ML18153A798
| ML18153A798 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 04/13/1995 |
| From: | Belisle G, Branch M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153A796 | List: |
| References | |
| 50-280-95-06, 50-280-95-6, 50-281-95-06, 50-281-95-6, NUDOCS 9504240045 | |
| Download: ML18153A798 (18) | |
See also: IR 05000280/1995006
Text
Report Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/95-06 and 50-281/95-06
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:
March 5 through April 1, 1995
Lead Inspector: £_ ltJJc~ ~
M: W. Branch, Senior Resident Inspector
'f-1J-pS-
Date Signed
Inspectors:
D. M. Kern, Resident Inspector
S. G. Tingen, Resident Inspector
Approved by:
G."~~Chief
Reactor Projects Section 2A
Division of Reactor Projects
SUMMARY
Scope:
r /;;;, ~--
~
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, surveillance
inspections, plant support, action on previous inspection items, and on-site
engineering.
Inspections of backshift and weekend activities were conducted
on March 10, 19, 20, 21, 28 and 30, 1995.
Results:
Operations
A violation was identified for exceeding the 100 degrees F per hour technical
specification pressurizer heatup rate on February 4, 1995, during a Unit 2
shutdown evolution (paragraph 7.2).
9504240045 950414
ADOCK 05000280
G
2
Maintenance
Work plan development on the Unit 2 main generator Voltage Regulator {VR)
repair, and return of the VR to automatic control were performed in a
professional manner {paragraph 4.1).
During Unit 2 Motor Operated Valve (MOV) testing, operators followed
procedures, craft were knowledgeable of the MOV diagnostic test equipment, and
the system engineer efficiently coordinated the efforts of operations and
craft personnel while performing the test (paragraph 5.1).
An apparent violation, pertaining to Unit 2 power operation from June 24, 1994
to February 3, 1995, with three channels of low pressurizer pressure reactor
trip protection and three channels of low-low pressurizer pressure Engineered
Safeguards Action instruments inoperable was identified (paragraph 5.2).
Engineering
Nuclear engineers and operations personnel communicated effectively to
maintain plant parameters within prescribed conditions for physics testing
(paragraph 3.2).
Plant Support
During the Unit 2 refueling outage, station personnel provided appropriate
focus to minimize personnel exposure and solid waste generation
(paragraph 6) .
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
- W. Benthall, Supervisor, Licensing
- H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- M. Bowling, Manager Nuclear Licensing
D. Christian, Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
D. Erickson, Superintendent of Radiation Protection
- R. Garner, Outage & Planning
B. Hayes, Supervisor, Quality Assurance
D. Hayes, Supervisor of Administrative Services
- D. Llewelyn, Superintendent, Nuclear Training
C. Luffman, Superintendent, Security
- J. McCarthy, Assistant Station Manager
- A. Price, Assistant Station Manager
- S. Sarver, Superintendent of Operations
K. Sloane, Superintendent of Outage and Planning
- E. Smith, Site Quality Assurance Manager
- D. Sommers, Supervisor, Corporate Licensing
T. Sowers, Superintendent of Engineering
- S. Stanley, Supervisor, Station Procedures
- J. Swientoniewski, Supervisor, Station Nuclear Safety
- T. Williams, Manager QA
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
NRC Personnel
- M. Branch, Senior Resident Inspector
D. Kern, Resident Inspector
S. Tingen, Resident Inspector
- A. Belisle, Section Chief
- Attended Exit Interview
Acronyms used throughout this report are listed in the last paragraph.
2.
Plant Status
Unit 1 operated at full power for the entire inspection period .
Unit 2 started the inspection period with the reactor in cold shutdown.
A RFO was in progress. Reactor startup began on March 19 and the
2
turbine was ~laced on-line on March 21.
The Unit 2 RFO was completed in
47 days.
The unit was operating at full power at the close of the
inspection period.
3.
Operational Safety Verification (71707, 61710)
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.
3.1
Unit 2 Containment Walkdown
On March 14, the inspectors walked down the Unit 2 containment.
All RFO maintenance was complete and the inspectors verified that
containment was in a condition to support unit operation.
The
inspectors verified that the containment sump was clean and that
the remaining containment areas were reasonably free of debris.
The inspectors concluded that the overall condition of the
containment was adequate.
During previous inspections the inspectors have questioned the
acceptability of plant operation with the refueling transfer canal
drain valves closed (see NRG IR 50-280, 281/94-31).
