ML20195D078
| ML20195D078 | |
| Person / Time | |
|---|---|
| Site: | Fort Saint Vrain  |
| Issue date: | 05/22/1986 |
| From: | Farrell R, Jaudon J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20195D075 | List: |
| References | |
| 50-267-86-16, NUDOCS 8606020088 | |
| Download: ML20195D078 (5) | |
See also: IR 05000267/1986016
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APPENDIX
U.S. NUCLEAR REGULATORY C0fittISSION
REGION IV
NRC Inspection Report:
50-267/86-16
License: DPR-34
Docket: 50-267
Licensee: Public Service Company of Colorado (PSC)
P. O. Box 840
Denver, Colorado 80201
Facility Name:
Fort St. Vrain Nuclear Generating Station
!
Inspection At:
Fort St. Vrain Nuclear (FSV) Generating Station, Platteville,
Inspection Conducted: May 6-9, 1986
Inspector-
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. {. F[rrell, Senior Resid t Inspector (SRI)
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Approved:
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'Date
Geapor
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Inspection Sunnary
Inspection Conducted May 6-9, 1986 (Report 50-267/86-16)
Areas Inspected: Special, unanr.ounced inspection of operation in excess of
duthorized power limit.
Results: Within the areas inspected, one violation was identified
(paragraph 2).
8606020088 860523
ADOCK 05000267
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2
DETAILS
1.
Persons Contacted
Principal Licensee Employees
- H. Brey, Manager, Nuclear Licensing and Fuels
- M. Deniston, Shift Supervisor
- D. Evans, Superintendent Operations
- J. Gahm, Manager Nuclear Production
- D. Rodgers, Planning & Scheduling Manager
- J. McLotter, Lawyer, Kelly, Stansfield, and O'Donnell
- R. Walker, President and Chief Executive Officer
NRC/NRR Personnel
- F. Allenspach, Reactor Systems Engineer
- R. Farrell, Senior Resident Inspector
- J. Gagliardo, Chief, Reactor Projects Branch
- R. Ireland, Chief, Engineering Section
- J. Jaudon, Chief, Reactor Projects Section A
- E. Johnson, Director, Division Reactor Safety Project
- D. Powers, Enforcement Officer
- M. Skow, Project Engineer
The SRI also contacted other licensee and contractor personnel during
the inspection.
- Denotes those in attendance during the Enforcement Conference held in
Arlington, Texas on May 9,1986.
2.
Operation in Excess of Authorized Power Limit
At 1009 MDT, on May 6, 1986, the NRC SRI was contacted by FSV operations
management and informed that there had been a small perturbation with the
reactor.
The SRI was infornied that based on preliminary information then
available, the reactor power level had " drifted" above 35% power to a
possible maximum of 40% power. The SRI, was additionally told, that the
time above 35% power was approximately 10 minutes. The following is a
narrative description of the actual event as determined from plant
personnel interviewed, computer printouts, recorded plant parameters, and
inspection of control room strip chart recorders.
At 0820 MDT, on May 6,1986, the reactor was in steady-state operation
with the following parameters:
core power = 34.7%
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generator output = 90 megawatts electric
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core outlet temperature = 1207 F
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reactor pressure = 618 psia
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reactor coolant flow = 47%
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reactor coolant dewpoint = -42.6 F
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,
The licensee had been experiencing a hydraulic fluid leak on a
hydraulically operated steam isolation valve. The valve was on a main
steam bypass line which is used in startup, prior to admitting steam to
the high pressure turbine. With the turbine on line, this valve is
normally closed, and main steam follows its normal flow path through the
high pressure turbine. With the valve open, steam is bypassed to the
desuperheater and the flash tank and hence to the cold reheat steam line
without passing through the high pressure turbine. Cold heat steam drives
the circulators and then is reheated in the steam generator. A decision
had been made to remove hydraulic oil pressure from this valve and to
repair the hydraulic fluid leak, utilizing a downstream pressure control
valve as the steam isolation valve because the licensee anticipated that
the isolation valve could drift open when hydraulic fluid pressure was
removed.
The pressure control valve in the main steam by-pass line was closed and
hydraulic fluid pressure to the isolation valve in this line was removed
to facilitate repair of the hydraulic fluid leak.
Following removal of
hydraulic fluid pressure from the main steam by-pass isolation valve, the
control room noted a step increase in feed water flow. Concurrenuy, the
control room received a Delta Temperature Alann between reactor Loop I and
reactor Loop II. That is, the steam coming from the steam generator for
one loop was at a temperature different than that from the other steam
generator. A shift supervisor who was acting as operations superintendent
Wds in the control room and directed the reactor operators to increase
helium circulator speed on the loop with the lower temperature to equalize
the steam outlet temperatures of the two steam generators. This increased
helium flow to the core, increasing heat removal from the core and raising
core power. At this point, the reactor was already above its authorized
power level of 35%, and operator actions taken were tending to increase
power level even further. The reactor was in the remote automatic control
mode, in which all control systems follow main turbine steam demand.
