ML18152A408
| ML18152A408 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 11/03/1988 |
| From: | Cantrell F, Holland W, Larry Nicholson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A409 | List: |
| References | |
| 50-280-88-36, 50-281-88-36, NUDOCS 8811150237 | |
| Download: ML18152A408 (13) | |
See also: IR 05000280/1988036
Text
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UNITED STATES_
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA ST., N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-280/88-36 and 50-281/88-36
Licensee:
Virginia Electric and Power Company
Richmond, VA
23261
Docket Nos.:
50-280 and 50-281
License Nos.: DPR-32 and DPR-37
Facility Name:
Surry 1 and 2
Inspection Conducted:
September 4 - October 1, 1988
Inspectors: ~~~
L.
W. ?.Roiianc( Senior Res~.$nspector
~~~
/:,_
L. E. Nicholson, Residen~nsp"ector
Accompanying Personnel:
M.A. Scott (September 6-9, 1988)
Approved by:F: S. ~~ion
2A
D1v1s1on of Reactor ProJects
SUMMARY
11/3/ii
Da te1s igned
Scope:
This routine resident inspection was conducted onsite in the areas of
plant operations, piant maintenance, plant surveillance, and review
of TI 2515/98.
Resuits:
No violations or deviations were identified in this inspection
report.
The following new items were identified in this inspection
report.
Licensee Identified Violation (LIV) 280/88-36-01, Failure to meet the
requirements of Technical Specification 3.0.1 during shutdown of Unit
1 on September 14, 1988 (paragrap~ 5).
Inspector Followup Item (IFI) 280/88-36-02, Followup on discrepancies
identified
0 during walkdown of Unit 1 containment spray system
(paragraph 5).
Unresolved Item (URI) 280/88-36-03; 281/88-36-01, Review of addition-
al licensee evaluation and conclusions addressing timely determina-
tion of safety system operability, and engineering/field evaluation
to determine if the use of this type fitting in safety related
systems is a generic safety problem (paragraph 6).
88111~0??7 881104.
F'DR
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.
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- -*f*. 05000:280
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
- J. Bailey, Superintendent of Operations
- 0. Benson, Station Manager
R. Bilyeu, Licensing Engineer
H. Blake, Superintendent of Site Services
- R. Blount, Sup~rintendent of Technical Services
- E. Grecheck, Assistant Station Manager
G. Miller, Licensing Coordinator, Surry
- H. Miller, Assistant Station Manager
- J. Ogren, Superintendent of Maintenance
J. Price, Site Quality Assurance Manager
- S. Sarver, Superintendent of Health Physics
- Attended exit meeting.
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and other plant personnel.
The
NRC Region II Project Engine*er for the Virginia Power plants,
M. Scott, was on site from September 6 through 9, 1988.
The NRC Region II Branch Chief for the Virginia Power plants, B. Wilson
was on site September 29 and 30, 1988.
During the visit, Mr. Wilson
toured the Unit 2 containment.
2.
Plant Status
Un it J
Unit 1 began the reporting period at power.
The unit operated at power
until September 14, at 2320 hours0.0269 days <br />0.644 hours <br />0.00384 weeks <br />8.8276e-4 months <br />, when a notification of unusual event
was declared because of the determination that both emE,rgency diesel
generators were inoperable (see paragraph 5 for details).
The unit was
shut down in accordance with normal procedures, and the reacto:* w2s
manually tripped at 0611 hours0.00707 days <br />0.17 hours <br />0.00101 weeks <br />2.324855e-4 months <br /> on September 14.
The unit was subsequently
placed in cold shutdown and remained shut down for repairs to the
emergency electrical systems and other maintenance activities at the end
of the inspection period.
Unit 2
Unit 2 began the reporting period at power.
The unit operated at power
until September 10, at 0158 hours0.00183 days <br />0.0439 hours <br />2.612434e-4 weeks <br />6.0119e-5 months <br />, when an automatic reactor trip occurred
from approximately 4 percent power.