The
inspectors verified, prior to the Unit 2 startup, that refueling
transfer canal drain valves (RL-11 and 12} were open based on a
valve lineup dated March 10, 1995.
3.2
Unit 2 Startup from Refueling Outage
The inspectors observed Unit 2 startup and low power physics
testing activities on March 19-21.
Communications and control of
activities within the control room were good.
This was the first
reactor startup following core reload. Operators were briefed to
anticipate criticality at any point during the startup and to
closely monitor the performance of a new IRNI detector which had
been replaced during the outage. Criticality was achieved very
close to the estimated critical position. Reactor power was
stabilized at approximately 1% power for physics testing.
Nuclear engineers conducted a detailed pre-evolution brief for low
power testing. Operators' questions regarding allowed plant
conditions were clearly answered. Several IRPis did not track
3
properly with control bank movement during physics testing.
Operators appropriately halted testing and had the IRPis adjusted
to match control rod bank demand position. Engineers verified
that the effected control rods were correctly positioned and were
not misaligned as the IRPis had indicated. The inspectors
observed that nuclear engineers and operations personnel
communicated effectively to maintain plant parameters within
prescribed conditions for physics testing.
The inspectors observed turbine startup and vibration monitoring.
Control room operators communicated closely with vendor personnel
during turbine roll-up to verify acceptable turbine vibration.
Operators exercised due caution when performing front panel trip
checks.
The turbine was placed on-line at 5:28 a.m., on March 21.
Operators manually maintained steam generator levels as the
turbine was loaded.
Within the areas inspected, no violations or deviations were identified.
4..
Maintenance Inspections {62703}
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
4.1
Unit 2 Main Generator VR Repair
The main generator exhibited voltage instability following unit
startup. Engineers and vendor personnel formed a VR task team to
identify the cause and recommend action to correct the voltage
instability. The team determined that vendor personnel had not
properly connected generator field forcing overexcitation
protection circuitry during outage maintenance activities. The
inspectors monitored resulting corrective maintenance activities
to verify appropriate measures were established to preclude
tripping the unit.
On March 29, the VR task team presented their findings and a
corrective maintenance work plan to SNSOC for approval.
SNSOC
closely reviewed the team findings and thoroughly questioned each
aspect of the on-line repair plan. Discussions included VR
cabinet vibration, positive identification of relays and contacts,
ICCE process controls, lessons learned from previous Unit 1 VR
work, worker communications, and interfaces between the station
and the off-site grid load dispatcher.
The inspectors observed
that SNSOC carefully evaluated whether the repair should be done
on-line or with the unit off-line. The decision to perform the VR
repair on-line and the detail of the work plan were sound.
The inspectors observed the repair prebrief and the corrective
maintenance to the VR circuits. An additional reactor operator
was assigned to operate and monitor the main turbine generator
4
controls in the control room.
Communications were established
between this reactor operator and the repair crew in the turbin~
building. Operations personnel coordinated closely with the load
dispatcher when shifting the VR from automatic control to base
load control to support the repair. The system engineer led the
repair effort and closely directed maintenance personnel through
all portions of the repair plan.
The inspectors particularly
noted excellent step by step communications between the system
engineer and the electricians in the high noise work environment
at the VR control cabinet.
The inspectors concluded that work
plan development, VR repair, and return of the VR to automatic
control were performed in a professional manner.
4.2
Review of Work Controls and Streamlining Efforts
In order to expedite work processes, several new initiatives were
implemented during the Unit 2 RFO in the area of MOV testing and
breaker maintenance.
MDAP-0002, Conduct of Maintenance, revision
2 was changed to allow the craft to review and sign MOV diagnostic
partial clearance forms, remove/install danger tags, and operate
the required breaker to energize MOVs in order to perform
diagnostic testing. Partial clearances were previously performed
by operations personnel.
MDAP-0002 was also revised to allow the
craft to relocate danger tags when removing and installing a
breaker in order to perform maintenance.
The inspectors verified
that craft personnel were trained on these new work process
methods.
The inspectors also reviewed deviation reports initiated
during the RFO due to tagging discrepancies and verified that
these new initiatives in danger tagging did not result in any DRs.
4.3
Modification to Waterproof MOV Operators
On March 5 through 9, the inspectors monitored portions of
DCP 93-17-03, Modify CW Limitorque Motor Operators to be *
Submersible, Surry/Units 1 and 2, field change 8. This design
change modified the eight condenser CW inlet MOV actuators to make
them watertight. Watertight actuators would enhance MOV operation
if these actuators were to become submersed in water during a
turbine building flood.
