ML20135C301
| ML20135C301 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 02/25/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20135C277 | List: |
| References | |
| 50-298-96-24, NUDOCS 9703030475 | |
| Download: ML20135C301 (49) | |
See also: IR 05000298/1996024
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Docket No.:
50-298
License No.:
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Report No.:
50-298/96-24
Licensee:
Nebraska Public Power District
Facility:
Cooper Nuclear Station
. Location:
P.O. Box 98
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Brownville, Nebraska
Dates:
October 7 through February 19,1997
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Team Leader:
L. J. Smith, Reactor inspector
inspectors:
G. D. Replogle, Resident inspector
D. Prevatte, Consultant
J. Lievo, Consultant
B. Gupta, Consultant
Approved By:
Chris A. VanDenburgh, Chief, Engineering Branch
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Division of Reactor Safety
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Attachment:
SUPPLEMENTAL INFORMATION
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9703030475 970225
ADOCK 05000298
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TABLE OF CONTENTS -
EXECUTIVE SUMMARY . . . . . . . . . . .
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R e p o r t D e t a il s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . 1
I l l . E n g i n e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
E1
Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
E1.1
Reactor Protection System and Anticipated Transient Without
Scram (ATWS) Setpoint Calculations . . . . . . . . . . . . . . . . . . . . . 1
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E1.2 Conformance with Safety Guide 11 for Drywell Pressure
Instrument Line Penetrations . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
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E1.3 Plant Monitoring Information System - Standby Liquid Control
System Circuit Separation and Isolation . . . . . . . . . . . . . . . . . . . 4
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USAR Discrepancies (10 CFR 50.71(e))
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E1.5 ATWS Safety Analysis - Main Steam isolation Valve Closure
Time............................................
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E2
Engineering Support of Facilities and Equipment
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E2.1 - Repetitive Problems with Scram Valve Fastener Assemblies . . . . 12
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E3
Engineering Procedures and Documentation
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E3.1
Site-Specific Emergency Operating Procedure issues . . . . . . . . . 14
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E3.2 Industry Emergency Operating Procedure issues . . . . . . . . . . . .
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E7
Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . . 22
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E7.1
Open item Tracking for Design Criteria Document Validation
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E7.2 Licensee Corrective Actions for Previously identified USAR
Discrepancies
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E7.3 Licensee Corrective Actions for General Electric Identified
Potential Reportable Condition 89-15, " Control Rod Drive
System Leakage During a LOCA"
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E7.4 Implementation of Generic Letter 85-06, " Quality Assurance
Guidance For ATWS Equipment That is Not Safety-Related" . . . . 32
E8
Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
E8.1
(Closed) Licensee Event Report 50-298/94026-01," Standby
Liquid Control System Not Maintained at Proper Temperature
Due to Design Deficiency and Lack of Appropriate Monitoring
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V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . .
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Exit M e eting Sum m a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
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EXECUTIVE SUMMARY
Cooper Nuclear Station
NRC Inspection Report 50-298/96 24
The NRC performed an announced safety system functionalinspection at the Cooper
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Nuclear Station. The safety system functional inspection was an in-depth,
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multi-disciplinary engineering review to verify that the selected systems were
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capable of performing their intended safety functions. The team reviewed systems
which were used to achieve safe shutdown. The inspection was conducted in accordance
with inspection Procedures 93801, " Safety System Functional Inspection (SSFI)" and
37550, " Engineering." The standby liquid control, the reactor protection, and the
control rod drive systems were selected because of risk significance, in addition,
neither the licensee nor the NRC had recently performed this type of review for these
systems.
Generic safety significant findings were pursued across the system boundaries on a
- plant-wide basis. The secondary objective of the safety system functionalinspection was
to determine the program-related root cause for identified performance deficiencies and
analyze the implications of these deficiencies on the licensee's quality assurance program,
in general, the inspection team determined that the systems reviewed were capable of
performing their intended safety function.
Operations
The team identified two inadequate operability determinations. The first was based
on engineering judgement alone and did not consider seismic qualification test data.
The second involved the licensee's failure to evaluate the safety basis of the diesel
generator fuel oil tank, which was documented in the Updated Safety Analysis
Report, when thcy evaluated the operability implications of a design criteria
document open item. The licensee resolved both concerns satisfactorily
(Sections E2.1 and E7.1).
The team identified three failures to provide adequate procedures for emergency
conditions, involving: (1) appropriate instructions to ensure that adequate space
was available in the reactor vessel when reactor core isolation cooling is utilized for
alternate boron injection; (2) appropriate instructions to ensure that design basis
boron concentrations would not be compromised during an anticipated transient
without scram event; and, (3) appropriate instructions to ensure that the
containment of radioactive materials would not be compromised during an
anticipated transient without scram event. These failures are a violation of
Technical Specification 6.3.2. The team noted the licensee had previously identified
the third example; however, their corrective actions were ineffective (Section E3.1).
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The team identified a generic issue regarding the licensee's technical basis for the
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emergency operating procedures related to an anticipated transient without scram
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event. ' The licensee had not fully considered the mixing effects related to boron
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displacement during cooldown. In addition, hot and cold shutdown boron worth
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were not calculated conservatively. This item is unresolved pending further
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evaluation by the Office of Nuclear Reactor Regulation (Section E3.2).
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Maintenance
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The team identified one violation of Technical Specification 6.3.1 involving the
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failure of a maintenance worker and a quality controlinspector to follow procedural
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requirements. This experience is contrary to the information provided in a letter
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dated November 1,1996. The team also identified that procedural guidance for the
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installation of the scram valve actuator mounting brackets needed improvement,
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and that the licensee's corrective actions addressing repetitive instances of non-
conforming scram valve actuator mounting assemblies have been ineffective
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Enaineerina
The team identified several unverified or questionable assumptions in the sample of
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reactor protection system and anticipated transient without scram setpoint
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calculations; however, none of the discrepancies affected equipment operability.
The licensee had pr0 grammatically identified similar setpoint calculation problems
during a 1996 quality assurance audit and was in the process of correcting and
updating the calculations. This licensee-identified and corrected violation is being
treated as a noncited violation, consistent with Section Vll.B.1 of the NRC
Enforcement Policy (Section E1.1).
The licensee did not clearly describe their intent with respect to implementation of
Safety Guide 11, " Instrument Lines Penetrating Primary Containment," in either the
Final Safety Analysis Report or in the Updated Safety Analysis Report V.2.3.5,
" Primary Containment isolation Valves." Further, the inspection team could not
deterrnine whether the current administrative controls met the intent of the
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Supplement to Safety Guide 11 with respect to providing a method to verify during
operation the status of each isolation valve. This item is unresolved pending further
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evaluation by the Office of Nuclear Reactor Regulation (Section E1.2).
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The licensee had modified their standby liquid control system to make it electrically
less reliable. Whether this design change was in violation of 10 CFR 50.59 is
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unresolved, pending an Office of Nuclear Reactor Regulation review of the licensing
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basis (Section E1.3).
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In recent years, the licensee had made a poor effort to assure that the Updated
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Safety Analysis Report contained the latest information regarding the systems that
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licensee's corrective actions related to these discrepancies had been ineffective.
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Based on the number of deficiencies identified, the team concluded that the
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Updated Safety Analysis Report contained many inaccuracies. The team identified
ten specific examples of an apparent violation of 10 CFR 50.71(e)(Sections E1.4
and E7.2).
.The licensee relied on a generic analysis to determine the acceptability of the
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f acility's response to an anticipated transient without scram. The team concluded
this analysis was not bounding, because the minimum main steam isolation valve
closure time was not used. This generic issue is being forwarded to the Office of
Nuclear Reactor Regulation to determine whether the licensee was required to
provide a bounding analysis for f acility response to an anticipated transient without
scram (Section E1.5).
The licensee provided weak oversight to the design criteria document validation
program. Based on the inspection team's questions, the licensee identified 87 open
validation items which had not been previously tracked by the licensee. The team
determined that some of these* items were significant conditions adverse to quality.
The licensee also f ailed to promptly evaluate the Category I and ll open items to
determine if the affected equipment was operable. The failure to promptly identify
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conditions adverse to quality is a violation of 10 CFR 50, Appendix B, Criterion XVI,
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" Corrective Action" (Section E7.1).
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Based on a prudence determination, the licensee had installed two series check
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valves to address a potential containment bypass leak path identified by the vendor.
However, the inspection team identified that the licensee had not updated the
10 CFR 100 or the control room shielding dose calculations to include the dose
contributions from this leak path because they did not believe the leak path was.
credible. In addition, the licensee had not updated their license to include this
potential leak path or establish check valve leakrates, which would be consistent
with their license requirements for credible bypass leakpaths. This item is
unresolved pending further evaluation by the Office of Nuclear Reactor Regulation
(Section E7.3)
The team concluded that the licensee had not established an effective quality
assurance program for the standby liquid control system that was consistent with
industry standards. While the team concluded the licensee was not required to
commit to Generic Letter 85-06," Quality Assurance Guidance for ATWS Equipment
that is Not Safety-Related," the failure to do so was a significant weakness
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(Section E7.4).
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Report Details
Ill. Enoineerina
E1
Conduct of Engineering
E1.1
Reactor Protection System and Anticipated Transient Without Scram (ATWS)
Setooint Calculations
a.
Inspection Scope (93801. 37550)
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The team reviewed a sample of reactor protection system and ATWS setpoint
calculations, corresponding surveillance procedures, and the licensee's setpoint
calculation methodology. The team also reviewed a related licensee-generated audit
finding and the planned corrective actions.
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b.
Observations and Findinas
The team identified several unverified or questionable assumptions in the sample
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of reactor protection system and ATWS setpoint calculations. For example,
Calculation NEDC 92-050AG, "PC-PS-12A/B/C/D and PC-PS-119A/B/C/D
Setpoints," Revision 1, incorrectly used qualification test data. To justify the use of
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1 percent rather than 7 percent radiation effect on the accuracy of the high drywell
pressure scram setpoint, the licensee determined that the radiation effects and
seismic effects could be combined. They assumed that the effects of the
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earthquake would undue the harm caused by the radiation effects. Further, the
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calculation incorrectly applied a 3 sigma confidence level to the seismic data.
The team noted that a 3 sigma confidence level should only be used for data which
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is extensively backed by testing. The licenn
+1 reed that the qualification test
report data had been incorrectly interpretes 4 :Je as an input to the calculation,
and prepared Problem Identification Report 2-07763 to address the extent of the
problem. The licensee subsequently determined that even if the correct
assumptions were used, the actual setpoints were acceptable; therefore, operability
was not a concern.
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As a second example, Calculation NEDC 90-384, "NBI LITS-101 A,B,C,D Level 3
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Setpoint," Revision 2, was incorrect in that the confidence level for vendor drift,
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which had been calculated as a 95 percent confidence level (2 sigma), was credited
as a 3-sigma confidence (higher ::onfidence than justified) in the setpoint margin
calculation. The licensee subsequently identified other conservatisms in the
calculation which compensated for the error; therefore, operability was not a
concern.
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The licensee and the team independently identified that the results of
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Calculation NEDC 92-0501, " Reactor Vessel HI Pressure Scram Set Point
Calculation for NBI-PS-55A(B,C,D)," had not been fully implemented in
Surveillance Procedure 6.1RPS304,"RPS High Reactor Pressure Calibration
and Functional Test (Division 1)." The calculation included a change to the
existing elevation correction (14 to 13 psig), which had not been incorporated into
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the surveillance procedure. As a result, the surveillance test data was slightly
nonconservative. The licensee evaluated the as-left setpoint considering the 1.0 psi
error and found the reactor protection system to be operable.
10 CFR 50, Appendix B, Criterion lil, requires that design control measures be
established to assure that the design bases are correctly translated in specifications,
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drawings, procedures, and instructions. It also requires that design :..:ntrol
measures provide for verifying or checking the adequacy of design cs the
performance of design reviews, calculations, or a testing program and that design
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changes are implemcnted consistent with the design controls applied to the original
design.
The team noted, that in Quality Assurance Audit 9G-06, the licensee had previously
identified programmatic weaknesses related to the development of setpoints which
were applicable to the reactor protection system. The licensee had determined that
the reactor protection system setpoint calculations, and other scaling and setpoint
calculations, needed upgrading. The team found that the licensee had a
comprehensive program plan in place to upgrade these calculations. The licensee
had contracted with General Electric to perform again the reactor protection system
calculations using an updated methodology. This portion of the overall corrective
action plan was in process during the inspection. Tne licensee had scheduled
completion of the plan for December 31,1997. Mr. Fadi Diya of Cooper Nuclear
Station committed to complete the corrective action plan associated with the audit
finding.
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Based on review of the plan and conversations with the licensee's technical staff,
the team concluded that the licensee would have identified the errors which were
identified by the team during their upgrade review. The failure to accurately prepare
calculations and the failure to accurately translate the results of calculations into
surveillance procedures is a violation of 10 CFR 50, Appendix B, Criterion lit,
" Design Control." However, this licensee-identified and corrected violation is being
treated as a noncited violation consistent with Section Vll.B.1 of the NRC
Enforcement Policy (50-298/9624-01).
c.
Conclusions
The team identified several unverified or questionable assumptions in the sample of
reactor protection system and ATWS setpoint calculations. None of the
discrepancies effected equipment operability. The licensee had programmatically
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identified similar setpoint calculation problems during a 1996 quality assurance audit
and was in the process of correcting and updating the calculations. This licensee-
identified and corrected violation is being treated as a noncited violation.
