ML20149E621
| ML20149E621 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 01/15/1988 |
| From: | Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20149E589 | List: |
| References | |
| 50-338-87-38, 50-339-87-38, IEB-87-002, IEB-87-2, NUDOCS 8802110183 | |
| Download: ML20149E621 (12) | |
See also: IR 05000338/1987038
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION H
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101 MARIETTA STREET,N.W.
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ATLANTA, G EORGI A 30323
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Report Nos.:
50-338/87-38 and 50-339/87-38
Licensee:
Virginia Electric & Power Company
Richmond, VA 23261
Docket Nos.:
50-338~and 50-339
Facility Name: North Anna 1 and 2
Inspection Conducted:
November 20 - December 18, 1987
Inspectors:
4 /w
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J.~ L. Caldwell, Seri)(f Resident Inspector
Date Signed
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L.' P. King, Resident'4nspe'ctor
Date 5fgned
Approved by:
4[M2
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F. 5. Cantrell, Secti5
ief
D&te 5fgned
Division of Reactor Pr
cts
SUMMARY
Scope:
This routine inspection by the re:fdent inspectors involved
the
following areas:
plant status,. licensee event report (LER followup), monthly
maintenance observation, monthly surveillance observation, ESF walkdown,
operator safety verification, operating reactor events, Temporary Instruction
(TI) 2500/26, cold weather preparation, health physics, and instrumentation
problems related to startup of Unit 2.
During the performance of this inspec-
tion, the resident inspectors conducted reviews of the licensee's backshift
operations on the following days - November 17, 18, 23, 24 and December 1, 2,
3, 4, 5, 7, 8, 14, 15, 16, 17 and 18, 1987.
Results:
Three violations were identified: (1) Failure to follow the require-
ments of RWP-87-3156 (see paragraph 13); (2) Failure to perform adequate post
maintenance testing on Unit 2
"A" Steam Generator Flow Channel III (see
paragraph 14); (3) Violation of Technical Specifications (TS) 3.3.1.1 and
3.3.2.1 for failure to declare two steam flow channels inoperable (see
paragraph 14).
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REPORT DETAILS
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1.
Licensee Employees Contacted
- ti. W. Harrell, Station Manager
- R. C. Driscoll, Quality Control (QC) Manager
- G. E. Kane, Assistant Station Manager
- H. L. Bowling, Assistant Station Manager
R. O. Enfinger, Superintendent, Operations
- H. R. Kansler, Superintendent, Maintenance
- A. H. Stafford, Superintendent, Health Physics
J. A. Stall, Superintendent, Technical Services
- J. L. Downs, Superintendent, Administrative Services
J. R. Hayes, Operations Coordinator
D. A. Heacock, Engineering Supervisor
D. E. Thomas, Mechanical Maintenance Supervisor
G. D. Gordon, Electrical Supervisor
L. N. Hartz, Instrument Supervisor
F. T. Termine11a, QA Supervisor
J. P. Smith, Superintendent, Engineering
- D. B. Roth, Nuclear Specialist
J. H. Leberstein, Engineer
- G. G. Harkness, Licensing Coordinator
- L. L. Edmonds, Superintendent, Nuclear Training
- N. K. Martin, Security
Other licensee employees contacted include technicians, operators,
mechanics, security force members, and office personnel.
The following members of the regional staff met with the North Anna staff
on December 16, 1987, for a presentation of current plant initiatives and
a plant tour:
M. L. Ernst, Deputy Regional Administrator
A. F. Gibson, Director, Division of Reactor Safety
C. W. Hehl, Deputy Director, Division of Reactor Projects (DRP)
F. S. Cantrell, Chief, Proejet Section 2A, DRP
- Attended exit interview
2.
Exit Interview (30703)
The ins)ection scope and findings were summarized on December 18,
1987, w< th those persons indicated in paragraph 1 above.
The licensee
acknowledged the inspectors findings.
The licensee did not identify as
proprietary any of the material provided to or reviewed by the inspectors
during this inspection.
(0 pen) Violation 338/87-38-01:
Failure to follow the requirements of RWP
87-3156 (see paragraph 13).
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(0 pen) Violation 339/87-38-01:
Failure to perform adequate post
maintenance testing on Unit 2 "A" Steam Generator Steam Flow Channel III
(FI-2474) (see paragraph 14).
