ML20151X441
| ML20151X441 | |
| Person / Time | |
|---|---|
| Site: | Fort Saint Vrain  |
| Issue date: | 08/11/1988 |
| From: | Farrell R, Mullikin R, Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20151X423 | List: |
| References | |
| 50-267-88-13, IEB-84-02, IEB-84-2, IEB-88-001, IEB-88-003, IEB-88-1, IEB-88-3, NUDOCS 8808250358 | |
| Download: ML20151X441 (14) | |
See also: IR 05000267/1988013
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-267/88-13
Operating License:
Docket:
50-267
Licensee:
Public Service Company of Colorado (PSC)
2420 West 26th Avenue, Suite 15c
Denver, Colorado
80211
Facility Name: Fcrt St. Vrain Nuclear Generating Station (FSV)
Inspection At:
FSV Nuclear Generating Station, Platteville, Colorado
Inspection Conducted: June 1-30, 1988
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Inspectors:
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R. E. Farrell, Senior Resident Inspector
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R. P. Mullikin, Project Engineer, Project
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Section B
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Approved:
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T. F. Westerman, Chief, Project Section B
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8808250358 080819
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Inspection Sumary
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-Inspection Conducted June 1-30, 1988 (Report 50-267/88-13)
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Areas Inspected: ' Routine,-unannounced inspection of followup of licensee
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action on NRC bulletins, operational safety; verification, followup of
allegations, equipment qualification temperature profile, monthly maintenance
observation, monthly surveillance observation, radiological protection, and
monthly ' security observation.
Results: Within the eight areas inspected, one violation was identified (no
procedure for a safety-related activity, paragraph 5; and an inadequate
, procedure for surveillance activities, paragraph 8)
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DETAILS
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1.
Persons Contacted
D. Alps, Supervisor, Security
- H. Brey, Manager, Nuclear Licensing and Resources
- M. Block, System Engineering Manager
- R. Craun, Nuclear Engineering Manager
- M. Deniston, Superintendent, Operations
- D. Evans, Operations Manager
- M. Ferris, QA Operations Manager
- C. Fuller, Manager, h.alear Production
J. Gramling, Supervisor Nuclear Licensing Operations
- D. Goss, Regulatory Affeirs Manager.
- M. Holmes, Nuclear Licensing Manager
- F. Novachek, Nuclear Support Manager
- H. O'Hagan, Outage Manager
- R. Sargent, Assistant to Vice President, Nuclear Operations
- L. Scott, QA Services Manager
- N. Snyder, Maintenance Manager
- P. Tomlinson, Manager, Qt
R. Walker, Chairman of the Board and CEO
- D. Warembourg, Manager, Nuclear Engineering
- S. Wilford, Program Manager, Training Consolidation
- R. Williams Jr., Vice President, Nt. clear Operations
The NRC inspectors also contacted other licensee and contractor personnel
during the inspection.
- Denotes those attending the exit interview conducted July 5, 1988.
2.
Plant Status
This inspection period covering the month of June 1988, was the most
electrically' productive month in the history of the plant. At 8 p.m., MDT,
cn June 29, the plant set a new 1-month generation record of 160,000 net
megawatt hours. The plant continued to operate at approximately
80 percent power through the rest of the month, finishing with a net
generation for the month of June of 167,699 megawatt hours.
High oxidants
in the reactor coolant in excess of the LCO 4.2.10 limit continued to be a
problem. The NRC resident inspectors followed the licensee's actions to
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correct this ptoblem, which were unsuccessful.
3.
Followup of Licensee Action on NRC Bulletir.s (Module 92703)
(Closed) NRC Bulletin 88-01: Defects in Westinghouse Circuit Breakers -
NRC Bulletin 88-01 requested licensees to perform and document inspections
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on Westinghouse Series DS circuit breaker'.; used in Class 1E service. The
licensee identified in Letter P-88112, that no circuit breakers subject to
the requirements of this bulletin are utilized at FSV. This item is
closed.
