ML20206J596
| ML20206J596 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 11/15/1988 |
| From: | Lesser M, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20206J564 | List: |
| References | |
| 50-413-88-34, 50-414-88-34, NUDOCS 8811290049 | |
| Download: ML20206J596 (16) | |
See also: IR 05000413/1988034
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UNITED STATES
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NUCLEAR REGULATORY COMMIS$10N '
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REGION il
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101 MARitTTA STREET,N.W.
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ATLANTA, GEORGI A 30323
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Report Nos. 50-413/88-34 and 50-414/88-34
Licensee: Duke Power Company
,
422 South Church Street
Charlotte, N.C.
28242
a
Docket Nos.:
50-413 and 50-414
License Nos.: NPF-35 and NPF-52
' Facility Name: Catawba 1 and 2
Inspection Conducted: September 26, 1988 - October 25, 1988
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Inspectors
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/// T W
W. T. Ofd rs
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Date/ Signed
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Inspectors *
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"M. 5.'T. esser
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Fa te/ Signed
//-/ T-77
Approved by:
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T. A. Peebles 3 SectioriT,hief
Date Signed
Projects Branch 3
Division of Reactor Projects
SUMMARY
Scope:
This routine, resident inspection was conducted on site inspecting in
the areas of review of plant operations; surveillance observation;
maintenance observation; review of licensee nonroutine event reports;
and followup of previously identified items; part 21 reports and
containment temperature instrumentation.
Results:
In the areas inspected, the licensee's programs were observed to be
adequate.
One weakness was identified in the area of valve position
limit switch setup for which corrective actions are ongoing.
Two
violations were identified one for failure to initiate prompt
corrective action following discovery of a valve failure and the-
other with four examples involved procedural adherence or inadequacy.
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8911290049 081116
PDP
ADOCK 05000413
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- H. B. Barron, Operations Superintendent
W. F. Beaver, Performance Engineer
W. H. Bradley, QA Surveillance
- R. N. Casler, Unit 1 Coordinator
R. H. Charest, Station Chemistry Supervisor
T. E. Crawford, Integrated Scheduling Superintendent
W. P. Deal
Health Physics Supervisor
- R. M. Glover, Compliance Engineer
- T. P. Harrall, Design Engineering
F. N. Mack, Project Services Engineer
W. W. McCollough, Mechanical Maintenance Supervisor
W. R. McCollum, Station Services Superintendent
C. E. Muse, Unit 2 Coordinator
- T. B. Owen, Station Manager
G. T. Smith, Maintenance Superintendent
J. M. Stackley, I & E. Engineer
D. Tower, Shift Operating Engineer
- R. F. Wardell, Technical Services Superintendent
R. White, CSRG Chairman
J. W. W'111s, Senior QA Engineer, Operations
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and office personnel.
NRC Resident Inspectors
- W. T. Orde.'s
- M. S. Lesser
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- Attended exit interview.
2.
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. There were
three unresolved items identified in this report (paragraphs 3d, 5d and
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6b).
3.
Plant Operations Review (71707 and 71710)
a.
The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements, Technical
Specifications (TS), and administrative controls. Control room logs,
danger tag logs, Technical Specification Action Item Log, and the
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removal and restoration log were routinely reviewed. Shift turnovers
were observed to verify that they were conducted in accordance with
approved procedures.
The inspectors verified by observation and interviews, that the
measures taken to assure physical protection of the facility met
current requirements.
Areas inspected included the security
organization; the establishment and maintenance of gates, doors, and
isolation zones in the proper conditions; and that access control and
badging were proper and procedures followed.
In addition to the areas discussed above, the areas toured were
observed for fire prevention and protection activities.
These
included such things as combustible material control, fire protection
systems and materials, and fire protection associated with
maintenance activities.
The
inspectors
reviewed Problem
Investigation Reports to determine if the licensee was appropriately
documenting problems and implementing appropriate corrective actions.
b.
Unit 1 Sumary
The unit started the reporting period at 100% power. On September 27
power was reduced to 20% to repair a packing leak on a Feedwater
Regulating Valve (CF-55).
The unit returned to 100% power af ter
completion of the maintenance and operated thera for the remainder of
the inspection period,
c.
Unit 2 Summary
The unit started the reporting period at 95% power. On September 28
a worker inadvertently secured the main generator Stator Cooling (KG)
pump which initiated a turbine runback.