(0 pen) Violation 339/87-38-02:
Violation of T.S. 3.3.1.1 and 3.3.2.1 for
failure to declare
"A" Steam Generator Steam Flow Channel III and "B"
Steam Generator Steam Flow Channel IV inoperable.
This is being
considered for escalated enforcement (see paragraph 14).
(0 pen) Unresolved Item 339/87-38-03.
Lack of overpressure protection for
the B accumulator (see paragraph 9).
3.
Plant Status
Unit 1
Unit 1 began the inspection period operating at 100% power.
On November 23,
the unit tripped due to a failed high level switch on the SA feedwater
heater (See paragraph 10 for details).
The unit was back on line by
November 24.
On November 28, the "B" Reactor Coolant Pump (RCP) number
one seal leak off went off scale high.
This resulted in a forced reactor
shutdown to replace the "B" RCP seal package.
On December 8, the licensee
restarted Unit 1, and the unit is presently operating at 100% power.
Unit 2
Unit 2 began and ended the inspection period operating at 100% power.
However, on December 3, the Unit 2 "B" accumulator relief valve began
lifting, making it difficult for the operators to maintain the required
pressure in "B' accumulator.
The licensee gagged the failed relief and
installed one from Unit 1 in the vent line next to the original relief
valve (See paragraph 9 for details).
4.
Unresolved Items
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An unresolved item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or
deviation.
One unresolved item was identified in this report and is discussed in
paragraph 9.
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5.
Licensee Event Report (LER) Follow-up (90712 and 92700)
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The following LERs were reviewed and closed.
The inspector verified that
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reporting requirements had been met, that causes had been identified, that
corrective actions appeared appropriate, that generic applicability had
been considered, and that the LER forms were complete.
Additionally, the
inspectors confirmed that no unreviewed safety questions were involved and
that violations of regulations or TS conditions had been identified.
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(Closed)~LER 339/86-01 (Rev.1):
High Lift Setpoints on Main Steam Safety-
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Valves.
The valves have been tested at Wyle Laboratories and reset.
(Closed) LER 338/87-06:
RCP Busses Undervoltage Relays Out of Tolerance:
1/2 PT-33.2A,B,C were revised to include the new dropout voltages.
(Closed) LER 338/87-16:
Inoperable Turbine Overspeed Protection System
Due to Incorrectly Reassembled Intercept and Reheat Stop Valves.
A
procedure has been developed to control maintenance on both Units 1 and 2
intercept and reheat stop valves.
The procedure includes steps for proper
identification of components.
Each valve and actuator will be uniquely
identified to preclude incorrect assembly.
(Closed) LER 338/87-19:
Excessive Skin Exposure Due to Contamination From
Hot Particle Transferred to Individual from Laundered Protective Clothing.
The following actions have been taken by the licensee:
a.
An automatic laundry monitor has been installed.
b.
Four additional personnel contamination monitors have been purchased
and placed into operation.
c.
A one hour session was developed and conducted for radiation workers
at station.
Hot particle information has been included with General
Employee Training.
d.
A four hour session was developed and conducted 17 times to give
special training to all Health Physics technicians.
e.
Radiological work practice #22C was developed to provide guidelines
for establishing controls for hot particles.
(Closed) LER 338/87-09 (Rev. O and 1):
Main Steam Safety Valves Setpoints
Below TS Minimum.
All 15 safety valves were sent to Wyle Labs for
testings.
Eleven safety valves had low setpoints and were readjusted to
within specifiestion.
The safety analysis contained in Chapter 15 of the
UFSAR was still bounding and there was no unreviewed safety question.
(Closed) LER 338/87-13:
Loss of Normal Power Supply to Emergency Bus
During Testing.
The licensee determined the root cause was failure to
follow procedure.
The electrical maintenance procedure has been revised to
emphasize the requirement that all wires need to be lifted prior to
testing relays.
(Closed) LER 338/87-18 (Rev. 0 & 1):
Non-Environmentally Qualified Motor
As Required Had No Documentation.
The licensee determined the root cause
of the event.
Present level of training should prevent reoccurrence.
(Closed) LER 338/87-03:
Single Component Failure in Access Control
Cardreaders/ Failure Could Have Permitted Unauthorized / Undetected Access
into Vital Areas.
The licensee has taken corrective action.
