ML17058A673
| ML17058A673 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 03/07/1991 |
| From: | Meyer G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17058A672 | List: |
| References | |
| 50-220-91-02, 50-220-91-2, 50-410-91-02, 50-410-91-2, NUDOCS 9103220147 | |
| Download: ML17058A673 (44) | |
See also: IR 05000220/1991002
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos'.:
Docket Nos.:
50-220/91-02
50-410/91-02
50-220
50-410
License Nos.:
'PF-69
Licensee:
Niagara Mohawk Power Corporation
301 Plainfield Road
Syracuse,
New York 13212
Facility:
Location:
Dates:
Nine Mile Point, Units
1 and 2
Scriba, New York
January 4 through February 15, 1991
Inspectors:
W. A. Cook, Senior Resident Inspector
R. R. Temps, Resident Inspector
R. A. Laura, Resident Inspector
M. S. Miller, Reactor Engineer
N. S. Perry, Resident Inspector - Ginna
C. E. Sisco, Operations Engineer, DRS
D. J Vito, Proj
t Engineer, DRP
Approved by:
lenn W. Meyer, Chief
Reactor Projects Section N
. 1B
Date
2
Ins ection Summar:
This inspection report documents routine and reactive inspections during day and backshift hours
of activities
including:
plant
operations;
radiological
protection;
and
surveillance
and
maintenance.
~Result:
One violation was identified involving the improper procedure revision and implementation of
an Appendix J exemption at Unit 1.
One non-cited violation was identified at Unit 1 involving
improper setting of emergency
condenser
isolation setpoints.
One'non-cited
violation was
identified at Unit 2 involving surveillance testing of source range monitor rod block functions
during refueling.
Executive
ummar
'ine Mile Point Combined Inspection Report
Nos. 50-220/91-02 and 50-410/91-02
PLANTOPERATIONS: Operator performance at Unit 1 was satisfactory during this inspection
period.
Operator response
to the February 5, 1991 recirculation pump trip was good and their
prompt and conservative actions to minimize the pressure transients due to turbine control system
problems were observed to be satisfactory.
Unit 2 operator performance was also assessed
to
be satisfactory during this inspection period.
Outage completion and unit start-up activities were
observed, including special turbine testing, and operator command and control ofthese evolutions
was satisfactory.
Operations staff response
to the electro-hydraulic system leak on 1/23 was
good, particularly in rapidly reducing reactor power and securing steam to the condenser prior
to any automatic protective function actuations.
SURVEILLANCEAND MAINTENANCE: Various surveillance and maintenance activities
were observed
or reviewed
during this inspection
period
and
no specific problems
were
identified.
Actions at Unit
1 to address
Generic Letter 89-13 regarding service water system
issues were determined to be thorough and timely. Turbine torsion testing observed at Unit 2
was considered well planned and executed.
The inspectors identified a Non-Cited Violation after
review of the Unit 2 source range monitor rod block surveillance test Technical Specification
(TS) violation, in accordance with the NRC Enforcement Policy.
ENGINEERINGANDTECHNICALSUPPORT:
Several unresolved items were reviewed and
closed by the inspectors.
One unresolved
item involving the Unit
1 emergency
condenser
isolation setpoint TS violation (LER 90-22) was reviewed and the inspectors identified a Non-
Cited Violation. Inspector followup of an unresolved item involving the implementation of an
Appendix J exemption identified a violation ofprocedural revision and review requirements.
The
inadequate
procedure
revision
resulted
in conflicting operating
and
emergency
operating
procedures
and was evidence of a poor licensing staff and station staff interface.
A detailed review of the Unit 2 Safety Parameter
Display System (SPDS) modification was
conducted
and the inspector concluded
that Niagara Mohawk had satisfactorily addressed
the
Operating License Condition C. (8) requiring the SPDS to be operational following the first refuel
outage.
SECURITY AND SAFEGUARDS:
The inspectors
considered
the contingency plans and
heightened security measures
in response
to the increased threat of terrorist activities due to the
Persian Gulf War to be satisfactory.
0
DETAILS',0.
PLANT OPERATIONS
1.1
Unit 1
At the beginning of the report period, the Unit 1 reactor was in cold shutdown to repair main
steam
isolation valve (MSIV) 01-02
and
to identify and repair the
sources
which were
contributing to an increasing drywell leakage rate.
Repair of the MSIV 01-02 was discussed in
Inspection Report 50-220/90-10.
The unit restarted and the turbine synchronized to the grid on
January 9, 1991.
The
plant
ope'rated
at
power
until it automatically
scrammed
on
February
12, 1991, due to a pressure oscillation from a turbine control valve going partially
closed.
Based on the estimated repair time and other factors, the plant manager decided to enter
the mid-cycle surveillance ou'tage, originally scheduled
to commence on March 1, 1991
~
On February 11, 1991, the Region I Regional Administrator closed Confirmatory Action Letter
88-17, Supplement
1.
A.
Following repair of MSIV 01-02 and satisfactory post-maintenance
and local leak rate
testing,
the Unit
1
reactor
was
taken critical on January 9, 1991.
The generator
was
synchronized
to the grid'on the following day and
subsequently
increased
to full power.
Maintenance
repairs to correct drywell leakage
appeared
effective as evidenced
by the low
leakage rate observed following the startup (( 0.5 gpm).
B.
On February 5, 1991, the motor generator (MG) set for the 12 reactor recirculation pump
(RRP) tripped due to a ground.
This initiated a down-power transient on the plant.
