ML17263A574
| ML17263A574 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 04/05/1994 |
| From: | Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17263A572 | List: |
| References | |
| 50-244-94-05, 50-244-94-5, NUDOCS 9404120032 | |
| Download: ML17263A574 (68) | |
See also: IR 05000244/1994005
Text
U. S. NUCLEARREGULATORY COMIVHSSION
REGION I
Inspection Report 50-244/94-05
License: DPR-18
Facility:
R. E. Ginna Nuclear Power Plant
Rochester
Gas and Electric Corporation (RG&E)
Inspection:
Inspectors:
February 8 through March 8, 1994
T. A. Moslak, Senior Resident Inspector, Ginna
E. C. Knutson, Resident Inspector, Ginna
Approved by:
s,
ief, Reactor Projects Section 3B
INSPECTION SCOPE
Date
Plant operations,
maintenance,
engineering,
and plant support.
9404120032
940406
ADOCK 05000244
8
INSPECTION EXECUTIVE SU584ARY
Operations
The plant operated at 98 percent power for the majority of the inspection period.
On February
17, 1994, loss of offsite power circuit 751 caused a spurious turbine runback.
By coincidence,
the "A" EDG was operating in parallel with circuit 751 at the time.
Although this prevented
the associated
480-volt safeguard
buses from being deenergized,
the resultant undervoltage
transient caused a momentary turbine runback.
Reactor power was subsequently reduced to less
than 90 percent,
as required by technical specifications, while core axial flux distribution was
stabilized. Full power operation was resumed later that day. Operator response to the transient
was prompt and in accordance with procedure.
Actions were well-focused on establishing and
maintaining plant stability.
On March 4, 1994, the plant was shut down to commence the scheduled annual refueling outage.
At the close of the inspection period, the reactor was in refueling shutdown mode, with reactor
disassembly in progress in preparation for full core offload to support extensive service water,
component cooling water, and residual heat removal system maintenance.
Maintenance
Corrective maintenance on spent fuel pool service water system components
was well planned
to optimize plant safety for a complete core off-load. Diagnostic testing on the Turbine Driven
Pump was effectively carried out to identify and evaluate off-normal
operating parameters.
Engineering
On February
15,
1994, the licensee
determined
that the two manual containment isolation
pushbuttons had not been periodically tested as required by technical specifications.
The licensee
requested,
and was granted, enforcement discretion to defer testing until after shutdown for the
refueling outage.
In January,
1994, the licensee determined
that two containment pressure
instruments had been inoperable since June 1992 due to blockage of the common sensing line
that connects the associated
pressure transmitters with containment;
as a result, the reliability
of automatic
initiation of certain
safety
features
was
degraded.
These
two conditions
demonstrated
that testing was not being appropriately performed, and constituted a violation of
10 CFR 50, Appendix B, Criterion XI, "Test Control."
Executive Summary
Plant Support
On March 1, 1994, while purging the pressurizer to the volume control tank, valve seat leakage
in the post accident sampling system resulted in minor radioactive contamination of water in the
condensate
storage tanks; the health physics technician who discovered
the problem was also
slightly contaminated.
Licensee
response
to this minor radiological event was prompt and
comprehensive.
At the close of the inspection period, a root cause analysis of this event was
in progress.
Safety Assessment/Quality Verification
In a meeting ofthe Nuclear Safety Auditand Review Committee, topics were candidly discussed
and were presented with sufficient detail for board members to assess
the safety significance of
the agenda issues.
TABLEOF CONTF22lTS
EXECVI'IVESUMMARY
TABLE OF CONTENTS
1v
1.0
OPERATIONS (71707)
1.1
Operational Experiences
1.2
Control ofOperations....................
1.3
Spurious
Actuation of Automatic Reactor
Protection
Offsite Electrical Transient
1.4
Plant Shutdown For Cycle 24 Refueling Outage
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System
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Due To
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2.0
MAINTENANCE(62703, 61726).....
2.1
Preventive/Corrective Maintenance
2.1.1
Routine Observations....
2.2
Surveillance Observations
2.2.1
Routine Observations....
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3.0
ENGINEERING (71707)
3.1
Failure to Test Containment Isolation Manual Push Buttons......
3.2
Containment
Pressure
Transmitters
Due to Blockage
Pressure
Sensing Line
of
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4.0
PLANT SUPPORT (71707)
4.1
Radiological Controls..........
4.1.1
Routine Observations......
4.1.2
Post Accident Sampling System
4.1.3
ALARAPlanning For Outage
4.2
Securjty
4.2.1
Routine Observations......
4.3
Fire Protection ..............
4.3.1
Routine Observations......
Material Condition
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5.0
SAFETY ASSESSMENT/QUALITY VERIFICATION....
5.1
Periodic Reports .......................
5.2
Licensee Event Reports...................
5.3
Nuclear Safety Audit and Review Committee Meeting
5.4
Regional Staff/RG&E Management Meeting ......
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6.0
ADMINISTRATIVE(71707, 30702, 94600)
6.1
Deep Backshift Inspection
6.2
ExitMeebngs.........................
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DETAILS
1.0
OPERATIONS (71707)
1.1
Operational Experiences
At the beginning of the inspection period, the plant was operating at full power (98 percent).
On February
17, 1994, a voltage transient on one of the two offsite electrical power supply
circuits resulted in a fivepercent power reduction due to momentary, transient-induced actuation
of the turbine runback functions.
Operators
subsequently
reduced power to 89 percent,
as
required by technical specifications, while core axial fluxdistribution was stabilized. Full power
operation was resumed later that day and continued until March 4, 1994, when a controlled
shutdown was performed to commence the scheduled annual refueling outage.
At the close of
the inspection period, the reactor was in refueling shutdown mode, with reactor disassembly in
progress in preparation for full core offload to support extensive service water, compone'nt
cooling water, and residual heat removal system maintenance.
1.2
Control of Operations
Overall, the inspectors
found the R. E. Ginna Nuclear Power plant to be operated
safely.