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E1.2 Conformance with Safety Guide 11 for Drvwell Pressure Instrument Line
a.
Inspection Scone (93801,37550)
The team reviewed the instrument impulse line configuration for various
instruments, including the drywell pressure instruments,
b.
Observations and Findinas
The team found that the licensee had not clearly described their intent with respect
to implementation of Safety Guide 11, " Instrument Lines Penetrating Primary
Containment," in either their response to Final Safety Analysis Report (FSAR)
Question 5.5 or in Updated Safety Analysis Report (USAR) Section V-2.3.5,
" Primary Containment Isolation Valves." The team found that the licensee's
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responses needed clarification to indicate that the Supplement to Safety Guide 11,
" Instrument Lines Penetrating Primary Reactor Containment Backfitting
Considerations," was applicable to Cooper Nuclear Station and not Safety Guide 11.
The team reviewed the design of the drywell pressure sensing lines and could not
determine if it was consistent with the guidance in the Supplement to Safety
Guide 11. The Supplement stated that for each instrument line penetrating
containment, including those connected to the containment atmosphere, some
method of verifying during operation the status (open or closed) of each isolation
valve should be provided. The licensee stated that procedural controls are in place
to verify the alignment status of valves of this type before each start up. However,
the inspection team noted that the licensee does not periodically verify the status of
these valves during normal operation. Rather, the licensee relies on their general
valve alignment status program to ensure the alignment is not changed without
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operator knowledge. This issue will be reviewed with the Office of Nuclear Reactor
Regulation to confirm that the administrative controls established by the licensee
provide a sufficient method for verifying the status of these valves during normal
operation. This item is unresolved (50-298/9624-02).
C.on_rlusions
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The licensee did not clearly describe their intent with respect to implementation of
Safety Guide 11, " Instrument Lines Penetrating Primary Containment" in either the
FSAR or in USAR Section V 2.3.5, " Primary Containment isolation Valves." The
team identified an unresolved item concerning whether the current administrative
controls met the intent of the Supplement to Safety Guide 11 with respect to
providing a method to verify during operation the status of each isolation valve.
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E1.3 Plant Monitorino information System - Standby Liauid Control System Circuit
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Separation and Isolation
a.
Insoection Scope (93801,37550)
The team reviewed the elementary diagrams for the standby liquid control system to
assess conformance to standby liquid control system design and licensing basis
requirements, including functional requirements, as well as criteria for separation
and isolation.
b.
Observations and Findinas
The team initially observed that the licensee had not maintained their commitment in
FSAR/USAR lll-9.4, " Standby Liquid Control System Safety Evaluation," to power
and control the standby liquid control system pumps and valves from separate
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buses and circuits, so that a single failure would not prevent system operation.
Specifically, the licensee had modified both trains of the power and control circuits
for the standby liquid control pumps and squib valves to add a wire from each
power and control circuit to the plant monitoring information system. The licensee
routed the two wires to adjacent terminals on a common non-qualified data
acquisition cabinet (Cabinet No. 9-81; Addressable Points N869, N870) without
interposing isolation devices.
The team noted that a short circuit between these two wires or short-to-ground on
the data acquisition cabinet terminal assembly could defeat both standby liquid
control system pumps and squib valves. Therefore, the team did not believe this
configuration met the licensee's commitment to maintain a design such that a single
f ailure in the power and control circuit would not prevent system operation. The
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team reviewed the licensee's safety evaluation, which supported the modification to
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add the plant monitoring information system interface, and found that the safety
evaluation did not include consideration of the USAR Section 111-9.4, " Standby
Liquid Control System Safety Evaluation," commitment.
The licensee interpreted their commitment differently. They noted that the standby
liquid control system was a non-essential system and that single-failure proof
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system design was not required based on USAR Appendix G, Fig. G-5-45,
" Protection Sequences for Shutdown Without Control Rods." The plant safety
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requirements, which were credited in the accident analysis at the system level,
were specified in Appendix G. The licensee indicated that since the system was not
required to be single-failure proof, it was not necessary for the electrical support to
the system to be single-f ailure proof. The licensee also interpreted that the single-
f ailure proof requirement from FSAR/USAR Section 111-9.4, " Standby Liquid Control
System Safety Evaluation," only referred to the electricalinoependence of the
upstream power supplies. They believed that they had the authority to make a
USAR correction consistent with the accident analysis. As a result, they planned to
delete the electrical separation commitments specified in FSAR/USAR
Section 111-9.4.
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Notwithstand;ng the licensee's position, the team was concerned that the lack of
separation and qualified isolation devices represented an unevaluated deviation from
the standby liquid control system safety evaluation described in the USAR.
10 CFR 50.59 requires that a proposed change, test, or experiment shall be deemed
to involve an unreviewed safety question if the probability of occurrence or the
consequences of an accident or malfunction of equipment important to safety
previously evaluated in the safety analysis report may be increased. The team was
concerned that the licensee had not initially identified or evaluated this additional
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vulnerability and its effects, as required to comply with 10 CFR 50.59. Further, the
team questioned the licensee's interpretation that allowed them to delete the single
failure requirement for the electrical portion of the system without a license
amendment. This item will be referred to the Office of Nuclear Reactor Regulation
to determine whether the licensee's interpretation of their licensing basis is correct.
This item is consider d unresolved (50-298/9624-03).
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system interfacu ,iractice might have been extended to essential circuits other than
standby liquid control system (for example, diesel fuel oil transfer pumps, reactor
building closed cooling water pumps, core spray motor-operated valves, etc.). The
team reviewed an additional sample of essential system interfaces with the plant
monitoring information system and the plant monitoring information system
procurement specifications. Based on this review and discussions with the
licensee, the team found that the licensee had correctly designed the interface for
essential systems.
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c.
Conclusions
The licensee modified their standby liquid control system to make it less reliable.
With the modified configuration, a common single failure could be postulated (i.e., a
short and/or ground of the redundant 120V ac control power circuits) that would
de-energize the standby liquid control system pump contactor circuits and squib
valve firing circuits, rendering them all inoperable until the fault was located and
repaired. On a system level, the standby liquid control system is not required to be
single failure proof. Whether this design change was in violation of 10 CFR 50.59
is considered unresolved, pending Office of Nuclear Reactor Regulation review of
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the licensing basis. The licensee had correctly implemented the modification to add
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plant monitoring system inputs to essential systems.
E1.4 USAR Discrepancies (10 CFR 50.71(elj
a.
Inspection Scoce (93801. 37550)
The team evaluated compliance to selected USAR commitments.
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b.
Observations and Findinas
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During the inspection, the team identified several USAR discrepancies. All of these
discrepancies were discussed with the licensee. The most significant eight
examples are described in Sections b.1 through b.8 below.
b.1. Seismic Analysis for Small Bore Pinina
The team observed that the seismic analysis for 2 inch and under (i.e., small bore)
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piping was not performed in accordance with the USAR commitments. The USAR
indicates that seismic loads were accounted for in all piping systems. In addition,
dynamic analysis were performed for Class-l seismic piping systems. For C!ar,s-l
nuclear and seismic piping systems, these analysis included a model derivation of
natural period of vibration. The small bore Class-l nuclear and seismic piping
systems were not subjected to dynamic analyses that included a model derivation of
natural period of vibration. Instead, piping and supports were field routed using
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span charting procedures and engineering judgement.
The licensee acknowledged that the 2-inch and under piping systems were not
analyzed in accordance with the USAR commitments. However, the licensee
believed that the methods used were acceptable. The licensee also produced a
letter to the NRC, dated August 12,1988, entitled, " Code Qualification of Seismic
Class-IS Pipe Supports," that included a brief description of the seismic practices.
The NRC did not respond to this letter. Additionally, there was no indication that
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the licensee was aware that a USAR discrepancy existed at the time of the
inspection.
The licensee's methods appeated to be consistent with the approach taken by other
licensees of nuclear power plants; therefore, the team determined that operability
was not a concern. However, the team concluded that this USAR discrepancy was
an example of an apparent violation of 10 CFR 50.71!e). This regulation requires
that the licensee update the USAR periodically to assure that the information in the
USAR contains the latest material developed. Subsequent revisions are required to
reflect all changes up to a maximum of 6 months prior to the date of filing.
The failure to update the USAR to accurately describe the method for controlling
seismic qualification of small bore piping is the first example of an apparent violation
of 10 CFR 50.71(e)(50-298/9624-04).
b.2. Incorrect Description of Time Delav for Alternate Rod Insertion
The team noted that USAR Section 111-5.5.3.4, " Alternate Rod insertion," was
incorrectly updated to state that the time delay for initiating alternate rod
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insertion should be applied to both the low reactor water level initiating signal
and the high reactor pressure initiating signal. This was not consistent with
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USAR Section Vll-2.3.5.1, " Alternate Rod Insertion," which indicated that the
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time delay for initiating alternate rod insertion should be applied only to the
low reactor water level initiation signal, not the high reactor pressure initiation
signal. Drawing 945E632,"ARl/ATWS Recirc Pump Trip," Sheets 3 and 7, dated
January 15,1995, also indicated that the time delay should only be applied to the
low reactor water level initiation signal.
The f ailure to accurately update USAR Section 1115.5.3.4 to accurately
describe the applicability of the time delay is the second example of an apparent
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violation of 10 CFR 50.71(e)(50-298/9624-04).
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b.3. Room Temoerature Control for the Standby Liauid Control System
The team determined that since the initial construction of the facility, the
temperature for the room which houses the standby liquid control system
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equipment has not been designed as stated in USAR Section 111-9.3. Specifically,
USAR Section lil-9.3, " Standby Liquid Control System Description," inaccurately
claims that the equipment containing the solution is installed in a room in which the
air temperature is to be maintained within the range of 65 F to 100 F. The
equipment containing the solution is installed in a room in the reactor building. The
actual heating and ventilation equipment design is described in USAR
Section X-10.3.2, " Heating, Ventilation and Air Conditioning Systems Station
Heating System," and in Table X 10-1, " Heating, Ventilation and Air Conditioning
Systems Station Heating System Design Temperatures (Winter)." This USAR
section states that the normal minimum indoor temperature for the reactor building
is 50 F. Section E8.1 of this report describes corrective actions taken by the
licensee to improve temperature control of the liquid control solution. These
modifications lessened the safety significance of the room temperature controls.
The failure to update the USAR to accurately describe the method for controlling
temperature of the standby liquid control system is the third example of an apparent
violation of 10 CFR 50.71(e) (50-298/9624-04).
b.4. Standbv Liauid Control System Desian Basis Pressure Reauirement Not Updated
The team determined that USAR Section 111-9.4, " Standby Liquid Control System
Safety Evaluation," was not updated to address the new design requirements
specified in 10 CFR 50.62," Requirements for Reduction of Risk from Anticipated
Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power
Plants." Specifically, the licensee prepared Modification Design Change 86-34A,
"SLC/ATWS Modifications," Revision 0, in part, to change the standby liquid control
system relief valve settings so that the system would be capable of injecting liquid
control solution at the reactor pressure, which would be expected during an ATWS
event. During the worst-case ATWS conditions, reactor pressure vessel pressure
would equal the main steam relief valves'setpoints plus accumulation at the
maximum ATWS steam flow (approximately 1,100 psig plus the static head in the
7
c
,
,
,
reactor vessel). USAR Section lll-9.4, continued to state that, ". . . the standby
liquid control system and pumps have sufficient pressure margin, up to the allowed
system relief valve setting range of 1450 to 1680, to assure solution injection into
the reactor above the normal [ emphasis added] pressure of approximately 1030 psig
in the bottom of the reactor." The previous standby liquid control system design
was based on normal operation.
The failure to update the USAR to accurately specify design basis pressure
requirements is the fourth example of an apparent violation of 10 CFR 50.71(e)
(50-298/9624-04).
b.5. Standbv Liauid Control Solution Temperature and Concentration inaccuracies
The team determined that the solution concentrations and temperatures listed in
Updated Safety Analysis Report Section 111.9.3, [ Standby Liquid Control] Description
were not consistent with Technical Specification Figure 3.4.2, Percent Sodium
j
Pentaborate by Weight of Solution versus Temperature,
j
Updated Safety Analysis Report Section lll.9.3, states that, "In the event that the
tank heater fails and the room temperature is below the minimum tank water
)
temperature of 85 F, the solution concentration in the tank can be reduced by
!
adding water to the tank until an acceptable concentration level is reached. At the
minimum room temperature of 65 F, the maximum permitted solution concentration
is 12.5 weight percent." The team found that these values were not consistent
with the Technical Specifications. In accordance with T9chnical Specification
Figure 3.4.2, at 65 F, the maximum permitted concentration was 12.1 per~nt. At
12.5 percent concentration, the minimum allowable temperature was 67 F.
Based on a review of Updated Safety Analysis Report Section 111.9.3 and the
,
Technical Specification Bases section, the team found that the adjusted saturation
'
temperature referenced in the Updated Safety Analysis Report corresponds to the
Technical Specification minimum allowable temperature. Both temperatures are
defined as being equal to the actual saturation temperature plus 10 F. Considering
this equivalency, the team noted one additional conflict. Updated Safety Analysis
Report Section 111.9.3, states that a concentration of 11.5 percent corresponds to
an adjusted saturation temperature of 61 F. However, Technical Specification
Figure 3.4.2 indicated that the minimum permitted temperature at 11.5 percent was
62 F.
The failure to update the Updated Safety Analysis Report to accurately specify
standby liquid control solution temperatures and concentrations is the fifth example
,
of an apparent violation of 10 CFR 50.71(e)(50-298/96024-04).
