ML16148A700
| ML16148A700 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 11/16/1992 |
| From: | Belisle G, Binoy Desai, Harmon P, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A699 | List: |
| References | |
| 50-269-92-24, 50-270-92-24, 50-287-92-24, NUDOCS 9212020066 | |
| Download: ML16148A700 (26) | |
See also: IR 05000269/1992024
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-269/92-24, 50-270/92-24 and 50-287/92-24
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242
Docket Nos.:
50-269, 50-270, 50-287, 72-4
License Nos.:
DPR-38, DPR-47, DPR-55, SNM-2503
Facility Name:
Oconee Nuclear Station
Inspection Conducted:
September 26 -
November 3, 1992
Inspector:___
P. . Harmon ,enior
esident Inspector
Date/Si ed
B. . Desai, R ident InspectorSigned
W.K Pr
r
ient Inspector
W. K.eR-Dt'S
d
Approved b
G. A. Belisle, Section Chief
Date.Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine, resident inspection was conducted in the
areas of plant operations, surveillance testing,
maintenance activities, Keowee issues, and Low Pressure
Service Water (LPSW) issues.
Results: One apparent violation was identified which is under
consideration for escalated enforcement action and
involves inadequate LPSW flow through the 3B Low
Pressure Injection (LPI) cooler (paragraph 6.d).
One
unresolved item with two parts was identified and
involved annual testing the MG-6 relay for the Keowee
overhead path in accordance with the Technical
Specification and taking corrective action for testing
of the Keowee overhead electrical path (paragraph 5.b).
Two other unresolved items were identified involving
submitting a TS change for Unit 3 LPSW (paragraph 6.d)
and submitting a TS change for the LPSW system
(paragraph 6.a),. Two inspector followup items were
identified related to the containment
pressure/temperature response during accident
conditions and NPSH requirements
(paragraphs 6.i and
6.j respectively).
9212020066 921116
ADOCK 05000269
G
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- H. Barron, Station Manager
S. Benesole, Safety Review
- D. Coyle, Systems Engineering
- J. Davis, Safety Assurance Manager
D. Deatherage, Operations Support Manager
- B. Dolan, Manager, Mechanical/Nuclear Engineering (Design)
W. Foster, Superintendent, Mechanical Maintenance
J. Hampton, Vice President, Oconee Site
- 0. Kohler, Regulatory Compliance
C. Little, Superintendent, Instrument and Electrical (I&E)
- M. Patrick, Performance Engineer
- B. Peele, Engineering Manager
S. Perry, Regulatory Compliance
G. Rothenberger, Work Control Superintendent
R. Sweigert, Operations Superintendent
Other licensee employees contacted included technicians,
operators, mechanics, security force members, and staff
engineers.
NRC Resident Inspectors
- P.
Harmon
- W. Poertner
- B. Desai
- Attended exit interview.
2.
Plant Operations (71707)
a.
General
The inspectors reviewed plant operations throughout the
reporting period to verify conformance with regulatory
requirements, Technical Specifications (TS), and
administrative controls. Control room logs, shift
turnover records, the temporary modification log and
equipment removal and restoration records were reviewed
routinely. Discussions were conducted with plant
operations, maintenance, chemistry, health physics,
instrument & electrical (I&E), and performance
personnel.
Activities within the control rooms were monitored on
an almost daily basis. Inspections were conducted on
day and on night shifts, during weekdays and on
weekends. Some inspections were made during shift
2
change in order to evaluate shift turnover performance.
Actions observed were conducted as required by the
licensee's Administrative Procedures. The complement
of licensed personnel on each shift inspected met or
exceeded the requirements of TS. Operators were
responsive to plant annunciator alarms and were
cognizant of plant conditions.
Plant tours were taken throughout the reporting period
on a routine basis. The areas toured included the
following:
Turbine Building
Auxiliary Building
CCW Intake Structure
Independent Spent Fuel Storage Equipment Rooms
Units 1, 2 and 3 Electrical Equipment Rooms
Units 1, 2 and 3 Cable Spreading Rooms
Units 1, 2 and 3 Penetration Rooms
Units 1, 2 and 3 Spent Fuel Pool Rooms
Station Yard Zone Within the Protected Area
Standby Shutdown Facility
Keowee Hydro Station
During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation
control practices were observed.
Within the areas reviewed, licensee activities were
satisfactory.
b.
Plant Status
Unit 1
The Unit operated at power until October 3, 1992, when
the Unit experienced a reactor trip from 8 percent
power from an anticipatory loss of feed signal.
At
the time of the trip, 8:10 a.m., Unit 1 was critical at
8 percent power with the turbine generator off-line.
The licensee 'had reduced power from 100 percent power
to complete the testing and modifications on the Low
Pressure Service Water (LPSW) system as described in
paragraph 6. The cause of the trip was determined to
be a pressure swing that developed in the feed system
when a partially drained portion of the feed system was
realigned. The resultant pressure drop actuated the
Low Feedwater Discharge Pressure signal, which in turn
actuated the anticipatory Loss of Feedwater Reactor
Trip. Subsequent investigation revealed that a pump
vent valve did not function, resulting in the 1B
feedwater pump draining over a period of hours while
3
shut down. When operators began realigning the 1B
Pump, the void in the pump line caused a temporary low
pressure condition in the running pump's discharge
line.
Following the trip, the plant response was normal. The
vent valve was repaired and the unit was returned to
service on October 5, 1992.
Unit 2
The Unit operated at power until October 19, 1992 when
the Unit tripped due to a loss of offsite power. The
loss of offsite power event is discussed in NRC
Inspection Report Nos. 269, 270, 287J92-26. The Unit
was returned to service on October 26, 1992.
Unit 3
The Unit operated at power until September 29, 1992, at
9:16 a.m., when the Unit tripped from approximately 4
percent power. Just prior to the event, the Unit was
operating at 73 percent power and holding during
troubleshooting of the control rod drive (CRD) system.
