ML20134E378
| ML20134E378 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 01/30/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20134E364 | List: |
| References | |
| 50-333-96-08, 50-333-96-8, NUDOCS 9702060188 | |
| Download: ML20134E378 (25) | |
See also: IR 05000333/1996008
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U.S. NUCLEAR REGULATORY COMMISSION
Region I
License No.: DPR-59
Report No.:
96-08
Docket No.:
50-333
Licensee:
New York Power Authority
Post Office Box 41
Scriba, New York 13093
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Facility Name:
James A. FitzPatrick Nuclear Power Plant
Dates:
November 17,1996 through January 4,1997
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inspectors:
G. Hunegs, Senior Resident inspector
R. Fernandes, Resident inspector
R. Skokowski, Resident inspector
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D. Dempsey, Reactor Engineer
Approved by:
Curtic J. Cowgill Ill, Chief
Projects Branch 2
Division of Reactor Projects
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EXECUTIVE SUMMARY
James A. FitzPatrick Nuclear Power Plant
NRC Inspection Report 50-333/96-08
Ooerations
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The reactor startup following the refueling outage was performed in a safe and
prudent manner. The post refueling outage startup training was well presented and
comprehensive,
Operators demonstrated conservative decision making by directing a manual scram
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to be inserted when an electro-hydraulic control (EHC) system leak was identified on
a turbine bypass valve. In addition, operators demonstrated excellent control of the
plant transient.
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Auxiliary operators performed watchstanding duties in an acceptable mmer. Good
radiological control practices were observed and operators demonstrated
attentiveness by identifying and documenting rninor equipment deficiencies. Minor
logkeeping discrepancies as well as some equipment storage discrepancies were
noted and were addressed by operations management.
o
An unresolved item (URI 50-333/95021-01) involving extended operation of all four
residual heat removal system pumps in the suppression pool cooling mode was
closed. Failure to perform a safety evaluation prior to performing this evolution
resulted in a violation of 10 CFR 50.59. (VIO 50-333/96008-01)
Maintenance
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The approach to maintenance activities on the bypass valves was not rigorous and
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contributed to bypass valve hydraulic actuator seal failures and in one case resulted
in a manual reactor scram to be required. The licensee's equipment failure
evaluation was thorough and corrective actions well developed to address
maintenance practices for the bypass valves.
Personnel error by technicians during surveillance testing on reactor water level
instrumentation resulted in automatic reactor protection and primary containment
isolation actuation. Since the plant was shutdown at the time of the event, there
was no effect on plant operation. The inspector noted that this event contained
similarities with the September 16,1996, scram described in NRC inspection report
50-333/96-06 in that technicians proceeded with work without fully recognizing the
potential to cause a plant transient. The condition [a valve packing leakl was not
reported to supervision; thus the decision to proceed with the packing adjustment
was not challenged.
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Configuration control for reinstallation of tubing for the HPCI governor hydraulic
control system was lost during maintenance when tags used to label components
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Executive Summary (cont'd)
became illegible. Although efforts were made to regain configuration control for the
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tubing, the licensee failed to ensure that installation was proper. The problem was
identified during HPCI post work testing.
Enaineerina
Primary containment leakage rate testing was well conducted by the
operations staff. The program was properly implemented and the as-left
testing data met the requireinents for plant start-up following the refueling
outage.
The equipment failure evaluation for the local leak rate testing (LLRT) failures
was comprehensive with appropriate corrective actions completed or planned
for completion. The licensee's decision to replace several poor performing
valves was warranted based on the testing history. The LLRT results over
the past several refueling cycles have shown continuous improvement in the
number of as found failures. However, since the as-found totalleakage rate
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based on Type B and C LLRT results was greater than the technical
specification (TS) limits, a violation of NRC requirements occurred. This
violation will not be cited in accordance with Section Vll.B.1 of the NRC
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Enforcement Manual as the violation was non-recurring, promptly corrected
and of low safety significance (50-333/96008-02).
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Plant Suocort
There were several radiological control barriers and radiation worker practices which
were not adhered to by two workers which resulted in one worker becoming
contaminated. These requirements which were not met included the failure to
obtain a radiation control brief, not adhering to the radiation work permit, wearing
inadequate anti-contamination clothing, disregarding radiological posting
requirements and improper use of the portal monitor. The results were that an
individual became contaminated and the potential existed for the spread of
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contamination. The issue is unresolved item (URI 50-333/96008-03).
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TABLE OF CONTENTS
E X EC UTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TA B LE O F C O NT E NT S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
Sum m a ry of Plant Statu s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. O p e ra ti o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Cond uct of Operation s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 R e a cto r St a rt u p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.2 Manual Reactor Scram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
O2
Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 2
O2.1 Engineered Safety Feature System Walkdowns
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Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 3
04.1 Observations of Auxiliary Operator Watchstanding . . . . . . . . . . . 3
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Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
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05.1 Post refueling outage (RFO) startup training . . . . . . . . . . . . . . . . 4
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Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
08.1 (Closed) LER 5 0-3 3 3 /9 6007 . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
08.2 (Closed) Unresolved item 50-333/95021-01
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11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
M1
Conduct of Maintenance
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M 1.1 General Comments
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M1.2 General Comments on Surveillance Activities . . . . . . . . . . . . . . . 6
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M1.3 Conclusions on Conduct of Maintenance . . . . . . . . . . . . . . . . . . 6
M2
Maintenance and Material Condition of Facilities and Equipment
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M2.1 Turbine Bypass Valve Actuator Seal Leak
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M4
Maintenance Staff Knowledge and Performance . . . . . . . . . .