The ensuing feedwater
transient resulted in a steam generator high high level feedwater
isolation and a manual reactor trip from approximately 35% power.
The unit was started up on October 1 and gradually increased power to
100% by October 4.
On October 12 power was reduced to 98% due to
recurring fouling of the feedwater flow orifice to the 2C steam
generator.
On October 16 resin from a condensate polisher was
inadvertently pumped into the steam generators.
The resulting high
sulfates and cation concentration required power level to be reduced
to 2% until the contamination could be cleaned up. The t: nit returned
to 98% power on October 19 and operated there for the remainder of
the inspection period.
d.
On the afternoon of October 17, 1988 the resident inspector, during a
routine tour of the control room, noted in the Unit 2 Technical
Specification Action items Logbook (TSAIL) that both B diesel
generator starting air (VG) compressors had been taken out of service
at 7:30 a.n that morning. The inspector also noted that at 9:50 am
that morning, the 2A motor driven auxiliary feedwater pump was
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removed from service.
The inspector, in discussions with the unit 2
operators, determined that the D/G was actually considered to be
operable because the accumulators (air tanks) were charged to their
normal pressure which is approximately 250 psig.
This pressure, by
design, and as described in FSAR Section 9.5, is sufficient to ensure
adequate capacity for a minimum of five successful engine starts.
The inoperability of the VG compressors had been noted in the TSAll
for "tracking purposes" only.
The inspector was concerned about not having the compressors
operable. This concern was based, in part, on a previous observation
by the inspector of a recent 1A diesel run during which both VG
compressors ran continuously af ter the engine start for the entire
time the inspector was in the diesel room (approximately 35-40
minutes). This, coupled with the knowledge that the diesel employs a
pneumatic control system which must be operable for t'? diesel to run
and a recent related incident associated with the starting air system
for the McGuire diesels prompted the inspector to expand his review.
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In a review of the Removal and Restoration (R&R) under which the VG
compressors were removed from service, and discussions with
operations supervisory personnel, it was learned that both
compressors were remon.u from service to facilitate the installation
of a modification which would provide the VG air dryers with separate
power supplies. It was also learned that one of the compressors was
apparently returned to service at approximately 11:00 am that morning
after necessary wiring modifications had been made.
In an effort to determine if having both VG compressors inoperable
actually degraded the D/G, the inspector reviewed the FSAR and other
documents,
in FSAR, Section 8.3.1.1.3, the 0/G's are described as having
air
storage capacity sufficient for a minimum of five successful engine
starts without the use of the air compressors.
When the diesel
generator receives an automatic start signal from the diesel
generator load sequencer, starting air is admitted to the engine to
begin the starting process.
If the engine has not attained at least
44% rated speed within 10 seconds after receiving the automatic start
signal, the diesel engine will continue to admit starting air until a
second start attempt occurs.
Sufficient starting air is available for two automatic start
attempts.
This includes a first unsuccessful start attempt and a
second start attempt.
If the diesel does not start on the second
automatic attempt and starting air pressure drops below 150 psig, the
diesel will cease trying to start automatically.
The starting air receiver tanks also supply air at reduced pressure
to the engine control instrumentation. Air enters the engine control
pa iel where it is filtored and a self-contained pressure regulator
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maintains constant pressure of 60 psi for the diesel automatic safety
shutdown system.
The automatic safety shutdown system is made up cf
a network of vent on fault pneumatic devices which monitor the
engines parameters, tripping the engine when a recomended
temperature, pressure, overspeed, or vibration setpoint has been
exceeded.
The control system trips the diesel by removing the air
from the pneumatic devices.
Herein lies the inspectors concern
relative tc 3e operability of the diesel with no makeup air
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available.
After review of the above mentioned documents, the inspector in
discussions with the licensee confirmed their belief that a D/G is
operable with both VG compressors inoperable if the VG receiver tanks
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are charged.
Pending receipt of dccumentation to support the
licensee's contention, the matter of 0/G operability will be carried
as an Unresolved Item 413/88-34-02:
0/G Operability With Both VG
Compressors Inoperable.
During the above mentioned event analysis, the inspector reviewed
Operations Management Procedure (OMP) 2-29 which includes
instructions for the operating staff on support systems which are
required for operability of Technical Specification (TS) required
equipment.
