ML16161A785
| ML16161A785 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 11/28/1986 |
| From: | Bryant J, Peebles T, Sasser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16161A784 | List: |
| References | |
| 50-269-86-33, 50-270-86-33, 50-287-86-33, NUDOCS 8612100022 | |
| Download: ML16161A785 (14) | |
See also: IR 05000269/1986033
Text
C11-
p'ftRE~j
q.,UNITED
STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos: 50-269/86-33, 50-270/86-33, and 50-287/86-33
Licensee:
Duke Power Company
422 South Church Street
Charlotte, N.C. 28242
Facility Name:
Oconee Nuclear Station
Docket Nos.: 50-269, 50-270, and 50-287
License Nos.: DPR-38, DPR-47, and DPR-55
Inspection Conducted: October 15 - November 10, 1986
Inspectors:
7,10A Z
J. C. Bryant
Date Signed
M.-(. Sasstr
Date Signed
Approved by:
T. Peeblef, Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection involved resident inspection on-site
in the areas of operations, surveillance, maintenance, verification of engineered
safety features lineups, followup of events, followup items of non-compliance,
and performance indicators.
Results: Of the seven areas inspected, no violations or deviations were identi
fied in six areas.
One item of violation was identified in one area; Failure to
test the ECCW system adequately.
This violation is being considered for escalated enforcement:
Technical Specification 4.0 requires that surveillances be performed to
assure that the quality of systems is maintained and that operation is
within the safety limits and limiting conditions for operation.
The ECCW
system test frequency is given in Table 4.1.2.
Contrary to the above, as discovered during a test conducted on October 1,
1986, the ECCW had never been tested in a manner adequate to reveal that the
ECCW would not perform its required function during station blackout with
Lake Keowee level nine feet below full pond. Although the system has been
tested according to procedure at the required frequency, the test procedure
was inadequate to reveal system deficiencies.
The violation was identified
by the licensee. The resident inspectors also were present.
8612100022 861201
PDR ADOCK 05000269
G
REPORT DETAILS
1. Licensee Employees Contacted
- M. S. Tuckman, Station Manager
T. B. Owen, Maintenance Superintendent
R. L. Sweigart, Operations Superintendent
J. M. Davis, Technical Services Superintendent
- C. L. Harlin, Compliance Engineer
- F. E. Owens, Assistant Engineer, Compliance
N. A. Rutherford, System Engineer, Licensing
Other licensee employees
contacted included technicians,
operators,
mechanics, security force members, and staff engineers.
Resident Inspectors:
- J. C. Bryant
- M. K. Sasser
.
- Attended exit interview.
2. Exit Interview
The inspection scope and findings were summarized on November 13, 1986, with
those persons indicated in paragraph 1 above.
The licensee did not identify as proprietary any of the materials provided
to or reviewed by the inspectors during this inspection.
3.
Licensee Action on Previous Enforcement Matters
VIO 270/85-10-01
(Closed)
Control
Rod Position Limits Exceeded.
The
inspectors have reviewed the procedural revisions, additional training, and
other corrective actions and consider them satisfactory to prevent recurr
ence of this type of violation.
VIO 270/85-41-01 (Closed) Delayed Shutdown With RCS Leakage Greater Than 1
GPM. The inspectors have reviewed the implementation of a revised reactor
coolant system leakage calculation procedure and have verified that adequate
acceptance criteria exist to prevent similar problems in the future.
VIO 269/84-25-04, 270/84-24-04, 287/84-27-04 (Closed) Failure to Dissemi
nate Information on Operating Experience to Mechanical and I&E Personnel.
The inspectors reviewed revised Maintenance Directive II.3 which implements
the program for providing operating experience information to all levels of
Maintenance personnel.
The implementing procedures and training records
were also reviewed to ensure that plant personnel are being appropriately
trained on pertinent information and that this information is documented.
2
The program as implemented provides assurance for compliance with TMI Action
Item I.C.5, Establishment of Procedures for Feedback of Operating Experience
to Plant Staff.
4. Unresolved Items
No unresolved items were identified during this inspections.
5. Licensee Event Reports
The inspectors reviewed nonroutine event reports to verify the report
details met license requirements,
identified the cause of the event,
described corrective actions appropriate for the identified cause,
and
adequately addressed the event and any generic implications.
In addition,
as appropriate, the inspectors examined operating and maintenance logs, and
records and internal investigation reports.