Control room staffing was as required.
Operators exercised control over access to the control
room.
Shift supervisors
maintained authority over activities and provided detailed turnover
briefings to relief crews.
Operators adhered to approved procedures
and were knowledgeable
of off-normal plant conditions.
The inspectors reviewed control room log books for activities
and trends,
observed
recorder
traces for abnormalities,
assessed
compliance with technical
specifications,
and verified equipment availability was consistent with the requirements
for
existing plant conditions.
During normal work hours and on backshifts, accessible
areas of the
plant were toured.
No operational inadequacies or concerns were identified.
1.3
Spurious
Actuation of Automatic Reactor
Protection
System
Due To Offsite
Electrical Transient
Offsite electrical power for the Ginna plant is provided by two independent 34.5 kilovoltsupply
lines, designated
circuits 751 and 767.
Each circuit supplies one of the two station auxiliary
transformers,
12A and 12B. Along with normal site loads,, these transformers each supply two
safety grade (1E) 480 volt electrical buses.
Two emergency diesel generators
(EDGs) serve as
backup 1E power sources for the auxiliary transformers.
The 1E electrical buses are safety
significant in that they supply power to reactor
safety/accident
mitigation equipment
and
instrumentation.
On February 17, 1994, operators were conducting a monthly performance test of the "A"EDG,
with the diesel loaded to 2000 KW. Since normally operating plant equipment does not provide
this much load, the EDG was being operated in parallel with circuit 751,
This electrical
alignment is specified by the performance test and allows operators
to establish the required
EDG loading by backfeeding power through circuit 751.
Concurrent with the EDG testing, a mechanical problem had developed with one of the power
distribution breakers at the offsite supply station (station 204) that supplies power forcircuit 751.
At about 2:20 PM, offsite power control initiated switching operations to isolate the affected
circuit breaker.
During this operation, malfunction of a bank of automatic close-in capacitors
produced a loss of the circuit 751 supply bus.
Since the "A"EDG was coincidentally operating
in parallel with circuit 751, it assumed all of the electrical load upon loss of the normal power
supply. This large increase in load caused the EDG voltage to drop below the undervoltage trip
setpoint of the two 1E bus normal supply breakers.
These breakers opened, thus isolating the
1E buses
(buses
14 and 18) from circuit 751, with power continuing to be supplied to these
buses by the "A" EDG.
Bus 14 supplies normal power to two of the four instrument buses which power one channel of
the reactor
protection
system.
One of these
two instrument
buses
(bus "A") receives
auctioneered power from the 125-volt DC 1E electrical distribution system, such that degradation
or loss of a single power supply will not affect power at the instrument bus.
The other
instrument bus (bus "B") is powered only by bus 14.
Therefore, while the "A" EDG was
carrying circuit 751, the degraded voltage was translated to instrument bus "B". Voltage was
sufficiently low to trip reactor protection system channel "B"protective function bistables.
Since
the reactor protection
system
turbine runback
functions
(overpower
and overtemperature
temperature difference) require only one signal to satisfy the system logic, a turbine runback
occurred during the approximately four seconds of degraded voltage operation.
The automatic turbine runback decreased
plant power to approximately 93 percent.
Although
this was a relatively small power reduction, a xenon buildup complicated the operators'fforts
to maintain allowable core flux distribution. Operators were not successful at maintaining axial
flux difference within the target band, and consequently initiated a further reduction in power
to less than 90 percent,
as required by technical specification 3.10.2.9.
The power reduction
was halted at 89 percent and axial flux difference was stabilized within the target band.
Stable offsite power was restored to circuit 751 within two minutes of the transient.
After
discussion with the load dispatcher,
operators transferred the affected 1E electrical buses back
to circuit 751 and shut down the "A"EDG. Reactor power was slowly escalated,
due to end-of-
cycle core physics constraints, with fullpower operation being achieved at 10:10 PM, February
17, 1994.
The inspector arrived at the control room several minutes after the transient started and observed
good operator
response
to the transient.
Actions per abnormal procedure
(AP)-TURB.2,
"Turbine Load Rejection," were promptly carried out. The Head Control Operator effectively
maintained focus on verifying that the necessary
equipment was operating and that conditions
were stable.
Reactor power was promptly reduced when axial flux difference exceeded
the
target band.
NRC notification was completed as required by 10 CFR 50.72.
Although good procedural
adherence
was observed,
the inspector
questioned
whether the
directions in PT-12.1, "Emergency Diesel Generator 1A," for operation of the EDG voltage
regulator and speed governor, were adequate.
During this test, EDG voltage and speed control
are selected for manual control to facilitate operation of the generator in parallel with the grid.
The procedure contains a precaution to return these controls to automatic ifa safety injection
signal were to occur during conduct of the test.
The basis of this precaution is that the normal
(offsite power) feed breakers
would open in response
to a safety injection signal, and the
generator would become the sole source of power to the associated
safeguard buses.
Although
loss of circuit 751 had produced the same result, operators left the EDG voltage and speed
control in manual,
because
the precaution
was specific to safety injection.
The inspector
discussed this question with the licensee.
The licensee agreed that the precaution for returning
the EDG voltage and speed control to automatic should be extended to a loss of offsite power.
The inspector had no additional concerns on this matter.
1.4
Plant Shutdown For Cycle 24 Refueling Outage
The inspector observed portions of the power reduction and plant shutdown that were conducted
on March 4, 1994 for the Cycle 24 refueling outage.
The inspector observed that the power
reduction was well controlled. Strict procedural adherence and good communications, including
repeat-backs of directed procedural steps, were observed.
Low power operations,
pre-outage
turbine testing, and reactor shutdown were well coordinated.
Management
involvement in
operations was evident during preparations for, and conduct of, turbine testing.
The reactor
shutdown and transition to plant cooldown were conducted deliberately and without incident.
The inspector had no additional concerns in this area.