Page 36 of Attachment 3 to OMP 2-29, lists VG as required
to be operable to support the operability of the diesel generators.
Specifically, one VG air compressor and storage tank are required to
support each diesel.
The procedure specifies that if a compressor
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and tank are not operable the operators are to provide an operable
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alternate source of compressed air or declare the diesel inoperable
and enter the TS action statement,
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When this was discussed with the licensee, operations management
stated that the intent of the requirement to have VG operable as a
support system was to support "long term operability".
Operations
management stated what was intended by the statement in a column
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titled Discussion / Reference in OMP 2-29.
The statement specifies ,
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that "as long as sufficient pressure is in the tanks, support systems
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are not needed; however, some controls on the diesel are supplied by
storage tanks; therefore, compressor (s) are required for long term
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operability."
bsing that logic, VG would not be required if the
diesel was only required for a short time af ter being called upon to
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perform it's intended safety function.
However, one cannot predict
how long the 0/G would be required to perform its safety function.
Therefore, one cannot predetemine that VG is not necessary to
support VG operability.
Assuming the provisions of OMP 2-29 would be employed as interpreteu
by operations management the procedural requirement (Station
Directive 3.1.14) associated with taking compensatory actions was not
performed in this case.
Station Directive 3.1.14, Operability
Determination, specifies that when there is a requirement for
automatic actuation of a system, subsystem, train, component, or
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device to fulfill a specific safety function, the item shall be
declared inoperable upon loss of automatic capability.
The procedure goes on to say that in some situations manual operation
of the system, subsystem, train, component, or device may be
considered to replace the lost automatic capability.
This would be
considered compensatory action replacing the lost automatic function
and would need to meet the following criteria:
1.
A procedure or other written instruction is available to direct
the manual operation.
2.
The individual designated to perform the function has been
trained / qualified.
3.
The post accident environment in which the designated individual
must operate is acceptable,
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The response time assumptions of the accident analysis can be
met.
5.
An individual can rcasonably perform the task (strength,
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accessibilit>>.
6.
The sigal or indication which will signify the individual to
perform tne function has been clearly defined, as well as the
method through which it will (can) be connunicated during
accident conditions.
Compensatory measures taken are to be documented on Enclosure 3 to
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The Station Ofrectory, Compensatury Actions To Maintain Operability.
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These actions were not performed.
Given the foregoing, it appears that:
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1)
OMP 2-29 is inadequate in that the procedure is ambiguous
when specifying the operability of the VG system.
The
procedure requires the components to be operable, yet
states they are required only for long term operability.
Huwever, "long term "is not defined.
This was a point of
confusion among the operators queried.
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Station Directive 3.1.14 was not followed as described
above.
The two cases above constitute two of four examples in this report of
inadequate or failure te follow procedures and are identified as a
/iolation of Technical Specification 6.8.1. (413,414/88-34-01)
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e.
On the morning of October 15, 1988 the Catawba Unit 2 operating staff
was notified by secondary chemistry personnel that sample results
indicated that the unit was in Action Level 3.
Action Level 3 is a
secondary chemistry condition described in part when samples reveal
sodium (Na) concentrations greater than 500 ppb (the normal
concentration is less than 20 ppb) or cation conductivity greater
than 7 micro mho/cm (the normal valve is less than 0.8 micro mho/cm).
On the morning in question, cation conductivity was 45 in the B S/G
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and 110 in the D S/G.
The concern with having secondary chemistry out of specification is
steam generator S/G tube corrosion which leads to concerns relative
to tube leaks or ruptures.
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Abnormal Procedure AP-0-A-5500-34, Secondary Chemistry Out of
Specification, specifies the actions to be taken to identy and
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correct the cause of the chemistry problem and to minimize S/G
corrosion.
The procedure specifies the actions to be taken when in
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Action Level 3.
The procedure requires that the operator "Ensure
power level reduced to (less than) 2% within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />." After having
been natified of the situation at approximately 6:15
a.m.,
the
operators began reducing load at 6:20 am,
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The inspectors noted through log book review, however, that reactor
power was not reduced to less than 2% within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by
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the procedure.
The unit was not at 2% power until about 11:50 am or
51/2 hours after notification.
The inspectors questioned the licensee as to why the unit was not
placed in the condition required by the procedure.
The inspectors
were told that 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> was not a realistic time within which to shut
the unit down in a controlled manner given the fact that unit 2 has
the 05 S/G level control problems.
