the
equipment to verify that there were no significant conditions not already in the licensees
work control system.
b.
Findings
No findings of significance were identified
1R05
Fire Protection (71111.05Q)
a.
Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on the
availability, accessibility, and condition of fire fighting equipment, the control of transient
combustibles, and the condition and operating status of installed fire barriers. The
inspectors selected fire areas for inspection based on their overall contribution to
internal fire risk, as documented in the Individual Plant Examination of External Events,
their potential to impact equipment which could initiate a plant transient, or their impact
on the plants ability to respond to a security event. Using the documents listed at the
end of this report, the inspectors verified that fire hoses and extinguishers were in their
designated locations and available for immediate use, that fire detectors and sprinklers
were unobstructed, that transient material loading was within the analyzed limits, and
that fire doors, dampers, and penetration seals appeared to be in satisfactory condition.
The following areas were inspected:
containment building (fire zone D) including the east D-ring; and
component cooling water heat exchanger and pump room.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Effectiveness (71111.12Q)
a.
Inspection Scope
The inspectors reviewed the licensees overall maintenance effectiveness for
risk-significant mitigating structures, systems, and components (SSCs). This evaluation
consisted of the following specific activities:
observing the conduct of planned and emergent maintenance activities where
possible;
reviewing selected CRs, open WOs, and control room log entries in order to
identify system deficiencies;
Enclosure
5
reviewing licensee system monitoring and trend reports; and
a partial walkdown of the selected SSCs listed below.
The inspectors also reviewed whether the licensee properly implemented the
Maintenance Rule, 10 CFR 50.65, for the SSCs. Specifically, the inspectors determined
whether:
the SSCs were scoped in accordance with 10 CFR 50.65;
performance problems constituted maintenance rule functional failures;
the system had been assigned the proper safety significance classification;
The above aspects were evaluated using the maintenance rule program and other
documents listed in the Attachment.
The inspectors reviewed the following SSCs:
high pressure injection pump 1 (rotating element disassembly);
high pressure injection pump 1 (installation of modified rotating assembly for
rotordynamic testing); and
reactor coolant pump seal RTD installation rework.
b.
Findings
.1
High Pressure Injection Pump Rotating Element Disassembly
Introduction: A Green self-revealing Non-Cited Violation of Technical Specification 6.8.1.a was identified for failing to provide adequate procedural guidance for tightening
fasteners internal to the high pressure injection pump. As a direct result, five socket
head cap screws, located near the discharge of the pump, failed during pump operation.
Description: On June 1, 2003, the licensee was removing the rotating assembly from
high pressure injection pump 1 in preparations for shipping it to the vendor for
modification. While making preparations for the removal of the high pressure injection
pump 1 rotating assembly from its associated pump barrel casing, the licensee
discovered that five of the six cap screws were sheared where the threads met the
shank. Although the sixth cap screw was intact, it showed signs of impending failure.
This rotating assembly had recently been repaired at a vendor maintenance facility, with
direct licensee oversight, in accordance with Davis-Besse Mechanical Maintenance
Procedure DB-MM-09173, High Pressure Injection Pump Maintenance, Revision 02.
As part of the rotating assembly reassembly process, an internal head plate is installed.
Step 8.7.45 provided the instructions for installing the six internal head plate socket
head cap screws which secured the head plate. The instructions provided were install
internal head plate pins with locking devices and tighten securely. There was no
reference to the proper torque value for these cap screws. The procedure was
inadequate because it did not provide proper tightening instruction for installing the
internal head plate cap screws. Further evaluation by the licensee revealed that the
proper torque value for these cap screws was relatively small (70 in-lbs). This torque
value can easily be exceeded with a small wrench.
Enclosure
6
Although the failure of these cap screws did not pose a significant challenge to the
operation of the high pressure injection pump, they did present a loose parts issue.
Once the failure of the cap screw occurred, there was no physical barrier preventing the
cap screw from entering the discharge flow exiting the pump, being transported to the
reactor coolant system, and eventually the reactor. In this case, all of the failed cap
screws remained in place. As part of the corrective actions implemented to address this
deficiency, the licensee modified DB-MM-09173, step 8.7.46(b) as follows; torque
internal head plate socket heat cap screws to 70 in-lbs.
Analysis: In accordance with IMC 0609, Appendix A, Attachment 1, the inspectors
performed a SDP Phase 1 screening and determined that the issue affected the
Mitigating Systems Cornerstone. The finding was of more than minor safety significance
because it: (1) involved the procedure quality attribute of the Mitigating System
cornerstone; and (2) affected the cornerstone objective of ensuring the availability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. The finding is of very low safety significance because no actual loss of
a safety function occurred due to the failure of the cap screws.
Enforcement: The performance deficiency associated with this event is the failure to
provide adequate procedural guidance in a safety-related maintenance procedure which
provides guidance for tightening fasteners internal to the high pressure injection pump.
Technical Specification 6.8.1.a requires establishing and implementing procedures
required by Regulatory Guide 1.33. Regulatory Guide 1.33 requires procedures for
maintenance which can affect the performance of safety-related equipment. The
licensee developed Procedure DB-MM-09173, High Pressure Injection Pump
Maintenance, Revision 02, which provides guidance for the maintenance of the high
pressure injection pumps. Contrary to the requirements of Technical Specification 6.8.1.a, Procedure DB-MM-09173 did not provide adequate procedural guidance for
tightening the internal head plate socket head cap screws. As a direct result, five socket
head cap screws, located near the discharge of the pump, failed during pump operation.
Because of the very low safety significance and because the issue has been entered
into the licensees corrective action program (CR 03-04278) it is being treated as a
Non-Cited Violation, consistent with Section VI.A of the NRC Enforcement Policy
(NCV 50-346/03-015-01).
.2
Reactor Coolant Pump Seal Resistance Temperature Detector (RTD) Installation
Rework
Introduction: A self-revealing Non-Cited Violation of Technical Specification 6.8.1.a was
identified for failing to perform work in accordance with approved maintenance
procedures during the installation of reactor coolant pump mechanical seal RTDs. As a
direct result, the RTD tubing nuts were not installed to a sufficient tightness to provide a
leak tight joint at normal operating pressure.
Enclosure
7
Description: During the current refueling outage, the seal packages were replaced on
all four reactor coolant pumps. As part of the seal change-out process, the RTDs that
measured the temperature of each of the seals three stages (3 per pump) were
removed and subsequently reinstalled during seal assembly. These RTDs were
secured in place by mechanical fittings. The leak tightness of these fittings was
checked during the 50 psig and 250 psig reactor coolant system pressure tests. During
evaluation of the fittings while the reactor coolant system was pressurized, the licensee
identified that 4 of the 12 RTD fittings exhibited signs of leakage. As part of the
licensees corrective actions to address the leakage, new RTDs, O-rings, fittings, and
tubing connectors were installed in four of the RTD locations. During the RTD
installation process, when the workers discovered that each RTD was not secure after
using the guidance described in the work instructions, they continued to tighten the
tubing nut an additional 1/2 turn to secure the RTD. This was a deviation from the
instructions in the work package. After the required reactor coolant pump mechanical
seal RTD work was completed, the reactor coolant system was refilled, vented, and
pressurized to approximately 40 psig. No leakage was noted from the fittings where the
RTDs had been replaced, but leakage was noted from another RTD fitting. During the
licensees investigation into why the fitting was leaking, they discovered the
maintenance deviation that had occurred during the replacement of the four RTDs.
Additionally, the licensee discovered that the original guidance in the work instructions
for tightening the tubing nut (hand tight plus 3/4 of a turn) was insufficient to provide a
leak tight joint. The correct instructions should have been to tighten the tubing nut to
hand tight plus 1 3/4 turns. As part of the corrective actions for this issue, the licensee
planned to tighten the tubing nuts on the four replaced RTDs and the remaining leaking
RTD to the correct value prior to operational Mode 4 and verify leak tightness at full
operating pressure.