2.0
MAINTENANCE(62703, 61726)
2.1
Preventive/Corrective Maintenance
2.1.1
Routine Observations
The inspector observed portions of maintenance activities to verify that correct parts and tools
were utilized, applicable industry code and technical specification requirements were satisfied,
adequate
measures
were in place to ensure
personnel
safety and prevent damage
to plant
structures, systems, and components, and to ensure that equipment operability was verified upon
completion.
The following maintenance activities were observed:
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Work Order (WO) 19320990, "Disassemble/Inspect/Replace
V-4622 (Spent fuelpit (SFP)
heat exchanger "A" service water outlet isolation valve), observed February 22, 1994
This is a Crane model 143'lobe valve; as discussed in inspection report 50-
244/93-12, the licensee determined that these valves are susceptible to stem/disc
separation due to failure of the stem/disc lock weld. This maintenance revealed
that the lock weld on this valve had failed, but that there was still full stem/disc
V'
engagement.
Additionally, the seat ring guide (fits around the lower valve stem
to help keep the disc centered) was found to be worn. A non-conformance report
(NCR 94-009) was issued by the Quality Assurance department to document the
deficiencies identified during this maintenance and to authorize interim use until
November 30, 1994.
The inspector considered that conducting this maintenance prior to the refueling
outage was prudent, for the following reasons:
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Maintenance was coordinated withother service water system maintenance
which required both trains of SFP cooling to be secured
to provide
isolation;
SFP cooling was secured for maintenance when the heat load was low as
possible (approximately 10 months after the last refueling outage and just
prior to the current refueling outage);
With a full core off-load to be performed during the current refueling
outage,
maintenance
performed prior to the outage improved
system
reliability.
The inspector considered that deferral ofvalve replacement
as specified by NCR
94-009 would be of minimal safety significance.
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"Turbine Driven Auxiliary Feedwater Pump - Repair Outboard Pump
Bearing," observed February 25, 1994
During routine monthly performance testing on February 24, 1994, technicians
noted that the turbine driven auxiliary feedwater
(TDAFW) pump outboard
bearing cartridge temperature increase was greater than expected.
The pump was
declared
pending further investigation.
The following day, after
changing
the bearing oil and inspecting the bearing cartridge,
the pump was
operated for several hours while bearing oil and cartridge temperatures
were
monitored.
Although bearing
cartridge
temperature
was still higher
than
expected,
the long monitored
run time demonstrated
that oil temperature
eventually
stabilized
within the
band
specified
in
the
vendor's
manual.
Additionally, pump vibration was monitored periodically until oil temperature
stabilized, and indicated normal operation.
Based on these results, the TDAFW
pump was declared operable on February 25, 1994.
The inspector considered that this maintenance activity was well executed.
The
inspector considered
that the licensee's
action to declare
the TDAFW pump
operable was adequately supported by the test results.
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"Perform DP Testing on MOV-4663 (Air conditioning service water
isolation)," performed per M-64.1.2, "MOVATSTesting of Motor Operated Valves,"
revision 20, effective date February 15, 1994, observed March 1, 1994
The technicians were knowledgeable oftest methods and procedural requirements.
No deficiencies were noted.
2.2
Surveillance Observations
2.2.1
Routine Observations
Inspectors observed portions of surveillances to verifyproper calibration oftest instrumentation,
use of approved
procedures,
performance of work by qualified personnel,
conformance
to
limitingconditions for operation (LCOs), and correct system restoration following testing.
The
following surveillances were observed:
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Performance
Test (PT)-2.1M, "Safety Injection System Monthly Test," revision 10,
effective date December 30, 1993, observed February 17, 1994
PT-12.1, "Emergency Diesel Generator 1A," revision 72, effective date October 26,
1993, observed February 17, 1994
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PT-50.3, "Differential Pressure
Testing of Containment Spray Valves MOV-860C and
MOV-860D," revision 1, effective date April 28, 1990, observed February 23, 1994
T-18C, "Turbine Overspeed
Trip Test," revision
16, effective date June 4,
1993,
observed March 4, 1994
The inspector determined
through observing this testing that operations
and test personnel
adhered to procedures,
test results and equipment operating parameters
met acceptance criteria,
and redundant equipment was available for emergency operation.
3.0
ENGINEERING (71707)
3.1
Failure to Test Containment Isolation Manual Push Buttons
By letter dated February 15, 1994, RG&E requested
that the NRC staff exercise discretion to
not enforce compliance with the required actions of Technical Specification (TS) Table 4.1.2,
Item No. 9, for testing the manual containment isolation push buttons, because testing at power
could potentially challenge plant engineered
safety features.
RG&E had informed the NRC by
telephone on February 14, 1994, that it had determined that the two control room push buttons,
which can be used by operators to manually actuate the containment isolation system, had not
been
tested
as part of the routine surveillance testing of that system.
On the basis of the
submitted documents,
the NRC staff concluded that postponement of performing this test until
fl
P
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after the plant is in cold shutdown, beginning March 7, 1994, involves minor safety impact.
Therefore, discretion was exercised to delay testing until the refueling outage and not to enforce
immediate compliance with the requirement ofTS Table 4.1.2, Item No. 9, from 10:00 AMon
February
16,
1994 (the time that the limiting condition for operation for this requirement
expired) to 12:00 AMon March 7, 1994, when the plant would be in cold shutdown and the TS
requirement
would be no longer applicable.
Testing of the manual containment isolation
function willbe performed prior to resuming power operations.
The NRC staff has reviewed relevant plant procedures and supporting documentation, including
Licensee Event Report 94-04, addressing
the functional testing of both containment isolation
push buttons.
Dedicated surveillance testing of this manual function had not been performed as
required by Technical Specifications and as such, represented
failure to implement a testing
program as required by 10 CFR 50, Appendix B, Criterion XI, "Test Control."
Criterion XI
states, "Atest program shall be established to assure that all testing required to demonstrate that
structures,
systems,
and components will perform satisfactorily in service is identified and
performed in accordance with written test procedures which incorporate the requirements
and
acceptance
limits contained in applicable design documents."