The inspectors asked why the
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procedure had not been changed to reflect a realistic time for unit
shut down, or why the procedure in use on October 15, had not
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undergone a procedure change.
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The licensee stated that the procedure had been under review for
rearly a year and they were awaiting information from the
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Westinghouse S/G owners group relative to the relaxation of the 4
hour requirement. The licensee also stated that a simple pen and ink
change (a temporary procedure change) to an AP is not normally
allow 2d and that a retype would have been required.
The procedure, as written is inappropriate for the circumstance; it
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requires action which according to the licensee would jeopardize a
controlled unit shutdown and enuld result in unwanted safety system
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challenges.
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Given that procedure, AP-0-A-5500-34, is inappropriate for the
circumstances it is considered inadequate and as such constitutes the
third of four examples ir this report of a failure to follow or
inadequate procedures and is violation of the requirements of
TS 6.8.1 (413,414/88-34-01)
4.
Surveillance Observacion (61726)
a.
During the inspection period, the inspector verified plant operations
were in compliance with various TS requirements.
Typical of these
requirements were confirmation of compliance with the TS for reactor
coolant chemistry, refueling water tank, emergency power systems,
safety injection, emergency safeguards systems, control room
ventilation, and direct current electrical power sources.
The
inspector verified that surveillance testing was performed in
accordance with the approved written procedures, test instrumentation
was calibrated, limiting conditions for operation were met,
appropriate removal and restoration of the affected equipment was
accomplished, test results met requirements and were reviewed by
personnel other than the individual directing the test, and that any
deficiencies identified during the testing were properly reviewed and
resolved by appropriate management personnel.
b.
The inspectors witnessed or reviewed the following surveillances:
4296 SWR
SSPS and Reactor Trip Breaker Train "A"
Test
PT/1/A/4330/028
DG 1A Operability Test
PT/1/A/4200/01T
1B CA Pump Head Verification
PT/1/A/4200/01T
Containment Penetration Valve Injection
Water System Test
5.
Maintenance Observations (62703)
a.
Station maintenance activities of selected systems and components
were observed / reviewed to ascertain that they were conducted in
accordance with the requirements.
The inspector verified liccasee
conformance to the requirements in the following areas of inspection:
the activities were accomplishet using approved procedures, and
functional testing and/or calibrations were performed prior to
returning components or systems to service; quality control records
were maintained; activities performed were accomplished by qualified
personnel; and materials used were properly certified. Work requests
were reviewed to determine status of outst6nding jobs and to assure
that priority is assigned to safety-related equipment maintenance
which may effect system performance.
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b.
The inspectors witnessed or reviewed the following maintenance
activities:
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27050 OPS
Inspect / Repair VC/YC Chiller 'B'
Tripping
41478 OPS
Inspect / Repair MSIV
Failure to clo:e
6625 PRF
Inspect / Repair NS pump 2B Breaker
Failure to Close
29118 OPS
Replace Channel 11 Power Supply
c.
On October 6, 1988 the licensee was conducting slave relay testing on
Unit 2 using PT/2/A/4200/09A, Auxiliary Safeguards Test Cabinet
Periodic Test. Section 12.38 tests the ability of the 2B Containment
Spray (NS) Pump to start on ESF signal.
The prerequisites to the
test require the NS pump circuit breaker 2ETB8 to be racked to the
"test" position and the pump suction valve from the refueling water
storage tr' , 2NS-38, to be open.
A test switch simulating an ESF
signal is .omentarily depressed and breaker 2ETB8 is verified to
close.
On October 6, 1988 this section of the procedure was run and
the circui?. breaker failed to close.
Technical Specifications for
Containment Spray automatic act%cion logic and activation relays
requir. 2 channels.
If one ch,nnel is inoperable the unit is to be
placed in Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
In this case the licensee
applied a Technical Specification Interpretation dated December 1,
1987 which states in part Nfailure of the latch device to latch
properly on an SSPS activation relay does not constitute a failure of
the activation channel,
it does, however, render inoperable those
components the latch device actuates."
Procedure PT/2/A/4200/09A is
written to test the actuation relays individually. The licensee was
able to immediately identify the inoperable component as the 2B NS
pump.
The licensee applied TS 3.6.2 which requires the NS pump to be
operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or place the unit in Hot Standby in the
following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Work Request 6625 PRF was written to investigate.