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(Closed) LER 339/87-03:
Improper Determination of Quadrant Power Tilt
Ratio.
QPTR was determined by one set of four symmetric incore thimbles
instead of two sets.
The P-250 program was revised so that a tilt is only
printed when eight of the symmetric thimbles are obtained and calibrated.
The program has been implemented on both Units 1 and 2 P-250 computers.
(Closed) LER 339/87-06:
Reactor Trip Caused by a Failing Intermediate
Range Detector.
Detector replaced and calibrated.
Also, replaced H.V.
power supply, P-6 bistable board and spare bistable board.
(Closed) LER 339/87-08:
Pressurizer Safety Valves Set Pressures Not
Within TS Limits. The safety valves were repaired and readjusted at Wyle
Labs to within the correct set pressure allowed by TS 3.4.3.
6.
Monthly Maintenance (62703)
Station maintenance activities affecting safety related systems and
components were observed / reviewed, to ascertain that the activities were
conducted in accordance with approved procedures, regulatory guides and
industry codes or standards, and in conformance with TS.
The inspector attended several daily maintenance meetings during the
outage to replace the radial motor bearings and the seal package on the
Unit 1 "B" reactor coolant pump.
The inspector made several tours of the
containment and observed the work on the radial bearings for the
"B"
reactor coolant pump motor.
1he Westinghouse procedure for the repair was
reviewed.
Readings taken before the bearings were replaced indicated the
tolerances were out of specification.
It was not clear at this time if
the seal failure was due to the problem with the radial bearing.
The inspector observed work on the replacement of a drain valve FW-69 on
the 1-RC-E-1A main steam generator feed line.
Several valves were repacked on the
"C" accumulator during this outage.
The inspector noted during a walkdown of containment that the following
additional accumulator valves appeared to need repacking based on boric
acid buildup on valve stems.
The licensee was informed of the inspectors'
observations:
a.
Motor operated valve 1850 C
b.
"B" accumulator outlet
c.
All three accumulators makeup valves
d.
"A" accumulator lower level transmitter shutoff valve 1-51-117
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The inspector reviewed the work order and inspected che work on main
feedwater valve FW-110.
This is a pressure seal valve that was leaking
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badly before the outage.
The manufacturer was contacted and a spacer ring
was machined.
The valve was reassembled.
No violations or deviations were identified.
7.
Monthly Surveillance (61726)
The inspectors observed / reviewed technical specification required testing
and verified that testing was performed in accordance with adequate
procedures, that test instrumentation was calibrated, that limiting
conditions for operation (LCO) were met and that any deficiencies
identified were properly reviewed and resolved.
On November 25, 1987, the inspectors observed 2-PT-14.1 "Test of the
Unit 2 "A" Charging Pump".
No problems were identified.
On December 3,1987, the inspectors observed containment air lock leak
rate test 1-PT-62.4.
The seal failed the test and needed to be replaced.
The next test was performed satisfactorily on December 12, 1987.
On December 2,1987, the inspectors observed the start of the security
aiesel using test 1-MISC-20.
No problems were identified.
No violations or deviations were identified.
8.
ESF System Walkdown (71710)
The following selected ESF system was verified operable by performing a
walkdown of the accessible and essential portions of the system on
December 15, 1987:
A check was made of the Unit 1 casing cooling system using operations
checklist 1-0P-7.10A.
No violations or deviations were identified.
9.
Operational Safety Verification (71707)
By observations during the inspection period, the inspectors verified that
the control room manning requirements were being met.
In addition, the
inspectors observed shift turnover to verify that continuity of system
status was maintained.
The inspectors periodically questioned shift
personnel relative to their awareness of plant conditions.
Through log review and plant tours, the inspectors verified compliance
with selected TS and Limiting Conditions for Operations.
In the course of the monthly activities, the resident inspectors included
a review of the licensee's physical security program.
The performance
of various shifts of the security force was observed in the conduct of
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' daily activities to include:
protected and vital areas access controls,
searching of personnel, packages and vehicles, badge issuance and retrieval,
escorting of visitors, patrols and compensatory posts.
In addition, the
resident inspectors observed protected area lighting, protected and vital
areas barrier integrity and verified an interface between the security
organization and operations or maintenance.
On a regular basis, radiation work permits (RWP) were reviewed and the
specific work activity was monitored to assure the activities were being
conducted per the RWPs.
