ML14191A910
| ML14191A910 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 03/11/1988 |
| From: | Fredrickson P, Garner L, Latta R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14191A909 | List: |
| References | |
| 50-261-88-03, 50-261-88-3, NUDOCS 8803280166 | |
| Download: ML14191A910 (16) | |
See also: IR 05000261/1988003
Text
8 REc.
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No.:
50-261/88-03
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
License No.: DPR-23
Facility Name: H. B. Robinson
Inspection Conducted: January 11 -
February 10,
and March 7, 1988
Inspectors:
A I
L. W. G~rner, Senior Resident Inspector,
Date Signed
M. Latta, Resident Inspector,
Date Signed
Contributing
B.
Breslau,.Reactor Engineer
Inspectors:
. J. Kel ogg, Rea tor Engi
er
Approved by: U
/
S /1/
P. E. Fredrickson, Chief
Date Signed
Reactor Projects Section 1A
Division of Reactor Projects
SUMMARY
Scope: This routine,
announced inspection was conducted in the areas of
followup on previous inspection items, operational
safety verification,
surveillance observation, maintenance observation,
system walkdown, onsite followup of events at operating power reactors, onsite
review committee, and natural circulation cooldown.
Results: One violation was identified involving four examples of failure to
operate the plant within the design basis (paragraph 10.c).
An additional
related violation was identified involving failure to identify and correct
conditions adverse to quality as required by 10 CFR 50 Appendix B, Criterion
XVI ( paragraph 10.c).
0
8803280166 80-314
A
05000261
REPORT DETAILS
1. Persons Contacted
Licensee Employees
R'.
Barnett, Maintenance Supervisor,. Electrical
+*G. Beatty, Vice President, Robinson Nuclear Project Department
- C. Bethea, Manager, Training
- H. Bryon, Instructor
R. Chambers, Engineering Supervisor, Performance
0..Crocker, Supervisor, Radiation Control
+*J. Curley, Director, Regulatory Compliance
J. Eaddy, Supervisor, Environmental and Chemistry
R. Femal, Shift Foreman, Operations
W. Flanagan, Manager, Design Engineering
- W. Gainey, Support Supervisor, Operations
P. Harding, Project Specialist, RadiationControl
+*E. Harris, Director, Onsite Nuclear Safety
D. Knight, Shift Foreman, Operations
E. Lee, Shift Foreman, Operations
F. Lowery, Manager, Operations
D. McCaskill, Shift Foreman, Operations
R. Miller, Maintenance Supervisor, Mechanical
R. Moore, Shift Foreman, Operations
+#R. Morgan, Plant General Manager
D. Myers, Shift Foreman, Operations
D. Nelson, Operating Supervisor
M. Page, Engineering Supervisor, Plant Systems
D. Quick, Manager, Maintenance
B. Rieck, Manager, Control and Administration
- D. Sayre, Senior Specialist, Regulatory Compliance
D. Seagle, Shift Foreman, Operations
R. Steele, Shift Foreman, Operations
+#H. Young, Director, Quality Assurance/Quality Control (QA/QC)
Other
licensee employees
contacted included
engineers,
technicians,
operators, mechanics, security force members, and office personnel.
Region II Attendees
- B Breslau
- P Kellogg
NRC Resident Inspectors
+#*L. Garner
+#R. Latta
- Attended exit interview on January 27, 1988
BAttended exit interview on Mbrso 7 , 1988
- Attended exit interview on eari s,
1988
2
2.
Exit Interview (30702, 30703)
The inspection scope and findings were summarized on January,27, February
11,
and March 7, 1988, with those persons indicated in paragraph 1.
The
inspectors described the areas inspected and discussed in detail the
inspection findings listed below. Dissenting comments were not received
from the licensee.
Proprietary information is not contained in this
report.
No written material was given to the licensee by the Resident
Inspectors during this report period.
Note:
A list of abbreviations used in this report is contained in
paragraph 13.
Item Number
Status
Description /Reference Paragraph
261/84-45-01
Open
IFI -
Service Water Degradation
261/88-03-01
Open
UNR* -
Review OT Delta T Safety
Analysis Results
261/88-03-02
Open
IFI -
Review Finalized Transition
Document and Step Deviation Forms
261/88-03-03
Open
IFI -
Review Step Deviation Forms
For-Plant Specific Soak Time
and Subcooling Margin
261/88-03-04
Open
VIOLATION -
Failure to Comply with
Criterion 35 of 10 CFR 50 Appendix A
261/88-03-05
Open
VIOLATION -
Failure to Comply with
Criterion XVI of 10 CFR 50 Appendix B
- Unresolved items are matters about which more information is required to
determine whether they are acceptable or may involve violations or
deviations.