The unit was in the process of shut-
ting down for a scheduled refueling/maintenance outage when a malfunction
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2
in the governor va 1 ve contra 1 c,rcuit resulted in a turbine trip and
subsequent reactor trip. Details of this event are discussed in paragraph
5 of this report.
The unit proceeded to cold shutdown and commenced a
scheduled refueling/maintenance -outage.
At the end of the inspection
period the unit was in day 20 of a scheduled 81 day outage.
3.
Licensee Action on Previous Enforcement Matters (92702)
No previous enforcement matters were addressed during this inspection period.
4.
Unresolved Items
Unresolved items are matters about which more information is required to
determine whether they are acceptable or may involve violations cir
deviations.
One new unresolved item with regard to additional licensee
evaluations and conclusions addressing timely determination. of safety
system operability, and engineering/field evaluation to determine if the
use of this type fitting in safety related systems is a generic safety
problem is identified in paragraph 6 of this inspection report.
5.
Plant Operations
Operational Safety Verification
(71707)
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator adherence
to approved procedures, technical specifications, and limiting conditions
for operations; examination of panels containing instrumentation and other
reactor protection system elements to determine that required channels are
operable; and review of control room operator logs, operating orders,
plant deviation reports, tagout logs, jumper logs, and tags on components
to verify comp 1 i ance wi. th approved procedures.
The inspectors conducted weekly inspections in the following areas:
verification of operability of se 1 ected emergency safety feature ( ESF)
systems by valve alignment, breaker positions, condition of equipment or
component(s), and operability of instrumentation and suppo,rt items
essential to system actuation or performance.
Plant tours were performed t.hat included observation of the following:
general plant/equipment conditions, fire protection and preventative
measures,
control
of activities in progress, radiation protection
controls, physical security controls, plant housekeeping conditions/
cleanliness, and missile hazards.
The insp~ctors routinely monitor the
temperature of the auxiliary feedwater pump discharge piping to ensure
steam binding is prevented.
The inspectors conducted biweekly inspections in the following areas:
verification review and walkdown of safety-related tagout(s) in effect;
review of sampling program (e.g., primary and secondary coolant samples,
3 '
boric acid tank samples, plant liquid and gaseous samples); observation of
control room shift turnover; review of implementation of the plant problem
identification system; verification of selected portions of containment
isolation lineup(s); and verification that notices to workers are posted
as required by 10 CFR 19.
Certain tours were conducted on backshifts or weekends.
Backs hi ft or
weekend tours were conducted on September 5, 6, 8, 10, 14, 19, 20, ~2, 23,
24, 29, and October 1.
Inspections included areas in the Units 1 and 2
cable vaults, vital battery rooms, steam safeguards areas, emergency
switchgear rooms, diesel generator rooms,
control
room,
auxiliary
building, Units 1 and 2 containments, cable penetration areas, independent
spent fuel
storage facility,
low level
intake structure, and the
safeguards valve pit and pump pit areas. Reactor coolant system (RCS) leak
rates were reviewed to ensure that detected or suspected leakage from the
system was recorded, i nvesti'gated, and evaluated; and that appropriate
actions were taken, if required.
The inspectors routinely independently
calculated RCS leak rates using the NRC Independent Measurements Leak Rate
Program (RCSLK9).
On a regular basis, radiation work permits (RWPs) were
reviewed and specific work activities were monitored to assure they were
being conducted per the RWPs.
Selected radiation protection instruments
were peri odi cal ly checked, and equipment operability and calibration
frequency were verified.
In the course of monthly activities, the inspectors included a review of
the licensee 1 s physical security program.
The performance of various
shifts of* the security force was observed in the conduct of daily
activities to include: protected and vital areas access controls;
searching of personnel, packages and vehicles; badge issuance and
retrieval; escorting of visitors; and patrols and compensatory posts.
The inspectors responded to the site and monitored activities associated
with the automatic reactor trip of Unit 2 at 0158 hours0.00183 days <br />0.0439 hours <br />2.612434e-4 weeks <br />6.0119e-5 months <br /> on September 10.
The unit was in the process of ramping down to commence a scheduled
refueling/maintenance outage when
an
automatic trip occurred from
approximately 4 percent power.
