ML18152A063
| ML18152A063 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/15/1996 |
| From: | Branch M, David Kern, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A064 | List: |
| References | |
| 50-280-96-05, 50-280-96-5, 50-281-96-05, 50-281-96-5, NUDOCS 9607230436 | |
| Download: ML18152A063 (33) | |
See also: IR 05000280/1996005
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-280/96-05 and 50-281/96-05
Licensee:
Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:
May 5 through June 15, 1996
Inspectors:
Approved by:
D. M. Kern, Resident Inspector
W. K. Poertner, Resident Inspector
R. D. Gibbs (section 3.9)
F. N. Wright (section 5.0)
J. W. York (section 4.0)
P. ~~lo~~;;)
G. ~B"eisle~
Reactor Projects Branch 5
Division of Reactor Projects
SUMMARY
Scope:
7-/'J...-9'-r
Date Signe
This routine resident inspection was conducted on site in the areas of plant
operations which included plant status, draining the Unit 2 RCS to reactor
vessel flange level, POTT gas release to containment, Unit 2 reactor trip
during startup, Unit 2 restart, Unit 1 power reduction due to high sulfate
concentration in SGs, Unit 1 power reduction due to relay failure, inoperable
control room air handling units, inoperable charging pump service water pumps,
outage commitment review and open item followup review; maintenance which
included review of Unit 2 rod testing to satisfy NRC Bulletin 96-02,
replacement of Unit 2 Rod M-10 CROM rod travel housing, rod system testing for
DCP verification, RWST recirculation pump suction valve repairs, AAC diesel
generator testing, Unit 2 TDAFW pump operability testing, Unit 2 MG-6 relay
9607230436 960715
ADOCK 05000280
G
ENCLOSURE 2
2
failures, Unit 2 CW REJ replacements and maintenance program review;
engineering which included review of safety and oversight committee
activities, review of engineering documents, engineering interface with other
groups, problems with safety related batteries, problems with safety related
relays - type MG-6, 125 VDC system ground detection equipment, and 480 VAC
ground detection equipment, plant support which included occupation radiation
exposure control program changes, external and internal .exposure controls,
control of radioactive materials and contamination, surveys and monitoring,
maintaining occupational exposures ALARA, UFSAR review in the radiation
protection area; and review of UFSAR commitments.
Plant Operations
During the planned draindown of the Unit 2 RCS to reactor vessel flange level,
operator performance was judged to be good with excellent command and control
demonstrated.
Communication within the control room was also good.
However,
problems were encountered with the radio-phone used to communicate with the
operator in containment who was locally monitoring standpipe level* (paragraph
2. 2).
Failure to isolate relief valve 2-DG-RV-202 resulted in a PDTT gas release to
containment.
The failure to ensure that the system was aligned to support the
work order task requirements and failure to ensure that the equipment was
prepared for maintenance prior to approval of the work order is identified as
violation 50-281/96-05-01, Inadequate System Isolation (paragraph 2.3).
Steam dump and feedwater regulation valve control instrumentation design
requires operators to use manual control during r~actor startups and low power
operation.
Manual control has made SG level control during reactor startups a
highly challenging activity.
On ~une 6, Unit 2 tripped from 16 percent power
due to high B SG water level. Safety systems responded as designed.
Operators responded to the reactor trip in a safe and well controlled manner
(paragraph 2.4).
Evolution briefings and communications were good during the Unit 2 restart and
operator performance and supervisory oversight during the startup were
excellent. Several minor equipment problems were experjenced during the Unit
2 restart on June 7.
Operators responded promptly to each equipment problem
(paragraph 2.5).
A resin intrusion to the Unit 1 SGs forced a downpower to 30 percent reactor
power on June 7.
Immediate actions to reduce power level and to stop the
resin intrusion in addition to ongoing efforts to improve condensate polisher
operations demonstrated appropriate concern for SG integrity (paragraph 2.6).
Operations' decision to initiate a reactor shutdown after identification of a
failed RPS relay was a conservative decision based on available information.
The relay replacement and testing activity was well coordinated between
operations, maintenance, and the system engineer (paragraph 2.7).
Immediate corrective actions for inoperable main control room AHUs were
appropriate.
The operating crew demonstrated a good questioning attitude
3
by promptly identifying that the main control room AHUs were degraded
(paragraph 2.8).
Operators promptly responded to a low discharge pressure indication and
reestablished charging pump service water flow in an expeditious manner
(paragraph 2.9).
Unit 2 refueling outage commitments and items of regulatory interest were
completed during the Unit 2 refueling outage (paragraph 2.10).
Long term corrective actions associated with the violations associated with
the Unit 1 RCS draindown event described in NRC Inspection Reports Nos.
50-280/95-20 and 50-281/95-20 were completed prior to commencing the Unit 2
refueling outage (paragraph 2.11).
Maintenance
Technicians promptly diagnosed and replaced a failed rod control circuit card
during low power physics testing (paragraph 2.4).
Unit 2 control rod testing to satisfy NRC Bulletin 96-02 was conducted.
The
inspectors verified that test prerequisites and reactor plant conditions
including reactivity shutdown margin were properly established.
Communication
repeatbacks between technicians at the rod control cabinets and the test
coordinator were clear (paragraph 3.1).
Unit 2 control rod testing was performed in a professional manner and clearly
demonstrated RCCA operability prior to reactor startup from the refueling
outage (paragraph 3.1).
The licensee's corrective actions for control rod M-10 position indication
problems were satisfactorily completed (paragraph 3.2).
Control Rod System testing results for DCP verification met procedural
acceptance criteria (paragraph 3.3).
The work activity on the RWST recirculation pump suction valve was
accomplished in accordance with the work package requirements and the
maintenance activity was well coordinated to minimize the time that the freeze
seal was required to provide isolation for the work activity (paragraph 3.4).
Alternate AC Diesel Generator testing was performed in accordance with the
test procedure and good command and control was exhibited by the operators
conducting the procedure (paragraph 3.5).
Unit 2 turbine driven auxiliary feedwater pump testing was successfully
completed to satisfy TS and IST program requirements.
Operators were familiar
with the test procedures and communicated clearly. Mechanical problems
identified during the test were appropriately resolved (paragraph 3.6) .
4
The number of MG-6 relay failures during testing were high.
The licensee
continues their evaluation of the cause and potential reportability (paragraph
3.7).
Eight CW REJ were replaced during the Unit 2 refueling outage.
Work packages
for this maintenance were comprehensive (paragraph 3.8).
Maintenance personnel were well qualified for their positions, work areas were
orderly and well maintained, the plant material condition was excellent, and
procedures were clear and concise (paragraph 3.9).
Engineering
After a review of the meeting minutes for the MSRC for the period of January
through May 1996, the inspectors observed that the committee was successfully
performing the functions delineated in the committee's procedure (paragraph
4. I).
A continuing strength exists in the area of materials/metallurgical solutions
to corrosion, erosion problems identified at the site (paragraph 4.2).
During a review of engineering interface with other groups, the inspectors
concluded that there was an excellent interface between engineering and the
groups they supported (paragraph 4.3) .
No concerns were identified during review of station battery problems
(paragraph 4.4).
The licensee is reviewing MG-6 relay failures for potential reportability
pursuant to 10 CFR 21 (paragraph 4.5).
Design concerns were identified in the ground detection schemes for the 480
VAC Distribution System and the 125 VDC Distribution System.
Inspection
Followup Items were established to track these issues (paragraphs 4.6 and
4.7).
Plant Support
Radiation exposure control program changes reviewed were found acceptable
(paragraph 5.1).
The licensee was implementing adequate RP controls and monitoring individual
occupational radiation exposures in accordance with the requirements.
All
individual doses reported were within 10 CFR Part 20 limits (paragraph 5.2).
Overall, the licensee appeared to have a good contamination control program
(paragraph 5.3).
The licensee was utilizing ALARA techniques, developing challenging ALARA
goals and making progress in reducing collective doses for the staff
(paragraph 5.4) .
5
Review of the UFSAR with respect to radiation protection did not identify any
discrepancies (paragraph 5.5).
LER 50-281/96-002 was closed (paragraph 5.6) .
REPORT DETAILS
Acronyms used in this report are defined in paragraph 9.0.