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M4.1 Reactor Protection System Actuation Error Caused By
Personnel Error
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M4.2 High Pressure Coolant injection incorrect Tubing Installation . . . . 8
111. Engineering
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Conduct of Engineering
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E1.1
Primary Containment Leakage Rate Testing Program . . . . . . . . . . 9
E1.2 (Closed) LER 96-012, Primary Containment Leakage Exceeding
Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
IV. Plant Support . . . . . . . . . . . . . . . .
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R1
Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 12
R1.1
Personnel Contam' nation Identified at the Security Building
Radiation Monitor
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Table of Contents (cont'd)
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V. Ma nagement Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
X1
Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
X2
Review of UFS AR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
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ATTACHMENT
Attachment 1 - TlA Regarding Design Basis Functionality of FitzPatrick RHR System When
Operated in the Suppression Pool Cooling Mode (TAC No. M94319)
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Report Details
Summarv of Plant Status
The unit began this inspection period in cold shutdown with the refueling outage in
progress. The control rod drive change out was completed on November 19 the core was
reloaded on November 27 and reactor vessel pressure testing was completed on December
3. On December 6, the licensee implemented technical specification amendment No. 239.
This amendment increased the steady state reactor core power levellimit from 2436 to
2536 megawatts (thermal). The licensee had to complete several actions as conditions for
the approval of this power uprate license amendment. These actions included monitoring
the recirculation pump motor vibrations during initial power ascension, performance of a
startup test program and incorporation of any potential effects of operation at an increased
power level into operator training.
On December 7, at 10:28 p.m., a reactor startup was commenced and the reactor was
critical on December 8 at 12:36 a.m. On December 15, operators identified an electro-
hydraulic control (EHC) system leak from the turbine bypass valve (BPV) actuator seal and
manually scrammed the reactor from 36% reactor power. Following repairs to the BPV,
the reactor was restarted and was critical on December 18. At the end of the inspection
period, the reactor was at 96% power and power uprate testing was in progress.
l. Operations
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Conduct of Operations'
01.1 Reactor Startuo
a.
Inspection Scope
The inspectors observed portions of the reactor startup conducted on December 7,
1996, inspector attention was focused on reactivity control, operator procedure
use and communications.
b.
Observations and Findings
The startup was characterized by clear operator communications and procedure use,
attentive management oversight, and effective control by shift supervision. Shift
turnover meetings were performed in a controlled manner and crew briefings were
good. Senior operations management personnel were designated to provide
continuous oversight. Training was conducted for operations personnel to cover
operating parameter changes which had been made as a result of the power uprate.
' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized
reactor inspection report outline. Individual reports are not expected to address all outline
topics.
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c.
Conclusions
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The reactor startup following the refueling outage was performed in a safe and
prudent manner.
01.2 Manual Reactor Scram
a.
Inspection Scoce
On December 15, at 1:00 a.m., operators inserted a manual reactor scram following
the identification of an electro-hydraulic control (EHC) fluid leak from the number
four turbine bypass valve. The inspectors reviewed the post transient evaluation
including logs and operator actions. The plant operating review committee (PORC)
which was conducted to review the event was also observed. In addition, the
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inspectors verified that the action commitment tracking system (ACTS) items which
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were generated from the event were appropriately addressed.
b.
Observations and Findinas
On December 15, an operator was performing turbine building rounds and identified
one to two gallon per minute (GPM) electro-hydraulic control (EHC) system leak
from the turbine bypass valve (BPV) actuator seal. Based on the system engineer's
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recommendation and the potential for the leak to increase substantially and possibly
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lose EHC pressure control, shift management determined that insertion of a manual scram was a prudent course of action. Control room operators were briefed and
stationed at a.5 signed panels and a manual scram was inserted from 36% reactor
power. All required actions occurred and plant response to the transient was
normal. Operators stabilized reactor pressure and level and commenced a normal
reactor cooldown. The EHC leak was stopped by securing the operating EHC pump.
c.
Conclusions
Operators demonstrated conservative decision making by directing a manual scram
to be inserted when an EHC leak was ideritified, in addition, operators
demonstrated excellent control of the plant transient.
O2
Operational Status of Facilities and Equipment
O2.1 Enaineered Safetv Feature System Walkdowns
The inspectors performed a walk down of accessible portions of the following
systems and performed general area tours:
oresidual heat removal service water system
oprimary containment
salternate decay heat removal system
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Equipment operability and material condition were good. Housekeeping conditions
were acceptable. Some outage related equipment was not stored prior to plant
operation. For example, some small tools and tubing were found unattended and
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severalladders in both the reactor and turbine buildings were not secured. The
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licensee addressed these issues.