At the time of the trip, the operators
were preparing to perform a turbine overspeed test with the main generator
output breakers open and the governor valve limiters being moved in the
open direction to increase turbine pressure.
When the out direction
switch was pushed, the limiter jumped unexpectantly to approximately 21
percent, causing the governor valves to open and increase first stage
impulse pressure (Pimp).
When
Pimp increased to a value indicating
greater than 15 percent power with the generator output breakers open, a
turbine trip signal was generated tripping the main turbine.
The Pimp
signal also caused permissive P-7 to reinstate (P-7 indicates reactor
power greater than 10 percent).
An automatic reactor trip was then
initiated due to the turbine trip with P-7 reinstated.
All
systems
appeared to perform as required during the transient .
4
On September 12, 1988, the licensee reported to the NRC, in accordance
with 10 CFR 50.72, that the technical specification requirement for the
emergency service water pumps does not account for single failure during a
LOCA with a loss of off-site power with the non-accident unit on residual
heat removal. It was determined that operator action would be required to
maintain adequate intake canal level. In addition, it was determined that
the instrumentation which provides indicated canal level and isolates the
service water to the main condenser is not safety-related.
A station
deviation was initiated specifically identifying the following concerns:
INTAKE CANAL LEVEL DRAWDOWN DURING A DESIGN BASIS ACCIDENT
The design basis accident (OBA) is a loss of coolant accident in one
unit with a concurrent loss of offsite power to the station.
Technical Specification 3.14.A.4 requires two service water pumps to
be operable, with each service water pump capable of delivering
15,000 gpm.
With this scenario, and assuming failure of one of the
emergency service water pumps,
an intake canal drawdown of 21,000
gpm could be expected.
This depletion of the ultimate heat sink
would be caused primarily by the recirculation spray system consuming
approximately 36,000 gpm.
NON-SAFETY RELATED CONDENSER ISOLATION
The intake canal level inventory depends on a non-safety related trip
circuitry to measure canal level and close the circulating water
condensor inlet valves.
INADEQUATE SERVICE WATER DURING A OBA WITH THE NON-ACCIDENT UNIT ON
A LOCA coincident with a loss of off-site power with the unaffected
unit operating on residual heat removal would result in a rapid drop
of canal level inventory.
The resident inspector monitored the licensee actions and coordinated the
followup actions regarding this issue with the
NRC
Safety System
Functional Inspection (SSFI) which was conducted on the service water
system during t~is period.
Interim corrective actions included a standing
order to maintain a minimum of ~7 feet in the intake canal and maintaining
a minimum of three (3) emergency service water pumps operable .prior to
initiating RHR on either system. This item will be discussed in detail in
the SSFI inspection report (280,281/88-32).
CONTROL ROOM AND EMERGENCY SWITCHGEAR ROOM VENTILATION
On September 12, the licensee identified to the resident inspector a
concern involving the ability of the existing control room and emergency
switchgear room ventilation system to perform its intended design function
during a loss of offsite power.
This concern is attributed in part to the
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5
fact that the emergency switchgear room heat loads have increased with the
installation of new electrical equi~ment over the years.
In addition,
the licensee stated in the deviation report (SI-88-937 dated September 9,
1988) that the overall material condition of the HVAC equipment has
significantly degraded since original installation.
The region is
following this item with region-based specialists.
EMERGENCY DIESEL GENERATOR (EOG) OPERABILITY
On September 13, at approximately 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />, the licensee notified the
NRC of the results of an engineering study that concluded that the station_
emergency diese I generators would not be able to carry the expected load
of a design basis accident (OBA) with a loss of offsite power (LOOP)
occurring approximately 5 minutes later.
Surry was* originally designed
for a OBA in conjunction with a LOOP, and is equipped with individual
timers* tliat begin on an accident signal in lieu of a sequencer.