Contrary to this requirement,
dedicated
testing of the manual
containment
isolation function was not incorporated
into
procedures
and implemented.
(50-244/94-05-01)
3.2
Containment Pressure Transmitters Inoperable Due to Blockage ofPressure Sensing
Line
As documented in Inspection Report 50-244/94-01, in January
1994, a control room operator
observed that one of the narrow range (0-60psig) containment pressure instruments, PI-947, was
reading slightly lower than the other two, PI-945 and PI-949.
Troubleshooting revealed the cause to be a blockage in the sensing line between containment and
the pressure
transmitter,
PT-947.
The portion of the sensing line within the containment
penetration was found to be made of carbon steel; this was the location of the blockage, which
was later determined to be rust.
Because this sensing line is shared with containment pressure
transmitter PT-948, two channels ofcontainment pressure instrumentation had been inoperable.
Review of computer-archived
data revealed that this condition had existed since June 1992.
The apparent cause ofthe blockage was that water had historically been used as the process fluid
during annual instrument calibrations.
This testing was performed by isolating the detector and
then attaching the pressure
source to a test connection within the detector isolation boundary.
Upon restoration from testing, residual water would drain from the detector, through the sensing
line, and into containment.
Exposure of the horizontal run of carbon steel tubing within the
containment penetration to this runoffwater caused rust, which, after years of service, plugged
the line. Existence of the blockage went undetected for a long period (1) because the scales of
the associated
meters were too large to show significant deflection as a result of normal
containment pressure variations, and (2) because verifying communication through the sensing
line, from the transmitters root valves to its end point inside containment, was not included in
performance testing.
The result of this problem was that it degraded the reliability of automatic initiation of certain
safety features, with the two-out-of-three (2/3) logic being reduced to two-out-of-two (2/2).
Specifically, the 2/3 logic required for a safety injection signal based on a 4 psig containment
pressure would have been reduced to a 2/2 logic with the inoperability ofP-947. However, the
diverse actuation circuitry for the safety injection signal has three additional means of actuation
(steam generator low steam pressure,
pressurizer low pressure,
and manual).
None of these
diverse means was affected by the inoperability of P-947.
The 2/3 logic required for steam line isolation actuation based on a 18 psig containment pressure
was reduced to a 2/2 logic with the inoperability of P-948.
The diverse actuation circuitry for
steam line isolation has three additional means of actuation (high steam flow, high-high steam
flowwith safety injection, and 2/4 low T-average with safety injection, and manual).
None of
these diverse features were affected by the inoperability of P-948.
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The 2/3 plus 2/3 logic required for containment spray actuation based on a 28 psig containment
pressure was reduced to a 2/2 plus 2/2 logic with the inoperability ofP-947 and P-948, however,
manual actuation was available ifrequired.
Subsequent
to identifying the plugging, the affected channels were tripped until the line was
cleared and licensee management
tasked the operations and engineering staffs to evaluate the
safety implications and implement corrective actions to preclude a recurrence.
Results of these
efforts are documented in LER 94-02, submitted to the NRC on March 4, 1994.
In reviewing LER 94-02, the inspector identified two shortcomings in the licensee
s scope of
corrective action and safety evaluation.
First, the licensee
failed to address
test program
inadequacies
that resulted in a failure to promptly identify line blockage and inoperable pressure
sensing channels.
This incident is similar in nature to that described in section 3.1 above, in
which containment isolation pushbuttons were not tested, and represented
a second example of
a violation of the requirements of 10 CFR 50, Appendix B, Criterion XI, "Test Control" (see
Detail 3.1).
The second shortcoming was that an evaluation of the effect of the loss of one (circuit 751) of
two offsite power sources
on the remaining operable pressure
channels
was not addressed.
Automatic containment spray initiation could be compromised by a loss ofcircuit 751 in certain
situations
because
such
a loss could temporarily deenergize
safety bus
14 and associated
instrument bus "B", which has no backup power supply. Instrument bus "B" powers one set of
pressure
sensing channels (PI-946 and PI-949).
Therefore, loss of instrument bus "B" could
cause
the loss of an additional two channels of containment pressure
instrumentation.
The
licensee acknowledged this design vulnerability and willaddress this evaluation in a supplement
to LER 94-02.
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The inspector reviewed the licensee's
immediate corrective actions taken in response
to this
incident including: placing the affected pressure channel relays in the tripped position, clearing
the sensing line, daily trending narrow range containment pressure
indications on the plant
computer, revising the instrument calibration procedure
to use air rather than water as the
process fluid, and scheduling inspection of the remaining containment pressure
sensing lines
during the refueling outage.
The inspectors had no further questions at this time.
4.0
PLANT SUPPORT (71707)
4.1
Radiological Controls
4.1.1
Routine Observations
The inspectors periodically confirmed that radiation work permits were effectively implemented,
dosimetry was correctly worn in controlled
areas
and dosimeter
readings
were accurately
recorded, access to high radiation areas was adequately controlled, survey information was kept
current, and postings and labeling were in compliance Lith regulatory requirements.
Through
observations ofongoing activities and discussions with plant personnel, the inspectors concluded
, that the licensee's radiological controls were generally effective.
4.1.2
Post Accident Sampling System Material Condition
On March 1, 1994, operators established
a purge of the pressurizer
steam space to the volume
control tank, through the post-accident sample system (PASS).
The purpose of this purge was
to reduce the hydrogen concentration in the pressurizer in preparation for the refueling outage.
While this purge was in progress,
a health physics (HP) technician prepared to perform a water
flush of the PASS deionized water header.
The PASS is configured
such that these two
operations can be performed simultaneously; however, as preparatio'ns for the flush progressed,
the HP technician observed
steam coming from a flexible hose in the DI water header.
A
portable radiation survey instrument in the area of the steam discharge alarmed, indicating that
the pressurizer was the likely source of the steam.
The HP technician isolated the flexible hose
and then informed the control room operators of the problem.