Selected radiation protection instruments were
periodically checked and equipment operability and calibration frequency
was verified.
The inspectors kept informed, on a daily basis, of overall status of both
units and of any significant safety matter related to plant operations.
Discussions were held with plant management and various members of the
operations staff on a regular basis. Selected portions of operating logs
and data sheets were reviewed daily.
The inspectors conducted various plant tours and made frequent visits to
the control room.
Observations included: witnessing work activities in
progress; verifying the status of operating and standby safety systems and
equipment; confirming valve positions, instrument and recorder readings,
annunciator alarms, and housekeeping.
On December 2, at 11:45 a.m. , the Unit 2 operators commenced nitrogen
makeup to the "B" accumulator in order to maintain the pressure within the
TS limits.
At 1:45 p.m.,
the licensee discovered that the relief valve
was lifting on the "B" accumulator and at 3:38 p.m. , the licensee gagged
the relief valve.
The following day at 3:51 a.m. , the licensee
successfully blocked open the nitrogen fill isolation valve to the
"B"
accumulator ensuring that the relief valve on the nitrogen fill header
would not be isolated from the "B" accumulator.
This nitrogen relief
valve was exactly like the accumulator relief with the exception that the
nitrogen relief has a carbon steel body and the accumulator relief had a
stainless steel body.
On December 3, the inspectors questioned the licensee whether the relief
setpoints and capacities for the nitrogen relief and the accumulator
relief were the same and whether or not the nitrogen relief was in the
Inservice Inspection (ISI) program (i.e., periodically setpoints tested).
On December 4, the licensee informed the inspectors that at approximately
2:00 a.m., a Unit I relief valve was installed on a vent line next to the
gagged Unit 2 "B" accumulator relief valve because with different piaing
configuration, they could not demonstrate equivalent relieving capability
with the nitrogen relief valve.
This vent line is the same size as the
relief line and the vent line isolation valve was locked open.
The reason
for this installation was because the licensee could not demonstrate that
the relief capabilities were the same between the nitrogen relief and the
accumulator relief even though they were confident that the accumulator
could not exceed pressures beyond which it had already been tested.
Also,
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even though theLnitrogen relief valve' had a listed 'setpoint of 700 isig,
.the 'same.as 'the. accumulator relief, this valve was not in the ISI program
and had not been tested since it was installed.- The valve had lifted in
the recent past due to' high pressures in the nitrogen system, but the
licensee .could. not be sure what the setpoint was. . Consequently, ' the
- licensee decided to install a qualified and tested relief valve obtained -
from Unit I which was in Mode.5, cold shutdown, at the time.
This item is ~
identified as Unresolved Item 339/87-38-03, pending NRC determination of
'the acceptability of the relief valve being downstream of a blocked open
isolation' valve.
On December.7, the inspectors witnessed portions of the Unit I startup per.
1-0P-1.4, Unit Startup from Hot Shutdown Condition (Mode 4) to Hot Standby
Condition (Mode 3). at 547 degrees F.
Also, on-December 7,.the inspectors
witnessed portions of- 1-0P-1.5, Unit'Startup from Hot Standby Condition
(Mode 3) to Startup Condition (Mode 2) with Reactor Critical at less Than
or Equal to 5% Power, for Unit 1.
During the performance of the procedure,
the rod bottom light for rod B2 in Bank A failed to go out when the rods
in Bank A were pulled past 35 steps. When the Instrumentation and Control-
(I&C) technicians could not quickly resolve the problem, the operators
elected to drive the rods in Bank A back into the core.
A bistable card
was replaced.to correct the problem.
No violations or deviations were identified.
10.
Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed
reactor events.
The review included determination of cause, safety
significance, performance of personnel and systems, and corrective action.
The inspectors examined instrument recordings, computer printouts,
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operations journal entries, scram reports and had discussions with
operations, maintenance and engineering support personnel as appropriate.
At 0009, on November 23, Unit 1 experienced a turbine trip and resulting
The turbine trip was caused by a level switch in the number
SA feedwater heater which failed high.
This failure of the level switch
also tripped the condensate pumps which in turn caused the feedwater pumps
to trip and the feedwater regulating valves to go shut.
level was restored and maintained by the auxiliary feedwater pumps until
the condensate and feedwater pumps could be restarted.