1.0
PERSONS CONTACTED
Licensee Employees
- Benthall, W., Supervisor, Procedures
- Blount, R., Superintendent of Maintenance
Christian, D., Station Manager
- Cramer, R., Maintenance
Crist, M., Superintendent of Operations
- Erickson, D., Superintendent of Radiation Protection
- Hayes, D., Supervisor, Administrative Services
- Lovett, C., Supervisor, Licensing
- McCarthy, J., Assistant Station Manager, Operations & Maintenance
- Meekins, A., Supervisor, Construction Engineering
- Sowers, T., Superintendent of Engineering
- Stanley, B., Nuclear Oversight
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
2.0
PLANT OPERATIONS (40500, 71707, 92700)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indications to assess operability.
Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
2.1
Plant Status
Unit 1 operated at power the entire reporting period.
On June 7 power
was reduced to less than 30 percent due to high sulfate concentrations
in the steam generators (paragraph 2.6).
The unit returned to 100
percent power on June 8.
On June 11 a reactor shutdown required by TSs
was initiated due to a failed relay (paragraph 2.7).
The power
reduction was stopped at 58 percent when the relay was replaced and
tested.
The unit was returned to 100 percent power later that same day.
Unit 2 began the period shutdown for refueling.
Entire core offload was
completed on May 13.
Core reload was completed on May 26, *and the head
was set on May 27.
A reactor trip occurred on June 6 prior to placing
2
- ~
the generator online {paragraph 2.4).
The unit was returned to service
on June 7 and obtained 100 percent power on June 10 (paragraph 2.5).
2.2
Draining the Unit 2 RCS to Reactor Vessel Flange Level
On May 7, the inspectors witnessed draining of the RCS from
approximately 22 percent in the PZR to a level just below the reactor
vessel flange.
This draining was part of the refueling evolutions
necessary to remove the reactor head.
During previous RCS draining
evolutions, problems had been noted associated with verification of
actual RCS level.
As required by procedure 2-0P-RC-004, Draining The
RCS To Reactor Flange Level, revision 9, two cold calibrated PZR level
transmitters were used for the initial RCS level indication while level
was still in the PZR.
During the draindown the licensee utilized
several methods to verify level changes in the RCS.
Portions of the
RVLIS were maintained functional for trending purposes only.
Additionally, the inventory balance used a temporary recorder to more
accurately measure BRT level changes.
The reactor vessel level
standpipe performed as designed and there was good agreement between
local indication and CR standpipe indication.
The inspectors observed that normal operator staffing was augmented
which allowed the operator in charge to concentrate on the task at hand.
Operator performance was judged to be good with excellent command and
control demonstrated.
Communication within the CR was also good.
However, problems were encountered with the radio-phone used to
communicate with the operator in containment who was locally monitoring
standpipe level. These observations were discussed with operations
management.
The following day the inspectors monitored additional
radio-phone communication between the CR and containment and noted
improvements.
2.3
POTT Gas Release to Containment
On May 18 at 10:22 a.m., the ventilation vent vent radiation monitors
went into alert and the operator noticed that overhead gas pressure had
decreased by approximately 2 psi.
At 10:27 a.m. the operator isolated
the POTT from the overhead gas header and terminated the release to the
Unit 2 containment atmosphere.
The operators determined that the
release path was through relief valve 2-DG-RV-202 that had been removed
from the system to perform setpoint testing.
When the valve discharge
flange had been disconnected a vent path to containment was established
from the overhead gas header through the POTT.
The calculated release
was a small fraction of TS allowable limits (less than 12 percent).
The inspectors reviewed the work order and tagout associated with the
maintenance activity.
The relief valve was removed by WO 00334395, Test
RV 2-DG-RV-202.
The WO referenced tagging reports 2-96-CH-0067, 2-96-
RC-004, 2-96-RC-008, and 2-96-RC-0010.
The inspectors determined that
the tagouts referenced did not establish an adequate isolation boundary
to perform the maintenance activity.
VPAP-2002 section 5.7 requires the
Shift Supervisor to align systems to support work activities and
3
equipment be prepared for maintenance prior ta WO approval.
The failure
to ensure that the system was aligned to support the work order task
requirements and failure to ensure that the equipment was prepared for
maintenance prior to approval of the work order is identified as
violation 50-281/96-05-01, Inadequate System Isolation. Specifically,
the Shift Supervisor failed to ensure that relief valve 2-DG-RV-202 was
isolated from the overhead gas header.
2.4
Unit 2 Reactor Trip During Startup.
Reactor startup was performed on June 5 following completion of RFO 13.
The inspectors noted that individual responsibilities and startup
activities were thoroughly discussed during the pre-evolution control
room brief.
The unit achieved criticality at 5:56 p.m. on June 5 and
commenced low power physics testing.
On June 6, Shutdown Bank A Group 2 control rods failed to withdraw
during low power physics testing.
I&C technicians quickly determined
that the lift phase card for the affected group had failed.
The
inspectors monitored troubleshooting and repair activities.
Communications between operations and maintenance personnel were precise
and the failed circuit card was promptly replaced.
Low power physics testing and turbine checks were successfully
completed.
The inspectors continued to monitor reactor operations from
the control room as operators prepared to connect the Unit 2 main
generator to the off-site power distribution grid. Surry control
systems require operators to maintain manual steam dump and feedwater
regulation valve control while at low power levels. This is a
challenging activity which requires close coordination between several
operators to maintain SG water levels within the desired band as steam
flow rate changes.
At about 15 percent reactor power the SG steam flow
rates began oscillating and operators had difficulty adjusting feedwater
flowrate sufficiently to compensate for SG level swell.
At 11:45 p.m.
the reactor tripped from approximately 16 percent power due to high B SG
water level.
Safety systems responded as designed and the unit was
stabilized in a hot shutdown condition.
The Unit 2 SRO maintained good
direction and control of recovery activities.
The inspectors concluded
that operators responded to the reactor trip in a safe and well
controlled manner.
The post trip review confirmed that SG steam flow oscillations had
developed and that the B SG had swelled to the high level turbine trip
setpoint. Technicians determined that the B feedwater regulation valve
bypass valve (2-FW-HCV-255B) had failed to fully close when operators
attempted to reduce B SG level prior to the trip. This valve
malfunction and other minor equipment problems were corrected prior to
the June 7 reactor restart.
The inspectors determined that the post
trip review evaluated the trip and prerequisites for restart in
appropriate detail.
Station management informed the inspectors that
feedwater control system modifications were being considered to improve
SG level control at low power levels.
4
2.5
Unit 2 Restart
2.6
Reactor startup, following the post trip review, was performed on
June 7.
The shift supervisor clearly discussed the previous reactor
trip and stressed the fact that there were no time constraints on the
reactor startup.
The inspectors monitored startup activities to
evaluate equipment and operator performance.
Evolution briefings and
communications during the startup were good.
The main turbine D reheater intercept valve (2IR) failed to open during
turbine startup testing. Mechanics disassembled the hydraulic actuator
and identified a deteriorating o-ring which may have blocked control oil
flow.
The inspectors observed the actuator disassembly and noted that
foreign material exclusion controls were good.
Theo-ring was replaced
and intercept valve 2IR was successfully retested.
Maintenance
personnel informed the inspectors that they would review the PM scope
for these hydraulic actuators based on the degraded o-ring.
The
inspectors concluded that intercept valve 2IR corrective maintenance was
performed in a timely and high quality manner.
Several minor equipment problems emerged during the startup.
One of the
two generator output breakers (OCB-G-202) failed to close when placing
the generator on-line.
Steam dumps began to drift open beyond the
desired position without operator demand while in manual control.
B SG
feedwater regulation valve response was sluggish, requiring operators to
maintain the valve in manual control until the unit was at approximately
30 percent power.
Operators responded promptly to each equipment
problem.
The inspectors concluded that operator performance and
supervisory oversight during the startup were excellent.
Unit 2 was
placed on-line at 9:34 p.m. on June 7, ending a 36 day refueling outage.
The unit achieved 100 percent power on June 10.
Unit 1 Power Reduction Due to High Sulfate Concentration in SGs
On June 7, resin from the condensate polishing system passed by the
system strainer causing elevated Unit 1 SG sulfate levels. All three
generators exceeded the vendor specified Action Level II limit (100
ppb).
Operators reduced reactor power to 30 percent as required by the
vendor until sulfate levels were returned below 20 ppb.
Sulfate levels
returned to allowable values at 7:12 a.m. on June 8, and a power
increase to 100 percent was commenced.
The unit was returned to 100
percent at 6:38 p.m. that same day.
The inspectors have noted that the
licensee has recently increased their sensitivity to SG chemistry
quality and has a low threshold for initiating associated DRs.
The
inspectors concluded that immediate actions to reduce power level and to
stop the resin intrusion in addition to ongoing efforts to improve
condensate polisher operations demonstrated appropriate concern for SG
integrity.
