ML20216E762
| ML20216E762 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 03/12/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20216E728 | List: |
| References | |
| 50-382-97-25, NUDOCS 9803180143 | |
| Download: ML20216E762 (59) | |
See also: IR 05000382/1997025
Text
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGIOiiIV
Docket No.:
50-382
License No.:
Report No.:
50-382/97-25
Licensee:
Entergy Operations, Inc.
Facility:
Waterford Steam Electric Station, Unit 3
Location:
Hwy.18
Killona, Louisiana
Dates:
December 1,1997, through February 5,1998
Team Leader.
L. Smith, Senior Reactor Inspector, Engineering Branch
Inspectors:
C. Patel, Project Manager, PDIV-1
M. Runyan, Senior Reactor inspector, Engineering Branch
P. Goldberg, Reactor Inspector, Engineering Branch
D. Pereria, Reactor Inspector, Engineering Branch
R. Bywater, Reactor inspector, Engineering Branch
Contractors:
D. Tondi
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H. Anderson
Approved By:
Thomas F. Stetka, Acting Chief, Engineering Branch
Division of Reactor Safety
ATTACHMENT:
Supplemental Information
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9803180143 980319
ADOCK 05000582
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TABLE OF CONTENTS
EXECUTIVE SUMMARY . .
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11. Maintenance .
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M2
Maintenance and Material Condition of Facilities and Equipment
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M2.1 Control of Grounds on the Direct Current Distribution System . .
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Ill. Engineering . . .
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E1
Conduct of Engineering . .
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E1.1
Safety injection System Design Basis Calculations . .
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E1.2 Air-Operated and Hydraulic-Operated Valve Calculations . . . . . .
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E1.3 Hydrogen Generation Calculations . . . . . .
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E1.4
Low DC Voltage to Emergency Feedwater Pump Turbine Steam
Admission Valves . .
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E2
Engineering Support of Facilities and Equipment
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E2.1
Implementation of Emergency Core Cooling System Surveillance
Requirements . .
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E2.2 High Pressure Safety injection Flow Control Valve Replacements
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E2.3
10 CFR 50.59 Implementation . . .
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E3
Engineering Procedures and Documentation
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E3.1
Engineering Request Process
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E3.2 Design Bases Documentation - 125V DC Distribution System. . . .
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E3.3 Seismic Qualification Documentation - 125V DC Station Batteries . .
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E3.4 Environmental Qualification of the Static Uninterruptible Power Supply
(SUPS) .
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E4
Engineering Staff Knowledge and Performance
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E4.1
Interview of Staff Personnel .
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E6
Engineering Organization and Administration . .
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E6.1
Engineering Backlegs
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E7
Quality Assurance in Engineering Activities
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E7.1
Condition Report Review
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E8
Miscellaneous Engineering issues
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E8.1
(Closed) Inspection Followup Item 50-382/96202-01.
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E8.2 (Open) Inspection Followup item 50-382/9708-01
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E8.3 (Closed) Licensee Event Report 50-382/97-007.
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E8.4 (Closed) Licensee Event Report 50-382/97-015.
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E8.5 (Closed) Violation 50-382/9714-01 .
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V. Management Meetings
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X1 Exit Meeting Summary
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EXECUTIVE SUMMARY
Waterford Steam Electric Station, Unit 3
NRC Inspection Report 50-382/97-25
During the weeks of December 1 and December 14,1997, six NRC personnel and two
consultants conducted an engineering team inspection. Additionalinoffice inspection was
conducted through February 5,1998. A safety system engineering inspection was performed for
the high pressure safety injection system (HPSI). In addition, the team reviewed the design
basis for the 125V electrical distribution system and for safety-related hydraulic and air-operated
valves. The team also reviewed the status of various upgrade programs, which were planned or
in progress.
Although some unresolved issues existed at the conclusion of the inspection, the team did not
identify any inoperable equipment or systems. The team did identify six apparent violations that
focused on two major subject areas: the capability of the HPSI system to provide adequate
emergency core cooling and the licensee's interpretation and implementation of 10 CFR 50.59.
The HPSI issue was of concern because the facility was operated from July 28 through
December 17,1997, in a condition that would have been prohibited, as determined by the
licensed emergency core cooling system analysis. This issue also involved several related
concerns about prioritization of corrective action activities, the effectiveness >f some corrective
actions, and test control. The 10 CFR 50.59 issue was of concern because the licensee had
apparently failed to perform a written safety evaluation in two instances and had apparently
authorized three changes to the facility, which involved unreviewed safety questions, prior to
obtaining NRC approval. In addition, one other violation was cited that involved the licensee's
failure to appropriately assess the implications of industry information and take appropriate
corrective action. The licensee did not identify the need to reanalyze the capability of Anchor-
Darling air- and hydraulic-operated gate valves when they realized that the assumed valve
factors were not conservative.
Strong points were also identified during the inspection. The licensee had previously identified
many of the issues, which were discovered by the team during the course of the inspection. The
discovery phase of the licensee's design basis review and calculation upgrade program was
effective for the safety injection system. Despite recent turnover, in general, the team found
licensee personnel to be knowledgeable of their equipment and systems. Material condition, as
it related to the operation of the 125Vdc system, was good.
higintenanc_e
The licensee effectively resolved long-term problems with electrical grounds by modifying
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junction box seals to prevent water intrusion. In addition, the licensee promptly corrected
electrical grounds as they occurred, resulting in good material condition (Section M2.1).
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Enaineerina
The discovery phase of the licensee's design basis review and calculation upgrade
program was effective for the safety injection system. The licensee had previously
identified issues that were independently identified by the team (Section E1.1).
The licensee took appropriate actions to establish and improve calculations for
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air-operated valves, but did not include safety-related hydraulic-operated valves in the
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scope of the calculation upgrade program (Section E1.2).
The licensee's evaluation of the applicability of NRC Information Notice 96-48,
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" Motor-Operated Valve Performance issues," was inadequate. The licensee did
not promptly initiate a condition report when they identified that main feedwater
isolation valve performance did not conform with the initial sizing calculation
assumptions for the valve. The failure to initiate a condition report was identified as
a violation of 10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures and
Drawings" (Section E1.2).
While the emergency feedwater pump turbine steam admission valves received low
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direct current voltage, the team agreed with the licensee that the valves were operable
(Section E1.4).
The team concluded that the emergency core cooling system surveillance procedures
were scheduled and implemented in accordance with the technical specification
requirements. The team noted that the schedules were in accordance with the
surveillance frequency requirements and that the acceptance limits of the technical
specification surveillance requirements were included in their respective surveillance
procedures. However, the team noted that uncertainties were not always being factored
into surveillance requirements (Sections E2.1, E2.2, and E8.1).
One apparent violation of 10 CFR Part 50, Appendix B, Criterion XI, " Test Control," was
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identified for the HPSI flow balance test related to the specification of test instrumentation
and the inclusion of valve position variability in the test acceptance limits. An additional
example was identified for the auxiliary component cooling water flow balance test
related to the inclusion of measurement uncertainty in the test acceptance limits
(Sections E2.2 and E8.1).
Two apparent violations of 10 CFR 50.46, " Acceptance Criteria for Emergency Core
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Cooling Systems for Light Water Nuclear Power Reactors," were identified. The first
involved the failure to assess the impact of the lower HPSI flow on peak fuel clad -
temperature. The second involved the failure to report operation outside the design
basis of the facility and the subsequent failure to submit the schedule for revising the
emergency core cooling system analysis within 30 days (Section E2.2).
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One apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action,"
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'was identified related to a failure to promptly correct the HPSI flow balance test
acceptance limit deficiency, following ident!fication of the issue in a self assessment
(Section E2.2).
Two apparent violations of 10 CFR 50.59, " Changes, Tests, and Experiments," were
identified. The first involved an apparent failure to perform a written safety evaluation.
The second involved approving three changes to the facility, which apparently involved
unreviewed safety questions, prior to obtaining NRC approval (Section E2.3).
The team found that the licensee had not completed the transition to the new
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engineering request process. The licensee satisfactorily resolved concerns identified by
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the team related to a review of 25 engineering requests (Section E3.1).
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The current seismic qualification of the Waterford 3 safety-related station batteries was
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acceptable. Seismic qualification from 15- to 20-years qualified life was not clearly
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established. The licensee initiated an engineering request to further evaluate the
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qualification of the batteries during this period (Section E3.3).
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The team noted an increasing backlog for the portions of the engineering request
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process that had been implemented However, the licensee had good control of the
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condition report backlog. Since May 1997, the condition report backlog has decreased
(Section E6.1).
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Reoort Details
insoection Obiectives
This inspection was performed to implement the core inspection program requirements, using
the Safety System Engineering inspection Procedure to review the high pressure safety
injection (HPSI) system. This system was selected because NRC had not recently reviewed the
system and because the licensee had conducted self-assessments on the system. In addition,
the team reviewed the design basis for the 125V electrical distribution system and for safety-
related hydraulic and air-operated valves. These support systems were selected because of
their risk significance. The inspection also included an evaluation of the licensee's control of
changes to the facility pursuant to 10 CFR 50.59, " Changes, Tests and Experiments." The team
also reviewed the status of various upgrade programs, which were planned or in progress.
This inspection also included regional ;nitiative inspection focused on naluating the licensee's
plans for upgrading the design and license bases for the facility. Prior to the inspection the
NRC performed an internal review of the licensee's response, dated February 6,1997, to the
NRC's 10 CFR 50.54(f) letter of October 9,1996. The NRC 50.54(f) letter requested currently
licensed nuclear generating facilities to submit specific information pertaining to their programs
and processes for ensuring operation in accordance with design, the availability and adequacy
of design basis information, and the effectiveness of such programs or processes for
maintaining operation within design. The licensee's response was reviewed by both regional
and program office personnel. The results of this review were presented to and discussed with
regional management, inspection specialists, and program office representatives who were
knowledgeable of the facility's regulatory performance and history as it relates to the availability
and use of design basis information. The followup recommended by this review was performed
during this inspection, as documented in Sections E1.1, E1.2, E1.3, E2.2, E2.3, E3.2, E3.3,
E3.4, E7.1, and E8.1.
II. Maintenance
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Control of Grounds on the Direct Current Distribution System
a.
Insoection Scoce ( 93809)
The team conducted a walkdown of the battery rooms, the battery chargers, the direct
current distribution panels, and the 120Vac inverters. The team also reviewed Condition
Report 96-0516, " Recurring Electrical Grounds During Heavy Rainfalls."
b.
Observations and Findinos
During the walkdown, the team noted that the direct current electrical system was
operating free of any grounded circuits. The licensee stated that ground alarms were
given immediate attention. The licensee provided Condition Report 96-0516, which
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described corrective actions taken by the licensee to minimize the number of grounds.
The licensee had determined that most electrical ground-related failures occurred after
heavy rains. To address this issue, the licensee implemented a corrective action
program to replace junction box gaskets. The licensee stated that this program had
significantly reduced the number of grounding problems. The team considered the
operational philosophy of operating free of electrical grounds to be an example of
maintaining good material condition of the electrical system.
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c.
Conclusions
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The licensee effectively resolved long-term problems with electrical grounds by modifying
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junction box seals to prevent water intrusion. In addition, on a continuing basis, the
licensee promptly corrected electrical grounds as they occurred, resulting in good
material condition.
Ill. Enaineerina
E1
Conduct of Engineering
E1.1
Safety Iniection System Desian Basis Calculations
a.
Insoection Scoce (37550. 93809)
The team reviewed six design basis calculations related to the safety injection system.
The team assessed technical adequacy, consistency with license basis commitments,
and administrative completeness. In addition, the team evaluated the design upgrade
project as it related to the upgrade of these calculations.
b.
Observations and Findinos
Design Bases Upgrade
The licensee was conducting a design basis review and calculation upgrade program,
which included review of the safety injection system. Phare 1, " Discovery," involved
identification of design basis open items for conflicting or incorrect design basis
information. The licensee had completed the discovery phase for the high and low
pressure portions of the safety injection system. Phase 2," Corrective Action," involved
completion of the necessary design document revisions to develop a comprehensive
consistent design basis for the system. The licensee planned to complete Phase 2,
" Corrective Action," for these systems in 1998.
During the discovery phase, Phase 1, a senior engineering review team:
1.
Determined if the specific calculation fully supports the design basis
2.
Identified open items (inadequacies, errors, inconsistencies, etc.)
3.
Recommended disposition of open items
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The licensee tracked open items in the program's internal open item tracking system.
The team questioned the basis for input assumptions and consistency of calculation
assumptions with the license basis. The team reviewed the licensee's entries in the
open item tracking system related to the safety injection system and found that the
licensee previously had identified the same unjustified input assumptions and license
basis inconsistencies in the design basis review / calculation upgrade program and in
Condition Report 97-806. The examples include: 1) hput assumptions for the
containment water level calculation; 2) input assumptions for the HPSI and containment
spray net-positive; suction head calculation; and 3) the failure to include the flow control
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valve pressure drop in the HPSI flow path pressure drop calculation. The team
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determined that the licensee's discovery phase was effective and that the first two issues
required further.eview. For the third issue, the team reviewed a draft calculation and
determined that no further review was needed because the change in pressure drop was
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small and the licensee had acceptable plans to correct the deficiency.
Net-Positive Suction Head Margins Not Accurately Stated
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The licensee identified that pump run out flows were not consistently defined in various
calculations resulting in conflicting net-positive suction head (NPSH) determinations.
The licensee also identified that the safety injection sump level design calculations did
not have consistent conclusions regarding the minimum sump water level during
recirco'ation, which affects the available NPSH. In addition, calculation results were not
alw.sys consistent with the Updated Final Safety Analysis Report. For example,
Calculation MN(Q)-6-27, "NPSH Calculation (HPSI & CS (containment spray] Pumps),"
Revision 2 and Updated Final Safety Analysis Report (UFSAR), Section 6.3.2.2.2.3,
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specified different values for required NPSH for these pumps. Specifically:
Calculation MN(Q)-6-27
Revision 2
Section 6.3.2.2.2.3
HPSI Required
20 feet
18 feet
(which matches NPSH
(which matches the
available at 985 gpm per
pump data sheet -
pump curve - near
required for runout flow)
runout)
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HPSINPSH
25.35 feet
25.35 feet
Available
26.75%
40.8%
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Calculation MN(Q)-6-27
Revision 2
Section 6.3.2.2.2.3
18 feet
14 feet
(which matches NPSH
(which matches the
available at 2250 gpm
pump data sheet-
per pump curve - near
required for runout flow)
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runout)
27.27 feet
25.35 feet
51.5 %
94.8 %
As a result, the pump design margins stated in the Updated Final Safety Analysis
Report were not achievable at actual pump runout. The licensee planned to correct
Calculation MN(Q)-6-27, "NPSH Calculation for HPSI and CS ? umps," Revision 2, and
delete the margin requirements from the UFSAR. While the committed margins were not
maintained, the existing ca!culations demonstrated sufficient NPSH was available to
maintain system operability.