(Closed)hRCBulletin88-03:
Inadequate Latch Engagement in HFA
Latching Relays Manufactured by General Electric (GE) Company:-l_Typ_e
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licensee documented to the NRC in letter P-88198 that no relays subject to
NRC Bulletin 88-03 are utilized in safety-related applications at FSV.
This is the same response as to NRC Bulletin 84-02, which also dealt with
GE latching relays. This matter is closed.
No violations or deviations were identified in the review of this program
aree.
4.
Operational Safety Verification (Module 71707)
The NRC resident inspectors reviewed licensee activities to asccrtain that
the facility is being o)erated safely and in conformance with regulatory
requirements and that t w licensee's management control system is
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effectively discharging its responsibilities for continued safe operation.
Tie NRC resident inspectors toured the control room on a daily basis
during normal working hours and at least twice weekly during backshift
hours. The reactor operator and shift supervisor logs and Technical
Specification compliance logs were reviewed daily.
The NRC resident
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inspectors observed proper control room staffing at all times and verified
that operators were attentive and adhered to approved procedures.
Control
room instrumentation was observed by the NRC resident inspectors and the
operebility of the plant protective system and nuclear instrumentation
system were verified by the NRC resident inspectors on each control room
tour. Operator awareness and understanding of abnormal or alarm
conditions was verified. The NRC resident inspectors reviewed the
operations order book, operations deviation report (0DR) log, clearance
log, and temporary configuration report (TCR) log to note any
out-of-service safety-related systems and to verify compliance with
Technical Specification requirements.
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The licensee's Panager of Nuclear Production, 03erations Manager, and
Superintendent of. 0peretions weie observed in tie control room on a daily
basis, with the superintendent of operations frequently in the control
room during the day and during tpecial evolutions.
The NRC resident inspectors verified the operability of a safety-related
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system on a weekly basis. The helium purification system, prestresscd
concrete reactor vessel (PCRV) auxiliary piping system, reserve shutdown
system, and DC essential power distribution system were verified operable
by the NRC resident inspectors during this report period. During plant
tours particular attention was paid to components of these systems to
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verify valve positions, power supplies, and instrumentation were correct
for current plant conditions. General plant condition and housekeeping
was improved during the inspection period _
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Shift turnovers were observed at least weekly by the NRC resident
inspectors. ,The information flow was good, with the shift supervisors
routinely soliciting comments or concerns from reactor operators,
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equipment operators, and auxiliary tenders.
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During the inspection period, the limit of 10 parts per million total
oxidants in the reactor coolant from LC0 4.2.10 was exceeded. The
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licensee interprets LC0 d.2.10 to allow the integration of parts per
million above 10 with raspect to duration to amass a total grace period of
LC0 4.2.10 in terms of parts per million days of oxidants in reactor
coolant above the 10 parts per million limit. This interpretation of the
grace period as an integration is not found in the existing LC0 4.2.10.
The NRC resident inspectors discussed this interpretation with the NRR
project manager and determined that NRR had reviewed this interpretation
in the past and had concurred with the licensee that this was an
appropriate interpretation of LCO 4.2.10.
However, LCO 4.2.10 still
requires that the continuous time that oxidants in the primary coolant
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exceed 10 parts per million not be greater than 10 calendar days. The
licensee, during the inspection period, reduced power which had the effect
of reducing oxidants in the primary coolant to come within the
requirements of 10 parts per million and reset the clock on the 10 days
continuous time exceeding 10 parts per million. The licensee then
increased power and continued to track integrated part per million days
versus LC0 4.2.10 requirements.
During tours of the control room, the NRC resident inspectors determined
that no written instructions existed to preclude operation of the reactor
outside the parameters tusted in Procedure RT-500. The RT-500 test
measures reactivity fluctuations caused by movement of fuel blocks in the
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core at various primary coolant pressure drops across the core. This was
a problem early in the life of the reactor and was corrected by physical
restraints anplied to the fuel blocks.
Procedure RT-500 verifies that
these reactivity changes do not occur at various pressure drops across the
core.
The NRC resident inspectors verified that operations personnel were
aware of the maximum pressure drop across the core measured by RT-500 and
that the reactor was not to be operated above this maximum pressure drop.