04
Operator Knowledge and Performance
04.1 Observations of Auxiliary Operator Watchstandina
a.
Scope
The inspectors observed auxiliary operators (AOs) during reactor and turbine
building watchstanding. The inspectors assessed the performance of the AOs, and
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the material and housekeeping conditions of the plant. Additionally, the inspectors
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reviewed applicable site procedures, and held discussions with operations
department personnel, including AOs, shift managers, and the operations
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department manager.
b.
Observations and Findinas
The inspectors observed AOs on the December 11,1996, day shift rounds of the
reactor building, and the December 12 day shift rounds of the turbine building. The
rounds were completed in accordance with Operations Department Standing Order
(ODSO) 17, " Auxiliary Operator Plant Tours and Operating Logs," Revision 59. The
AOs demonstrated good radiological controls practices in the performance of their
duties. The inspector identified some minor logkeeping discrepancies which were
appropriately addressed by operations management. The inspector noted that AOs
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identified some minor equipment deficiencies and appropriately documented the
deficiencies using the Problem Identification (PID) process. The operators wiped up
small amounts of oil under several components including the condensate booster
pumps, the rer.ctor recirculation system (RCS) pump motor generator (MG) sets and
the hydrogen seal oil pumps.
c.
Conclusions
The AOs performed watchstanding duties in an acceptable manner. Good
radiological control practices were observed and operators demonstrated
attentiveness by identifying and documenting minor equipment deficiencies. Minor
logkeeping discrepancies were noted and were addressed by operations
management.
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Operator Training and Qualification
05.1 Post refuelina outaae (RFO) startuo trainina
a. Inspection Scope
Post refueling outage (RFO) startup training was conducted 'o cover the power
uprate technical specification amendment. The inspector observed portions of
power uprate training and discussed the content of training with the Operations
manager.
b. Observations and Findinas
Training included power uprate training, operating experience, changes in plant
system parameters, operations management expectations and an overview of
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special uprate test procedures including sequence of testing. The inspector noted
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good participation from operators that were attending the training.
c. Conclusions
The post refueling outage startup training was well presented and comprehensive.
08
Miscellaneous Operations issues
08.1 (Closed) LER 50-333/96007 Engineered Safety Feature Activation Due to False
High Radiation isolation Signal. On May 22,1996, the reactor building ventilation
exhaust radiation monitor spiked. Automatic actions including reactor building
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ventilation system isolation, standby gas treatment system initiation, and closure of
primary containment atmosphere sample system isolation valves occurred as
required. The redundant ventilation radiation monitor showed no change in radiation
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levels.
Subsequent trouble; Joting determined that the Geiger-Muller type radiation
detector had failed
nich generated the signal spike. The detector was replaced
and the system re
ned to operation.
Operator response to the ESF actuation was appropriate.
08.2 (Closed) Unresolved item 50-333/95021-01: Operation of all residual heat removal
(RHR) pumps in the suppression pool cooling mode for extended periods of time.
On November 7,1995, the licensee operated all four RHR pumps for ten hours in
the suppression pool cooling mode. The operation wm conducted in response to
NRC Bulletin 95-02, " Unexpected Clogging of a Resic.ual Heat Removal Pump
Strainer While Operating in Suppression Pool Cooling Mode," using normal operating
procedures. The licensee did not perform a safety evaluation pursuant to 10 CFR 50.59, " Changes, tests, and experiments," prior to performing the evolution.
Subsequently, the licensee determined that a safety evaluation had not been
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required, but, nonetheless, completed a formal evaluation to ensure that no safety
inues had been overlooked.
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Due to the potential for water hammer should a design-basis accident occur while
both RHR trains are aligned for suppression pool cooling, NRC Region I referred the
issue to the NRC Office of Nuclear Reactor Regulation (NRR) for evaluation. In a
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memorandum dated October 30,1996 (attached to this report), the NRC concluded
that infrequent operation of both RHR trains in the suppression pool cooling mode,
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such as on November 7,1995, was not an unreviewed safety question. However,
frequent, long-term operation of the RHR system either in the suppression pool
cooling or test modes would constitute an unreviewed safety question (per 10 CFR 50.59) due to the increased likelihood of a malfunction due to a water hammer
event. The inspector concluded that the licensee's failure to perform a safety
evaluation prior to operating both trains of the RHR system in the suppression pool
cooling mode on November 7,1995, was a violation of 10 CFR 50.59. (VIO 50-
333/96008-01)
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11. Maintenance
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M1
Conduct of Maintenance
M1.1 General Comments
a.
Insoection Scope
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The inspectors observed all or portions of the following work activities:
eWR 96-06652-01 Inspect condenser thermowells for cracks and determine the
extent of identified crack
eWR 96-06703-04 Post modification testing of off-gas system check valve for the
steam packing exhauster drip pot drain line
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eWR 95-08324
Perform inspection of scram discharge header isolation valve
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disk in accordance with maintenance procedure
b.