When technicians opened a CRD breaker associated with
the 3A CRD power supply, the alternate 3B CRD power
supply should have provided power to the regulating
rods to keep them energized and withdrawn. Instead,
the control room operators observed that a single group
of regulating rods, group 5, had dropped. The
transient monitor later indicated that all three
regulating rod groups 5, 6, and 7 had dropped, but the
operators insisted that only the group 5 rods had
fallen.
With the dropped rods, a rapid power drop
occurred, and RCS pressure began dropping.
Approximately 13 seconds after the rods dropped, a
reactor trip was initiated by the RCS Low Pressure
signal.
The post trip response was normal, and the plant was
stabilized at Hot Shutdown conditions. The trip
investigation concluded that the probable cause of the
trip was a spurious failure of the 3B CRD power supply.
The actual root cause of the trip may not have been
positively determined. The licensee was also unable to
resolve the discrepancy between what the operators
observed as a single group of dropped rods, and what
the transient monitor identified as three dropped
regulating rod groups. Corrective actions included
replacing.a CRD programmer and revising troubleshooting
procedures to require checking the alternate
4
programmer's output prior to removing one programmer
from service.
After completing the post-trip review, permission to
restart was given by the plant manager at 8:15 p.m.,
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> after the trip. The plant returned to'
criticality at 11:57 p.m., on September 29, 1992.
On October 1, Unit 3 was at 83 percent power and in the
process of pressurizing the electrical generator to 60
psig with hydrogen. At 3:00 p.m., generator alarms
began coming in which indicated that seal oil was
entering the generator.
The hydrogen addition was
stopped at approximately 58 psig, and a power reduction
initiated. The generator was taken off-line at 8:35
p.m.
Investigation into the event disclosed that
approximately 1600 gallons of seal oil had leaked past
seals on each end of the generator. The seal
assemblies were found to be cocked. The seals were
repaired and the generator inspected and cleaned. The
Unit was returned to service on October 14, 1992.
Within these areas, no violations or deviations were
identified.
3.
Surveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy. The completed tests
reviewed were examined for necessary test prerequisites,
instructions,.acceptance criteria, technical content,
authorization to begin work, data collection, independent
verification where required, handling of deficiencies noted,
and review of completed work. The tests witnessed, in whole
or in part, were inspected to determine that approved
procedures were available, test equipment was calibrated,
prerequisites were met, tests were conducted according to
procedure, test results were acceptable and systems
restoration was completed.
Surveillances reviewed and witnessed in whole or in part:
TT/1/A/0251/21 Unit 1 and 2 LPSW System Flow Test
Within the areas reviewed licensee activities were
satisfactory.
No violations or deviations were identified.
4.
Maintenance Activities (62703)
5
Maintenance activities were observed and/or reviewed during
the reporting period to verify that work was performed by
qualified personnel and that approved procedures in use
adequately described work that was not within the skill of
the trade. Activities, procedures, and work requests were
examined to verify; proper.authorization to begin work,
provisions for fire, cleanliness, and exposure control,
proper return of equipment to service, and that limiting
conditions for operation were met.
Maintenance reviewed and witnessed in whole or in.part:
WR 92018790 Perform Diagnostic Test on 3FDW-316
WR 38156C
Investigate Why 3FDW-315 Indicates Open
WR 92046928 Repair Leak on Unit 2 EFDW Instrument Tap
Within the areas reviewed, licensee activities were
satisfactory.
No violations or deviations were identified.
5.
Keowee Issues
a.
General
The two Keowee hydro units provide two functions,
emergency power to the Oconee Nuclear Station (ONS)
through either the overhead or underground path and
commercial electrical power to the Duke system grid.
The electrical distribution and control circuitry is
designed so that one of the units will provide power
through the underground path and its respective
underground air circuit breakers (ACB) (ACB 3 for
Keowee Unit 1 and ACB 4 for Keowee Unit 2) through
transformer CT-4 to the standby buses. The other
Keowee unit provides emergency power through the
overhead path and its respective overhead ACB (ACB 1
and 2 for Keowee Units 1 and 2 respectively), the
Keowee main step up transformer, the 230 kv switchyard
and to each Oconee Units' startup transformer CT-1, 2,
or 3. The overhead path is also the path used when
using Keowee to generate power to the Duke Power
distribution grid via the 230 kv switchyard. The
overhead path is the preferred source of power because
unlike the underground path, it eliminates the need for
loadshed.
During an emergency, each Keowee unit could be either
running or in standby, and one units' underground ACB
would be closed. Upon receiving an emergency start
signal, both units will start if not already running,
and both overhead breakers (ACB 1 and 2) will open if
6
the units had been running and generating to the grid.
The overhead breaker for the unit aligned to the
overhead path will then close after certain criteria
are met. The criteria are:
1.
A four second time delay to enable Reactor Coolant
Pumps (RCPs) to trip and thus prevent overloading
a Keowee unit.
2.
Verification that the associated underground
feeder breaker is open to prevent energizing both
overhead and underground paths from the same unit.
3.
Verification that switchyard isolation has
occurred and a dedicated overhead path from Keowee
to Oconee has been established.
4.
Verification that the Keowee main step-up
transformer is deenergized.
After the above criteria are met, the Keowee unit would
then provide power to the main feeder busses either
through the overhead path or through the underground
path.
b.
Keowee Unit 2 Inoperable Due to Failure of MG-6 type
Undervoltage Relay
On September 29, 1992, at approximately 10:00 p.m.,
while performing a test concurrent with a post
modification test following installation of interlocks
on ACBs 1 and 2, ACB 2 did not close as expected per
the test procedure.
(The modification was initiated
because of a single failure vulnerability resulting in
two Keowee units tying to the overhead path, out of
phase, is discussed in NRC Inspection Report Nos. 50
269, 270, 287/92-23, URI 92-23-02).