These
timers would not shed the equipment and restart sho~ld a LOOP occur after
they have timed out. Engineering Type 2 Report IR 5438/IO S408 concluded
in part that the EOG tutbocharger li~iti the amount of load the EOG can
accept in the first several minutes of operations until the exhaust gases
can provide sufficient heat to turn the turbocharger faster than* the shaft
driven gears.
The report further stated that this load limitation
requires that both the inside and outside recirculation spray pumps be
sequenced onto the diesel after the turbocharger becomes
11 hot 11
at
approximately 2-3 minutes.
The above conclusions resulted in the licensee declaring the Unit 1 EOGs
inoperable. at 2320 hours0.0269 days <br />0.644 hours <br />0.00384 weeks <br />8.8276e-4 months <br />.
Unit 1 ~as operating at 100% power with Unit 2
in cold shutdown for refueling.
The licensee declared a Notification of
Unusual Event at 2341 hours0.0271 days <br />0.65 hours <br />0.00387 weeks <br />8.907505e-4 months <br /> and commenced a rampdown of Unit 1.
The unit
was placed in hot shutdown at 0611 hours0.00707 days <br />0.17 hours <br />0.00101 weeks <br />2.324855e-4 months <br /> on September 14 and cold shutdown
at 0552 hours0.00639 days <br />0.153 hours <br />9.126984e-4 weeks <br />2.10036e-4 months <br /> on September 15.
Both units remained in cold shutdown for
the remainder of this inspection period.
Technical Specification 3.0.1 requires the unit to be placed in at least
hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, which in the above case would have been at
0520 hours0.00602 days <br />0.144 hours <br />8.597884e-4 weeks <br />1.9786e-4 months <br /> on September 14.
The unit was tripped at 0611 hours0.00707 days <br />0.17 hours <br />0.00101 weeks <br />2.324855e-4 months <br />, which
exceeded the LCD by 51 minutes.
The station superintendent of operations
offered ~he following explanation to this violation of Technical
Specifications:
The shift supervisor erroneously started the 6-hour cl oc_k to hot
shutdown at the time the unit rampdown was started, and not when the
EOGs were ~eclared inoperable. This resulted in a 21 minute error in
the actual 6-hour clock.
The unit had previously exhibited indications of a fuel failure in
addition to a sma 11 steam generator tube 1 eak.
The operators were
concerned that releasing heat to the environment through the
secondary power operated relief valves would increase the potential
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for an offsite radiological release. Based on this~ the rampdown was
slowed to allow time for startup of an auxiliary boiler to provide
vacuum for the main condensor.
Although the fuel failure and steam
generator tube leak did not violate parameters specified in technical
specifications, the licensee has decided to off-load the fuel for
inspection and plug the leaking steam generator tubes.
Station deviation report 1-88-927, dated 9/14/88, 'identified this
violation of technical specificat,on and determined that it is reportable
in accordance with 10 CFR 50.73.
The resident inspectors discussed this
it~m with station management and considers that the violation meets the
criterion 10 CFR, Part 2, Appendix C,Section V for exemption from
issuance. of a Notice of Violation.
Therefore, this violation is
identified as a LIV ( 280/88-36-01) for failure to meet the requirements
of Technical Specification 3.0.1 ..
VORTEXING RESIDUAL HEAT REMOVAL SYSTEM DURING MID-NOZZLE OPERATION
On September 19, at approximately 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />, apparent vortexing in the
Unit 2 residual heat removal
(RHR) system occurred during mid-loop
operations.
Control room operators noticed motor a~ps for 2-RH-P-18 RHR
pump oscillating and the RHR Low Flow alarm (3200 gpm) was received.
Immediate operator response included reducing RHR system flowrate to 2800
gpm, increasing charging flow into the primary plant, and securing the
draining of the 1A1 reactor coolant system loop (RCS) that was in progress
at the time.
Reduction in RHR flow allowed for immediate recovery from
the apparent vortexing condition.
The reactor vessel water level was being maintained between 12 feet 4
inches and 12 feet 5 inches (approximately 7 inches above mid-loop) as
observed by a continuous standpipe watch utilizing a television camera and
monitor.