Observations and Findinas
The inspectors found the work performed under these activities to be professional
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and thorough. All work observed was performed with the work package present
and in active use. Technicians were experienced and knowledgeable of their
assigned task. The inspectors frequently observed supervisors and system
engineers monitoring job progress, and quality control personnel were present when
required. - When applicable, appropriate radiation control measures were in place.
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M1.2 General Comments on Surveillance Activities
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a.
Inspection Scoce
The inspectors observed selected surveillance tests to determine whether approved
procedures were in use, details were adequate, test instrumentation was properly
calibrated and used, technical specifications were satisfied, testing was performed
by knowledgeable personnel, and test results satisfied acceptance criteria or were
properly dispositioned.
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The inspectors observed portions of the following surveillance activities:
- ST 20K
control rod withdrawal checks
- ST 39Q
drywell inspection
- ST 4N
high pressure coolant injection (HPCI)
- ST 24Q
reactor core isolation cooling (RCIC) turbine slow roll and overspeed
test
- ST 4K
HPCI turbine slow roll and overspeed test
- TST 55
feedwater level control power uprate startup test
- TST 56
feedwater level control power uprate startup test
b.
Observations and Findinas
The licensee conducted the above surveillance activities appropriately end in
accordance with procedural and administrative requirements. Good coordination
and communication were observed during performance of the surveillance.
M1.3 Conclusions on Conduct of Maintenance
Overall, maintenance and surveillance activities were well conducted, with good
adherence to both administrative and maintenance procedures.
M2
Maintenance and Material Condition of Facilities and Equipment
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M 2.1 Turbine Bvoass Valve Actuator Seal Leak
a.
Inspection Scope
On December '.'5, the number four turbine bypass valve actuator seal was observed
to be leaking at a rote of one to two gallons per minute. Operators inserted a
manual reactor scram to address the hydraulic oilleak.[see section 01.2] The
inspectors reviewed the equipment failure evaluation, reviewed material history and
discussed the seal failure with the maintenance engineer.
b.
Observations and Findinas
The piston, piston rod and rod seal for the number four turbine bypass valve had
recently been replaced during the refueling outage. The seal package consists of a
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lip seal which is the primary pressure retaining device, a backup seal which
supports the primary seal and a wiper seal which prevents external contamination
from the seal area. It appears that the primary seal was damaged during
installation. The damage to the primary seal provided a leakage path for the high
pressure fluid (approximately 1600 psig) to leak past the seal. This caused
pressurization of the wiper seal which is not designed to retain pressure.
On November 24, the number one bypass valve hydraulic actuator piston seal failed
and approximately 50 gallons of EHC fluid leaked from the system. The EHC
system had been restored to operation following preventive and corrective
maintenance activities. The piston seal had been replaced earlier in the outage.
The licensee performed equipment failure evaluations for the seal failures which
included a review of their maintenance practices. In the case of the number one
seal failure, the piston stem had some coating degradation which caused the seal to
wear during operation. The number one seal had exhibited excessive oscillation
during the plant shutdown for the refueling outage and the licensee elected to
replace the seal but did not inspect the piston stem, in the case of the number four
seal, a small burr on the piston damaged the seal during installation. There is a
starting sleeve to facilitate seal replacement which was not used because the
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licensee was not aware of the availability of the tool.
The licensee developed corrective actions to improve maintenance practices
associated with seal replacement.
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c.
Conclusions
The approach to maintenance activities on the bypass valves was not rigorous and
contributed to bypass valve hydraulic actuator seal failures and, in one case,
resulted in the need to insert a manual reactor scram. The licensee's equipment
failure evaluation was thorough and corrective actions well developed to address
maintenance practices for the bypass valves.
M4
Maintenance Staff Knowledge and Performance
M4.1 Reactor Protection System Actuation Error Caused By Personnel Error
a.
Inspection Scope
The inspector reviewed Licensee Event Report (LER)96-013, Reactor Protection and
Primary Containment isolation System Actuation on False Low Reactor Water Level
Due to Personnel Error, and various procedures associated with the event and
discussed the issue with licensee personnel.
b.
Observations and Findinas
On November 16,1996, an automatic reactor protection and primary containment
isolation system actuation occurred on a f alse low reactor water level signal.
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During surveillance testing of reactor water level instrumentation, technicians noted
and attempted to correct an instrument isolation valve stem packing leak which
caused a pressure transient in the level sensing lines and resulted in the instruments
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sensing a false low reactor water level. Systems which were in service
automatically isolated and there was no negative effect on the plant.
The licensee determined that the technician attempted to tighten the valve stem
packing nut while holding the valve handwheel. When the packing nut was turned,
a reactor scram signal and primary containment isolation signal occurred. It appears
that when the packing nut was turned, the technician slightly opened the isolation
valve which resulted in a pressure decrease in the reactor water level variable leg
sensing lines.
The licensee determined that the event was caused by personnel error. The
procedure, IMP-G17, " Whitey Valve Packing Adjustments", which had been
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developed to adjust packing was not used nor was supervision informed of the
packing leak. Use of the procedure would have resulted in a different system
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configuration which would essentially isolate the valve being worked on from the
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system.
c.