The licensee issued Operations Order 88-04, which prohibited reactor
operation with a core pressure drop greater than 4.25 pounds per square
inch.
The NRC resident inspectors also had the opportunity to watch the licensee
perform an equipment manipulation with a potential for causing i ant
% backup
transient. Specifically, the licensee wac attempting to place
bearing water in service to the helium circulators while the S u was
opera ting. This is a delicate process since the monitors on @ nelium
circulator bearing cartridges sense differences in pressure between
bearing water, buffer helium, and reactor primary coolant.
If the
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pressure differences change significantly, the helium circulator would
trip causing a reduction in plant power.
If two circulators would trip in
one loop, an engineered safety feature actuation would occur that would
result in a loop shutdown, a potentially significant plant transient. A
two-loop trouble reactor scram would occur when all of the helium
circulators would trip. The licensee wished to place the backup bearing
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water system back in service because it is normally in service supplying
backup bearing water in the event normal bearing water makeup is lost.
Backup bearing water supplies bearing water makeup to the helium
circulators through pressure breakdown valves from the emergency feedwater
header. The NRC resident inspectors attended the job briefing conducted
in the control room and observed that plant engineers conducted the
br'afing and supervised the effort to place the backup bearing water on
line. There was ample communication between the control room, the
auxiliary electric room (where the engineers monitored the system
parameters and also controlled the pressure breakdown valves), and Level 2
in the reactor building where the equipment operators manually opened the
system isolation valves upon instruction and authorization from the
engineers. The NRC resident inspectors observed that the precautions and
control instituted by the licensee were appropriate for the job. All
personnel involved indicated that they understood the importance and
sensitivity of the operation they were performing. The plant did not
experience a transient during this operation.
Other observations by the NRC resident inspectors during plant tourt, are
as follows:
The oil filled viewing windows to the reactor building hot cell on
Levels 9 and 10 were both seeping oil. The accumulation was not
significant. This was brought to the licensee's attention and
corrected.
The No. 2 battery light on the diesel driven firewater pump was out.
The NRC resident inspectors notified the shift supervisor and tne
outside tender advised that the problem was simply a burned out
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indicating light. The problem was imediately corrected.
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The fire door between the auxiliary electric room on Elevation 6 of
the turbine building and the walkover to Building 10 had a defective
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latch. The licensee repaired the latch.
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The special handling document station in the helium bottle farm area
was noted as having documents in poor physical condition.
Specifically, Drawing FI-24, Issue BG had been ripped from the
drawing holder and was laying on the floor of the bottle farm area.
Drawing PI-25-3 was partially ripped from the holder. The NRC
resident inspectors noted that the drawing holder was suspended by
wire hook from the handwheel of Valve V-24105. The licensee
corrected this condition and took steps to prevent recurrence.
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A small oil leak was observed from an unknown source dripping on the
top of Valve PDV-2191-1 on Level 2 of the reactor building. The
licensee cleaned up the oil and was troubleshooting to identify and
correct the source.
On June 27, 1988, it was noted that there was no thermometer in the
plant protection system battery pilot cell.
It is the licensee
practice to leave a thermometer in the pilot cell of each battery.
The licensee advised that the thermometer had been removed for
routine checks and had since been returned to the pilot cell.
No violations or deviations were identified in the review of this program
area.
5.
Followup of Allegations
(Module 92701)
a.
Followup of Alleoation 4-87-A-0092
This allegation concerned the melting of conductor insulation while
attempting to install heat shrinkable insulation (HSI) sleeves.
HSI
sleeves are installed over splices and connectors of electrical
cables to create an environmentally qualified seal. The sleeves are
heated by a heat gun and shrunk to conform to the splice or
connector. The alleger stated that, while heating some HSI sleeves,
the insulation on the conductor melted.
The NRC it,aector interviewed licensee personnel and reviewed
documentation which resulted in the following information.
During the installation of Raychem HSI sleeves in 1985 and 1986
the licensee used heat guns capable of reaching 1000'F.
In
addition, the procedure used stated that the Raychem sleeve was
adequately shrunk when the outer surface was smooth and glossy.