3.
Licensee Action on Previous Enforcement Matters (92702)
Not inspected
4.
Licensee*Action on Previously Identified Inspection Items (92701)
a.
(Open) IFI 261/84-45-01
Service Water Degradation
Inspection in this area has previously been reported in Inspection
Reports nos. 261/84-45, 261/84-48, 261/85-12, 261/85-22, 261/86-12,
261/87-03 and 261/87-35. This report documents the December 1987,
3
weld control
group radiographic examination results and the
subsequent actions taken by the licensee in response to the indicated
increased MIC growth rate.
During the week of December seventh, 29 service water pipe welds were
radiographed. Results available on January 5, 1988, indicated that
the average annual growth rate for 6 inch diameter pipe had
increased from 5/8 inch to 1.6 inches circumferentially. None of the
welds had MIC lengths greater than the structural limit.
Based on
the new growth rate, all welds which were projected to exceed 9
inches by the scheduled August, 1988, refueling outage were
radiographed during January 11 -
15,
1988.
Weld 4-SCH-3, associated
with containment fan cooler unit HVH-4,
was found to have exceeded
the structural limit of 10.19 inches.
The fan unit was declared
inoperable, the weld was sleeved and HVH-4 returned to service on
January 20, 1988.
During January 22
-
February 8, 1988, all welds in the auxiliary
building service water system which are considered susceptible to MIC
and which were unsleeved were radiographed.
One additional weld on
HVH-4 was found to have slightly exceeded the structural limit and
was sleeved. Other welds which exceeded the administrative criteria
for sleeving, e.g.
one half the structural limit or which might
exceed the structural limit by the upcoming refueling outage, were
also sleeved. Thus,
of the 272 original welds in the auxiliary
building, 144 welds are now sleeved. Service water pipe welds inside
containment are already sleeved.
The December 1986 radiographic examination indicated that sleeved
welds exhibited growth in the sleeve-to-pipe fillet weld heat
affected zone.
A sampling of such weld joints revealed that growth
is continuing in these joints.
Based
upon this fact and the
increased growth rate, the licensee is considering changes to the MIC
surveillance program. A new program with increased emphasis on both
the unsleeved welds in the auxiliary building and the fillet weld
heat affected zones inside containment
as well
as a revised
examination frequency is under evaluation.
A revised program should
be ready for implementation by early Spring,
1988.
The resident
inspectors and/or Region II inspectors will review the program when
available.
b. NRC Information Notice No. 88-01, Safety Injection Pipe Failure
The inspectors reviewed the subject document to ascertain whether or
not the document is relevant to the plant's SI design.
The three
positive displacement charging pumps are not part of the SI system.
The three SI pumps which would inject through the BIT into the cold
legs have a shutoff head of 1700 psig. This shutoff head is well
below the normal RCS operating pressure of 2235 psig. Hence, leaking
into the RCS via leaking valves with the associated thermal cycling
of piping is not considered a feasible event for this design.
No violations or deviations were identified within the areas inspected.
4
5. Operational Safety Verification (71707)
The inspectors observed licensee activities to confirm that the facility
was being operated safely and in conformance with regulatory requirements,
and that the licensee management control system was effectively dis
charging its responsibilities for continued safe operation. These activi
ties were confirmed,
by direct observations,
tours of the facility,
interviews and discussions with licensee management and personnel,
independent verifications of safety system status and limiting conditions
for operation, and reviews of facility records.
Periodically, the inspectors reviewed shift logs, operations records, data
sheets, instrument traces, and records of equipment malfunctions. Specific
items reviewed include control room logs, maintenance work requests,.
auxiliary logs,
operating orders,
standing orders,
jumper logs,
and
equipment tagout records. The inspectors routinely observed shift changes
to verify that continuity of system status was maintained and that proper
control room staffing existed. The inspectors also observed 'that access
to the control room was controlled and operations personnel were carrying
out their assigned duties in an attentive and professional manner.