Analysis: In accordance with IMC 0612, Appendix B, the inspectors determined that the
issue was of more than minor safety significance because if left uncorrected, it could
become a more significant safety concern. Investigation by the licensee revealed that
the RTD tubing nuts were not installed to a sufficient tightness to provide a leak tight
joint at normal operating pressure. In accordance with IMC 0609, Appendix A,
Attachment 1, the inspectors performed a SDP Phase 1 screening and determined that
the issue affected the Barriers Cornerstone. The finding is of very low safety
significance because the current operational Mode of the did not challenge the integrity
of the RTD mechanical joints.
Enforcement: The performance deficiency associated with this event is the failure to
perform work in accordance with approved maintenance procedures. Technical Specification 6.8.1.a requires implementation of procedures required by Regulatory
Guide 1.33. Regulatory Guide 1.33 requires procedures for maintenance which can
affect the performance of safety-related equipment. The licensee developed DB-MN-
00001, Conduct of Maintenance, Revision 10, a procedure affecting quality, to provide
general guidance for the conduct of maintenance at the Davis-Besse facility. Step
6.5.2(c) states that tasks shall be completed as described in the latest approved
version of the work document. Contrary to this requirement, on four separate
occasions, RTD tubing nuts were tightened in excess of the guidance provided in the
work control document without first obtaining a formal change to the work document.
Further evaluation by the licensee revealed that, although the additional tightening was
Enclosure
8
sufficient to prevent axial movement of the RTD during installation, it was still insufficient
to ensure a leak tight seal at normal operating pressure. Because of the very low safety
significance and because the issue has been entered into the licensees corrective
action program (CR 03-04773) it is being treated as a Non-Cited Violation, consistent
with Section VI.A of the NRC Enforcement Policy (NCV 50-346/03-015-02).
.3
High Pressure Injection Pump Installation of Modified Rotating Assembly for Special
Test
On June 5, 2003, to support the validation of the licensees proposed modifications for
the high pressure injection pumps, a modified rotating assembly was installed into high
pressure injection pump 1 for testing. During the installation process, the torque applied
to the casing bolts was approximately 4.3% in excess of the desired torque. This error
occurred because a maintenance worker failed to check that a gauge which was part of
the hydraulic torque wrench being used to tighten the casing nuts was in calibration as
required by DB-MM-09173, High Pressure Injection Pump Maintenance, Revision 4.
Subsequent evaluation revealed that the gauge indicated approximately 200 psig low,
which corresponded to an additional 77 ft-lbs of torque being applied to the pump casing
nuts in excess of the 1785 ft-lbs required by the procedure. This issue was further
discussed in Section 4OA7 of this report.
1R13
Maintenance Risk Assessment and Emergent Work Evaluation (71111.13)
a.
Inspection Scope
The inspectors reviewed the licensees response to risk significant activities. These
activities were chosen based on their potential impact on increasing overall plant risk.
The inspection was conducted to verify the planning, control, and performance of the
work were done in a manner to reduce overall plant risk and minimize the duration
where practical, and that contingency plans were in place where appropriate. The
licensees daily configuration risk assessments, observations of shift turnover meetings,
observations of daily plant status meetings, and the documents listed at the end of this
report were used by the inspectors to verify that the equipment configurations had been
properly listed, that protected equipment had been identified and was being controlled
where appropriate, and that significant aspects of plant risk were being communicated
to the necessary personnel. The following risk significant issues were evaluated by the
inspectors:
the loss of all source range nuclear instruments during the testing of nuclear
instruments 3 and 4;
the disassembly and removal from service of both high pressure injection
pumps;
reactor coolant system draining to 54 inches and the implementation of the
developed contingency plan for the evolution; and
reactor coolant pump mechanical seal RTD replacement work.
Enclosure
9
b.
Findings
No findings of significance were identified. The risk categorization and the
implementation of the developed contingency plan for the reactor coolant system
draining activity was further discussed in 4OA5.1 of this report.
1R14
Personnel Performance During Nonroutine Plant Evolutions (71111.14)
.1
a.
Inspection Scope
The inspectors reviewed operations personnel conduct during the filling of the circulating
water system to determine if the evolution was conducted in a safe and conservative
manner. The inspectors reviewed TSs, operations procedures, and facility
administrative procedures to determine the acceptance criteria for the inspection.
b.
Findings
Introduction: A Green self-revealing Non-Cited Violation of Technical Specification 6.8.1.a was identified for failing to properly implement system procedures during the
filling of the circulating water system. As a direct result of three drain valves being
improperly left open during the system fill, approximately three inches of water
deposited on the 565 elevation of the turbine building.
Description: On May 12, 2003, System Procedure DB-OP-0632, Attachment 1,
Circulating Water System Fill Valve Checklist, was completed as part of the
preparations for filling the circulating water system. The general timeline of the event
was as follows:
5/15/03 (21:00):
conducted a brief for filling the circulating water
system
5/16/03 (00:05):
commenced filling the circulating water system
5/16/03 (00:40):
increased fill rate
5/16/03 (01:49:06):
west condenser pit sump level high level alarm in
5/16/03 (01:49:12):
west condenser pit sump level high level alarm
clear
5/16/03 (02:01:15):
west condenser pit sump level high level alarm in
5/16/03 (02:01:30):
west condenser pit sump level high level alarm
clear
5/16/03 (02:04:56):
west condenser pit sump level high level alarm in
5/16/03 (02:13:34):
west condenser pit sump level high level alarm
clear
5/16/03 (02:23:34):
Bus 2 DC system ground alarm in
5/16/03 (02:36):
Electrician reports water on 565 foot elevation of
turbine building. Operators dispatched to
investigate find CT50 [HP Condenser 1 Water Box
- 1 Inlet Drain Valve] and CT51 [LP Condenser 2
Water Box #1 Outlet Drain Valve] open. The
Enclosure
10
operators placed the valves in their required
position (closed).
5/16/03 (02:47):
stopped filling the circulating water system;
5/16/03 (06:07):
A valve lineup of the circulating water valves in the
condenser pit revealed an additional valve, CT17
[HP Condenser 1 Water Box #1 Drain Valve] was
also open.
The three 8-inch rising stem gate valves, CT17, CT50, and CT51, were required to be
closed and were signed for as being in that position on DB-OP-0632, Attachment 1,
Circulating Water System Fill Valve Checklist, prior to commencing the circulating
water system fill.
The Equipment Operator that performed the circulating water system valve lineup was
interviewed as part of an apparent cause evaluation for this event. Information gained
from this interview included:
the operator had successfully closed CT16, CT14, and CT13 (the same
type of rising stem gate valves as CT17, CT50, and CT51);
after unsuccessfully attempting to close CT17, CT50 and CT51, the
operator did not ask for assistance in closing the valves; and
even though he was unsure about the position of the three drain valves,
he initialed the Circulating Water System Fill Valve Checklist for the
valves being closed without first elevating his concern to his supervisor.
Operations Administrative Instruction DB-OP-01002, Component Operation and
Verification, Revision 00, a safety related procedure, provided direction and guidance
for the manipulation of components for the purposes of system operation, lineup,
verification, and testing. Some specific guidance given by this procedure included:
When performing manual valve manipulations, they shall be performed
with sufficient force to ensure the valve is in the proper position;
To check a manual valve or stop check valve closed, attempt to move
the valve handwheel in the closed direction; and
Verifying the valve in the proper position would consist of first checking
the current position as described above and then repositioning the valve
to the desired position if needed. Other methods to confirm desired
position should be used when available such as remote valve position
indicator, stem position, local valve position indicator, and process
variables.