The problem was
isolated to the interlock in the pump start circuitry associated with
2NS-3B being open. The interlock in part ensures that 2NS-38 is open
prior to pump start, making sure a source of water is available. The
interlock consists of one of six sets of contacts on the Rotork
actuator's "add on pack" (A0P).
The A0P contacts are typically used
for permissives, interlocks, torque bypass contacts, or monitor
lights and are different from "primary switch" mechanism contacts,
which are used for torque switch operation and valve position
indicators.
During troubleshooting the technicians stroked the valve several
times and detennined that the A0P contacts did not actuate correctly
each time.
The A0P had apparently been set up in a marginal fashion
such that tolerances allowed the contacts to correctly actuate upon
valve strmng in some random cases, but failed to actuate on others.
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Apparently the last time 2NS-3B had been opened, the primary switch
mechanism actuated correctly when the valve opened and deenergized
the motor actuator, however, the A0P contacts did not actuate and
failed to make up the interlock.
IP/0/A/3820/09, Removal,
Replacement and Field Set up of Rotork Actuators, section 10.5.6
states "A0P switches that are intended to actuate as volve reaches
open end of travel shall be adjusted to actuate just prior to
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actuation of primary switch mechanism open limit switcles".
A
similar requirement exists for switches that actuate upon valve
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closure.
Clearly for the A0P contacts to function properly, they
must actuate prior to the primary switch mechanism contacts, however
there is no apparent reason to actuate "just prior" to the primary
switch mechanism contacts.
The procedure ,1ves no consideration for
tolerances involved with the equioment and provides no amplifying
guidance as to what is meant by "just prior". The procedure appears
to er. courage the technician to set up the A0P as close as possible to
the primary switch mechanism and to leave no margin.
Although the
procedure requires functional checkout of the contacts after setup,
tolerances may result in an A0P contact operating correctly after one
valve stroke, but not in the next.
This is apparently what occurred
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with 2NS-3B.
The safety significance of the incorrectly set AOP is as follows:
The system automatically actuates upon a high high containment
pressure (Sp) ESF signal of 3.0 psig and isolates when pressure drops
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to 0.3 psig. The incorrectly set A0P for 2NS-3B would have prevented
a pump start if a Phase B Containment Isolation signal had been
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initiated manually.
The pump would have started on an automatic Sp
signal or on a manual pump start as the interlock is not present in
these portions of the circuit.
At the inspect,rs request the licensee reviewed previous work
requests to compile a history of A0P related problems.
The licensee
htermined that previous problens requiring A0P adjustments had
occurred on five occasions since early 1987; three involving valve
interlocks and two involving the failure of a monitor light.
On March 27, 1987 unit 2 was shutdown.
On attempting to start
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the Residual Heat Removal (ND) system, hcwever, valve 2ND-36B,
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28 N0 pump hot leg suction; failed to open because the interlock
from 2N1-1368 failed to actuate. Valve 2NI-136B allows ND to
supply flow to the suction of the Safety Injection pumps (NI)
during "piggy back" operation and is required to be shut prior
to opening 2ND-36B.
The AOP for 2Nt-136B was adjusted to
correct the problem.
On December 6, 1987 with unit 1 shutdown operators were unable
to open ' Q-27A, Refueling Water Storage Tank (FWST) Supply to
1A ND pop.
The problem was isolated to the interlock from
1NI-185A, Containment Sump Supply to 1A ND pump.
The interlock
ensures that both valves are not simultaneously opened.
The A0P
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for 1NI-185A was adjusted to correct the problem.
It had
recently been setup after MOVATS testing on November 9,1987.
On October 6, 198o the 2A NS pump breaker failed to close during
slave relay testing.
The interlock requiring 2NS-32A, 2A NS
pump discharge valve, be shut prior to testing the pump had
failed, however, only the slave relay test circuitry was
affected.
The AOP was adjusted to a.or"ect the problem,
l.ater
that day the previously described problem accurred with the 2B
NS pump.
The licensee ini'ially felt the above probler.s to be isolated and
random, however. agreed that the setup procedure was inadequate and
should be revisH to ensure that in the future a margin exists
between A0P contact actuation and primary switch mechanism contact
actuation.
Due to the inadequate setup procedure and history of
occurrences, the inspectors were concerned that the problem could
exist generically.