The inspectors witnessed the
modifications implemented by the design change and testing
associated with 2-CW.-MOV-206D.
The design change was accomplished
by WO 284426-01 and O-ECM-1504-01, Limitorque SMB Type MOV
Operator Maintenance, revision 1.
After the actuator was modified, an air drop test was performed.
The actuator was pressurized to 4.5 psig and the acceptance
criteria was that pressure could drop no more than .5 psig within
one hour.
The actuator failed the air drop test and a new motor
was installed. The air drop test was then satisfactorily
performed. The inspectors walked down the other CW inlet MOV
actuators and verified that they had been modified to be
watertight.
No deficiencies were noted.
5
4.4
Review of Unit 2 WO Backlog
Prior to the Unit 2 RFO on February 3, 1995, the inspectors
reviewed the licensee's WO backlog status. Prior to the outage,
Unit 2 had 3277 open WOs of which 2360 WOs were classified as
outage related and 824 WOs were classified as non-outage related.
After the outage completion, there were 1189 open WOs of which 401
WOs were classified as outage related and 788 WOs were classified
as non-outage related. The inspectors concluded that the licensee
was effectively tracking their WO backlog.
WOs were not
reclassified to reduce outage work scope.
4.5
Review of Selected RFO Maintenance and Testing Activities
During previous Unit 2 power operations, equipment degradation and
failures resulted in either plant transients or off-normal plant
operations. During this RFO, the inspectors monitored selected
maintenance and testing activities associated with correcting
these equipment problems.
Previously jumpered cell 52 and 17 other cells were replaced in
Station Battery 2A.
Work was performed per WO 303202-01 which
invoked procedure O-ECB-D102-0l, Large Exide Stationary Battery
Cell Replacement, revision 1.
IRPI coils for rods L-11 and M-10 were replaced per WO 301913-01
and 303204-01, respectively, using procedure O-ECM-1902-06, CRDM
and RPI System Maintenance, revision O.
During the disconnection
of the CRDM and IRPI cables to support refueling, the electricians
noted that several cables had heat damage.
The damaged cables
were sleeved with RayChem Kits which repaired the insulation
damage.
During the RFO, CRDR enhancements associated with main control
board single filament indicator bulb testing and replacement were
implemented.
New bulbs were tested (WO 313440-01} prior to
replacement.
The old bulbs were also tested as part of the
process and no failures were identified. There were 11 bulbs
involved in this maintenance activity.
The inspectors verified that Operations personnel were monitoring
the component cooling system radiation monitor when the Unit 2
excess letdown heat exchanger was pressurized during the ISI
hydrostatic test. Based on a review of station records, no alarms
were received when the heat exchanger was pressurized which
indicated tube integrity in the heat exchanger.
Within the areas inspected, no violations or deviations were identified.
6
5.
Surveillance Inspections (61726)
During the reporting period, the inspectors reviewed surveillance
activities to assure compliance with the appropriate procedural and TS
requirements.
5.1
MOV DP Testing
On March 13, the inspectors witnessed the performance of
2-PT-25.1, Quarterly Testing of CW and SW System Valves,
revision 3. This test verified that valves 2-SW-MOV-202A and B
would shut at maximum DP.
The test was being accomplished to meet
the requirements of GL 89-10, Safety-Related Motor-Operated Valve
Testing and Surveillance, dated June 28, 1989.
In order to obtain
maximum DP across the valves, intake canal level was raised to a
level of 30 feet and the piping downstream of the valves was
depressurized. The valves were instrumented with diagnostic test
equipment and satisfactorily opened during the test. Operators
followed the procedure, the craft was knowledgeable of the MOV
diagnostic test equipment and the system engineer efficiently
coordinated the efforts of .operations and craft personnel while
performing the test. The inspectors were informed by the system
engineer that thirteen valves were successfully DP tested during
the Unit 2 RFO.
5.2
Calibration Problems Associated With Unit 2 Pressurizer Pressure
Transmitters
5.2.1 Licensee's Identification and Evaluation of Problem
On February 10, 1995, during refueling calibrations, all
three Unit 2 Pressurizer Protection pressure transmitters
were found out of calibration. The Unit had been on line
continuously since June 25, 1994.
The as-found conditions
for the transmitters were:
2-RC-PT-2455 was high by 121 mv;
2-RC-PT-2456 was high 143 mv; and 2-RC-PT-2457 was high 152
mv.