The Equipment Operator did not effectively implement the guidance for conducting valve
lineups contained in DB-OP-01002 or demonstrate a proper questioning attitude as
outlined in the Davis-Besse Business Practice DBBP-OPS-0001, Operations
Expectations and Standards, Revision 04.
Enclosure
11
Administrative Procedure DB-OP-0000, Conduct of Operations, Revision 06, a safety
related procedure, states that Operations personnel shall be alert for any unusual
trends in plant parameters, early signs of abnormal situations, and ensure the Control
Room and supervision are notified. Even though the crew had been briefed and the
Control Room staff knew that potential for flooding existed during the fill of the
circulating water system, they took no specific actions to investigate the cause of
several west condenser pit high level alarms, which occurred in a short period of time. It
wasnt until a field electrician notified the Control Room of the water on the floor in the
condenser pit area, that action was taken to investigate the problem. The control room
staff did not demonstrate a proper questioning attitude as outlined in the Davis-Besse
Business Practice DBBP-OPS-0001, Operations Expectations and Standards,
Revision 04.
Analysis: In accordance with IMC 0609, Appendix A, Attachment 1, the inspectors
performed a SDP Phase 1 screening and determined that the issue affected the
Initiating Events Cornerstone. The finding was more than minor because it: (1) involved
the configuration control attribute of the Initiating Event Cornerstone; and (2) affected
the cornerstone objective of limiting the likelihood of those events that upset plant
stability and challenge critical safety fuctions during shutdown as well as power
operations. The finding was of very low safety significance because the event was
terminated prior to actual loss of a equipment important to plant safety.
Enforcement: The performance deficiency associated with this event is the failure to
correctly implement procedures required for plant operation. Technical Specification 6.8.1.a requires implementation of procedures required by Regulatory Guide 1.33.
Regulatory Guide 1.33 requires procedures for General Plant Operation. The licensee
developed DB-OP-06232, Circulating Water System and Cooling Tower Operation,
Revision 05, a procedure affecting quality, to, in part, provide instructions on filling the
circulating water system. Contrary to the requirements of Technical Specification 6.8.1.a, System Procedure DB-OP-0632, Attachment 1, Circulating Water System Fill
Valve Checklist, was completed with three drain valves left in the incorrect (open)
position. As a result, approximately three inches of water flooded the 565' elevation of
the turbine building. Because of the very low safety significance and because the issue
has been entered into the licensees corrective action program (CR 03-03815) it is being
treated as a Non-Cited Violation, consistent with Section VI.A of the NRC Enforcement
Policy (NCV 50-346/03-015-03).
.2
High Pressure Injection Pump 1 Enhanced Baseline Testing in Piggyback Mode
a.
Inspection Scope
The inspectors reviewed operations personnel conduct during the development and
implementation of Special Test Procedure DB-SP-10030, HPI Pump 1 Mode 5
Enhanced Baseline Testing in Piggyback Mode. The test was developed to collect data
relevant to the validation of rotordynamics analysis modeling and associated post
accident condition of the rotating assembly of the high pressure injection pumps. This
test was conducted utilizing a modified rotating element which had increased wearing
ring clearances to simulate degrade pump conditions. The inspectors verified that the
required procedure reviews and safety screening were performed and were adequate,
Enclosure
12
that the required plant conditions were maintained to support the test, and that
operations personnel conducted the evolution in a safe and conservative manner.
b.
Findings
No findings of significance were identified.
.3
Reactor Coolant Drain from level of 80 inches to 54 inches above hot leg
a.
Inspection Scope
The inspectors reviewed operations personnel conduct during the drain and venting of
the reactor coolant system (RCS) work in preparation for work on reactor coolant pump
seal package resistance temperature detectors (RTDs). The license had identified the
draining evolution as placing the plant in an orange risk condition and had developed a
contingency plan for the period of time spent in an orange risk plant configuration. The
RCS had previously been drained to approximately 80 inches above the centerline of the
RCS hot leg loop. Work on the RTDs required draining to 54 inches or less and venting
the reactor coolant pump seal package to break the vacuum created in reactor coolant
pump to minimize potential adverse siphon effects that could be caused by the vacuum.
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors selected condition reports (CRs) which discussed potential operability
issues for risk significant components or systems. These CRs were evaluated to
determine whether the operability of the components or systems was justified. The
inspectors compared the operability and design criteria in the appropriate sections of the
Technical Specifications and USAR to the licensees evaluations presented on the
issues listed below to verify that the components or systems were operable. Where
compensatory measures were necessary to maintain operability, the inspectors verified
that the measures were in place, would work as intended, and were properly controlled.
The issues evaluated were:
Operability Evaluation 2002-0023, Revision 3 (addressed safety related
components cooled by non-safety ventilation in the high voltage switchgear
rooms and auxiliary shutdown panel room);
Operablity Evaluation 2003-0009, Revision 1 (addressed emergency diesel
generator low frequency and low voltage during safety features actuation loading
conditions); and
Operability Evaluation 2002-0039, Revision 2 (addressed emergency diesel
generator maximum room temperature).
Enclosure
13
b.
Findings
No findings of significance were identified.
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors witnessed the following surveillance test and evaluated test data to verify
that the equipment tested met TSs, USAR, and licensee procedural requirements, and
also demonstrated that the equipment was capable of performing its intended safety
functions. The activity was selected based on its importance in verifying mitigating
system capability. The inspectors used the documents listed at the end of this report to
verify that the test met the TS frequency requirements; that the test was conducted in
accordance with the procedures, including establishing the proper plant conditions and
prerequisites; that the test acceptance criteria were met; and that the results of the test
were properly reviewed and recorded.
The following test was observed and evaluated:
CC-1467, Component Cooling Water From DH Removal Cooler 1-1 Outlet Valve,
Timing Test.
b.
Findings
No findings of significance were identified.
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed Temporary Modification 03-016, Install a Temporary
Jumper to Pressurize EDG 2 Receiver 2-1 and Receiver 2-2 directly from EDG
Air Compressor 2 During Cross-tie Piping Work, to verify that the modification
did not affect the safety functions of risk significant safety systems. This
temporary modification was put in place to maintain a reliable source of starting
air for emergency diesel generator 2 while modifications were performed on the
emergency diesel 1 air start compressors and piping.
The inspectors reviewed Temporary Modification 03-017, Second Stage Seal
Temperature on RCP1-2."
The inspectors reviewed these temporary modification and associated
10 CFR 50.59 screenings against system requirements, including the USAR and
TS to determine if there were any effects on system operability or availability and
to verify temporary modification consistency with plant documentation and
procedures.
Enclosure
14
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA3 Event Followup (71153)
.1
(Discussed) Licensee Event Report (LER) 50-346/03-002: Potential Degradation of High
Pressure Injection (HPI) Pumps Due to Debris in Emergency Sump Fluid Post Accident
a.
Inspection Scope
The inspectors reviewed LER 2003-002, which documented an issue in which debris
from the containment sump would impact the high pressure injection (HPI) pumps,
following a design basis accident, whereby the pump internals would be damaged to the
extent that would impact the pumps ability to complete their intended safety function.
b.
Findings
Introduction: An apparent violation of 10 CFR Part 50, Appendix B, Criterion III, Design
Control," was identified for the failure to adequately implement design control measures
for verifying and checking the adequacy of the original design of the HPI pumps for all
postulated accidents.
Description: On October 22, 2002, with the reactor defueled, the licensee identified a
deficiency regarding the internal clearances of the HPI pumps ability to pass debris or
particles that may be entrained in the process fluid during some post accident scenarios.