4
8
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b.6. Reactor Water Cleanup System Valve Loaic Modification
.
In response to the anticipated transient without SCRAM Rule,10 CFR 50.62, the
licensee performed Modification Design Change 86-34A, Revision 0, "SLC/ATWS
4
j
Modifications." One of these modifications changed the controllogic of the reactor
water cleanup system isolation valves, reactor water cleanup system MOV-M015
,
(the inboard isolation valve) and M018 (the outboard isolation valve). In the original
design, operation of either of the standby liquid control system pumps would initiate
,
isolation of both reactor water cleanup system valves. In the modified design, the
operation of each pump would cause isolation of only one valve. However,
l
Updated Safety Analysis Report Figure IV-9-4, " Reactor Water Cleanup System
Leak Detection and Isolation," incorrectly still showed a single logic line from the
,
!
standby liquid control system affecting both reactor water cleanup system valves.
I
Additionally, Section 9.3, "[ Reactor Water Cleanup System] Description," contained
)
ambiguous statements concerning the operation of these valves. The failure to
updato Updated Safety Analysis Report Figure IV-9-4 is the sixth apparent example
of an apparent violation of 10 CFR 50.71(e)(50-298/96024-04).
1
b.7. Standby Liauid Control System Desian Basis Iniection Times Not Clearly Described
The team determined that Updated Safety Analysis Report Section Ill.9.3,
[ Standby Liquid Cont ol System] Description and Updated Safety Analysis
Report Section 111.9.4 [ Standby Liquid Control Systeml Safety Evaluation
included standby liquid control system injection times which were confusing.
The injection times appeared to be system performance descriptions when in
f act they were bounding design requirements. The licensee stated that the
Updated Safety Analysis Report contained design requirements based on the
General Electric Design Specification 22A2896, NEDE-24111, and -31096-P rather
than current performance information. Consistent with the General Electric
Design Specification, Updated Safety Analysis Report Section ll1.9.3, stated,
"Each positive displacement pump is capable of injecting the required weight of
solution into the reactor in 53 to '4 20 minutes, independent of the amount of
'
solution in the tank (within the roquired volume), and the pump rate (within the
specified Tech. Spec. limits)."
i
The licensee stated that original design requirements for single pump operations
were based on a boron injection rate of 8 to 20 ppm change in boron concentration.
To meet 10 CFR 50.62 it was necessary to reduce the volume injection time from
i
the General Electric Specification in half to 27 to 60 minutes. Updated Safety
'
Analysis Report Section 111.9.4, "With the simultaneous operation of both positive
displacement pumps, the solution can be injected into the reactor in 27 to 60
minutes, independent of the amount of solution in the tank (within the required
volume), and the pump rates (within the specified Tech. Spec. limits)."
Actual system design capability is bounded by the General Electric Design
Specification, but is less conservative than the General Electric Design Specification.
Technical Specification Figure 3.4.1 and Calculation NEDC 93-142, Revision 0,
"SLC Storage Tank Setpoints and Concentration Requirements," required the
9
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..__.. - - - - .-_-- -.
.
,
"
,
i
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i
minimum volume of sodium pentaborate solution in the standby liquid control
system storage tank to be between 3,132 gallons and 4,414 gallons for
-
j
concentrations between 16 percent and 11.5 percent, respectively. Updated Safety
Analysis Report Section 111.9.4, [ Standby Liquid Control System] Safety Evaluation,
!
' and Technical Specifications 4.4.A.1 and 4.4.A.2.b., Standby Liquid Control
,
System, stated that the minimum reqvired flow rate for the standby liquid control
system pumps was 38.2 gpm. Dividing the required volumes for the high and low
"
concentration by the minimum pump flow rate results in injection times which are
different from the Updated Safety Analysis Report. Considering these values, the
minimum time for one pump to inject the required volume of solution should have
,
i
been described as 82 to 116 minutes, and for two pumps,41 to 58 minutes. The
team agreed with the licensee that the system, as designed, was capable of
j
meeting the General Electric design requirements.
~
The failure to update the Updated Safety Analysis Report to clearly describe
system design capability is the seventh example of an apparent violation of
10 CFR 50.71(e) (50-298/96024 04).
!
b.8. Inconsistent Standby Liouid Control Solution Tank Level Alarm Setooints
The team determined that Updated Safety Analysis Report Section 111-9.3,
(Standby Liquid Control System] Description, inaccurately stated the
-
studby liquid control solution tank level alarms, in accordance with
a
Alarm Procedure 2.3.2.28, Revision 26, March 15,1996, Panel 9-5-2,
I
Window F-8, standby liquid control system Tank Hi/ Low Level, the high and
iow alarm setpoints for the standby liquid control system sodium pentaborate
storage tank were at 84 and 74 percent, respectively. In accordance with
Surveillance Procedure 6.SLC.601, Revision 0, November 17,1995, "SLC Tank
I
Sampling," these setpoints corresponded to 3,835 and 3,378 gallons, respectively.
However, Updated Safety Analysis Report Section ll1.9.3, stated that these alarms
1
were set at 3,850 and 3,350 gallons, respectively. Since both the rurveillance
3
i
procedure and the Updated Safety Analysis Report values appeared to have been
j
'
derived from the same source, Calculation NEDC 93-142, Revisien 0, "SLC Storage
]
Tank Setpoints and Concentration Requirements," this inconsistency appeared to
i
.
have been caused by compounded rounding error.
I
The failure to update the Updated Safety Analysis Report to accurately describe the
standby liquid control so'ution tank level alarm setpoints is the eighth example of an
apparent violation c,i 10 CFR 50.71(e)(50 298/96024-04).
,
l
c.
Conclusions
The licensee had not been successfulin ensuring that the USAR contained the latest
information regarding the systems that were addressed by this inspection. Based
on the number and nature of the discrepancies discovered in the USAR, the team
3
I
concluded that the unreviewed balance of the USAR is likely to contain a similar
l
level of discrepancies. The inspection identified eight examples of an apparent
i
violation of 10 CFR 50.71(e).
d
10
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4
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E
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E1.5 ATWS Safety Analysis - Main Steam isolation Valve Closure Time
a.
Inspection Scope (93801,37550)
l
The team reviewed USAR Section XIV.5.11, " Anticipated Transients Without
Scram," which described a generic ATWS event analysis, which reflected nominal
values and was not specific to the Cooper Nuclear Station. The team also reviewed
Table XIV-5-4, which described the inputs and assumptions that were used in this
j
generic analysis,
b.
Observations and Findinos
l
The team observed that Table XIV-5-4 listed several non-conservative input
parameters. For the most part, the team found that the results of the generic
analysis would not be sensitive to changes in these parameters. However, the team
identified one potentially significant non-conservatism in the generic ATWS event
analysis which could significantly affect the results of the analysis. The team noted
l
that this non-conservatism would likely be applicable to other boiling water reactor
plants.
The team found that General Electric had performed the generic ATWS event
analysis using a nominal value of 4 seconds for main steam isolation valve closure
time, rather than the minimum allowable value. The USAR Section IV.6.3, "MSIV
Description," and Technical Specification 3.7.D.1, " Primary Containment isolation
Valves," allowed a 3-second minimum closure time. The team believed that the
analysis was sensitive to changes in main steam isolation valve closure time. This
sensitivity was due to the effect of the closure time on the rate-of-void collapse in
the reactor and the resultant rate-of-reactivity insertion versus the rate-of-reactivity
removal inherent in the fuel design. Shorter main steam isolation valve closure time
would produce a higher net rate-of reactivity insertion, with the resultant higher
neutron-flux peak and fuel and cladding temperature peaks. For the analyzed 4-
second closure time, the peak cladding temperature was 1,359 F. The team
believed that using a 3-second main steam isolation valve closure time in the
analysis would likely result in significantly higher peak cladding temperature and
increased oxidation.
In the safety analysis report, the licensee f avorably compared the results of
the generic analyses with the acceptance criteria in 10 CFR 50.46, " Acceptance
Criteria for Emergency Core Cooling Systems for Light Water Nuclear Power
Plants," to demonstrate the f acility would have an acceptable response to an
ATWS.10 CFR 50.46 established the peak cladding temperature limit for a
loss-of-coolant-accident at 2,200 F, and the cladding local oxidation limit at
17 percent. Although these limits were not applicable by regulation for a failure-to-
scram accident, they were adopted by the licensee in USAR Section XIV.5.11.2.a.
l
The team concluded that the comparison was not bounding for all plant conditions
j
and would not be valid for a 3-second closure time. As a result, the expected
l
source term and radiological consequences for an ATWS event could be
!
11
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.
.
significantly higher than specified in the USAR. This issue is being forwarded to the
Office of Nuclear Reactor Regulation for evaluation of the sensitivity of the analysis
to changes in main steam isolation valve closure time and to determine whether the
licensee was required to provide a bounding analysis for facility response to an
ATWS event. This item is considered unresolved (50-298/9624-05).
c.
Conclusions
The licensee used a non-bounding generic analysis to determine the acceptability of
facility response to an ATWS event. The acceptability of this analysis is
unresolved. This issue is generic to other boiling water reactors.
E2
Engineering Support of Facilities and Equipment
E2.1
Repetitive Problems with Scram Valve Fastener Assemblies
a.
Insoection Scope (93801,37550)
I
The team reviewed documentation related to loose mounting bolts for hydraulic
control unit air-operated inlet and outlet scram valves.
b.
Observations and Findinas
J
During the last refueling outage, the licensee had replaced approximately 25 percent
of the diaphragms on the hydraulic control unit air-operated inlet and outlet scram
j
valves. Prior to declaring the hydraulic control units operable, licensee engineers
identified that a total of 9 mounting brackets for air-operated scram valves on five
hydraulic control units had not been properly installed. The engineers initiated
,
Problem Identification Report 14476 to document the deficiency and Maintenance
Work Request 95-4519 to re-perform the work. On December 23,1995, a
craftsman and a quality controlinspector implemented Maintenance Work
i
Request 95-4519 and signed that the mounting brackets, nuts, and washers were
properly installed and torqued to 240 in-lbs. The hydraulic control units were
determined to be operable based on work completion. The unit was restarted on
December 27,1995.
On December 28,1995, the engineers that had originally identified the loose
brackets, walked the system down and found that four of the air-operated scram
inlet and outlet valves still had loose mounting brackets. Some of the associated
lock washers and flat washers were also missing. The licensee issued Condition
Report 951450 to document the continuing problem. The licensee completed the
i
necessary rework on December 28,1995. The licensee also performed a prompt
operability determination. Since the scram valve mounting brackets were slotted,
loose bolts would allow the scram valve actuators to move about 1/2-inch back and
forth during a seismic event. Based on engineering judgement, the licensee
concluded that the additional movement of the scram valve actuators during a
seismic event would not affect the operability of the valves.
.
i
12
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,
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__.__ _ _ _ _ _
.
__
_ ____
_m._
_ .
.
I
I
i.
!
l
The inspection team was concerned that the licensee's operability evaluation
r
on December 28,1995, was not based on a review of the seismic qualification
'
data. General Electric was in possession of the seismic qualification
'
documentation and the licensee did not contact General Electric to validate
their assumptions, in response to this concern, the licensee contacted
i
General Electric and determined that the valves were required to be rigidly
secured in order to maintain the seismic qualification of the hydraulic control
units. Therefore, the team concluded tha' 'he December 28,1995, operability
determination for Inlet Scram Valves CRD , bCV126 (Hydraulic Control Unit 22-39)
and CRD-AO-CV126 (Hydraulic Control Unit 26-43) had been incorrect. However, a
l
Technical Specification violation did not occur between time of discovery and
completion of the rework because the licensee had promptly reworked the mounting
brackets.
I
The team also noted that the documentation for Condition Report 95-1450
(December 1995) indicated that the licensee considered the possibility that
i
Maintenance Work Request 95-4519 was an example of a generic concern with
maintenance personnel signing work as complete when it was not. After
investigating, the licensee determined that there was insufficient evidence to
j
conclude that the work hao not been performed correctly. The licensee decided
that the bolting had apparently been loosened after torquing without documentation.
!
On October 30,1996, the team visually inspected all of the scram valve actuator
mounting brackets. The team found that 14 additional bracket assemblies (not
,
previously identified in Condition Report 95-1450) were missing flat washers or
!
lock washera. The washers helped to ensure that the nuts did not come loose.
'
In response to the team's finding, the licensee checked the 14 bracket assemblies.
On or about flovember 21,1996, the licensee found two capscrews which were
.
installed, but not torqued. One capscrew was located on the mounting bracket
j
on Hydraulic Control Unit 38-23 for Inlet Scram Valve CRD-AO-CV126. A
similar capscrew was loose on the mounting bracket for Outlet Scram
i
4
Valve CRD-AO-CV127 on the same hydraulic control unit. The licensee initiated
}.
Problem identification Report 2-08308 to address the non-conforming condition.
!
However, in this instance consistent with the information from General Electric, the
licensee detenined that the valves were operable based on the f act that one tight
4
nut was sufficient to rigidly secure each valve.