Conclusions
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Personnel error by technicians during surveillance testing on reactor water level
instrumentation resulted in automatic reactor protection and primary containment
isolation actuation. Since the plant was shutdown at the time of the event, there
was no effect on plant operation. The inspector noted that this event contained
similarities with the September 16,1996 scram described in NRC inspection report
50-333/96-06 in that technicians proceeded with work without fully recognizing the
potential to cause a plant transient. The condition la valve packing leak] was not
reported to supervision and the decision to proceed with the packing adjustment
was not challenged.
Based on this review, LER 50-333/96-013 is closed.
M4.2 Hiah Pressure Coolant Iniection incorrect Tubina Installation
a.
Insoection Scope
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On December 9,1996, the high pressure coolant injection (HPCI) turbine would
not roll during ST 4K, HPCI Turbine Slow Roll and overspeed Test, conducted at
150 PSIG reactor pressure. The surveillance test was conducted, in part, as post
work testing. The licensee identified that tubing connecting ports on the governor
hydraulic control system was installed incorrectly. The inspector reviewed the
maintenance procedure, the deviation and event report (DER) response and
discussed the event with the system engineer, in addition, the inspector observed
the performance enhancement review committee (PERC) meeting during which the
personnel error was discussed.
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b.
Observations and Findinas
During maintenance performed on the HPCl turbine, all piping was identified in
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accordance with MP 23.14, Turbine Maintenance. However, the method used to
identify components was to use duct tape and a magic marker. The identification
subsequently became illegible. The tubing was reassembled using the procedure
and the tubing was walked down by the system engineer to verify correct
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installation. Due to the configuration, the walkdown verification failed to identify
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that the tubing was installed incorrectly. The problem was subsequently identified
during post work testing.
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As part of their corrective actions, the licensee initiated ACTS items to provide
better labels for the tubing and connection ports and provided additional
maintenance procedure enhancements.
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c.
Conclusions
Configuration control for reinstallation of tubing for the HPCI governor hydraulic
control system was lost during maintenance when tags used to label components
became illegible. Although efforts were made to regain configuration control for the
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tubing, the licensee failed to ensure that installation was proper. The problem was
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identified during HPCI post work testing.
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E1
Conduct of Engineering
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E1.1
Primarv Containment Leakaae Rate Testina Proaram
a.
Insoection Scone
The licensee submitted and received approval for Technical Specification
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Amendment No. 234 last cycle which allowed the licensee to implement
10 CFR Part 50, Appendix J, Option B, " Performance Based Containment Leakage
Testing", during the refueling outage. The licensee's program is based on Nuclear
Energy Industry NEl 94-01, "Inductry Guidelines For Implementing Performance
Based Option of 10 CFR Part 50, Appendix J, Revision 0, dated July 26,1995.
This document is endorsed by the NRC, with certain industry wide exceptions, in
USNRC Regulatory Guide 1.163. The technical methods utilized by the licensee for
performing Type A, B, and C test are contained in ANSl/ANS-56.8-1994,
Containment System Leakage Testing Requirements. The actual implementation of
the program is conducted in accordance with the licensee's surveillance testing
program. The inspector observed testing, reviewed the program plan and the
results of the localleak rate testing conducted during the refueling outage.
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10
b.
Observations and Findinas
The inspector observed the LLRT performed on penetration X7A in
accordance with ST-398-X7A, Type C Leak Test Main Steam Line A MSIVs.
The test was conducted by a group of auxiliary operators and supervised by
a senior reactor operator. During the outage, testing was conducted on both
shifts with oversight and coordination of the testing being directed from the
work control center. The inspector noted that the operators were
knowledgeable and experienced with the test equipment, procedures were in
use and good communications were noted between operators in the field.
The inspector reviewed the Primary Containment Leakage Rate Testing
Program against the requirements and noted the following:
The licensee's Primary Containment Leakage Rate Testing Program
,
was consistent with 10 CFR 50 Appendix J, Regulatory Guide 1.163
,
and NEl-94-01 Revision O.
Regulatory Guide 1.163, Performance-Based Leak Rate Test Program,
requires that if the test interval for the Type A test is being extended
for 10 years, then at least two refueling outages have to include a
visual examination of accessible portions of the containment. The
licensee completed two consecutive Type A test successfully and is
extending the interval; however a visual examination was not
j
performed as a part of the recent outage. The licensee has developed
and assigned an ACTS item to write a procedure to perform this for
the next outage. The next Type A test is due March 7,2005.
The program allows for reduced testing on good performing valves
and increased test frequency for the poor performers. The inspector
reviewed ST-39B, Type B and C LLRT of Containment Penetrations,
and the licensee's Appendix J Option B Test Program Baseline
j
Evaluation and concluded that all the penetrations which required
LLRT were performed during the last outage or where within current
testing periodicity.