Further
investigation revealed that relay 27T2X (Westinghouse
MG-6) had a one half inch contact gap instead of the
seven sixteenths inch gap specified by the
manufacturer. A technician tried to adjust the gap
between the contacts, and the plastic armature stop nut
broke apart. The relay was repaired by installing a
new armature stop nut and adjusting the contacts. The
test was reperformed and ACB 2 operated as required.
As a result of the failed MG-6 relay, the Keowee Unit 2
overhead path had been inoperable for an indeterminate
amount of time. One of the.prerequisites for the
overhead ACB (ACB 2) to close following an emergency
start is confirmation that the Keowee main step-up
transformer has deenergized. This is accomplished by
7
the MG-6 relay. With the relay failed, ACB 2 would not
have closed during an emergency start. Thus, the
overhead path when aligned to Keowee Unit 2, would not
have been available following an emergency start.
As previously stated, the MG-6 relay and consequently
the Keowee overhead path were inoperable for an
indeterminate amount of time. The time is
indeterminate for the following two reasons.
1.
The overhead path through ACB 2 was inoperable
only when Keowee Unit 2 was aligned to the
overhead path. Swapping of Keowee Units between
overhead and underground paths is done routinely.
2.
Neither the particular MG-6 relay nor the Keowee
overhead path had ever been tested according to
the licensee. The relay could have been bad and
thus the overhead path could have been inoperable
since initial installation. Periodic testing of
either the relay or the overhead path would have
identified the problem.
The inspectors had discussed the issue regarding the
lack of direct testing of the overhead path with the
licensee on several occasions. The licensee had
acknowledged the inspectors concern and had maintained
the position that they were in the process of.
coordinating a test to prove that the overhead path
would work if called upon. The licensee's current
test, as required by TS 4.6.5, is limited to testing
the External Grid Trouble Protection System logic.
This test is a continuity test and does not directly
test the Keowee overhead function.
In addition Oconee Technical Specification 4.6.2.a
requires that the Keowee Hydro units will be started
annually using the emergency start circuits in each
control room. This is to verify that each hydro unit
and associated equipment is available to carry load
within 25 seconds of a simulated requirement for
engineered safety features. The licensee conforms to
this requirement by performing PT/O/A/0620/16, Keowee
Hydro Emergency Start Test. This performance test
verifies operability of the Keowee emergency start
circuitry, and demonstrates that both Keowee units can
supply 25 MW of power within 23 seconds of emergency
start initiation. It does not verify operability of
the MG-6 feature of ACB 2 which is part of the
"associated equipment" referred to in TS 4.6.2.a. The
licensee has stated that they do not agree with the
inspectors position on the intent of the TS.
In
8
effect, the licensee has never tested the actual path
emergency power must take from Keowee to the Oconee
emergency buses. Until this issue of testing the MG-6
relay feature of the Keowee overhead path can be
resolved, this is identified as one part of Unresolved
Item 50-269, 270, 287/92-24-01: Testing the MG-6 Relay
Function Of The Keowee Overhead Path
The licensee performed a test, concurrent with the post
modification test, on September 29.
This test directly
challenged a portion of the overhead emergency path.
It was during this test that the failed relay was
identified.
The licensee issued LER 269 92-14 which described this
event. The licensee.stated in the LER that as part of
planned corrective action, they intend to develop and
implement an appropriate preventive maintenance program
for the MG-6 relays. The LER also states that the
licensee intends to test the overhead path. No time
frame for the completion of these actions is mentioned.
In view of the on-going efforts related to Keowee by
the AIT, the adequacy of corrective action following
the identification of the lack of testing of the
overhead path is identified as the second part of
Unresolved Item 50-269, 270, 287/92-24-01, Corrective
Action For Testing The Keowee Overhead Path.
c.
Single Failure That Could Result in Both Keowee
Emergency Power Sources Becoming Inoperable.
On October 12, 1992, at approximately 6:00 p.m., the
licensee identified a potential single failure which
could result in the loss of both overhead and
underground emergency power paths. The single failure
was a postulated fault on the overhead breaker ACB 1 or
2 for the Keowee Unit tied to the underground path. A
fault on the ACB in an overlap region between Keowee
generator zone differential current and main
transformer zone differential current transformers
would result in tripping the Keowee unit tied to the
underground power path as well as isolate the overhead
power path for both Keowee units thus rendering them
As an immediate fix, the licensee opened the
disconnects for ACB 2 to preclude the potential single
failure from occurring. This removed the capability of
the Keowee unit to generate to the grid. With ACB 4
closed, Keowee unit 2 was aligned to the underground
path, thus retaining both the overhead and underground
paths.
The issue is still under review and will be
9
tracked as part of the review of the LER which will be
issued on this item.
6.
Low Pressure Service Water (LPSW) Issues
a.
Unit 1 and 2 LPSW Technical Specification Deficiency
The inspectors identified that the TS associated with
the LPSW system for the shared Unit 1 and 2 LPSW system
was inadequate when a single failure of an LPSW pump
was considered. TS 3.3.7, Low Pressure Service Water,
requires that two of the three LPSW pumps for the
shared Unit 1 and 2 LPSW system be operable when the
reactor coolant system (RCS) is in a condition with
pressure equal to or greater than 350 psig or
temperature equal to or greater than 250 degrees F.
The inspectors determined that the ability of one LPSW
pump to supply accident loads on one unit and shutdown
loads on the other unit was questionable after review
of the licensee's flow model calculation for the shared
Unit 1 and 2 LPSW system. The inspectors discussed the
potential inadequacy of the TS with the plant manager
and the operations superintendent, and were told that
the calculation was only a preliminary calculation.
The inspectors responded that the calculation had been
completed and reviewed prior to review by the
inspectors and that the calculation did not appear to
support operation of Units 1 and 2 with only two LPSW
pumps operable as required by the TS.