Operators
responded
to the event, power was stabilized and later brought back up to 87%.
In three-loop
operation,
the unit Technical
Specifications
(TS) impose
a limit of 90%
reactor power.
Following repairs to the RRP MG set, the 12 RRP was restarted on February 7, 1991 and four-
loop operation recommenced.
The inspector determined that operator response to the event was
proper and the appropriate TS limits and procedure requirements for idling and restoring 12 loop
were followed.
Assessment of the repairs to the MG set are discussed in Section 2.1.A of this
report.
C.
On January 25, 1991, small power oscillations as a result of reactor pressure oscillations
were observed.
Reactor power was reduced slightly and the condition cleared.
Over the
following two days, the condition repeated itself intermittently. Initial troubleshooting efforts
focused on the low oil level for the turbine's hydraulic control system and speculation that this
was causing pressure surges in the hydraulic system. 'owever, once oil level was restored to
the normal range, the pressure oscillations still occurred.
On January 27, 1991, pressure control
was switched from the Electronic Pressure Regulator (EPR) over to the Mechanical Pressure
Regulator (MPR) to allow testing of the EPR.
The EPR was examined extensively and no
problems were found.
Additionally, a computerized
data acquisition system
was placed in
service to monitor and record for later analysis, various parameters
in case the oscillations
reoccured.
On February 7, 1991, while on the MPR, the oscillations occurred again.
Reactor power was
reduced and the condition stabilized.
Analyses of the data acquisition system's data indicated
that changes in hydraulic pressure were not the cause of the oscillations.
Also, the oscillations
occurred while on the MPR which indicated the oscillation problem was a result of common
elements downstream of the MPR or EPR.
The system engineer determined that the most likely
source of the problem was the torque tube, which is located in the front standard,
and controls
the turbine control valves position.
Additional data obtained by the data acquisition system on
control valve response
added credence to the belief that the problem was in the front standard.
Niagara Mohawk had
numerous
conversations
with the turbine vendor and
an expert in
mechanical hydraulic control systems was arranged to be sent to the site.
However, before the
vendor arrived on February 12, 1991, one of the control valves went rapidly to the 50% closed
position and then back to full open.
This induced a pressure
transient on the reactor which
caused reactor power to increase and the reactor to automatically scram as a result of the high
flux condition.
The plant shutdown,
as designed,
and a plant cooldown to cold shutdown was
initiated as a result of management's
decision to enter the mid-cycle outage early. The inspector
concluded that Niagara Mohawk was pursuing identification of the pressure surges in a timely
and conservative
fashion.
Additionally, operator response
to the automatic shutdown
was
satisfactory.
1.2
iinit2
r
During this inspection period the containment integrated leak rate test was performed, final
preparations for reactor startup from the first cycle refuel outage were made and the reactor was
taken critical on January
19, 1991
~
Augmented NRC coverage was provided by region based
inspectors during reactor startup.
A forced shutdown from 12 percent power was required on
January 23, 1991, due to an Electro Hydraulic Control (EHC) piping weld crack.
Repairs were
affected and the reactor again taken critical on January 24, 1991. At the end of the period, the
reactor was operating at 100% power.
A.
A review of completed valve line-ups performed on safety related systems to support
reactor startup followingthe refuel outage was performed by the inspector.
The review consisted
of ensuring independent verification ofvalve positioning was exercised for safety related valves,
the required valve positions were correct by confirming actual position and valve line-up sheets
were properly completed.
Six systems were reviewed for adequacy and are listed below:
N2-OP-33, High Pressure
N2-OP-36A, Standby Liquid Control
N2-OP-74B, Major Components Power Supplies
N2-OP-57, System Power Supply Lineup
N2-OP-82, Containment Monitoring Leakage (CML)
N2-OP-35, Reactor Core Isolation Cooling (RCIC)
The inspector found the valve line-ups were properly executed with only two minor deficiencies.
These
deficiencies
were discussed
with operations
management
and satisfactorily resolved.
Overall, the inspector concluded
that startup valve line-ups were adequately
performed
and
verified by the operators.
B.
The inspector conducted
a review of the training organization to verify that procedures
and programs
were in place
to identify plant modifications that require changes
to plant
procedures,
changes
to operator training programs,
and changes
to the Unit 2 simulator.
The
inspector reviewed a sampling of the plant modifications implemented during the refuel outage
and verified that operators were trained on the modifications, plant procedures
were properly
revised, and that the plant simulator was scheduled to be modified to reflect these modifications.
The inspector concluded that the training program and procedures were adequate to identify plant
modifications requiring changes
to the operator training program and that the Unit 2 operating
staff had been satisfactorily trained on the recent modifications made to the station.
C;
During a walkdown of control room panels, the inspector identified that Uninterruptible
Power Supply (UPS) 2VBA*UPS2Ahad a blown fuse on the inverter. Following the,inspector's
questioning of this condition, operators submitted a work request to replace the blown fuse.
The
inspector questioned
the operability of the UPS per Technical Specification 3.8.3.1
and was
subsequently informed that the blown fuse did not impact operability of the UPS in its present
power supply lineup.
Operations
management
did commit to evaluate
the alarm response
procedure 852100 No. 116 and make any necessary
changes
to ensure that UPS trouble lights
are clearly understood by the operators.
4
I
The inspectors also observed several shift briefings and turnovers conducted by the station shift
supervisors.
The briefings and turnovers were'thorough,
informative and professionally
conducted.
D.