The inspector reviewed the test data and calculations for the as left
minimum and maximum pathway penetration leakage rate and
concluded the calculations were correct. The requirement is for both
values to be less than 63.182 standard liters per minute (SLM). The
minimum pathway was determined to be 16.6764 SLM and the
maximum was 31.9627 SLM.
The inspector reviewed the test data and calculations for the total as
found minimum pathway leakage rate and concluded that the
calculations were correct. The total as found minimum pathway was
determined to be 311 SLM, exceeding the limit of 63.182 SLM. This
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was reported to the NRC in accordance with 10 CFR 50.73 in
Licensee Event Report LER-96-012 and is discussed in section E.1.2.
c.
Conclusions
1
The inspector concluded that the testing was well conducted by the
1
operations staff and the as-left testing data met the requirements for plant
start-up following the refueling outage. The inspector determined that the
Primary Containment Leakage Rate Testing Program was in accordance with
the regulatory requirements and being properly implemented,
j
E1.2 (Closed) LER 96-012. Primary Containment Leakaae Exceedina Technical
Soecifications
a.
insoection Scope
j
On November 11,1996, the licensee determined that the as found running total
primary containment leakage rate was in excess of the TS limit of 105.3 SLM and
reported the event in accordance with 10 CFR 50.72. The licensee determined the
as-found running totalleakage rate to be 122 SLM. At the conclusion of the as-
found minimum pathway localleak rate testing conducted during the refueling
outage, the licensee determined the total as found minimum pathway to be 311
SLM, exceeding the limit of 63.182 SLM. The inspector reviewed the LER as part
of the primary containment leakage rate program review.
b.
Observations and Findinas
The licensee processed an equipment failure evaluation (EFE) for each of the LLRT
failures which discusses the causes and corrective actions for each of the failures.
Five of the eight main steam isolation valves (MSIVs) failed to pass testing. The
EFE concluded that this was attributed to normal wear occurring during the closing
stroke of the valve. The licensee utilized a separate vendor supplied valve team
with special tooling to repair the valves. All valves passed the subsequent retests.
The mean time between failures of the MSIVs is about 5 years. The MSIVs are
required to be tested every two years. The corrective actions appear to be
adequate with respect to the MSIV failures.
Three valve failures were Anchor Darling double disk gate valves, which the
licensee determined to be a poor design for steam applications. All three valves
were reworked and subsequently passed the retesting. The EFE resulted in the
generation of problem identification entries (PlDs) to track the replacement of two of
the valves. The inspector noted that the mean time between failures for these
valves was approximately a cycle, in discussion with the licensee's engineering
staff, the inspector learned that the valves were replaced several cycles ago and
albeit the valves have a long history of LLRT failures, the more recent failures are
attributed to the design of the replacement valves. The inspector concluded that
the corrective actions for these valves were adequate.
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One feedwater system non-return valve,34 NRV-111B also has a history of
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LLRT failures while its matching valve, 34 NRB-111 A ht : very good LLRT
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history. The licensee attributed this to a disc to seat misalignment during
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manufacture of the valve. The valve was repaired and subsequently retested
satisfactorily. The long term corrective action for this valve included a PID to
replace the valve or have a field service repair team correct the misalignment
problem. The inspector concluded that the corrective actions were
adequate. The remainder of the failures were attributed to normal wear,
system particle accumulation, and corrosior products.
c.
Conclusions
The inspector concluded that the EFEs for the LLRT faiiures were
comprehensive with appropriate corrective actions completed or planned for
completion. The licensee's decision to replace several poor performing
valves was warranted based on the testing history. The LLRT results over
,
the past several refueling cycles have shown improvement in the number of
as found failures. However, since the as-found running total leakage rate,
based on Type Band C LLRT results was greater than the TS limit, a violation
l
of NRC requirements occurred. This violation will not be cited in accordance
with Section Vll.B.1 of the NRC Enforcement Manual as the violation was
non-recurring, prompt:y corrected and of low safety significance (50-
333/9608-02). Licensee event report LER-96-012, is closed.
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IV. Plant Support
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R1
Radiological Protection and Chemistry (RP&C) Controls
R 1.1 Personnel Contamination Identified at the Security Buildina Radiation Monitor
a.
Insoection Scope
On December 7, a non-licersed operator leaving to go home was identified as
contaminated at the security building radiation monitor. The inspector reviewed the
licensee's followup corrective actions including surveys, portal monitor testing, and
discussed the event with licensee management. Additionally, radiological control
procedures pertinent to the event were reviewed.
b.
Observations and Findinas
On December 7, a non-licensed operator leaving to go home was identified as
contaminated at the security building radiation monitor. A health physics technician
escorted the individual back to the radiation protection office and performed a
whole body count and decontaminated the worker's face and hands. The workers
clothing, including shoes, socks, trousers and outer coat were contaminated up to
12,000 cpm and removed. Following decontamination activities, the worker was
allowed to go home. The worker's egress route was surveyed and no
contamination was found. Additional subsequent surveys identified some
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paperwork located in the control room that the operator had been in contact with
had some detectable contamination, but was less than release limits.