Specifically, it was determined that the pumps internal openings that supplied
lubricating water flow to the hydrostatic bearing were smaller than the ECCS sump
screen openings. Certain reactor accident scenarios required the HPI pump (via the low
pressure injection pump) to pump water that had collected in the containment ECCS
sump and inject it back into the reactor coolant system. It was during this mode of
operation that the potential existed for debris from the sump, to be transported to the
HPI pump and cause blockage of lubricating water to the hydrostatic bearing.
On April 7, 2003, the licensee reported this deficiency to NRC. Subsequently, on
May 5, 2003, the licensee submitted a 10 CFR 50.73 report, which documented this
issue. The report was submitted pursuant to the following reporting requirements:
as a condition that could have prevented the fulfillment of the safety
function of a system needed to maintain the reactor in a safe condition
and remove residual heat;
as a single condition that caused two independent trains to become
inoperable in a single system designed to remove residual heat; and
as a condition that resulted in the nuclear power plant being in an
unanalyzed condition that significantly degraded plant safety.
Enclosure
15
The licensee planned to replace or modify both of the HPI pumps, prior to restart, to
eliminate the potential for blockage of cooling water to the HPI hydrostatic bearings
during the piggyback mode of operations utilizing water from the containment ECCS
sump.
Analysis: In accordance with IMC 0609, Appendix A, Attachment 1, the inspectors
performed a SDP Phase 1 screening and determined that the issue affected the
Mitigating Systems Cornerstone. The finding is more than minor because it: (1) involves
the design control attribute of the Mitigating Systems cornerstone; and (2) affects the
cornerstone objective of ensuring the availability, and capability of systems that respond
to initiating events to prevent undesirable consequences. The inspectors evaluated the
significance of this issue using IMC 0609, Appendix A, Significance Determination of
Reactor Inspection Findings for At-Power Situations." Because the finding described
above represented an actual loss of safety function of the HPI system, a Significance
Determination Process Phase 2 analysis was required. The inspectors utilized SDP
worksheets for the Davis-Besse Nuclear Power Station to perform a Phase 2 evaluation
of the finding. The finding was determined to have potential safety significance greater
than very low safety significance. Although the facility operated with this deficiency prior
to entering the current extended shutdown, the finding was not an immediate safety
concern because the HPI pumps are not required to support the current operational
Mode of the reactor plant. The finding is unresolved pending completion of a final
significance determination.
Enforcement: The performance deficiency associated with this event is the failure to
correctly implement design control measures for verifying the adequacy of the original
design for the HPI pumps to mitigate all postulated accidents. 10 CFR 50, Appendix B,
Criterion III, Design Control, requires, in part, that measures shall be established to
assure that the design basis for safety-related functions of structures, systems, and
components are correctly translated into specifications, drawings, procedures, and
instructions. Further, Criterion III requires that the design control measures shall
provide for verifying and checking the adequacy of design. Contrary to the above, the
licensee failed to adequately implement design control measures for verifying and
checking the adequacy of the original design of the HPI pumps. Pending determination
of the findings final safety significance, this finding is identified as URI 50-346/03-15-04,
Potential Inability for HPI Pumps to Perform Safety Related Function.
.2
(Discussed) Licensee Event Report (LER) 50-346/02-005-00, 50-346/02-005-01,
50-346/02-005-02: Potential Clogging of the Emergency Sump Due to Debris in
Containment
a.
Inspection Scope
The inspectors reviewed LER 2005-002, and subsequent revisions, which documented
an issue involving the potential clogging of the emergency sump by debris generated
during specific reactor accidents.
Enclosure
16
b.
Findings
Introduction: A apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI,
Corrective Action," was identified was identified for the failure to effectively implement
corrective actions for design control issues related to deficient containment coatings,
uncontrolled fibrous material, and other debris. This deficiency resulted in the inability of
the emergency core cooling system sump to perform its safety function under certain
accident scenarios due to clogging of the sump screen.
Description: On September 4, 2002, with the reactor defueled, the licensee determined
that the existing amount of unqualified containment coatings and other debris (e.g.,
fibrous insulation) inside containment could have potentially blocked the emergency
sump intake screen, rendering the sump inoperable following a loss of coolant accident.
The unqualified coatings and fibrous insulation had existed since original construction.
The licensee declared the emergency sump inoperable and entered the deficiency into
their corrective action program. With the emergency sump inoperable, both
independent emergency core cooling systems (ECCS) and both containment spray (CS)
systems are inoperable, due to both requiring suction from the emergency sump during
the recirculation phase of operation. This could prevent both trains of ECCS from
removing residual heat from the reactor and could prevent CS from removing heat and
fission product iodine from the containment atmosphere.
The licensee reported this information in LER 2002-05 on November 4, 2002. On
December 11, 2002, the licensee submitted Supplement 1 in which the licensee stated
that a debris generation and transport analysis would be performed. In Supplement 2
dated May 21, 2003, the licensee indicated that the debris generation and transport
analysis would be provided. Subsequently, on May 28, 2003, the licensee informed the
NRC that the analyses would not be performed. The licensee determined that further
review efforts for past significance of these issues was not justified.
The licensee obtained information on at least two occasions prior to issuance of the LER
that should have alerted them to the problem. First, a 1976 letter from Babcock and
Wilcox (B&W) informed Toledo Edison that B&W had no data regarding design basis
accident testing for particular coatings. The equipment coated with unqualified paint
identified in the letter included the reactor coolant pump motors, reactor vessel, steam
generators, pressurizer, and reactor coolant system piping. Second, NRC Generic Letter 98-04, "Potential for Degradation of the Emergency Core Cooling System and the
Containment Spray System after a Loss-of-Coolant Accident Because of Construction
and Protective Coating Deficiencies and Foreign Material in Containment," dated
July 14, 1998, was issued to operating reactors requesting information about the
potential effects of containment coating deficiencies. The licensee initiated several
Condition Reports (CRs) to address this issue, including CR 03-01718, Update
Response to Generic Letter 98-04; Protective Coatings in Containment, CR 03-03609,
Component Protective Coatings Not DBA Qualified, and CR 02-02846, Containment
Emergency Sump Issues.
Enclosure
17
Analysis:
Phase 1 Screening Logic, Results and Assumptions
In accordance with IMC 0612, Appendix B, the inspectors determined that the
issue was of more than minor safety significance because if left uncorrected, it
could become a more significant safety concern. The potential loss of low
pressure recirculation due to sump strainer clogging represents a potential loss
of the mitigation for medium and large sized LOCAs.
In accordance with IMC 0609, Appendix A, Attachment 1, the inspectors
performed a SDP Phase 1 screening and determined that the issue affected the
Mitigation Systems Cornerstone. Specifically, the issue represented an actual
loss of a safety function (i.e., low pressure recirculation), thus an SDP phase 2
analysis was required. The actual loss of low pressure recirculation was
assumed to occur upon initiation of sump recirculation following a medium or
large LOCA.
Phase 2 Risk Evaluation
In accordance with IMC 0609, Appendix A, Attachment 1, the inspectors
performed a SDP phase 2 analysis using Revision 1 to the licensees site
specific risk-informed inspection notebook. Only the worksheets for medium and
large LOCA were evaluated because it was assumed that these were the only
initiating events that could result in the transfer of unqualified coatings and other
debris to the containment sump. During the Phase 2 evaluation, the inspectors
assumed that there was a total loss of low pressure recirculation (i.e., loss of
LPR function) caused by the loss in net positive suction head (NPSH) to the low
pressure injection pumps. The loss of NPSH was assumed to be the result of
paint and other debris (e.g., piping insulation) clogging the containment sump
intake strainer. This condition existed for greater than 30 days and no credit was
given for recovery of the clogged strainer.