On January
16,
1991, while performing an inspection for EHC system leakage,
the
turbine trip logic was reset.
Contrary to expectations, turbine speed selection indication changed
from "all valves closed" to "1800 rpm" when the speed selection changed.
The closed turbine
stop valves (TSV) began to open, resetting the existing condenser low vacuum containment
isolation bypass.
In that the unit was shut down, the condenser low vacuum signal initiated an
MSIV isolation signal (the MSIVs were already shut).
Niagara Mohawk reported the event per
10 CFR 50.72, and an occurrence report (OR) was initiated.
The inspector observed much of the troubleshooting performed on the system and discussed
th'
problem with the responsible I&C staff. No component or equipment failures could be found,
consequently an operating procedure change was made to alert operators to the potential for an
1800 rpm signal resulting from a turbine trip reset and pointing out that, in the event of such a
signal, approximately 10 seconds were available (while the TSVs open) for the operator to select
"all valves closed"
and avoid the isolation signal.
In addition, operator training would be
conducted on this change.
The OR was forwarded to the system engineer for review and will
remain open until a final engineering determination on corrective action is completed.
The inspector concluded that a reasonable attempt had been made to isolate and recreate the cause
of the event.
Corrective action taken to date (procedure revision and training), while not a
solution to the problem, provides sufficient interim compensatory action.
E.
During low power operations on January 23, 1991, a significant oil leak in the EHC
system was identified by an operator on rounds.
Prompt actions were taken by the control room
operators to reduce power, secure steam to the turbine and the condenser
and then secure the
EHC pumps.
This included initiating the steam condensing mode of the B residual heat removal
system and starting the reactor core isolation cooling system to control reactor pressure and level.
Subsequently,
a controlled plant shutdown was performed.
The inspector determined that approximately 150 gallons of EHC oil leaked from the system.
The leak w'as identified to be from a crack in a piping weld.
The apparent cause of the weld
crack was cyclic fatigue due to vibration.
The weld was repaired and all other welds in the
system were examined via dye penetrant testing and found to be acceptable.
The inspector concluded
that the operators performed well by identifying the leak and then
placing the plant in a safe condition.
Their prompt actions avoided any automatic protective
system actuations.
2.0
MAINTENANCEAND SURVEILLANCEOBSERVATIONS
2.1
gni~1
A.
The following activities were observed:
1
Drywell hydrogen sampling in accordance with procedure N1-CSP-W343.
Troubleshooting and repair to reactor recirculation pump motor generator set 12
per Work Request 187782.
The cause of the MG set ground was determined to
be two worn spots in the epoxy coating of the stator windings which exposed the
metal windings. This, in conjunction with the carbon and copper dust inside the
machine,
set-up a conductivity path which allowed one of the three phases
to
ground-out and caused
the MG set protective relaying to actuate.
A vendor
representative
was called in and repair of the epoxy coating was performed,
as
well as, cleanup of, the machine's internals.
These activities resulted in clearing
the ground condition.
Preventive maintenance procedure N1-MPM-070-A409 on the 12 reactor building
closed loop cooling (RBCLC) heat exchanger (HX).
Zebra mussels and some
silting were found in the HX during the inspection of the service water side.
The
inspector observed cleanup of the HX and performance of an air pressure test to
test integrity of the tube sheet welds prior to an operational pressure
test with
water which was satisfactory.
No performance or procedural problems were identified.
B.
Prelimina
Review of Generic Letter
GL
8 -13 Re ardin
ervice Water S
tern
Problems Affectin
fet -Related
i ment
t
The inspector reviewed GL 89-13 and its supplement and held discussions with the appropriate
system engineers to determine current and planned practices at Unit 1 to address the requirements
of the GL. The inspector determined that for Unit 1, the systems which fall under the general
heading of service water as described in the GL are:
service water (SW), emergency
service
water (ESW), emergency diesel generator (EDG) cooling water and the containment spray raw
water (RW) supply.
Each of these systems has its own suction source in the screenwell house.
The inspector determined that the following programs are in place or planned for each of the
systems:
I
B.1
These two systems provide cooling water to various heat exchangers
and area coolers in the
reactor and turbine building. The ESW system provides backup to SW in the event of loss of
. off-site pow'er and supplies specific loads only. The only safety-related load cooled by SW or
ESW are the reactor building closed loop cooling (RBCLC) heat exchangers.
By the definition of GL 89-13, RBCLC is a closed system and is thereby exempt from the GL
requirements.
However, the inspector notes that this system does have its own water chemistry
monitoring and surveillance program.
The only safety-related loads cooled by RBCLC are the
post-accident sampling system and control. room emergency ventilation system.
These two loads
are a small part of the total cooling demand on the RBCLC system.
It appears
that there is
adequate margin to accommodate
any degradation in SW or ESW cooling water supply to the
RBCLC HXs due to silting or fouling.
Potential silting or biofouling of reactor building area
coolers was determined not to be of safety significance, in that, they do not support operability
of safety-related equipment located in the spaces they cool.
The inspector determined that for the SW and ESW systems,
the following maintenance
and
testing activities are (or have been) performed:
Allof the RBCLC heat exchangers (11,12, and 13) were opened and inspected during the
1988-90 outage.
Extensive repairs and post-repair vibration testing were done as a result
of flow-induced damage to the tubes and tweeners.
The SW side of one HX is inspected every three months which results in all three HX's
being inspected on a 9-month cycle.
Power Ascension Test, Nl-PAT-11, was performed on the RBCLC HXs during the
startup program to verify operability and verify they met their design basis.