In a related effort, the licensee identified inconsistencies in containment water level
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predictions and the associated inputs to NPSH calculations. The licensee planned to
revise Calculation MN(Q)-6-4, " Water Level inside Containment," Revision 0, to
comprehensively determine water level in containment for both the loss-of-coolant
accident and a main steam line break. Minimum containment water level was used to
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determine available NPSH, during the recirculation mode. The NRC plans additional
review of the completed HPSI calculations to determine the significance of the
inconsistencies and to confirm adequate resolution of the inconsistencies. Additionally,
the NRC will review the final UFSAR revision and the associated written safety
evaluation to determine compliance with 10 CFR 50.59. This issue will be tracked as an
unresolved item (50-382/9725-01) pending NRC review of completed
Calculations MN(Q)-6-27 and MN(Q)-6-4, and the approved written safety evaluation of
the planned change to the UFSAR.
Impact of increased Containment Flooding
Maximum predicted containment water level was used to identify equipment, which
would be adversely impacted by containment flooding. In Condition Report 97-1287
and Engineering Request ER-W3-97-0263, the licensee identified that its post
loss-of-coolant accident containment flooding analysis resulted in an unacceptable
maximum flood level. When increased instrumentation uncertainties, addition of
trisodium phosphate dodecahydrate baskets in containment, and a refueling water
storage pool (RWSP) volume versus level error were considered, the licensee predicted
partial flooding of the cooling coils for Containment Fan Cooler AH-14B-SB and
submergence of instruments, which were not qualified for submergence. Specifically, the
following instruments would be submerged:
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Steam Generator Wide Range Level Used in
1125A
Emergency Feedwater Flow Control
RC IPT 0106 A&B
Hot Leg Prt;ssure Used in Subcooled Margin
Calculation
St ILT 7145 A&B
Safety injection Sump Level
The licensee determined it was necessary to administratively impose a 90 percent upper
limit on maximum RWSP inventory to prevent partial flooding of the containment fan
cooler cooling coils and flooding of the nonqualified instruments.
With respect to the containment fan cooler cov,,ng coils, the licensee evaluated the effect
of coil submergence on peak containment pressure. The licensee concluded that with
20 percent coil submergence, peak containment pressure only increased by 0.15 psig,
which they stated was within the acceptance criterion for post-accident peak containment
pressure. With respect to the instrumentation, the licensee concluded that the sump
level instrumentation would be available as the accident progressed until it was no longer
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necessary and loss of the remaining instrumentation could be compensated by the
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operators by using other backup instruments. The licensee concluded that a technical
specification amendment was not required and that the RWSP maximum limit could be
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administratively controlled.
As stated above, the licensee planned to revise Calculation MN(Q)-6-4, " Water Level
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inside Containment," Revision 0, to comprehensively determine water level in
containment for both the loss-of-coolant accident and a main steam line break. The
licensee deferred their past operability and their reportabilitiy determination until after this
calculation is complete.
NRC Regulatory Guide 1.97, " Instrumentation ior Light-Water-Cooled Nuclear Power
Plants to Assass Plant and Environs Conditions During and Following an Accident,"
Revision 2, identified types of variables to be monitored during post-accident conditions.
This equipment must be provided with assurance that it is environmentally qualified as
required by 10 CFR 50.49, " Environmental Qualification of Electric Equipment important
to Safety for Nuclear Power Plants."
This issue is unresolved (50-382/9725-02), pending NRC review of the completed
calculation and past operability determination to determine: 1) past compliance with the
technicsi specification, and 2) past compliance with environmental quclification
requirements for instrumentation that could become submerged following an accident.
The NRC also plans to review the written safety evaluation associated with the updated
calculations to confirm compliance with 10 CFR 50.59.
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c.
Conclusions
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The discovery phase of the licensee's design basis' review and calculation upgrade
program was effective for the safety injection system. The licensee had previously
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identified the substantive issues that were independently identified by the team.
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E1.2 Air-Ooerated and Hydraulic-Ooerated Valve Calculations
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a.
Insoection Scooe (37550)
In Generic Letter 89-10. " Safety-Related Motor-Operated Valve Testing and
Surveillance," the NRC made recommendations related to the testing, inspection, and
maintenance of motor-operated valves to provide the necessary assurance that they
would function when subjected to the design-basis conditions. The testing performed to
address the recommendations in Generic Letter 89-10 provided information about the
motcr-operated valve actuator performance and about valve performance. The valve
performance information was also applicable when other types of actuators were used,
such as: air-operated or hydraulic-operated actuators. Based on insights gained during
review of Generic Letter 89-10 testing programs, the team reviewed four air and
hydraulic-operated valve sizing calculations and discussed the documents with licensee
engineers.
b.
Observations and Findings
Through review of this material and discussions with licensee engineers, the team
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determined that the calculations adequately demonstrated the operability of the subject
valves. However, one calculation, Calculation EC-M91-076, contained discrepancies
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that required correction.
Calculation EC-M91-076
The team identified the following four discrepancies within Calcu'at;on EC-M91-076,
"SI-405A(B) Actuator Thrust Calculation," Revision 2, dated September 14,1995:
A valve factor of 0.5 was assumed, although this was not consistent with motor-
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operated valve test results of similar valves (flex-wedge gate valves). After
review of motor-operated valve tests of similar valves, the licensee agreed to
increase the valve factor to 0.6. The team considered the revised valve factor to
be appropriate for this valve.
The calculation to determine the minimum force necessary to keep the valve
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open did not include a term to account for the weight of the valve disc and stem,
which together weighed approximately 250 pounds.
Unseating thrusts were based on tests performed under static conditions and,
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therefore, did not account for extra unwedging loads resulting from dynamic
pressures applied across the valve disc.
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in Section 8.7.2 of the calculation, packing drag forces were applied
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inconsistently because they were included for some stoke analyses, but not for
others.
The licensee agreed to correct these discrepancies and stated that the changes would
not affect the operability status of Valves SI-405A(B). The team agreed with this
assessment.
Use ofisothermal Assumptions
The team identified one general deficiency involving the lack of justification for an
assumption that most airmperated valves exhibit isothermal behavior during operation.
The team observed that
numerous applications within the calculations reviewed, the
licensee used a formula of the form P / V = P / V. This formula stated that the pressure
divided by the volume in an earlier state equaled the pressure divided by the volume in
a later state. Using ideal gas laws, this implied that the temperature was constant
from the initial to the final state, which would be nonconservative for some applications of
air-operated valves.
The licensee noted that isothermal conditions were not assumed for valves that had
multiple actuations during an accident scenario. Also, the licensee performed a
calculation to verify isothermal assumptions for a special case involving air leakage
during long-term holding of a valve disk in either an open or closed position against
spring pressure.
The team determined the licensee had not developed a bounding calculation, which
addressed marginal thrust-limited valves, where the nitrogen or air volume expands
during the stoke. The team noted that the expansion would cause a decrease in
temperature and a further drop in pressure t. y'nd that calculated by an isothermal
analysis. The increased pressure drop would result in less thrust being available to
stroke the valve. Eventually, the temperature in the air chamber would equalize to the
ambient, which would cause pressure to be restored to the calculated value. However, if
the valve were tn hang up in mid stroke, it would then have to overcome static friction to
resume the stroke. The static frictional forces would be greater than the sliding frictional
forces assumed in the analysis, and could potentially prevent a resumption of the valve
stroke. However, the team did not identify any valves that fit the postulated
circumstances. The team concluded that the licensee's isothermal assumpon was not
well justified and was a weakness in the licensee's air-operated valve program.
Licensee Program to Upgrade Performance Calculations for Air-Operated and
Hy:fraulic-Operated Valves
The team noted that many air and hydraulic-operated valves did not have calculations
demonstrating the capability of the valves to perform their safety functions. The licensee
previously identified this deficiency, for air-operated valves only, and hired a consultant
to generate new or improve existing calculations for approximately 120 air-operated
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valves. Selection of the valves to be analyzed by the consultant was based on
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outstanding condition reports (problematic valves), probabilistic risk assessment
rankings, and valves with active safety functions. Safety-related air-operated valves not
selected in the original contract were to be included in a second contract following
completion ef the first, and consisted of approximately 45 valves, mostly in ventilation
systems.
The team considered the licensee's selection of valves to be appropriate with one
exception. The scope did not include the plant's six safety-related hydraulic-operated
valves. These valves were:
SI-405M
Component Cooling Water to Shutdown Cooling
Heat Exchanger Isolations
FW-184A/B
Main Feedwater isolation Valves
MS-124A/B
in response to the team' questions concerning the operability of the main feedwater
isolation valves (discussed below) the licensee decided to add the safety-related
hydraulic-operated valves to the scope of the contract. Therefore, new calculations will
be performed for each of these valves.
Valve Factor Estimate for Main Feedwater Isolation Valve (Hydraulic-Operated)
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team requested the calculation that demonstrated the capability of the main
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feedwater isolation valves to perform their safety functions. The licensee stated that this
calculation did not exist, but that the valves were sized during initial design in accordance
with the manufacturers specifications. The team was concerned that this initial sizing
may have been based on assumed valve factors that have since been proven to be
nonconservative as a result of motor-operated valve testing performed under Generic Letter 89-10.
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The main feedwater isolation valves are 20-inch Anchor-Darling double disk gate valves.
Though previously assumed to have 0.2 valve factors, these valves exhibited valve
factors as high as 0.4 during Generic Letter 89-10 tests. The licensee confirmed that the
initial sizing of the main feedwater isolation valves was based on a 0.2 valve factor.
During the inspection, the licensee performed a draft calculation, which determined that
the available valve factor (highest valve factor, which would yield a successful stroke by
calculation) was 0.31.
The licensee periormed a review of test results of Anchor-Darling double disk gate
valves and found valve factors ranging from 0.31 to 0.35. These test results were for
6-inch valves and the licensee stated that motor-operated valve testing had shown that
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valve factors tend to decreme with increasing valve size. The licensee determined that
the main feedwater isola
valves were operable pending further analysis based on the
proximity of the availabh ive factor to the test results and based on previous
occurrences where feedwater isolations had occurred and the main feedwater isolation
valves successfully closed.
This matter was discussed with the licensee during a conference call on January 8,
1998, which included the NRC program office. The NRC observed that the 0.31 valve
factor was not conservative with respect to test results from the Electric Power Research
institute and testing performed by Commonwealth Edison. These test results would
suggest a more appropriate valve factor of 0.4 or greater. However, the licensee stated
that the main feedwater isolation valves had automatically closed in response to a
feedwater isolation signal on at least five previous occasions. Each of these closures
was a complete stroke to the closed position. Some of these cycles occurred under
conditions approximating design basis conditions. There were no occurrences known to
the licensee where the main feedwater isolation valves failed to stroke properly. Based
on this historical record, the team agreed with the licensee's conclusion that, for
immediate purposes, the main feedwater isolation valves could be considered operable.
As stated above, the licensee planned to prepare actuator performance sizing
calculations for these valves. The licensee stated this effort would include a review of
design basis information to ensure the bounding design basis conditions were identified.
Based on uncertainties in the valve factor analysis, the fact that the licensee had not fully
defined the design basis conditions of the valves, and the fact that the main feedwater
isolation valves had never performed a closure under full blow down conditions, the team
considered the matter of the main feedwater isolation valve operability to be unresolved.
This issue will be tracked as an unresolved item (50-382/9725-03), pending additional
NRC review of the completed actuator performance sizing calculations and the finalized
design basis conditions.
The licensee stated that its contractor was in the process of preparing a complete
calculation for the main feedwater isolation valves on an expedited basis, with
compleijon in approximately mid-February. Depending on the results of this review,
additional compensatory actions may be necessary to ensure the continued operability of
these valves.
Failure to identify a Condition Adverse to Quality
The team considered the licensee's failure to translate information from the
Generic Letter 89-10 testing to the design of the main feedwater isolation and other
Anchor-Darling gate valves to be a significant oversight. Additional review was
performed to determine whether the licensee should have recognized this condition
adverse to quality.
NRC issued Information Notice 96-48, " Motor-Operated Valve Performance issues," on
August 21,1996. This notice alerted licensees to lessons learned from the Electric
Power Research Institute (EPRI) motor-operated valve test program. This program
9
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indicated that many of the previous assumptions used in motor-operated valve
calculations were not accurate and that their use resulted in the over prediction of motor-
operated valve capabilities. Within this program, testing of Anchor-Darling gate valves
indicated that a valve factor of approximately 0.4 was applied to these valves, depending
on service conditions. Based on interviews, the team determined that the licensee's
j
engineers understood that this valve factor was applicable to any Anchor-Darling gate
valve, regardless of the type of operator, and also understood that the use of the
0.4 valve factor would result in a considerable increase in predicted thrust requirements
above those calculated using the previous industry-wide assumed 0.2 valve factor.
On March 7,1997, the licensee's operatioaal experience engineering evaluation (OEEE)
for Information Notice 96-48 was approvec. Issue 1 of the OEEE stated that the EPRI
program for motor-operated valves provided important information, applicable to gate,
globe and butterfly valves, regardless of type of actuator operating the valve. However,
in the October 29,1997, draft response, the component engineering group relied on the
motor-operated valve closeout report and did not address valves operated by hydraulic
or air operators. The licensee stated the draft was essentially complete except for
agreement on scheduled completion dates.
10 CFR Part 50, Appendix B, Criterion V, requires that activities affecting quality shall be
prescribed by procedures appropriate to the circumstances and shall be accomplished in
,
accordance with these procedures.
Procedure W2.501, " Corrective Actions," Revision 6, Section 4.1, required that condition
reports be generated when an adverse condition was identified. Section 3.1 of the
_
procedure defined an adverse condition as "an event, defect, characteristic, state or
activity, which prohibits or detracts from the safe, efficient operation of Waterford 3." The
adverse condition was further defined to include nonconforming conditions.
The team determined that a condition report should have been initiated shortly after
March 7,1997, and before October 29,1997, to identify that Anchor-Darling gate valve
performance did not conform with the initial sizing calculation assumptions. The use of
a condition report to resolve this concern would have resulted in a timely operability
determination for this nonconformance and identification of the need for reanalysis.
The discovery of higher than previously assumed valve factors for Anchor-Darling
double-disk gate valves was an adverse condition with respect to the operability of
the main feedwater isolation valves. The licensee's failure to identify the need to
reanalyze the capability of the Anchor-Darling air- and hydraulic-operated gate valves
in light of this information is a violation of 10 CFR Part 50, Appendix B, Criterion V
(50-382/9725-04).
c.
Conclusions
Some minor errors, which did not affect operability, were identified with
Calculation EC-M91-076, 'SI-405A(B) Actuator Thrust Calculttion, Revision 2,
dated September 14,1995. The licensee had taken appropriate actions to establish
and improve calculations for air-operated valves, but had not included hydraulic-operated
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valves in the scope of the calculation upgrade program. The licensee's evaluation of the
applicability of NRC Information Notice 96-48, was inadequate because they did not
promptly initiate a condition report when they identified that the Anchor-Darling gate
valve performance did not conform with the initial sizing calculation assumptions. The
failure to initiate a condition report was identified as a violation of 10 CFR Part 50,
Appendix B, Criterion V. The question of the operability of the main feedwater isolation
valves was identified as an unresolved item, although the team agreed with the licensee
that valves could be considered operable pending the results of further evaluation.