Based on the Phase 2 SDP results, the issue was determined to be RED, which
is of high importance to safety. This preliminary finding represents a change in
the core damage frequency of greater than 1E-4 per reactor year of operation
(MLOCA - Medium Loss of Coolant Accident).
Comparisons with the licensees risk model indicated that the licensees
frequencies for the medium and large LOCAs are about one order of magnitude
lower than that assumed in the SDP Phase 2 result. The licensee used the
initiating event frequencies identified in NUREG/CR-5750, Rates of Initiating
Events at U.S. Nuclear Power Plants, which is commonly used in most licensee
PRAs. Differences in the LOCA initiating event frequencies result in the
worksheets being somewhat conservative by about one order of magnitude.
Enclosure
18
Phase 3 Risk Evaluation
SPAR Analysis
Revision 3i of the Davis-Besse SPAR model was used for the SPAR analysis.
When the conducting the analysis, there were three primary considerations. The
first was the determination of which accident types to consider. The analysis
was consistent with the SDP Phase 2 approach in that only the medium and
large LOCAs were considered as a primary means for transporting paint and
other debris to the containment sump. Other than the forces and environmental
conditions that would occur during the LOCAs, the actuation of containment
spray was also considered as a means to transport the debris to the containment
sump. It was assumed that containment spray would actuate during the medium
and large LOCAs. Although it does not appear reasonable that small LOCAs
and other transients should be considered in the analysis due to the lack of
debris transport to the sump, all accidents requiring the use of high pressure
recirculation (i.e., piggyback mode of ECCS operation) were considered.
The second consideration was determination of the appropriate failure probability
of the sump. The basic event of interest in the SPAR model is named HPR-
SMP-FC-SUMP and has a failure probability of 5E-5. The licensees value is
2.2E-5. Based on the increased likelihood of sump clogging due to the
performance deficiency, these probabilities were not considered to be
appropriate. The SPAR model probability was therefore adjusted based on
information provided in NUREG/CR-6771, GSI-191, The Impact of Debris
Induced Loss of ECCS Recirculation on PWR Core Damage Frequency. This
NUREG was appropriate for this analysis because it studied the performance of
an industry wide cross section of PWR containments and the Davis-Besse
containment is within the bounds of this study. This NUREG suggests much
higher failure probabilities for the sump than used in previous PRA studies.
Numerous factors were considered in the GSI-191 study which have an impact
on the failure probabilities postulated. These factors include such information as
sump strainer surface area, NPSH margin, ECCS flow rates, containment spray
actuation setpoint, amount of insulation material in containment, etc. For this
analysis, however, no attempt was made to vary the qualitative failure
probabilities described in Table 4.1 of GSI-191 based on plant specific
information at Davis-Besse. Rather, failure probabilities from Table 4.1 were
assigned based on a qualitative understanding of the increased likelihood of
sump clogging due to the large amount of unqualified coatings in containment,
the as-found degraded condition of peeling coatings, and the transfer of those
coatings and other debris to the sump during the accidents evaluated.
Therefore, for the purposes of this analysis, a failure probability of 0.9 was used
for the best estimate result for the large LOCA. This probability is considered as
a likely occurrence in GSI-191. For the medium LOCA, a failure probability of
0.5 was selected. This probability is considered fully possible. For small
LOCAs and other transients, a sump failure probability of 0.1 was used. This
probability is characterized as unlikely in GSI-191. Note that these probabilities
are several orders of magnitude higher than the nominal failure probability in the
SPAR model and licensees data bases. This is considered conservative and is
Enclosure
19
appropriate due to the lack of an actual transport analysis (The licensee has no
plans to perform a detailed transport analysis which would likely refine some
conservative assumptions made in this analysis). In order to bound the analysis,
the loss of low pressure recirculation during medium and large LOCAs and loss
of high pressure recirculation during small LOCAs and other transients was
assumed to occur by adjusting the failure probability to True or 1.0 (guaranteed
failure). These results are presented below.
The third consideration was whether recovery credit should be applied to the
clogged sump strainer. During the event, it is reasonable to conclude that
operators would become aware through annunciation and pump performance
monitoring that a problem with the low pressure ECCS pumps had occurred. It is
possible that operators could reduce flowrates or stop the pumps when
indications of a loss of NPSH had occurred. However, without a thorough review
of operating procedures and related training, it would be difficult to understand
the probability of non-recovery of the loss or impending loss of low pressure
injection during the recirculation phase of ECCS injection. Also, it is reasonable
to conclude that operators may be hesitant to shutdown the low pressure
injection pumps or reduce their flow under LOCA conditions, especially the large
LOCA. Therefore, for this analysis, no credit was given for recovery of the
clogged sump strainer on the loss of the low pressure injection pumps.
SPAR Analysis Results
The results below reflect the change in the core damage frequency from the
base case model with the sump failure probability at 5E-5 subtracted from results
with the sump failure probabilities as noted.
Best Estimate SPAR Analysis Results
Large LOCA (sump failure probability set to 0.9)
5.13E-10/hr x 8760 hrs = 4.50E-6
Medium LOCA (sump failure probability set to 0.5)
2.28E-9/hr x 8760 hrs = 2.00E-5
Other Accidents (e.g., small LOCA, transients, etc.) Requiring High Pressure
Recirculation (sump failure probability set to 0.1)
2.15E-9/hr x 8760 hrs = 1.88E-5
Combined Large and Medium LOCA Results With Other Accidents
2.45E-5 + 1.88E-5 = 4.33E-5 (Yellow)
Based on the SPAR model results presented above, the finding is in the mid
Yellow range of importance.
Bounding SPAR Analysis Results
Enclosure
20
Results with Sump Failure Probability Set to 1.0 for Both Medium and Large
(5.70E-10/hr x 8760 hrs) + (4.57E-9/hr x 8760 hrs) = 4.50E-5
Results with Sump Failure Probability Set to 1.0 for Other Accidents Requiring
High Pressure Recirculation
2.64E-8/hr x 8760 hrs = 2.31E-4
Combined LOCA Results with Other Accidents
4.50E-5 + 2.31E-4 = 2.76E-4 (RED)
RAW Calculation (provided by licensee)
Davis-Besse baseline CDF = 1.22E-5/yr (includes internal plant flooding)
RAW value for failure of sump strainer for large and medium LOCAs = 1.41 and
4.27 respectively. RAW value for small LOCA and all other accidents = 9.18
1.22E-5/yr x 1.41 (LLOCA RAW) = 1.72E-5/yr
1.72E-5/yr - 1.22E-5/yr = 5.00E-6/yr (delta CDF for LLOCA)
1.22E-5/yr x 4.27 (MLOCA RAW) = 5.21E-5/yr
5.21E-5/yr - 1.22E-5/yr = 3.99E-5/yr (delta CDF for MLOCA)
1.22E-5/yr x 9.18 (SLOCA and Other Accidents) = 1.12E-4
1.12E-4/yr - 1.22E-5/yr = 9.98E-5/yr (delta CDF for SLOCA and Other Accidents)
Total Delta CDF for All Accidents
5.00E-6/yr + 3.99E-5/yr + 9.98E-5/yr = 1.45E-4 (RED)
Although the total delta CDF is in the low RED range of importance assuming a
complete failure of the containment sump under all conditions requiring low and
high pressure recirculation, this result is not representative of the significance of
the finding. As mentioned earlier, the likelihood of debris transport during a
small LOCA and during other accidents is much less likely. This bounding
analysis provides the worst possible result using the PRA results provided by the
licensee and those in the SPAR model. Note that the results from both the
SPAR model and licensee model are very similar. This similarity provides a
validation of the results and provides reasonable assurance of the significance of
the finding when making the assumptions presented.