This data
willbe used to baseline future tests.
The area coolers are inspected by various preventive maintenance
procedures.
These
procedures
are being revised to include opening them up to allow inspection for silting
or biofouling'.
Performance of the ESW system
is checked periodically by procedures
N1-ST-Q13
(quarterly) and N1-ST-R16 (each refueling) to check the pumps'erformance,
to obtain
vibration data and to verify operability of the downstream check valves.
B.2
There are four loops of CS and each loop has its own CS HX with associated cooling supplied
by its own RW cooling pump and piping.
The inspector determined that:
One of the four CS HXs is opened up and inspected on the tube side (raw water) every
three months resulting in inspection of all four HXs on an annual basis.
Heat transfer capacity was demonstrated during the power ascension program on one of
the HXs.
Results
indicated
degraded
performance
(a level II test exception
was
generated)
and the HX was opened.
Scaling on the lower one-third of the tube bundle
was identified and was attributed to incomplete drainage of the HX.
The physical
arrangement of the connection point ofRW to the HXprecludes draindown ofabout one-
third of the tubes and both inlet and outlet plenums following operation.
The operating
and surveillance procedures
were. modified to ensure complete draindown of the HX's
tube side via installed vent and drain valves following operation.
Quarterly and refueling surveillances are done to monitor RW pump vibration and flow
characteristics for signs of degraded performance.
B.3
Coolin~ Water Su
I
The inspector determined that:
Performance of each EDG cooling water pump is monitored quarterly as part of the In-
Service Testing (IST) program.
Procedure
N1-MPM-079-A412 is performed annually and involves opening
up and
cleaning the associated
heat exchangers.
~
B.4
Zebra Mussel Intrusion
GL 89-13 also addressed
the issue of biofouling of service water systems.
Until recently, this
was not a concern at the site.
However, Lake Ontario is currently experiencing infestation of
mollusks referred to as Zebra mussels.
Niagara Mohawk has implemented a monitoring program
to detect the presence of zebra mussels in their larval (velliger) stage,
as well as, adult stage.
A treatment system was recently installed and was approved by the New York State Department
of Environmental Conservation (DEC), for the application of a molluscicide (Clamtrol) to the
various SW systems (including the fire water system).
A limited number of treatments are
allowed by the DEC each year with treatments
based
on the velliger monitoring program,
presence ofadult mussels on the substrate racks and on breeding habits.
The inspector observed
a molluscicide treatment on January 16, 1991, on the SW and fire water headers.
Post-treatment
results indicated that an effective treatment had been performed.
The'inspectors determined that
procedures were being properly followed.
B. 5
QmalllA
I
Niagara Mohawk responded to GL 89-13 by letter dated February 16, 1990, and in a supplement
letter,
which provided
more
detail
as
to programs
to
address
each
GL issue,
dated
December
10, 1990.
The inspector verified that the stated programs were in place and that
future activities were identified and were being tracked by the responsible system engineers.
The
inspector. concluded that Niagara Mohawk was addressing the issues of GL 89-13 in a timely and
comprehensive
manner.
2.2
iinit2
A.
-
Portions of the following special tests were observed by the inspectors:
Integrated Leak Rate Test per N2-TSP-CNT-@001.
Turbine Torsion Test per N2-STP-9.
Turbine Valve Surveillance Test per N2-STP-24, performed for post-
modification testing.
The performance of these tests were assessed
to be well controlled and executed in a cautious and
deliberate manner.
The interface between operations and the system engineering test directors
was observed
to be good.
When problems arose,
the tests were stopped
and the problems
appropriately resolved.
B.
While reviewing a completed source range monitor and rod block function check per N2-
an Instrument and Controls (I&C)supervisor identified the rod block check
portion was not performed on December 3, 1990.
The reactor was in mode 5 (refueling) at the
time of the discovery.
In addition, at the time of the supervisor's review, the surveillance test
frequency had been exceeded by 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
This resulted in a violation of TS Table 4.3.6-1 for
the surveillance frequency.
I
The I&C technician who performed the test did not perform the rod block checks
due to
conflicting plant conditions.
The technician noted this in the procedure, but failed"to obtain a
proper review to determine if this exception was acceptable.
The supervisory review of the
surveillance was not performed in a timely manner and thus when the error was detected,
a
violation of TS had already occurred.
The missed surveillance was reported to the station shift supervisor (SSS). The SSS directed that
all activities involving core alterations be stopped.
However, three hours later a management
review of these actions determined that at least one rod block channel should have been placed
into the tripped conditions within one hour ofdiscovery.
The failure to take this action resulted
in a violation of TS Table 3.3.6-1, Action Statement 6.1.b.
A Niagara Mohawk review ofpreviously performed N2-ISP-NMS-W@008 tests was performed
and identified that on September
19 and September
25,
1990, the rod block checks
were
similarly not completed.
On these occurrences,
the supervisory reviews did not detect the missed
rod block test exceptions.
Based on the identification of these two additional missed rod block
checks,
the plant manager
directed
a 100% review of all completed I&C surveillances
be
performed and a sampling of other departments'ompleted
surveillance tests be performed.
No
additional TS violations were identified.
However,
several
instances of minor procedural
adherences
and misuse of notes were found in other I&C tests.
Other corrective action directed
by the plant manager included training on procedural adherence
and an accountability meeting.
The inspector concluded that the safety significance of the three missed rod block surveillance
tests was low because the rod block function was proven to be functionally operable during the
next performance of the test.