E1.3 Hydroaen Generation Calculations
a.
Insoection Scooe (37550)
The team reviewed Calculation HVAC-70, " Hydrogen Generation By Station Batteries,"
Revision 1, and Calculation HVAC-059, " Battery Room Air Flow Required to Limit
j
Hydrogen Concentration to 1%," Revison 1, to evaluate the capability of the ventilation
system to adeouately sweep hydrogen from the battery rooms.
,
b.
Observations and Findinos
During the inspection, the team toured the battery rooms and noted in Battery Room A
)
that the supply and exhcast duct were located within a few feet of each other. The team
'
questioned the capability of the ventilation system to adequately sweep pockets of
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hydrogen from the far end of the battery room and to maintain the hydrogen
concentration in the room below the 1 percent limit.
The team found that Calculation HVAC-70 included a nonconservative assurnption.
Specifically, the calculation was based on nominal room temperature, rather than
)
worst-case temperature. The team noted that worst-case room temperature should be
used because hydrogen generation increases with temperature. The licensee agreed
that the calculation should be corrected.
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In Calculation HVAC-59, the licensee used the hydrogen generation rate, determined in
Calculation HVAC-70, to determine the minimum required air flow to ensure hydrogen
concentration remains at less than 1 percent. The team found that Calculation HVAC-59
included an unverified assumption. Specifically, in the minimum required air flow portion
of the calculation, the licensee assumed a 25 percent mixing efficiency, which had not
been verified as achievable by a quantified test. During the inspection, the licensee
qualitatively assessed the room ventilation via a smoke test. The licensee discharged
small puffs of chemical smoke at the end of the room, which was remote from the
ventilation supply and exhaust duct. The licensee observed the smoke patterns and
concluded that some circulation was occurring at the end of the room, which was remote
from the supply and exhaust doct. The team did not agree that this test substantiated a
25 percent mixing rate.
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However, the results of the minimum required vent!'ation rate calculation were
conservative with respect to the design of the installed equipment. A much smaller-
mixing efficiency and a much larger hydrogen generation rate could have been assumed
with satisfactory results. The team concluded these errors were not signincant.
Calculation HVAC-59 also included a calculation of the minimum time to reach tne
hydrogen limit of 1 percent with the ventilation secured, which was 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br />. The
licensee provided a design guide, which specified that a 25 percent mixing rate is
normally assumed for explosive contaminates in well vent! lated rooms. The design guide
suggested that, for improperly ventilated areas, a lower mixing rate assumption may be
necessary. The team noted that the doors to the battery rooms are typically closed.
Diffusion and thermal convection would provide the only mechanism for air mixing in this
case. The team determined that the licensee had not adequately justified the use of a 25
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percent mixing assumption in the minimum time portion of Calculation HVAC-59. The
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licensee agreed and planned to revise or delete this partion of the calculation.
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Since the licensee no longer had a valid estimate of the time to reach the hydrogen
!
concentration limit, the team discussed related operating instructions with the licerme to
f
confirm hydrogen accumulatier, was being acceptab(y controlled. The licensee noted
j
that the system operating procedures required that the ventilation system be in service
during battery charging. However, they also stated that the alarm response procedure
for a battery room ventilation failure did not provide direction to the operators to secure
the battery charger to prevent hydrogen accumulation. Given the iack of basis for the
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time to reach the hydrogen limit, the tearr, considered this to be an alarm response
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procedure weakness.
c.
Conclusions
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The team determined that Calculations HVAC-70 and HVAC-59 contained
nonconservative assumptions, which did not effect the conclusion that the battery room
exhaust ventilation system was capable with respect to removal of hydrogen. The team
also found that the licensee's calculation of the mirimum time to reach a 1 percent
concentration of hydrogen was not well justified, resulting in a procedure weakness.
E1.4 Low DC Voltaae to Emeraencv Feedwale.dy.mo Turbine Steam Admission ValyLs
1
a.
Insoection Scone (93809)
The team reviewed the voltage conditions available to the plant's only de motor-operated
valves, MS-401 A(B) - emergency feedwater pump turbine steam admission valves.
b.
Observations and Findinas
Valves MS-401 A(B) are normally closed and muct open to initiate steam flow to the
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emergency feedwater pump turbine. The valves were designed to utilize de power to
enable operation in the event that all alternating current sources are lost. The licensee
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had calculated that the minimum voltage available at the motor term.inals was 80Vde,
which was 64 percent of the rated voitage of 125Vdc.
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Tne team identified two concerns related to these voltage conditions:
The licencee used a standard formula for computing the torque capability of the
motor-actuator, using a linear relationship of voltage to output torque. The
actuator manufacturer, Limitorque, has stated that this linear relationship is valid
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only at levels of 70 percent rated voltage or greater. Below 70 percent rated
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voltage,'the voltage-torque relationship could potentially become exponential,
such that the percentage of output torque would decrease faster than the voltage.
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The licensee's use of a linear relationship appeared essentialin its calculation of
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valve operability. In consultation with the NRC program office, the team learned
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that the Idaho National Engineering Laboratory, under contract with the NRC,
was in the process of performing de motor testing. Preliminary results indicated
an exponent of 1.3 (1.0 is linear) should be applied to degraded voltage torque
output. An exponent greater than 1.0 indicated that torque output would
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decrease at a greater rate than the voltage would decrease from the rated value.
Limitorque, during the most recent motor-operated valve users' group meeting,
also indicated that additional testing would be performed leading to the issuance
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of new guidance conceming the sizing of de motor-operated valves.
Low voltage levels could prevent pickup of the de contactors and prevent valve
operability even if sut0cient voltage existed to operate the valve.
In response to the first concern, the licensee agreed that Limitorque did not endorse use
i
of the linear voltage-to-torque relationship below 70 percent rated voltage. However, the
licensee researched testing performed by another licensee, Commonwealth Edison, of
eight de moto. t The results indicated that the relationship of voltage to output torque
was linear to voltages as low as 10 percant of rated nameplate voltage. At least one of
the motors tested by Commonwealth Edison was the same size and manufacturer as the
motors used in the emergency feedwater steam admission valves. Based on this testing,
the team considered the licensee's use of the Inear equation for their valves to be
appropriate while additional industry testing is ongoing.
In response to the second concern, the licensee teferred to IEEE Standard 323-1974,
" Qualification and Test Summary Report for Class 1E Starter Control Station,"
CC 74-256, Revision 0, prepared by Gould, Inc. This report stated that the pickup
voltage for Size 1 (applicable to the licensee's valves) de contactors was 60 percent of
rated voltage. Based on this document, the licensee considered Valves MS-401A(B)
operabic. The team consulted the NRC program office and concluded that the licensee's
use of the 60 percent threshold for contactor operability was acceptable.
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c.
Conclusions
The licensee adequately supported immediate operability of the turbine-driven
emergeacy feedwater steam admission valves with respect to the potential low voltage
condition. la the near future, new information concerning dc motors could affect the
licensee's analysis.
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E2
Engineering Support of Facilities and Equipment
E2.1
Imolementation of Emergepcv Core Coolino System Surveillance Recqirements
a.
Ingstion Scoce (37550)
1
The team reviewed the emergency core cooling systems (ECCS) technical specification
surveillance requirements and the associated surveillance procedures to confirm the
acceptance limits contained in the technical specification surveillance requirements were
included in the associated surveillance procedures and that the surveillances were being
tracked and properly scheduled. In this portion of the inspection, the team did not
evaluate the basis for the technical specification surveillance requirement acceptance
limits,
b.
.Q)servations and Findings
The team noted that all the ECCS technical specification surveillances were being
{
tracked, scheduled, and implemented during the applicable modes of operation. The
technical specification surveillance frequency requirements were met and, in fact,
surveillances were often conducted more frequently than required.
Except as described in Section E2.2, the team found that acceptance limits from the
technical specifications were correctly included in surveillance procedures. The team
noted that the surveillance procedures detailed the acceptance, alert, and required action
,
values in their respective attachments. In addition, the team noted that each procedure
required returning the component back to service and removing any test equipment
installed following the conclusion of the surveillance test.
c.
CQDClW.SiO.D
The team concluded that the ECCS surveillance procedures were scheduled and
implemented in accordance with the technical specificat;on requirements. The team
noted that the schedules were in accordance with the surveillance frequency
requirements, and that the acceptance lirr.its of the technical specification surveillance
requirements were included in their respective surveillance procedures. However, in
Sections E2.2 and E8.1 of this report, the team noted that uncertainties were not always
being appropriately factored into surveillance requirements.
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E2.2
Hioh Pressure Safety iniection Flow Control Valve Reo!acements
a.
Insoection Scope (37001.37550. 93809)
The team reviewed the documentation for Design Change 3440, "HPSI Flow Control
Valve Replacement," Revision 0, to verify that the design basis of the HPSI system had
been appropriately maintained following the installation of new valves. The team also -
reviewed the post-modification testing results.
b.
Observations and Findinas
The licensee replaced the eight HPSI (HPSI) flow control valves during the 1997
refueling outage because of problems with cracks in the valve seats and valve seat
leakage problems. The team found that the valve replacements were essentially like-for-
like replacements. The flow control valves were designed to open to a throttled position
on a safety injection actuation signal. The throttled position was controlled by the limit
switch setting of the valve actuator and was determined during flow balance testing The
flow control valves were required to open sufficiently to provide enough HPSI flow to the
reactor to limit peak clad temperature without opening too far to allow the HPSI pumps to
operate in a run out condition. The team determined these valves were capable of
meeting HPSI design basis requirements. However, the team noted that during post-
modification testing, appropriate flow balancing was not performed.
Post-Modification Testing
The post-modification testing of the new valves included the HPSI flow balance test in
accordance with Technical Specification 4.5.2.h, which required the adjustment of the
actuator limit switches to the correct setting. The testing was completed on May 23-24,
1997, in accordance with Surveillance Procedure OP-903-108, "Si Flow Balance Test,"
Revision 3, Change 1, dated April 10,1994. The acceptance limit of the procedure
stated that the sum of HPSI injection header line flow rates, excluding the highest flow
rate, shall be greater than or equal to 675 gpm. This was consistent with the requirement
of Technical Specification 4.5.2.h. The resulting sum of measured HPSI injection header
line flow rates were 675 gpm (A pump /A headers), 718 gpm (AB pump /A headers),
712 gpm (8 pump /B headers), and 690 gpin (AB pump /B headers).
The new valvec were installed with the open limit switch setting for the valve actuators
set at the same setting as the original valves prior to their removal to serve as a
reasonable starting point for the flow bclance testing. The test results met the
,,
acceptance limit of the procedure; therefore, no limit switch adjustments were made.
The licensee considered the results of the tests acceptable and declared the HPSI
system operable.
The bases section for Technical Specification 3/4.5.2 states that the surveillance
requirements ensure that, at a minimum, the assumptions used in the safety analysis are
15
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met. The team questioned the acceptability of the test results, particularly for the A train
pump, which just met the minimum acceptance limit. The team questioned whether the
surveillance procedure acceptance limit properly included margin for flow measurement
,
uncertainty and for flow control valve position variability.
After discussions with the team, the licensee identified that not all of the flow instrument
uncertainty had been accounted for. The licensee stated that the 675 gpm acceptance
j
criterion from Technical Specification Surveillance Requirement 4.5.2.h included an
'
allowance of 5 gpm/ leg, to account for flow instrument measurement uncertainty.
However, Surveillance Procedure OP-903-108 directed personnel to use flow
instruments, which had a flow measurement uncertainty of approximately 18 gpm/ leg.
The licensee initiated Condition Report 97-2695 on December 5,1997, to document this
condition.
10 CFR Part 50, Appendix B, Criterion XI, requires, in part, that test procedures shall
include provisions for assuring that adequate test instrumentation is used. As of
December 18,1997, the licensee had not corrected Surveillance Procedure OP-903-108
to include provisions for assuring that adequate test instrumentation was used. The test
procedure specified instrumentation, which had an uncertainty that was greater than that
,
assumed in the basis for Technical Specification Surveillance Requirement 4.5.2.h. The
failure to specify sufficiently accurate test instrumentation is the first example of an
apparent violation of 10 CFR Part 50, Anpendix B, Criterion XI (50-382/9725-05).
Technical Specification 4.5.2.g required the licensee to verify the correct position of each
electrical and/or mechanical position stop for the ECCS throttle valves each tirne the
valve was cycled. Surveillance Procedure OP-903-010, "ECCS Throttle Valves Position
Verification," Revision 3, implemented this technical specification requirement and
I
allowed a +/- 2 percent tolerance band for the as-found flow control valve position from
its set point value. The team questioned what impact this acceptance limit had on HPSI
flow and whether this variability was incorporated into the technical specification flow
rate acceptance limit it appeared that one or more flow control valves could open some
amount less than set point, still be within the 2 percent acceptance limit, and yet cause
HPSI flow to the reactor to be less than 675 gpm. Likewise, one or more flow control
valves md open some amount greater than set point, still be within the 2 percent
accepta ' e limit, but cause the HPSI pump to operate closer to a run out condition.
The licensee determined that valve position variability had not been included in the
development of Technical Specification Surveillance Requirement 4.5.2.h and that after
consideration of valve position variability, the surveillance requirement would not assure
I
that the assumptions used in the safety analysis were met. The team concluded that an
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additional allowance should have been included in the acceptance limit of Surveillance
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Procedure OP-903-108 to account for valve position variability.
i
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10 CFR Pait 50, Appendix B, Criterion XI, requires, in part, that all testing required to
l
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demonstrate that structures, systems, and components will perform satisfactorily in
service, is performed in accordance with written test procedures that incorporate the
requirements and acceptance limits contained in applicable design documents.
I
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As of December 18,1997, the licensee had not corrected Surveillance
{
Procedure OP-903-108 to incorporate an acceptance limit allowance for valve
)
position variability, which was necessary to ensure that the flow assumptions used in
I
the safety analysis were met. The failure to include an appropriate acceptance limit in
Surveillance Procedure OP-903-108 is the second example of an apparent violation of
,
10 CFR Part 50, Appendix B, Criterion XI (50-382/9725-05).
I
Emergency Core Cooling System Evaluation
The original HPSI flow limit calculation performed by the nuclear steam suMy system
I
vendor was provided to the !icensee on September 9,1997, as part of a design
basis information transfer project. This calculation used an instrument uncertainty of
5 gpm/ injection leg (8.7 gpm total for combined legs). Calculation EC-195-011,
"SI-HPSI Flow Instrumentation Loop Uncertainty Calculation," Revision 1, determined
that the instrumentation uncertainty was actually approximately 18 gpm/ injection leg
(31.2 gpm total when statistically combined). Therefore, an additional 22.5 gpm of
combined flow measurement uncertainty needed to be considered. As discussed above,
on December 5,1997, after consideration of these instrument uncertainties and other
uncertainties, the licensee determined that the technical specification limit of 675 gpm
did not p,ntect the analytic value of 621.8 gpm in the small-break loss-of-coolant accident
,
(SBLOCA; safety analysis.