4
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The licensee's review showed that, during the week of December 1, various repairs
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were being performed on condensate demineralizer valves located in a contaminated
,
area in the turbine building. On December 7, the operators involved were tasked
j
with clearing a protective tagging request (PTR) associated with the system. The
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first operator did not obtain the required radiation protection briefing prior to-
4'
entering the contaminated area. A second operator entered the area without a brief
because he believed that the shift meeting brief covered the activity and the first
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operator had informed him that the required anti-contamination clothing was booties
f
and gloves. NRC and NYPA review of the event is continuing; this is unreso!ved
item (URI 50-333/96008-03) pending additional review.
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c.
Conclusions
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A radiation worker had performed some tasks in a contaminated area and had
!
improperly exited the radiologically controlled area. In addition, the radiation
workers involved did not take proper radiological precautions while performing
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work.
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t
There were several radiological controls barriers and radiation worker practices
which were not adhered to by the workers involved. These requirements included
the failure to obtain a radiation control brief, not adhering to the radiation work
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permit, wearing inadequate anti-contamination clothing, disregarding radiological
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posting requirements and improper use of the portal monitor. The results were that
'
an individual became contaminated and the potential existed for the spread of
contamination.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of the licensee management at
{
the conc usion of the inspection on January 14,1997. The licensee acknowledged the
>
findings presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
X2
Review of UFSAR Commitments
A recent discovery of a licensee operating their facility in a manner contrary to the Updated
Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused
review that compares plant practices, procedures and/or parameters to the UFSAR
description. While performing the inspections discussed in this report, the inspector
reviewed the applicable portions of the UFSAR that related to the areas inspected. The
inspector verified that the UFSAR wording was consistent with the observed plant
practices, procedure and/or parameters.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. Colomb, Plant Manager
R. Locy, Operations Manager
D. Ruddy, Director, Design Engineering
J. Maurer, General Manager, Support Services
NB.G
C. Cowgill, Chief, Projects Branch 2
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INSPECTION PROCEDURES USED
37550
Engineering
37551
Onsite Engineering
62703
Mrintenance Observations
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61726
Surveillance Observations
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71707
Plant Operations
,
71750
Plant Support
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92903
Followup - Engineering
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ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
,
50-333/96008-01
failure to perform a 50.59 safety evaluation
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50-333/96008-02
NCV primary containment leakage exceeding technical specifications
,
50-333/96008-03
improper radiation worker practices by a non-licensed operator
Closed
50-333/96008-02
NCV primary containment leakage exceeding technical specifications
!
50-333/96007
LER
Engineered Safety Feature Activation Due to False High
Radiation Isolation Signal.
50-333/96012
LER
Primary Containment Leakage in Excess of TS Limits
50-333/96013
LER
Reactor Protection and Primary Containment isolation System
Actuation on False Low Reactor Water Level Due to Personnel
Error
50-333/95021-01
residual heat removal pump operation
Discussed
None
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LIST OF ACRONYMS USED
As Low As Reasonably Achievable
American Society of Mechanical Engineers
Boiling Water Reactor
Core Damage Frequency
CFR
Code of Federal Regulations
Dry Active Waste
DP
differentia; pressure
dpm
disintegrations per minute
Engineered Safety Feature
,
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FR
Federal Register
Feedwater Level Control System
,
Hydraulic Control Unit
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High Pressure Coolant injection
IFl
Inspection Followup Item
i
Individual Plant Evaluation
IR
Inspection Report
ISEG
Independent Safety Engineering Group
Inservice inspection
Inservice Testing
LER
Licensee Event Report
)
Low Specific Activity
Non-Cited Violation
NRC
Nuclear Regulatory Commission
Occupational Safety and Health Administration
PEP
Performance Enhancement Program
)
ppm
parts per million
Probabilistic Safety Assessment
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psig
pounds per square inch gage
Quality Assurance
Quality Control
Radiological Controlled Area
Reactor Core Isolation Cooling
Radiation Protection
RP&C
Radiological Protection and Chemistry
Reactor Water Clean-Up
Radiation Work Permit
SCO
Surface Contaminated Objects
TS
Technical Specification
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Unusual Event
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Updated Final Safety Analysis Report
I
Violation
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ATTACHMENT 1
r.t
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UNITED STATES
g
j
NUCLEAR REGULATORY COMMISSION
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f
WASHINGTON, D.C. 20555 @ 01
% , j ,o
October 30, 1996
MEMORANDUM T0:
Curtis Cowgill
Division of Reactor Projects, Region I
FROM:
S. Singh Bajwa, Acting DirectorgAy4/p 7//M
.
Project Directorate I-l
Division of Reactor Projects - I/II
Office of Nuclear Reactor Regulation
SUBJECT:
TIA REGARDING DESIGN BASIS FUNCTIONALITY OF FITZPATRICK RHR
SYSTEM WHEN OPERATED IN THE SUPPRESSION POOL COOLING MODE
(TAC N0. M94319)
By letter dated December 12, 1995, the Region raise / concerns regarding water
hammer issues and extended operation of the residual heat removal (RHR) system
in the Suppression Pool Cooling (SPC) mode.