In Problem Identification Report 2-08308, the licensee determined that the two
l
loose capscrews were not torqued during installation. The team noted that
Maintenance Procedure 7.2.55.2,"HCU SCRAM Valve Operator Diaphragm
Replacement," required the maintenar.ce worker and the quality controlinspector to
sign-off that the nuts were torqued to 240 in-lbs. The failure to properly torque the
'
nuts was a violation of Technical Specification 6.3.1, which requires that station
personnel use maintenance procedures for maintenance of system components and
systems that could have an effect on nuclear safety (50-298/9624-06).
3
1
4
13
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r
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.
The team was also concerned that the licensee's previously noted generic concern
with maintenance personnel signing work as complete, when it was not, may not
have been fully remedied. Therefore, the team reviewed the most recent work
packages that required disassembly of the 14 valves found with missing washers.
All work was performed utilizing Maintenance Procedure 7.2.55.2,"HCU SCRAM
Valve Operator Diaphragm Replacement." Although different revisions of the
procedure were in effect during different jobs (over a 6-year period), all of the
revisions contained the same general guidance with respect to the installation of
the subject components. Based on the f ailure rate, the team concluded that the
applicable procedural guidance was weak. Specifically, Maintenance Procedure
7.2.55.2 required the mechanic to install the capscrews with nuts and washers, but
did not specify that each capscrew assembly required a nut, flat-washer, and lock
washer. The licensee indicated that this particular knowledge was within the skill-
of-the-craf t. However, since the team identified 14 examples: 6 of the valves were
worked in 1995,1 in 1994,5 in 1992 and 2 in 1991; there appeared to be a trend
of errors, which would indicate that skill-of-the-craft alone was not sufficient to
ensure proper assembly. Therefore, the team concluded that improved procedural
guidance was warranted.
During interviews, licensee personnel stated that loose scram valve mounting
brackets has been a recurring problem at this facility for several years. The team
concluded that the licensee's corrective actions to address this long-standing
problem were not effective.
c.
Conclusions
The team identified one violation regarding the failure of a maintenance worker and
a quality controlinspector to follow procedural requirements. The team also
concluded that: 1) the operability determination, which addressed the non-
conformances, was incorrect because it was based on engineering judgement alone
and did not consider seismic qualification test data which was available from the
vendor; 2) procedural guidance for the installation of the scram valve actuator
mounting brackets was in need of improvement; and 3) the licensee's corrective
actions for addressing repetitive instances of non-conforming scram valve actuator
mounting assemblies were ineffective.
E3
Engineering Procedures and Documentation
E3.1
Site-Specific Emeraency Ooeratina Procedure issues
a.
Inspection Scope (93801. 37550)
The team reviewed Design Change 90-001,"RCIC Alternate Boron injection,"
Station Operating Procedure 2.2.69.2,"RHR System Shutdown Operations,"
Revision 19, Emergency Operating Procedure 5.8, Sheet 6A, "RPV Pressure (Failure
to Scram)," and Emergency Operating Procedure 5.8.8, " Alternate Boron injection
and Preparation," Revision 3, to evaluate the adequacy of the licensee's procedures
for emergency conditions.
14
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.
.
b.
Observations and Findinas
b.1. Alternate Boron Iniection
The team identified that Emergency Operating Procedure 5.8.8, " Alternate Boron
injection and Preparation," Revision 3, was inadequate because it did not
appropriately implement design assumptions made in Design Change 90-001, "RCIC
Alternate Boron Injection." "hese oversights contributed to the difficulties the
licensee experienced when attempting to utilize the reactor core isolation cooling
-system for alternate boron injection during a drill on October 8,1996.
Design Change 90-001 provided a temporary modification that permitted alternate
boron injection with the reactor core isolation cooling system (in the event that the
standby liquid control system f ailed). The temporary modification consisted of'a
200-ft long hose and fittings that could be installed between the standby liquid
control system tank drain valve and the suction of the reactor core isolation cooling
pump. As documented in Design Change 90-001,37 minutes of reactor core
isolation cooling operation would be required to transfer the contents of the standby
liquid control system tank into the reactor. vessel. During this time 14,800 gallons
of fluid (including 3,600 gallons of boric acid solution and 11,200 gallons reactor
core isolation cooling system water) would be injected. The licensee calculated that
the injection inventory was equivalent to 88 inches of level in the reactor vessel.
Design Change 90-001 also stated that the emergency operating procedures
I
required level to be lowered to the top of active fuel prior to boron injection; .
therefore, sufficient room would be available to accommodate the 14,800 gallons of
fluid. However, contrary to what was stated in the design calculation, the team
identified that reactor vessel level would not necessarily be reduced during an
ATWS. Emergency operating procedures allowed level to be as high as 58.5 inches
(reactor core isolation cooling high level trip).
On October 8,1996, the team observed the licensee during an ATWS drill where
alternate boron injection with the reactor core isolation cooling system was
attempted. At the time of boron injection, reactor level was close to the reactor
core isolation cooling high level trip. To avoid tripping the reactor core isolation
cooling pump, the operator reduced reactor core isolation cooling flow substantially.
However, the operator had failed to accomplish the procedural requirement to de-
energize closed the reactor core isolation cooling system minimum flow valve.
Subsequently, the minimum flow valve opened and diverted most of the boric acid
inventory to the torus. The team determined that, even if the valve had been
deactivated closed, the failure to lower level to make room for the boron inventory
(prior to injection) would have likely resulted in either tripping the reactor core
isolation cooling pump or extending the boron injection time due to the very low
reactor core isolation cooling system flow.
15
_
.
.
The licensee agreed with the inspector's observation and included an appropriate
finding in the quality assurance report that addressed the October 8 drill (the report
was dated October 22,1996). Additionally, the licensee briefed all of the operating
crews on the emergency operating procedure deficiency and delineated temporary
measures to avoid potential control problems. However, the final corrective actions
to address this deficiency were not determined at the conclusion of the inspection.
The team considered Emergency Operating Procedure 5.8.8 to be inadequate
because it did not caution operators to control reactor water level at an appropriate
level (when injecting boron svith the reactor core isolation cooling system) to ensure
that sufficient room was available to accommodate the boric acid solution as
assumed in the design. This is considered to be the first example of a violation of
Technical Specification 6.3.2, which requires the licensee, in part, to establish and
implement written procedures for emergency conditions involving possible releases
of radioactive materials (50-298/9624-07).
b.2. Loss-of-Boron to Radwaste System
The team identified that Station Operating Procedure 2.2.69.2, Revision 19, was
inadequate for use during an ATWS event because it instructed operators to flush
reactor vessel (borated) water to the radwaste system. Specifically, during an
ATWS the licensee would use the shutdown cooling mode of residual heat removal
system to achieve a cold shutdown condition in the reactor vessel. Because the
control rods are unavailable during an ATWS, the emergency operating procedures
direct the operators to inject the liquid control solution (boron) into the reactor
vessel. The borated water acts as a neutron poison and shuts the nuclear reaction
down. Af ter enough boron has been injected to maintain the reactor in cold
shutdown, Emergency Operating Procedure 5.8, Sheet 6A, Step FS/P-11, instructs
the operators to cool the reactor using the shutdown cooling mode of the residual
heat removal system.
Licensee personnel stated that they would use Station Operating
Procedure 2.2.69.2 to place the residual heat removal system in the
shutdown cooling mode, in accordance with Station Operating Procedure 2.2.69.2
the residual heat removal system piping would be initially warmed up by flushing
hot reactor water through the residual heat removal system lines and on to
radwaste. Approximately two-thirds of the volume of the residual heat removalline
would be flushed while the remaining one-third would continue to contain pure
water (as it is outside the flow path). Based on information provided 'oy the
licensee, the team determined that as much as 18,000 gallons of borated water
would be removed from the reactor coolant system during the warmup process. Of
that amount, approximately 6,000 gallons would remain available in the residual
heat removal system piping, but the remainder would be lost to the radwaste
system and would not be recoverable. The concentration of boron still available to
control reactivity at the conclusion of the warmup process would be reduced by
approximately 20 percent. This loss was not considered in the design basis
calculations for establishing the necessary amount of boron.
16
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.
.
The licensee agreed with the team's observations, but pointed out that the design
basis amount of boron contains an additional 25 percent boron concentration to
compensate for imperfect mixing. The team acknowledged the information but
determined that imperfect mixing was likely. Therefore, the loss of 20 percent of
the boron inventory could challenge the licensee's ability to maintain the reactor in a
shutdown condition. The team also noted that emergency operating procedures
instruct the operators to go to shutdown cooling before the additional 25 percent
boron concentration has been injected (see Section E3.2.1 of this report).
The team concluded that the licensee's procedure for placing the shutdown cooling
mode of residual heat removal system in service was inadequate because it failed to
provide appropriate instructions to ensure that design basis boron concentrations
would not be compromised during an ATWS event. This is considered to be the
second example of a violation of Technical Specification 6.3.2, which requires the
licensee, in part, to establish and implement written procedures for emergency
conditions involving possible releases of radioactive materials (50-298/9624-07).
b.3. Possible Release of Radioactive Materials Durina Cooldown Followina an Accident
On April 24,1996, the licensee had identified that the use of Station Operating
Procedure 2.2.69.2, Revision 19, to discharge reactor water to radwaste when
secondary or primary containment is needed had not been analyzed in the USAR
and, as a result, may be outside of the USAR safety design basis. As an immediate
corrective action, the licensee generated a potential Limiting Condition For
Operation requiring that,
". . . should Mode V (Refuel or Shutdown with one or more
reactor vessel head closure bolts less than fully tensioned)
Potential Limiting Condition For Operation ' Secondary
,
'
Containment' be entered, water shall not be discharged to the
main condenser or Radwaste via Valve RHR-MO-57 and 67
prior to an acceptable analysis on the issue being performed."
The licensee used a Potential Limiting Conditions for Operation to keep operators
aware of actions which could place them in a Technical Specification Limiting
Condition For Operation. They reviewed the condition for reportability under
10 CFR 50.73 and concluded that the condition was not reportable.
When questioned regarding the current status of the Potential Limiting Condition For
Operation, the licensee indicated that they could not find any evidence that the
operators were still tracking the Potential Limiting Condition for Operation. The
team did not find any indication that the licensee had considered use of the
procedure during emergency conditions. As of November 1,1996, the licensee had
not updated Standard Operating Procedure 2.2.69.2 to provide appropriate
precautions related to use of the procedure during emergency conditions.
17
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,
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.
The team concluded the procedure was inadequate because it f ailed to provide
appropriate instructions to ensure that containment of radioactive materials would
not be compromised during an ATWS event. The team noted that this concern is
also applicable to use of Procedure 2.2.69.2 following any accident. This is
considered the third example of a violation of Technical Specification 6.3.2, which
requires the licensee, in part, to establish and implement written procedures for
emergency conditions involving possible releases of radioactive materials
(50-298/9624-07).
c.
Conclusions
The team identified three failures to provide adequate procedures for emergency
conditions. First, Emergency Operating Procedure 5.8.8 was inadequate because it
,
f ailed to provide appropriate instructions to ensure that adequate space was
available in the reactor vessel when reactor core isolation cooling is utilized for
alternate boron injection. Second, Procedure 2.2.69.2 was inadequate because it
failed to provide appropriate instructions to ensure that design basis boron
concentrations would not be compromised during an ATWS event. Third,
Procedure 2.2.69.2 was inadequate because it f ailed to provide appropriate
instructions to ensure that containment of radioactive materials would not be
compromised during an ATWS event. The team also concluded that the licensee's
immediate corrective actions to preclude release of radioactive materials following
and accident were ineffective.
E3.2 Industry Emeraency Operatina Procedure Issues
a.
Inspection Scope (93801. 37550)
The team reviewed Emergency Procedure 5.8, "RPV Pressure (Failure to Scram),"
Revision 8, with particular attention on Attachment 1, pages 6A through 7B,
involving the instructions for dealing with a failure to scram. These sections
included the instructions for using the standby liquid confrol system to shut down
the reactor. The team reviewed NEDC 93-142,"SLC Storage Tank Setpoints and
Concentration Reauirements," Revision O. The team also reviewed an informal
calculation the licensee had used for the development of the emergency operating
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procedures.
b.
Observations and Findinas
The team found that NEDC 93-142,"SLC Storage Tank Setpoints and
Concentration Requirements," Revis;on 0, was the official design calculation that
determined the standby liquid control system tank volume required to assure that
660 ppm of boron would be in the reactor core when it was injected. This boron
concentration was required to achieve coK st;utdown. The team found that the
licensee had provided for enough boron to achieve this concentration in the reactor
pressure vessel and the non-isolated portions of other connected systems: the
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reactor water cleanup system, the recirculation system, and the residual heat
removal system in the shutdown cooling mode. In addition, this calculation
included a 25 percent margin (reactor concentration of 825 ppm) for leakage and
mixing inaccuracies, and it was the basis for the minimum solution volume-versus-
concentration curve in Figure 3.4.1 of the Technical Specifications.
The team identified three concerns with Emergency Procedure 5.8 as described in
the following paragraphs presented in approximately the order they would appear in
an actual accident.
b.1. Inadeauate Mixina Not Considered When Determinino Hot and Cold Boron
Shutdown Worths
The two decision points in the f ailure to scram portion of Emergency Procedure 5.8,
Revision 8, were based on the amount of boron which had been injected into the
core. During an ATWS event, reactor water level is lowered to control power The
procedure allowed operators to raise reactor water ievel once hot shutdown boron
worth was achieved. Since cooling the reacter increases reactivity, the procedure
allowed the operators to cool the reactor once cold shutdown boron worth was
achieved.