The licensee's SDLOCA safety analysis assumed a HPSI flow rate of 621.8 gpm and a
charging pump flow rate of 18 gpm. Thc analysis was performed for the licensee by its
nuclear steam supply system vendor using a SBLOCA evaluation mocel previously
'
reviewed by the NRC and found acceptable. The resultant peak clad temperature (PCT)
was 1879'F, which was within the 10 CFR 50.46 emergency core cooling acceptance
criterion of 2200*F.
The licensee determined that if the correct instrumentation error was accounted for,
the analytic value for HPSI flow would have to be reduced to 599.3 gpm .(621.8 gpm -
22.5 gpm). Alternatively, a hi her technical specification limit of 697.5 gpm (675 gpm
0
+ 22.5 gpm) could be used to ensure exceeding the analytic value, but this measured
flow rate wac unachievable for all HPSI pump and injection path combinations. In their
December 5,1997, operability determination, the licensee estimated the available flow at
590 gpm to account for valve position variability and other uncertainties, which were not
previously considered.
10 CFR 50.46 (a)(3)(i) requires, in part, that each holder of an operating license shall
estimate the effect of any change to, or error in, an acceptable ECCS evaluation model
or in the application of a model to determine if the change, or error, is significant. For this
purpose, a significant change or error is one that results in a calculated peak fuel
cladding temperature different by more than 50 F from the temperature calculated for the
limiting transient using the latest acceptable ECCS model, or is a cumulation of changes
and error that the sum of the absolute magnitudes of the respective temperature
changes is greater than 50 F.
17
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On December 5,1997, the licensee identified that the licensing basis safety analysis was
in error, in that available HPSI system flow (an ECCS system) was less than assumed.
However, the licensee failed to estimate the effect of this error on peak fuel cladding
temperature. The failure to estimate the effect of this error on peak clad temperature is
an apparent violation of 10 CFR 50.46 (a)(3)(i) (50-382/9725-06).
When asked by the team on December 18,1997, to assess the impact of lowered HPSI
flow on the calculation of PCT to account for the additional uncertainty, the licensee
determined that a HPSI flow value of 599.3 gpm as input into the SBLOCA analysis
using the original evaluation model would result in a PCT greater than 2200'F.
If the additional uncertainty for flow control valve position was accounted for
(approximately 11 gpm), the analytic value would have to be reduced further to account
I
for this additional random e Tor term. This would aiso result in exceeding a PCT of
2200'F for a SBLOCA using the original evaluation model.
10 CFR 50.46 (a)(3)(ii) requires, "Any change or error correction that results in a
calculated ECCS performance that does not conform to the criteria set forth in
paragraph (b) of thic Section is a reportable event as described in .
10 CFR 50.72 and
10 CFR 50.73." 10 CFR 50.46 (b)(1) requires, "The calculated maximum fuel elemen(
cladding temperature shall not exceed 2200'F.10 CFR 50.72 (b)(ii)(B) requires, in Part,
". . the licensee shall notify the NRC as soon as practical nnd in all cases within
one hour of the occurrence of any of the following:
. (ii) Any event or condition during
operation that results in . . . the nuclear power plant being: . . (B)In a condition that is
outside the design basis of the plant."
]
On December 5,1997, the licensee identified and did not report within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> an error
correction, which would have resulted in a calculated ECCS performance that did not
conform to the criteria set forth in paragraph (b) of 10 CFR 50.46. Specifically, the
licensee identified that availab!e HPSI flow was tens than that stated in the safety
'
analysis. Using the licensing basis analysis and the available HPSI flow, the licensee
estimated that peak fuel cladding temperature would have exceeded 2200V, a condition
outside the design basis of the plant. The condition was not reported until De.nember 18,
1997. The failure to report an ert. correction that would result in a peak clad
temperature that exceedeo 22006, :., the first example of an apparent violation of
10 CFR Part 50.46 (a)(3)(ii) (50-382/9725-07).
10 CFR 50.46 (a)(3)(ii) also requires, "For each change to or error discovered in an
acceptable ECCS evaluation model or in the application of such a model that affects the
temperature calculation, the applicant shall report the nature of the change or error and
its estir...ted effect on the limiting ECCS analysis to the Commission at least annually
.
as specified in 10 CFR 50.4. If the change or error is significant, the applicant shall
I
provide this report withia 30 days and include with the report a proposed schedule
for providing a reanalysis or taking other action as may be needed to show compliance
with 10 CFR 50.46." The licensee reported the issue to the NRC in a 10 CFR 50.72
notification on December 18,1997, and in a licensee event report in accordance with the
requirements of 10 CFR 50.46 and 10 CFR 50.73 on January 5,1998.
18
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As of January 22,1998, the licensee had not provided a proposed schedule for providing
a limiting ECCS reanalysis, which corrected the significant HPSI system flow error or for
{
taking other action as may be needed to show compliance with 10 CFR 50.46. The
failure to provide a schedule for the reanalysis within 30 days of discovery is the second
example of an apparent violation of 10 CFR 50.4t (a)(3)(ii)(50-382/9725-07).
System Operability
The !icensee concluded that the HPSI system remained operabie because a new
SBLOCA evaluation model had been developed by its nuclear steam supply system
vendor and was nearing fermal approval by the NRC. The new evaluation model
implementsc' improvements in core heat transfer modeling, which included steam
3
cooling. A gencaic olant analysis using the original roodel and an assumed injection flow
of 695 cpm from H,TI rJone resulted in a PCT of 1732*F. Application of the new
evaluatiori mode; to a generic plant SBLOCA ardalysis with no change in ECCS
j
performance resulted in a 336*C reduction in PCT, from 1732 to 1396'F. The licensee
concluded that a similar reouction in PCT was expected when the new evaluation model
was applieel to its plant-specific data. The analysis had not been completed at the
conclusion of the inspection. The licensee reasoned that this reduction in PCT using the
new evaluation model could be used to reduce recuired HPSI flow rate and still achieve
{
sn acceptable PCT. The NRC formally epproved the new SBLOCA methodology on
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December 17,1997.
i
The licensee stated that it had performed an informal calculation to evaluate HPSI
system performance at 108 percent power to support a possible power uprate request
An acceptable PCT was obtained using the new model and a HPSI flow of 621.8 gpm.
The licensee reasoned that if 621.8 gpm flow was acceptable for the 108 percent power
case, then a reduction in HPSI flow accounting for additional uncertainties, which
j
amounted to about 5 percent (588.2 gpm), was acceptable.
i
On January 9,1998, the licensee initiated Condition Report 98-0046, which identified
that additional sources of instrumentation uncertainty needed consideration for the
operability evaluation of Condition Report CR-97-2695. They included a scaling
<
difference between the instruments (one of the instruments was not calibrated for the
assumed temperature) and that portioris of Procedure OP-93-108, "Si Flow Balance
Test," Revision 3, Change 1, dated April 10,1994, used the less accurate control board
instruments instead of the qualified safety parameter display system (QSPDS).
By removing from conservatisms that were in Instrument Loop Uncertainty
Calculation EC-195-011, the licensee concluded that the HPSI system remained
Previous Opportunities to identify and Correct Condition
The team noted that the licensee had several previous opportunities to identify this
condition.
19
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,o
1994 Flow Anomajlims
In 1994, the licensee noted unexpected flow anomalies, which they attributed to test
'
instrumentation uncertainty. In Condition Identification 290132, the licensee noted that
i
' the QSPDS flow indicators were about twice as accurate as the control board analog
{
indicators. To improve test accuracy, the licensee issued Procedure OP-903-108,
"Si Flow Balance Test /' Revision 3, Change 1, dated April 10,1994, which changed the
flow readout device to the more accurate QSPDS indicators for portions of the test.
Licensee personnel sf.ated that the procedure was not revised to require that all of the
.
test data be collected using the more accurate display because operations management
was concerned that too much dependence on QSPDS would cause the operators to lose
their control board skills. The team also noted that it appeared that the licensee did not
fully research the design basis for the test requirements at this time.
Technical Onecification Instrument Uncertaintv Proie.c.t
(
Condition Report CR-96-0382 was initiated on March 15,1996, when it was identified
that instrumentation loop uncertainties were not accounted for in emergency feedwater
'
pump acceptance criteria. An action plan was developed to perform a review of
technical specifications to evaluate the generic issue of instrument error and surveillance
u
testing acceptance criteria. The action plan included an open item to evaluate the effect
of instrument error on the HPSI flow balance surveillance requirement, but the action had
not been completed at the time of the inspection.
During discussions with the team, the licensee stated that they considered evaluating the
impact of the flow instrument uncertainty on the surveillance testing requirements.
However, the need to perform a detailed evaluation was given a low priority because the
licensee four.d a December 1,1989, document from the nuclear steam supply system
i
vendor, which stated instrument uncertainties were accounted for in determining the
HPSI flow balance surveillance requirement. The actual value was not provided to the
licensee in that document.
1MS_}liatdressurg_ Safety Iniection System Self Assessment
A HPSI self ascessment, completed by the licensee July 16,1996, stated:
"A design engineer and a design engineering supervisor were interviewed
concerning the generic issue of incorporating instrument error in a surveillance
'
test [s] [in] compliance with technical specification requirements. Technical
Specification Action 4.5.2.h requires the sum of the three smallest HPSI injection
flows to be greater than 675 gpm as does the acceptance criteria of surveillance
procedure OP-903-108. Both use 675 gpm but neither includes instrument error.
,
CR 96-0382 documents the instrument error question generically in action item 4
and will be addressed later this year."
20
i
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1
=
\\
-
The licensee did not initially generate a separate condition report, evaluate the
operability of the HPSI system, or correct the surveillance procedure, instead they relied
j
on the action plan for Condition Report 96-0382, described above. The licensee stated
i
that an informal operability evaluation was perfonned on approximately August 1996,
which found the system operable based on past surveillance test data. In part, because
the licensee did not correct the surveillance procedure, this informal operability
)
determination became invalid after the flow balance was performed in May 1997, The
i
licensee did not evaluate system operability until December 5,1997, and as of
December 18,1997, the condition was not promptly corrected.
10 CFR Part 50. Appendix B, Criterion XVI, " Corrective Action," requires that measures
shall be established to ensure that conditions adverse to quality, such as failures,
malfunctions, deficiencies, deviations, defective material and equipment, and
nonconformances are promptly identified and corrected. The failure to take
,
prompt corrective action when the licensee identified that neither Surveillance
Procedure OP-903-108,"SI Flow Balance Test," Revision 3, Change 1 nor
Technical Specification Surveillance Requirement 4.5.2.h included an adequate
allowance for test instrument uncertainty is an apparent violation of 10 CFR Part 50,
Appendix B, Criterion XVI (50-382/9725-08).
Eailure to ootirnally Adiust thejioh PressuleEafgly Iniection System
The team noted that during the May 1997 flow balance test, the licensee did not take
time to adjust the flow control valve positions to optimize system performance. The
A train /A pump configuration met the flow criteria exactly with no test margin. The
licensee originally planned additiona! limit switch adjustmems, but canceled these
add;tional adjustments when the acceptance limits were met. The team noted that it
would have been possible for the licensee to adjust the flow control valve limit switches
to obtain more margin, but the licensee did not take the time to make the additional
adjustments.
LR9n_Unsellaioly&alradation Update
A HPSI instrumentation loop uncertainty calculation. Calculation EC-195-011, "SI-HPSI
Flow instrumentation Loop Uncertainty Calculation," Revision 0, was performed in 1995
as part of a site-generic effort to update instrument loop uncertainty calculations, and it
was revised on September 18,1996, to implement a revised transmitter calibration
temperature. The team noted that the results of this calculation were not evaluated for
impact on surveillance testing acceptance criteria.
Rssian Bas.ijitung_radeftoiect
As stated above, the original calculation performed by the nuclear steam supply system
vendor to determine an acceptable HPSI flow technical speci5 cation acceptance
criterion was provided to the licensee in September 1997 as part of a design basis
information transfer project. For the first time, this calce!ation quantitatively provided the
licensee with the instrument uncertainty assumption used in the development of the
21
.
..
1
,
technical specification surveillance requirement. The licensee had an open item in the
design basis upgrade project to compare this instrument uncertainty value with the
uncertainty estimate in Calculation EC-195-011, "SI-HPSI Flow instrumentation Loop
Uncertainty Calculation," Revision 1, but the action had not been completed at the time
of theinspection.
'
Similar Low Pressure Safety Iniection System (LPSI) Dgficiency
in Cor,dition Report 97-0649, dated March 19,1997, the licensee determined that an
uncertainty of 725 gpm calculated in Revision 0 of Calculation EC-191-05.2, "LPSI Flow
instrumentation Loop Uncertainty Calculation," exceeded the uncertainty assumed in the
j
development of the corresponding surveillance requirement for the LPSI system portion
i
of Technical Specification 3/4.5.2.h.
The surveillance requirement specified an acceptance limit of 4810 gpm, which provided
adequate allowance for the LPSI flow instrument uncertainty specified in their interface
document with the nuclear steam supply vendor However, the surveillance requirement
was not high enough to provide an adequate allowance for a 725 gpm uncertainty. In an
operability evaluation, the licensee noted that the as-tested flows exceeded the
surveillance requirement acceptance limit. As a result, the licensee determined that the
as-tested flows were sufficient to allow for the larger calculated uncertainty.
The licensee evaluated whether or not the surveillance requirement required revision.
'
They contacted the nuclear steam supply vendor and determired that they could lower
the amount of LPSI flow assumed in the emergency core cooling system analysis. As a
result, the licensee concluded, that even after considering the 725 gpm of uncertainty,
the surveillance requirement,4810 gpm, was acceptable.
In Condition Report CR 97-0649, the licensee documented that there were no stated
requirements to perform 50.59 reviews of calculations and that the interrelationship
between instrument uncertainties and testing to satisfy technical specification limiting
conditions for operation and the use of analytic values was often neither clearly apparent
nor widely understood.
Corrective actions included ensuring that all instrument uncertainty calculations were
evaluated in accordance with 10 CFR 50.59 and reviewing the bases for all technical
specifications to determine whether associated instrument uncertainty was properly
considered. The condition report stated that these efforts were being addressed as
corrective actions for Condition Reports 95-1242 and 96-0382.
The team considered this planned corrective action to prevent recurrence to be
ineffective. On December 11,1997, the licensee evaluated the most recent revision of
the HPSI flow uncertainty calculation and determined that a full written safety evaluation
in accordance with 10 CFR 50.59 was not required. This corrective action should have
resulted in a written safety evaluation for the HPSI flow uncertainty calculation. This
failure to perform a written safety evaluation is discussed in more detailin Section E2.3.
22
,,
.-
c.
Conclusions
The team identified two apparent violations of 10 CFR Part 50, Appendix B, Criterion XI,
related to test control in the HPSI flow baiance test. The licensee had not specified test
instrumentation, which had an accuracy commensurate with the assumptions in 'ho
development of the surveillance requirement. The licensee also had not adequateiy
considered valve position variability when the acceptance limits were established for the
survei!!ance procedure.
.
The team identified two apparent violations of 10 CFR 50. 46. When the licensee
determined that HPSI flow was less than assumed in the emergency core cooling system
analysis, the licensee did not assess the impact of the flow deficiency on peak fuel clad
temperature, They also did not report operation outside of tne design basis or submit a
schedule for the performance of a revised emergency cure cooling system analysis.