As noted above, several I&C technicians marked the rod block
checks section of the test as Not Applicable, wrote a note in the remarks section as justification,
and did not obtain a proper technical review. Also, I&Csupervision did not detect this problem
on two other occasions.
When it was finally identified on December 7, 1990, the review was
not timely and resulted in a third violation. The improper use of notes and inadequate technical
review of completed surveillance tests were the root cause of similar TS surveillance violations
a few years ago.
However, Niagara Mohawk did identify these missed rod block checks and
performed a thorough review to determine the scope ofthe problem. Additionally, the corrective
actions described in the associated LER (90-19) appeared
to be thorough and satisfactory.
In that these TS surveillance violations were ofminor safety significance, were promptly reported
to the NRC, were identified by Niagara Mohawk and corrective actions taken appear
to be
thorough, no Notice ofViolation is being issued in accordance with the NRC Enforcement Policy
stated in 10 CFR 2, Appendix C, Section.V.G.
NON-CITED VIOLATION(50-410/91-02-01)
.10
C.
(Closed) Violation (50-410/90-09-01):
Two examples of the failure to adhere
to
procedures
by mechanical
maintenance
technicians
were identified during safety
related
preventive maintenance on hydraulic cont'rol units.
Niagara Mohawk admitted to the violation,
as stated.
The plant manager conducted an accountability meeting with all personnel involved
and disciplinary actions were taken. Procedural adherence was reinforced withinthe maintenance,
department.
The inspector verified that the corrective action stated in the Niagara Mohawk
response
to this violation (letter dated January 2, 1991) were adequately implemented.
This
violation is closed.
D.
After engineering
review of data obtained during surveillances
on the standby
gas
treatment system, per procedure N2-OSP-GTS-R001, itwas dete'rmined that although acceptance
criteria were met, the. drawdown time was greater than expected.
A retest of the system was
initiated on January 17, 1991.
During performance of the procedure preliminaries, the A train
fan tripped twice when given a manual initiation signal.
The problem was determined to be a
relay which failed to latch properly.
The relay was replaced,
and the surveillance
was
successfully performed with a satisfactory drawdown time.
The inspector observed portions of the surveillance, and noted that timing of the drawdown was
started
when
the fan started
rather
than
when
the signal
was initiated.
The fan starts
approximately five seconds after signal initiation.
Plant personnel indicated that the accident
analyses takes credit for drawdown time from when the fan starts, so the method of timing used
during the surveillance test was appropriate.
The inspector concluded that the surveillance test
was adequately performed.
3.0
ENGINEERING AND TECHNICALSUPPORT
3.1
iinit i
A.
(Closed) Unresolved Item (50-220/88-34-09):
.L'ack of proper identification of post-
accident instrumentation on the control boards.
Following identification ofthis concern Niagara
Mohawk implemented,
on an interim basis,
the use of colored
dots to identify accident
assessment
instrumentation.
After a detailed evaluation and operator input, Niagara Mohawk
implemented,
on November 7, 1990, a design change to identify all control panel accident
assessment
instrumentation with distinctive 3/4 inch red tape affixed above each ofthe indicators.
The inspector
conducted
a control panel
walkdown and verified the accident
assessment
instrumentation was properly identified.
This unresolved item is closed.
11
B.
(Closed)
Unresolved
Item (50-220/88-34-08):
Adequacy of electrical and physical
separation of the redundant control room post-accident monitoring components.
By letter dated
May 19, 1989, (NMP1L 0401), Niagara Mohawk committed to develop and implement a long
term action plan to address electrical and physical separation of control room Regulatory Guide (RG) 1.97 Category
1 instrumentation.
To support the long term plan, various short term actions
were undertaken by Niagara Mohawk to ensure the as-built configurations were in compliance
with RG 1.97.
These action items were previously reviewed and found acceptable
by the
inspector
and
documented
in Inspection
Report 50-220/89-35,
Section
3.1.
Using
the
information gathered
from the short term plan, elements of the long term action plan were
developed
as documented
in an October 29,
1990 letter (NMP1L 0534).
The inspectors
reviewed the long term cable separation program for RG 1.97 Category
1 instrumentation which
is a subset of the broader Design Basis Reconstitution Program.
The inspector concluded the
action plan being implemented by Niagara Mohawk was satisfactory and adequately
addressed
the commitments made for this item.
This unresolved item is closed.
C.
(Closed) Unresolved Item (50-220/90-09-02):
This item was open pending review of the
LER for the improper setting of the emergency condenser isolation setpoint,which did not meet
the design basis.
LER 90-22, issued November 19, 1990,. was reviewed by the inspector.
Niagara Mohawk's conclusion
as to the root cause for this condition was inadequate
design
documentation.
Further, the root cause which allowed the condition to continue after it was
initially'iscovered was a programmatic failure. The inspector agreed with this assessment.
Due to the low safety significance of the event, prompt reporting of this violation to the NRC,
the condition was self-identified and that appropriate corrective actions, as described in LER 90-
22, have been taken, the violation for non-conservative
setpoints was not cited, in accordance
with the criteria in the NRC Enforcement Policy of-10 CFR Part 2, Appendix C,Section V.G.
NON-CITED VIOLATION(50-220/91-02-01)
D.
(Closed) Unresolved Item (50-220/90-09-03):
This item was open pending Niagara
Mohawk investigation of NRC identified deficiencies with implementation of the Appendix J
water seal methodology on the containment spray discharge check valves.