The licensee reviewed the inspectors concerns and
concluded that three LPSW pumps were required to
support continued operation of Units 1 and 2.
Additional flow model calculations would also be
required to determine if LPSW flows to safety related
components would be acceptable assuming that both units
were operating at power if a design basis event
occurred. The licensee made a four hour non-emergency
notification to the NRC at 7:17 p.m., September 2,
1992, identifying that a single failure of one of the
required two LPSW pumps could result in the inability
of the LPSW system to maintain adequate flow to all
safety related components. The licensee initiated a TS
interpretation to require that all three LPSW pumps in
the shared Unit 1 and 2 LPSW system be operable to
consider the LPSW system operable. The licensee will
also be submitting a TS change to reflect this
interpretation and until this TS change is submitted,
this is identified as Unresolved Item (URI) 269, 270,
287/92-24-05: TS Change For LPSW System.
10
b.
Unit 1 and 2 LPSW Flow Calculation
The inspectors reviewed calculation OSC-4672, Unit 1
and 2 LPSW System Response To A Large Break LOCA With
Single Failure Using a Benchmarked Hydraulic Computer
Model. The inspectors questioned the adequacy of the
LPSW systems prior to reviewing the calculation and had
been informed by the licensee that the flow model
calculation had been completed on all three units and
that the calculation showed that flows to safety
related components were acceptable. .The calculation
assumed that one unit was shutdown and that the other
unit was operating at power and that the accident
occurred on the operating unit. The calculation was
then divided into separate scenarios:
The first scenario assumed all system flow path
valves wide open, all three LPSW pumps running
with loss of instrument air, no single failure and
both LPI coolers on the shutdown unit in service.
In this scenario, the calculation predicted that
LPSW flow to the Reactor Building Cooling Units
(RBCUs) would range from 1169 gpm to 1235 gpm and
that LPSW flow to the LPI coolers would range from
5447-gpm to 5944 gpm.
The 2nd scenario assumed a LOCA on Unit 1 and Unit
2 in a refueling outage with only one LPI cooler
in
service. The scenario assumed a loss of
instrument air, a single failure of an electrical
bus resulting in the loss of an LPSW pump and the
failure of an LPSW block valve to an LPI cooler to
open. This scenario also assumed that LPSW flow to
one RBCU was isolated and two LPSW pumps started.
In this condition, LPSW flow to the RBCUs on the
accident unit were predicted to be 1389 gpm and
1336 gpm and flow to the LPI cooler was predicted
to be 5810 gpm.
-
The 3rd scenario assumed a LOCA on Unit 2 and Unit
1 in a refueling outage with one LPI cooler in
service. In this condition, LPSW flow to the
RBCUs on the accident unit were predicted to be
1318 gpm and 1371 gpm and flow to the LPI cooler
was predicted to be 6120 gpm.
The inspectors questioned design engineering: (a) about
the assumption that two LPSW pumps would be available
on the combined Unit 1 and 2 LPSW system assuming a
pumps be operable for the LPSW system to be considered
11
operable; (b) the assumption that only one LPI cooler
would be in service on the shutdown unit; (c) the flow
to the RBCUs since past operability of the RBCUs had
been based on achieving 1400 gpm through the cooling
units under accident conditions; (d) the assumption
that LPSW flow to one RBCU was isolated since the RBCUs
are normally in service with LPSW flow established
through them; (e) the assumption that LPSW flow to the
RBCUs on the non-accident unit was throttled; and (f)
the assumption that LPSW flow to the reactor coolant
pumps on the non-accident unit would be isolated.
The inspectors-were told that the calculation was based
on the system capabilities, not the TSs and that
operator action could be expected to occur to throttle
LPSW flow to the LPI coolers to increase LPSW flow to
the RBCUs. The inspectors stated that the calculation
did not assume that only one LPSW pump would be
available under single failure conditions and informed
the design engineer that indication of flow to the
RBCUs would not be available under a loss of instrument
air conditions because the RBCU flow instruments are
air operated flow instruments and would lose indication
with a loss of instrument air. Therefore, the operator
would not have any indication that flow was less than
1400 gpm to the RBCUs. The inspectors also expressed
concern that credit was taken for operator action to
throttle LPSW flow to the LPI coolers since this
evolution could not be accomplished from the control
room and no guidance was available to the operators in
the control room on when or how to accomplish this
task.
The inspectors determined that calculation OSC-4672 had
been completed on June 19, 1992, and that the approval
of the calculation had been completed on July 30, 1992.
Based on the licensee's additional review and
discussion with the residents, the licensee determined
that the LPSW system required that three pumps be
operable and made a report to the NRC on September 2,
1992, as discussed in paragraph 6.a.
c.
Unit 3 LPSW Flow Calculation
The inspectors reviewed Calculation OSC-4489, Predicted
LPSW System Response To A Large Break LOCA With A
Single Failure Using a Benchmarked Hydraulic Computer
Model. The calculation assumed that the worst case
single failure was a loss of a 4160 volt switchgear
which would result in the loss of an LPSW pump, a low
pressure injection (LPI) pump and LPI cooler LPSW inlet
valve, and a reactor building cooling unit (RBCU).
12
The inspectors questioned the adequacy of the
licensee's assumptions in determining predicted flow to
the safety-related components. The calculation
reviewed by the inspectors assumed that all non
essential (non-safety) loads were isolated during a
LOCA event and that when a component was lost due to a
single failure, flow through that component was
isolated. The inspectors questioned the assumption
that all non-safety loads would isolate and that LPSW
flow to the inoperable RBCU would be zero. Unit 3 was
in a scheduled refueling outage when the inspectors
reviewed the calculation and the LPSW system was not
required to be operable per the TS.