These voltages correspond to 24 psig, 28.5 psig, and 30
psig above the allowable setpoint value. A root cause team
was formed to evaluate the event and determine the cause of
the unusually high indications. The following is a sequence
of events and a summary of that root cause evaluation:
Sequence of Events
May 12, 1994 - Bench calibration performed on all
three new Rosemount 1154 transmitters designated as
2-RC-PT-2455, 2456, 2457.
June 18, 1994 - After installion of the new
transmitters, I&C technicians performed a field
calibration. All three transmitters were found out of
calibration high and required adjustment.
Heise gage
M&TE #SQC-437 was used to perform the calibration.
7
June 21, 1994 - Heise gage SQC-437 was checked into
the Metrology Laboratory for its normal quarterly
calibration check.
No problems were found.
June 24, 1994 - Operations noted that all three
protection channels were indicating lower than control
channels and DR S-94-1352 was written.
Test gage
SQC-437 was used to perform calibration check on all
three Pressurizer Pressure Protection transmitters.
All three transmitters were found out of calibration
low and required adjustments.
June 24, 1994 - Unit 2 Critical
June 25, 1994 - Operations received pressurizer
pressure alarms and noted that protection channels
were reading approximately 15 - 20 psig higher than
the control channels.
June 28, 1994 - Heise gage SQC-437 was returned to the
Metrology Laboratory for calibration check.
The gage
was found to be nonrepeatable and low at the high end.
February 10, 1995 - During refueling calibrations, all
three Pressurizer Pressure Protection transmitters
were found out of calibration high and required
adjustment.
Licensee's RCE
The licensee's RCE determined that the most probable
cause of the calibration error was the use of a non-
temperature compensated test.gage. Test gage
calibrations were affected by 3 psig/5 degrees F
change from 73 degrees F.
This resulted in an
estimated 24 psig error. Additionally, the gage was
identified as binding due to inadequate torque during
the manufacturing process.
The licensee also
determined that a contributing cause was inadequate
training in using compensated/noncompensated gages.
5.2.2 Inspectors' Review and Assessment of Causes
The inspectors reviewed the licensee's RCE and supporting
information.
Based on vendor information from the test gage
supplier, a non-temperature compensated gage could
contribute to a calibration error as much as 3 psig/5
degrees F change from the reference calibrated temperature
of 73 degrees F.
The inspectors reviewed operator's logs
for temperature in containment.
The logs reviewed did not
provide an ambient temperature during shutdown.
However,
other data indicated that ambient conditions were at the
8
reference temperature.
Containment temperature during hot
shutdown and power operations is normally between 100 - 115
degrees F and therefore the licensee's assumptions of error
associated with use of a non-temperature compensated gage
was reasonable.
The licensee used the same non-temperature compensated test
gage to calibrate all three pressurizer pressure channels
and along with minor binding of the bourdon tube resulted in
the (worst case of the three) pressure transmitters reading
approximately 30 psig greater than actual pressure.
After determining that non-temperature compensated test
gages were in the M&TE system, the licensee confiscated all
these type gages and locked them up.
The RCE also.
determined that the licensee had to flush all gages that had
been used in contaminated systems prior to release to the
non-contaminated calibration facility for calibrations.
The inspectors reviewed the two DRs issued by operations
when the instrument error was initially identified in June
1994.
The first DR (S-94-1352) was dispositioned by
maintenance as a personnel error associated with
difficulties in reading the test gage during calibration
while in a respirator. The second DR (S~94-1353), issued
after alarms were received during unit startup, was closed
out due to the corrective actions of DR S-94-1352.
These
two DRs provided early opportunities for recognition and
correction which could have prevented unit operation with
degraded pressurizer pressure channels.
Another opportunity to identify and correct the above
condition occurred when M&TE test gage SQC-437 was found out
of calibration on June 28, 1994.
Had the intent of
VPAP-1201, Control of M&TE, revision 2, been followed, a re-
calibration of the three pressurizer pressure transmitters
would have occurred with a different test gage.
Specifically, the following requirements of VPAP 1201 were
not followed:
1) Section 6.3.2.b states, "The reliability and
accuracy of M&TE may be affected based on
environmental conditions (e.g., temperature extremes,
high humidity, etc.) The use of M&TE in such
environmental conditions shall be in accordance with
manufacturer's equipment specifications". This was
not done.
2) Section 6.6 requires an evaluation be performed
whenever M&TE is found out of calibration. The stated
purpose of the evaluation was to review the impact of
the out-of-spec readings on plant equipment that may
9
have been calibrated with questionable M&TE.