The unresolved item
included three concerns.
Inspector review of these concerns follows:
C
D.1
Steps were added to Nl-OP-14 describing an alternate water seal method that did not
receive NRC review and approval. Further, the addition ofthe steps caused the entire subsection
of N1-OP-14 (Section H.7) dealing with the water seal to be confusing as to its applicability and
implementation, based upon interviews with several licensed operators.
e
12
Niagara Mohawk root cause analysis identified that:
The procedure
steps
were added
at the behest of the operations
department for the
potential scenario where no containment spray pumps are running and a water sealing
function is needed.
The change to add these steps to Nl-OP-14 were approved via
, routing the change to SORC'members
vice a routine SORC meeting.
Review of letters between Niagara Mohawk and NRC staff made it clear that the NRC
wanted to be informed of the method(s) of implementing the water seal.
The corporate licensing group which was tasked with oversight of the water seal project
were unaware of the change made to Nl-OP-14 by the operations department,
and the
. operations department was unaware of the fact that the NRC had to be informed of any
methods used for establishing a water seal.
Operators did not receive training in the simulator for the Section H.7 changes.
This was
considered
one reason
why operators
were confused
over its implementation
when
questioned by the inspector.
Niagara Mohawk speculates
that had training been given,
the procedural problems might have been identified and properly resolved.
D.2
This concern dealt with a revision to the Niagara Mohawk Safety Evaluation 89-13 which
appeared
to add a commitment to enter the containment spray system Limiting Condition for
Operation (LCO) for certain conditions, specifically, torus cooling or makeup mode.
The
inspector identified that these instructions were not reflected in the appropriate sections of N1-
Further discussions with operations management
determined that an assumption
was
made that the operators entered the LCO anytime these conditions were established.
This was
found not to be the case.
Consequently, Nl-OP-14 has been revised to caution operators to enter
the applicable LCO when in the torus cooling or torus makeup modes.
D.3
The ALARAreview for Safety Evaluation 89-13 did not appear to be comprehensive,
in
that, the modification ofvalves 80-40 and 80-45 to manually operated (normally open) had been
judged by Niagara Mohawk to be of minor radiological significance since the valves would not
have to be operated to mitigate or recover from an accident.
However, the inspector identified
that EOP-10, Drywell Flooding, requires operation of these valves per Section H.8, Nl-OP-14.
A subsequent
Niagara Mohawk evaluation of this issue concluded
the same.
However, the
ALARAgroup was not faulted for the inadequate
evaluation
as they were informed that the
valves would only be operated during routine plant evolutions.
The inspector agreed with this
assessment.
0
13
~nclusicn
I
The inspector considered
these three concerns to be resolved and Item 50-220/90-09-03 closed.
However, the inspector concluded that Nl-OP-14 was revised, on May 7, 1990, per Safety
Evaluation 89-13, and as a result conflicted with EOPs. Two specific examples were identified.
First, Section H.7 of Nl-OP-14 states that following a design basis Loss of Coolant Accident
(LOCA), two containment spray pumps should remain in operation when containment pressure
is greater than 3 psig and one pump should remain in operation when less than 3 psig, in order
to maintain a long term water seal.
However, EOP-4 states to terminate containment sprays
when drywell pressure is less than 3.5 psig.
Secondly, EOP-10 directs performance of Section
H.8 of Nl-OP-14;
Section H.8 requires alternate closing/opening operations of valves 80-40
and/or 80-45.
However, in the event of a LOCA, the radiation field in the vicinity of these
valves would likely preclude operation of the valves.
Both of these conditions were not
identified during the procedural
revision process
for incorporating the water seal
steps
to
operating procedure Nl-OP-14.
The two Emergency Operating Procedure conflicts and the
inadequate
and confusing water seal implementation
steps in Section H.7 of N1-OP-14 are
contrary to Technical Specification 6.8.1
and ANSI 18.7-1972 regarding proper procedure
revision and review.
This is a VIOLATION. (50-220/90-02-02)
Assessment
Niagara Mohawk's root-cause analysis for this event revealed numerous other procedural and
programmatic deficiencies.
Additionally, lessons learned transmittals have been prepared and
disseminated
to corporate and site personnel.
The root-cause analysis, as well as, preliminary
corrective actions taken were discussed with the resident staff.
Niagara
Mohawk's overall root-cause
was
that the failure to adequately
implement
the
Appendix J water seal commitment was poor managerial methods.
The inspectors concurred
with this broad conclusion, but remained concerned
that the interface between the corporate
licensing group and the station warrants further examination,
in that, this project was the
responsibility of the licensing group.
Particularly troubling to the inspectors
was that the
exemption to Appendix J was a specific issue in the Restart Action Plan and thus was supposed
to have received
a higher level of attention and review.
Despite these additional oversight
functions and review processes,
the water seal methodology was poorly implemented.
32
Unit 2
A.
~D
On September
13, 1985, the NRC submitted the results ofits Nine MilePoint Unit 2 SPDS pre-,
implementation audit to Niagara Mohawk and requested
that Niagara Mohawk respond to'he
concerns which resulted from the audit. Niagara Mohawk responded to these concerns in a letter
dated November 15, 1985, which delineated the corrective actions to be taken for each area in
question.
NRC concurred with the proposed corrective actions and included a License Condition
(C.(8)) in the Nine Mile Point Unit 2 Facility Operating License dated July 7, 1987.
The
License Condition indicated that Niagara Mohawk shall have an operational SPDS that includes
.the enhancements
described in their 11/19/85 letter prior to startup following the first refueling
outage.