Venting of the pressurizer
through the PASS was secured.
Extensive radiation and contamination surveys were performed.
The HP technician was found
to be contaminated with short-lived radioactive gases, and was decontaminated.
Radiation levels
in the vicinityof the steam leak were normal.
Some loose surface contamination was detected
on the floor in the area of the leak; the area was roped off, and subsequently
cleaned
and
decontaminated.
Since the deionized water header cross-connects
to several other radiologically
clean water systems, all connecting water systems were sampled for radioactive contamination.
Small concentrations ofradioactive gases and particulates were found in the condensate
storage
tanks.
The concentrations
were so low as to not pose a radiological concern for normal use.
No significant contamination was detected in the remaining deionized water systems associated
with this event.
(
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C
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In response to this event, the licensee initiated a root cause analysis investigation.
The affected
portions of the PASS were removed from service, pending results of this investigation and
determination of corrective action. Multiplevalve seat leakage through the ih-inch line was an
apparent contributor to this event.
The inspector examined the material condition of the PASS.
The inspector noted that the existing installation ofthe air operator forvalve AOV-10017 (PASS
sample cooler outlet AOV to PASS liquid and gas sample panel), a valve that is normally shut,
could have allowed for some seat leakage.
This, and several minor material discrepancies,
were
addressed
to the licensee.
The inspector assessed
the licensee's
response
to this radiological event to have been good.
Based on the nature and duration of the discharge,
as well as the measured contamination levels,
the inspector assessed
that the radiological significance of this event was minimal.
At the close of the inspection period, the licensee
s root cause investigation was in progress.
The inspector had no further questions at this time.
4.1.3
ALARAPlanning For Outage
The inspector reviewed
the ALARA planning packages
that will be used to support core
offload/refueling operations and motor operated valve testing during the 1994 outage.
Through
this review, the inspector determined that the licensee has proactively addressed
measures
to
reduce
exposure
to personnel
performing these
tasks.
These
measures
included mock-up
training, job site decontamination,
shielding installation, equipment pre-staging,
and work
package/procedure
development.
The inspector
concluded
that these
measures
reflected
attention-to-detail in job planning and preparations to minimize dose.
4.2
Security
4.2.1
Routine Observations
During this inspection
period,
the inspectors
verified that x-ray machines
and metal
and
explosive detectors were operable, protected area and vital area barriers were well maintained,
personnel were properly badged for unescorted or escorted access,
and compensatory
measures
were implemented when necessary.
4.3
Hre Protection
4.3.1
Routine Observations
The inspectors periodically verified the adequacy of combustible material controls and storage
in safety-related areas of the plant, monitored transient fire loads, verified the operability of fire
detection and suppression
systems,
assessed
the condition of fire barriers,
and verified the
adequacy of required compensatory
measures.
No discrepancies
were noted.
10
5.0
SAFETY ASSESSMFAT/QUALITYVERIFICATION
5.1
Periodic Reports
Periodic reports
submitted by the licensee
pursuant
to Technical Specification 6.9.1 were
reviewed.
Inspectors verified that the reports contained information required by the NRC, that
test
results
and/or
supporting
information were
consistent
with design
predictions,and
performance specifications, and that reported information was accurate.
The following reports
were reviewed:
Monthly Operating Reports for January and February 1994
Semi-annual Radioactive Effluent Release Report (July-December
1993)
No unacceptable
conditions were identified.
5.2
Licensee Event Reports
Licensee Event Reports (LERs) submitted to the NRC were reviewed to determine whether
details were clearly reported,
causes
were properly identified, and corrective actions were
appropriate.
The inspectors also assessed
whether potential safety consequences
were properly
evaluated, generic implications were indicated, events warranted additional onsite follow-up, and
applicable requirements of 10 CFR 50.72 were met.
The following LERs were reviewed (Note:
date indicated is event date):
94-001, Radiation Monitor R-32 (Main Steam Line) Not Properly Calibrated.
R-32
output was one decade low due to a technician's mathematical error.
(January 19, 1994)94-002, Containment Pressure Transmitters PT-947/PT-948 Inoperable Due to a Blocked
Sensing Line (February 2, 1994)
The inspector concluded
that LER 94-001 was accurate,
met regulatory requirements,
and
appropriately identified the root causes.
Shortcomings identified in LER 94-002 are addressed
in section 3.2 of this inspection report.
In response,
the licensee willsubmit a supplement to
LER 94-002.
5.3
Nuclear Safety Audit and Review Committee Meeting
On February 24, 1994, the inspector attended a meeting of the Nuclear Safety Audit and Review
Committee.
Topics included review of recent plant events, technical specification improvement
program status, a presentation by the modification subcommittee including discussion of recent
PASS modifications, review of licensee event reports, an outage overview presentation,
and a
review of QA/QC subcommittee activities. The inspector determined that the licensee satisfied
11
the requirements oftechnical specifications 6.5.2 regarding committee membership composition
and quorum.
The inspector concluded that topics were candidly discussed
and were presented
with sufficient detail for board members to assess
the safety significance of the agenda issues.
5.4
Regional Staff/RG&E Management Meeting
On February
17, 1994, RG&E management
met with the NRC staff in the Regional office to
discuss proposed changes to the licensee's Quality Assurance Plan, including implementation of
a peer inspection program.
Additional topics discussed
were 1994 refueling outage plans,
maintenance rule implementation status, and quality improvement initiatives.
Attendees at this
meeting are identified in Attachment I.
Handouts provided by the licensee are included as
Attachment II to this report.
6.0
ADMINISTRATIVE(71707, 30702, 94600)
6.1
Deep Backshift Inspection
During this inspection period,
deep backshift inspections
were conducted
on February 21,
February 27, March 5, and March 6, 1994.
6.2
Exit Meetings
At periodic intervals and at the conclusion of the inspection, meetings were held with senior
station management
to discuss the scope and findings of inspections.
The exit meeting for the
current resident inspection report 50-244/94-05 was held on March 14, 1994.