The as-
found error of the M&TE is required to be compared
against the tolerance of the plant equipment
calibration procedure.
If the M&TE error exceeds the
allowable tolerance of the acceptance criteria for the
plant equipment, then the calibration is invalid and
must be repeated if justification to do otherwise
cannot be found and documented.
The evaluation
performed when M&TE test gage SQC-437 was found out of
calibration on June 28, 1994, did not require a re-
calibration of affected plant equipment and attributed
the problem to disassembly of the test gage for
decontamination which is prohibited by Section
6.4.4.e.2 of VPAP 1201.
5.2.3 Review of Safety Significance
The February 10, 1995, as-found calibration error associated
with each of the three pressurizer pressure transmitter£ was
evaluated by electrical engineering.
The inspectors
reviewed this evaluation dated February 20, 1995.
The
evaluation compared the actual calibration error found for
each transmitter with the error assumed in the instrument
set-point calculation.
The transmitter error was tabulated
along with other instrument loop errors to determine the
overall error associated with the reactor trip and ESA
channels.
The impact of the instrument loop error on low
pressurizer pressure reactor trip and low-low pressurizer
pressure ESA events was calculated. The margin between the
value used in the SA and the actual pressure where the
channel would actuate the safety function was determined ..
In all cases, the TS allowable values and SA values were
exceeded and, therefore, the pressure channels were
inoperable. The worst case low pressurizer pressure reactor
trip point was 21.38 psig below the 1850.3 psig used in the
SA and the worst case low-low pressurizer pressure ESA was
31.38 psig below the SA value of 1700.3 psig.
The worst
case values were rounded to 22 psig and 32 psig and this
information was provided to the licensee's NAF group for
review.*
The NAF review was documented in ET no. NAF-95031,
Evaluation of Impact on Safety Analyses Pressurizer Pressure
Transmitters for RPS Input, Surry Power Station, Unit 2,
revision 0. This evaluation analyzed the impact of the
worst case setpoint errors on the SA for DNB plant
transients, steam line break, and large and small break
The evaluation determined that the worst case error
would result in a slight reduction of SA margin but was
still bounded by the SA for the cycle 12 operation (the
period of time that the instruments were
10
inoperable). The NRC questioned why ET NAF-95031, revision
0, did not review the error's impact on a SG tube rupture
event. This was discussed with the licensee and NAF-95031
was revised to include this information without changing the
results of the review.
The inspectors, along with other NRC
staff, found the licensee's safety impact review .acceptable.
5.2.4 Regulatory Issues
Technical Specifications 3.7.8 which references TS Table
3.7-1, and TS 3.7.C which references TS Table 3.7-2,
requires that Reactor Protection and Engineered Safeguards
Action channels and interlocks be operable as specified in
their respective tables.
TS Table 3.7-1, item 7, including
Operator Action 7 requires a minimum of 2 out of 3 Low
Pressurizer Pressure Reactor Trip channels be operable for
power operation.- TS Table 3.7.2, item l.d, including
Operator Action 20 requires a minimum of 2 out of 3
Pressurizer low-low pressure channels be operable for power
operations.
In summary, because of instrument calibration errors, Unit 2
operated at power from 9:25 pm on June 24, 1994, to 3:08 am
on February 3, 1995, with all three pressurizer low pressure
reactor trip and pressurizer pressure low-low ESA channels
inoperable. This item is identified as Apparent Violation
EEI 50-281/95-06-0l, Operation With All Three Channels of
Pressurizer Pressure Low Reactor Trip and Pressurizer
Pressure Low-Low ESA Inoperable.
Within the areas inspected, one apparent violation was identified.
-6,
Plant Support (71750)
The station established radiological performance goals for volume of
sold waste generated and cumulative personnel radiation exposure.
Station management remained actively involved in tracking performance
indicators to assess RP performance throughout the outage.
The
inspectors attended daily work status briefings and frequently toured
Unit 2 radiological work areas to observe RP practices.
RP technicians
provided comprehensive job coverage throughout the outage.
Both the
personnel exposure and solid waste generation goals were achieved.
The
total personnel exposure for the RFO was 157.7 Rem whfch is the lowest
RFO exposure achieved to date.
The inspectors concluded that station
personnel provided appropriate focus to minimize personnel exposure and
solid waste generation.
Within the areas inspected, no violations or deviations were identified.
.*
11
7.