The standpipe consists of a tygon hose attachment to
11 C11 RCS
loop cold leg centerline tap-and vented to the top of the pressurizer via
a vent valve on the pressurizer spray line.
Also, at the time of the
event, the evacuation of the reactor vessel head was in progress to remove
radioactive gas and particulate inventory in preparation for lifting the
vessel head.
This evacuation is accomplished by jumpering the containment
vacc:um pump, to take suet ion on the pressurizer and thus, through the
surge line and half-filled loop, pull a suction from the vessel head.
Approximately 30 minutes prior to the event, the 11A11 RCS loop stop valves
were closed and draining of the 11N1 loop had commenced.
T~e licensee organized an investigative team to evaluate the event that
consisted of a Shift Technical Advisor, the System Engineer and a
Corporate Engineer.
The team was tasked with the fundamental question as to how a decrease in
reactor vessel water could occur without a corresponding decrease in the
standpipe indicated level. The onset of vortexing Has been calculated to
occur at approximately 12 feet 2 inches and the indicated water level was
not observed to drop below 12 feet 4 inches.
7
This, team, in a report date September 28, 1988, concluded in part the
following:
A momentary entry into vortexing of the
11811 RHR pump was experienced
and was quickly mitigated by the operators.
The operability of the RHR system was maintained with no Technical
Specification or UFSAR impact.
The root cause of the event was:
(1)
The head evacuation process contributed to erroneous standpipe
level indication.
(2) A slight differential pressure was established between the
reactor vessel head and the standpipe due to the head evacuation
coupled with the restriction of the pressurizer surge line by
the level of water being maintained in the reactor vessel. This
restriction was determined to be due to the orientation of the
pressurizer surge line penetration to
11C11 loop hot leg.
The
loop hot leg (29 11/0D) surge line penetration (12 11/0D) is into
the side of the loop piping.
Therefore, if level is maintained
at the administrative limit of 12 feet 6 inches, the surge line
opening to the loop is covered.
This essentially isolates the
reactor vessel from the pressurizer, and results in a lower
pressure within the pressurizer from the containment vacuum
pump.
The lower pressure was determined to act on the standpipe
water column resulting in an erroneously high indicated level.
(3)
The actual lowering of vessel water level was probably due to
leakage past the loop stop valve(s) and to the partially drained
11A11 RCS loop.
The inspector reviewed the results of the licensee investigation and
independently walked down the Unit 2 vessel level indication system inside
containment.
Additional corrective actions included restricting minimum
water level to 12 feet 6 inches, establishing a different flow path for
degasing the reactor vessel head, and installing a television monitor in
the control room to display standpipe level. A permanent standpipe system
with a display in the control room, similar to that installed during the
previous Unit 1 outage, is being installed during this Unit 2 outage.
In
addition, the inspector reviewed the licensee actions in response to the
vendor owners group and associated correspondence.
It appears from the
manner in which the licensee handled this particular event, coupled with
fhe resources devoted to responding to the generic concern that appro-
priate attention is being placed in this area. The resident inspectors
will continue to closely monitor licensee actions in this area.
8
Engineered Safety Feature System Wal kdown
(71710)_
The inspector performed a wal kdown of the accessible portions of the
containment spray for Unit 1.
This verification also included the
following: confirmation that the licensee's system lineup procedures
matches pl ant drawings and actua 1 pl ant configuration; hangers and
supports are operable; housekeeping is adequate; valves and/or breakers in
the system are installed correctly and appear to be operable; fire
protectfon/preventi on is adequate; major -system* components are properly
labeled and appear to be operable; instrumentation is properly*installed,
calibrated, and functioning; and valves and/or breakers are in correct
position as required by plant procedure and unit status.
The walkdown of the containment spray system included all accessible
piping and components from the refueling water storage tank and chemical
addition tank to the penetration into containment.
The inspector used the
latest available revisions of station drawing 11448-FM-084A, Containment
Spray System Unit 1, and identified the following discrepancies:
The piping that provides cooling water to the bearings of containment
spray pump 1-CS-P-lA were loose from their hangers.