Following the step increase in feedwater flow, turbine generator power
increased, the center control rod (regulating rod) stepped out to mr *
turbine demand, and reactor power increased peaking between 42.6%
43.3% reactor power at approximately 0840 MDT.
The shift supervisoi
(acting operations superintendent) in the control room made the decision
to bring the plant down below its authorized power level of 35% in a " slow
controlled manner," rather than by scram of the reactor or by shifting the
control mode to local automatic to reduce power rapidly.
When the reactor operators noticed the turbine generator output had
increased from 90 megawatts electric to approximately 108 megawatts
electric, the shift supervisor directed them to reduce turbine generator
load demand in an attempt to reduce reactor power to within the authorized
operating limit of 35%. As the reactor operators reduced turbine
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generator demand, the regulating rod inserted, but reactor power continued
to increase as did feed water flow. The negative thermal coefficient of
reactivity inherent in the reactor core served to increase reactor power
as feedwater flow increased, and additional heat was removed from the
Core.
Control room personnel who were analyzing the event to determine why
feedwater flow and reactor power did not follow turbine generator demand,
identified the work on the main steam by-pass line valves as the apparent
cause. At this time maintenance was contacted, and hydraulic oil pressure
was restored to the main steam by-pass line isolation valve, causing that
valve to close. Reactor power dropped as did feedwater flow to correspond
to the power demanded by the turbine generator. At 0915 MDT, reactor
power was again below the authorized limit of 35%.
With the reactor in remote automatic control, the control loops in the
plant regulate equipment to match turbine generator load demand, taking
the signal from the high pressure turbine throttle pressure. When the
hydraulic pressure was removed from the main steam by-pass line isolation
valve, that valve partially opened, passing high pressure steam to the
by-pass line. The pressure control valve in the main steam by-pass line
was being relied upon to function as an isolation valve, even though it is
not designed to provide such service; this pressure control valve either
leaked or was not completely seated, and it passed high pressure steam.
The steam flow through the by-pass line reduced turbine throttle pressure
causing the control systems to demand more steam and power from the
reactor. Additionally, the steam passing through the flash tank and into
the reheat lines, increased reheat steam flow. Since a reheat steam flow
signal is utilized to control feed water flow, an increase in reheat steam
flow caused an increase in feed water flow. Consequently, the feedwater
system was getting an increase flow, signal from the turbine generator
control system, which was sensing an inadequate turbine throttle pressure
and was getting an increase feed water flow signal from reheat steam flow.
At the same time the turbine generator control system was demanding more
feedwater flow, it caused the regulating rod to withdraw, increasing
reactor power to match the turbine generator load demand. The increase in
feedwater flow cooled the reactor core and caused an increase in reactor
power due to the negative thermal coefficient of reactivity.
4
The effect of the negative thermal coefficient of reactivity held reactor
power above 35% even as turbine generator load demand was reduced by the
reactor operators.
Reactor power returned to authorized levels when the
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flow through the main steam by-pass line was terminated, and the turbine
generator remote automatic controls were again sensing all of the steam
flow provided from the reactor.
The licensee, while operating at 34.7% reactor power with an authorized
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reactor power limit of 35%, chose to do maintenance on a velve which had
the potential for effecting reactor power level. While doing this work,
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the licensee relied upon a pressure control valve, not designed as an
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isolation valve, to perform an isolation function. The pressure control
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valve utilized as an isolation valve was not tested for isolation
capability prior to relying upon it for isolation. When the first alarm,
the Delta T un main steam alarm, was received, the reactor operators were
directed to take action which increased reactor power in order to clear
the alarm.
The reactor was operated at power levels in excess of the authorized power
level from 0830 MDT, May 6,1986, to 0915 MDT, May 6,1986. Although
there was no apparent intention to exceed the authorized power level, the
licensee did choose to do maintenance on a valve which had the potential
to affect reactor power level without reducing reactor power level to
provide a margin of error in the event power level did increase.
Additionally, the licensee relied upon an untested valve to perform a
function for which it was not designed. When the licensee realized that
the reactor was not operating within the authorized power limit, the first
actions caused reactor power level to increase further. Additionally, the
licensee chose to remain at an unauthorized power level for 45-minutes
rather than manually scramming the reactor or quickly reducing reactor
power, risking an automatic scram.
Operating the reactor at power levels above 35% is an apparent violation
of the NRC Order of November 26, 1985, authorizing operation of the FSV
reactor at power levels not to exceed 35% (50-267/8616-01).
3.
Enforcement Conference
An Enforcement Conference was conducted on May 9, 1986, at the NRC Region
IV offices in Arlington, Texas. At that time, the events of May 6, were
reviewed and potential actions to prevent reoccurrence were discussed.
The meeting was attended by those indicated in paragraph 1.