Internal plant flooding is a relatively low contributor to the total CDF. The IPE
states that the overall contribution is about 3%. Since the IPE submittal, the
updated overall Davis-Besse PRA model results have been reduced, therefore
the current internal flooding contribution is about 15% of the total CDF. A large
percentage of this risk is associated with flooding and subsequent failure of all
service water or component cooling water pumps resulting in a LOCA condition
Enclosure
21
due to failure of the reactor coolant pump seals. Given that a seal failure and
subsequent small LOCA occurs, the need for feed and bleed requires the use of
high pressure recirculation to maintain the core cooled. When feed and bleed is
placed in service, the resulting letdown of coolant inventory is drained to the
containment sump. As discussed previously, this mechanism of debris transport
is not as likely as during medium and large LOCAs. Based on the relatively low
contribution from internal flooding and the lower likelihood of debris transport
during feed and bleed operation, it is judged that the impact from flooding is not
significant and would not change the overall significance of the finding.
Summary for Internal Events Analysis
The results of the SDP Phase 2 are conservative because the initiating event
frequencies for LOCAs assumed in the site specific notebook are higher by
about one order of magnitude than the licenses results. If these frequencies are
adjusted to coincide with the licensees frequencies, which are consistent with
NUREG/CR-5750, the SDP Phase 2 result would be in the Yellow range of
importance. This result would then match the SPAR analysis result and the
RAW values provided by the licensee. Because the licensee did not perform a
transport analysis, it is appropriate to use conservative failure probabilities for
sump failure. The values chosen in the SPAR analysis are significantly higher
than the base case value in the both the licensees PRA model and the SPAR
model. Increasing the sump failure probability from the 1E-5 range to the 1E-1
range and higher is appropriate due to the lack of information regarding the
transport of coatings and debris to the containment sump. In addition, the
information discussed in GSI-191 indicates that sump failure is likely to be more
important than previously analyzed.
The primary contributing events leading to the transport of debris and paint to the
containment sump are the medium and large LOCAs. Other accidents were
considered, such as small LOCAs and transients where high pressure
recirculation is needed to prevent core damage. Assuming a conservative failure
probability of 0.1 for these accidents resulted in an increase in the core damage
frequency in the Yellow range of importance using the revised SPAR model.
When this result was added to the primary LOCA contributors, the result
remained in the Yellow range of importance.
Although recovery of low pressure recirculation was not considered in this
analysis, the results would likely not decrease below the Yellow range of
importance because the non-recovery failure probability would likely be very high
(greater than 0.5). Applying this 0.5 non-recovery factor to the calculated SPAR
model result would still result in the finding being in the Yellow range (4.33E-5/yr
x 0.5 = 2.17E-5 - Yellow) .
It is estimated qualitatively that there is approximately one order of magnitude of
uncertainty with the final outcome of this analysis. The most uncertain aspect of
the evaluation is the failure probability of the sump during the various accident
types. Because the licensee did not perform a transport analysis, high
probabilities for sump failure were used. As discussed earlier, this is appropriate
Enclosure
22
for the purposes of the SDP process. As presented in the SPAR model
sensitivity calculations, the finding is in the Yellow range of importance. This
overall importance could be reduced given credit for recovery. It is judged,
however, that even if a non-recovery probability of 0.1 was applied that the
overall result would not reduce beyond one order of magnitude. Given the
performance deficiency related to the unqualified coatings and other debris and
recent information presented in GSI-191, the relatively high sump failure
probabilities are appropriate. The overall results of this analysis would be
reduced significantly if the sump failure probability was significantly less than
assumed in this analysis.
Potential Risk Contribution due to LERF
The impact of strainer clogging and subsequent loss of low pressure
recirculation and high pressure recirculation is not a significant contributor to
LERF.
Potential Risk Contribution due to External Events
IMC 609, Appendix A, Attachment 1, requires that that when any of the SDP
Phase 2 sequence result is greater than 1E-7 per year, that the finding be
evaluated for additional risk due to external event contribution. The evaluation
may be qualitative or quantitative. Considering the information reviewed from
the plants IPEEE and related documents, accounting for external events does
change the conclusion that the finding is Yellow.
Conclusion
The preliminary safety significance of the inspection finding based on the change
in CDF due to internal, external and LERF considerations is Yellow. A Yellow
finding is of substantial importance to safety
Enforcement: The performance deficiency is the licensees failure to effectively
implement corrective actions for design control issues related to deficient containment
coatings, uncontrolled fibrous material and other debris. This deficiency resulted in the
inability of the emergency core cooling system sump to perform its safety function under
certain accident scenarios due to clogging of the sump screen. 10 CFR Part 50,
Appendix B, Criterion XVI, "Corrective Actions," requires, in part, that measures shall be
established to assure that conditions adverse to quality such as failures, malfunctions,
deficiencies, deviations, defective material and equipment, and nonconformances are
promptly identified and corrected. In the case of significant conditions adverse to quality,
the measures shall assure that the cause of the condition is determined and corrective
action is taken to preclude repetition. Contrary to the above, the licensee failed to
effectively implement corrective actions for design control issues related to deficient
containment coatings, uncontrolled fibrous material and other debris. Pending
determination of the findings final safety significance, this finding is identified as
Apparent Violation (AV) 50-346/03-015-05.
Enclosure
23
4OA5 Other Activities
One of the key building blocks in the licensees Return to Service Plan was the
Management and Human Performance Excellence Plan. The purpose of this plan was
to address the fact that management ineffectively implemented processes, and thus
failed to detect and address plant problems as opportunities arose. The primary
management contributors to this failure were grouped into the following areas:
Nuclear Safety Culture;
Management/Personnel Development;
Standards and Decision-Making;
Oversight and Assessments;
Program/Corrective Action/Procedure Compliance.
The inspectors had the opportunity to observe the day-to-day implementation that the
licensee made toward completing Return to Service Plan activities. Almost every
inspection activity performed by the resident inspectors touched upon one of those five
areas. Observations made by the resident inspectors were routinely discussed with the
Davis-Besse Oversight Panel members and were used, in part, to gauge licensee efforts
to improve their performance in these areas on a day-to-day basis.
To better facilitate the inspection and documentation of issues not specifically covered
by existing inspection procedures, but important to the evaluation of the licensees
readiness for restart, the Special Inspection for Residents inspection plan was
developed and implemented. Inspection Procedure 93812, Special Inspection, was
used as a guideline to document these issues and remains in effect for future resident
inspection reports until a time to be determined by the Davis-Besse Oversight Panel.
The inspectors performed inspections, as required, to adequately assess licensee
performance and readiness for restart in the following area:
performance of plant activities, including maintenance activities;
follow-up of specific Oversight Panel Technical issues;
attended and assessed selected licensee restart readiness meetings;
evaluated licensee performance in categorizing, classifying, and
correcting deficient plant conditions during the restart process;
reviewed licensee controls, criteria, and assessed licensee performance
at meetings associated with work backlogs, including the deferral of work
orders, operator work arounds, temporary modifications, and permanent
modifications; and
reviewed activities associated with safety conscious work environment
and safety culture.
The following issues were evaluated during this inspection period.
.1
Inappropriately Lowering Shutdown Risk Category During Reduced Inventory
Operations
While refilling and prior to venting the reactor coolant system after reactor coolant pump
seal package resistance temperature detector work, the licensee incorrectly and
Enclosure
24
inadvertently lowered the risk category from orange (marginal shutdown safety) to
Yellow (adequate shutdown safety). This lowering of the risk category permitted
stopping some of the contingency plan actions that were in place for the orange risk
condition. The inadvertent lowering of the classification was not safety significant
because of the short time that the condition existed and all decay heat trains remained
available.