The licensee initiated a category 2 RCE to investigate the
resin intrusion .
2.7
2.8
5
Unit 1 Power Reduction Due to Relay Failure
On June 11 at 11:23 a.m., Unit 1 commenced a reactor shutdown to hot
shutdown in accordance with TS 3.7 due to a failed relay in the reactor
protection system circuitry.
Relay 1-RP-RLY-TTXA failed to reenergize
and smoke was detected in the relay cabinet during RPS system testing.
At the time of the relay failure the A main reactor trip breaker was
open and the A reactor trip bypass breaker was closed to allow testing.
TS Table 3-7.1 item 18, reactor trip breakers, allows one reactor trip
breaker to be bypassed for two hours for surveillance testing.
The
operating crew did not want to reclose the A reactor trip breaker based
on the failure of the relay and entered a six-hour action statement to
hot shutdown.
The relay was replaced, tested, the A reactor trip
breaker was reclosed and the bypass breaker reopened at 1:20 p.m. with
the unit at 58 percent power.
A power increase to 100 percent power was
commenced at 1:26 p.m. and the unit was returned to 100 percent power at
3:39 p.m.
The inspectors monitored portions of the power reduction and return to
100 percent power operation and verified that the appropriate
notifications were made to the NRC.
The inspectors also observed
replacement and testing of the failed relay by maintenance personnel.
The inspectors determined that operations' decision to initiate a
reactor shutdown was a conservative decision based on available
information.
The relay replacement and testing activity was well
coordinated between operations, maintenance, and the system engineer.
Inoperable Control Room Air Handling Units
At 5:05 a.m. on May 13, control room AHU 1-VS-AC-2 was secured and
control room AHU 1-VS-AC-l was started to support testing of the main
control room chiller 4C service water pump.
When AHU 1-VS-AC-l was
started the operators noticed that the ventilation noise level in the
control room was abnormally low.
Investigation by the operating crew
determined that the filter and coil differential pressure was below the
allowable value of 0.16 inches H20 indicating reduced flow through the
AHU.
AHU 1-VS-AC-l was declared inoperable which initiated a seven-day
TS action statement in accordance with TS 3.23 and control room AHU 1-
VS-AC-2 was restarted.
When AHU 1-VS-AC-2 was restarted ventilation
noise and flow were determined to be lower than when AHU 1-VS-AC-l was
in service and the filter and coil differential pressure did not meet
the minimum acceptable value of 0.16 inches H20 when checked by the
operators.
At 5:15 a.m., main control room AHU 1-VS-AC-2 was declared
inoperable making both Unit 1 ma~n control room AHUs inoperable.
TS 3.23 does not address the inoperability of both AHUs and the operators
entered a six-hour action statement to hot shutdown in accordance with
The HVAC maintenance crew and system engineer were contacted to
troubleshoot the AHUs.
Initial troubleshooting efforts focussed on
potential blockage of the supply ductwork.
No blockage was identified .
6
Subsequent troubleshooting identified that the counterweight arms on the
AHU backdraft dampers were out of position.
The counterweight arm for
l-VS-AC-2 was returned to the proper position and filter and coil DP
returned to normal.
Ventilation flow was verified using an anemometer
and the AHU was declared operable at 8:21 a.m. exiting TS 3.0.1 and
entering a seven-day action statement in accordance with TS 3.23.
The
counterweight arm for main control room AHU 1-VS-AC-l was repositioned
and the AHU was declared operable at 4:09 p.m.
The inspectors reviewed the TS requirements and monitored licensee
troubleshooting efforts.
The licensee initiated a root cause evaluation
to determine the cause of the failures and will issue a LER describing
this event and corrective actions to prevent recurrence.
The inspectors
determined that the licensee immediate corrective actions were
appropriate and that the operating crew demonstrated a good questioning
attitude by promptly identifying that the Unit 1 main control room AHUs
were degraded.
2.9
Inoperable Charging Pump Service Water Pumps
At approximately 1:51 a.m. on May 6 a charging pump service water low
pressure alarm was received in the Unit 2 control room.
At the time of
the event, Unit 2 was in cold shutdown and the charging pump service
water system was not required to be operable.
At approximately 1:55
a.m. a charging pump service water pump low pressure alarm was received
in the Unit 1 control room.
The operators verified that the standby
service water pumps auto started, however, discharge pressure did not
return to normal.
The operators declared both flowpaths to the charging
pump service water pumps inoperable, immediately responded to the MER
and vented service water pump 1-SW-P-lOA.
After venting air from the
system, pump discharge pressure returned to normal and service water
pump 1-SW-P-lOA was declared operable at 1:56 a.m.
Unit 1 service water
pump 1-SW-P-lOB was vented and returned to service at 2:19 a.m.
returning both Unit 1 charging pump service water pumps to service.
During the approximate one minute time period that both Unit 1 service
water flowpaths were inoperable, Unit 1 was in a six-hour action
statement to hot shutdown in accordance with TS 3.0.1. Charging pump
temperatures remained within allowable values throughout the event.
Charging pump bearing temperatures only increased approximately
4 degrees fahrenheit.
The Unit 2 charging pump service water pumps were
also vented and both pumps were returned to service at 2:30 a.m.
The licensee initiated a Category 1 Root Cause Evaluation to determine
the cause of the air intrusion into the charging pump service water
system.
The licensee determined that the air was the result of divers
previously working in the Unit 2 A high level intake structure 96-inch
The divers had been performing a PM to
clean the piping of marine growth.
The air exhaled by the divers
accumulated in the piping and when valve 2-SW-MOV-201B was opened for
testing, air was transported to the suction of the charging pump service
water pumps.
Previous cleaning evolutions had been accomplished with
the high level intake structure isolated and drained.
The inspectors
i
I
--
7
reviewed the event and discussed the issue with operations and station
management.
The licensee plans to develop a procedure that addresses
the use of divers to clean station piping and develop an Operations
Checklist to control manipulation of service water during periods of
high maintenance activity.
The inspectors determined that the operators
promptly responded to the low pressure indication and reestablished
charging pump service water flow in an expeditious manner.
Licensee
actions to strengthen control of maintenance activities in the CW and SW
systems were appropriate.
2.10 Outage Commitment Review
Prior to Unit 2 startup following refueling, the inspectors reviewed the
status of licensee's actions to meet commitments related to the
refueling outage.
The inspectors verified that the work was completed
to meet the following commitments and items of regulatory interest:
AAC diesel connection to Unit 2.
The licensee completed
installation and testing of the AAC diesel during the refueling
outage.
Testing of the AAC diesel is discussed further in
paragraph 3.5.
Flow test recirculation spray heat exchangers.
The licensee
performed procedure 2-0SP-SW-007, Service Water Flow Test of
Recirculation Spray Heat Exchangers 2-RS-E-IA and 2-RS-E-ID,
revision 0, to establish service water flow through the RSHX.
Replace SG alloy 600 tube plug.
The licensee reolaced the alloy
600 tube plug in the A SG cold leg.
Rod control system surveillance testing.
rod control system surveillance testing.
further in paragraph 3.3.
The licensee completed
This item is discussed
Implement corrective actions for RCS draindown event. The licensee
completed the corrective actions discussed in the response to EA 95-223 prior to commencing the Unit 2 refueling outage.
This item
is discussed further in paragraph 2.11.
Revise GOP I.I to reference GL 95-07.
The licensee revised GOP
1.1 to reference GL 95-07 prior to restart of Unit 2.
Visual inspections of pressurizer instrument nozzles.
The
licensee and inspectors performed visual inspections of the
instrument nozzles and verified that no indication of leakage was
present.
Replace one recirculation spray heat exchanger MOV.
The licensee
replaced valve 2-SW-MOV-205A using DCP 96-006.
Develop procedure for controlling reactor vessel head vent valves .
The licensee developed procedure 2-0P-RC-013, Reactor Head Vent
8
And Standpipe Operations, revision 1, to control the reactor
vessel head vent valves.
This procedure was implemented prior to
commencing the Unit 2 RFO.
Resolve conflicting numbers between minimum time allowed for
defueling.
The licensee revised the UFSAR to resolve the
conflicting time requirements for core offload. The inspectors
verified that core offload did not commence prior to the most
conservative time referenced in the UFSAR prior to revision.
Expansion joint replacement.
The licensee replaced the Unit 2
circulating water expansion joints. This item is discussed
further in paragraph 3.8.
Control rod M-10 repairs.
The licensee replaced the CROM rod
travel housing.
This item is discussed further in paragraph 3.2.
Control rod testing.