Action on Previous Inspection Items (92901, 92902}
7.1
(Closed} VIO 50-280/93-23-01, Fuse Removal Not Accomplished in
Accordance with Tagging Record and OPAP-0010.
This issue involved electricians removing and danger tagging the
wrong fuses when establishing isolation for a maintenance
evolution.
In a letter dated November 19, 1993, the licensee
stated that electricians were not adequately trained or properly
qualified to install and verify electrical danger tags and that
the station tagging policy was revised to only allow Operations
personnel to install/remove electrical or mechanical danger tags.
The inspectors reviewed the station tagging policy contained in
VPAP-1402, Control of Equipment, Tag-Outs and Tags, revision 2,
OPAP-0010, Tag-Outs, revision 4, and MDAP-0002 and concluded that
the station policy to allow Operations personnel to install/remove
electrical or mechanical danger tags had been revised to allow
electricians to install/remove electrical danger tags in certain
instances.
VPAP-1402, Paragraph 4.2, discussed when electricians
are allowed to remove/install danger tags. The inspectors also
verified that electricians were trained. The inspectors concluded
that the revised policy was acceptable in that electricians were
thoroughly trained.
7.2
(Closed} URI 50-281/95-03-01, Unit 2 Pressurizer Excessive Heatup
Rate
On February 4, 1995, pressurizer heatup rate exceeded the 100
degrees F per hour TS limit during an RCS degas evolution. The
licensee identified that a 146 degrees F pressurizer heatup
occurred in one hour as operators adjusted charging flow to
maintain pressurizer level. Appropriate immediate actions were
taken to stop the pressurizer heatup and procedure revisions were
initiated to more clearly alert operators to the potential for
excessive heatup/cooldown during degas operations. This issue
remained unresolved pending inspector's review of the pressurizer
fatigue analysis.
IR 50-280, 281/95-03 discussed in detail the conditions that
caused the pressurizer heatup event.
Based on recent industry
events the licensee had modified their procedure to increase
operator sensitivity to pressurizer thermal transients. During
this event, operators had successfully terminated an unexpected
pressurizer cooldown because of their increased sensitivity to
thermal transients. However, plant conditions established for RFO
electrical surveillance testing hampered the operator's ability to
effectively control this event to prevent exceeding TS limits.
The licensee recently indicated that an industry group is
currently reviewing known startup and shutdown plant evolutions to
determine if better controls can be established to prevent future
events of this nature.
12
The vendor performed a pressurizer fatigue analysis to assess the
effects of the excessive heatup on pressurizer integrity. Station
records did not document pressurizer temperatures on an hourly
basis. Therefore, the licensee established 40 similar heatup
transients as a bounding case to account for potential excess
heatups during the current 40 year license. The inspectors
determined that this assumption was valid. The fatigue analysis
determined that the pressurizer inner wall was the limiting
component and concluded that cumulative fatigue was within
pressurizer design.
The resident inspectors discussed the fatigue
analysis with licensee personnel. It was determined that the
analysis was technically sound and that the fatigue associated
with this event was within pressurizer design.
TS 3.1.B.3 requires that pressurizer heatup rate not exceed 100
degrees F per hour.
On February 4, 1995, from 10:30 a.m. to 11:30
a.m., the Unit 2 pressurizer temperature increased 146 degrees F
(from 254 to 400 degrees) in one hour.
This excessive heatup is
identified as VIO 50-281/95-06-02, Pressurizer Excessive Heatup
Rate.
Within the areas inspected, one violation was identified.
8.
On-Site Engineering (37551)
8.1
Unit 2 HHSI Pump Motor Evaluation
NRC IR 50-280, 281/95-03 discussed a design issue associated with
the power requirements for the Unit 2 C HHSI pump motor. Testing
identified that the maximum motor power requirement was 711 HP
which exceeded the design value of 690 HP.
The motor
manufacturer, Westinghouse, was, contacted and evaluated motor
operation at 711 HP.
The inspectors reviewed Engineering Report CEE 95-23, HHSI Pump
Motor Overduty, dated March 10, 1995.
The report concluded that
the motor was operable and that EDG loading would not exceed the
2000-hour rating. The inspectors reviewed the Unit 2 HHSI pump
head curve and noted that the flow rates obtained during the
latest and previous flow rate tests were within twenty GPM of the
curve.
The inspectors concluded that small flow deviations from
the pump head curve resulted in large changes in motor power
requirements.
The inspectors also concluded that the licensee
satisfactorily resolved this issue prior to Unit 2 restart.