During the week of June 8, 2003, the licensee made preparations to drain the reactor
coolant system water level to 54 inches above the hot leg centerline for repair of leaks
from resistance temperature detectors located in the mechanical seal packages of the
reactor coolant pumps. In accordance with their procedures, the licensee analyzed the
risk of the draining evolution and determined that during a portion of the evolution, the
risk would transition from the existing Yellow category to the higher orange category.
The licensee developed a contingency plan for management actions during initial
draining activities and draining below 80 inches. The contingency plan required, during
orange risk configurations, various items including protecting from unnecessary work
both trains of decay heat removal equipment. If work were permitted in the rooms
housing decay heat removal equipment, the contingency plan also required than an
operator had to be present in those rooms.
On June 13, 2003, at 9:53 a.m., management permission was given to enter orange risk
during the drain. At 1:41 p.m. the plant activated the contingency plan for orange risk
condition. On June 14, 2003, at 5:03 p.m. the drain to 54 inches was completed. On
June 15, 2003, at 5:27 p.m. the reactor coolant system had been refilled to 80 inches.
At that time a log entry records that due to commencing the fill to 250 inches in the
pressurizer, the plant exited the orange risk category and entered Yellow risk. On June
16, 2003, at approximately 5:00 a.m., it was determined that the plant should have
remained in an orange risk category and, at 7:45 a.m., the orange risk contingency
action plan was reestablished. During the period that orange risk condition was required
but was not established, one decay heat train had been made unprotected from
unnecessary work. The licensee documented the incorrect application of risk in a
condition report. At 4:40 p.m., the licensee had completed all actions to exit from the
orange risk condition and return to the Yellow risk condition.
Because of lack of clear directions to the operating shifts and a shutdown risk procedure
with some provisions clearly understood only by a limited number of operations
personnel, the operations shift, on June 15, 2003, exited orange risk conditions, contrary
to existing procedural requirements, for a period of approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />. For a
period of that time, contingency plan requirements, designed to minimize the potential to
lose shutdown cooling during the elevated risk condition, were relaxed.
.2
Negative Trend in the Number of Engineering Change Request Administrative Errors
On June 28, 2003, the licensee wrote condition report (CR) 03-05092 to document that
numerous administrative deficiencies had been discovered during document
managements acceptance review of engineering change packages and to provide a
mechanism to review a trend of deficiencies. The CR listed 25 other CRs that were
written to document administrative deficiencies.
Enclosure
25
The inspectors separately conducted a review of the CR system for identified
discrepancies in engineering change requests. The intent of the review was to verify
that there were not other adverse trends associated with engineering change requests
and to verify that the licensee had properly characterized the adverse trend. The review
identified 25 condition reports, covering the period of October 25, 2002 through June 25,
2003, that identified problems in engineering change packages. Many of the licensee
identified CRs were the same as those independently identified by the inspectors. The
majority of the problems identified were administrative in nature and were judged by the
inspectors to indicate a lack of attention to detail in the existing process as detailed in
licensee procedures. The inspectors did not identify any condition report in which the
documented error had impacted a design change had been installed and accepted in
the plant.
The inspectors did identify that CR 02-08642 had identified, on October 25, 2002,
administrative errors in the engineering change process after implementation of a
process change in the design interface review. The CR stated that the issue was
already being addressed through the completion of lesson learned training identified in
CR 02-09694. The inspectors met with licensee representatives to review similarities
between the new trend and the previously identified issue and, if the conditions were
similar, the impact of the lesson learned training. That licensee stated that the problem
identified in CR 02-08642 was directly related to the implementation of a then recent
process change and the formulated corrective action was not targeted to generic
administrative errors as identified in the CR 03-05092.
Administrative errors in engineering change packages have been identified in condition
reports as an recurring problem. Recurring administrative errors can be an indicator of
inattention to detail which may extend beyond just administrative details. The licensee
had indications of ongoing administrative problems prior to the initiation of CR 03-05092,
but until this CR reviewed many of identified problems as independent events.
.3
Classification, Categorization, and Resolution of Restart Related Issues
The resident inspectors continued to monitor the licensee activity related to properly
classifying, categorizing and resolving their backlog of work orders, corrective actions,
and modifications required to be completed prior to transitioning to Mode 4. To
accomplish this, the inspectors:
attended and assessed licensee management meetings;
monitored the management of open Mode 4 and 3 restraints;
evaluated the licensee classification of emergent deficient conditions; and
evaluated closed mode restraints.
As part of this inspection, the inspectors attended selected Corrective Action Review
Board meetings, Senior Management Team meetings, Scheduling meetings,
Management Review Board meetings, and Restart Oversight meetings, where
classification of condition reports, prioritization of work activities, and setting of work
completion dates took place. The inspectors also evaluated a sampling of completed
Mode 4 and Mode 3 resolution forms.
Enclosure
26
No significant issues were identified.
.4
Safety Conscious Work Environment (SCWE) and Safety Culture Observations
The inspectors continued to evaluate, on a day-to-day basis, the impact that scheduling
has on quality of work and safety conscience work environment. The inspectors
performed this evaluation when they attended the following meetings:
Emergency Diesel Generator (EDG) air start modification scheduling meeting,
June 5, 2003; and
Safety Conscious Work Environment Review Team, June 12, 2003.
No significant issues were identified.
4OA6 Meetings
Exit Meeting
The inspectors presented the inspection results to Mr. Lew Myers, and other members
of licensee management on July 9, 2003. The licensee acknowledged the findings
presented. No proprietary information was identified.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance was identified by the licensee and
is a violation of NRC requirements which meet the criteria of Section VI of the NRC
Enforcement Manual, NUREG-1600, for being dispositioned as a NCV.