The licensee performed rod drop time. testing
during the unit shutdown, and rod drag testing during the defueled
maintenance window.
This item is discussed further in paragraph
3.1.
2.11
Open Item Followup Review (Operations)
(Closed) EA 95-223: 01013, 01023 and 01033, RCS Draindown Event
Violations.
During the Fall 1995 Unit 1 RFO, several problems occurred during the
RCS draindown for removal of the reactor vessel head.
NRC Inspection
Report Nos. 50-280/95-20 and 50-281/95-20 documented this event and
escalated enforcement was taken.
The licensee's short term corrective
actions associated with this item included increased management
ovfrsight, station management meetings with operations personnel and
STAs to clarify and reinforce management expectations, additional
training of operators and STAi and procedure revisions to provide
additional control of shutdown activities. These corrective action
items were reviewed by the inspectors and were found to be acceptable.
Long term corrective actions included implementation of more detailed
operations standards, performance of an operations configuration control
assessment, implementation of an outage controlling procedure to
integrate and better control outage activities, and continued training
programs for operations personnel and STAs.
The inspectors reviewed the licensee long term corrective actions and
verified that they had been adequately accomplished to support the
Unit 2 refueling outage.
One violation was identified .
9
3.0
MAINTENANCE (61726, 62700, 627n1, 90712, 92902)
3.1
During the reporting period, the inspectors reviewed the following
maintenance and surveillance activities to assure compliance with the
appropriate procedures and TS requirements.
Review of Unit 2 Rod Testing to Satisfy NRC Bulletin 96-02
The inspectors reviewed the recorder traces for the as-found rod drop
testing that was committed to as part of the licensee's response to NRC
The test was performed on May 3 after the unit shutdown
for refueling with the unit at NOT and NOP conditions.
Procedure 2-NPT-
RX-014, Hot Rod Drops by Bank, revision 2, was used to control testing.
The inspectors verified that rod drop times were within TS allowable
values.
The traces clearly indicated dashpot entry.
However, because
of equipment sensitivity and signal strength it was difficult to
determine ~ctual rod bottoming.
The inspectors along with the reactor
engineer did however note a slight trace disturbance following the
voltage decay after dashpot entry.
Per procedure 2-NPT-RX-014 this
disturbance is indicative of the rod bouncing on the bottom.
This
bouncing was verified on all rods except rod F-10 for which the
inspectors were unable to see the slight trace disturbance.
However,
two reactor engineers who routinely perform this type of testing
indicated, that although extremely difficult to observe, rod bouncing
did occur.
The inspectors accepted their position .
The second part of as-found rod testing was a rod drag test that was
performed in the spent fuel pool.
This testing was performed per
procedure STD-FP-1996-7751, Surry RCCA and Fuel Assembly Examination
Field Procedure, revision 0.
On May 31, the inspectors reviewed data
collected for the rod drag test. Westinghouse had performed the testing
under contract to Surry and the acceptance criteria was vendor supplied.
The inspectors' review of the data indicated that tw9 of the 48 rods
exhibited an upper guide tube drag force greater than the 40 lbs.
specified in the procedure.
Both assemblies had a burnup of
approximately 40,000 MWD/MTU and neither were planned to be reused for
future cycle core configurations.
The core locations where these two
assemblies had been discharged from were D-6 and H-10.
In addition to
the 48 RCCAs tested, Westinghouse used the dummy RCCA to drag test
several other high burnup assemblies that had been previously discharged
to the spent fuel pool.
Based on the inspectors' review of the data provided and in consultation
with the licensee's NAF personnel there appears to be a correlation
between fuel burnup and guide tube drag forces even in the 15Xl5 fuel
assemblies.
The final review and analysis of the licensee's data will
be conducted by NRR as part of Bulletin 96-02 review and closure
process.
On June 4, technicians performed 2-NPT-RX-014 to confirm Unit 2 RCCA
operability following the refueling outage.
The inspectors verified
that test prerequisites and reactor plant conditions including shutdown
10
margin were properly established. Communication repeatbacks between
technicians at the rod control cabinets and the test coordinator were
clear. All test connections were double verified prior to measuring rod
drop times.
The inspectors independently reviewed the recorded rod drop
traces. All control rod drop times were consistent and satisfied TS
requirements.
Each trace indicated bottom bounce which demonstrated
that the RCCA fully inserted and there was no indication of an unlatched
The inspectors concluded that control rod testing was
performed in a professional manner and clearly demonstrated RCCA
operability prior to reactor startup from the refueling outage.
3.2
Replacement of Unit 2 Rod M-10 CROM Rod Travel Housing
During the Unit 2 RFO the licensee replaced the CROM Rod Travel Housing
for rod.M-10.
This replacement was another step in the licensee
attempts to correct a rod position indication problem for rod M-10.
The
licensee along with their CROM and IRPI vendor had determined that
housing magnetism might have been the cause of previous indication
problems.
The inspectors reviewed the licensee CROM housing replacement
activities.
Work was performed by Westinghouse and was accomplished
while the reactor head was stored on its stand for refueling activities.
Work was controlled by WO 00335120-01.
Rod exercise and drop time
testing along with system pressure testing of the housing were performed
to verify rod operability.
The inspectors verified that the licensee's
corrective actions for control rod M-10 position indication problems
were satisfactorily completed.
3.3
Rod System Testing for DCP Verification
During the RFO the licensee implemented DCP 94-073 to modify and correct
a rod control system timing problem that occurred at another facility.
The licensee committed to modify the system in their response to NRC GL 93-04.
This modification involved re~sitioning diodes on the Slave
Cycler Decoder cards in the Rod Control System logic cabinets.
Rod
motion was controlled by procedure 2-NSP-RX-014, Rod Exercise Test,
revision 2.
This procedure referenced SNSOC approved Westinghouse
procedure O-NSD-EIS-95-047, CROM Timing Modification and Verification
Testing Vendor Procedure, revision 0, for sequencing and timing test of
the stationary, movable, and lift coils.
On June 2, the inspectors
monitored testing of CB A and C rods.
The recorder traces were reviewed
against a sample trace contained in the procedure.
The traces were
similar to the sample provided in the procedure.
The procedure allowed
variances between the actual and sample traces to account for electrical
noise and signal strength. Test results met procedural acceptance
criteria. During the test one !RPI failed and three of the eight step
counters did not exhibit good audible indication.
WOs and a DR were
written to track and correct the problems.
11
3.4
RWST Recirculation Pump Suction Valve Repairs
During the inspection period the inspectors observed corrective
maintenance activities associated with valve 2CS-27.
This valve is the
RWST recirculation pump suction header isolation valve.
The maintenance
activity consisted of establishing a freeze seal and replacing the valve
bonnet assembly due to problems with the spindle position indicator.
The work activity was accomplished in accordance with WO 00333229, RWP
96-2025, and procedure O-MCM-0402-01, Grinnell Diaphram Valve Removal,
Replacement, and Overhaul, revision 3.
The inspectors reviewed the WO,
RWP, system tagout, and monitored maintenance activities in progress.
The inspectors also verified that the freeze seal was properly*
established prior to commencing valve maintenance activity.
During the
installation of the replacement bonnet assembly the spindle separated.
The licensee installed a new diaphragm in the valve and reassembled the
valve using the old valve bonnet.
The work activity was accomplished in
accordance with the work package requirements and the maintenance
activity was well coordinated to minimize the time that the freeze seal
was required to provide isolatiQn for the work activity.
3.5
AAC Diesel Generator Testing
3.6
During the Unit 2 refueling outage the licensee completed the electrical
connection of the AAC diesel to Unit 2.
The AAC diesel generator
provides the power source for onsite electrical loads during SBO
conditions.
The inspectors observed the performance of Final Design
Test Procedure FDTP-92-052-3-9, AAC Diesel Generator Installation E
Transfer Bus Tie, revision 0.
This procedure coordinated and performed
the post modification testing to verify proper operation of the AAC
diesel generator after connection to the E transfer bus.
The procedure
verified proper phasing, governor and excitation controls during
parallel system operation, diesel auto start and proper breaker
operation during a SBO signal, proper bus voltage when a large motor
load was connected, and the ability to recover normal offsite power
following a SBO.
The inspectors reviewed the test procedure and verified that the test
acceptance criteria was met.
The test was performed in accordance with
the test procedure and good command and control was exhibited by the
operators conducting the procedure.
No problems were encountered during
the performance of the functional testing.
Unit 2 TDAFW Pump Operability Testing
Mechanics replaced the TDAFW pump governor stem and repaired the TDAFW
pump B steam supply isolation valve during the RFO.