The
control room was observed to be free of unnecessary distractions. The
inspectors performed channel checks, reviewed component status and safety
related parameters, including SPDS information, to verify conformance with
the TS.
During this reporting interval, the inspectors verified compliance with
selected limiting conditions for operation.
This verification was
accomplished by direct observation of monitoring instrumentation, valve
positions, switch positions, and review of completed logs and records.
The inspectors verified the axial flux difference was within the values
required by the TS.
Plant tours were routinely conducted to assess the operability of standby
equipment and general plant/equipment conditions, such as the existence of
unusual fluid leaks, excessive pipe vibrations, pipe hanger and seismic
restraint abnormalities,
various valve and circuit breaker positions,
equipment clearance tags,
component status verifications, instrument
calibrations, operability of fire fighting equipment including fire
alarms, suppression equipment, and emergency lighting equipment.
The inspectors determined the following:
plant personnel
including
operation staff members were knowledgeable of plant conditions including
equipment out of service and maintenance activities, that appropriate
radiation controls were properly established and implemented,
and that
fire hazards and combustible materials were properly controlled. The
.
inspectors also selectively examined radiation protection instrumentation
such as area monitors, friskers, and portal monitors to verify operability
and adherence to calibration frequency requirements.
Plant housekeeping
and contamination control were observed to be adequate.
5
On
February 2,
1988 the inspectors toured containment.
In general,
conditions of equipment were adequate.
Some deficiencies which did not
effect operability were observed and reported to the
licensee for
appropriate action.
No violations or deviations were identified within the areas inspected.
6. Physical Protection (71707)
In the course of the monthly activities, the inspectors included a review
of the licensee's physical security program.
The inspectors verified by
general observation,
perimeter walkdowns and interviews that measures
taken to assure the physical protection of the facility met current
requirements. The inspectors visited the central and secondary alarm
stations at various times during the reporting period to ensure that they
were properly staffed and operational.
The performance of various shifts of the security force was observed to
verify that daily activities were conducted in accordance with the
requirements of the
security plan.
Activities inspected included
protected and vital areas,
access controls,
searching of personnel,
packages and vehicles, badge
issuance and retrieval,
escorting of
visitors, patrols, and compensatory measures. In addition, the inspectors
routinely observed protected and vital area lighting and barrier
integrity.
During this inspection period a Regional QA effectiveness inspection team
identified that two security audits, QAA/0020-86-01 and QAA/0020-87-01,
contained audit checklist items which potentially specified safeguards
information.
The concern was identified to the appropriate regional
personnel.
Followup action by Region II security specialists is currently
planned.
No violations or deviations were identified within the areas inspected.
7. Monthly Surveillance Observation (61726)
The inspectors observed certain surveillance related activities of
safety-related systems and components to ascertain that these activities
were conducted in accordance with license requirements.
The inspectors
determined that the surveillance test procedures listed below conformed to
TS requirements, that all precautions and LCO's were met,
and that the
surveillance test was completed at the required frequency. The inspectors
also verified that the required administrative approvals and tagouts were
obtained prior to initiating the test, that the testing was accomplished
by qualified personnel in accordance with an approved test procedure and
that the required test instrumentation was properly calibrated.
Upon
completion of the testing, the inspector observed that the recorded test
data was accurate, complete and met TS requirements; ensured that test
discrepancies were properly rectified; and independently verified that the
6
systems were properly returned to service.
Specifically, the inspectors
witnessed/reviewed portions of the following test activities:
a. OST-611 (revision 6) Low Voltage Fire Detection and Actuation System
Zones 1,2,3,4,5,6 and 7
The purpose of this semi-annual test is to provide an operational
verification of the detection capability of the pyrotronics fire
detection system as required by TS Section 4.14.1.1.b.
During the
conduct of this test several discrepancies were identified including
the failure of detector 1B2 to operate. The inspectors determined
that appropriate compensatory
measures were taken including the
posting of a fire watch within one hour and that corrective actions
were initiated to repair the subject deficiencies.
The inspectors
will continue to monitor this activity during subsequent inspections.
b. OST-905 (revision 9) Radiation Monitoring System
This test is conducted daily in order to verify the operability and
response of the radiation monitoring system as stipulated in TS Sections 4.1.1, 4.19.1,
and 4.19.2.