The licensee stated that the problem was as a result of the
craft's and QC's interpretation of "smooth and glossy."
In
order to obtain the "smooth and glossy" acceptance criteria, the
heat gun was sometimes applied for too long a time which did
result in some conductor insulation melting. However, each
Raychem installation was QC inspected and nonconformance reports
were written against melted insulation.
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The applicable installation procedures were subsequently
changed, according to instructions from Raychem, to clarify the
acceptance criteria. These criteria are:
(1) apparent
conformance to substrate, (2) no flat surfaces on tubing,
(3) visible flow of adhesive at each end of tubing, and
(4) "possible" glossy appearance.
In addition, the 1000*F heat
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guns were replaced with 700*F heat guns with deflector shields.
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In response to IE Information Notice 86-53, "Improper
Installation of Heat Shrinkable Tubing," the licensee issued
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CorrectiveActionRequest(CAR)86-140onSeptember 18, 1986, to
-Raychem sleeve, percent reinspection of all Raychem installations.
perform a 100
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splices and a few other applications at FSV.
TheNRCinspectorreviewedCAR86-140andtwoNCRs(EQ-0026and-
EQ-0127) that were initiated during the original installation of
Raychem sleeves.
in addition, a field inspection was performed by
the NRC inspector to verify that the dispositions of the two'NCRs
reviewed were correct and that no conductor insulation damage
existed. There were no problems noted during this review and
inspection.
This allegation was substantiated, but it appears tt.at, with two
100 percent QC inspecticas c' .sil Raychem installations, all melted
insulation has been identified and corrected. This allegation is
closed.
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b.
Followup of Allegation 4-88-A-0036
This allegation concerned the adequacy of the safety-related station
batteries. The allegation consisted of three parts which are
addressed below.
(1) No Automatic Action or Proceduralized Instructions to Shed Some
DC Loads.
The NRC inspector determined that. according to Design
Criteria DC-92-1, there are some DC loads that are required to
be removed from the DC safety-related battery bus after a
specified amount of time following loss of all AC power. After
discussions ~with licensee personnel it was acknowledged that
there was no automatic action that would shed these loads nor
was there any proceduralized instructions to do so. The
licensee stated that this requirement will be proceduralized.
The licensee, in the interim, has issued Special Instruction To
Operators No. 85-15, Issue 4 dated June 23, 1988, to alert
operators of the need to shed certain DC loads after a specified
amount of time following a turbine trip with a loss of offsite
power. However, there is a discrepancy between DC-92-1 and
No. 85-15 as to the time when Computer Inverter N-9234 should be
removed from the DC bus.
The failure to establish proper procedural controls for DC load
shedding as described above is considered a violation of
Technical Specification 7.4.a (267/8813-01).
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In addition, the NRC inspector will review the licensee's
determination of the safety impact of removing these loads. The
safety impact of removing these loads is an open item
(267/8813-02).
This part of the allegation was substantiated.
(2) No Analysis Which Includes Cable Losses in Determining Minimum
Required DC Voltage at the Individual Loads
This allegation was that, although batteries are tested to
maintain a minimum voltage of 105 VOC, cable losses to the DC
loads are not analyzed when determining minimum voltage at the
loads.
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The licensee stated that this was true. However, the licensee
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further stated that the voltage losses due to the resistance of
the cables was negligible for the length and size of cables
used. Thisisanopenitem(267/8813-03) pending a review of
the cable losses by the NRC inspector.
This part of the allegation was substantiated.
(3) Batteries are not Tested Against a Load Profile as Degraded
Cells are Replaced
The NRC inspector detennined that the licensee does not have a
commitment to perform a capacity or a service test on the
batteries when a cell is replaced.
IEEE 450-1980 recomends
that a cell should be tested prior to installation. The
licensee has proceduralized and performs the testing of new
battery cells under Procedure MPE-1705, "Removal, Cleaning, and
Installation of Battery Cells."
This part of the allegation could not be substantiated since no
requirement exists for the licensee to perform a load profile
test when new cells are replaced.
This allegation is considered closed. Certain parts were substantiated
and will be followed up as open items. One part was substantiated and is
an apparent violation of NRC regulations.