The team identified one apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI.
In July 1996, the licensee identified the HPS) test instrumentation uncertainty issue
described above, but did not initiate a separate condition report, perform a documented
operability determination, or correct the surveillance procedure prior to the next test
performance, in addition, the team identified several prior opportunities to correct the
HPSI system flow deficiencies.
E2.3
10 CFR 53,.59 Imolementat on
a.
laspection Scoce (37001)
The team reviewed 4 prescreenings,7 screenings, and 12 safety evaluations involving
permanant modifications, component replacements, engineering calculation changes,
technical specification base changes, and procedure changes.
b.
Qbservations a.D.d Findinas
With the exceptions described below, the team found that the 10 CFR 50.59 written
safety evaluations were generally logical and of acceptable quality, Most of the safety
evaluations addressed the change being evaluated in adequate detail and most provided
the justifications for concluding that there were no unreviewed safety questions.
Appropriate references were provided in many safety evaluations. However, some
safety evaluations did not reference important documents like safety evaluation reports
issued by NRC during the operating license review process, standard review plans, or
appropriate sections in UFSAR.
These documentation deficiencies were discussed with the licensee. The team found
that the licensee had identified similar documentation deficiencies in their intemal
assessment, which was perfc med by quality assurance. The team found that the
licensee had appropriately initiated condition reports for the findings.
23
_
c
v,
.
"
The team identified two instanct s in which a written safety evaluation was not performed
and apparently should have been The team also identified three apparent unreviewed
safety questions that involved changes that were implemented without prior NRC
approval.
Securing Charging During a Loss-of-Coolant Accident (LOCA)
The team identified a failure to perform a written safety evaluation for Change 2,
r
Revision 7, of Procedure OP-902-002, " Loss of Coolant Accident Recovery Procedure." ~
This procedure was the general emergency response procedure for all types of loss-of-
coolant accidents. The change directed operators to secure the charging pumps after a
recirculation actuation signal (RAS) had occurred. As discussed in Section E1.1, the
licencee identified that its post-LOCA containment flooding analysis resulted in an
unacceptable maximum flood level when appropriate uncertainties were considered. To
prevent the instrumentation from becoming submerged, the licensee imposed an
administrative limit of 90 percent maximum RWSP level. In order to provide additional
operating margin for RWSP level, the licensee evaluated the sources of water to
containment following a LOCA and determined that charging pump operation could be
stopped following a RAS.
!-
The team noted that the 10 CFR 50.59 screening for this change stated that, "This
change is purely procedural and does not alter any components in the facility as
described in the Licensing Basis Documents." Therefore, the licensee determined
that a safety evaluation in accordance with 10 CFR 50.59 was not required. The team
identified that Section 6.3.3.3.1 of the UFSAR stated, "In addition to the SIS [high and
low pressure safety injection system] flows, injection from the charging pumps is credited
in the small break analysis for Waterford 3."
!
The team discussed this issue further w;th the licensee to determine if an immediate
safety concern existed with the change in Procedure OP-902-002 to terminate charging
pump flow, which was credited in the ECCS analysis. The licensee stated that charging
pumps were only credited for a small-break loss-of-coolant accident and that the time
when the charging pumps were secured (RAS actuation) was long after the maximum
peak clad temperature had occurred. Therefore, charging pump operation was not
required
'
The team noted that Procedure OP902-002 was the general loss-of-coolant accident
recovery procedure, which also included responses to large-break loss-of-coolant
l
accidents. The team determined that securing a source of coolant credited in the safety _
i
analysis required a written safety evaluation.
24
e
.
10 CFR 50.59 (b)(1) states, in part, that the licensee shall maintain records of changes in
procedures made pursuant to this section to the extent that these . changes constitute
changes in procedures as described in the safety analysis report. These records must
include a written safety evaluation, which provides the bases for the determination
that the change does not involve an unreviewed safety question. The failure of
the licensee to perform a safety evaluation for this change is an apprrent violation of
10 CFR 50.59 (b)(1) (50-382/9725-09).
10 CFR 50.59 Screening Review for Calculation EC-195-011
On December 18,1997, the team requested the 10 CFR 50.59 safety evaluation for the
most recent revision of Calculation EC-195-011. "SI-HPSI Flow instrumentation Loop
Uncertainty Calculation," Revision 1, dated September 18,1996. The team found that as
of December 18,1997, the licensee had not performed a written safety evaluation for this
calculation.
The licensee performed a screening review of the calculation on December 11,1997,
and incorrectly concluded that the instrument loop uncertainty calculation did not have
the potential to alter the information described in license basis documents. The team
found that the calculation did have the potential to alter the information described in
l
license basis documents. For example, UFSAR, Section 6.3.3.1, " Emergency Core
1
Cooling System Performance Evaluation," stated that the results of the ECCS
f
performance analysis show that the plant meets the 10 CFR 50.46 acceptance criteria.
j
The team noted that, when the results of Calculation EC-195-011 were applied to the
i
NRC approved model, it resulted in exceeding the 10 CFR 50.46 ECCS acceptance
criteria, which changed the facility as described in UFSAR, Section 6.3.3.1.
,
The team determined that failure to perform a written safety evaluation apparently
resulted in operation with an unreviewed safety question, without prior NRC approval.
The results of Revision 1 to Calculation EC-195-011 effectively made a change to the
facility described in the safety analysis report, which reduced the margin of safety
defined in the basis for a technical specification. Specifically, UFSAR, Table 6.3-7,
"HPSI Pump Minimum Delivered Flow to Reactor Coolant System for The 0.04 FT' Break
Analysis," stated that 207.25 gpm is 25 percent of the delivered flow from one high
pressure pump at .0 psig (or the flow in one injection path). The safety analysis assumed
that flow is delivered from three out of four of the injection paths or a total of 621.8 gpm.
Technical Specification Bases 3/4.5.2 stated that the surveillance requirements ensure
that, at a minimum, the assumptions used in the safety analysis are met. The bases
j
section further stated that maintenance of proper flow resistance and pressure drop in
'
the piping system to each injection point is necessary to provide an acceptable level of
4
total ECCS flow to all injection points equal to or above that assumed in the ECCS LOCA
i
analyses.
)
,
25
e
.
However, after consideration of instrument uncertainty as calculated in Revidon 1 of
Calculation EC-195-011, the licensee estimated that Technical Specification 4.5.2.h did
not assure HPSI flow greater than the assumptions in the ECCS LOCA analyses.
Twenty-five percent of the surveillance acceptance limit less uncertainties was 197 gpm,
which was less than 207.25 gpm specified in UFSAR, Table 6.3-7. As a result, this
revision reduced the margin of safety defined in Technical Spccification Bases 3/4.5.2,
because the surveillance no longer provided an acceptable level of flow to all points
equal to or above that assumed in the currently licensed ECCS-LOCA analyses.
10 CFR 50.59 (a)(1) states, in part, that a licer,see may make changes in the facility as
described in the safety analysis report without prior Commission approval unless the
.
'
proposed change involves a change in the technical specifications incorporated in the
license or an unreviewed safety question.10 CFR 50.59 (a)(2) states that a proposed
change, test, or experiment shall be deemed to involve an unreviewed safety question if
the margin of safety as defined in the basis for any technical specification is reduced.
The reduction in the margin of safety as defined in the basis for a technical specifir?;cn
was considered to be an unreviewed safety question and the first example of appant
violation of 10 CFR 50.59(a)(1) (50-382/9725-10).
Emergency Feedwater Pump Capability (SE 97-165)
The team identified a second example of a change to the facility described in the
UFSAR, which apparently involved an unreviewed safety question. On July 10,1997,
the licensee revised the bases section of the technical specifications to reduce
emergency feedwater pump capability requirements below the assumptions made in the
safety analysis.
The affect of this change on system operability was reviewed in NRC Inspection
Reports 50-382/96-202 and 50-382/97-10. In NRC Inspt ction Report 50-382/96-202, the
NRC noted that Calculation EC-M96-004, " Design Basis Reconstitution for EFW Flow
Rate," Revision A, datermined that minimum required emergency feedwater flow rate
was 575 gpm. This flow rate was needed to provide a 4980 pounds-mass steam
generator margin while using a 10 percent decay heat uncertainty value. The NRC
agreed with the licensee's determination that current pump capability supported the
operability of the emergency feedwater system.
Reduction in the Marcin of Safetv
UFSAR, Section 10.4.9.2, " Emergency Feedwater System Description," stated that the
turbine driven pump or both motor-driven pumps together have been designed to
provide 700 gpm flow to the steam generators upon loss of feedwater flow in order to
remove decay heat and to reduce reactor coolant system temperature and pressure to
the shutdown cooling entry conditions.
,
26
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O
.
From December 18,1984, until July 10,1997, Technical Specification Bases 3/4.7.1.2
stated that each electric-driven emergency feedwater pump is capable of delivering a
total feedwater flow of 350 gpm at a pressure of 1163 psig to the entrance of the steam
generators. The steam-driven emergency feedwater pump is capable of delivering a
total feedwater flow of 700 gpm at a pressure of 1163 psig to the entrance of the steam
generators.
On July 10,1997, the licensee approved Safety Evaluation 97-165 for Licensing
Documen+. Change Request (LDCR) 97-0034. LDCR 97-0034 revised Technical
Specification Bases 3/4.7.1.2 to reduce the pump capability requirements to the
following: "The two electric-driven emergency feedwater pumps combined are capable of
delivering a total feedwater flow of 575 gpm at a pressure of 1102 psig to the entrance of
the steam generators. The steam-driven emergency feedwater pump is capable of
delivering a total feedwater flow of 575 gpm at a pressure of 1102 psig to the entrance of
the steam generator."
The team noted that the safety analysis performed for the current operating cycle,
Cycle 9, was based on two motor-driven pumps producing a combined flow of 630 gpm
at 1102 psig and on the turbine driven pump producing 645 gpm at 1102 osig. The
licensee did not perform a revised safety analysis for the lower emergency feedwater
flow rates,575 gpm at 1102 psig (combined electric pumps or turbine-driven pump).
l
The team determined that this change was an apparent reduction in the margin of safety
!
as defined in the basis for a technical specification,
lacigate in the Probability of a Malfunction
Updated Final Safety Analysis Report, Section 15.2.3.1, "Feedwater System Pipe
Breaks," indicated that no operator actions were assumed for the first 30 minutes
following a main feedwater line break. With reduced emergency feedwater flow, the
reactor coolant system will heat up faster, which could cause the pressurizer to become
'
solid and lift the relief valves. The relief valves were designed to discharge steam not
water and cannot be relied upon to close in this situation. If these relief valves were to
stick open, a small break LOCA would occur. Using licensed safety analysis methods,
the nuclear steam supply vendor determined that operator actions to secure charging
was needed 7 minutes after the reactor trip. The licensee determined by alternative and
less conservative analysis rnethods that at the reduced emergency feedwater flow rates
(575 gpm at 1102 psig), operator actbn would be needed within 25 minutes to secure
charging pumps to prevent the pressurizer from going solid rather than the 30 minutes
that was stated in the UFSAR. The team noted that UFSAR Section 15.6.3.4,
.
" inadvertent Opening of a Pressurizer Safety Valve," contained an estimate of the
'
frequency of inadvertent opening of a pressurizer safety valve. The team determined
that the reduced operator action time increased the probability of a malfunction of the
pressurizer relief valves and increased the probability of a LOCA.
27
.
"
Unreviewed Safety Question Determination
The team determined that the reduction in emergene feedwater pump capability
I
requirements reduced the margin of safety as defined in the basis of a technical
specification, increased the probability of a previously evaluated malfunction (stuck open
pressurizer safety valve) and increased the probability of a LOCA. The change in
emergency feedwater pump capability requirements was considered to be an
unreviewed safety question and the second example of an apparent violation of
10 CFR 50.59 (a)(1) (50-382/9725-10).
Hydrogen Analyzer (LDCR 98-0032)
{
i
The team identified a third example of a change to the facility as described in the
UFSAR, which apparently involved an unreviewed safety question.
All accident analyses assume containment is isolated and leakage le less than an
assumed value. To ensure this assumption is valid, the originallicense application
included the following commitments regarding the containment isolation system. Final
J
Safety Analysis Report, Section 6.2.4.2.1, " Actuation Signal," included a commitment to
'
meet 10 CFR Part 50, Appendix A, General Design Criteria 54," Piping Systems
Penetrating Containment." General Design Criteria 54 str2s,
'
" Piping systems penetrating primary reactor containment shall be provided with
leak detection, isolation and containment capabilities having redundancy,
reliability, and performance capabilities which reflect the importance to safety of
isolating these piping systems."
Final Safety Analysis Report Section 6.2.4.3.2, " Single Failure Analysis," stated
that wherever two automatic isolation valves are in series, each valve operator is
'
actuated from a separate and redundant containment isolation actuation signal (CIAS)
channel. The licensee's original technical specifications, issued as NUREG 1117,
" Technical Specifications, Waterford Steam Electric Station, Unit No. 3," Table 3.6-2
designated Hydrogen Analyzer Valves HRAISV0110A(B), HRAISV0109A(B), and
HRAISV0126A(B) as automatic containment isolation valves.
To ensure the availability of the hydrogen analyzer post accident, Final Safety Analysis
Report Section 6.2.5.2.1, " Hydrogen Analyzer System," stated that the system consisted
of two identical units which are completely independent of each other and are powered
from an independent source. Therefore, assuming a single failure, process capability is
available to monitor the hydrogen concentration in containment. Also in this section, it
was noted that the isolation valves for the hydrogen analyzer system are normally locked
closed and the automatic actuation signal can be overridden for analyzing after a LOCA.
<
28
.
.
In late 1995, the licensee determined that the commitment to have a single failure
proof containment isolation system conflicted with the commitment to have an
available single failure proof post-accident hydrogen analyzer. To operate the hydrogen
analyzers, it was necessary to open the associated containment isolation valves. The
'
licensee reasoned that the commitment to have an available post-accident hydrogen
analyzer implied that the associated containment isolation valves would also be
available. If they used the standard containment isolation design practice of using one
train of power for the inboard isolation valve logic and the other train of power for the
outboard containment isolation valve logic, the failure of one power supply would prevent
use of either hydrogen analyzer. On January 3,1996, the licensee approved a change
to UFSAR, Section 6.2.4.3.2, " Single Failure Analysis," to allow an exception to the
containment isolation single failure commitment for Hydrogen Analyzer
Valves HRAISV0110A(B), HRAISV0109A(B), and HRAISV0126A(B). They added the
following to UFSAR 6.2.4.3.2:
"To maintain compliance with Regulatory Guide 1.7, GDC #14, i.e., to be able to
measure containment hydrogen concentration after LOCA despite the worst
single active failure, Waterford 3 had designed the HRA [ hydrogen recombiner
analyzer] containment isolation valves so that CIAS Channel A is exclusively
used in HRA Train A containment isolation valve control circuits. Similarly, CIAS
Channel B is exclusively used in HRA Train B containment isolation valve control
circuits."