8.2
Pressure Locking of PWR Containment Sump Recirculation Gate Valves
(NRC TI 2515/129)
The inspectors reviewed the licensee's activities to evaluate
susceptibility of the CSRSVs (1-SI-1860A/B and 2-SI-1860A/B) to
the pressure locking phenomenon. These valves are designed to
13
open and provide a flow path from the containment sump to the LHSI
pumps for long term decay heat removal following a design basis
LOCA.
Initial assessment by the licensee indicated that the likelihood
of pressure locking would be greatly reduced or eliminated by
maintaining the containment sump suction piping full of water.
The containment sump suction piping and CSRSVs are located at a
lower elevation than the containment sump.
Operations personnel
visually verified the presence of water in the Unit 2 containment
sump and associated piping prior to restart. Engineers observed
water in the Unit 1 containment sump during the December 1994
outage. Operations and engineering personnel are developing a
plan to verify water in the containment sump during periodic
containment entries while at power and prior to each unit startup.
Engineering initiated a UFSAR change to document this design basis
configuration change.
The inspectors determined that these
actions were appropriate pending completion of a formal
engineering evaluation regarding susceptibility to CSRSV pressure
locking.
The licensee performed engineering evaluation ET CME 95-0018,
Engineering Review of OE 7107, revision 0, to evaluate
applicability of CSRSV pressure locking at Surry Station. The
evaluation concluded that l-SI-1860A/B and 2-SI-1860A/B were not
susceptible to pressure locking provided that the piping between
the containment recirculation sump and these valves was maintained
full of water.
The inspectors independently reviewed ET CME 95-
0018, the UFSAR, interviewed personnel, and visually inspected
associated valves and piping to evaluate the licensee's
conclusions.
The inspectors determined that assumptions used in evaluating ET
CME 95-0018 were generally conservative.
Assumed initial and post
DBA LOCA containment sump temperatures were more severe than
specified in the UFSAR.
The inspectors reviewed station drawings
and *visually inspected suction piping in the valve pits. The
actual piping length from the containment sump to the suction
valves was greater than assumed in the evaluation. Additionally,
credit was not taken for heat dissipation from the suction piping
to the surrounding concrete embedment.
Worst case assumptions
were also factored for valve seat leakage, packing leakage, and
presence of water inside the valve bonnet.
The resulting
calculated heatup rate inside the valve bonnet was 0.2 degrees F
per hour.
Engineering determined that the DBA LOCA leakrate would
necessitate shifting from LPCI to LPCI recirculation mode within 1
hour of the accident start. This resulted in a 0.2 degrees F
heatup of the water inside the valve bonnet and a maximum bonnet
pressure of 52 psig when the valve would be required to open.
The
evaluation concluded that valve operator design was sufficient to
overcome this amount of pressure within the bonnet.
14
The inspectors observed that the heat transfer calculations within
ET CME 95-0018 were technically sound.
However, the evaluation
did not address heat transfer to and from the atmosphere
surrounding the valve or heat transfer from the sump to the valve
via the piping metal.
Engineering informed the inspectors that ET
CME 95-0018 would be revised to address this concern.
Subsequent
to the inspection period, ET CME 95-0018 was revised and reviewed
by the inspectors. The inspectors concluded that the licensee's
actions to evaluate and address CSRSV pressure locking were
appropriate.
8.3
Shutdown Risk Assessment
SNS engineers performed an independent safety assessment of the
outage activity schedule in accordance with VPAP-2805, Shutdown
Risk Program, revision 1, to support safe integration of Unit 2
RFO maintenance activities. The Unit 2 Refueling Outage
Assessment Report was completed and distributed prior to the start
of the RFO.
The inspectors reviewed VPAP-2805, the Outage
Assessment Report, the outage work schedule, and daily
reassessments of safety critical parameters during the outage to
determine whether shutdown risk was properly managed.
VPAP-2805 provided detailed guidance regarding shutdown safety
system availability criteria. Several system requirements, in
addition to TS requirements, were specified to implement a defense
in depth philosophy.
The supplemental safety system requirements
encompassed decay heat removal, RCS inventory addition, reactivity
control, electrical power sources, and SFP operations.
The inspectors reviewed the Outage Assessment Report and observed
that scheduled activities which had the potential to degrade
critical shutdown safety attributes below established acceptance
criteria were clearly identified and evaluated.
Where
appropriate, the outage activities were rescheduled to maintain
acceptable availability of critical safety equipment.
One example
was a conflict between the monthly #3 EOG operability surveillance
test and maintenance on the B RSST.