During the current inspection period, the inspectors reviewed the implementation of the Nine
Mile Point Unit 2 SPDS to determine ifLicense Condition C.(8) had been met.
Issue //1
Man-in-the-Loop
Testing,
Validation
and
Verification
Documentation
Centralization
The inspectors determined that adequate man-in-the-loop testing was performed to verify that the
SPDS displays and parameter
set provide the necessary
safety status information during both
normal and abnormal plant conditions.
The testing involved the imposition of various plant
scenarios on the Unit 2 simulator and having control room personnel and test observers evaluate
the dynamic performance of the SPDS.
Several modifications were made following the test to
correct system problems and improve usability. In addition, a followup man-in-the-loop test was
performed to validate these modifications.
The inspectors found that all documentation,
both internal and external to Niagara Mohawk,
relating to the design, construction, installation, validation and verification of the Unit 2 SPDS
was in Niagara Mohawk's possession.
This resolved an NRC audit comment relating to the
centralization of SPDS.validation and verification documentation.
15
Issue ¹2
Content of Field Verification and Validation Testing
Following the man-in-the-loop testing, SPDS computer operational testing was performed.
The
system was tested by the insertion of predetermined
raw data inputs and verification of data
manipulation and validation, alarm setpoints,
display functions,and
system
response
times.
Testing also included the performance of calibration procedures on instrument loops providing
SPDS inputs and verifying that input point values (at the SPDS computer) corresponded
with
calibration inputs, thereby validating sensor to display response of SPDS.
Test exceptions were
minor and have been satisfactorily resolved.
The inspectors concluded that the field testing was
successfully completed and appropriately addressed
the testing aspects of SPDS validation and
verification.
Issue ¹3
Evaluation of SPDS Reliability
In the November 19, 1985 letter, Niagara Mohawk indicated that a computer log would be
maintained to document SPDS system failures, their duration, and the equipment that failed. The
inspectors reviewed procedure N2-COMP-L.WS.01, Liquid Radwaste Computer System Power-
Up/Power-Down Procedure.
This procedure has been temporarily changed to include the SPDS
availability log which willbe maintained by system support engineering.
While the procedure
notes that the log should be evaluated periodically to assess SPDS reliability, goals for reliability
were not indicated.
However, reliability goals were noted in the SPDS design documentation.
The inspectors
concluded
that this commitment had been adequately
addressed
by Niagara
Mohawk.
Issue ¹4
Use of BWROG Parameter Set at NMP2
On September 7, 1990, Niagara Mohawk submitted to NRC its evaluation of the adequacy of
the BWROG parameter
set used for the Unit 2 SPDS.
This met the commitment noted in the
November 19, 1985 letter.
Issue ¹5
Human Factors Improvements
Niagara
Mohawk
implemented
the
human
factors
recommendations
noted
in
the
November 19, 1985
letter,
as well as,
other recommendations
which have
resulted
from
validation testing.
The inspectors
verified that these
changes
had
been
implemented
by
observation of the affected SPDS displays.
16
Issue ¹6
Radioactivity Control SPDS Display
The NRC pre-implementation audit noted that the display ofradioactivity control parameters was
not concise because too many instruments (two annunciators, two displays, and two strip chart
recorders)
would have to be observed
by the operators
to assess
the status of necessary
parameters.
Niagara Mohawk responded to this concern by adding the necessary radioactivity
control parameters
to the SPDS Level II displays.
In their summary report dated January
11, 1991, the independent engineering consultant that
performed the SPDS validation and verification stated that the Unit 2 SPDS displays were
adequate to ensure that the information provided willbe readily comprehended by the operating
staff with one exception.
The consultant felt that placing four trend plots on the Radioactivity
Control SPDS
display may not'provide sufficient resolution for indication of the trended
parameters
and that Niagara Mohawk should evaluate this after the operators gained experience
with the SPDS.
Niagara Mohawk disagreed with the consultant's position because they felt that
the current display does provide adequate resolution and also because
the current display was
responsive to the NRC pre-implementation audit concern.
The inspectors observed the SPDS
Radioactivity Control display and found the resolution of the trended parameters to be adequate,
Issue ¹7
Continuous Display of SPDS in Control Room
In response to an NRC audit concern, Niagara Mohawk committed to ensuring that at least one
screen of the Honeywell System in the control room willbe dedicated to the SPDS mode at all
times.
Niagara Mohawk has included this requirement in Operating Procedure OP-91B, SPDS.
The inspectors noted, during numerous visits to the control room, that one of the Honeywell
screens
was indeed committed to SPDS.
During the review of the Operating Procedure OP-91B, the inspectors noted a precaution related
to the SPDS Level II display of group isolation valve status.
In particular, since input signals
to the SPDS computer are provided by valve control power, it is possible for the computer to
indicate a valve as closed even if it is open, if power is lost to the isolation valve control
circuitry or to optical isolators in the circuitry.
This could result in faulty indication of a
containment isolation valve group on the associated
SPDS Level II display.
When questioned
as to the possibility of physically modifying the circuitry to eliminate this problem, Niagara
Mohawk indicated
that the problem
is not unique in the industry
and
that the physical
modifications
needed
to
resolve
this problem
would be
extensive
and
costly
and
not
commensurate
with a comparable improvement in safety.
Niagara Mohawk has included a
discussion of this potential problem in the operations training lesson plan for SPDS.
The
inspectors concluded that the issue had been adequately addressed
by Niagara Mohawk.