The inspectors' concerns were discussed with licensee
management. The licensee's response was that flow
testing was not required. After further discussion,
the licensee agreed to perform an LPSW flow
verification test on Unit 3 prior to returning the unit
to service from the refueling outage. The inspectors
met with licensee management to express concerns that
the flow model did not accurately reflect the LPSW
system. The inspectors were initially told that the
Unit 3 flow model would be verified by the flow test
and that the adequacy of the Unit 1 and 2 flow model
would be evaluated based on the results of the Unit 3
testing, since flow testing on Units 1 and 2 could not
be performed conveniently with the units at power.
d.
Unit 3 LPSW Flow Testing
The inspectors reviewed and witnessed the Unit 3 LPSW
system flow testing which commenced on September 14,
1992.
During review of the initial procedure, the
inspectors identified that the test did not fail all
the air operated valves in the system to their failed
condition. The air operated flow control valves to the
air handling units in the auxiliary building were left
in their normal alignment. These valves fail open on a
loss of air. The inspectors discussed this item with
the licensee and were told that the flow through these
lines would be insignificant even with the air operated
valves failed open and that failing'the valves open
would only increase the time required to perform the
flow test and would not affect the outcome of the test.
During the flow test, the licensee was unable to
achieve greater than 5200 gpm flow through the 3B LPI
cooler with the 3A LPI cooler isolated and the main
turbine oil cooler isolated. The licensee's emergency
operating procedures require that LPSW flow be
increased to 5200 gpm on the operable LPI cooler after
13
swap over to the containment sump if both trains of LPI
are not available. The licensee determined that manual
isolation valve, 3LPSW-78, downstream of the cooler
flow control valve was not fully open due to an
actuator problem. The valve is a butterfly valve and
the pin connecting the actuator to the stem had
dislodged. This resulted in the valve being in a
throttled position when the handwheel indicated full
open.
The inspectors expressed doubts to the licensee about
the ability to achieve 5200 gpm through the 3B LPI
cooler prior to the unit shutting down for the
scheduled refueling outage. The inspectors had
reviewed a performance of procedure PT/3/0150/22A,
Operational Valve Stroke Test, on June 9, 1992, while
Unit 3 was operating at full power. The LPSW portion
of this PT requires that a flowrate of 5200 gpm be
achieved through the LPI coolers. During the
performance of the test, 5200 gpm could not be achieved
through the 3B LPI cooler with only one LPSW pump
running, so the operators in the control room started
the second LPSW pump to achieve the required 5200 gpm.
The inspectors questioned the operators in the control
room, operations staff and performance engineering,
about the adequacy of the testing conducted and were
told that the status of the LPSW pumps was not a
requirement for performing the test and that under
accident conditions, 5200 gpm could be achieved through
the cooler due to isolation of nonessential loads. The
inspectors were also told that the 3B LPI cooler had
always exhibited lower flow than the 3A LPI cooler and
that starting the second LPSW pump to achieve the
required flow was normally done for the test and not
unexpected. The inspectors expressed concern about the
apparent flow imbalance between the two LPI coolers to
licensee management and requested that flow testing of
the LPSW system be considered during the refueling
outage. The inspectors consider the licensee's actions
inadequate with respect to identifying and correcting
the degraded LPSW flow path to the 3B LPI cooler and
identify this item as apparent Violation 269, 270,
287/92-24-02: Inadequate Corrective Action.
After valve 3LPSW-78 was repaired, the licensee
recommenced the LPSW flow test. The inspectors
witnessed the performance of the test and observed that
during the performance of the test, the licensee could
not achieve 1400 gpm flow through the RBCUs with only
one LPSW pump running, unless flow through both LPI
coolers was secured. The licensee has experienced
fouling of the RBCUs in the past and implemented an
14
RBCU testing program to ensure operability of the
RBCUs.
The operability determinations assumed that the LPSW
flow to the RBCUs would exceed 1400 gpm. The TS also
requires that 1400 gpm-LPSW flow be achievable for RBCU
operability. TS 4.5.2.1.2, Reactor Building Cooling
System, requires that a system test be conducted each
refueling outage to demonstrate proper operation of the
system. The test is considered satisfactory if control
board indication verifies that all components responded
to the actuation signal properly, the appropriate pump
breakers completed their travel, fans are running at
half speed, LPSW flow through each cooler exceeds 1400
gpm and air flow through each fan exceeds 40,000 CFM.
The licensee took the position that 1400 gpm was not a
requirement with only one LPSW pump operating, and that
as long as the heat inside containment could be removed
with the reduced flow rate provided by one LPSW pump,
restart of Unit' 3 could proceed. The licensee stated
that the requirements of the TS could be met by
operating two LPSW pumps. The inspectors did not agree
with the licensee's interpretation of the TS
requirement and a meeting was held between NRR, Region
II and the licensee. The meeting determined that
restart of Unit 3 with LPSW flows less than 1400 gpm to
the RBCUs, with one LPSW pump operating, was acceptable
provided an analysis was performed to verify that
reactor building heat removal requirements could still
be met with the reduced LPSW flow available, and 1400
gpm could be achieved with two LPSW pumps operating.
The licensee would also submit a TS amendment to revise
the operability requirements for the LPSW system. The
inspectors will review the corrective action as stated
in the LER to verify that a TS change is submitted for
this item. Until the licensee submits this TS change,
this is identified as Unresolved Item (URI) 269, 270,
287/92-24-04: TS Change For Unit 3 LPSW.