After further discussions the licensee
prioritized a list of valves containing A0P's with safety related
interlocks and permissives.
The list contains 25 valves on unit 1
and 26 on unit 2,13 of which on each unit are accessible during
power operations.
The licensee is setting up a plan for inspection
and adjustment as neces.ary.
This is identified as Inspector
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Followup Item 414/88-34-04:
Testing and Adjustment of Rotork Add On
Pack Switches.
d.
On the morning of October 11, 1988 at approximately 11:00 AM, the
inspector observed two Instrument and Electrical (IAE) technicians
replacing the Unit 1 protection channel 2, 24 VDC Backup power
supply.
The inspector reviewed work request OPS 29118 under which the work
was being performed.
The inspector noted that the technicians had no
equipment specific electrical prints nor as built cabinet
in+.erconnection diagrams.
Instead they were employing a general
troubleshooting procedure IP-0-A-3890-01, Controlling Procedure for
Troubleshooting and Corrective Maintenance and were referring to a
Westinghouse Tech Manual.
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The inspector was concerned relative to the accuracy of the
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Westinghouse manual. This issue is discu> sed below.
At approximately 1:30 pm that same day the inspector returned to
review the status of the work.
The inspector noted that the
technicians were t. hen performing wor; without the above mentioned
work request, with no procedure, and no prints. The inspector asked
to review the work request and proNdure and was told that the work
package had been lef t back in the office.
At this point, work
stopped while the technicians retrieved the *:auired documents.
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The technicians returned with the work package, and continued to use
the procedure throughout the remainder of the work observed.
A number of concerns were identified with the above evolutions.
The
first was the performance of work without the benefit of a procedure,
prints, or work request.
Technical Specifications 6.8.1 requires that written procedures shall
established, implemented, and maintained covering the activities
referenced in Appendix A of Regulatory Guide 1.33, Revision 2,
February, 1978.
One of the activities referenced is the performance
of maintenance that can effect the perforraance of safety related
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equipment.
The work being performed by the two technicians was on
safety related equipment that can affect the performance of other
safety related equipment.
The failure of the technicians to employ a procedure during the above
mentioned work is a fourth example in this report of a Violation of
the requirements of TS 6.8.1.
(413,414/88-34-01)
Another area of concern, is the fact that on the af ternoon of
October 11, the technicians did not have the work request in their
possession.
The work request is considered to be a "general"
procedure designed to control maintenance, repair and replacement of
equi pment.
A third area of concern is the lack of equipment
specific, as built electrical prints.
The inspector has not completed his review of the failure to have the
work request at the job site, and the lack of electrical prints.
Pending the completion of that review, these areas will be carried as
an Unresolved Item 413/88-34-03:
Lack of Electrical Drawings for
Channel II Power Supply.
6.
Review of Licensee Non Routine Event Reports (92700)
a.
The below listed Licensee Event Reports (LER) were reviewed to
determine if the information provided met NRC requirements.
The
determination included: adequacy of description, verificacion of
compliance with Technical Specifications and regulator / requirements,
corrective action taken, existence of pot (ntial geacric problems,
reporting requirements satisfied, and the
21ative safety
tignificance of each event.
Additional inplant reviews and
d,scussion with plant per;onnel, as appropriate, were conducted for
those reports indicateu sy an (*).
The following LCRs are closed:
413/86-;4 Rev 1.
Two InaJvertent Containment Purge Trips Oue
to Unknown Cause and Procedural Deficiency.
- 413/88-22
Technical Soecification Violation Due to
Failure to Retast a Containmer.t Isolation
Valve.
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_ - -
- - - - _ - . - - _ - - - - - - - - - - - - - - - - - _ - - - - _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - _ - -
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- 414/87-9,1 Rev 1.
Reactor Trip Resulting From a Condensate
,
Transient Oue to Unknown Cause.
e
414/87-24
Main Feedwater Isolation and Auxiliary Feed
Water Pump Auto Start due to Steam Generator
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Overfill Caused by Management "-ficiency.
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- 414/88-13 Rev 1.
Feedwater Isolation Caused by Steam
Steam Generator High Level Due to Valve
Failure and a Personnel Error.
r
414/88-14 Rev 2.
Auxiliary Feedwater Auto Start Due to Loss
of Main Feedwater Pump Turbine Condenser
Vacuum.
b.