6.
Equipment Qualification Temperature Profile (Module 37998)
During the inspection period, the licensee notified the NRC resident
inspectors, the NRR licensing project manager, and NRC Region IV that they
had received a letter from their reactor vendor identifying that the
vendor had revised the computer code used to calculate post-pipe break
temperature profiles within the plant and had obtained new results which
indicated higher long-term temperatures following certain kinds of
postulated pipe breaks within the plant. The NRC resident inspectors
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reviewed the licensee action and noted that the licensee was pursuing
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para.lel avenues in an attempt to expeditiously close the matter and
determine the validity of the vendor's new computer calculations.
The
licensee has, with permission from the NRC, contracted with the NRC
vendor, who performed the confirmatory calculations for the NRC during the
original equipment qualification program, to run comparative calculations
to those run by the licensee's reactor vendor. Additionally, the licensee
is reviewing the changes made to the computer program by the reactor
vendor and has also contracted with an architect engineer to run parallel
calculations using that firm's in-house equipment qualification
temperature profile computer code. The licensee advised the NRC SRI that
should the reactor vendor's higher temperature calculations be validated,
37 equipment qualification binders representing 398 components would be
adversely affected. Additionally, 14 components qualified by thermal lag
analysis may be affected and there is a potential adverse impact on the
qualification of all in-plant cable.
This activity will be followed by
the NRC resident inspectors and is considered an open item (267/8813-04).
7.
Monthly Maintenance Observation (Module 62703)
During the inspectior period, a li-inch valve (PV-21105-1) in the helium
circulator backup bearing water system developed a through body leak and
was cut out of the line for replacement.
It was noted by the licensee
that the body nole was due to erosion.
Additionally, upstream and
downstream piping for several inches from the valve also displayed the
effects of severe erosion.
The NRC resident inspectors interviewed the
licensee's maintenance manager regarding actions taken to determine the
cause of the erosion and identify additional areas of erosion or possible
erosion. The licensee's maintenance department documented in Action
Recuest 2197, dated June 14, 1988, that significant erosion in the valve
anc inlet and outlet piping had occurred and that engineering was
requested to determine the cause and identify other potential locations
where this might be taking place.
The licensee subsequently reported to the NRC SRI that the valve erosion
that was experienced in PV-21105-1, and its associated inlet and outlet
piping, was due to the high velocity of flow in this valve and the use of
this valve as a pressure breakdown valve. The licensee is planning to
replace this valve with a valve specifically designed for pressure
breakdown service. Additionally, the licensee is evaluating replacing the
inlet and outlet piping, which has a li-inch diameter with 3-inch piping
to reduce the erosion problem. The licensee noted that this same piping
had been replaced in 1981 due to severe erosion. The licensee's
engineering department did an evaluation of other piping locations in the
plant with similar configurations and determined that the conditions
experienced by this valve and this piping were unique. The licensee
concluded that there were no other similar areas of concern in the plant.
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.The quarterly maintenance on Instrument Air Compressor C was observed.
The NRC resident inspectors reviewed Station Service
Request (SSR) 88503257 and the associated Control Work Instruction
Procedure MAP-7, "Gardner-Denver Instrument Air Compressors, Quarterly."
No violations or deviations were identified in the review of this program
a rea.
8.
Monthly Surveillance Observation (Module 61726)
During the inspection period, the NRC resident inspectors observed
performance of the following surveillances:
SR-5.1.8, Minimum Helium Flow / Maximum Core Region Temperature Rise
Surveillance Requirement
SR-5.6.1.a. Weekly Emergency Diesel Generator Load Test
SR-5.2.20, ACM Diesel Driven Generator Surveillance (Weekly and
Monthly)
SR-4.1.1. A.1.a. X-High Motor Temperature Partial Scram
The NRC resident inspectors also observed the sampling and analyses of
primary coolant to determine compliance or extent of noncompliance within
the limits of LCO 4.2.10, which governs the amount of oxidants allowable
in primary coolant. The % resident inspectors also reviewed licensee
calculations and method of calculations for determining compliance with
LC0 4.2.7.c, 4.2.7.d. and 4.2.9.