I
ATTACHMIi22IT1
NAME
REGION I/RG&EMEETING
QA PROGRAM CHANGES AND 1994 REFUELING OUTAGE PLANS
FEBRUARY 17, 1994
TITLE
~R&E
Steven Adams
Charles Anderson
John Cook
Thomas Marlow
Robert McMahon
Joseph Widay
George Wrobel
Superintendent,
Support Services
Manager, QA
Manager, Planning and Scheduling
Manager, Quality Performance
QC Engineer-Operations
Plant Manager-Ginna
Manager, Nuclear Safety &Licensing
Suresh Chaudhary
Allen Johnson
William La2arus
James Linville
Thomas Moslak
Senior Reactor Engineer, DRS
Project Engineer, NRR
Chief, Reactor Projects Section 3B, DRP
Chief, Projects Branch 3, DRP
Chief, Materials Section, DRS
Senior Resident Inspector, Ginna
ATTACHM<22lT2
REGION I/RG&EMEETING
QA PROGRAM CHANGES AND 1994 REFUELING OUTAGE PLANS
MEETING SLIDES
FEBRUARY 17, 1994
RGckElNRC MEETING
February 17, 1994
nl
J. Widay
5 Min.
li
V if'
nPr
m
~
Purpose
~
Program Description
~
CFR 50.54 Change Basis
Questions/Open
Discussion
S. Adams
5 Min.
C. Anderson
10 Min.
15 Min.
R. McMahon
20 Min.
ali
Im r vmn
ii iv
T. Marlow
15 Min.
IV.
1
4
J. Cook
15 Min.
V.
Mi
l Im lmn
i
S. Adams
15 Min.
QUALITYVERIFICATIONPROGRAM
PUIU'OSE
i
fWr
li h
~
Enhances ownership of work
accomplished
Clarifies accountability of work
~
Enhance pride in workmanship
n
~
Eliminate waiting for inspector
QUALITYVERIFICATION
B
k r
n
~
Quality standards traditionally
assigned to the Quality Control
organization.
~
Maintenance expressed
interest in
performing "quality" verifications.
~
Quality Performance
screening of
selected inspection hold points with
pertinence to ANSI and other
recognized and appropriate
engineering codes and standards.
t
~
Based on importance, complexity, and
training.
QUALITYVERIFICATION
Quality Verification (QV) - Checks or
process monitoring performed and
documented to assure task acceptability by
an individual who is trained and qualified
to perform the task, but did not perform
the task being verified.
QUALIZTVERIFICATION
ifi A
i
i n
'n
quality inspection
quality inspection
quality verification
quality verification
for cleanliness
level B, C 8c D
EXAMPLE
Cleanliness Inspection Procedural Change to
Quality Verification
M- 71
" 'IDi hr
V v
M in
During work planning within the shops if
Quality Control and Maintenance concur
that an existing Quality Control hold point
is for an.ASME Class 2 or 3 component
requiring Cleanliness level B, C or D then
V
'
would be applicable.
step 5.3
LD P
step 5.3.1
JQ.C.
to perform
cleanliness inspection in
accordance with
m/QCIP-5 on all parts prior
to assembly.
ÃrJQC
QUAI.IZTVERIFICATION
Pr nnl
lifi
i n
~A~ri gt;
i
V ifi
N4
2 LvlI
Education
H.S. Graduate or
equivalent
H.S. Graduate or
equivalent
Experience
4 yrs. related plus
qualif. per N18'.1
3 yrs. related or
1 yr. as a Level I
Physical
near vision - annual
color vision - initial
near vision - annual
color vision - initial
Requalification
3 yrs. maximum
3 yrs. maximum
~
Quality Verification requirements
meet or exceed the N45.2.6 Level II
requirements.
1
~
Quality Verifier training includes instructions on duties and
responsibilities of a quality verifier and demonstrated proficiency.
QUALITYVERIFICATIOX
n
n
~
Quality Verifier did not perform the
specific task being verified.
~
Consistent with N45.2 QA Program
requirements
Cl
organizational structure
verification of conformance
~
Effectiveness by QA/QC oversight.
QUALITYVERIFICATION
a
Verifier reports to Line Organization
Documentation of discrepancies.
r
'n
n Tr
in
~
Assessment
results willbe tabulated
and trended by QC.
Discrepancies willbe tracked by
Maintenance.
QUALIZTVERlFICATION
L
T
Selection of activities
Define Quality Verification
Interview line organization
Presentation of program to GPC and endorsement
OS/01/93
Completed
12/13/93
Completed
12/15/93
Completed
01/07/94
Completed
Presentation of program to Maintenance and
endorsement
01/07/94
Completed
Write and approve implementing Administrative
procedure
Write.and approve guidelines that direct torquing
and cleanliness
01/14/94
Completed
01/28/94
Completed
Provide an assessment
plant of QV during the
94 Outage
Approval of changes
to A-503 & A-1603.3
Revision to QAM Sect. 10 and Glossary
10CFR50.54 Analysis
Revise QCIP-1 gnspection Instructions)
NRC introduction meeting to QV
Training of Maintenance personnel
02/01/94
Completed
02/02/94
Completed
02/07/94
Completed
02/10/94
Completed
02/15/94
02/17/94
02/28/94
QUALIZYVERIFICATION
vri h
~
QA/QC personnel
a
Sample plan
~
Specific criteria assessed
a
Week1y progress meetings
'
Updates to NAM and Line
Management
Final Assessment
r
10 CFR 50.54 CHANGE BASIS,
Impact on Traditional QC Inspection
Scope Limited - routine, repetitive
tasks
~
Complexity Modest - witness, check
~
QC Involvement Remains Extensive
CONSISTENCY WITH
ANSI/IEEE/APPENDIXB
Standards
recognize requirement
variability e.g. N45.2.8
~
Screening criteria based on variability
for:
Cl
Risk
C3
Complexity
C3
Inspector Training
~
QV selections consistent with criteria
~
QV approach - consistent with
Appendix B, II (control extent
consistent with Importance to Safety)
T
N - Comparison of Control
(Quality Inspection vs Quality Verification)
D - Similarity
~
Attribute definition
~
Acceptance Criteria Specified
~
Education and Experience
~
Structured Training
Demonstrated Proficiency
Near and Color Vision
~
Qualification Documented
Verifier not responsible
~
QA/QC Oversight
~p
h
UNCHANGED ELEMENTS
.