Specifically, the inspectors
determined that all operable radiation monitors had power available,
that the required
monitors
and their associated pumps
were
functioning, and that the source check values were properly recorded.
No deficiencies were identified during the conduct of this test.
c. OST-007 (revision 4) Nuclear Instrumentation Comparator Channel
The inspector- witnessed the operational verification of the alarm
setpoints of the power range channels. In particular, the inspectors
determined that subject channels and their associated comparitor
bistables were within the required setpoint tolerance of two plus or
minus 0.5 of their full scale value by comparing the deviation
between the power range channel being tested and lowest power range
channel not being tested. The inspectors confirmed that the required
control room annunicators responded correctly to the test conditions
and that over power differential temperature and over temperature
differential temperature reactor trip bistables were reset to the
normal mode.
No deficiencies were identified during the conduct of
this test.
d. OST-001
(revision
18)
Nuclear Instrumentation Source Range,
Intermediate Range, Power Range Weekly.
This test performs surveillances required by TS Table 4.1-1, items 1
through 3.
On January 20,
1988,
OST-001 was being performed in
preparation for startup. The inspectors observed that the operator
had recorded a value for an intermediate range monitor which exceeded
the acceptance criteria without noting the exception.
The operator
stated that they are not required by procedure to flag any out of
tolerance value and the acceptance criteria would be reviewed by the
7
shift foreman prior to final signoff.
The inspectors observed that
the operator continued with the procedure and did not report the out
of tolerance value to the shift foreman until shift turnover,
approximately an hour after the condition was found.
Technical
Specification
requirements
were
not
exceeded
because
the
instrumentation was not required to operable in that mode.
No violations or deviations were identified within the areas inspected.
8. Monthly Maintenance Observation and.Maintenance Program Evaluation
(62703, 62704, 62705)
The
inspectors observed several maintenance related activities of
safety-related systems and components to ascertain that these activities
were conducted in accordance with approved procedures, TS and appropriate
industry codes and
standards.
The inspectors determined that these
activities were not violating LCO's and that redundant components were
operable. The inspectors also determined that the procedures used were
adequate to control the activity, that QC hold points were established
where required, that required administrative approvals and tagouts were
obtained prior to work initiation, that proper radiological controls were
adhered to, that appropriate ignition and fire prevention controls were
implemented,
and that replacement parts and materials used were properly
certified.
The
inspectors confirmed that these
activities were
accomplished by qualified personnel using approved procedures, and that
the effected equipment was properly tested before being returned to
service.
In particular the inspectors observed/reviewed the following
maintenance activities:
a. MST-552 (revision 3) Turbine Redundant Overspeed Trip System Testing
This test is conducted monthly in accordance with TS requirements in
Table 4.1-1. The inspectors observed that the following surveillance
test acceptance criteria were satisfied:
Voltages were within the specified tolerance
Overspeed test potentiometer setting
remained within the
specified allowable ranges
Proper indications were observed on the test and
failure lamps
Required operation of the overspeed trip system logic occurred
as verified by
the correct operation of all
test light
indications.
b.
MST-014 (revision
14)
Steam Generator Pressure Protection Channel
Testing
This test. confirms operability of the steam generator pressure
protection channels II, III, and IV.
The successful completion of
8
this surveillance test satisfies the requirements of TS table 4.1-1,
item 24.
For those portions of the surveillance test observed, the
inspectors confirmed that the annunciators gave the proper status,
that the associated alarms responded
as required,
and that the
specified test voltages were within the
required tolerance.
Subsequent to this maintenance activity, the inspectors determined
that the required processing points for the ERFIS computer were
correctly returned to service.
c. MST-021 (revision 1) Reactor Protection Logic Train "B" at Power
The inspectors observed the adequacy of communications between the
reactor protection logic panel and the control room as well as the
conduct of the individuals involved in the surveillance test.
The
inspectors determined that the logic network de-energized the under
voltage coil for the B reactor trip breaker for
each logic
combination specified in the test procedure and that the appropriate
annunciator lights and alarms were received on the reactor turbine
generator board.
The inspectors also reviewed several outstanding work requests and the
licensee's automated maintenance management tracking system to determine
that the licensee was giving priority to safety-related maintenance and
that a backlog which might affect performance was not developing.
No violations or deviations were identified within the areas inspected.
9.