These LCOs govern the pressurization and
leak rate of pressurizing helium gas from PCRV penetration interspaces.
The space (referred to as the interspace) in between the primary and
secondary closurn seals of each PCRV penetration is pressurized with
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purified helium.
The leak rate from each penetration is used as a measure
of the operability of its seals.
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On June 21, 1988, the licensee, in performing Procedure SR-5.2.16.a-Q,
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Issue 34 "PCRV Closure Leakage Determination," determined that the
Group 4 penetrations (Loop 2 steam generator penetrations) leakage rate
exceeded the rate specified in LC0 4.2.9.
The maximum allowable leakage
rate for the Group 4 penetrations is a total of 700 pounds per day at a
differential pressure of 10 pounds per square inch with respect to cold
reheat steam pressure or 400 pounds per day at a differential pressure of
10 pounds per square inch with respect to cold reheat stcom if there is no
leakage between the interspace and the reheat steam pipe. The licensee
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determined by performing the above surveillance that the Group 4
penetration leakage was 736.09 pounds per day at 10 pounds-per-square-inch
differential pressure with respect to cold reheat steam.
This measurement
was performed with the reactor at 80 percent power.
Subsequently, the licensee lowered reactor power to see if the leakage
rate was affected. The leakage rate, on the evening of June 21, was
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determined to be 626.8 pounds per day at 10 pounds-per-square-inch
differential pressure with respect to cold reheat steam when the reactor
varies directly with reactor power.)(NOTE:
power was lowered to 73.5 percent.
Cold reheat steam pressure
The lowering of reactor power, and
thus the lowering of the required pressure inside the penetration
interspace to maintain a 10 pound-per-square-inch different'al with
respect to cold reheat steam, would affect the leakage rau out of the
secondary seal into the reactor building but not necessarily affect the
leakage rate into reheat steam. Without an established leakage rate into
reheat steam the limit on this penetration is 400 pounds per day of helium
at 10 pounds-per-square-inch differential with respect to cold reheat.
On June 22,'1988, in an attempt to'show that the leak rate from the
Group 4 penetrations was indeed acceptable, the licensee utilized the
methodology, but not the actual calculctions of Procedure SR-RE-151-X,
Issue 2. "Penetration Interspace Leakage Pressure Decay Test." The
methodology of this procedure is to pressurize a penetration ir.terspace,
seal the flow to and from the interspace, and measure and time the
pressure decay from the interspace.
From this information, a leak rate in
terms of pounds per day at a given pressure as specified in the Technical
Specifications is calculated. The licensee utilized this methodology but
did not use the actual procedure because the licensee had identified a
problem in the calculation instructions contained within the procedure.
This problem, which the NRC resident inspectors understood to be a label
of incorrect units, did not affect the numbers provided to the NRC because
this problem was identified prior to uti.lzing the procedure. Utilizing
this methodology and installed plant equipment, Pressuro Gauge TDT-11380,
which measures the differential pressure between the cold reheat steam and
the penetration interspace, the licensee obtained a leak rate of
384 pounds per day at a differential pressure of 10 pounds-per-square-inch
with respect to cold rueat steam. Later, utilizing this same methodology
but installing a more finely calibrated pressure gauge measuring absolute
ressure rather than pressure with respect to another variable pressure
p(Cold Reheat Steam), the licensee obtained a number of 308.5 pounds per
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day helium leakage rate at '10 pounds-per-square-inch differential pressure
with respect to cold reheat steam from the Group 4 penetrations. This
leak rate corresponds with the measured purified helium makeup flow to
these penetrations.
The NRC resident inspectors, having been provided with four different leak
rates in the course of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, requested that the licensee review the
calculations, the calculational methods, and the equipment used.
The NRC
inspectors also requested an explanation as to the actual leak rate from
the Group 4 penetrations and the calculations that demonstrated Technical
Specification compliance.