The team found that the licensee had used a separate informal calculation to
determine the hot and cold shutdown boron worth values for use in the emergency
operating procedures. This calculation was not named, numbered, signed, checked
nor approved. The licensee stated that they had prepared it in accordance with the
Boiling Waier Reactor User's Group guidelines. However, this informal calculation
assumed that the solution was " mixed uniformly" with the water in the reactor
vessel and appurtenances; no margin was provided to account for non-uniform
mixing. The team was concerned that these two emergency operating procedure
variables (i.e., hot shutdown boron worth and cold shutdown boron worth) had
been calculated without allowing for the safety margins which were included in the
original design. The design basis and the Technical Specification included 25
percent additional boron to allow, in part, for non-uniform mixing. The values for
these emergency operating procedure decision points were calculated without the
25 percent additional boron.
The team was also concerned that non-uniform mixing was likely and, as a result,
the reactor may not remain shutdown when water level was raised because
insufficient boron had been injected to actually achieve hot shutdown boron worth.
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The team was similarly concerned that the reactor would not remain shutdown
when the reactor was cooled because insufficient boron had been injected to
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actually achieve cold shutdown boron worth.
The licensee stated that they were not required to use the more conservative design
volumes, which mcluded a margin for inadequate mixing, in the emergency
operating procedures. This issue is considered unresolved and will be forwarded to
the Office of Nuclear Reactor Regulation for additional review (50-298/9624-08).
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b.2. Limitina Standbv Liauid Control Svstem Tank Concentration Assumotions Not Used
to Determine Hot and Cold Boron Shutdown Worths
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The team found that the emergency procedure calculation for determining the
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amount of injected boron necessary to achieve hot and cold boron shutdown worth
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also contained a non-conservative tank concentration assumption. The licensee had
assumed that the tank concentration was 15 percent. The licensee noted that this
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was their lower administrative limit. However, the team noted that the Technical
1
Specification limit on standby liquid control system was lower (i.e.,11.5 percent).
The team was concerned that the licensee could operate within the Technical
Specifications limits and the emergency operating procedures would not be
effective. The licensee stated that it was the Boiling Water Reactor Owner's Group
policy to use a nominal value rather thac c limiting value. This issue is considered
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unresolved and will be forwarded to the Office Of Nuclear Reactor Regulation for
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additional review as part of the unresolved item discussed in E3.2.b.1
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(50-298/9624-08).
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b.3. Standby Liauid Control System Boron Disolacement Not Considered Durina initiation
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Following use of the standby liquid control system to achieve cold shutdown boron
worth and depressurization of the reactor, the emergency operating procedure
called for the use of the shutdown cooling mode of residual heat removal system to
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bring the reactor to the cold shutdown condition. The initial boron concentration in
the reactor pressure vessel when the shutdown cooling was initiated would be
higher than necessary to allow for dilution as the shutdown cooling loop is placed in
service. However, the team was concerned that the licensee had not adequately
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accounted for the mixing process which would occur when the residual heat
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removal system was placed in service in the shutdown cooling mode.
Specifically, the flow path for the residual heat removal system during the
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shutdown cooling mode was from the vessel downcommer area through one of the
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recirculation loops, back to the vessel through the same or the opposite
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recirculation loop, through the jet pumps, into the vessel bottom plenum, and up
into the core. Initially water from the residual heat removal system would all be
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unborated water. Borated water in the core would be displaced out the top and
over into the downcommer area. A-
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3ed above, some of the borated water
would leave the vessel and enter
ial heat removal system via the
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recirculation suction loop. At the jo
as, a portion of the borated water
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displaced from the core would be mixed with the unborated incoming water from
the residual heat removal system loop and be returned to the bottom of the vessel.
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The licensee provided an uncontrolled copy of a calculation prepared in accordance
with Boiling Water Reactor Owner's Group guidelines which stated that 542,005
lbm of water would be in the reactor, the recirculation loops, and the reactor water
cleanup system loops during hot conditions and that, at cold conditions, the same
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piping plus residual heat removal system piping would contain 1,009,647 lbm of
water. The team was concerned because the volume of the residual heat removal
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system was so large with respect to the volume of the borated water, that a period
of time could exist, prior to complete mixing, where a significant portion of the
boron would be in the shutdown cooling loops of the residual heat removal system.
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This boron would not be in the core and, therefore, would not be available to
control reactiv;ty.
The team performed an informal calculation of the possible initial effects of this
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disolacement of borated water from the core to the shutdown cooling loop. While
the informal calculation was bued on unverified assumptions, the results indicated
that there may not be enough boron in the core under all conditions. Starting from
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an initial concentration of 1,124 ppm in the vessel, with a shutdown cooling flow
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rate of approximately 5,000 ppm, in less than 4 minutes the concentration in the
reactor would be below the 660 ppm minimum, and in approximately 12 minutes,
the concentration would be down to less than 200 ppm. This reactivity reinsertion,
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combined with the reactivity reinsertion of the cold water from the sesidual heat
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removal system loop, could potentially allow a significant reactivity excursion.
Discussion with General Electric representatives and the Office of Nuclear Reactor
Regulation Project Manager indicated that the effects of the boron displacement
during initial operation in the shutdown cooling mode had not been previously
comprehensively considered during the development of the emergency operating
procedures. The General Electric representative stated that mixing issues related to
raising reactor vessel water level with unborated water had been previously
evaluated, but mixing related to boron dilution during initial operation in the
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shutdown cooling mode had not.
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The team was concerned that this potential reactivity excursion had not been
analyzed to determine the potential for fuel failure, reactor repressurization, or
overpressurization of the shutdown cooling loops before they could automatically
isolate (40 seconds maximum allowable stroke time on the isolation valves).
Overpressurization of the shutdown cooling loops could potentially cause a residual
heat removal system rupture (a loss-of-coolant accident outside primary
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containment), and a loss of the boron previously injected. This issue is considered
unresolved pending additional evaluation by the Office of Nuclear Reactor
Regulation and will be followed as the third part of the unresolved item discussed in
Sections E3.2.b.1 and b.2 (50-298/9624-08).
c.
Conclusions
The team concluded that the directions contained in Emergency Operating
Procedure 5.8, Revision 8, were based on non-conservative assumptions and,
therefore, would not necessarily provide sufficient operator guidance for an ATWS
event. The team also concluded that, as a result of the above described
observation concerning displacement of boron from the core, the emergency
operating procedure relating to standby liquid control system injection on failure-to-
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scram did not necessarily provide a success path for the operators, and could lead
to even more serious conditions from which there could be no recovery. These
3
issues will be followed as an uaresolved item pending further evaluation.
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E7
Quality Assurance in Engineering Activities
E7.1
Ooen item Trackina for Desian Criteria Document Validation
a.
insoection Scope (93801. 37550)
The team reviewed the identification and disposition of open items identified
in the development of Design Criteria Document DCD-14, " Reactor Protection
System (RPS)," Revision 0, July 26,1995.
b.
Observations and Findinas
The team noted that there were several open items in the design criteria documents
regarding seismic qualification of various reactor protection system instruments and
devices. Examples of these open items were identified on reactor protection system
design criteria document Validation Checklist DBI-7, Validation, Paragraph 111-2,.
Items 1F,1G, (et. al.). For example, the reactor protection system design criteria
document validation concluded, in part, that documentation of seismic qualification
for the HFA-model relays was not retrievable, and suggested (via Note 1 of the
document) that this would be resolved via the seismic qualification users group-
program pursuant to Unresolved Safety issue A-46. The team asked the licensee to
provide the status of this resolution, and how the qualification of the device would
be linked to a seismic qualification test. Other similar examples included:
!
General Electric CR 2940 pushbuttons
p. Ill-32
General Electric CR 29412-position switches
p.111-34
Circuit breakers for 120V ac service to reactor protection
p. Ill-36
system
Magnetrol 751 level switches for scram discharge Volumes
p.111-39
Barksdale B2T pressure switches
p. Ill-42
Intermediate range neutron monitor
p. Ill-47
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The licensee researched these open items and determined that they had not been
captured in the licensee's open item tracking system for resolution. Specifically,
these open items had been identified by the contractor developing the design
criteria documents in June 1995, but had not been formally transmitted to the
licensee as contractually required. The licensee prepared Problem Identification
Report 2-06128 to address this concern and subsequently identified a total of
87 open items which had not been formally transmitted to the licensee from the
contractor.
The team reviewed Problem Identification Report 2-06128 and noted that on
October 9,1996, the licensee determined that there were no operability concerns
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because the open items involved were all Categories Ill, IV, or V problems. These
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categories were determined by the design criteria document validation contractor
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using NUMARC 90-012," Design Basis Program Guidelines," dated October 1990,
regarding design document reconstitution and NRC comments on the NUMARC
guidelines identified in an NRC Letter, W. T. Russell to W. H. Rasin (NUMARC),
"NRC Comments on Design Document Reconstitution Programs," November 9,
1990.
On December 10,1996, the team requested a copy of the list of the 87 open items.
The licensee stated that they had not completed their evaluation of the open items
classified as Category I or il to determine if they agreed with the classification and
to determine whether it was necessary to initiate problem identification reports. On
December 11,1996, the licensee provided the team with a list of open items. The
licensee stated that they had completed technical evaluations of some of the
Category 1 and 2 items and had determined that it was not necessary to issue
problem identification reports. On December 11,1996, the licensee provided the
team with a copy of the technical evaluations which had been completed.
The team reviewed the list of 87 open items and noted it included three Category I
items and seven Category 11 items. The team was concerned that the operability
determination for Problem Identification Report 2-06128 was not updated when the
Category I and 11 items were identified. The team concluded that since the initial
operability determination did not address Category I and 11 items, the licensee should
have promptly prepared operability determinations as Category I and il items were
identified.
The team reviewed the following three Category 1 items:
Diesel Generator Fuel Oil Sucolv Limits
The contractor identified that the Technical Specification 3.9.A.1.b requirement
for 48,000 gallons of fuel oil may be insufficient because some of the oil in
the main fuel oil storage tank is below the suction pipe and is not usable. USAR
Section Vill-5.2.7, " Standby A-C Power Source Safety Design Bases," requires that
both main fuel storage tanks combined shall be capable of providing sufficient fuel
for seven days of operation of one diesel-generator unit under postulated accident
conditions. The contractor calculated that 46,794 gallons were needed to meet the
7-day requirement at worst-case specific gravity. The contractor used a diesel
gereerator fuel oil storage tank volume graph from Calculation 87-052 and roughly
estimated that the verification being performed twice per shift by the operators
using Procedure 2.1.11, Attachment 1, corresponds to approximately
46,500 gallons.
On December 11,1996, the licensee determined that this issue was not a condition
adverse to quality. On December 19,1996, the NRC team reviewed the basis for
this determination and found it to be incorrect. Specifically, the licensee had
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reasoned that the oil supply from the day tank could be added to the oil supply from
the main fuel oil storage tanks to meet the 7-day requirement. This conflicted with
the design basis described in Section Vill-5.2.7. The USAR specifies a 7-day supply
requirement for the main fuel oil storage tanks and a separate 6-hour supply
requirement for the day tanks.
On December 19,1996, after discussion with the team, the licensee initiated a
picblem identification report to document this condition adverse to quality and
performed an operability determination. The licensee determined that if the
Technical Specification requirement of 48,000 gallons is just met, the resulting
usable volume present in the main storage tanks is 45,324 gallons. This usable
volume is less than the calculated 7-day fuel consumption. The licensee found the
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main storage fuel oil tanks to be operable because they currently contained rnore
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than 48,000 gallons. They contained enough fuel oil to meet the 7-day
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requirement, after allowing for the unusable volume.
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Automatic Depressurization System Accumulator Sizina Calculations
The contractor identified that the worst-case leak had not been analyzed in the
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sizing calculations for the automatic depressurization system accumulators. The
contractor postulated that the worst-case leak was a slow, but significant leak,
)
upstream of the automatic depressurization system accumulator check valves. The
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contractor evaluated: 1) the automatic depressurization system accumulator sizing
calculation, 2) the automatic depressurization accumulator low pressure alarm
setpoint,3) the accuracy of the associated pressure switches, and 4) the
accumulator check valve leak test criteria. Based on worst-case design
)
assumptions, the contractor determined that the automatic depressurization system
accumulators could degrade to below their operability limit before operations
personnel were aware the leak had occurred. The contractor concluded that the
plant design had not assured that the automatic depressurization system could
accomplish it's safety function: two main steam relief valve actuations at
70 percent of drywell design pressure 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after loss of the instrument
air / nitrogen system.
On December 19,1996, the licensee stated that they still had not completed the
technical evaluations of all of the Category I items, including this item. After
discussion with the team, the licensee initiated a problem identification report to
document this condition adverse to quality and on December 20,1996, the licensee
completed an operability evaluation.
The licensee determined that the contractors' conclusions were correct. On an
interim bases, using actual as-left pressure switch calibration data, the licensee
identified that the low instrument-air header pressure alarm could currently be relied
upon to alert the operators to the postulated leak prior to the accumulator pressure
going below the operability limit. The licensee concluded that while design and/or
procedure improvements were needed, the existing configuration assured the
automatic depressurization system accumulators were operable.