ESF System Walkdown and Monthly Surveillance Observation (71710,61726)
The inspectors verified the operability of an engineered safety features
system by performing a walkdown of the accessible portions of the SI
system.
The inspectors confirmed that the system lineup procedures
matched plant drawings and the as-built configuration.
The inspectors
verified the absence of equipment conditions and items that might degrade
performance such as loose pipe supports, the presence of debris or loose
materials,
and unauthorized jumpers
or evidence of rodents inside
electrical and instrumentation cabinets. Valves were verified to be in
the proper position with power available and locked as appropriate. Local
and remote indications were verified to be consistent.
The inspection also included observation of the successful completion of
OST-151, Safety Injection System Component Test, revision 22, for SI pumps
B and C. The inspectors verified that the differential pressure and pump
bearing vibration amplitude met acceptance criteria, that all components
associated with the subject SI pumps appeared to functioning as designed,
and the system was properly returned to service.
No violations or deviations were identified within the areas inspected.
9
10.
Onsite Followup of Events at Operating Power Reactors (93702, 37701,
92700)
a. Potentially Non-conservative OT Delta T Trip Setpoint
On December 12,
1987, the licensee determined that an error existed
in the safety analysis used to determine the OT Delta T trip setpoint
for the present core load (cycle 12).
The analysis performed by
Advanced Nuclear Fuels improperly utilized information contained in
FSAR Table 15.0.7-1. Advanced-Nuclear.Fuels had incorrectly assumed
that the table's OT Delta T nominal time delay of 2.3 seconds was the
total time for transport of fluid from the manifold scoops to the
RTD's,
response of the RTD's and signal processing time till
the
reactor trip breakers open. The 2.3 seconds represent only a portion
of this total time. The total value should be approximately 4.5
seconds.
The licensee is in the process of determining the exact
value.
Completion is expected by early March.
In the interim, the
licensee, after consulting with Westinghouse and Advanced Nuclear
Fuels, determined the maximum upper limit on the desired delay time
is 6 seconds.
Using 6 seconds, a new value for K1,
a constant used
in the OT Delta T trip setpoint equation,
was calculated. . The
revised K1 constant was implemented on December 12,
1987,
by plant
modification M-950.
Use of too small of a time delay would result in the analysis
indicating that an event terminated by the OT Delta T trip would end
earlier and potentially with less consequences than it
might in
actuality. The incorrect time delay was used in accident analysis
for the following events; 1) loss of external load, 2) uncontrolled
rod withdrawal and 3) rod drop with turbine runback. The licensee is
in the process of determining if
the error resulted in operation
outside the safety analysis described in the FSAR.
This item is considered as an unresolved item: Review OT Delta T
Safety Analysis Results (50-261/88-03-01).
b. Turbine Trip/Reactor Trip
Due
to Failed Component in Turbine
Electro-Hydraulic Control System
On January 19,
1988, Unit 2 experienced a turbine trip/reactor trip
from approximately
66% power as a result of low autostop oil
pressure.
Reactor power
had been reduced to test the turbine
overspeed trip feature of the turbine electro-hydraulic control
system in accordance with a monthly operations surveillance test
OST-551. All safety systems operated as designed including auxiliary
feed water which was
secured following normalization of steam
generator levels. As determined in the post trip review the combined
effects of a leaking relief valve (LO-57) and the lifting of a second
relief valve (LO-58)
during the pressure transient that accompanies
reseting of the turbine trip caused low autostop oil pressure to the
interface valve. This allowed the interface valve to open (venting
the governor hydraulic fluid) which by design caused all of the
turbine steam control, stop, intercept, and reheat valves to close.
10
Following this event both of the original autostop oil pressure
relief valves,
LO-57 and LO-58,
were replaced and OST-551
was
performed to provide post maintenance verification of the repair.
The inspectors witnessed the performance of this surveillance test
and determined that the overspeed trip valve operated properly and
the autostop oil pressure was within the expected range.
Subsequent to this testing the inspectors witnessed the unit startup
from hot shutdown at no-load T-avg to critical,
as controlled by
general procedure GP-003 (revision 15), Normal Plant Startup From Hot
Shutdown to Critical.
The inspectors determined that all required
procedural prerequsites had been performed and that the expected
critical boron concentration was within the allowable difference
between the estimated critical position and the actual critical
position. The unit was synchronized to the grid on January 19, 1988.