17
Som'mary
The inspectors
concluded that the Unit 2 SPDS has undergone appropriate modification and
testing and has been properly validated and verified to ensure
compliance with applicable
regulatory requirements and guidelines provided in NUREG 0737, Supplement 1, NUREG-1342,
and the Standard Review Plan.
Niagara Mohawk adequately
addressed
and responded
to the
specific SPDS commitments which resulted from the 1985 NRC pre-implementation audit of the
Unit 2 SPDS.
The inspectors concluded
that in adequately
addressing
these specific SPDS
commitments, Niagara Mohawk had successfully met Facility Operating License Condition C. (8).
B.
(Closed) Unresolved Item (50-410/88-201-01):
Molded case breaker testing deficiencies
involving a lack of guidance for adjustable trip'relay settings.
To address this issue Niagara
Mohawk conducted a comprehensive walkdown ofall safety-related molded case circuit breakers
(MCCBs) and motor control centers to identify which MCCBs have adjustable trip settings.
In
addition, the generic testing procedure, N2-EPM-GEN-V582, was revised to incorporate the
necessary
acceptance criteria for magnetic trip testing.
These corrective actions were reviewed
and found acceptable during a previous inspection (reference Inspection Report 50-220/90-23,
Section 3.4).
During this inspection period the inspector verified that the appropriate design
drawing, AE-003, "Overload Heater List," was revised per Engineering Design Change (EDC)
2E10330 and that the associated
electrical maintenance
procedures
were properly revised to
correctly identify the required trip settings.
This unresolved item is closed.
3.3
ll
1
d2
eneric Letter 8 -10 Res
n e R view
. By letters dated December
14,
1990, (NMP1L 0556 and NMP2L 1267) Niagara Mohawk
responded
to GL 89-10, Supplement 3, Consideration of the Results of NRC sponsored Test of
Motor-Operated Valves, dated October 25, 1990.
This GL supplement specifically requested
licensees
to complete a plant specific safety evaluation of the susceptibility to failure under
accident conditions of motor-operated valves in the high pressure core injection (HPCI), reactor
core isolation cooling (RCIC), reactor water cleanup (RWCU) and isolation condenser
(IC)
systems, ifapplicable.
For the impacted systems (Unit 1 - RWCU and IC, Unit 2 - RWCU and
RCIC) Niagara Mohawk concluded that the isolation valves would function satisfactorily under
accident full-flowconditions.
18
4
The inspector reviewed the supporting safety assessments
forboth units (Calculation No. S14-33-
V001, dated December
11, 1990, for Unit 1 and Safety Assessment for NRC Generic Letter 89-
10, Supplement 3, dated December
13, 1990 for Unit 2) and concluded that they adequately
addressed
the specific assessment
considerations outlined in Supplement 3. However, following
discussions with Headquarters
and region-based
specialists,
the inspector was informed that a
more detailed technical evaluation of the utilities'eneric Letter responses
would be conducted
by a schedule not yet established.
Consequently,
this inspector's review is complete, but the
formal NRC technical assessment of Niagara Mohawk's response
to Generic Letter 89-10 will
be conducted in a subsequent
inspection.
4.0
REVIEW OF LICE<NSEE EVENT REPORTS (LERs) AND SPECIAL REPORTS
4.1
Unit
1
The following LERs were reviewed and found satisfactory:
LER 90-19, Reactor scram due to spurious trip of neutron monitor caused by noise.
LER 91-01, Reactor scram due to spurious non-coincident logic trip signal.
Special Report dated January
25,
1991, (NMP77309), dealing with inoperability of the
12
Containment Hydrogen Monitoring System was reviewed and found acceptable.
4.2
~Jni ). 2
The following LERs were reviewed and found satisfactory:
LER 90-17, Personnel error results in inadvertent actuation of the standby gas treatment
system.
LER 90-18, Standby liquid control system declared
inoperable due to excessive
pipe
stress caused by a failed mechanical snubber.
LER 90-19, Technical Specification violations ofrod block checks due to procedural non-
compliance and inadequate work practices.
(see Section 2.2.B)
5.0
SE<CURITY/SAI<EGUARDS
A.
(Closed)
Unresolved
Item (50-220/88-30-01
and 50-410/88-29-01):
This item was
recently updated in a security inspection conducted the week of December
17, 1990.
The item
was left open pending repair of certain areas.
These areas were repaired soon after the security
team's visit and verified to be proper by the resident staff.
This item is closed.
0
19
'.B.
The inspectors discussed the heightened Security Guard Force preparedness
measures and
contingency plans initiated as a result of the increased potential for terrorist activities with respect
to the Persian Gulf War.
The inspectors found these measures
satisfactory.
6.0
MANAGEMENTMEETINGS
Management/Exit Meetings conducted by Region Based inspectors during this inspection period:
ate
~ub'eet
R~eort No
~ln pec~tr
1/25/91
2/1/91
2/15/91
2/15/91
EP Program Review
EOP Review - Unit 2
Effluents
HP/Transportation
91-03/91-03
91-80
91-05/91-05
91-04/91-04
Amato
Walker
Jang
Furia
7.0
PRELIMINARYINSPECTION FINDINGS
At periodic" intervals and at the conclusion of the inspection,
meetings were held with senior
station management
to discuss the scope and findings of this inspection.
Based on the NRC
Region I review of this report and discussions held with Niagara Mohawk representatives,
it was
determined that this report does not contain safeguards or proprietary information.