~
Total QC/QV Hold Points Unchanged
~
Quality Inspections remain QC
cognizance
~
QV - Independent Verification
Similarity
SUMMARYAND CONCLUSION
Personnel qualifications
~
Independence
~
QA/QC Oversight
Ginna Safety and Reliability Enhanced
Coimnitments Not Reduced
RG&E/NRC REGIONIMEETING
February
17, 1994
i n
I
n
iI
n
r n
r
Rviin
r Dir
i
i Pr
m rhniv
mn
V.
r R
w
1
1
1
i
n in
D
m n
In rf
li
n-I.in R vi
VIII.
R
'
Quality 'Provement initiative Milestones
Attachment
2
Nuclear Directives
Prograa Aevision:
Expand
QA Scope
Change to VP trow Sr.
Reduce In-Line Reviews
P-8 Audit Frequency
Work by Directives
QA Manual Phase
Out
Reforest por SRP 17.3
) 994
Develop/Approve
Develop/Approve/Subait
NAC Approval
or 60 days
Iepl scent
1996
Annual
FSAA Update
VP chango
Align w/prograw
Develop
QA Grading
QV Prograa
Prepare/Subait
Develop, Train
Iapleaent
Asview, Expand as appropriate
Reduce In-Line Reviews
Coaproheneive
Assessments
Tech Spec Revision
Aeviso Section
S.O
Interia Prograw Revision
Audit Frequency
Prepare/
a t
Iwploaont
Iapleaent
MC Approval
leplseent
NRC Approval or 60
days
lnteria Prograw Aovision
Procedure
Review Por iodicity
prepare/
Subwit
legis aent
QUALIZTASSURANCE PROGRAM
FOR STATION OPERATION
QAPSO REVISION
1
f
P17
Ar
C3
Management
0
Performance
0
Assessment
r
IP ni i iv
GINNA NUCLEAR DIRECTIVES
~
Contain Existing Appendix B
QA Criteria
~
Nuclear Directives WillReplace
QA Manual
~
Ownership of QA Policy/Directives
by Vice-President
~
Corporate Responsibility for:QA
Program Shifting from Senior Vice-
President to Vice-President
~
Willbe Included in QA Program
Submittal, End of 1994
L
COMPREHENSIVE ASSESSMENTS
a
.
Performance Based Assessments
Transition to Proactive Oversight
versus Mandated Audits
~
Determine Assessment
Scope and
Process
Cl
Effective Scoring System
0
Areas of Concentration
Cl
Past Performance Dictates
Priority, Frequency, Importance,
History
Overall Results Determine Need for
Audit
PROCEDURE
REVIEW'ERIODICIZY
~
Symptom Based, Event Driven
Procedure Review Will Continue
~
Reviews Replaced With Programmatic
Controls Based Upon Procedure
Usage and Alternative Procedure
Control Programs
Periodic Review Requirements for
Certain Procedures
Deleted
El
Administrative
C3
Technical
.1I
~
.
T
Y
E
t
LICENSINGDOCUMENTS INTERFACE
a
Plans to Upgrade to Improved Technical Specifications
Evaluate Administrative Controls Section 6.0 of Existing T.S.
Section
6.5.1
6.5.2
NSARB
Description
Relocate/Change
Emergency,
and Security
Programs
Emergency,
and Security
Programs
6.8
Procedures
Relocate review and approval
process of procedure changes
6.10
Record Retention
Relocate to QA Program or
~
Relocation of changes to UFSAR would be submitted to NRR along
with TS Amendment
~
Relocation to QAPSO willrequire interim submittal (March)
~
Potential mid-year QAPSO submittal - procedure review
End of year major revision to QAPSO.
~
UFSAR Chapter 17 willcontain QAPSO
~
Changes required to Chapter 13 of UFSAR
QUALIZTIN-LINEREVIEW
.
PHASE OUT
~
Establish Transfer Plans
Cl
Procedures
Cl
Approvals
CI
Training
Cl
Define Oversight Methodologies
Transfer Processes
to Line
Organizations
Implement Oversight
Discontinue Low Value-Added
Reviews
Grading of QA Requirements
.
r Ini i iv
1
i
Cl
Documentation
0
Control
Cl
Verification
1 -
h
1
i
ff
AllSteps
Verifications
Hold Points
N/A
Yes
N/A
Final Signor
N/A
N/A
N/A
Final Signoff
- QUALITYVERIFICATION .
FUTURE PLANS
Goal is to maximize worker
responsibility for quality while
assuring optimum utilization of
resources.
~
Three year program to integrate
traditional QC into line organizations.
~
Existing QC personnel transferred into
Operating Departments.
Department personnel trained and
qualified to same standards
as present
QC personnel.
~
Results reporting shifted to line
organizations.
1994 OUTAGE PRESENTATION
mn lni
i IP
n I
1994 OUTAGE OBJECTIVE
.
RGRE
ORK
SAFETY
QUALITY
SCHEDULE
INNA STA110h
.
AIL
<<9!tPIARY DARCHAR~
tlARCH
APRlL
5
5
5
5
tl
I
el
1
F
5
5
tl
1
N
'I
F
5
5
'I
8
1
F
5
5
?
6
9
13
II
l2
!3
I
l5 Il
l6
19 i2
2I
22
2l
21
2
25
2?
I
V
1
F
5
5
1
. D
I
F
5
5
26
29
30
31
2
I
2
3
1
5
5
?
6
9
~91
CTIAR91
L Nf,/PLANT SIRJTINNNI/CODLDDNN
I
H Gst .