C. Single Failure Design Deficiency
On January 28,
1988, during development of a response to an NRC to
licensee letter, subject, Request for Additional Information Safety
Injection Pump B Auto Transfer Scheme,
dated January
14,
1988,
engineering personnel determined that a single failure of either
battery could result in only one SI pump being available to mitigate
a design basis event (see
scenario 1 below).
A PNSC
review
determined at 5:00 p.m.
that an unanalyzed condition existed.
A
plant shutdown at 10% per hour was initiated at this time such that
the plant could be in hot shutdown in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> as required by TS
action statement 3.0. One hour notification was made pursuant to 10
CFR 50.72.b.1.ii.A at 5:49 p.m.
Review of the normal
breaker
configuration for powering the B SI
pump from either of the two
emergency buses revealed that realignment of the normal
breaker
configuration would prevent the problem.
A procedure change was
made, the breakers were realigned, and the shutdown was terminated at
40% of full power at 11:43 p.m. Full power operation was resumed at
5:35 a.m. on January 29.
As a result of a subsequent review by the NRC on January 29, the
licensee was verbally requested by the Senior Resident Inspector at
approximately 11:00 a.m.
to provide information concerning plant
response to certain other types of faults in the-electrical system
which could also have a potential for resulting in automatically
starting only one SI pump.
One of the questions dealt with what
effect a loss of the A battery bus would have on EDG A after having
successfully loaded, i.e. SI pumps A and B, sequenced onto it. While
preparing an answer to this and other questions, another single
failure was identified which, with the normal plant configuration,
would also result in only one SI pump being automatically available
(see
scenario 4 below).
At that time plant management decided that
another procedure fix, though available, was unacceptable and elected
to shut the unit down until a comprehensive single failure review
could be performed and appropriate corrective actions taken.
TS
11.
Action Statement 3.0 was re-entered at 1:25 p.m.
and the unit was
placed in hot shutdown at 8:46 p.m.
The NRC was notified at 2:10
p.m.
in accordance with 10 CFR 50.72.b.l.ii.A.
At the end of the
report period the unit was in cold shutdown.
By the end of the report period four scenarios had been identified
which required plant procedure or equipment changes.
Two additional
items were also being evaluated, which included tie bus breaker
coordination and the effect of a diesel generator voltage regulator
failure. Resolution of the latter items will be discussed in a
subsequent inspection report.
A brief description of the four
confirmed scenarios follows:
1. Breaker Misalignment El-E2 Bus Cross Tie
The loss of the A battery bus would result in El not being
powered (EDG A would not start). Also no control power would be
available to open the normally closed El to El-E2 breaker.
Thus,
the El to El-E2 breaker interlock to the E2 to E1-E2
breaker would
prevent
E2
from
powering
the
El-E2 bus.
Therefore, both SI pumps A and B would be inoperable.
The loss
of the B battery bus would result in E2 not being powered (EDG
B would not start) and control power would not be available to
close the normally open B SI pump breaker.
Consequently, SI
pumps B and C would be inoperable.
2. Train A Safeguards Sequence Interlock with Train B Safeguards
Sequencer
Normally, the B SI pump which is powered from the El-E2 bus is
preferrentially selected to El by a relay in the A train which
prohibits the B train from closing the E2 to E1-E2 breaker if A
train has been actuated. This interlock relay is in parallel
with the sequencing relay which initiates closure of the A SI
pump and El to El-E2 bus breakers.
Thus a failure of the
sequencing relay would result in A SI pump not starting and the
absence of power to El-E2 from El.
At the same time, the
interlock relay would actuate, thereby, locking out the B train
from powering El-E2 from the other bus,
E2.
Similarly two SI
pumps, A and B, would not auto start.
4.
Loss of EDG Field Flash Circuitry During LOOP with SI Conditions
After successful completion of sequencing of loads onto El due
to an SI coincident with a LOOP,
the equipment has aligned
itself in the same configuration as described in scenario 1
except that it
is being powered by the EDG's.
The loss of
battery bus A would then result in loss of excitation to EDG A.
The loss of EDG A would cause a similar situation as described
in scenario 1.
12
5.
Loss of DC Control Power to El or E2 Emergency Buses
DC control power to the El and
E2 bus breaker are separate
circuits from the respective train A and B safeguard circuits.