The reactor
coolant system TAVE dropped to approximately 520 degrees F, pressure
dropped to approximately 1860 psig and pressurizer level dropped to less
than 15% at their lowest points.
The licensee is investigating the cause of the level switch failure.
Also, during this event, the following problems occurred:
a.
With the steam dumps in the steam pressure mode below 547 degrees F,
three dump valves came open.
Only two dump valves are supposed to
open; the third valve had to be de-energized shut.
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b.
Two of the three main feedwater isolation valves failed to go fully
closed when the operator manually closed the valves from the control
room to reduce the leakage past the feedwater regulation valves.
c.
One of the turbine trip valves failed to provide a reactor protection
trip signal or indicate a shut position in.the control room following
the turbine trip.
The licensee discovered that the valve actually
went shut, but the position indication linkage was broken.
d.
Two control rods, G-13 and B-6 did not indicate fully inserted
following the trip.
The licensee determined that the control rods
were actually inserted and the problem was with the Individual Rod
Position Indication for those two control rods.
The inspectors will follow the licensee's actions related to the above
problems and review their corrective actions to ensure that they are
adequate.
No violations or deviations were identified.
11.
Compliance Bulletin No. 87-02
On December 3,1987, the inspector participated in the selection of
fasteners in accordance with the guidelines given in the subject bulletin.
The licensee selected the fasteners by reviewing the usage rates from the
storeroom and warehouse.
Sections of threaded stock were also selected.
The licensee site and corporate engineering staff as well as plant quality
assurance group participated in the selection from the storeroom and
warehouse.
After the destructive testing is completed on the selected
fasteners, the results of the test will be sent by the licensee to the
NRC.
12.
Cold Weather Preparation (71714) - Units 1 and 2
The inspectors reviewed the following preventative maintenance procedures
which are performed prior to cold weather:
a.
PM-E-00-HT/A-1 - Heat Trace Verification
b.
PM-E-00-HV/A-1 - Heaters
c.
PM-M-00-SY/A-1 - Walkdown of Outdoor Areas
d.
PM-M-00-SY/A-2 - Plant Winterization Program, Storeroom
e.
PM-M-00-SY/A-3 - Plant Winterization Program, Mechanical Department
f.
PM-M-00-SY/A-4 - Installation of Thermal Barriers
g.
PM-M-00-FP/SA-1 - Fire Gate talve Lubrication
No problems were identified.
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13.
Health Physics
On November 24, 1987, during the Unit 1 startup, auxiliary operators were
throttling the feedwater outlet valve from the main feedwater regulator.
This area was designated as a contaminated area by RWP E7-3156 due to
leakage from FW-110.
The inspector observed that the operators were not
following the portion of the RWP that required them to obtain a whole body
frisk.
Technical Specification 6.11 requires that procedures for personnel
radiation protection shall be prepared consistent with +he requirement of
10 CFR Part 20 and shall be approved, maintained and adhered to for all
operations involving personnel radiation exposure.
Licensee procedure
HP 5.310 establishes a work permit program.
Health Physics procedure
5.320, "Initiating, Using, Extending and Terminating a Radiation Work
Permit (RWP)" is part of that program.
It requires a radiation worker
to comply with the requirements, instructions, and precautions of the
RWP.
The failure of the auxiliary operators to 3erform a whole body
frisk constitutes a violation of TS. 6.11 and is 'dentified as Violation
87-38-01.
14.
Previous Inspection Followup
(Closed) Unresolved Item (338,339/87-36-03), Potential Inadequate Post
Maintenance Testing.
During a review of this item, that inspectors
discovered several problems.
The first deals with the discovery by the
licensee on November 4,1987, during the Unit 2 startup, the steam flow
instrument FI-2474 was inoperable due to the instrument leads being
reversed (LER 87-15).
The inspector was informed by the licensee that
maintenance had been performed on this steam flow instrument during the
refueling outage in the form of replacement of the Raychem splices per
Engineering Work Request (EWR)87-206.
The inspector reviewed the EWR
87-206 and discovered that for Steam Flow Instrument FI-2474, the signoffs
for post maintenance testing were not completed.
The inspector determined
that this EWR had been reviewed by all the required personnel including
the station safety committee without detecting that the proper signoffs
had not been made for the post maintenance testing of FI-2474.