On November 26,1997, the licensee identified that the hydrogen analyzer piping was not
designed to meet 10 CFR Part 50, Appendix A, General Design Criteria 54, " Piping
Systems Penetrating Containment." The licensee determined that this design <d not
meet the General Design Criteria 54 requirement to maintain reliable redundancy to
ensure containment isolation. Failure of one CIAS relay would defeat containment
isolation of the hydrogen analyzer. The licensee reported operation outside of the
Technical Specification 3.6.3 in Licensee Event Report 50-382/97-032.
To resolve the design issue, the licensee reclassified Hydrogen Analyzer Valves
HRAISV0110A(B), HRAISV0r IA(B), and HRAISV0126A(B), from automatic to
manual / remote manual, locket closed, containment isolation valves. This change
effectively substituted operator action for a 5-second automatic closure. The change
introduced the possibility that an operator would not be able to close the valves within 5
seconds of the containment isolation actuation signal, which introduced the possibility of
increased dose consequences to the public. However, the team noted that this
distinction was only important during surveillance testing. At all other times during
normal operation, these valves were required to be locked closed.
The team noted that the accident analyses assumed all containment isolation valves
were closed and leakage was controlled below a minimum value. The licensed
configuration, a single-failure proof redundant automatic isolation, would be less likely to
result in a failure to isolate containment, than reliance on manual / remote manual closure
of the valves. The licensee had not evaluated the dose consequences of the failure to
close the valves or requested NRC staff review of the reclassification. The team
29
'
.
.
determined that tNe change described in LDCR 98-0032 introduced the possibility of a
malfunction of a different type than any previously evaluated in the safety analysis report.
The introduction of the possibility of a new malfunction was an unreviewed safety -
question and the third example an apparent violation of 10 CFR 50.59 (a)(1)
(50-382/9725-10).
c.
Conclusions
,
The team identified two apparent violations of 10 CFR 50.59. The first apparent violation
involved a failure to perform a written safety evaluation. The second apparent violation
included three examples of changes to the facility that involved unreviewed safety
questions, which had not been approved by the NRC. Other 10 CFR 50.59 written safety
evaluations reviewed by the team were generally logical and of acceptable quality.
E3
Engineering Procedures and Documentation
E3.1
Engineerina Reauest Process
a.
InsDection Scoce (37550.)
The team reviewed Procedure W4.104, " Engineering Request Process," Revision 0, and
25 engineering requests. The team dis Jssed the engineering request process and
some of these engineering requests with appropriate licensee personnel.
b.
Observations and Findings
'
The team discussed the engineering request process with the licensee. While not fully
implemented, the licensee planned for the engineering request process to provide a
single process governing initiation of requests for engineering technical support. The
team noted that the engineering request process included requests for changes to plant
related structures, systems, and components. The team found that this process
eliminated the generation of requests in different forraats.
The licensee stated that Phase 1 of the engineering request process was implemented
on April 1,1997. Phase 1 consisted of preparing engineering requests for engineering
replies, administrative changes, and engineering evaluations that had no design changes
associated with them. The management expectation was that there would be no design
changes performed using the engineering request process during Phase 1, The licensee
stated that Phase 1 replaced engineering inputs and problem evaluation /information
requests. The team determined that all of the open problem evaluation /information
requests were converted to engineering requests or were closed.
The licensee stated that Revision 1 of Procedure W4.104 would be in effect on
December 15,1997. The licensee also stated that Phase 2 of the engineering request
process implementation would be completed by March 31,1998. The licensee stated
that Phase 2 would replace the following engineering programs:
30
. _
.
.
.
.
.
.
Control of vendor information
Temporary alteration requests
+
Set point changes
Design changes
-
Engineering reviews
Substitute part engineering evaluation report
-
Resolving procurement document change requests
+
Design proposals
+
Design change packages
-
The team reviewed 25 engineering requests generated for the safety injection system
and other safety-related systems. Several concerns were identified by the team and
satisfactorily addressed by the licensee.
c.
Conclusions
The team found that the licensee had not completed the transition to the new
engit.eering request process. The licensee satisfactorily resolved concerns identified by
the team related to a review of 25 engineering requests.
E3.2
Desian Bases Documentation - 125V DC Distribution System
a.
Insoection Scoos (37550)
The team reviewed Design Basis Document DBD-008, " Electrical Distribution (DC
portion)," dated February 28,1996.
b.
Observations and Findings
The team 'ound that the design basis document for the de electrical distribution system
was generally comprehensive and was being appropriately updated by the licensee. The
team did identify some missing references to applicable regulations and commitments,
as well as, some minor update erro s. The team discussed these minor weaknesses
with the licensee. The licensee agreed that they were weaknesses and planned to
correct them.
c.
Conclusions
in general, the design basis document for the de electrical distribution system was
comprehensive and was being appropriately updated by the licensee.
'
E33
Seismic Quahfication Documentation - 125V DC Station Batteries
a.
10inection Scoce (37550. 93809)
The team reviewed the documentation related to the seismic qualificatim of the station
batteries.
31
s
.
e
b.
Observations and Findinas
The licensee stated that the batteries were installed in 1992 and seismically qualified for
i
20 years. The team found that the licensee had qualified the batteries by equivalency,
based on the battery vendor's Qualification Report OR-51155-01. The team identified
that the qualification test included aging-related test failures, which the licer,see argued
were not applicable to the installed batteries. The licensee noted that the installed
batteries were similar to cells, which passed the qualification test. The team noted that
the qualification report did not include documentation of a test of the exact design
installed at Waterford 3.
Subsequent to the exit interview, the licensee provided excerpts from a seismic test
report for the e"act battery cell design installed at Waterford 3. The seismic test was
conducted successfully on 15-year cells, for the Diablo Canyon Nuclear Power Plant, a
facility with more rigorous seismic requirements. The Diablo Canyon test results also
identified failures for 20-year old cells. Since, the Waterford 3 batteries were installed in
1992, these test failures were not presently applicable to the bterford 3 batteries. The
team determined the current seismic qualification of the Waterford 3 batteries was
acceptable.
The licensee believed that their seismic qualification test documentation adequately
'
demonstrated qualification for 20 years. However, based on the Diablo Canyon
test result failures for the 20-year old batteries, they initiated Engineering
Request W3-98-0134 to evaluate whether further testing was needed to qualify the
Waterford 3 batteries for the 15- to 20-year period.
i
c.
Conclusions
The current seismic qualification of the Waterford 3 safety-related station batteries was
?
acceptable. Seismic qualification, from 15- to 20-years qualified life, was not clearly
established. The licensee initiated an engineering request to further evaluate the
qualification of the batteries.
E3.4
Environmental Qualification of the Static Uninterruotible Power Sucolv (SUPS)
a.
Inspection Scope (37550,93809)
The team reviewed the documentation related to the seismic qualification of the station
batteries.
b.
Observations and Findinos
During the walkdown of the de system, the team noted that the SUPS, or inverters, were
j
ooerating without fan cooling. The inverters were being cooled by natural draft air
'
circulation. While this operation was in accordance with design, the team was concerned
1
32
a
e
I
i
this design might be vulnerable to loss-of-room cooling. The team requested
documentation related to the inverter's capability to reliably operate for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, following
i
a station blackout.
1
The team found that during a station blackout. a 120 F temperature was used as the
upper design limit for the room where the inverters were located. The team found that
the vendors' documentation for the inverters, indicated an upper ambient temperature
limit for inverter operation of 104' F. The team was concerned that a 120 F limit on room
temperature was inappropriate considering the vendor limit on inverter operation of
104 F. Also, the inverter design did not include any forced drsit cooling. In addition, the
licensee had not established any compensatory measures to enhance cooling in the
event of a station blackout.
The licensee referred the team to their station blackout submittal dated April 14,1989,
and NUMARC 87-00 " Guidelines and Technical Bass; for NUMARC Iritiatives
j
Addressing Station Blackout." They stated that these documents justified that specific
'
thermal qualification was not necessary for the inverters, as le'g as the room
temperatures stayed below the 120'F limit. During the insperSon, the licensee contacted
the vendor. The vendor provided a preliminary determination that the SUPS could
operate for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at the 120 F limit. The vendor stated that they would perform
additional aniJysis to confirm this determination.
On May 9,1998, the licensee provided additional vendor documentation. The vendor
'
found that a similar model or inverter was tested at 122 F for 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> under both full
and no load with no degradation in performance specifications. The vendor concluded
this test data demonstrated that the inverters at Wate: ford 3 will function in an ambient
temperature of 120 F for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
c.
Conclusions
The team found that the reliability of the safety-related inverters during station blackout
conditions was not clearly established. The licensee contacted the vender and was
provided additional documentation that confirmed the capability of the safety-related
inverters to operate at room temperatures expected during a station blackout.
E4
Engineering Staff Knowledge and Performance
E4.1
Interview of Staff Personnel
a.
Inspection Secoe (37550)
During the inspection, the team interviewed a number of engineering personnel
regarding a wide variety of technicalissues.
33
l
i
.
9
b.
. Observations and Findings
l
In general, licensee personnel were knowledgeable of the equipment and systems,
which were assigned to them. During walkdowns, they comprehensively answered
questions and weo able to discuss relevant equipment issues. In many instances,
during the inspectan. the team identified potential areas for concern, which were readily
resolved by licensea personnel.
c.
Conclusions
in general, licensee personnel were knowledge able of the equipment systems assigned
to them.
E6
Engineering Organization and Administration
E6.1
Engineerino Backfoos
i
a.
Insoection Scooe (37550)
The team reviewed the engineering request and condition report backlogs to determine
the trend of these backlogs. Since the engineering request process was new, the team
reviewed all of the available backlog data. The team reviewed the backlog of condition
reports for plant engineering from July 1996 to November 1997. The team also
.
assessed licensee resolution of specific engineering requests and ( ondition reports as
documented in Sections E3.1 and E7.1 of this report.
b.
Observations and Findinos
Engineering Requests
The team determined that the engineering request backlog was increasing. The. team
noted that, since May of 1997, the engineering request backlog increased from 10? open
items to 250 open items. The team discussed the plans to reduce the backlog with the
licensee and found that the licensee planned to rM nitor the backlog for a few months
prior to implementing any corrective actions to reouce the backlog. The licensee stated
that the engineering requests were trended biweekly by providing each supervisor a list
of the open items for which they were responsible. In addition, the licensee stated that
the engineering requests were trended monthly by providing management a graph of
engineering requests initiated and closed. The licensee stated that they had plans to
initiate a performance indicator for the average age of open engineering requests.
The licensee acknowledged the backlog was increasing, but viewed the increase as
manageable. They stated that the increase occurred, in part, because of increased
emphasis on completing corrective actions for condition reports.
34
.
.
Condition Reports
The team noted that there were 261 open condition reports in July 1996 and 221 open
condition reports in November 1997 for system engineering. The team determined this
was a downward trend for system engineering.
,
For design engineering, the team found that there were 221 open condition reports in
July 1996 and 345 open condition reports in November 1997. The team noted that a
number of condition reports were opened for design engineering during the refueling
outage in March through July 1997. The number of open design engineering condition
reports peaked at 414 in May 1997 and trended down to 345 in Novenicer 1997. After
considering the timing of the refueling outage, the team determined that the number of
open condition reports for design engineering also trended downward.
,
c.
Conclusions
The team determined that the engineering requests backlog wr increasing. The
licensee acknowledged the backlog was increasing, but viewed the increase as
manageable. They stated that the increase occurred, in part, because of increased
emphasis on completing corrective actions for condition reports. Based on the
decreasing trend in the number of condition reports and the acceptability of the condition
reports as documented in Section E7.1 of this report, the team concluded that the
licensee was effectively reducing the condition report backlog.
E7
Quality Assurance in Engineering Activities
E7.1
Condition Reoort Review
a.
Insoection Scooe (37550)
The team reviewed Procedure W2.501, " Corrective Action." Revision 6, and 22 condition
reports. The team discussed the condition report process w;th licensee personnel. In
addition, the team discussed some of the condition reports with applicable licensee
personnel.
b.
Observations and Findinas
The team determined that the purpose of the corrective action procedure was to provide
a means to promptly identify and correct adverse conditions. Adverse conditions were
defined as an event, defect, characteristic, state, or activity that prohibited or detracted
from the safe, efficient operation of the plant. The team determined that adverse
conditions ;ncluded nonconforming conditions, conditions adverse to quality, industrial
safety concerns, and plant reliability concerns.
35
.
.
The team reviewed 22 condition reports associated with the safety injection system.
The team noted that Condition Reports 97-1675 and 97-1288 identified configuration
control problems. As described in Section E3.1, the team also identified Engineering
Request ER-W3-97-0144, which involved a configuration control problem.
Condition Report CR-97-1675, dated June 26,1997, identified that the 26.5-inch
-
diameter round nc:zle strainers, shown on Design Drawing G-907 for the
refueling water storage pool, which should have been installed inside the
box-type pool strainers on each of the lines, were not installed. The licensee did
not have any evidence that the round nozzle strainers had ev6r been installed.
The licensee determined that large box-type pool strainers located at suction
lines were added to the design later to comply with nuclear steam supply vendor
criteria for particulates in the reactor core and the installation of the box strainers
superseded the need for the round strainers. The licensee concluded that the
26.5-inch round strainers were not required since the round screens were on the
design drawings downstream of the box strainers and the round strainers utilized
screen mesh size with much larger openings.
The team reviewed Condition Report CR-97-1288, dated May 21,1997, which
-
determined that there was no seat material on the fitting of the solenoid for
Valve SP ISV0105. The solenoid was the containment isolation solenoid for
the containment sump pump inside containment and the seal material was the
equipment qualification boundary. The licensee declared the solenoid valve
inoperable and repaired the seal. In the reportability determination, the licensee
noted that an electrical failure of the solenoid valve wo ld not prevent the -
containment isolation valve from performing its safety function to close. The
licensee noted that the air-operated containment isolation valve failed closed on
loss-of-power to the solenoid. Once a containment isolation occurs, the solenoid
is de-energized. Therefore, there is no electrical failure mode at the solenoid,
which will result in the valve inadvertently opening. The licensee determined that
the valve had an active iosed requirement only and the missing sealin the
solenoid would not make the containment isolation valve inoperable.
The team reviewed Engineering Request ER-W3-97-0144, dated May 23,1997.
-
The engineering request was initiated for engineering to perform an evaluation of
diesel generator component bolting that was not instaPed in accordance with
vendor drawings. The emergency diesel generator standpipe, Jacket water
heater, and tube oil heater were installed with some of the installed botting snorter
than those shown on the vendor drawings. The licensee stated that they
attempted to install loager bolts in accordance with the vendor drawing. During
bolt changeout, the licensee determined that the longer bolts would not fit in the
areas where the shorter bolts were found. The licensee also identified that four of
the standpipe flange bolts were incorrect material. The vendor drawing specified
SA193, Grade B7 heavy hex bolts. However, four of the installed bolts were SAE
Grade 5, regular hex, which was not as strong as the SA193, Grade B7 material.
The licensee installed SA193, Grade B7 bolting, which was short enough to fit.
36
-.
.
.