The loss of DC control power during the sequencing onto El or E2
would result in the safeguard train interlocks responding as
though the loads had properly
sequenced onto El
and
E2.
However,
since DC control power must be available to close
breakers, the loads would not have sequenced onto the effected
bus.
The result is similar to the sequencer relay failure
discussed in scenario 2. Since loss of DC control power is a
detectable
occurrence, this
scenario
is feasible
only
immediately preceding an SI or within the first 20 seconds after
an SI.
After 20 seconds,
two SI pumps would already have
sequenced onto the emergency bus and loss of breaker control
power would not result in breakers tripping.
The above scenario numbers and titles are from a licensee to NRC
letter dated February 12,
1988,
subject,
Commitments to Resolve
Concerns Regarding Safety Injection System Operability.
Scenario 3
described in the February 12,
1988,
letter was determined not to
exist because of the way in which wiring was terminated to power
sources.
The time the plant has operated in the configuration
described by scenario 1 has not been determined in that scenario 1.
did not involve hardware changes. However,
scenarios 2, 4, and 5
have existed since initial licensing of the plant.
At
the end of the report period,
Modification-947,
Pump
Availability Upgrade, had been,installed and tested per Special
Procedure-796, Verification of SI Pump Availablility and Safeguards
Sequencer Functions, to correct the design deficiencies identified by
the above scenarios.
Two regional
inspectors assisted by the
resident
inspectors
witnessed
the
performance
of
Special
Procedure-796.
The
review of the technical
adequacy of this
procedure
and
corresponding
observations
made
during
its
implementation are documented in Inspection Report No. 50-261/88-05.
Manual initiation of a second SI pump,
e.g.
SI pump B, for the
postulated four scenarios is available in the El-E2 bus room, located
immediately below the control room. The Westinghouse style DB-50 and
DB-75 breakers,
the SI
pump B breaker and the El-E2 bus supply
breakers respectively, can be tripped by actuating a mechanical trip
button located on the breaker and can be closed by inserting a bar
into a slot on the front of the breaker and pushing the contacts into
the latched position. Thus, for the four scenarios, the ability of
the operating crew to potentially mitigate the accident was never
lost. However, because of the uncertainty associated with whether or
not operator actions would or could be timely, existing safety
analysis does not take credit for operator actions.
13
As described above,
the four scenarios (Nos.
1, 2, 4 and 5)
constitute conditions in which a single failure would result in only
one SI pump automatically starting to mitigate the consequences of an
accident. Operations with only one SI pump is outside the design
basis of the plant and thus the SI system would not.meet the ECCS
criteria of 10 CFR 50.46.
FSAR Table 6.3.2-8, Single Failure
Analysis -
Safety Injection
System,
states that the
safety
evaluations are based
on operation of two SI pumps.
The four
scenarios constitute four examples of a violation: Failure to Operate
Plant Within the Design Basis (50-261/88-03-04).
Furthermore,
the failure to identify the additional three single
failure scenarios (Nos.
2, 4 and 5) after entering
TS Action
Statement 3.0 on January 28,
1988 is a violation of 10 CFR 50,
Appendix B, Criterion XVI.
Failure to Promptly Identify Conditions
Adverse to Quality (50-261/88-03-05).
Two violations were found within the areas inspected.
11.
Onsite Review Committee (40700)
The inspectors evaluated certain activities of the plant nuclear safety
committee to determine whether the onsite review functions were conducted
in accordance with TS and other regulatory requirements.
In particular,
the inspectors attended the special PNSC meeting held on January 19, 1988,
concerning the turbine trip/reactor trip which occurred while plant
personnel were performing OST-551. It was ascertained that provisions of
the TS dealing with membership, review process, frequency, qualifications,
etc., were satisfied, and that the previous meeting minutes were reviewed
to confirm that decisions and recommendations were accurately reflected in
the minutes.
The inspectors also followed up on selected previously
identified
PNSC
activities to independently confirm that corrective
actions were progressing satisfactorily.
No violations or deviations were identified within the areas inspected.
12.
Natural Circulation Cooldown (25586)
During this inspection period, the licensee's actions to implement Generic
Letter 81-21,
Natural Circulation Cooldown were reviewed.