5
UR IN
NSt'EC
ON
I
H
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AND 5 IIV C
P. VAL
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h
I SASSEICLT
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9tlAR91
ISA << TNLE R
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REACTOR
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I
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5/G-tIANIPU>>ATDA INSIALLA'IION/EODT CU?tPEN'I
I
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SEAL INSPECTIOh
ISINRS~ SIIIAIIS
A RCP
REASSEIISLT
I
)
B 5/G SLEEVING/PLUGGING
)
I
ACTOA tlf.AC
It FUf.<</R <<f
It
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'LIIAF9 ~ SFRARR
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CURD Nl
VERI SLEEVES
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LEGEND
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6 AI'R9
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I /Hf AIUP 1C 54?
0[C/CRIR ICAL IT'I I[5?5
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LDAPII91 ~ I 2 APR92
R'CT0$
<<IARIUP/PHTSILG II.52 INC
2
2 IAPR9<>
IN[
PR[-tlU I
P
lhPR91
RAIN RCS/CLOS[
PstltlART
SAFR9 ~
6I R9I
FILL I ILRI R 'SIFLC 'AR":- IL I III,
BAPR9A
I
OUTAGE
PERFORMANCE
INDICATORS
QFETY
!~
1993
GOAL
1993
ACTUAL
1994
GOAL
~ 1994
BUSINESS
PLAN
Lost
Time
Accidents
0
0
0
0
Person-Rem
Ex osure
Contaminations
Rad
Waste
Generation
210
155
140
140
96
100
1000
cu.
980
cu.
900
cu.
ft/wk
ft/wk
ft/wk
190
130
9,000
QIJAL1TY.
Preventive
Maintenance
Corrective
Maintenance
Ins ections
Rework
9096
9096
90%
96. 4%
93.896
99. 196
0.9%
9596
9596
9596
!,! 'EGUL'ATORY " I~
"
License
Event
Re orts
(LERs)
HRC
Si
ificant
Events
0
0
0
0
PI ANT
IMPRQVEMENTS
~
Modification
Work
90%
10096
95%
Startu
Problems
Continuous
Run
0
60
60
0
60
~i ~
CORPORATg
. e e~
Outa
e
Len
h
55
45.3
39
49
RF/kal:outper94.ind
1994 AI.AO OVERVIEW
V
1
Defueling
HP Turbine Minor Inspection and
Preseparator
Pipe Wall Repair
PORV Refurbishment
A RCP Seal Inspection
A RCP Motor Swap
Service Water Outage of A and B
Loops
C3
Valve
Replacement/Ref'urbishment
C3
Inspection
1&4 AIck0 OVERVIEW
iv'
(cont'd)
~
Refurbishment of 101XU's
C3
0
Primary Side Valve Inspection
0
CV 842 A8cB
El
CV 867 AAB
~
S/6 Inspection and Repair
I
a
Rod Control System Card
Replacements
8c Minor Modifications
Rx Compartment and Bus Duct
Cooler Replacement
¹ Work Orders Planned for Outage
C3
IA,C
338
CI
Mechanics
118
Cl
Pipe
276
C3
49
CI
Electricians
TOTAL
928
OUTAGE RISE MANAGEMENT
Use of PRA to Evaluate Outage
Configuration
Delayed Installation of S/G Nozzle
Dams Until After Defueling
~
Improve PORC Overview of Outage
Activities
~
Fire Protection Review of Outage
Activities
Added NSL Personnel to Outage
Safety Assessment
Team
GINNA STATION
MAPPFENANCE RULE IMPLEMENTATION
Current Status
II.
Training
Peer Group Involvement
Project Team Composition
V.
Major Milestone Schedule
Reorganization in November to
dedicate one Manager full time to
Maintenance Rule implementation
efforts.
Project Team formed - 1st
meeting 2/10/94
~
EOP review for "Non-Safety
(Operations)
80 key players briefed (10 sessions)
including
~
(Company-Wide) 31 affected
Mgrs 8c key supervisory
personnel
~
System Engineers
~
Operations (4 of 6 shifts)
Craft training planned after
project completion
a
Westinghouse Two Loop Group
~
MR Info. Sharing Committee
. Mtg. (NMPl,"NMP2,
Fitzpatrick, Ginna)
a
Region
1 Utilities
Project Manager
John Fischer, Director Maintenance Rule
Design Engineering
Len Sucheski, Supervisor, Structural Engineering
Instrumentation 8c Control and Electrical
Robert Popp, INC/Electrical Station Engineer
Materials Engineering 8c Inspection Services
Frank Klepacki, ISI Engineer
Nuclear Safety Sc Licensing (Programs)
David Wilson, Associate Engineer
Nuclear Safety 8c Licensing (License Renewal)
John Jorgensen,
Senior Nuclear Engineer
Operating Experience
Frank Puddu, Operating Experience Specialist
rl
jl
'J
'I
n(
(cont'd)
Operations
Doug Peterson,
Operations-Maintenance
Liaison
(Shift Supervisor)
Preventive 4, Predictive Maint./RCM/NPRDS/Root
Cause Analysis
Tom Plantz, Maintenance Systems Manager
Performance Testing
Gregg Joss, Results 4, Test Supervisor
Scheduling
John Cook, Planning 8c Scheduling Manager
System Engineers 4 Modifications
Jeff Wayland, Lead Engineer - Systems Engineering
Sub stations
Terry Walter, Manager, System Design Engineering
Jeffrey I'iske, Supervisor, Substation Design
V.
2/94
5/94
6/94
10/94
Majority of the data
gathering in place
Complete MR scoping
Determine risk significance
Identify affected processes
J
AllSSC performance
criteria complete
Allaffected processes
modified
4Q94
4Q94
IQ95
7/95
7/96
C assist visit
RG8cE QA Audit
NRC non-enforceable
inspection
RGB Goal MR
Implementation Deadline
10CFR50.65 Legal MR
Implementation Deadline
H
>l