The vendor's design drawings contained the longer bolts and the correct material
bolts. The vendor agreed that the as-built length was correct and the drawing
was in error. In addition, the vendor agreed that the SAE Grade 5 bolts
previously installed were the wrong material and should be SA 193 Grade 67 as
shown on the design drawing. The inspectors determined that this was an
example of a lack of configuration control.
While individually, these conditions were satisfactorily resolved, the team was concerned
that based on the sample size, that a high percentage of the examples involved
configuration control problems. The team determined that these examples rnay indicate
an adverse trend related to configuration control. Additionalinspection is planned to
evaluate the licensee's program for identifying adverse trends as it applies to these
recent configuration control findings. This inspection will be tracked as ar$ !nspection
followup item (50-382/9725-11).
c.
Conclusions
The team noted that 2 of the 22 condition reports reviewed had configuration control
problems. Further inspection is planned to determine whether an adverse trend exists
rdateo to configuration control.
E8
Miscellaneous Engineering issues
E8.1
(Closed) Insoection Followuo item 50-382/96202-01: Instrument uncertainties for
component cooling water system and auxiliary component cooling water system.
Backaround - The licensee did not account for measurement and other uncertainties in
the evaluation of flow test results associated with the component cooling water (CCW)
and auxiliary component cooling water (ACCW) systems. The ficansee planned to
address this issue from a generic perspective to ensure that all relevant uncertainties
were accounted for in the evaluation of test acceptance criteria.
,
A corporate-wide instrumentation and control peer group began work on a policy to
consider instrument uncertainties in special test procedures and other related plant
surveillance test parameters. At the time of this inspection, the due date 'or completion
I
of this effort was February 28,1998.
Insoection Followuo - The team reviewed Engineering Report ER-W3-97-0174-00-00,
"CCW and ACCW Flow Balance Test Acceptance Criteria," dated May 19,1997. This
document indicated that the design basis minimum ACCW flow to the CCW/ACCW heat
exchanger was 4500 gpm. UFSAR Table 9.2-1 supported this figure. During a flow
b4: lance test conducted May 8,1997, the measured ACCW flow rate was 4662 gpm.
Accu ding to the report, the uncertainty in this measured flow was 350 gpm. Therefore,
r
the acNal flow rate may have been as low as 4312 gpm.
37
f
s
,
.
.
The team found that the licensee determined that it was not necessary to apply any
uncertainty to the flow balance test acceptance criteria, because a flow measurement
uncertainty term was already included in the assessment of system capability during
thermal r rformance testing. The licensee stated that the performance of the
CCW/A' W heat exchanger from the ACCW (shell) side was defined by two
i
pararrets t (1) a ficw of 4500 gpm or greater and (2) a fouling factor of 0.0011 or less.
n the above test, the measured fouling factor was approximately 0.0007. The
measurecent of the fouling factor included application of uncertainties for all
measurements. The licensee stated that since flow measurement unwrtainties were
included in the fouling factor measurement it was not necessary to factor uncertainties
into the flow rate measurement in the flow balance test, in the sense that this would be
double-cccounting for the uncertainties of the flow instruments.
The team did not agree. The team noted that thermal performance testing included two
phases. Initially, the licensee used measured flows and temperatures and an estimate of
the associated measurement uncertainties to derive the heat exchanger fouling factor.
Then the licensee used the derived fouling factor, the design heat load, and the design
flow to determine whether the heat exchanger was capable of adequately cooling the
component cooling water system. The team noted that the licensee assumed in the
second phase of the calculation that a design flow of 4500 gpm would be available. The
team determined that this was an analytic value and that the acceptance limits for the
flow balance test should be revised to include sufficient measurement uncertainty to
ensure this analytic assumption would be met.
10 CFR Part 50, Appendix B, Criterion XI, requires, in part, that all testing required to
demonstrate that structures, systems, and components will perform satisfactorily in
service is performed in accordance with written test procedures, which incorporate the
requirements and acceptance limits contained in applicable design documents.
As of December 18,1997, the licensee had not corrected Engineering
Procedure UNT-001-002, "ACCW & CCW System Flow Balance," Revision 14, to
incorporate an acceptance limit allowance for flow instrument uncertainty, as
necessary to ensure that the flow assumptions used in the thermal performance test
were met. The failure to include an appropriate acceptance limit in Engineering
Procedure UNT-001-002, Revision 14, is a further example of an apparent violation of
10 CFR Part 50, Appendix B, Criterion XI (50-382/9725-05).
The licensee also stated that the fouling factor margin (i.e.,0.0007 versus 0.0011)
sufficiently accounted for the flow rate deficit. The reasoning for this position was that
the 4500 gpin ACCW minimum flow was a design basis limit that was intended to be one
of two necessary conditions. A sufficient flow and low fouling factor were necessary to
<
demonstrate operability of the heat exchanger. Therefore, the margin in the fouling
38
.
.
factor would offset the uncertainty in the flow-rate acceptance criteria. In addition, the
licensee noted that they used a 3-sigma confidence interval to develop their
measurement uncertainties, which is mere restrictive than the 2-sigma interval, which is
usually assumed. The team acknowledged the licensee's reasoning and considered it
adequate to conclude that the CCW/ACCW heat exchanger was operable with flow rates
potentially less than design.
E8.2 (Ocen) Insoection Followuo item 50-382/9708-01: Review licensee evaluation of the
adequacy of instrument uncertainties.
Backaround - The licensee initiated long-term corrective action to use vendor guidelines
to review, evaluate, and document technical specification instrument uncertainty
calculations and to verify that technical specification surveillance test acceptance criteria
were consistent with these instrument uncertainties.
Insoection Followuo - The completion date for this effort was June 30,1998, but the
licensee stated that the project should be completed earlier than June 30,1998. At the
time of the inspection, the licensee estimated that the project was 80 to 85 percent
complete. A total of 10 condition repods were written to document identified
discrepancies. However, in all cases the licensee determined that the equipment
remained operable.
E8.3 (Closed) Licensee Event Reoort 50-382/97-007: Voluntary licensee event report on
refueling water storage pool level indication inaccuracies. This event was discussed
'
in NRC Inspection Repoit 50-382/97-12, which identified two unresolved items:
50-382/9712-01 and -02. Further review of the event described in this licensee event
report will be tracked by these unrescived items.
E8.4 (Closed) Licensee Event Reoort 50-382/97-015: Ultimate heat sink did not
incorporate conservative assumptions. This event was discussed in NRC Inspection
Report 50-382/97-16. Discretion was granted for this design control violation in
accordance with Section Vll.B.4 of the Enforcement Policy (Reference EA 97-415).
E8.5 (Closed) Violation 50-382/9714-0j: Failure to maintain UFSAR accurate.
Backaround - In NRC Inspection Report 50-382/97-14, the NRC identified three
examples of a failure to update the licensing basis as required by 10 CFR 50.71(e).
The hT concluded that all necessary corrective actions had been initiated and
therefore concluded that no response to the violation was required. In NRC Inspection
Report 50-382/97-21, the NRC verified the completed corrective actions for two of the
examples, but held the violation open pending completion of corrective actions for
the third example, related to updating a technical specification bases section. On
October 20,1997, the licensee submitted a response to Violation 50-382/9714-01,
asking the NRC to reconsider its position that technical specification bases sections
were required to be updated pursuant to 10 CFR 50.71(e). The eensee maintained that
changes to technical specification bases sections should be controlled in accordance
with 10 CFR 50.59.
39
F
~
{
,
-
L
insoection Followuo - On January 23,1998, the NRC agreed with the licensee's position
that technical specification bases sections were not required to be updated pursuant to
10 CFR 50.71(e), but rather should be controlled pursuant to 10 CFR 50.59. The NRC
withdrew Example 3 of the violation (EA 97-593). Since no further action is required of
the licensee, this violation is closed.
!
Note: In the January 23,1998, correspondence, the NRC stated that futher review of
Safety Evaluation 97-165 would be conducted. This review is documented in
Section E2.3.
l
i
V. Manaaement Meetinas
4
(,
X1 Exit Meeting Summary
The team met with the management of Waterford 3 Steam Electric Station on December 18,
1997, to conduct a technical debrief prior to leaving site. Following additional in-ofGee review
and telephonic discussions of the team's findings, an exit interview was conducted on
February 5,1998, by the team leader, accompanied by the acting engineering branch chief. The
team leader noted that team personnel had reviewed proprietary documentation during the
course of the inspection. Proprietary documentation was not removed from the site. The
licensee acknowledged the team's findings.
i
I
1
l
40
.
.
6.TTACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensas
T. Brennan, Technical Support Coordinator
C. Dugger, Vice President
E. Ewing, Director, Nuclear Safety & Regulatory Affairs
C. Fugate, Operations Shift Superintendent
T. Gaudet, Manager Licensing
P. Jackson, Supervisor, Electrical / Instrumentation and Control
D. Matthews, Licensing Specialist
j
B. Randolph, Licensing Specialist
J. Reese, Senior Engineer, Mechanical
D. Viener, Supervisor, Applied Mechanics Engineering
A. Wrape, Director, Design Engineering
NBC
J. Keeton, Resident inspector
C. Liang, Office of Nuclear Reactor Regulation
T. Scarbrough, Office of Nuclear Reactor Regulation
Dr. Saba N. Saba, Office of Nuclear Reactor Regulation
i
Mr. Frank Ashe, Office of Nuclear Reactor Regulation
]
INSPECTION PROCEDURES USED
37001
10 CFR 50.59 Safety Evaluations
37550
Engineering
92903
Followup - Engineering
93809
Safety System Engineering Inspection (SSEI)
4
ITEMS OPENED, CLOSED, AND DISCUSSED
1
Ooened
50-382/9725-01
HPSI and CS NPSH margin inaccurately stated in UFSAR
(Section E1.1).
1
.
.
50-382/9725-02
Inadequate containment floodir;g calculations resu t in
nonqualified instrumentation (Section E1.1).
50 382/9725-03
Main feedwater isolation valve operability questioned
(Section E1.2).
50-382/9725-04
Failure to follow condition reporting procedures as required by
10 CFR Part 50, Appendix B, Criterion V (Section E1.2).
50-382/9725-05
APV
Apparent failure to specify sufficiently accurate test
instrumentation, and to consider valve position variability and
measurement uncertainty when establishing test acceptance
criteria as required by 10 CFR Part 50, Appendix B Criterion
XI (Sections E2.2 and E8.1).
50-382/9725-06
APV
Apparent failure to assess the affect of lower than assumed
HPSI flow on peak clad temperature as required by 10 CFR 50.46(a)(3)(i) (Section E2.2).
50-382/9725-07
APV
Apparent failure to report operation outside of design basis of
facility and apparent failure to submit schedule for
performarce of a new ECCS analysis as required by
10 CFR 50.46(a)(3)(ii) (Section E2.2).
50-382/9725-08
APV
Apparent failure to promptly correct HPSI flow balance test to
account for instrument uncertainty as required by
l
10 CFR Part 50, Appendix B, Criterion XVI (Section E2.2).
50-382/9725-09
APV
Apparent failure to perform written safety evaluation for a
change to LOCA EOP as required by 10 CFR 50.59(b)(1)
(Section E2.2).
50-382/9725-10
APV
Prior NRC approval was not obtained for three changes,
which appareatly involved unreviewed safety questions, as
required by 10 CFR 50.59(a)(1) (Section E2.3).
50-382/9725-11
!FI
Evaluation of possible adverse configuration control trend
(Section E7.1).
Closed
i
50-382/96202-01
IFl
CCW and ACCW instrument uncertainties not adequately
accounted for in the evaluation of test results (Section E8.1).
50-382/97-007
LER
Voluntary LER on RWSP level indication inaccuracies
l
(Section E8.3).
!
50 JB2/97-015
LER
Ultimate Heat Sink design basis did not include conservative
assumptions (Section E8.4).
50-382/9714-01
Failure to accurately maintain the UFSAR (Section E8.5).
2
]
a
.
D?scussed
50-382/9708-01
IFl
Review licensee's evaluation of the adequacy of instrument
uncertainties (Section E8.2).
LIST OF ACRONYMS USED
auxiliary component cooling water
APV
apparent violation
component cooling water
CFR
Code of Federal Regulations
CIAS
containment isolation actuation signal
~ CIV
containment isolation valve
emergency feedwater
emergency operating procedure
Electric Power Research Institute
flow control valve
gpm
gallons per minute
high pressure safety injection
,
IFl
inspection followup item
1
LDCR
licensing document change request
'
LER
licensee event report
loss-of-coolant accident
low pressure safety injection
net positive suction head
OEEE
operational experience engineering evaluation
peak clad temperature
psi
pounds per square inch
psig
pounds per square inch gage
3
..
..
psia
pounds per square inch absolute
qualified safety parameter display system
recirculation actuation signal
RWSP
refueling water storage pool
small break loss-of-coolant accident
SSEI
safety system engineering inspection
TS
Technical Specification
Updated Final Safety Analysis Report
unresolved item
uraeviewed safety question
V de
volts direct current
VIO -
violation
-
,
DOCUMENTS REVIEWED
SAFETY EVALUATIONS
NUMBER
DESCRIPTION
REVISION
SF.-97-006
DC-3440 - HPSI Flow Control Valve Replacement
Revision 0
LDC-98-0032 - Hydrogen Recombiner Analyzer
November 28,1997
Containment Isolation Valve Evaluation
UFSAR Soction 11.2.2.1, Boron Management
January 24,1997
System
LDC 97-0194 - Containment Atmosphere Release
June 26,1997
System
EFW Minimum Flow Requirement EC-S97-016
July 16,1997
UFSAR, Section 9.5.1
May 26,1997
LDC 97-0170, FSAR, Section 9.5.1
May 28,1997
DC-3483 - LPSI Minimum Flow Recirculation Line
Revision 0
Check Valve Replacement
DC-3498 - HPSI Flow Control Valve Position
Revision 0
Indications
1
4
1
.
.
. .
. . . .
.
.
. .
-
-
-
-
-
1
..
.
SAFETY EVALUATIONS
NUMBER
DESCRIPTION
REVISION
DC-3528-0
RWSP LevelIndication
May 9,1997
SE-9~7-038
FSAR Section 9.5.1 And Table 9.5.1-1
March 31,1997
Calculation MN (Q)-9-46
July 3,1997
.
STP For Shutdown Cooiing Flow Control Valve -
April 17,1997
WA#01158897
Adding Trisodium Phosphate Baskets for SIS Sump
February 19,1997
i
SCREENING REVIEWS
NUMBER
DESCRIPTION
REVISION
OP-100-014
Technical Specification and Technical Requirements
Ravision 7
Compliance
HP-001-150
Use of Protective Clothing
Revision 9
OP-903-110
RAB Fluid Systems Leak Test
Revision 2
W1.109
Project Management Standards and Expectation
September 23,1997
Policy
SSP-801
Materials Technical Department Training Program for Revision 0
<
Engineers and Technical Specialists
OP-902-002
Loss of Coolant Accident Recovery Procedure
July 5,1997
CONDITION REPORTS
NUMBER-
DESCRIPTION
REVISION
CR 97-1288
Plant equipment configuration did not match design
Revision 0
documents
CR-97-1675
Refueling water s+orage pool nozzle strainers were
Revision 0
not installed in accordance with drawing
CR-94-0761
Four systems walked down to address drawing
Revision 0
errors
CR-97-1158
Seismic supports for safety-related solenoid valve
Revision 0
condulets were not installed per instructions
5
1
'
.