This is the
piping that contains valves 1-CS-83 and 84,
The actual tie-in of the pump bearing cooling water p1p1ng and local
pressure indication is upstream of the containment spray pump
discharge flange versus downstream as shown on the drawing.
Pressure switch isolation valves 1-CS-121, 122, 123 & 124 are not
labeled in accordance with the drawing.
The containment spray pump casing vents are connected to tygon tubing
run to a floor drain instead of capped as shown on the drawing.
The 1 i censee ac-knowl edged these items with the inspector comment that
although these may not pose an immediate action-type concern, they are
worth noting and correcting during the current outage.
The above items
are identified as an inspector followup item for review of the licensee
corrective action (280/ 88-36-02).
Within the areas inspected, one licensee identified violation was noted.
6.
Maintenance Inspections (62703)
During the reporting period, the inspectors reviewed maintenance activi-
ties to assure compliance with the appropriate procedures.
Inspection
areas included the following:
On September 26, the inspector witnessed maintenance and testing of
the 4160 volt switchgear for auxilliary feedwater pump 2-FW-P-3A.
This work was being conducted in accordance with maintenance
procedure EPH-BKR-E/Al, Inspect and Service Circ~it Breaker, dated
9
August 2, 1988, as authorized by work order 3800071227.
The breaker
appeared in good ~hape with no problems noted.
No discrepancies were
identified in the areas inspected.
REPAIR TO PIPING UPSTREAM OF 2-SI-60 (Unit 2)
At 1:30 p.m. on September 6, 1988, during performance of 2-PT-18.1, Low
Head Safety Injection Test and Flushing of Sensitized Stainless Steel
Piping, leakage was identified on a pipe coupling upstream of flow
transmitter (FE-2945) isolation valve 2-SI-60.
The leakage was quantified
and determined to be in excess of that allowed by Technical Specification 3.3.
The unit was at approximately 70% power at the time.
The appro-
priate LCO for excess leakage was entered and the Unit SRO wrote a
deviation report (S2-88-398).
He also requested engineering evaluation of
the condition.
The system engineer was notified of the deficiency the
next day and went to evaluate the condition at approximately 11:00 a.m. on
September 7.
Evaluation of the co~dition continued and at approximately
5:50 p.m. on September 7, the unit entered a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO in order to
repair the leaking coupling.
Repairs were accomplished in accordance with
EWR 88-258A, Fabrication of Pipe Fittings for SI Flow Transmitter
(2-SI-FT-2945)/Surry/U-2.
Weld repairs were completed and the affected
low head SI pump (2-SI-P-lA) was tested in accordance with PT-18.1 and
determined to be operable at approximately 5:00 p.m. on September 8.
The inspector monitored the 1 i censee actions from the time that the
problem was first identified until the repairs were completed and the
system was returned to operation.
The inspector reviewed EWR 88-258A
which accomplished the repair work and also reviewed EWR 88-258 which
accomplished a similar repair to a pipe fitting on the same transmitter in
June 1988.
The inspector identified the following concerns to the
licensee at the end of the review period.
The time from identification of the leak by the operators (1330 hours0.0154 days <br />0.369 hours <br />0.0022 weeks <br />5.06065e-4 months <br />
9/6/88) to entering the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO in order to accomplish repairs
(1750 hours0.0203 days <br />0.486 hours <br />0.00289 weeks <br />6.65875e-4 months <br /> 9/7 /88) was approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />.
The inspectors
consider that evaluation of operability of the system from a design
and emergency procedures application perspective should have been
accomplished in a more timely manner.
Review of EWR 88-258 dated June 18, 1988, identified as part of the
problem statement that the fitting which was leaking was not
appropriate for the piping configuration as it is currently designed.
The inspector determined that other fittings had not been inspected
to determine the generic applicability even though another repair
was subsequently made using an amendment to the EWR (88-258A), and
that a deviation report had not been written.
e
10
Based on the preceeding concerns, this issue is unresolved pending
additional licensee evaluation and conclusions addressing timely
determination of safety* system operability, and engineering/field
evaluations to determine if the use of this type fitting in safety related
-systems is a generic safety problem (280/88-36-03; 281/88-36-01).