This review
included the following documents:
TI-200 Rev 22 Plant Operator Requalification Program
TI-201 Rev 18 Plant Operator Replacement Training Program
TI-203 Rev 11 Senior Reactor Operator Replacement Training Program
TI-301 Rev 19 Training Documentation
TI-303 Rev 14 Dissemination of Information
TI-902 Rev 5 Instructor Requalification Program
TI-906 Rev 11 Training Records
14
EOP Lesson Plan for EPP-5
EOP Lesson Plan for EPP-6
EPP-5 Rev 1 Natural Circulation Cooldown
EPP-6 Rev 1 Natural Circulation Cooldown with Steam Void in Vessel
WOG ES-0.2 LP-Rev 1 Natural Circulation Cooldown
WOG ES-0.4 LP-Rev 1 Natural Circulation Cooldown with Steam Void in
Vessel
WOG Background Information for ES-0.2 LP-Rev 1
WOG Background Information for ES-0.4 LP-Rev 1
WOG Emergence Response Guidelines-Executive Volume Rev 1
RO Training Records
SRO Training Records
The inspectors determined from their review of the training records, that
the training includes both classroom and simulator training on natural
circulation cooldown.
The above training is included in RO and SRO
certification
training
and in the operator retraining programs.
Additionally, the procedures were reviewed to ensure they followed the WOG
guidelines with respect to step content, specific plant parameters
had been added, cooldown rates, subcooling temperature limitations, hold
points for reducing head temperatures, and step deviations are documented.
During the review the inspectors noted that the Procedure Generation
Package forwarded by the licensee on July 2,1984, contains in Section
II.E.
Conversion Method Documentation,
a statement that an
ERG/EOP
Transition Document was created to document and track the conversion
This document was to contain a list of the
differences between the ERG LP reference plant and HBR,
step deviation
forms and derivations for the instrument values used in HBR EOP's.
The
step deviations forms were to be used to explain any variance between a
HBR step and a WOG step.
At the time of this inspection, the step
deviation documents were not available for review and interviews with
personnel indicated that not all had been generated.
This will be an
inspector followup item: Review the Transition Document and the Step
Deviation Forms (50-261/88-03-02).
It was also noted that a deviation from the WOG was contained in EPP-5
step 22 in that 190 degrees of subcooling is called for vice the 200
degrees in the WOG and the soak time was 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> vice the 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> in the
WOG. Additionally, an earlier SER dated Sept 27,
1983 indicated a soak
time of 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> and 200 degrees of subcooling was required. This will be
an inspector followup item: Review the Step Deviation Forms for Plant
Specific Soak Time and Subcooling Margin. (50-261/88-03-03)
EPP-5 and EPP-6 appear to be almost verbatim rewrites of the WOG with very
little plant specific information other than temperatures,
pressures,
levels and operating procedure references.
No specific plant information
was included for several steps in these procedures. Additionally, step 9
of EPP-5 requires pressure less than 1950 psig and step 11 requires
pressure at 1950 psig.
Steps 5 and 6 of EPP-6 contain
similar
inconsistencies. Steps 7, 13, and 17 of EPP-6 do not contain instructions
to place the charging and letdown controls in manual although these
15
instruction are recommended in the WOG. The need for enhancements in this
area was discussed with the Training Manager.
No violations or deviations were identified in this area.
13.
List of Abbreviations
Auxiliary Feedwater System
AVG
Average
BIT
Boron Injection Tank.
Component Cooling Water System
CFR
Code of Federal Regulations
Direct Current
Emergency Operation Procedures
End Path Procedures
ERFIS
Emergency Response Facility Information System
Emergency Response Guidelines
Final Safety Analysis Report
GL
Generic Letter
HBR
H. B. Robinson
Health Physics
Inspection and Enforcement
,IFI
Inspector Followup Items
LCO.
Limiting Conditions for Operations
Loss of Coolant Accident
Lesson Plan
Microbiologically Induced Corrosion
Maintenance Surveillance Test
NRC
Nuclear Regulatory Commission
OST
Operations Surveillance Test
OT Delta T
Overtemperature Delta Temperature
PRZR
Pressurizer
Reactor Coolant Pump
REV
Revision
Reactor Operator
Systematic Assessment of Licensee Performance
Small break Loss of Collant Accident
Safety Evaluation Report
Safety Injection
SPOS
Safety.Parameter Displays Systems
Senior Reactor Operator
Service Water System
TI
Training Instruction
TS
Technical Specification
mUNR
Unresolved Item
Westinghouse Owners Group