The inspectors
observed TDAFW pump testing on June 6 to verify operability prior to the
reactor achieving 10 percent power.
Procedures 2-0PT-FW-003, TDAFW Pump
2-FW-P-2, revision 6-Pl, and 2-0PT-FW-007, TDAFW Pump Steam Supply Line
Check Valve Test, revision 3, were successfully completed to satisfy TS
and ISI program requirements.
The inspectors noted that operators were
familiar with the procedure and communicated clearly during the test.
- .
- .. *,.;,",
12
Check Valve Test, revision 3, were successfully completed to satisfy TS
and ISI program requirements.
The inspectors noted that operators were
familiar with the procedure and communicated clearly during the test.
Two equipment discrepancies were identified during the testing.
The
TDAFW pump failed to achieve rated speed on the first attempt.
Operators secured the turbine and determined that the governor speed
adjust control had been left at the low speed setpoint following outage
maintenance.
The speed adjust control was repositioned to the normal
full speed setpoint and the test was run successfully on the second
attempt.
The second discrepancy was that the B steam line supply
isolation valve (2-MS-120) stuck in the open position. Operators
subsequently freed the valve to complete the check valve 1ST.
The
inspectors discussed both discrepancies with the maintenance division
manager and verified that appropriate corrective action was initiated to
preclude recurrence.
3.7
Unit 2 MG-6 Relay Failures
During TS bus logic testing per procedure 2-0PT-ZZ-002, ESF Actuation
With Undervoltage And Degraded Voltage - 2J Bus, revision 6, several
MG-6 relays failed to perform properly.
DRs S-96-0899 and S-96-0922
documented these failures. Three of the failed relays were reported to
be original equipment and failed because of unsatisfactory resistance
across the contacts. These three relays were replaced and subsequently
tested satisfactorily.
Two other relays that failed had been installed in 1993 and 1995.
Both
of the relays electrically energized to actuate but failed to latch
(i.e. mechanically hold in the correct position) during the test. These
relays were 2-SI-REL-SIA-B, the SI master relay, and 2-SI-REL-F2-B, a B
train feedwater isolation relay.
The relays were replaced and the logic
was successfully tested. These relay failures are discussed further in
paragraph 4.5.
The failure of 5 of 16 MG-6 relays during logic testing
was considered high.
3.8
Unit 2 CW REJ Replacements
3.9
Eight CW REJs were replaced due to reaching the end of their vendor
specified service life during the Unit 2 RFO.
This maintenance was
added to the outage work scope just prior to beginning the RFO.
The
inspectors verified that all eight CW REJ replacements were completed
and reviewed selected completed work packages.
The work packages were
comprehensive and included good consideration for turbine building
flooding precautions.
Maintenance Program Review
The inspectors conducted interviews with the Maintenance Superintendent,
his lead supervisor in maintenance engineering, and discipline
supervisors in mechanical, electrical, and instrumentation and controls .
Each of these interviews focussed on the background and training of each
13
individual, and general responsibilities in their current positions.
In
addition, the interview with the Mainte~ance Superintendent included a
review of the organization and staffing of the Maintenance Department,
and a review of the quality indicators used to track maintenance
performance.
During this interview, it was learned that the Maintenance
Department is currently staffed with approximately 200 people organized
into the three trade disciplines, maintenance engineering, and a support
group which performs the equipment predictive analysis .function.
Interviews with the discipline supervisors also included tours of each
work area, tool rooms and material storage areas.
The inspectors
observed that all of the work areas were clean and orderly. All
calibrated equipment observed by the inspectors in the work areas was
noted to be within the required calibration due date, and materials
stored in these areas was properly identified and protected.
The
following Quality Indicators involving maintenance performance were
reviewed by the inspectors during the inspection:
Quarterly Deviation Trend Reports for 3Q95, 4Q95, and 1Q96
April 1996 Work Process Production Indicators
Virginia Power Nuclear Business Plan Goal Performance (December
1995):
Total Work Order Backlog
Non-outage Corrective Maintenance Backlog
Work Order Rework
Work Orders Completed Not Closed
Actual/Planned Outage Schedule
Maintenance Rule SSCs in (a)(l)
Safety System Failures (Maintenance Related Issues)
EOG Reliability (Maintenance Related Issues)
EDG Unavailability (Maintenance Related Issues)
HHSI Unavailability (Maintenance Related Issues)
LHSI Unavailability (Maintenance Related Issues)
Containment/Quench Spray System Unavailability (Maintenance
Related Issues)
Recirculating Spray System Unavailability (Maintenance Related
Issues)
AFW System Unavailability (Maintenance Related Issues)
RHR System Unavailability (Maintenance Related Issues)
SALP Rating (Maintenance Related Issues)
Regulatory Performance Indicator (Maintenance Related Issues)
Licensee Event Reports (Maintenance Related Issues)
NRC Violations (Maintenance Related Issues)
Forced Outage Rate by Unit (Maintenance Related Issues)
Reactor Trips (Maintenance Related Issues)
The inspectors conducted a general plant tour and reviewed several key
administrative procedures which control the maintenance program.
The
plant tour included the control room, Turbine Building, and the
Auxiliary Building.
Areas observed by the inspector were noted to be in
excellent condition.
The procedures reviewed during the inspection were:
14
VPAP-0801, Maintenance Program, revision 5
VPAP-0802, Maintenance History Program, revision 2
VPAP-0803, Preventative Maintenance Program, revision 5
VPAP-0804, Safety and Relief Valve Program, revision 4
VPAP-0805, Motor Operated Valve Program, revision 5
VPAP-0812, Station Lubrication Program, revision 2
VPAP-2002, Work Requests and Work Order Tasks, revision 5
All areas reviewed during this inspection provided a favorable
impression of the overall maintenance program at Surry.
Personnel
appeared to be well qualified for their positions, work areas were
orderly and well maintained, the plant material condition was excellent,
and procedures were clear and concise.
No violations or deviations were identified.
4.0 * ENGINEERING REVIEW (37551, 37550)
4.1
Review of Safety and Oversight Committee Activities
The inspectors reviewed activities of two of the safety committees,
i.e., the on site SNSOC and the off site MSRC.
The inspectors attended the SNSOC meeting that involved a review of
SE 96-0084, revision 1, and JCO No. S2-96-002.
These documents
concerned the Unit 2 main control room annunciators being taken out of
service to replace the power supplies.
It was observed that the meeting
was well conducted and involved very extensive and detailed discussions
by the members involved.
The replacement of the power supplies was
successfully completed the week of June 3-7.
A review of all the meeting minutes for the MSRC was conducted for the
period January-May, 1996.
The inspectors observed that the committee
was successfully performing the functions delineated in the committee's
procedure.
4.2
Review of Engineering Documents
The inspectors reviewed four DRs, five SEs, two JCOs, and three
modification packages.
These documents covered activities dealing with
a leak in the RHR System, erosion/corrosion of a FW pipe, improper
installation of a valve, a relay problem, and a modification of
radiation monitoring equipment.
The inspectors examined the areas involving the repair and replacement
of the leaking RHR piping and the repair/replacement of a portion of the
15
FW p1p1ng due to erosion/corrosion. A through-wall leak in a Unit 2
six-inch diameter RHR pipe adjacent to a saddle weld for a support
resulted in a shutdown of the unit for repairs.
The metallurgical failure analysis of the piping and the repair and
replacement activities displayed a through understanding of this
engineering discipline. Another example of this continuing strength
(had been noticed in previous inspections in this area) was the repair
and subsequent replacement of a section of the FW piping.
The SEs, dispositions of DRs, and JCOs reviewed by the inspectors were
good.
A continuing strength exists in the area of
materials/metallurgical solutions to corrosion, erosion problems
identified at the site.
4.3
Engineering Interface With Other Groups
4.4
The inspectors attended several meetings and had discussions with
engineering personnel to determine the extent of interfacing with other
groups.
The inspectors attended a safety committee meeting, a Unit 2 outage
meeting, and a daily meeting of the engineering group.
The engineering
group participated well with the other groups and readily accepted
requests for additional assistance. A member from operations attended
and participated in the daily engineering meeting.
Discussions with the
engineering manager revealed that he assigned one of the two system
engineering managers to attend the daily maintenance meeting to
determine if additional engineering assistance was needed on any
maintenance project.
The inspectors concluded that there was an
excellent interface between engineering and the groups they supported.
Problems with Safety-Related Batteries
In 1989, the licensee and the NRC became aware that the safety-related
vital batteries were experiencing problems that appeared to be the
result of manufacturing defects.