Maintenance on the B RSST
required both Unit 2 4160 volt emergency buses to be supplied from
the C RSST.
The #3 EOG was the only available emergency power
supply to these buses in the event the C RSST. failed.
Unavailability of a backup power supply to the Unit 2 emergency
buses was identified as an unacceptable condition.
The #3 EOG
surveillance was rescheduled to eliminate this conflict. The
inspectors determined that the outage schedule had been thoroughly
evaluated and revised where appropriate to provide acceptable
defense in depth.
The outage schedule was frequently revised to accommodate
resource, work scope, and activity duration changes.
The licensee
used a computer application to assist in developing the Outage
Assessment Report.
The computer model tracked the impact of
.------:-...,....,,....----------------------------------------
al .~
, ***
15
outage activities on critical safety parameters including
reactivity, core cooling, electrical power availability,
containment, and RCS integrity.
SNS engineers effectively used*
this model to reassess the schedule on a daily basis during the
outage.
The inspectors reviewed selected daily shutdown safety
assessments and the resulting addendum to the Outage Assessment
Report.
Schedule revisions were evaluated in a timely manner and
addendum to the Outage Assessment Report were issued before the
schedule changes became effective. The inspectors concluded that
SNS review of outage activities was comprehensive and the licensee
had properly managed shutdown risk.
Within the areas inspected, no violations or deviations were identified.
9.*
Exit Interview
10.
The inspection scope and findings were summarized on April 5, 1995,
with those persons indicated in paragraph 1.
The inspectors described
the areas inspected and discussed in detail the inspection results
addressed in the Summary section and those listed below.
Item Number
Status
Description/(Paraqraph No.)
EEi 50-281/95-06-01
Open
Operation With All Three
Channels of Pressurizer
Pressure Low Reactor Trip and
Pressurizer Pressure Low-Low
(paragraph 5.2).
VIO 50-281/95-06-02
Open
Pressurizer Excessive Heatup
Rate (paragraph 7.2).
VIO 50-280/93-23-01
Closed
Fuse Removal Not Accomplished
in Accordance with Tagging
Record and OPAP-0010
(paragraph 7.1).
URI 50-281/95-03-01
Closed
Unit 2 Pressurizer Excessive
Heatup (paragraph 7.2).
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
Index of Acronyms
CFR
CROM
CRDR
CSRSV
cw
CODE OF FEDERAL REGULATIONS
CONTROL ROD DRIVE MECHANISM
CONTROL ROOM DESIGN REVIEW
CONTAINMENT SUMP RECIRCULATION SAFETY VALVE
CIRCULATING WATER
DESIGN BASIS ACCIDENT
~-
,**: .t '
,.
16
DESIGN CHANGE PACKAGE
DEPARTURE FROM NUCLEATE BOILING
DP
DIFFERENTIAL PRESSURE
DR
DEVIATION REPORT
ESCALATED ENFORCEMENT ITEM
ENGINEERED SAFEGUARDS ACTION
F
FAHRENHEIT
GL
GENERIC LETTER
GPM
GALLONS PER MINUTE
HIGH HEAD SAFETY INJECTION
HORSEPOWER
ICCE
INFREQUENTLY CONDUCTED OR COMPLEX EVOLUTION
INSTRUMENTATION AND CONTROL
IR
INSPECTION REPORT NOS.
IRPI
INDIVIDUAL ROD POSITION INDICATION
IRNI
INTERMEDIATE RANGE NUCLEAR INSTRUMENT
INSERVICE INSPECTION
LHSI
LOW HEAD SAFETY INJECTION
LOSS OF COOLANT ACCIDENT
LOW PRESSURE COOLANT INJECTION
MEASURING AND TEST EQUIPMENT
MOTOR OPERATED VALVE
MV
MILLIVOLT
NAF
NUCLEAR ANALYSIS AND FUEL
NRC
NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
POUNDS PER SQUARE INCH GAGE
PRESSURIZED WATER REACTOR
QUALITY ASSURANCE
ROOT CAUSE EVALUATION
REFUELING OUTAGE
RADIATION PROTECTION
ROD POSITION INDICATION
RESERVE STATION SERVICE TRANSFORMER
SAFETY ANALYSIS
SPENT.FUEL POOL
SNS
STATION NUCLEAR SAFETY
SNSOC
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
TI
TEMPORARY INSTRUCTION
TS
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
VR
VOLTAGE REGULATOR
VIOLATION
WORK ORDER