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Main Steam isolation Valve inboard Accumulator Sizina Calculations
The contractor similarly identified that the worst-case leak had not been analyzed in
the sizing calculations for the inboard main steam isolation valve accumulators. On
December 20,1996, the licensee completed an operability evaluation. The licensee
determined that the contractor had used an incorrect calculation as the basis for his
conclusion. The licensee reviewed the correct calculation, considered the leak
postulated by the contractor, and found the design to be acceptable.
c.
Conclusions
The team concluded that two of the three Category I items constituted a condition
adverse to quality. 10 CFR 50, Appendix B, Criterion XVI, requires that measures
be established to ensure that conditions adverse to quality are promptly identified.
The team determined that the failure to establish measures to assure that these two
design criteria document open items were promptly evaluated to identify conditions
adverse to quality is a violation of NRC requirements (50-298/9624-09)
As a result of questions by the team, the licensee identified 87 design criteria
document validation checklist open items which were not previously t'eing tracked
by the licensee. The team determined that the f ailure to establish measures to
assure that all design criteria document open items were promptly evaluated to
identify conditions adverse to quality is a violation of NRC requirements. The
licensee also did not promptly evaluate the Category I and ll open items to
determine if the affected equipment was operable. The team concluded that the
licensee had provided weak oversight to the design criteria document validation
program.
E7.2 Licensee Corrective Actions for Previousiv identified USAR Discrepancies
a.
Inspection Scoce (93801,37550)
As described above, the team identified a number of USAR discrepancies. To further
understand the scope of the issue, the team reviewed licensee corrective actions for
previously identified USAR deficiencies to determine if the previous corrective
actions should have prevented the additional discrepancies.
b.
Observations and Findinas
b.1. USAR Deficiencies identified Durina NRC Inspection Report 50-298/94-04(Violation
50-298\\9404-01)
In 1994, the NRC identified two examples where the licensee did not accurately
update their USAR. The USAR was not accurately updated to accoun!'or:
/ safety evaluation to change the licensing basis for the service water
system from 85 to 90 F, and
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A safety evaluation to not operate the service water booster pumps when
the residual heat removal system was being operated in the shutdown
cooling mode.
The licensee determined that the violation occurred because (1) they had used a.
justification for continued operation to change the licensing basis in lieu of a design
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change, and (2) the failure to recognize that a new mode of operation was a change
to the USAR. The licensee upgraded plant procedures to prohibit using operability
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evaluations to change the design basis and to enhance the control for identification
of USAR changes ducing the operating procedure revision process. They also
upgraded their design basis reconstitution process to include an evaluation of plant
operation.
b.2. USAR Deficiencies identified Durina Surveillance Test Proaram Validation
The licensee identified a variety of USAR discrepancies during their surveillance test
program validation project, which was conducted in 1994. The team identified two
items for review. The team found that the USAR had still not been corrected for
either discrepancy. Specifically, Surveillance Test Program Deficiency CRD-14-94
identified that Note 4 to Table Vil-3-1, Pipeline Penetrating Containment,"
incorrectly indicated that the control rod drive system solenoid valves open during a
reactor scram. The licensee submitted License Change Request 94-0126 to correct
the USA 9 to indicate the solenoid operated directional control valves do not open
on a screm. The licensee stated this change request was scheduled for
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income,ation in the 1995 USAR update, but that the change was not correctly
implemented. As a result, the current wording for Note 4 is ambiguous and does
not clearly indicate that the solenoid operated directional control valves do not open
during a reactor scram. The failure to correct the USAR within a reasonable
timeframe is the ninth example of an apparent violation of 10 CFR 50.71(e)
(50-298/9624-04);
in addition, Surveillance Test Program Deficiency CS-08-94 identified that USAR
Section Vll-4.5.44, " Core Spray System Control and Instrumentation Core Spray
Valve Control," incorrectly described the configuration of the pressure switches.
The licensee stated that a specific licensing change request had not been initiated
for this discrepancy. Instead, the licensee had written a memorandum requesting
that this correction be included in a licensing change request which had been
initiated against the same USAR page for a different reason (i.e., License Change
Request 94-0084); however, this discrepancy was not corrected. The licensee
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noted that several other USAR discrepancies were handled similarly and planned
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additional investigation to determine if the other discrepancies were effectively
corrected. The f ailure to correct the USAR within a reasonable time frames is the
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tenth example of an apparent violation of 10 CFR 50.71(e)(50-298/9624-04).
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b.3. USAR Deficiencies identified Durina NRC Inspection Reoort 50-298/96-03
During this resident inspection, the team identified two additional USAR
discrepancies relatrad to the description of drywellinstrument line
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Penetrations X-40A/B/C/D. The team determined that these discrepancies had
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previousti been identified in NRC inspection Report 50-298/96-04during the
followup of Violation 50-298/94014-05. As described in NRC inspection
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Report 50-298/96-03,the licensee had initiated Condition Report 96-0160 to
generically address containment penetration description discrepancies. The licensee
stated that they expected to complete their planned corrective actions by
December 20,1996.
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The team also noted that the resident inspectors had identified several additional
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USAR discrepancies in inspection reports issued during 1996.
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b.4. USAR Deficiencies identified Durina on Residual Heat Removal Svstem and Hiah
Pressure Coolant Iniection Review
Early in 1996, the licensee contracted a limited scope review of the residual heat
removal system and the high pressure coolant injection systems to determine the
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extent of the USAR discrepancy problem. The licensee determined this review
identified several errors with respect to technical inaccuracies, inadequate
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descriptions and inconsistencies between their preventive maintenance program and
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implied USAR commitments. On May 16,1996, the licensee initiated Condition
Report 96-0578 on USAR discrepancies. The team noted, however, that at the
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time of the inspection, the licensee had not developed plans to address the
comprehensive issue of USAR inaccuracies.
The inspectors noted that the contractor's review had identified six issues, which
they regarded as potential condition reports. Further inspection followup is needed
to ensure that these discrepancies receive an adequate evaluation. This item will be
followed as an inspection followup item (50-298/9624-10).
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c.
Conclusions
The team concluded that the licensee's corrective actions related to the USAR
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discrepancies had been ineffective. The licensee's corrective actions for a
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previous violation involving USAR discrepancies (Violation 50-298/94004-01)did
not identify and correct the additional USAR discrepancies. The resident inspectors
continued to identify several additional of USAR discrepancies during 1996. In
addition, the licensee identified a number of USAR discrepancies as a byproduct of
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their surveillance test program validation; however, they were not successful in
assuring these deficiencies were corrected. Two of these USAR discrepancies are
considered additional examples of an apparent violation of 10 CFR 50.71(e).
Finally, the licensee contracted for a limited scope review of the residual heat
,
removal system and high pressure coolant injection systems to determine the scope
of the USAR discrepancy problem. This review was completed in mid-1996;
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however, as of November 1,1996, the licensee had not followed through with a
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comprehensive plan to correct and update the USAR. Based on the number of
deficiencies that were identified, by the licensee, the resident inspectors and the
team, the team concluded that the current licensing basis as described in the USAR
contained many inaccuracies.
E7.3 Licensee Corrective Actions for General Electric Identified Potential Reportable
Condition 89-15. " Control Rod Drive System Leakaae Durina a LOCA"
a.
Inspection Scope (93801,37550)
In 1989, the licensee was informed by General Electric of a potentially reportable
condition concerning bypass leakage (around the secondary containment) through
the control rod drive system. In response, the licensee added two series check
valves in this leak path. The team reviewed this modificatinn and the applicable
requirements with regard to allowable leakage, source term, allowable accident
exposures, etc., to determine the acceptability of the leakage limits which were
specified for the check valves.
b.
Observations and Findinas
General Electric Potentially Reportable Condition 89-15 notified utilities that one
BWR/5 utility had concluded that the control rod drive system had the potential for
post loss-of-coolant accident bypass leakage pathways. With the pumps shutdown,
the potential post loss-of-coolant accident leakage is from the reactor vessel
through the control rod drive housings, through the hydraulic control units, through
the water headers for exhaust, cooling, drive and charging, through the pumps and
open valves to outside containment. Once outside containment, the piping is not
safety-grade quality and was assumed to have broken.
The team noted that the potential reportable condition reflected a change in
understanding of the importance of this bypass leak path. This potential
bypass leak path was not considered credible during initiallicensing. USAR
Section V-2.3.5.1, " Primary Containment isolation Valves General Criteria," states,
'No automatic isolation valves are provided on the control rod
drive system hydraulic lines. The redundant seals and
restrictive flow areas that are inherent to the control rod drives
provide the required redundant Reactor Coolant Pressure
Boundary isolation. The system hydraulic lines are, therefore,
not considered part of the Reactor Coolant Pressure
Boundary."
The licensee contracted with General Electric to do a sensitivity study to determine
the aggregate control room inhalation dose as a result of the postulated leak path
following a design basis loss-of-coolant accident. General Electric performed the
study using two source terms (i.e., the Regulatory Guide 1.3/1.7 source term and
the facility-specific source term which had been submitted at the time of initial
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licensing).
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The team noted that at the time of the initiallicensing, the licensee submitted
source terms to be used for calculation of offsite dose and control room dose which
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were not consistent with Safety Guide 3 (later updated to Regulatory Guide 1.3).
Saiity Guide 3 required, among other things, that in calculating the potential
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consequences of postulated accidents, the licensee must assume that, in spite of
emergency core cooling system operation,100 percent of the noble gases and 50
percent of the halogens (primarily iodine) would be released from the fuel, and that
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50 percent of the released halogens would be plated out on containment surfaces
and other components. However, the original FSAR in Section 6.3.4, " Fission
Products Released to Primary Containment," stated that the fission products
assumed released were only 1.8 percent of the noble gases (56 times less) and
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O.32 percent of the halogens (78 times less).
The NRC staff reviewed the FSAR and issued a safety evaluation report which
evaluated the adequacy of the facility design using the criteria in Safety Guide 3.
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The current USAR contains the detailed results of dose calculations performed using
the source term originally submitted by the liceruee in their FSAR. For example,
Section XIV.6.3.8.1, " Loss-of-Coolant Accident Fission Products Released to
Primary Containment," item c, again stated the original FSAR source terms.
Although the licensee acknowledged in USAR Sectinn 6.3.8.4 that the Safety
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Evaluation Report source term was different, they made no reconciliation of the
differences. The USAR did generally describe the estimated dose using the Safety
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Guide 3 source terms. Licensee management maintains that the original FSAR
source term is their licensing basis for 10 CFR 100 dose calculations.
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in 1980, NUREG-0737," Clarification of TMl Action Plan Requirements," dated
October 31,1980, was issued by the NRC to address the special concerns
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identified as a result of the Three Mile Island accident. Section ll.B.2 of
this document, " Design Review of Plant Shielding and Environmental Qualification
of Equipment for Spaces / Systems Which May Be Used in Postaccident Operations,"
recognized the implications of the massive fuel failure experienced at Three
Mile Island (much worse than the Safety Guide 3 assumptions) and specified that
Regulatory Guide 1.3 (the successor to Safety Guide 3 containing the same basic
.
requirements) was the licensing basis for a// plants (regardless of their previous
licensing basis), with respect to spaces which may be used post accident. It
also reaffirmed the General Design Criteria 19 operator exposure limit of 5 rem
whole body or equivalent (30 rem thyroid dose) for accidents. NRC letter to
Mr. J. M. Pilant, Director - Licensing & Quality Assuranco, Nebraska Public Power
District, dated July 10,1981, was the Confirming Order stating that conformance
j
with NUREG-0737 was required and that, specifically, Section ll.B.2 was applicable
to a// licensees.
In response to the licensee's NUREG-0737 submittal, a safety evaluation report
transmitted to the licensee by an NRC letter to Mr. J. M. Pilant, Director -
Licensing & Quality Assurance, Nebraska Public Power District, dated March 11,
1983, stated that, "The licensee has not requested technical deviations from the
29
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criteria of item II.B.2," acknowledging the licensee's acceptance of Regulatory
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Guide 1.3 as the licensing basis for accident operator exposure. Licensee
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management acknowledged that control room shield design reviews were performed
1
based on dose estimates calculated using the Regulatory Guide 1.3 source term.
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As stated above, the General Electric separate calculations were prepared for each
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source term (i.e., the Regulatory Guide 1.3 source terms, and the source term from
the original Final Safety Analysis Report submittal). For the Regulatory Guide 1.3
case, the calculated control room exposure for 1 gpm leakage significantly exceeded
the 30 rem Regulatory Guide 1.3 limit. For the FSAR source-term case, the .
!
calculated exposure was 1.4 rem, which yielded an allowable leakage limit of 20.4
gpm.
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Based on these results, the licensee determined it was prudent to minirreize
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this type of bypass leakage. The licensee implemented Modification Design
Change 89-285/285A,"CRD Testable Check Valve Assembly," to add two series
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check valves. In 1990, the licensee performed two calculations to establish the
maximum allowable leakage of these check valves and their test acceptance criteria:
]
Calculations NEDC 89-2165," Permissible CRD System Bypass Leakage for a Design
Basis LOCA," Revision 0, and NEDC 89-2166, " Justification for Surveillance Test .
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Low Pressure Value for CRD System Check Valves CRD-CV-25CV and 26CV,"
Revision O. These criteria were used in Surveillance Procedure 15.CRD.502,"CRD
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Check Valve IST Leak Test," Revision 1C1, dated October 15,1996. The team
reviewed this modification and the applicable requirements with regard to allowable
leakage, source term, allowable accident exposures, etc., to determine the
acceptability of tb3 specified maximum allowable leakage for the check valves.