Technical Specification 6.8.1.a requires implementation of procedures required
by Regulatory Guide 1.33. Regulatory Guide 1.33 requires procedures for
maintenance which can affect the performance of safety-related equipment. The
licensee developed Procedure DB-MN-00001, Conduct of Maintenance,
Revision 10, a procedure affecting quality, to provide general guidance for the
conduct of maintenance at the Davis-Besse facility. Additionally, the licensee
developed Procedure DB-MM-09173, High Pressure Injection Pump
Maintenance, Revision 04, which provided instructions for the disassembly,
inspection, cleaning, repair, and reassembly of the high pressure injection
pumps. Contrary to the requirements of DB-MN-00001, step 6.1.6.a, the
calibration of the equipment utilized to torque the casing bolt nuts for the high
pressure injection pump 1 was not checked prior to use. As a result, during the
performance of DB-MM-09173, step 8.7.57, the desired torque on the casing bolt
nuts was exceeded by approximately 77 ft-lbs. This issue has been entered into
the licensees corrective action program (CR 03-04430). This issue was also
discussed in Section 1R12 of this report.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment
1
ATTACHMENT: SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
M. Bezilla, Site Vice President
G. Dunn, Outage Manager
R. Fast, Director, Organizational Development
J. Grabnar, Manager, Design Engineering
K. Ostrowski, Manager, Regulatory Affairs
L. Myers, Chief Operating Officer, FENOC
J. Powers, Director, Nuclear Engineering
M. Roder, Manager, Plant Operations
R. Schrauder, Director Support Services
M. Stevens, Director, Maintenance
Attachment
2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-346/03-015-04
Potential Inability for HPI Pumps to Perform Safety Related
Function
50-346/03-015-05
Failure to Effectively Implement Corrective Actions for Design
Control Issues Related to Deficient Containment Coatings,
Uncontrolled Fibrous Material and Other Debris
Opened and Closed
50-346/03-015-01
Failure to Provide Adequate Procedural Guidance for
Tightening Fasteners Internal to the High Pressure Injection
Pump
50-346/03-015-02
Failure to Perform Work in Accordance With Approved
Maintenance Procedures During the Installation of Reactor
Coolant Pump Mechanical Seal RTDs
50-346/03-015-03
Failure to Properly Implement System Procedures During the
Filling of the Circulating Water System
Discussed
50-346/03-002
LER
Potential Degradation of High Pressure Injection Pumps Due to
Debris in Emergency Sump Fluid Post Accident
50-346/02-005-00
50-346/02-005-01
50-346/02-005-02
LER
Potential Clogging of the Emergency Sump Due to Debris in
Containment
Attachment
3
LIST OF ACRONYMS
Agency-wide Document Access and Management System
Babcock & Wilcox
Core Damage Frequency
CFR
Code of Federal Regulations
CR
Condition Report
FirstEnergy Nuclear Operating Company
High Pressure Injection
Interim Compensatory Measures
IMC
Inspection Manual Chapter
Individual Plant Examination
IR
Inspection Report
LER
Licensee Event Report
Large Early-release Frequency
Loss of Coolant Accident
MLOCA
Medium LOCA
Non-cited Violation
Net Positive Suction Head
NRC
United States Nuclear Regulatory Commission
Publicly Available Records
Reactor Coolant Pump
Refueling Outage
Resistance Temperature Detector
Significance Determination Process
Standardized Plant Analysis Risk
TI
Temporary Instruction
TS
Technical Specifications
Unresolved Item
Updated Safety Analysis Report
Work Order
Attachment
4
LIST OF DOCUMENTS REVIEWED
1R01
Adverse Weather Protection
DB-OP-06913; Seasonal Plant Preparation Checklist, Revision 06
DB-OP-00005; Special Instructions and Expressions, Zone 1 Operations Tours;
Revision 8
1R05
Fire Protection
Fire Hazards Analysis Report
Fire Protection Drawings A-221F, A-222F, A-223F, A-224G,
1R12
Maintenance Effectiveness
High Pressure Injection Pump Night Shift Turnover Dated June 6, 2003
CR 03-04430 Cause Analysis Report; Use of Non-Calibrated Tools on HPI Pump 1
CR 03-04430; Use of Uncalibrated Tools
Order 200010574; Disassemble/Remove #1 HPI Pump Internals. Prepare for Shipment
to Vendor. Reassemble Pump With Replacement Rotating Element
DB-MN-00001; Conduct of Maintenance; Revision 10
DB-MM-09173; High Pressure Injection Pump Maintenance; Revision 04
CR 03-04278; Broken Bolting Found in High Pressure Injection Pump #1
CR 03-04279; FME Inside #1 HPI Pump
CR 03-04355; HPI Pump Internal Head Cover Shoulder Cap Screws
DB-MM-09173; High Pressure Injection Pump Maintenance; Revision 02
DB-MM-09173; High Pressure Injection Pump Maintenance; Revision 04
CR 03-04773; RCP RTD Installation Not in Accordance With Vendor Manual
Order 200000263; Rework the RTD/TC Connections (as required) for all three stages of
the RCP (1-1) Mechanical Seal
Order 200000274; Rework the RTD/TC Connections (as required) for all three stages of
the RCP (1-2) Mechanical Seal
Attachment
5
Order 200000279; Rework the RTD/TC Connections (as required) for all three stages of
the RCP (2-1) Mechanical Seal
Order 200000294; Rework the RTD/TC Connections (as required) for all three stages of
the RCP (2-2) Mechanical Seal
NG-DB-00225; Procedure Use and Adherence; Revision 12
DB-MN-00001; Conduct of Maintenance; Revision 10
DB-DP-00007; Control of Work; Revision 04
CR 03-0479; Leaking RTD on RCP 2-1
Problem Solving Plan for RCP RTD Leakage; dated 6/19/03
1R13
Maintenance Risk and Emergent Work
Contingency Plan 13RFO-32; All Source Range Nuclear Instruments Unavailable for
Testing; Revision 0
Unit Narrative Log; Dated 5/23/03
NOP-OP-1005; Shutdown Safety; Revision 3
Operations Directive GP-27; Shutdown Safety Assessment; Revision 2
Form NOP-OP-1005-02; Shutdown Safety Turnover Checklist; dated 6/3/03
Contingency Plan 13 RFO 21; Management Action for Orange Risk Level During Initial
RCS Draining Activities and Draining Below 80 Inches and Above 54 Inches; Revision 1
Davis-Besse Shutdown Safety Turnover Checklist; dated 6/13/03
Form NOP-OP-1005-02, Shutdown Safety Turnover Checklist; dated 6/16/03, 0500
Condition Report 03-04735; Plant Shutdown Safety Inadvertently Changed to Yellow
Unit Narrative Log; dated 6/13/2003 to 6/16/2003
1R14
Personnel Performance During Nonroutine Plant Evolutions
DB-OP-01002; Component Operation and Verification; Revision 00
DB-OP-00000; Conduct of Operations; Revision 06
DB-OP-06232; Circulating Water System and Cooling Tower Operation; Revision 05
DBBP-OPS-0001; Operations Expectation and Standards; Revision 04
Attachment
6
Unit Narrative Logs dated 5/16/03
CR 03-03815; West Pit Flooding
Apparent Cause Investigation for CR 03-03815
Regulatory Applicability Determination 03-01124; HPI Pump 1 Mode 5 Enhanced
Baseline Testing in Piggyback Mode; Revision 00
DB-SP-10030; HPI Pump 1 Mode 5 Enhanced Baseline Testing in Piggyback Mode;
Revision 01
DB-OP-06012;Decay Heat and Low Pressure Injection System Operating Procedure,
Revision 09
NG-DB-00201; Conduct of Infrequently Performed Tests and Evolutions, Revision 01
NG-DB-00201; Attachment 1; Pre-evolution or test activities briefing form completed by
S. Wise; dated 6/14/2003
1R15
Operability Evaluations
Operability Evaluation 2002-0023; Revision 3
DP-OP-06513; Auxiliary Building Non-Radioactive Areas Ventilation
Operability Evaluation 2003-0009; Revision 01
Operability Evaluation 2003-0039; Revision 02
Past Operability Evaluation for CR 02-07596; LIR EDG High Room Temperatures
Overall Condition Report
Root Cause Analysis Report; EDG Room Ventilation Concerns; dated 04/15/03
1R22
Surveillance Testing
DB-PF-0371 CCW Train 1 Valve Testing, Revision 06
Routine Maintenance WO 200002377 as existing on 6/23/2003
1R23
Temporary Plant Modifications
Temporary Modification 03-016; Install a Temporary Jumper to Pressurize EDG 2
Receiver 2-1 and Receiver 2-2 directly from EDG Air Compressor 2 During Cross-tie
Piping Work
DB-OP-06316; EDG Operating Procedure; Revision 04
Attachment
7
Piping and Instrument Diagram M-017B; Diesel Generator Air Start Piping; Revision 32
Temporary Modification 03-017, Second Stage Seal Temperature on RCP1-2"
4OA3 Event Followup
CR 03-01718; Update Response to Generic Letter 98-04; Protective Coatings in
Containment
CR 03-03609; Component Protective Coatings Not DBA Qualified
CR 02-02846; Containment Emergency Sump Issues
Root Cause Analysis Report;Non-DBA Qualified Protecftive Coatings Applied Within the
Containment; dated 03/29/03
4OA5 Other Activities
CR 02-08642; Deficiencies identified in ECR 02-0658
CR 02-09694; EAB concerns with DIE process
CR-03-05092; Trending CR-engineering change packages
NOP-CC-2004; Design Interface Reviews and Evaluations, 6/2/2003