The licensee performed a temporary test to verify that
1400 gpm could be achieved through the RBCUs with two
LPSW pumps operating and LPSW flow to the LPI coolers
throttled to 3000 gpm. The temporary test also
established maximum flow through one LPI cooler with
two LPSW pumps operating to verify that LPSW flow
through the cooler would not exceed 7500 gpm. The
design flow rate for the LPI coolers was originally
6000 gpm; however, the cooler manufacturer was
contacted and stated that the cooler was designed for
7500 gpm continuous service. During the performance of
the test the flow rate to the RBCUs was greater than
15
1400 gpm with two LPSW pumps operating. However, when
the flow control valve to the 1A LPI cooler was failed
open, flow exceeded 7500 gpm. The 1A LPI cooler flow
indicated 7900 gpm when the control valve was failed
open. The inspectors questioned the performance
engineer prior to the test about the expected flow to
the cooler when the control valve was failed open. The
performance engineer stated that design engineering had
calculated that LPSW flow to the cooler would not
exceed approximately 6500 gpm if the valve was failed
open and the other LPI cooler was isolated. The
procedure required that 5800 gpm be established through
both LPI coolers prior to failing the 1A cooler outlet
valve open. This was to ensure that excessive flow
would not be experienced through the cooler with the
failed open control valve. When the valve was failed
open, the control valve to the main turbine oil cooler
was in automatic and approximately 75 percent open.
Even with the extra flowpaths established, the flow to
the 1A LPI cooler exceeded the 7500 gpm requirement.
The licensee reduced the flow through the 1A LPI cooler
to less than 7500 gpm by securing an LPSW pump and
returned the control valve to normal.
The licensee contacted the cooler manufacturer and
obtained an engineering evaluation that 7900 gpm flow
would not have caused degradation of the cooler and
obtained an evaluation that LPSW flow through the
cooler could be sustained at 8800 gpm for two hours
without resulting in catastrophic failure of the
cooler. The licensee performed another temporary test
to determine if flow through an LPI cooler could be
throttled to less than 7500 gpm assuming two LPSW pumps
operating and still achieve greater than 5200 gpm with
one LPSW pump operating. The purpose of the temporary
test was to determine if travel stops could be
installed on the flow--control valves to prevent
excessive flow through the cooler and still achieve the
required flow rate during worst case low flow
conditions. The test determined that travel stops
could be installed. The licensee installed travel
stops on the LPI LPSW flow control valves while
increasing plant temperature and pressure in
preparation for restarting the Unit. The travel stops
were installed and tested prior to exceeding 250
degrees F or 350 psig in the RCS. No additional flow
model testing was conducted after installation of the
travel stops.
16
e.
Unit 1 and 2 LPSW System
Throughout the reporting period the inspectors
questioned the licensee about the adequacy of the Unit
1 and 2 flow model calculation. The inspectors were
informed that the Unit 1 and 2 flow model calculation
had been revised to reflect the worst case low flow
condition assuming both units were operating and that
the model showed that adequate flows would be achieved
through the safety-related loads but that flow to the
RBCUs would be less than 1400 gpm on the accident Unit.
The licensee performed an operability evaluation that
determined that LPSW flows as low as 800 gpm would be
acceptable to the RBCUs under accident conditions. The
flow model calculation predicted that LPSW flow to the
RBCUs would be greater than 1000 gpm. -The licensee
also performed a flow model calculation to determine
predicted high flow conditions through the LPI coolers
assuming only one cooler was in service and a loss of
instrument air occurred. The calculation determined
that with three LPSW pumps operating, LPSW flow to one
LPI cooler would not exceed 8800 gpm and that with two
LPSW pumps operating LPSW flow would not exceed 7500
gpm. The licensee had obtained an evaluation from the
cooler manufacturer that a flow rate of 8800 gpm could
be sustained for two hours and failure of the cooler
would not occur. Based on the predicted flow rate, the
licensee modified the emergency operating procedures to
require that one LPSW pump be secured following an
accident if all three LPSW pumps in the shared Unit 1
and 2 system automatically started.
The inspectors still had concerns with the adequacy of
the Unit 1 and 2 flow model and requested that the
licensee evaluate the possibility of performing limited
flow testing of the Unit 1 and 2 LPSW system to
determine if the flow model calculation could be
bounded or verified by actual flow or pressure
measurements. The licensee's position was that the
Unit 1 and 2 flow model calculation supported the
continued operation of Units 1 and 2 and that further
review of the issue would be conducted.
f.
Unit 1 and 2 Waiver of Compliance
On September 29, 1992, the licensee determined that the
LPSW pump performance curves assumed in the Unit 1 and
2 LPSW system flow model calculation were
nonconservative. The licensee initially used generic
pump performance curves provided by the pump
manufacturer and included a five percent margin in the
17
flow model calculation to account for actual pump
performance. On September 29, 1992, the licensee
performed a test to determine the actual head curve
generated by the LPSW pumps. The actual LPSW pump head
curve exceeded the generic head curve used in the flow
model calculation. Based on the information obtained
from the LPSW pump testing, the licensee determined.
that the predicted flow rate could exceed the allowable
maximum continuous flow rate allowed by the cooler
manufacturer. The licensee also determined that pump
runout problems could potentially exist under certain
conditions. The licensee reported the condition to the
NRC via the requirements of 10 CFR 50.72 and entered a
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Limiting Condition for Operation (LCO).
On September 30, 1992, the licensee requested a
temporary waiver of compliance to allow Units 1 and 2
to remain at less than 10 percent power for 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> to
permit testing and modification of the LPSW and LPI
systems. Units 1 and 2 commenced a power reduction and
power levels were stabilized at approximately 8 percent
on October 1, 1992, at approximately-2:30 a.m. to allow
testing and modification.
On October 4, 1992, testing and modifications of the
shared Unit 1 and 2 LPSW system were completed. The
licensee installed travel stops on the LPI cooler LPSW
flow control valves to prevent excessive flow through
the coolers under worst case conditions. During the
testing process, the licensee determined that with the
travel stops installed and two LPSW pumps operating,
the required LPSW flow to the LPI cooler on the
accident Unit might not be achievable if LPSW flow to
both LPI coolers on the non-accident Unit was
established. The licensee agreed that simultaneous
LPSW flow through the LPI coolers would not be
established and also stated that both Units would be
shutdown if one Unit was required to shutdown to cold
shutdown conditions until resolution of the issue.