On March 9,1988 with anit 2 in Mode 5, stean generators were being
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filled for flushing evolutions.
As the level the 2A steam generator
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approached the high high level trip setpoint, the operator attempted
to close 2CA-62A, Auxiliary Feedwater (CA) Isolation from 2A Motor
,
Oriven CA Puhlp.
The operator also tripped the 2A Motor Driven CA
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Pump, however, was unable to prevent an ESF actuation. The event was
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reported in Licensee Event Report (LER) 414/88-13.
On March 28,
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during the licensee's investigation of the incidcnt, it was
determined that 2CA-62A failed to close during the event and Problem
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Investigation Report (PIR) 2-C88-0143 was written.
The unit was in
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Mode 1 at the time. The valve had apparently failed to close under a
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high differential pressure (dp) d e to the existing CA flow to the 2A
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When the 2A Mowr Driven CA pump was secured and
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the (dp) removed, 2CA-62A fully closed as the operator continued to
press the control board switch.
Section II of the PIR requires an
,
evaluation of the condition for reportability and operability.
The
evaluation was not performed until April 5 and although 2CA-62A had
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failed to close under dp conditions, it concluded that t6e valve was
Proposed resolution of the problem recomended a M0 VATS
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test of the valve to check torque switch settings and part. meters
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against baseline data.
2CA-62A uses a Rotork motor actuator and itt
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safety function is to close within 20 seconds after operator action
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to isolate the 2A steam generator from the 2A CA pump in the event of
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a ruptured steam generator or steam line.
On April 20, Design
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Engineering determined that the failure of 2CA-62A to close was not
an operability concern.
The was based on calculations demonstrating
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that a condition resulting in insufficient CA flow to steam
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generators would not result, nor would additional energy into
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containment be significant.
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On April 27 the unit was in Mode 5 and 2CA-62A was M0 VATS tested and
all settings were detennined to be correct.
On April 28 the valve
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was tested under full dp conditions ind it failed to close.
The
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toraue switch setting was adjusted from 41/4 to 4 3/8 and the valve
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was tested satisfactorily.
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The resident inspectors were concerned with the following:
The
licensee failed to declare 2CA-62A inoperable on March 28 after
discovering that it has not closed upon demand.
The licensee was
unable to produce any tests which demonstrated 2CA-62A operable
between March 9 and the failure that occurred on April 28.
10 CFR 50 Appendix B criterion XVI requires in part that measures be
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established to ensure conditions adverse to quality such as failures
and malfunctions are promptly identified and corrected.
In this case
established measur(s were inadequate and this is identified as a
violation of criterion XVI Appendix B, violation 414/88-34-02:
Failure to take Prompt Corrective Action to Ensure Operability of
aview of the event determined that 2CA-62A failed to close even
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chough the torque switch settings were originally correctly set to
design calculations which specify required thrust output based upon
dp and on assumed packing load (a function of valve stem size).
The
inspectors were concerned with the adequacy of the calculations on
,
the performance of the actuator and its generic implications.
A
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review of design calculations showed a total required thrust of 12112
,
lbs. consisting of a dp component of 1071
lbs. and a packing load
component of 1375 lbs.
A tolerance of
-v, + 15% is specified.
Initial MOVATS settings established on December 4,1987 with closed
torque switch setting at 4 1/4 resulted in 13810 lbs thrust. Testing
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performed on April 28 resulted in 13100 lbs thrust.
The question
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that remains to be answered is why the valve failed with the original
torque switch settings.
The licensee suspects a higher drag
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resistance coming from the valve internals and intends to open and
inspect the valve at the next available opportunity.
The licenso
e
additionally intends to validate its design calculations by
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performing bench testing of valves under maximum dp conditions.
This
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is identified as Unresolved item 414/88-34-03:
Thrust Performance of
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Rotork Actuator for 2CA-62A, pending comnletion of testing and
{
inspection of 2CA-62A.
7.
Follow-up on Previous Inspection Findin5s (92701 and 92702)
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a.
(Closed) Violation 413,414/88-25-01:
Failed to maintain Two Operable
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Channels of \\alve Position Indication for PORY Block Valves.
The
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licensee responded to the violation in correspondence dated
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September 16, 1988.
TS amendments were issued October 6,1988 to
.
require one operable channel of position indicator per valve.
Based
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on this the item is closed.
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b.