The memorandum in particular
stated a position that the regional staff considers that operation of the RHR
system in secondary modes of operation for extended periods of time without
consideration of the inherent susceptibility to water hammer is unacceptable.
NRR is in agreement with the Region's position. We consider that frequent
long-term operation of RHR in the SPC mode constitutes an unreviewed safety
question (USQ).
For example, when operating in the SPC mode, the RHR system
is more likely to undergo a water hammer event should there be a loss of
station power. Hence, the probability of a water hammer event is increased in
direct proportion to the amount of time the system is operated in the SPC.
Furthermore, the likelihood of a malfunction of the RHR system is increased
when subjected to a water hammer event. Therefore, an increase in the
likelihood of a water hammer increases the likelihood of a malfunction of a
system important to safety. This meets the criterion for an USQ per 10 CFR 50.59(a)(2)(i).
We also believe that long-term operation of the RHR in the SPC mode
constitutes a modification to the facility which should be (and should have
been) subject to a 10 CFR 50.59 evaluation. We will recommend to the Generic
Communications Branch to send a generic letter to all the BWR licensees
stating our position.
The staff has previously evaluated the water hammer issue on a generic basis.
In Table 3-1 of NUREG-0927, BWR system water hammer causes are listed and
CONTALT:
George Thomas, SRXB/DSSA
415-1814
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the frequency of operation of RHR in the SPC mode.
Licensees typically have
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administrative controls in place to limit the use of RHR system in the SPC
mode and, thereby, reduce the potential for water hammer of the RHR system.
We believe that similar controls should be in place at FitzPatrick.
Finally, the Region provided four specific questions regarding SPC operation
at FitzPatrick, they are addressed in the attachment.
Attachment: As stated
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Response to Reaion I TIA reaardina
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Suporession Pool Coolina Mode of
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Operation at FitzPatrick
i
Q 1.
Was the operation of both RHR loops for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> on November 10, 1995,
at Fitzpatrick an unreviewed safety question (USQ)?
No.
We do not believe that an isolated instance of both RHR loops in SPC
such as the operation on November 10, 1995, constitutes an USQ. We believe
that such infrequent operation is included in the system design basis as
described in the FSAR which includes both periodic short-term operation as
well as long-term post accident operation.
Q 2.
Should RHR be considered inoparable for purposes of ECCS when run in the
SPC mode?
No.
RHR is considered operable for purposes of ECCS when run in the SPC mode
or in the test mode.
The RHR system is designed for automatic alignment to
the LPCI mode if the system is in the SPC mode or in the test mode.
The
cumulative running time must be considered in light of maintenance
specifications and pump maintenance and pump testing programs. As long as the
pump is maintained in accordance with these programs, the RHR pumps are
considered operable for purpose of ECCS.
Q 3.
Is extended use of RHR in the SPC mode (viz., one pump more than 2
hours, both loops simultaneously, or cumulative run time in excess of 100
hours annually) beyond the licensing basis?
Yes. We believe that extended use (increased frequency and long duration) of
RHR system in the SPC mode is beyond the licensing basis.
Frequent use of the
RHR system in the SPC mode changes the original design basis analysis (iOCA)
assumptions.
For example, in the original design of the RHR system, the
closing speeds of the valves in the system cooling / test lines were specified
as standard speed (12 inches / minute) and not fast closing valves such as the
LPCI injection valves.
Since the cooling / test return valves take longer to
close than the LPCI injection valves take to open, there is a potential for
the core injection flow to be diverted to the suppression pool. The ECCS
performance analysis does not include the longer closing time of the test line
vales since they are assumed to be normally closed. As the amount of time
(the time the test valves are kept open) increases, the assumption is
invalidated resulting in an unanalyzed condition.
Q 4.
Should E0Ps be reevaluated with respect to the meaning "----operate all
available torus cooling?" Should torus cooling be optimized along a
divisional basis until the need to maximize torus cooling is demonstrated?
Should a caution statement concerning the potential water-hammering a voided
system be considered?
The FitzPatrick E0P for torus cooling states the following:
" Operate all
available torus cooling, use only RHR pumps which do not have to be run
continuously in the LPCI mode for core cooling." This is in agreement with
the EPG, Rev.4 SER which states:
"The EPGs are based upon maintaining core
cooling and primary containment integrity.
In all but a few cases the EPG
Attachment
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I
emphasize core cooling.
But in a few specific situations, when a decision
between a possible loss of adequate core cooling and a loss of primary
containment integrity must be made, the EPGs preferentially choose to maintain
primary containment integrity in order to protect against the uncontrolled
release of radioactivity to the general public from a degraded core
l
condition." The LPCI mode of operation supersedes all other modes of RHR
except for scenarios where the containment integrity is in danger. This
philosophy should be taught to the operators during the training process.
Therefore, unless, it is found that the licensee's training program is
deficient with regard to emphasizing the primacy of the LPCI mode of
operation, or if the E0P fail to caution the operator in this regard, there is
,
no need to modify the E0P for torus cooling optimization along a divisional
basis.
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