.
CONDITION REPORTS
I
NUMBER
DESCRIPTION
REVISION '
CR-96-0538
Operator work arounds identified
Revision 0
CR-97-0861
Licensee assessment identified a number of valves
Revision 0
which were preconditioned
CR-97-0852
Valves exceeded their inservice test stroke time
Revision 0
CR-97-24SO
Low pressure safety injection pump B suction
Revision 0
pressure gauge was found to be over ranged
CR-97-2460
Low pressure safety injection pump B suction
Revision 0
pressure indicator was pegged high
CR-97-1240
Safety injection tank was not declared inoperable
Revision 0
during repressurizing the tank with nitrogen with the
tank connected to a nonsafety nitrogen header
CR-97-1687
The gasket in the safety injection tank top manway
Revision 0
flange did not meet accepted industry practices
CR-97-1895
' While performing the safety injection pump
Revision 0
operability test, the safety injaction tank 2A nitrogen
pressure began dropping
CR-97-1913
Safety injection check valve was found leaking
Revision 0
during testing
CR-97-0930
Penetration 59 failed local leak rate testing
Revision 0
CR-97-1452
Plant procedure required verification of minimura
Revision 0
high pressure safety injection flow. However, gages
were inadequate to measure the low flow
CR-97-1030
The snubber on the 10-inch low pressure safety
Revision 0
injection pump discharge line was found frozen
~ CR-97-1206
A concern was raised that penetrations connected to Revision 0
closed water filled systems outside of containment
could leak if piping outside the containment valve
was drained
- CR-97-2048
During testing the as-found set pressure of a relief
Revision 0
valve exceeded the high set pressure tolerance
CR-97-2390
. During testing, the low pressure safety injection
Revision 0
pump A differential pressure exceeded the alert limit
CR-97-1993
Investigate and document the cause of the charging
Revision 0
pump B abnormal noise
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CONDITION REPORTS
NUMBER
DESCRIPTION
REVISION
CR-97-0853
Pressure in the line between valves CS-1178 and
Revision 0
CS-125B exceeded the design pressure by 100 psig
CR-97-1185
Diesel Generator jacket water heater supports have
Revision 0
oversized mounting bolt holes that were not shown
on drawing
CR-96-1087
Broken Diaphragms on Air-Operated Valves
July 17,1996
CR-96-1155
Hydraulic Pump Running Continuously
July 26,1996
CR-97-0220
Damaged Valve Operator
January 29,1997
CR-97-0408
Motor-Operated Valve Pinion Key Not Properly Set,
February 22,1997
Lack of Grease in Clutch Housing
CR-97-0632
FSAR Discrepancy Regarding AOV Air Filters
March 18,1997
CR-97-0982
Bevel Gear Broken on Limitorque Actuator
April 23,1997
CR-97-0806
Waterford 3 Condition Report
April 8,1997
CR-97-2695
HPSI Flow Loop Uncertainty
December 5,1997
CR-97-0649
LPSI Flow Loop Uncertainty
March 19,1997
CR 96-0382
EFW Flow Loop Uncertainty
March 15,1996
CR-96-0414
Minimum Acceptable Pump Differential Pressure at
October 2,1956
the 'nservice Test Flow Rate
CR-95-1126
SlT transmitter static pressure thift input was
Revision 0
incorrect
CR-96-1965
Ultrasonic examination of low pressure safety
Revision 0
injection piping
CR-96-0671
While performing quarterly check of locked valves
Revision 0
per OP-100-009, CHW-152 was found out of position
CR-97-0632
No in line or point of use filters in safety-related air
Revision 0
operated valves
CR-97-0806
Review of design basis calculations revealed
Revision 0
inconsistencies in Si and CS pumps runout flowrates
CR-96-0516
Root Cause Analysis Report - Recurring Electrical
Revision 0
Grounds During Heavy Rainfall
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ENGINEERING RECiUESTS
,
NUMBER
DESCRIPTION -
REVISION
ER-W3-96-0046 . Operability determination input for SI-405A and
Revision 0
.
S-405B
ER-W3-97-0144 - Emergency diesel generator not per drawing
Revision 1
~ KSV-58-4
ER-W3-97-0560
Evaluation of new low pressure safety injection pump Revision 0
B baseline data
ER-W3-97-0417
Design basis operating parameter review
Revisiv b
ER-W3-97-0400
Containment spray pump seal sleeve needs to be
Revision 0
modified in order to prevent shaft to sleeve leakage
ER-W3-97-0265
Evaluate possible trend of thermal overload relays
Revision 0
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due to aging
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ER-W3-97-0010
Flow control valve flow rate determination
Revision 0
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ER W3-97-0109
Freeze seat evaluation for repacking SI-506A
Revision 0
ER-W3-97-0117
Low pressure safety injection pump conduit support
Revision 0
ER-W3-97-0130
Sl MVAAA109A valve has seat leakage and is
Revision 0
welded into a 20 inch line
ER-W3-97-0247
DC-3536 acceptance test 50.59 support
Revision 0
ER-W3-97-0197
input for Procedure OP-903-001
Revision 0
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ER-W3-97-0384
Increased frequency removal justification for high
Revision 0
.
pressure safety injection pump B
ER-W3-97-0067
Lock washers interfere with the flange welds for the
Revision 0
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Target Rock valves
ER-W3-97-0081
Wall thinning on drain line due to flow accelerated
Revision 0
j
corrosion
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ER-W3-97-0178
Seismic analysis of piping connected to the
Revision 0
emergency feedwater terry turbine steam traps
ER-W3-97-0203
P.ipe rusting on discharge structure
Revision 0
ER-W3-97-0467
Evaluation of air flow rates measured while
Revision 0
perforrning STP-011160647
ER-W3-97-0455
Control room emergency outside air intake linear
Revision 0
scale flow indicators requirement to a sequence root
extractor card
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ENGINEERING REQUESTS
NUMBER
DESCRIPTION
REVISION
ER W3-97-M007 Effect on emergency diesel generator fuel oil storage Revision 0
' tank level due vortexing
ER-W3-97-0562. Charging pum'p B unusual noise
Revision 0
ER-W3-97-0430
Overpressure a cfass 2 header respon.e in opening
Revision 0
high pressure safety injection flow control valves
ER-W3-97-0395
Verification that the safety injection system is full of
Revision 0
water
ER-W3-97-0313
Shut down cooling heat exchanger outlet stop check
Revision 0
valve leaks past its seat
ER-W3 97-0128
Colli pring fit up of discharge header relief valve tail
Revision 0
j
piece
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ER-W3-97-M001 Evaluation of reactor coolant system drain down
Revision 0
'
procedure with one shut down cooling pump
operating at 4000 gpm
'
ER-W3-97-0101
Request to use damaged stem for CS-125B
May 2,1997
ER-W3-97-0202
SI-205AB Rejected inspection of Shaft
May 28,1997
ER-W3-97-0100
Sl MVAAA225 A overthrust condition
May 1,1997
ER-W3-98-0134
Qualified life of safety-related batteries
February 17,1998
ER W3-97-0263
RWSP maximum level and containment flooding
June 27,1997
ER-W3-97-0601
Safety flow curves
November 18,1997
ER-W3-97-0390
Instrument accuracy fcr inservice testing
September 5,1997
PROCEDURES
l
NUMBER-
DESCR!PTION
REVISION
W2.501.
Corrective Action
Revision 6
W4.104
Engineering Request Process
Revision 0
1
OP-903-030
Surveillance Procedure - Safety injection Pump
Revision 11
Operability Verification
OP-903-108
Surveillance Procedure - Safety injection Flow
Revision 4
Balance Test
9
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PROCEDURES
NUMBER
. DESCRIPTION
REVISION
UNT-006-021
Pump and Valve inservice Testing
Revision 3
1
NOECP-258
Control of Waterford 3 Purap and Valve Inservice
Revision 0
Test Program
OP-903-010
Surveillance Procedure - ECC System Throttle
Revision 5
Valves Position Verification
- OP-903-108
Surveillance Procedure - SI Flow Balance Test
Revision 3
ME-007-008
Maintenance Procedure - Motor Operated Valve
Revision 10
UNT-006-021
Administrative Procedure - Pump and Valve'
Revision 3
Inservice Testing
OP 903-030 -
Surveillance Procedure - Safety injection Pump
Revision 11
-Operability Verification
OP-902-002
Loss of Coolant Accident Recovery Procedure
Revision 7
OP-902-ATT
Attachment 5, Minimum HPSI Flow Versus
Revision 4
Pressurizer Pressure
OP-902-002
Loss of Coolant Accident Recovery Procedure
Revision 7
OP-902-ATT
Attachment 5, Minimum HPSI Flow Versus
Revision 4
Pressurizer Pressure
OP-902-ATT
Attachment 6, Minimum LPSI Flow Versus -
Revision 4
Pressurizer Pressure
OP-903-001
Technical Specification Surveillance Logs
Revision 19
OP-903-011
High Pressure Safety injection Pump Preservice
Revision 8
Operability Check
OP-903-025
Safety injection Tanks and Shutdown Cooling
Revision 3
System interlock Verification
OP-903-026
Emergency Core Cooling System Valve Lineup
Revision 8
Verification
OP-903-027
Inspection of Containment
Revision 5
' OP-903-029
Safety injection Actuation Signal Test
Revision 7
OP-903-030
Safety injection Pump Operability Verification
Revision 11
OP-903 091
Recirculation Actuation Signal Test
Revision 3
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PROCEDURES
NUMBER
DESCRIPTION
REVISION
'
OP-903-108
Si Flow Balance Test
Revision 3
OP-903-121
Safety Systems Quarterly IST Valve Tests
Revision 2
'
CE-002-100
Chemistry Technical Specification
Revision 10
CE-003-163
Testing of Safety injection Sump Trisodium
Revision 0
Phosphate
i
CE-003-121
Boron Determination (Autotitration Method)
Revision 7
CE-003-122
Determination of Boron (Titration Method)
Revision 5
Ml-003-317
Refueling Water Storage Pool Level Loop Check and
Revision 6
Calibration
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CALCULATIONS
NUMBER
DESCRIPTION
REVISION
EC-M95-004
Dynamic, Seating, and Unseating Torque
Revision 0
Requirements for Air Operated Valves CC-963A,8
EC-M91-076
SI-405A(B) Actuator Thrust Calculation
Revision 2
EC-M91-060
Evaluation of Fisher 9200 Series Butterfly Valves
Revision 0
with Fisher Actuators
EC-M89-003
Switchgear Room 3A Heat Load at the inception of
Revision 4
EC-M89-089
Waterford 3 Design Engineering General
Revision 5
Computation Sheet
MN(Q)-6-4
Water Level Inside Containment
Revision 0
'
MN(Q)-6-19
Level of Water inside Containment
Revision 1
,
MN(Q)-6-27
NPSH Calculation (HPSI and CS Pumps)
Revision 2
>
MN(Q)-6-1
NPSH Calculation {This is for HPSI}
Revision 2
MN(Q)-6-43
Revision 0
MN(Q)-6-2
Safety injection System {HPSI flow dP)
Revision 1
,
MN(Q)-6-42
Head Available on Low Pressure Safety injection
Revision 0 - Change 1
Pump Minimum Flow Recirculation
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CALCULATlONS '-
NUMBER
DESCRIPTION
REVISION
' 612752 - MPS-~
Safety injection System: HPSI Technical
Revision 0
5 Calc 001
Specification Development Based on Analysis of
. Rewoted B Pump
EC-M95-010 ~
_ Stem Thrust / Torque Analysis of the Motor Operated Revision 0 - Change 2 -
Globo Valve (Assembly Number 716-002, Report
No 44951)
- HVAC-070
. Hydrogen Generation Gy Station Batteries
Revision 1
. HVAC-059
' Battery Room Air Flow Required to Limit Hydrogen
Revision 1
Concen' ration to 1%
F_C-S96-604
Cycle 9 Safety Analys!s_ Ground rules
Revision 2
EC-10S-011
SI-HPSI Flow instrumentation Loop Uncertainty
Revisions 0 and 1
Calculation
EC 191-052
LPSI Header Flow A & B instrumentation Loop
Revisions 0 and 1
Uncertainty Calculation
Sizing of HP & LP Safety injection Pump
Rewsion 0
DESIGN CHANGES
NUMBER
DESCRIPTION
REVISION
DCP-3440
High Pressure Safety injection Flow Control Valve
Revision 0
Replacement
DCP-3483
Low Pressure Safety injection Pump Minimum Flow
Revision 0
Recirculation Line: Check Valve Replacement
DC- 3498
ECCS Flow Control Valve Remote Position
Revision 0
Indication Replacement
LICENSING DOCUMENT CHANGE REQUESTS
NUMBER
DESCRIPTION
REVISION
LDC 97-0176
Revise UFSAR Section 8.0 to address battery
Revision 0
upgrade
12
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CISCELLANEOUS DOCUMENTS
NUMBER
DESCRIPTION
REVISION
C-PEC-262
Safety injection System: HPSI Technical
Revision 0
Specification Development and HPSI Restart Data
Analysis
NPF-38107
Technical Specification Change Request
February 12,1990
GQRT File E-5
3A-S and 38-S Battery Seismic Reports
Seism;c Simulation Test Program on Four C&D
September 7,1993
Power Systems LCUN-33 Battery Cells for Pacific
Gas & Electric Company
DES-E-008
Procurement Specification: Class 1E Emergency
August 18,1992
Batteries
TM 457002689
Technical Manual: UPS Elgar Model 103-1-151
Wtfrd3.98.1
Leiter from ELGAR to Entergy Operatlons: Operation
February 4,1998
of UPS 103-1-151
W3-DBD-008
Electrical Distribution (DC Portion) Design Basis
February 28,1996
Document
Guidelines and Technical Bases for NUMARC
Revision 1
Initiatives
Letter from Louisiana Power & Light to U.S. Nuclear
April 14,1989
Regulatory Commission
System Review Self-Assessment - HPSI
July 16,1996
Letter from Combustion Engineering to Louisiana
November 17,1989
Power & Light Co: High Pressure Safety injection
Pump "B" Pump Operating Condition
Letter from Combustion Engineering to Louisiana
December 1,1989
Power & Light Co: High Pressure Safety injection
System Technical Specification Values
Letter from Combustion Engineering to Louisiana
February 27,1984
Power & Light Co: Option No. NOL-63, Plant Specific
Inforrnation for Emergency Procedure Guidelines
DBD-C01
Waterford 3 Design Basis Document " Safety
Revision 2
Injecticn System,"
Cl-290132
SI Flow Balance Test
March 18,1994
13
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CISCELLANEOUS DOCUMENTS
.i
. NUMBER
DESCRIPTION
REVISION
PEIR-OM-68 '
HPSI/LPSI Flow Control Valve Remote Position
June 22,1994
I
Indication Problem
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