(Closed) Inspector Followup Item 413,414/88-19-01:
Clarification of
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the EAL addressing loss of an Engineered Safety Feature (EST).
The
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licensee revised enclosure 4.1 of RP/0/A/5000;1, Classificttion of
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Emergency, to clarify the ambiguity associated when an unusual event
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will be declared upon loss of an ESF.
The revision requires a
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Notificuion of Unusual Event (NOVE) upon loss of an ESF function or
actuation system requiring a power reduction to mc<'e 3 by Technical
Specifications.
The NOUE will be declared at the point a decision is
made to reduce power with the intent to enter mode 3.
Based on this
the ite" is closed.
8.
10 CFR Part 21 Inspection (36100)
(Closed) Part 21-86-03:
Contrometics Actuator with Emergency Override
Operator with Jackscrew Handwheel Units May Suffer Wearing / Fouling of
Threads in Actuator End Caps.
The licensee determined that the subject
dampers are installed in the Auxiliary Building (VA) and Fuel Pool (VF)
Ventilation Systems, however, none of the actuators are equipped with the
emergency override jackscrew / handwheel.
This determination was documented
in an August 18, 1988 memo to N. A. Rutherford, Jr. from T. F. Wyke and
J. F. Reed. This item is, therefore, closed.
9.
Information of High Temperature Inside Containment (TI 2515/98)
The objective of this inspection was to review temperatures and
ventilation inside containment to determine if high temperatures are a
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plant specific problem.
The inspector met with design engineering staff
members on September 8 to review ventilation drawings, temperature
history, detector locations and environmental qualification considera-
tions.
The Containment Ventilation System (VV) i, divided into the lower
Compartnent Subsystem consisting of 4 ?.ir handling units and the upper
compartment subsystem, also with 4 units.
Technical Specification 3.6.1.5
requires the upper containment average temperature be maintained between
75 and 100F and the Iowar containment be maintained between 100 and 120F
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during power operations.
One temperature detector is located at the suction of each of the 4 air
handling units in both upper and lower containment.
The compartment's
temperature is verified daily by computing the average of the detectort'
readings associated with the operating air handling units.
The licensee recorded temperature results at various other points in tha
containment during portions of 1986 and 1987, including high and low
pc ints Of the pressurizer and steam generator cavities.
The resu'ts for
different months of the ycar were sempled and reviewed by the inspectors.
Typically, readings were within the limits with the exception of the steam
generator cavities.
In this portion of the lower containment,
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temperatures typically ranged from 120 to 150'F.
The licensee uses 120*F as the basis for calculating the remaining life
time of envircnmentally goalified equipment. No equipment of this type is
located in the steam generator cavities.
Hydraulic snubbers in this area
(and mechanical snubbers elsewhere) are rated for 285'F.
_--_-_--_-1
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Most of the environmentally qualified equipment is located in lower
containment or the pipe chase area.
Tha licensee was unable to provide
temperature data for the pi
This area, however, is ventilated
with 4150 CFM (design value)pe chase.
by booster fans.
Based upon this review, stagnant areas do net appear to be a significant
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problem and the sensors used to verify containment temperature are
representacive of the average temperature.
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10.
Exit Interview
The ir,spection scope and findings were summarized on October 26, 1988,
,
with those persons indicated in paragraph 1.
The inspector described the
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areas inspected and discussed in detail the inspection findings listed
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below.
No dissenting coments were res.eived from the licensee.
The
licensee did not identify as proprietary any of the materials provided to
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or reviewed by the inspectors during this inspection.
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Item Number
Description and Reference.
413,414/88-34-01
Violation - Failure / Inadequate
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Procedure, four examples (para 3d, 3e
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and 5d)
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413/88-34-02
Unresolved Item - Diesel Generator
with
VG
Compressors
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Operability (para 3d)
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414/88-34-02
Violation
Failure to Take Prompt
t
Corrective Action to Ensure Operability
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of 2CA-62 (para 6b)
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>
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413/88 34-03
Unresolved Item - Lack of Electrical
Drawings for Channel II Power Supply
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(para 5d)
414/88-3/ 03
Unresolved item - Thrust Performance of
Rotork Actuator for 2CA-62 (pr.ra 6b)
414/88-34-04
Inspector Followup Item - Testing and
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Adjustment of Rotork Add on Pack
Switches (para Sc)
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