Based on these conditions, concurrence was obtained to
exit the LCO and return the Units to power.
g.
Previous LPSW Calculations
The inspectors reviewed some earlier calculations
performed by the licensee concerning LPSW flow
predictions. The calculations reviewed by the
inspectors all used the same basic assumptions
contained in the calculation reviewed by the inspectors
on September 2, 1992.
The calculations reviewed by the
inspectors were performed as early as 1988 and
concluded that the LPSW systems were acceptable as is.
18
The inspectors reviewed Calculation OSC-4017,
Evaluation of the LPSW System Flow Models Under Single
Failure Scenario, completed October 4, 1990. The
purpose of the calculation was to run the hydraulic
models assuming a single failure and a loss of offsite
power. The calculation assumed only one LPI cooler was
operable on the accident unit and that one LPI cooler
was out for maintenance on the outage unit. The
calculation assumed that one RBCU was out of service on
the accident unit and that flow was throttled to the
RBCUs on the nonaccident unit. The calculation assumed
that LPSW flow to the reactor coolant pump motors had
been isolated. The calculation determined that flow to
the two operable RBCUs on the accident unit would be
less than 1400 gpm for both Units 1 and 2 with two LPSW
pumps operating. The calculation concluded that LPSW
flow to the two operable RBCUs on Unit 3 would be
greater than 1400 gpm. The calculation stated that
flow is marginally inadequate to the RBCUs on Units 1
and 2, that in both cases flows are no greater than 10
percent less than the required flows and that given the
accuracy of the computer program, the flows were
acceptable. The calculation goes on to state that the
LPSW system is adequate as designed to provide the
required flowrates to all safety related components.
These calculations are additional examples like those
discussed in paragraph 6.b. The resolution of the
operation of the LPSW system is discussed in paragraph
6.a.
h.
Self Initiated Technical Audit (SITA) Findings.
The licensee performed a technical audit of the LPSW
system in 1987. This audit identified numerous
deficiencies and unresolved items. It also identified
that calculations which demonstrated acceptable flow to
all safety-related LPSW loads during accident
conditions were not documented and the current test
program was inadequate to verify acceptable flow. The
licensee response stated that recognition that normal
flows exceed emergency flow demand rendered this
calculation unnecessary; however, the licensee agreed
to generate a hydraulic flow model. The calculation
documenting the results of the model would be completed
by August 20, 1988, and the calculation would verify
that the LPSW system is sufficient to supply all
required needs. The licensee had the opportunity to
identify LPSW performance problems based on the results
of the flow model calculations.
The SITA identified that the LPSW control valves to the
LPI coolers fail open on a loss of air and that the LPI
19
coolers are susceptible to damage caused by excessive
flow. The licensee responded that the concern that the
LPI coolers are susceptible to damage caused by
excessive flow was not founded. Calculation OSC-859
determined that the maximum cooler flow that can be
obtained on the LPSW shell side is 7500 gpm. The
licensee also responded that performance tests also
support that an LPSW flow rate of over 7500 gpm through
the LPI cooler is not obtainable.
The inspectors reviewed calculation OSC-859, Decay Heat
Coolers Overflow Protection. The calculation states
that test data was obtained in the field with one LPSW
pump in operation and service water flow to all normal
LPSW requirements. The calculation records a flow
through the "A" LPI cooler of 5500 gpm with the outlet
flow control valve 60 percent open. The calculation
goes on to generate a flow versus head curve and
concludes that 7500 gpm is the maximum cooler flow if
approximately 10,500 gpm is assumed going to other LPSW
requirements. The assumption that 10,500 gpm goes to
other components is not supported.
The inspector's review concluded that the calculation
did not support the conclusion that LPSW flow through
the LPI cooler would not exceed 7500 gpm. The
inspectors also concluded that the performance testing
conducted on the LPSW system did not support the
conclusion that an LPSW flow rate of over 7500 gpm was
not obtainable through the cooler. LPSW flow through
the LPI coolers is discussed in paragraph 6.d under
item 92-24-02: Inadequate Corrective Action.
i.
Containment Heat Removal Requirements
The licensee performed a benchmark flow test on the
Unit 3 LPSW system in May of 1991. The licensee
performed a benchmark flow test of the shared Unit 1
and 2 LPSW system in January of 1992.
The purpose of
the tests was to record pressure and flow measurements
at various key points throughout the LPSW system. The
data obtained from the benchmark tests was used to
"calibrate" the LPSW flow model calculation originally
performed in 1988.
The inspectors reviewed the Benchmark test conducted on
the Unit 3 LPSW system and determined that the
benchmark test did not establish flow through all LPSW
loads simultaneously to establish a baseline condition.
The benchmark test established 3200 gpm flow through
the 3A LPI cooler, isolated the 3B RBCU, and throttled
LPSW flow to the 3A and 3B RBCUs to 1400-1450 gpm. The
20
inspectors questioned the usefulness of the data
obtained from the benchmark test since the system
resistance had been artificially induced by throttling
all the flowpaths. The inspectors questioned the
decision not to establish flow through the 3B RBCU and
the 3A LPI cooler. The inspectors were told that the
test had been performed when Unit 3 was operating at
power and that the normal accident alignment could not
be achieved because the nonaccident loads could not be
isolated. The inspectors reviewed the past operating
history of Unit 3 and determined that the Unit had been
shutdown for a scheduled refueling outage from February
13, 1991 to March 30, 1991. The benchmark test could
have been performed during the refueling outage and the
unit could have been configured in any test
configuration required to support the acquisition of
useful data. The inspectors believe that an adequate
benchmark test would have identified that the
performance of the LPSW system was questionable.
The inspectors reviewed the benchmark test performed on
the shared Unit 1 and 2 LPSW. The inspectors noted
that during the benchmark test the licensee was unable
to obtain greater than 1400 gpm through the Unit 2
RBCUs even though the 1B and 2B RBCUs were isolated.