The team found that the licensee had used the original FSAR source term and the
i
General Electric sensitivity study described above as a basis for establishing the
allowed check valve leakage limits. The licensee continued to believe that the
!
leakage path was not credible for the reasons submitted in the original FSAR and
still described in USAR Section V-2.3.5.1, " Primary Containment isolation Valves
General Criteria." They did not believe they were required to update either their 10 CFR 100 dose calculations or the calculations that supported their control room
shielding review to include potential dose from this leak path. As a result, they
'
determined they were within their license conditions to use the original FSAR source
term as a basis for establishing the leakage criteria for these check valves.
As stated above, the General Electric study had determined for the FSAR source-
term case, the calculated exposure was 1.4 rem, which yielded a allowable leakage
,
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limit of 20.4 gpm. To provide a safety factor the licensee reduced it by a factor
,
of 10 to establish 2 gpm as the valve test acceptance criterion. Additional
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conservatism was included because the leakage medium would be water, which has
a significantly lower viscosity than the test medium of air,
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The team noted that bypass leakage, particularly from sources connected directly to
the reactor vessel, such as the control rod drive line, had the potential to be a
particularly large contributor to the total control room and offsite exposures for the
following reasons:
For sources connected to the reactor vessel, such as the control rod drive
line, the benefits of iodine plateout inside the containment would not be
-
realized:
The mitigating effects of holdup time, plateout, and dilution inside seconda y
containment would not be realized; and
The cleanup provided by the standby gas treatment system (approximately
99 percent removal of iodine) would not be realized.
The team was concerned that the licensee had not used the Regulatory Guide 1.3
source term to e;stablish the leakage limits. Using the Regulatory Guide 1.3 source
terms and neglecting the conservatisms related to the difference between the
leakage and test medium results in unacceptable results. Using these'more
conservative assumptions, the team calculated that if bypass leakage occurred at
the leakage limits of the check valves, the control room exposure would be many
times the General Design Criteria 19 allowable - from this source alone.
The team asked the licensee to provide the current actual test results for the
control rod drive check valves.' The values were 1.357 and 1.028 scfh for
valves CRD-CV-25CV and CRD-CV 26CV, respectively, using air as the test
medium. Based on these test results, and the fact that the viscosity of air was
approximately 800 times lower than water, the team concluded that most, if not a",
of the effects of using the incorrect source terms would be offset. However, finai
determination of the net effects were dependent on the licensee performing a
rigorous analysis considering all of the potential operator and offsite exposure
sources.
The team concluded that it was important to determine whether or not this bypass
leakage path is credible if the leakage path is credible, as suggested by the
General Electric Reportable Condition 89-15, then the licensee had the responsibility
to correct their licensing basis to address this significant condition adverse to
quality. Further, the (icensee would have been responsible to add the consequences
of releases from this path to their 10 CFR 100 dose calculations and to their control
room shielding calculations. Use of the FSAR source term to establish check valve
leak rates would have been unacceptable because it would not have been
consistent with the NRC Order to use the riegulatory Guide 1.3 source term for
evaluating doses which impact the control shield design review. This item will be
forwarded to the Office of Nuclear Reactor Regulation to determine whether or not
this is a credible leak path. This issue is considered unresolved (50-298/9624-11).
31
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c.
Conclusions
Based on a prudence determination, the licensee installed two series check valves
to address a potential bypass leak path described in General Electric Potentially
Reportable Condition 89-15. However, the licensee stated that they did not believe
the leak path was credible and, as a result, did not update the 10 CFR 100 dose
4
calculations, or the control room shielding dose calculations to include dose
'
contributions from this leak path, in addition, the licensee had not updated their
license to include this potential leak path or establish check valve leakrates which
would be consistent with their license requirements for credible bypass leakpaths.
This issue is considered unresolved.
E7.4 Imolementation of Generic Letter 85-06. " Quality Assurance Guidance For ATWS
gauipment That is Not Safetv-Related"
a.
Insoection Scoce (93801. 37550)
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Throughout the inspection, the team analyzed the implications of deficiencies on the
licensee's quality assurance program, in Generic Letter 85-06, the NRC staff
promulgated acceptable quality assurance guidance for ATWS equipment that is rot
safety related. The guidance was less restrictive than the quality assurance
!
requirements of 10 CFR 50, Appendix B. However, to make the guidance easily
adaptable to licens'ee quality assurance programs, the staff wrote the guidance in a
format which paralleled the requirements of Appendix B. The team evaluated
{
deficiencies related to Generic Letter 85-06 Criteria lil, V, and XVI.
b.
Observations and Findinos
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b.1. Criterion lli-
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The team identified that the licensee had not developed formal scaling calculations
for the standby liquid control system tank level indication. This level indicator is
used to establish compliance with the Technical Specifications. See NRC Inspection
Report 50-298/97-02for additional review'of the licensee's program for ensuring
that instruments with non-automatic functions are correctly scaled. The team
,
identified that the quantities of boron needed to establish hot shutdown boron
i
worth and cold shutdown boron worth in the emergency operating procedures were
based on an unnamed, unnumbered, unsigned, unchecked, unapproved calculation
which the licensee stated had originated with the Boiling Water Reactor Owners'
Group. The licensee was also not able to retrieve some calculations which were the
basis for the quantities specified in the emergency operating procedures. The team
,
also identified several non-conservatisms in Calculation 92-015," Standby Liquid
Control Pump Net Positive Suction Head," Revision 0, August 15,1994,
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b.2. Criterion V
The team found that during the development of the emergency operating
procedures, the licensee had relied heavily on Boiling Water Reactor Owner's Group
calculations that did not include any margin for incomplete mixing. However, the
licensee's procedures did not require that the standby liquid control system tank be
mixed as specified in the generic ATWS submittal. The General Electric Topical
,
Report Submittal on ATWS requires that the tank be mixed to be operable. The
I
team found that the tank is currently not being mixed as described in ATWS
l
submittal. The licensee revised this practice based on weak technical data and
without communication with the staff. Further, the USAR describes compensatory
measures that the licensee will take if the standby liquid control system tank heater
'
f ails. The license had not prepared procedures to implement these commitments.
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b.3. Criterion XVI
On April 29,1988,in response to the ATWS Rule,10 CFR 50.62, the licensee
requested an amendment to the Technical Specifications to raise the minimum
!
setpoint for the standby liquid control system relief valves. The licensee evaluated
the proposed amendment with respect to 10 CFR 50.92. The licensee concluded
(
that the change would not involve a significant reduction in margin based on the
claim that raising the relief valve setpoint would ensure there is approximately 70
psi margin to the calculated pump discharge pressure to minimize relief valve
leakage during two-pump operation. This margin was comparable to the General
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Electric recommended margin of 75 psi. The margin was needed in part to account
for positive displacement pump pressure waves which had not been accounted for
in the hydraulic analysis.
1
USAR Section 9.6, " Standby Liquid Control System Nuclear Safety Operational
i
Requirements," states that each standby liquid control system relief valve shall have
a setpoint of no less than 1450 psig. This section of the USAR also references
Technical Specification Section 3.4 as the current source of basis information for
the relief valve setpoint. The team noted that Section 3.4 indicates that the
minimum relief valve setpoint is selected to prevent the relief valve from
prematurely lif ting and recycling the liquid control solution. The Technical
Specification Basis section also stated that the standby liquid control system
changes made as a result of the ATWS rule do not ;nvalidate the original system
design basis, which included a similar requirement.
.
On September 29,1988, based on an evaluation of post-modification test results,
.
the licensee learned that the 70 psi margin to calculated pump discharge pressure,
I
which was relied on in the no significant hazards determination, was incorrect; the
i
actual margin was 31.1 psi. As a result, the Technical Specification Basis, which
was referenced in the USAR, was not accurate and the licensee did not take
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corrective action to correct the Technical Specification surveillance requirement
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value.
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As a result of the team's questions, the licensee contacted the relief valve vendor to
determine relief valve performance if the setting was lowered to 1450 psig and the
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pump discharge pressure reaches 1418 psig. The vendor determined that, most
likely, the relief valve would open. The vendor noted that the relief valve had a set
pressure tolerance of i 3 percent. The vendor calculated that at the low side of
)
the tolerance, the opening pressure would be 1407 psig, which is below 1418 psig.
They further noted that their calculation of opening pressure did not include an
allowance for pressure waves, which are expected to occur during operation of a
positive displacement pump. The team concluded that pump oscillation peak
pressures would exacerbate the problem.
The licensee maintained that lifting of the relief valve would be acceptable, since it
would act as a pressure control device. The NRC team did not accept this position
for four reasons. First, if a valve were to lift, flow would be diverted from the
reactor, thereby, degrading the standby liquid control system function to mitigate an
ATWS. Second, if a valve were to lift, system pressure would immediately drop,
reseating the valve. This would cause pressure to rise again until the valve lifted
agair. This cycle would be rapidly repeated as long as the system was operated.
None of the standby liquid control system components (the relief valves, the pumps,
the piping, the motors, etc.) were designed for this cyclical loading, which could
cause failure in any of these components. Third, the function of relief valves is
overpressure protection, and as such, in accordance with piping codes, they are
required to be set above the maximum allowable working pressure of the system,
with appropriate margin, to assure that they will never lift under expected operating
{
conditions; this setpoint did not meet this requirement. And fourth, these relief
valves were not designed as pressure control devices and, therefore, could not be
relied upon to provide accurate pressure control.
The team determined that setting the standby liquid control system relief valve at
1450 psig would not prevent recycling of the liquid control solution via the lifting of
a relief valve at too low a pressure. The team found that the actual relief valve
i
setpoint was 1540 psig, which provided an ample margin of 122 psig; therefore,
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the team determined that operability was not a concern. However, the team
concluded that the licensee had not appropriately corrected their Technical
Specifications.
b.4.
Licensee Commitment to 0,eneric Letter 85-06
The team questioned the licensee regarding these quality assurance deficiencies.
The team requested that the licensee determine their commitment to Generic Letter 85-06 for the standby liquid control system. The licensee determined that
they had committed to the generic letter for altemate rod insertion and the
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recirculation pump trip which was established to meet the ATWS rule. They
determined that they had not committed to Generic Letter 85-06 for the standby
liquid control system.
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c.
Conclusions
,
The licensee had not' developed an effective quality assurance program for the
standby liquid control system. The team found inaccurate and missing calculations.
i
The team found that procedures had not been developed to address compensatory
measures described in the USAR. The licensee, also, did not take steps to' update a
i
Technical Specification surveillance requirement for the standby liquid control
j
system when they identified a condition which made the safety basis for a license
!
amendment invalid. The team concluded that the licensee had not established an
effective quality assurance program for the standby liquid control system that was
I
consistent with industry standards.
E8
Miscellaneous Engineering issues
E8.1
(Closed) Licensee Event Report 50-298/94026-01."Standbv Liould Control System
Not Maintained at Proper Temperature Due to Desian Deficiencv and Lack of
Acoropriate Monitorino"
'
a.
Insoection Scoce (93801,37550)
,
1
The team reviewed the licensee's corrective actions for Licensee Event
)
Report 50-298/94026-01. The team toured the standby liquid control system
j
tank room to inspect the piping insulation and heat trace. The tearn also
!
reviewed operating logs of room temperature during winter of 1995 an'd spring
of 1996.
b.
Observations and Findinas
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In Licensee Event Report 50-298/94026-01,the licensee reported that the standby
liquid control system had not always been maintained at the proper temperature.
The team found that the licensee had subsequently upgraded the piping insulation
and heat trace design to better control the temperature of the liquid solution and to
)
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prevent boron precipitation. The team found that the licensee had not added
insulation or heat trace to the piping which connected the discharge of the relief
valves to the pump suction.
The team was concerned that boron could precipitate in this piping and block the
relief valve discharge path. The licensee reviewed the temperature history in the
room and added heat tracing during the inspection. The team reviewed the same
operating logs and found that room temperature had dipped below 65
F, minimum
design room temperature, on 10 different days between December 5,1995, and
February 4,1996. As a result, depending on solution concentration in the
discharge piping, boron could have plugged the relief valve discharge piping. The
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licensee noted that demineralized water was used during quarterly surveillance
testing, so it was difficult to know the boron concentration in the relief discharge
piping. The licensee believed the concentration was likely less than the full tank
concentration.
35
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.
.
c.
Conclusions
f
The team determined that the licensee's initial corrective actions for Licensee Event
l
Report 50-298/94026-01 were not fully comprehensive, because the relief
'
discharge piping was not insulated or heat traced. However, the licensee completed
he installation of heat trace during the inspection. Licensee Event Report 50-
t
298/94026-01is closed.
V. Manaaement Meetinos
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Exit Meeting Summary
The team presented the inspection results to members of liunsee management at the
l
conclusion of the onsite inspection on November 1,1996. Following additional in-office
inspection, an exit meeting was held with your staff on November 26,1996. Several
!
items remained unresolved at the exit. At the team leader's request, the licensee provided
l
additionalinformation to the NRC following the exit. The results of the NRC's review of
the additional information and the overall results of this inspection were discussed during a
final exit meeting with Mr. Phil Graham on February 19,1997. The licer.see acknowledged
the findings presented.