During the course of this review, the licensee
identified a problem with Procedure SR-5.2.16.a-Q, Issue 34, in that the
procedure assumed that Group 4 penetrations were pressurized to above
primary coolant pressure rather than to above cold reheat steam pressure,
(Step 5.3.12 of the procedure). Cold reheat steam pressure varies with
plant load but will be at least 50 pounds per square inch below primary
coolant pressure,
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The NRC resident inspectors noted that Procedure SR-5.2.16.a-Q, Issue 34,
had six existing deviation reports against it with each change marked as a
permanent changt. None of these changes or previous issues of the
procedure identified or incorporated a change to the Technical
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Specifications a) proved on March 18, 1982. The error in the procedure
calculates a lea ( rate in the conservative direction, since it shows a
worse leak rate by calculation than actually existed. However, the
conservatism was such that the licensee erroneously placed the plant in
Technical Specification Limiting Conditions for Operation 6.2.9 which
would have required shutting down the plant.
This information was also
supplied to the NRC and was the subject of a conference call between the
licensee, NRR, and Region IV.
This error in the procedure, which has apparently existed undetected for
6 years, is considered a violation of Technical Specifications
(267/8813-01).
9.
Radiological Protection (Module 71709)
The NRC resident inspectors verified that required area surveys of
exposure. rates were made and posted at entrances to radiation areas and in
other appropriate areas. The NRC resident inspectors observed health
physics professionals on duty on all shifts including the backshift. The
NRC resident inspectors observed the health physics technicians checking
area radiation monitors, air samplers, and doing area surveys for
radioactive contanination.
The NRC resident inspectors observed that when workers are required to
enter areas where radiation exposure is probable or contamination
possible, the health physics technicians are present and available to
provide assistance.
No violations or deviations were identified in the review of this program
area.
10. Monthly Security Observation (Module 71881)
The NRC resident inspectors verified that there was a lead security
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officer (LS0) on duty authorized by the facility security plan to direct
security activities onsite for each shift. The LSO did not have duties
that would interfere with the direction of security activities.
The NRC resident inspectors verified. randely and on the backshift, that
the minimum number of amed guards required by the facility's security
plan were present.
Search equipment, including the X-ray machine, metal
detector, and explosive detector, were operational or a 100 percent hands
on search was being utilized.
The protected area barrier was surveyed by the NRC resident inspectors.
The barrier was properly maintained and was not compromised by erosion,
openings in the fence fabric or walls, proximity of vehicles, or crates or
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other objects that could be used to scale the barrier. The NRC resident
inspectors observed the vital area barriers were well maintained and not
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,
compromised by obvious breaches or weaknesses. The NRC resident
inspectors observed that persons granted access to the site were badged
indicating whether they had unescorted or escorted access authorization.
- Two items of note regarding the physical security program at FSV occurred
during this inspection. The first security matter of interest during the
inspection period involved backshift obserystion by the NRC SRI.
Specifically, on June 23, 1988, at 11:30 p.m. MOT, while performing a deep
backshift inspection, the NRC SRI visited the secondary alarm station a a
routine part of his inspection. While in the secondary alarm station. the
SRI was able to observe activities in the search / identification portion of
the primary access facility without his presence being detected by those
in the search / identification area.
At this time, the NRC SRI observed a
security officer placing parts of his body into the package X-ray machine.
The machine was then turned on by a second security officer, thus,
X-raying the first officer. These activ.ities were brought to the
attention of the licensee's security supervisor by the NRC SRI. The
licensee took extensive and thorough corrective action and made this
corrective action known to the entire security force in an attempt to
preclude recurrence. The NRC SRI observing the licensee's corrective
action concluded that it was timely and thorough.
On this same shift continuing into the morning of June 24, 1988, the NRC
SRI observed the same security crew demonstrate high quality performance.
This crew of security officers searching a truck making a delivery to the
plant in the middle of the night did successfully discover and prevent a
loaded hand gun from entering the plant. The gun was concealed within the
tractor of a tractor-trailer making the delivery.
No violations or deviations were identified in the review of this program
area.
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11.
Exit Meeting
An exit meeting was conducted on July 5, 1983, attended by those
identified in paragraph 1.
At this time the NRC resident inspectors
reviewed the scope and findings of the inspection.
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