A review
by the inspector of the actual post maintenance test revealed that if the
test had been performed on FI-2474 it would have detected the reversed
Considering the fact that there is no complete documentation of a post
maintenance testing being conducted on FI-2474, that if the test had been
performed the problem of the reversed leads would have been detected and
finally that steam flow channel FI-2474 instrument leads were in fact
reversed without being detected indicates that a proper post maintenance
test was not conducted on FI-2474 following maintenance.
The result of
this lack of post maintenance testing was that the licensee operated
Unit 2 from Mode 3 through Mode 1 up to 27 percent without having the
Reactor Protection System (RPS) and Engineering Safety Feature (ESF)
trip signal associated with FI-2474 operable.
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Technical Specification 6.8.1.c requires written procedures be established,
implemented and maintained covering surveillance and test actuators of
safety related equipment.
The failure of the licensee to conduct a 3 roper
post maintenance test of steam flow instrument FI-2474 following ma' nten-
ance which resulted in a degraded RPS and ESF system trip protection will
be identified as violation (339/87-38-01).
The second problem involves the delay by the operators in declaring steam
flow instruments FI-2474 ("A" Steam Flow Channel III) and FI-2485 ("B"
Steam Flow Channel IV) inoperable.
During the review of the unresolved
item the inspectors reviewed the oaerator's (both SRO and CRO) shift logs
and the operator's Technical Specification (TS) required channel check
logs.
Thi s review revealed that as early as 1200 noon on November 4,
1987, the operators had enough information to declare the steam flow
channels FI-2474 and FI-2485 inoperable and place then in the trip
condition as required by TS.
The 1200 noon channel check logs indicated
that both the above channels were essentially reading zero steam flow
while their redundant steam flow channels as well as boths the C loop
steam flow channels were indicating approximately 0.5 x 10 pounds mass
per hour.
The licensee's accgptance criteria for a proper channel check
is a maximum of i 0.25 x.10 pounds mass per hour difference between
redundant channels on a steam line.
The licensee's operations standard
which addresses channel check criteria states in part that an instrument
channel shall be declared inoperable when the stated acceptance criterial
tolerances are exceeded and the applicable actions of TS shall be
implemented.
At this point, the operators failed to declare the steam flow
channels inoperable and to place them in a trip condition for both RPS and
ESF trip signals as required by TS.
On November 4,1987, Unit 2 which was in Mode 2 continued with the
startup.
At approximately 17:54 on November 4, Unit 2 was placed on line
and per the SRP log entry at 1816 on November 4, with the unit at 24
percent power, the steam flow channels FI-2474 and FI-2485 were reading
zero steam flow.
Also a review of the channel check logs revealed that
the 2000 channel check stated that both FI-2474 and FI-2485 were pegge4
low with the redundant steam flow channels reading approximately 1 x 10
pounds mass per hour.
The operators again failed to comply with TS
channel check criteria and place these steam flow channels in the trip
condition.
It was not until 2153, approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after Unit 2 achieved greater
than 20 percent reactor power, that steam flow channels FI-2474 and FI-2485
which were still reading zero (ie, failed flow) steam flow were declared
It was later discovered that the reason for FI-2474 being
inoperable was due to the instrument leads being reversed and for FI-2485
mechanical agitation conducted on the instrument in containment caused the
channel to indicate properly.
Therefore it is clear that the steam flow
channel FI-2474 was inoperable and would not have provided its RPS or EFS
trip signals from the time Unit 2 was in Mode 3 up through Mode 1 at
approximately 27 percent power and should have been placed in the trip
condition as soon as the operators had indication of a problem.
Also the
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steam flow channel FI-2485 which required mechanical agitation to become
operable appeared to have been inoperable for Mode 3 through Mode 1 and
again should have been placed in the trip condition as soon Das the
operators had an indication of a problem.
TS 3.3.1.1 and 3.3.2.1 requires that all of the steam flow channels be
operable with the Unit in Modes 1, 2, and 3 and Action Statement 7 and 14
respectively state that operation.may proceed until the performance of
the next required channel functional test provided the inoperable channel
is placed in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The failure of the
licensee to. comply with TS 3.3.1.1 and 3.3.2.1 and place steam flow
channels FI-2474 and FI-2485 in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
resulting in degraded RPS and ESF trip protection will be identified as a
Violation (339/87-38-02).