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ATTACHMENT
,
SUPPLEMENTAL INFORM ATION
PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. Bennett, Licensing Supervisor
,
M. Boyce, Senior Engineering Manager
i
D. Buman, Design Engineering Manager
R. Creason, Senior Operations Training Specialist
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P. DiRito, Reliability Engineer
F. Diya, Engineering Support Manager
R. Godley, Plant Engineering Manager
B. Huston, Licensing Manager
J. Lindinger, Reactor Protection System Engineer
C. Moeller, Licensing Engineer
O. Olson, Core Cooling Supervisor
M. Peckham, Plant Manager
J. Pelletier, Senior Manager of Engineering
D. Schantzen, Standby Liquid Control System Engineer
j
J. Swanson, System Engineer
M. Unruh, Instrument and Controls Design Engineering Supervisor
B. Victor, Licensing Engineer
Z. Wahab, Configuration Management Supervisor
S. Wheeler, Operations Shift Engineer
General Electric (via telechonel
Jason Post
Michael Davis
NRC
Mary Miller, Senior Resident Inspector
Chris Skinner, Resident inspector
INSPECTION PROCEDURES USED
Safety System functional Inspection (SSFI)
Engineering
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ITEMS OPENED. CLOSED, AND DISCUSSED
Opened
50-298/9624-01
Failure to accurately prepare calculations and to
accurately translate the results of calculations into
surveillance procedures (Section E1.1)
50-298/9624-02
Possible deviation to Safety Guide 11 Supplement,
" Instrument Lines Penetrating Primary Reactor
,
Containment Backfitting Considerations" (Section E1.2)
'
50-298/9624-03
Possible 10 CFR 50.59 violation related to modification of
standby liquid control system circuit separation and
isolation devices (Section E1.3)
50-298/9624-04
APV
Ten apparent examples of a 10 CFR 50.71(e) violation
involving (1) seismic analysis of Class-1 piping, (2)
,
incorrect time delay for initiating control rod insertion, (3)
incorrect minimum building temperature, (4) incorrect
j
design pressure requirements for standby liquid control
system, (5) inconsistent temperature and concentration
requirements for the standby liquid control system, (6)
,
modification to reactor water clean up valve logic, (7)
standby liquid control system injection times, (8) standby
liquid control system tank level alarm setpoint, (9)
incorrect description of hydraulic control unit operation,
and (10) incorrect description of core spray system
pressure switch operation (Sections E1.4 and E7.2)
50-298/9624-05
Possible 10 CFR 50.71(e) violation related to a non-
bounding analysis involving the radiological consequences
for an ATWS (Section E1.5)
50-298/9624-06
Failure to torque hydraulic control unit scram valve
capscrews as required by maintenance instructions
(Section E2.1)
50-298/9624-07
Three examples of the failure to develop acceptable
procedures to respond to an enticipated transient without
sciam event involving (1) not ensuring adequate volume
in the reactor vessel before use of the reactor core
isolation cooling system as an alternate boron injection
method, (2) not ensuring that design basis boron
concentrations would be diluted during an ATWS, and (3)
not ensuring the containment of radioactive material after
an ATWS (Section E3.1)
2
.
50-298/9624-08
Three concerns regarding: (1) inadequate mixing not
considered when determining hot and cold boron
shutdown worth; (2) limiting standby liquid control
system tank concentration assumptions not used to
determine hot and cold boron shutdown worths; and (3)
standby liquid control system bcron displacement not
considered during initiation of shutdown cooling
(Section E3.2)
50-298/9624-09
Failure to promptly identify and correct conditions adverse
to quality related to a design criteria document review
(Section E7.1)
50-298/9624-10
IFl
Review licensee's disposition of contractor-identified
potential condition reports (E7.2)
50-298/9624-11
Possible inadequate corrective actions for a vendor
notification regarding a control rod drive bypass leak path
(Section E7.3)
Closed
50-298/9624-01
Failure to accurately prepare calculations and to
accurately translate the results of calculations into
surveillance procedures (Section E1.1)
-50-298/9426-01
LER
Standby Liquid Control System Not Maintained at Proper
Temperature Due to Design Deficiency and Lack of
Appropriate Monitoring (Section E8.1)
LIST OF DOCUMENTS REVIEWED
Cooper Nuclear Station Technical Specifications
Cooper Nuclear Station Final Safety Analysis Report
Cooper Nuclear Station USAR
Correspondence:
USNRC Letter to Mr. J. M. Pilant, Director - Licensing & Quality Assurance, NPPD, dated
July 10,1981
NPPD Letter NLS8500282 from Jay M. Pilant, Manager Technical Staff, to USNRC Hugh L.
Thompson Jr., Director, Division of Licensing, dated October 14,1985
NPPD Letter NLS8700187 from George A. Trevors, Manager of Nuclear Support, to
USNRC Document Control Desk, dated April 8,1987
)
3
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.
e
USNRC Letter from William O. Long, Project Manager BWR Project Directorate 2 Division of
Licensing to J. M. Pilant, NPPD Staff Manger, Docket 50-298 dated October 27,1986
USNRC Letter to Mr. Terry A. Pickins, Chairman, BWR Owner's Group, dated October 21,
i
1986, Subject: Acceptance for Referencing of Licensing Topical Report NEDE-31096 P,
" Anticipated Transients Without Scram: Response to NRC Rule,10CFR50.62"
'
General Electric, Nuclear Fuel and Engineering Services Department, internal memorandum,
G. A. Watford to J. S. Post, dated February 2,1987, Subject: Hot and Cold Shutdown
Boron Weight for EPGS
NPPD Letter NLS8700601 to USNRC dated November 18,1987, Subject: ATWS
(10CFR50.62) Additional Information
i
General Electric letter G-HPO-9-208 dated July 10,1989 to Mr. G. R. Horn, Nuclear
Operations Division Manager, NPPD, Subject: GE PRC 89-15 CRD System Leakage During
NPPD Letter from G.A. Trevors to USNRC. Attention: Document Control Desk,
Washington, D.C. Reference NLS9000150 dated April 12,1990
USNRC Letter, W. T. Russell to W. H. Rasin (NUMARC), NRC Comments on Design
Document Reconstitution Programs, November 9,1990
BWR Owners' Group Letter BWROG-94094 dated July 15,1994 to USNRC, Subject:
Submittal of Responses to Request for Additionalinformation Regarding Proposed EPG
Modifications Addrecsing ATWS/Stabilityissue
USNRC Letter from Harold R. Denton, Director, Office of NRR, to Mr. John M. Fulton,
Chairman, BWR Owner's Group, dated August 19,1995
Safety Evaluation Reports
Safety Evaluation Report dated February 14,1973, Section 15.2, Loss-of-Coolant Accident
Safety Evaluation Report concerning NUREG-0737 Action item il.B.2, " Shielding
Moaifications for Vital Area Access", transmitted by USNRC letter to Mr. J. M. Pilant,
Director - Licensing & Quality Assurance, NPPD, dated March 11,1983
Safety Evaluation Report concerning "BWR Owner's Group - Emergency Procedure
Guidelines, Revision 4," NEDO-31331, March 1987, dated September 12,1988
Calculations:
Calculation NEDC 87-153, Standby Liquid Control System Control Capability, Revision 0,
October 5,1987
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Calculation NEDC 87167, Standby Liquid Control System Operating Pressure with Two
4
Pump Operation, Revision 1, November 3,1988
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Calculation NEDC 89-2165, Permissible CRD System Bypass Leakage for a Design Basis
j
LOCA, Revision O. February 15,1990
4
.
Calculation NEDC 89-2166, Justification for Surveillance Test Low Pressure Value llor
'
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CRD system check valves CRD-CV-25CV and 26CV), Rev'ision 0, February 15,1990
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Calculation NEDC 90-384, NBI LITS-101 A,B,C,D Level 3 Setpoint, Revision 2,
February 25,1992
3
Calculation NEDC 91-147, ECCS and SLC Success Criteria During an Isolation ATWS,
1
Revision 0, October 11,1991
'
Calculation NEDC 92-015, Standby Liquid Control Pump Net Positive Suction Head,
Revision 0, August 15,1994
j
Calculation NEDC 92-020, NBi-LIS 101 A,B,C,D Level 8 Setpoint, Revision 1, January 3,
1994
Calculation NEDC 92-050AG,"PC-PS-12A/B/C/D and PC-PS-119A/B/C/D Setpoints,"
Revision 1, July 1,1994
Calculation NEDC 92-0501, Reactor Vessel High Pressure Scram Setpoint Calculation for
NBl-PS-55A (B, C, D), Revision 1, September 20,1994
Calculation NEDC 93-142, SLC Storage Tank Setpoints and Concentration Requirements,
Revision 0, August 2,1993
Procedures:
Alarm Procedure 2.3.2.28, Panel 9-5-2, Window F-8, "SLC Tank Hi/ Low Level,"
Revision 26, March 15,1996
Chemistry Procedure 8.3, " Control Parameters and Limits," Revision 15.1, May 13,1996,
Emergency Operating Procedure 5.8, " Emergency Operating Procedures," sheet 6A,
" Reactor Power (Failure to scram),"
Emergency Operating Procedure 5.8.8, " Alternate Boron Injection and Preparation"
Engineering Procedure 3.3, " Station Safety Evaluations"
Engineering Procedure 3.26.3," Instrument Setpoint and Channel Error Calculation
Methodology"
5
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Maintenance Procedure 7.2.55.2,"HCU scram Valve Operator Diaphragm Replacement,"
Revision 2
Standard Operating Procedure 2.2.69.2, "RHR System Shutdown Operations"
Surveillance Procedure 6.SLC.101, "SLC Pump Operability Test," Revision 2, August 16,
1996, performed September 1,1996
Surveillance Procedure 6.1RPS.304,RPS High Reactor Pressure Calibration and Functional
Test (Div.1)
Surveillance Procedure 6.SLC.601, "SLC Tank Sampling," Revision 0, November 17,1995
Drawings:
G.E. Drawing 729E430, Standby Liquid Control Tank, Revision N01, October 25,1988
)
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G.E. Drawing 791E262, Sheet 1
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3
G.E. Drawing 791E263, Sheet 1, PCIS Elementary Diagram
G.E. Drawing 791E266, Sheet 12, RWCU Elementary Diagram
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G.E. Drawing 945E632, Sheets 1-9, ARl/ATWS Recirculation Pump Trip
P&lD 2045, Sheet 2, Revision N14, Standby Liquid Control System, January 11,1996
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Union Pump Company Drawing P-C274826,7, Standby Liquid Control Pump
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Drawings IL-E-70-3 Sheets 15 and 16, Revision 1, (October 20,1994-illegible)
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Chicago Bridge & Iron Co. Drawings 68-2211, Sheet 38, Revision 4, Jan0ary 19,1995
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and Sheet 43, Revision 5 January 19,1995
Modifications:
Modification DC 74 031, Voltage Transient Suppression
Modification DC 86-34A, SLC/ATWS Modifications
Modification DC 89-124, Lower Reactor Water Level 3 Setpoint & Instrument Recalibration
Modification DC 89-285/285A,CRD Testable Check Valve Assembly.
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Modification DC 90-001, RCIC Alternate Boron injection
Modification DC 91-088, Main Steam Line Rad Monitor scram & Group 1 Functien Removal
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Equipment Spec Change ESC 88-004, HFA Relay Upgrade
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Problem Identification Reports:
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PIR 2-02529 to document that limited scope Review of RHR and HPCI systems n USAR'
Revealed several errors
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PIR 2-04963 - inaccurate vendor drift calculation
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PIR 2-07763 - to address the extent of misuse of seismic qualification data
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PIR 2-05041 - to investigate the methodology used to place the cables, determine the
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extent of the condition and to provide appropriate corrective action
PIR 2 07309- to perform operability assessment of potential ADS accumulator sizing
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nonconservatisms
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PlR 2-07812- to perform operability assessment of potential MSIV accumulator sizing
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nonconservatisms
PIR 2-07827- to perform operability assessment of potential diesel generator fuel oil
requirement discrepancies
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PIR 2-08308 - nuts on CRD actuator mounting brackets found installed but not tight
Condition Reports:
Condition Report 1-14476- to investigate and repair loose CRD actuator mounting
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brackets
Condition Report 95-1450 to investigate work which was not done during repair of loose
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CRD actuator mounting brackets
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Design Criteria Document Open item Data Forms
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DG 285 Possible Diesel Generato'r Fuel Oil Requirement Discrepancies
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IA-OO1 Possible ADS Accumulator Sizing Calc Nonconservatisms
IA-OO9 Possible MSIV Accumulator Sizing Calc Nonconservatisms
Miscellaneous:
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License Change Request 94-0126, USAR update for Surveillance Program Review
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Resolution Form Report CRD-14-94
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IE Information Notice 86-48, inadequate Testing of Boron Solution Concentration in the
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Standby Liquid Control System, dated June 13,1986
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GE Licensing Topical Report NEDE-31096-P, December,1985, Anticipated Transients
Without Scram, Response to NRC ATWS Rule,10CFR50.62
MWR 95-4519 to repair loose CRD actuator mounting brackets
1967 version of ANSI B31.1
RPS DCD Validation Checklist LLa-7, Validation, p. lll-2, items 1F,1G, et al (typ)
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NUMARC 90-012, Design Basis Program Guidelinee, October 1990
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Cooper Nuclear Station Quality Assurance Program for Operation
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Quality Assurance Audit 96-06, Setpoint Trending and Control & associated Condition
Report 96-0290 Resolution
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