Personnel were interviewed to verify that the report accurately reflected
the circumstances of the event, that the corrective action had been taken or
responsibility assigned to assure completion,
and that the event was
reviewed by the licensee, as stipulated in the Technical Specifications.
The following event reports were reviewed:
LER 269/86-01 (Closed) Generator/Reactor Trip Due To Failure Of PCB-20
In 230 KV Switchyard.
Corrective actions taken by the licensee have
been reviewed and are acceptable.
LER 269/86-03 (Closed)
Missed Grab Sample When The #3 Chemical
Treatment Pond Liquid Effluent Sampler Was Inoperable. Procedures have
been revised to improve shift turnover to ensure personnel are aware of
inoperable instruments and resulting required actions.
LER 269/86-04 (Closed)
Fuel Movement In Progress While NI-1 Inoper
able. Corrective actions taken by the licensee have been reviewed and
determined to be satisfactory.
LER 269/86-07 (Closed) Two Reactor Protection System Channels Inoper
able At The Same Time.
I&E Maintenance procedures have been revised to
require tagging of an
RPS channel
any time a dummy bistable is
installed or when the channel is inoperable due to a failed instrument.
Tagging of the bypass key alerts personnel of the condition to ensure
that two channels are not bypassed at the same time.
LER 270/86-02 (Closed)
Reactor Trip Due To Personnel Error During
On-Line Control
Rod Drive Breaker Testing.
The inspectors have
reviewed the corrective actions and consider them appropriate to
prevent recurrence of this type of event.
LER 270/86-04 (Closed) Reactor Trip From High Steam Generator Level.
(Closed) Reactor Trip From High Steam Generator Level.
3
LER 269/85-07 (Closed) Unit 1 Trip On Loss Of Main Feedwater Following
Failure of Static Inverter. All corrective actions have been completed
and are satisfactory.
LER 269/84-07 (Closed) Unit 1 Trip Upon Loss of Main Feedwater Pumps.
Shaft oil pump was disassembled and inspected with no problems found.
Check valve on auxiliary oil pumps was found stuck open, preventing
shaft pump from maintaining sufficient pressure.
6. IE Bulletins and Inspector Followup Items
BU 83-03 (Closed)
Check Valve Failures in Raw Water Cooling Systems of
Diesel Generators (DG's).
The inspectors reviewed the licensee's response
dated June 20, 1983.
At that time there were no DG's in use at Oconee.
Since that time, the standby shutdown facility (SSF) was completed and was
declared operational in October 1985.
The SSF utilizes a DG. The inspec
tors reviewed tests of flows and back leakage performed on valve CCW-284.
The system is tested under PT/O/A/0400/04, Diesel Engine Service Water Pump
Test, which is performed quarterly.
Tests performed on 7/30/85, 1/8/86,
6/3/86, and 9/3/86 gave satisfactory results with little or no back leakage.
The test of 4/8/86 revealed considerable back leakage.
The inspectors
reviewed Work Request (WR) 91067C, dated 4/8/86 and performed on 6/8/86,
under which valve CCW-284 was disassembled, inspected, cleaned and blue
checked. No problem was found other than crud in the system. The valve was
tested subsequently and performed with no back leakage.
IFI 269/84-25-05,
270/84-24-05,
287/84-27-05
(Closed)
Deficiencies in
General Employee Training (GET).
The inspectors reviewed the licensee's
upgraded training program to determine if upgrades had been effected in
those areas where deficiencies were found to exist. The licensee was found
to have appropriately upgraded training in security, QA, emergency response,
independent verification, adherence to procedures, and health physics, both
in the video presentations and the material included in the GET handbook.
These revisions were a direct response to the inspectors' earlier findings
and the licensee's normal program for review and upgrade of training
programs.
IFI
269, 270, 287/86-10-01
(Closed)
End of Cycle Moderator Temperature
Coefficient
(MTC)
Measurements.
Additional measurements of MTC were
completed on Unit 3. The results were acceptable and verified the revised
Final Safety Analysis Report calculations.
IFI 270/85-37-02
(Closed)
Mispositioned Containment Isolation Valve.
Immediate corrective actions were taken to ensure that containment integrity
was maintained.
Supplemental actions were taken to provide added assurance
that the valves in question will remain in the required position in the
- k
future.
4
7.
Plant Operations
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,
and equipment removal
and restoration records were reviewed
routinely.