These batteries were manufactured by
Exide, and the cell design was designated as 2GN-23.
They were flooded
cell type with lead calcium plates.
The 2 prefix indicated that two
cells were in one jar.
The inspection scope was to review the specific
circumstances and resolving corrective actions.
Inspection activities
included:
Discussions with the system engineer for the batteries.
Review of laboratory analysis reports on failed or weak cells.
Examination of the installed batteries .
16
Review of an engineering study ET NO. CEE-94-063, Evaluation of
Cell Jumpering, dated October 27, 1994.
Review of capacity tests results for the batteries.
The Train B batteries for both units were installed in 1986.
The date
code stamp affixed to the cells were 8603R and 8607R.
These batteries
have not experienced a problem except for cells 51 and 52 (same jar) in
the 2B battery which had voltage at the low end of the acceptable range.
The jar was replaced in January 1989 and again in May 1991.
Currently,
the voltage of those cells remains the lowest in the lineup, but is not
trending down.
The inspectors found the Train B batteries to be in good
condition during a detailed walkdown type inspection.
Records of tests
showed that the capacity of these batteries was at least 100 percent of
rated.
A number of cells in the Train A batteries, which were installed in
1988, had heavy sedimentation due to disintegration of the plates.
The
same cells also had decaying voltage and specific gravity. Six cells
(three jars) in the IA battery were replaced in December 1994.
Eighteen
cells (nine jars) were replaced in the 2A battery in November 1994.
The
replacement of cells did not resolve the problems, since voltage and
specific gravity of the new cells trended down.
At least one cell
failed and was jumpered out.
An analysis was performed to show that the
battery could meet the design basis with 59 cells rather than the
original 60.
The inspectors reviewed this analysis and found it to be
acceptable.
An entire new IA battery of the same design (2GN-23) was
installed in September 1995, and a new 2A battery was installed in May
1996.
In the past, equalizing charges were done at 138 V or 2.3 volts per
ce~l. which was lower than recommended by the manufacturer, due to
equipment rating limitations. This was seen as contributing to the
problems, although the basic problem was manufacturing defects.
Currently, the licensee uses single cell charging at 2.6 V when
necessary during normal unit operation.
After capacity testing, which
is performed during the unit outage period, freshening charges are
applied at 2.5 V to replace the expended energy.
The freshening charge
is supplied with a portable charger to a battery which has been isolated
from the rest of the system.
The inspectors concluded that, at the time of the inspection, there were
no concerns with the batteries.
The new Train A batteries and the 1986
Train B batteries were performing well.
In addition, the
inspectorsconcluded that at no time during the past period of problems
were the batteries not able to perform their intended function while the
respective unit was at power .
17
4.5
Problems with Safety-Related Reiays - Type MG-6
During TS surveillance testing of the ESF logic conducted during the
Spring 1996 Unit 2 refueling outage, several relay failures occurred.
The relays that failed were manufactured by Westinghouse Electric
Corporation and Asea Brown Boveri and were type MG-6 relays.
The
particular relays that failed were electrically reset latching relays.
A total of 16 of these relays were installed in safety-related
applications.
Five of the 16 failed.
For three relays, the failure
mode was high contact resistance in two or more of the contacts.
These
contacts were in the trip circuit of the feedwater pumps.
Two relays
failed to latch.
In addition, relays drawn from the warehouse as
replacements also failed to latch during the replacement and checkout
process.
The original relays were manufactured by Westinghouse Electric
Corporation.
At some point, the relay manufacturing plant was bought by
Asea Brown Boveri.
After the takeover, ABB did not offer the MG-6 relay
as safety-related.
The licensee purchased MG-6 relays from Westinghouse
who procured them from ABB and performed commercial grade dedication.
Of the original 16 installed relays, one had been replaced in August
1993 and one had been replaced in February 1995.
This fact was
determined by the licensee by checking the date codes on all the
installed MG-6 relays.
These were the two relays that failed to latch
in the Spring 1996 surveillance test.
The ABB representative, who came to the site to help determine the cause
of the failures, stated that the relays that failed to latch had date
codes putting them in the group of relays known to have some defect
causing the latching problem.
As related to the inspectors by the
licensee, the ABB engineer stated that any relays having date codes from
1991 to 1994 (first quarter) were suspect of having the failure to latch
problem.
The licensee stated they had not received any service bulletin
or other communication from ABB or Westinghouse about this problem.
The
licensee stated they were reviewing the failures for potential
reportability pursuant to 10 CFR 21.
The licensee stated they were in the process of determining the failure
mechanism for the relays at their corporate laboratory, at least the
cause of the high contact resistance.
4.6
125 VDC System Ground Detection Equipment
During the walkdown inspection of the batteries discussed in Section
4.4, the inspectors also looked at the battery chargers to confirm that
the voltage was normal and that the parallel chargers were sharing
loadequally.
At that time, the inspectors noted there was no system
ground fault indicators on the chargers, so the inspectors inquired
about the ground detection capability.
18
The ground detection equipment for the 125 voe Vital Safety-Related
System consisted of two 2800 ohm indicating lamps wired in series
between the positive and negative buses.
The center point (between the
lamps) was solidly grounded.
In the case where no ground faults existed on the system, the voltage
. across each lamp was one-half of full system voltage or about 62.5 voe.
The lamps can detect grounds as follows.
If a ground fault is present
on the system, the resistance of the ground fault itself would be in
parallel with one of the 2800 ohm lamps.
In this case, the equivalent
resistance of the lamp/ground fault combination is different than the
resistance of the lamp on the other side of the center point.
Therefore, the voltage across the two lamps is unequal.
The operator
would see a difference in brightness between the two lamps which is
indicative of a ground.
In the extreme case of a zero resistance ground
fault, one lamp will be dark and the other will be full brightness.
The lamps were located in the control room on the vertical control
board.
They are checked at shift turnover and at other times at the
discretion of the operators.
As stated in the licensee's Technical Report No. EE-060, "DC Ground
Detection," revision 0, dated June 29, 1990, the highest resistance
ground fault detectable with the lamp system described above was 6,760
ohms.
Determination of this value took into consideration the
subjectivity inherent in visual detection of differences in lamp
intensity. This report also calculated values called the minimum
allowable resistance to ground.
This was the threshold resistance value
that could cause a relay circuit to mis-operate if the ground were
located on the positive bus side of the relay coil.
The minimum
allowable resistances associated with a HFA relay and a HGA relay were
53,680 ohms and 102,550 ohms respectively.
Both these values were well
above the highest detectable resistance.
Therefore, the ground
detection equipment at Surry had a design weakness in that a ground of a
certain ohmic value could exist on the system which could cause a
safety-related circuit to mis-operate, and that ground could not be
detected by the ground detection equipment.
Another weakness of the ground detection equipment was that it did not
include continuous monitoring and annunciation.
A ground existing at an
end device that was operated for brief periods of time during normal
plant operation or surveillance testing would have had a low probability
of detection even though it was in the detectable range (6760 ohms or
less).
The reason for this is that the operator would have had to be
looking at the ground indicating lamps during the brief operating
period.
The installed DC ground detection equipment was consistent with that
described in the current version of the UFSAR text and diagrams.
Therefore, the inspectors concluded that the design was considered
acceptable at the time of initial plant licensing.
Since that time,
however, operational experience at other plants throughout the industry
19
has highlighted the weaknesses described above.
The licensee stated
they had no plans to upgrade the ground detection equipment.
The
inspectors concluded that the current design weaknesses require further
review by the NRC.
The matter will be tracked via Inspection Followup
Item 96-05-02, Adequacy of DC Ground Detection Equipment Under Review by
the NRC.
4.7
480 VAC Ground Detection Equipment
During plant walkdowns conducted in relation to review of engineering
activities, the inspectors noted that there were ground indicating lamps
on each of the 4160 - 480 V load centers.
The inspectors noted a
difference in brightness among the three ground fault indicating lamps
at load center 2-EP-LCC-2H.
The center {phase B) lamp was dimmer than
the other two lamps (phases A & C).
The inspectors followed up this
observation with a design review of the ground detection equipment for
the 480 VAC Distribution System.
The 4160 - 480 V transformers were connected in delta configuration on
both the high- and low-voltage sides. Therefore, it was an ungrounded
system.
At each of the load centers, a 480 V system neutral was derived
through the connection of potential transformers and a resistor. Three
480 - 120 V potential transformers were connected in wye configuration
on the high-voltage side and the neutral point was grounded through an
800 ohm resistor. Three ground indicating lamps were connected on the
low-voltage side of the potential transformers in a grounded wye
configuration. Should a ground fault occur on one phase of the system,
the voltage seen by the voltage transformer connected to that phase
would collapse and the lamp on the secondary side would become dark.