Within the areas inspected, no violations or deviations were identified.
7.
Surveillance Inspections
(61726)
During the reporting period, the inspectors reviewed various surveillance
activities to assure compliance with the appropriate procedures as follows:
Test prerequisites were met.
Tests were performed in accordance with approved procedures.
Test procedures appeared to perform their intended function.
Adequate coordination existed among personnel involved in the test.
Test data was properly collected and recorded.
Inspection areas included the following:
On September 9, the inspector witnessed testing of the Unit 2 main steam
safety valves in accordance with special test 2-ST-214, Main Steam Safety
Valve Setpoint Verification Using Furmanite Trevitest Equipment, dated
September 8, 1988.
This test, performed at normal operating temperature
and pressure, uses a hydraulic assist device to compress the spring to
determine the setpoint on the valve.
No discrepancies were noted.
PRIMARY POWER-OPERATED RELIEF VALVE
On September 15, while testing the Unit 1 reactor cold overpressure
mitigating system, it was determined that power operated relief valve
PCV-1456 would not open from the main control room.
The licensee declared
the valve inoperable and entered a 7 day action statement.
Subsequent
troubleshooting determined that a solenoid operated air valve (SOV) was
malfunctioning.
This SOV was jumpered out to permit operation of
PCU-1456 while making repairs.
The PORV was returned to service on
September 22 by testing in accordance with periodic test procedure
1-PT-2. 26 (P-1-458), Reactor Cool ant System Pressure (P-1-458).
The
11
inspector reviewed the completed results of this test and verified
adequate documentation of the valve 1 s return to service.
The licensee
continues to diagnose the problem with the SOV.
No discrepancies were
identified.
NUCLEAR INSTRUMENTATION SYSTEM
On September 20, the inspector witnessed portions of testing in accordance
with periodic test 2-PT-1.1, NIS Reactor Trip Channel Test Prior To
Start-Up, dated June 8, 1988. This test, performed weekly during shutdown
by instrument technicians, ensures the operability of the nuclear
instrumentation system (NIS) and includes observation of channel bistable
actions as related to alarms, permissives, rod stops, and reactor trips.
The inspector witnessed testing of the Unit 2 source range instruments.
No discrepancies were noted.
Within the areas inspected, no violations or deviations were identified.
7.
TI 2515/98 Review
(71707)
The inspectors conducted a review of the containment average operating
tempera tu res to determine the method and accuracy of the 1 i cen see
measurements.
This inspection effort consisted of the following reviews:
The method of measuring containment temperature.
A review of a sampling of temperatures during the summer months of
1987.
An overall review of previous NRC inspections on this subject.
A review of containment ventilation temperatures and flow paths.
A review of equipment qualifications regarding temperatures inside
containment.
A containment tour and visually inspected the locations of the RTDs
to verify they comprise a representative sample of actual tempera-
tures.
The inspector review determined the licensee actions with regards to
measuring an accurate temperature profi 1 e to be adequate.
No di scre-
panci es were noted.
8.
Exit Interview
The inspection scope and findings were summarized on October 4, 1988, with
those individuals identified by an asterisk in paragraph 1.
The following
new items were identified by the inspectors during this exit.
e
12
Licensee Identified Violation (LIV) 280/88-36-01, Failure to meet the
requirements of Technical Specification 3.0.1 during shutdown of Unit 1 on
September 14; 1988 (paragraph 5).
Inspector Followup Item (IFI) 280/88-36-02, Followup on discrepancies
identified during walkdown of Unit 1 containment spray system (paragraph
5).
.
Unreso'l ved Item ( URI) 280/88-36-03; 281/88-36-01, Review of add it i ona 1
licensee evaluation and conclusions addressing timely determination of
safety system operability,
and generic evaluation of the fitting
a,pplication in safety-related systems (paragraph 6).
The licensee acknowledged the inspection findings with no dissenting
comments.
The 1 icensee did not identify as proprietary any of the
materials provided to or reviewed by
the inspectors during this
inspection.