During the benchmark test both units were operating at
power and the nonaccident loads were not isolated.
The licensee performed an operability evaluation prior
to restart of Unit 3 to ensure that reduced LPSW flow
through the RBCUs would not adversely affect the
pressure/temperature response of thereactor building
after a design basis accident. This evaluation
determined that an LPSW flowrate of 800 gpm to the
RBCUs was acceptable to remove the required heat load
inside the reactor building. The inspectors requested
that the licensee provide the heat removal requirements
for the containment heat removal systems. The
inspectors were informed that the containment heat
removal requirements were predicated on not exceeding
59 psig peak containment pressure and the reactor
building equipment qualification (EQ) temperature
curve. The licensee stated that RBCU performance did
not affect peak containment pressure and that the
combined effect of the RBCUs and LPI maintained the
containment within the requirements of the EQ curve.
The FSAR states that a reactor building cooling unit
has a design heat removal capacity of 80 million BTU/HR
for a combined heat removal capability of 240 million
BTU/HR. The licensee, in the past, stated that the
combined heat removal capability of the two worst RBCUs
must meet or exceed 80 million BTU/HR to meet
21
containment heat removal requirements. A meeting was
held between the inspectors and the licensee on October
22, 1992, to discuss containment heat removal
requirements. The inspectors were provided a copy of
the licensees EQ curve superimposed on the reactor
building temperature response curves contained in the
FSAR (Figure 15-71).
Based on the curve provided, the
inspectors determined that containment heat removal
systems were not required to meet the EQ curve in the
first 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> of the accident. The inspectors asked
the licensee to verify this assumption and were told
that the RBCUs were required to remove 71.8 million
BTU/HR.until the LPI system was aligned to the
containment sump to maintain containment temperature
below the EQ curve. The inspectors stated that the
curves provided did not indicate that containment
temperature could exceed 286 degrees even with no RBCUs
operating and no building spray actuation. The
licensee again stated that based on analysis, the RBCUs
were required to remove 71.8 million BTU/HR until LPI
is aligned to the containment sump at which time they
are only required to remove 31 million BTU/HR to
maintain the containment within the requirements of the
EQ curve. The inspectors requested that the licensee
provide the original licensing basis of the containment
heat removal systems for review. Subsequent to the
meeting, the inspectors were informed that the 71.8
million BTU/HR requirement was based on a more
sophisticated computer code that the licensee is in the
process of submitting to the NRC for approval. The
FSAR curves are based on the present computer code and
show that containment temperature response stays below
the EQ envelope without RBCUs in operation for the
initial phase of the accident. The inspectors were
informed that the new computer code was scheduled to be
submitted to the NRC for approval in 1993.
The
inspectors identify this item as Inspector Followup
Item 269, 270, 287/92-24-03: Containment
Pressure/Temperature Response.
j*
Net Positive Suction Head (NPSH) Requirements
Subsequent to returning the Units to power operation,
the licensee determined that LPSW flow rates could
exceed the analyzed flow rate for pump operation of
15,000 gpm, with no Condenser Cooling Water (CCW) pumps
operating and a lake level of 780 feet. During the
LPSW flow testing conducted on the Unit 1 and 2 LPSW
system, the "C" LPSW pump indicated 19,200 gpm with
maximum flow through all four LPI coolers and one main
turbine oil cooler in service.
In this configuration,
one CCW pump was in operation supplying NPSH to the
22
LPSW pumps. The licensee was unable to determine the
developed flow rate from the other operating LPSW pump
due to the location of the flow instrument on the "B"
The licensee performed Calculation OSC-5018,
Operability Evaluation for PIR 0--92-0535, dated
October 26, 1992, to evaluate the operability of the
LPSW system and ensure that NPSH available to the LPSW
pumps is greater than required NPSH. The licensee
determined that available NPSH would exceed required
NPSH if lake level was maintained at or above 795 feet
and LPSW flow was limited to 16,600 gpm per pump. The
licensee contacted the pump manufacturer and obtained
an evaluation that the pumps could withstand operation
with inadequate NPSH for short term operation of 30
minutes. Based on the information provided, the
licensee's operability statement required that LPSW
flow to one LPI cooler on the nonaccident Unit be
secured within 10 minutes and flow through a bypassed
Main turbine oil cooler be secured within 30 minutes to
ensure that LPSW flow would be less than 16,600 gpm.
The NPSH concern is applicable when one Unit is in a
refueling outage and an accident occurs on the other
Unit. Until the inspectors can review this item in
detail prior to the Unit 1 refueling outage scheduled
for December 1992, this is identified as IFI 269, 270,
287/92-24-06: NPSH Requirements.
Within these areas, one apparent violation, two unresolved
items and two inspector followup items were identified.
7.
Exit Interview (30703)
The inspection scope and findings were summarized on
November 3, 1992, with those persons indicated in paragraph
1 above. The inspectors described the areas inspected and
discussed in detail the inspection findings. The licensee
did not identify as proprietary any of the material provided
to or reviewed by the inspectors during this inspection.
Item Number
Description/Reference
Paragraph
URI 269,270,287/92-24-01
Testing the MG-6 Relay And
Corrective Action For Keowee
Overhead Path (paragraph 5.b).
VIO 269,270,287/92-24-02
Inadequate Corrective
(Apparent)
Action For LPSW Low Flow
(paragraph 6.d).
23
Item Number (CONTINUED)
Description/Reference
Paragraph
IFI 269,270,287/92-24-03
Containment
Pressure/Temperature Response
(paragraph 6. i).
URI 269,270,287/92-24-04
TS Change For Unit 3 LPSW
(paragraph 6.d)
URI 269,270,287/92-24-05
TS Change For LPSW System
(paragraph 6.a).
IFI 269,270,287/92-24-06
NPSH Requirements
(paragraph 6.j).
ENCLOSUPE 2
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