It
was not clear to the inspectors what conditions could cause the lamp of
one phase to dim to some intermediate brightness as observed during the
walkdown.
However, the licensee stated that, based on their experience
with the system,' the difference in brightness observed by the inspectors
was too small a difference to indicate a ground.
Nevertheless, the
licensee stated they would evaluate this condition, and if necessary,
make voltage measurements to ascertain the true voltages.
Regardless of whether or not a ground existed on the system at the time
of the inspection, the fact that there was no system ground annunciator
installed represented a design weakness.
A ground existing at an end
device (such as a valve motor) that was operated from the control room
for brief periods of time during normal plant operation or surveillance
testing would have a low probability of detection since there would be
no indication of a ground in the control room.
Circuit breakers would
not trip because the ground fault current for the single-line-to ground
fault is negligible in an ungrounded system.
However, an undetected
ground is a concern, because it could result in a double-line-to-ground
fault should a second ground appear on the system.
The ground detection
equipment for the 480 VAC Distribution System was not described in the
current version of the UFSAR.
The inspectors concluded that the lack of
a system ground detector and the inability to detect a possible ground
20
require further review by the NRC.
This matter will be tracked via
Inspection Followup Item 96-05-03, Adequacy of 480 V Ground Detection
Equipment Under Review by the NRC.
No violations or deviations were identified.
5.0
PLANT SUPPORT (71750, 83750)
The inspectors conducted facility tours, work activity observations,
personnel interviews, and documentation reviews to determine whether
license programs met regulatory requirements in the areas of
radiological protection, security and fire protection.
5.1
Occupation Radiation Exposure Control Program Changes
Changes in the Radiation Protection program, since the last inspection
in October 1995, were reviewed to determine whether program changes met
applicable program requirements and to assess their impact on the
effective implementation of the RP program.
The review included interviews with the RP Manager and staff,
observations and selected review of licensee procedures.
The licensee recently established an oversight program and organization
for the purpose of improving overall site performance.
The Supervisor
of Radiological Engineering from the RP department was selected for the
Plant Support position in the oversight organization.
As a result,
several personnel moves within the RP organization were made.
The
inspectors determined that all personnel were sufficiently qualified to
fill newly assigned positions within the RP organization.
The licensee eliminated the requirement for an annual Whole Body Count.
The capabilities of the Radiation Control Area exit whole body friskers
to detect low levels of radioactive contamination and the relatively low
incidence of personnel receiving measurable intakes of radioactivity
were considerations in the licensee's decision.
The licensee was using
the whole body friskers as passive whole body monitors (paragraph 5.2).
The licensee increased the outage work week for plant HP staff from
approximately 50 hour5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />s/week to 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s/week.
The change permitted the
licensee to assign plant staff responsibilities for specific work
locations for improved RP control and accountability.
The licensee removed the requirement to issue a TLD for all personnel
entering the RCA.
The licensee removed TLDs for certain persons
typically having less than 100 mrem annual dose.
However, the licensee
21
still used the electronic dosimeter to monitor the radiation exposures
for those personnel when they entered the RCA and TLDs were required for
work in high radiation areas.
The inspectors did not identify any concerns with any of the reviewed
program changes.
No violations or deviations were identified.
5.2
External and Internal Exposure Controls
This program area was reviewed to evaluate the adequacy of the
licensee's RP controls for internal and external radiation hazards and
to verify individual radiation doses did not exceed regulatory limits.
The inspectors reviewed individual personnel exposure records, Radiation
Work Permits and survey documents.
Direct observations of radiological
controls were made during tours of the facilities and during the
performance of on-going work activities within the RCA.
The maximum individual doses (Rems) for calendar year 1995 is.shown
below.
The 1996 values are from TLD measurements through March 31,
1996.
Maximum Individual Radiation Doses
Year
Skin
Extremity
Lens-Eye
1995
2.817
3.674
3.674
2.850
1996
0.451
0.451
0.451
0.451
Limits
Part 20
5.000
50.000
50.000
15.000
Adm.
4.000
40.000
40.000
12.000
The highest individual internal exposures for 1995 was approximately
0.1 rem CEDE and the licensee had not made any CEDE dose assignments for
1996.
All external and internal exposures were well within the
regulatory limits.
No concerns with the individual radiation exposures
were identified.
The inspectors reviewed a few personnel radiation dose records to verify
that the licensee was maintaining records of radiation exposures.
One
of the records indicated a radiation worker had ended his work
assignment at Surry without an exit WBC.
The worker was an escorted
contractor employee on site during the period from February through
April 1993.
The inspectors determined that the worker was dismissed
from the site without processing through the dosimetry department prior
to his exit.
The staff reported that while it was desirable to obtain
an exit WBC for all personnel leaving the site it was not a requirement.
The licensee's procedures recommended but did not require an exit WBC .
22
Whole body friskers were being used as passive internal contamination
monitors.
The inspectors reviewed a technical evaluation report which
documented the whole body friskers' ability to detect approximately one
percent ALI.
Since all personnel routinely exit the RCA through the
whole body friskers the licensee concluded the whole body friskers
provided internal monitoring capabilities for each RCA exit.
Personnel
clearing whole body friskers were unlikely to have any measurable
intakes.
Personnel having one percent ALI could cause an alarm on the
whole body friskers prompting an investigation to determine whether the
contamination was internal or external.
Persons suspected of internal
contaminations could receive a quantitative assessment of suspected
intakes with WBC equipment and sampling as needed.
This was part of the
justification for eliminating routine annual WBCs.
The licensee had
utilized the whole body friskers at the Surry RCA exits for
approximately six years.
During tours of the facility, the inspectors verified radiological
postings were appropriate for the radiological hazard, radiation
monitoring equipment was operational and used appropriately, high
radiation areas were properly controlled and independent radiation
surveys agreed with the licensee's surveys.
The inspectors observed
good use of process and engineering controls to limit exposures to
airborne radioactivity.
No discrepancies were identified during those
tours.
The inspectors concluded the licensee was implementing adequate RP
controls and monitoring individual occupational radiation exposures in
accordance with the requirements and that all individual doses reported
were within 10 CFR Part 20 limits.
No violations or deviations were
i dent ifi ed.
5.3
Control of Radioactive Materials and Contamination, Surveys and
Monitoring
This area was reviewed to evaluate the licensee's control of radioactive
and contaminated material.
The review focused on observations made during plant tours and the
review of applicable procedures for the control of radioactive
contamination or radioactive material.
Housekeeping in the Auxiliary Building was generally good.
No
uncontrolled containers of radioactive material or contamination were
identified during tours of the licensee's facilities .
23
The following m1n1mum and maximum contaminated floor space during non-
outage periods was reported:
Plant Contaminated Areas (ft
2
)
Year
Total Area
Areas Contaminated
Minimum
Maximum
Goal
1994
- 137,127
0
11,000
250
1995
137,127
0
6,400
250
1996
137,127
0
2,544
750
The quantity of contaminated plant area was low and the maximum area
contaminated at any one point in time continued to decline.* The
licensee had recently raised the non-outage contaminated area goal from
250 to 750 ft 2 in 1996 in the interest of ALARA.
The inspectors reviewed recent PCE information for adyerse trends.
The
licensee documented PCEs at a low threshold of 100 cpm above background,
when measured with a thin window GM detector.
The numbers of PCEs
remained fairly constant in last_two years as shown below .
Personnel Contamination Events
Year
Actual
Goal
Skin
Outage Days
1994
199
NA
125
114
1995
198
NA
97
81
1996
47
NA
-
11*
- Through May 14, 1996
The licensee had seen an increase in numbers of hot particle
contaminations during the Unit 2 RFO.
A few of the particles resulted
in small individual skin exposures that were significantly less than
regulatory limits.
The inspectors reviewed the licensee's dose
assessments associated with the particles and did not identify any
concerns with the licensee's assessments.
The highest particle skin
exposure was approximately 2.5 rem.
The licensee increased monitoring
and cleanup frequencies in areas affected with hot particles.
Overall, the licensee appeared to have a good contamination control
program.
No specific concerns with the program were identified during
the inspection and no violations or deviations were identified .
5.4
-~~ ---* -
24
Maintaining Occupational Exposures ALARA
This program area was reviewed to determine the status and effectiveness
of ALARA program initiatives in reducing site collective dose.
The inspectors reviewed the licensee's annual and outage collective dose
goals and the status of ALARA initiatives with ALARA staff.
A summary of recent collective dose and goals for the site is shown
below.
Collective Personnel Exposures {Person-Rem)
Annual Dose
Outage Dose
Year
Actual Goal
Title
Actual
Goal
Days
1994
378
642
Ul RF0
1
233
312
64
U2 SG
29
20
22
Cleaning
Ul SG
29
22
28
Cleaninq
1995
406
460
U2 RFO,
158
164
47
Ul RFO
197
191
44
1996
66 2
209
U2 RFO
-
164
-
1-10 Year ISI Outage
2-1996 dose information through 05/13/96.
The primary reason for exceeding the Unit 1 RFO exposure goal in 1995
was expanded SG work and equipment problems.
The collective dose
exceeded the estimated 20 person-rem by approximately 13 person-rem.
The licensee took steps to prevent a similar performance on Unit 2 by
taking measures to improve SG planning and training.
The scope of SG
work on Unit 2 was significantly less and the actual person-rem was
approximately equal to the 10 person-rem project dose.
The 1996 annual collective dose goal was challenging considering
previous collective exposure history.
The licensee's 1996 collective
dose during non-outages was greater than anticipated by approximately 6
person-rem primarily from Unit 2 RCP work activities at power, failed
fuel on Unit 1 and continued permanent shielding on the Charging Pump
System.
The 1996 outage collective dose was approximately equal to the
estimated dose.
Overall, the licensee was approximately 4 person-rem
5.5
25
over the projected annual dose during the inspection.
The inspectors
concluded the licensee was utilizing ALARA techniques, developing
challenging ALARA goals and making progress in reducing collective doses
for the staff.
No concerns with the licensee's ALARA program were identified during the
inspection and no violations or deviations were identified.
UFSAR Review in the Radiation Protection Area
The licensee's RP program for Surry was not described in the licensee's
Therefore, no comparison with the actual RP program could be
made.
However, the inspectors reviewed the status of the Area Radiation
Monitors (ARMs) with the UFSAR descriptions in section 11.3.4, Area
Radiation Monitoring System.
The inspectors verified that the
licensee's system was operating as described.
The inspectors reviewed
the ARM System operability, maintenance activities and design changes.
The licensee was in the process of completing significant modifications
to the plant radiation monitoring systems.
The amount of effort in
maintaining certain process monitors and problems with obtaining parts
for the aging equipment were the primary reasons for implementing the
modification.
While the ARMs had performed well the system was modified
to take advantage of better signal capabilities with detectors having
local pre-amps.
The modifications did not change the general
description of the monitors in the UFSAR and the licensee did not plan
to amend it.
No concerns with the ARM System or UFSAR descriptions were identified.
5.6
Open Item Followup
6.0
(Closed) LER 50-281/96-002, Inoperable EOG Fire Suppression System Due
to Personnel Error.
This LER discussed the inoperability of the EOG number 2 carbon dioxide
fire suppression system due to the rear exit door being left open.
This
item was discussed in NRC Inspection Report Nos. 50-280/96-03 and
50-281/96-03 and resulted in a violation being issued for failure to
establish a fire watch as required by TS.
The inspectors reviewed the
LER and the associated corrective actions to prevent recurrence.
The
inspectors determined that the corrective actions should be adequate to
prevent recurrence.
No violations or deviations were identified.
Review of UFSAR Commitments
A recent discovery of a licensee operating their facility in a manner
contrary to the UFSAR description highlighted the need for a special
focused review that compares plant practices, procedures and/or
parameters to the UFSAR descriptions.
While performing the inspections
26
discussed in this report, the inspectors reviewed the applicable
portions of the UFSAR that related to the areas inspected.
No
discrepancies were identified during this review.
No violations or deviations were identified.
7.0
OTHER NRC PERSONNEL ON SITE
On May 13 and 14, the new NRR Project Manager, Gordon Edison, was onsite
to tour the facility and meet with licensee personnel.
8.0
EXIT
The inspection scope and findings were summarized on June 19, 1996, by
M. Branch with those persons indicated in paragraph 1.
Interim exits
were conducted on May 17 and 24, 1996.
The inspectors described the
areas inspected and discussed in detail the inspection results. A
listing of inspection findings is provided.
Proprietary information is
not contained in this report.
Dissenting comments were not received
from the licensee.
I:i.JIB.
Item Number
Status
50-280, 281/96-05-01
Open
IFI
50-280, 281/96-05-02
Open
IFI
50-280, 281/96-05-03
Open
95-223: 01013, 01023
Closed
and 01032
LER
50-281/96-002
Closed
9.0
AAC
ASEA BROWN BOVERI
ALTERNATING CURRENT
ALTERNATE ALTERNATING CURRENT
AIR HANDLING UNIT
Description and Reference
Inadequate System Isolation
(paragraph 2.3).
Adequacy of DC Ground
Detection Equipment Under
Review by the NRC (paragraph
4. 6).
Adequacy of 480 V Ground
Detection Equipment Under
Review by the NRC (paragraph
4. 7) .
RCS Draindown Event Violations
(paragraph 2.11).
Inoperable EOG Fire
Suppression System Due to
Personnel Error (paragraph
5. 6).
BRT
CB
CR
CFR
cpm
CROM
cw
DP
DR
EOG
GL
GM
IFI
IRPI
JCO
LER
LHSI
MER
mrem
MSRC
MWD
NAF
NOT
NRC
POTT
PPB
psi
PZR
RCCA
27
AS LOW AS REASONABLY ACHIEVABLE
ANNUAL LIMIT INTAKE
AREA RADIATION MONITOR
BORON RECOVERY TANK
CONTROL BANK
COMMITTED EFFECTIVE DOSE EQUIVALENT
CONTROL ROOM
CODE OF FEDERAL REGULATIONS
COUNTS PER MINUTE
CONTROL ROD DRIVE MECHANISM
CIRCULATING WATER
DIRECT CURRENT
DESIGN CHANGE PACKAGE
DELTA PRESSURE
DEVIATION REPORT
ENFORCEMENT ACTION
ENGINEERED SAFETY FEATURE
GENERIC LETTER
GEIGER MULLER
GENERAL OPERATING PROCEDURE
HIGH HEAD SAFETY INJECTION
HEATING VENTILATION AND AIR CONDITIONING
INSTRUMENTATION AND CALIBRATION
INSPECTION FOLLOWUP ITEM
INDIVIDUAL ROD POSITION INDICATOR
INSERVICE TESTING
JUSTIFICATION FOR CONTINUED OPERATION
LICENSEE EVENT REPORT
LOW HEAD SAFETY INJECTION
MECHANICAL EQUIPMENT ROOM
MOTOR OPERATED VALVE
MILLIREM
MANAGEMENT SAFETY REVIEW COMMITTEE
METRIC TON-URANIUM
MEGAWATT DAYS
NUCLEAR ANALYSIS AND FUEL
NORMAL OPERATING PRESSURE
NORMAL OPERATING PRESSURE
NUCLEAR REGULATORY COMMISSION
NUCLEAR REACTOR REGULATION
PERSONNEL CONTAMINATION EVENT
PUBLIC DOCUMENT ROOM
PRIMARY DRAIN TRANSFER TANK
PREVENTIVE MAINTENANCE
PARTS PER BILLION
POUNDS PER SQUARE INCH
PRESSURIZER
RADIATION CONTROLLED AREA
ROD CLUSTER CONTROL ASSEMBLY
- ,
,_
REJ
RFD
SNSOC
TS
V
VAC
VDC
VPAP
- !.
- ~.-:-.
ROOT CAUSE EVALUATION
REACTOR COOLANT PUMP
RUBBER EXPANSION JOINT
ROENTGEN EQUIVALENT MAN
REFUELING OUTAGE
RADIATION PROTECTION
RECIRCULATION SPRAY HEAT EXCHANGER
RADIATION WORK PERMIT
REACTOR VESSEL LEVEL INDICATION SYSTEM
REFUELING WATER STORAGE TANK
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
STATION BLACKOUT
SAFETY EVALUATION
SAFETY INJECTION
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SENIOR REACTOR OPERATOR
STRUCTURES, SYSTEMS AND COMPONENTS
TURBINE DRIVEN AUXILIARY FEEDWATER PUMP
TOTAL EFFECTIVE DOSE EQUIVALENT
THERMOLUMINESCENT DOSIMETER
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
VOLTS
VOLTS ALTERNATING CURRENT
VOLTS DIRECT CURRENT
VIOLATION
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WHOLE BODY COUNT
WORK ORDER