Interviews were conducted with plant operations, maintenance,
chemistry, health physics 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 week days and
on weekends.
Some inspections were made during shift change in order to
evaluate shift turnover performance.
Actions observed were conducted as
required by Operations Management Procedure 2-1. 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
Units 1 and 2 Penetration Rooms
Units 1,2, and 3 Electrical Equipment Rooms
Units 1,2, and 3 Cable Spreading Rooms
Station Yard Zone within the Protected Area
Standby Shutdown Facility
Condenser Circulating Water Intake Structure
During the plant tours,
ongoing activities, housekeeping,
security,
equipment status, and radiation control practices were observed.
Unit 1 began the report in cold shutdown,
having shut down during the
previous report period due to inoperability of the Emergency Condenser
Circulating Water (ECCW)
system (see report 86-26).
Following repairs to
and successful testing of the ECCW system, the unit was taken critical on
10/19 at 10:09 p.m.
The turbine generator was placed in service the
following day.
Power was increased to approximately 99% and remained there
for the duration of the report period. The unit is limited to 99% power due
to a high level in the B Once Through Steam Generator (OTSG).
Unit 2 began the report period in a refueling and maintenance outage, with a
delayed startup date due to ECCW inoperability. On 10/17 the reactor was
taken critical for performance of zero power physics testing (ZPPT).
Later
the same day, after completion of ZPPT,
power was increased to 15% for
additional Low Power Physics Testing.
On 10/18 the generator was place in
service and power was increased to succeeding higher levels for power
escalation testing.
5
Unit 2 reached 92%,
limited to that power level due to high level in the B
OTSG.
Both OTSGs had undergone water slap and sludge lance cleaning
processes during the outage, with levels in the A OTSG improving while the B
OTSG appeared to have gotten worse.
On 10/23, at 2:37 p.m. the reactor
tripped when high OTSG level caused a turbine trip. The high level trip was
reached during a secondary feedwater swing initiated by problems in the
integrated control system (see paragraph 10).
The reactor was returned
critical at 7:17 the same day.
Power was increased to approximately 95%
where it has remained for the duration of the report period.
Unit 3 began the report period in cold shutdown due to ECCW inoperability.
On 10/22 at 2:11 a.m. the reactor was taken critical and power ascension
began. At 8% reactor power control room alarms indicated a low oil level in
the 3B1 Reactor Coolant Pump (RCP).
The pump was secured and the reactor
taken subcritical at 7:50 a.m. in order to make a reactor building entry to
add oil to the RCP.
Following addition of oil the reactor was critical at
2:13 a.m.
On 10/23,
the turbine generator was placed on line and power
increased to 100%.
On 10/24 the Statalarm for low oil level on 3B1 RCP was again received in
the control room. Power was reduced to less than 75%, the RCP was secured
and shutdown of the Unit was initiated for repair of the oil leak.
The
reactor was shutdown at 1:02 a.m.
on 10/25 and subsequently taken to cold
shutdown conditions.
Following a four day outage the reactor was again
critical at 9:19 a.m. on 10/29.
Power was increased to 96% when, on 10/30,
the 3B1 motor frame vibration increased and alarms on the Unit 3 Loose Parts
Monitor indicated problems with the RCP. Power was reduced to less than 75%
and the pump was secured.
See paragraph 17 for details surrounding the
problems found with the RCP and analysis thereof. The Unit has continued in
a 3 RCP operating mode at 72% as limited by Technical Specifications. The
licensee plans to operate in this mode for the duration of this cycle, with
a refueling outage scheduled in March 1987.
No violations or deviations were identified.
8.
Surveillance Testing
The surveillance tests listed below were reviewed and/or witnessed 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, prere
quisites were met, tests were conducted according to procedure, test results
were acceptable and systems restoration was completed.
6
Surveillances witnessed in whole or part:
TT/2/A/0711/09 Unit 2 Cycle 9 ZPPT
TT/2/A/0811/09 Unit 2 Cycle 9 Power Escalation Test
No violations or deviations were identified.
9. Maintenance Activities
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, clean
liness, and exposure control,
proper return of equipment to service, and
that limiting conditions for operation were met.
Maintenance witnessed in whole or in part:
WR 91457C Repair Gov. Valve on 2 TDEFWP
WR 40501C Troubleshoot ICS to find source of feedwater swings,
turbine header pressure swings.
No violations or deviations were identified.
10.
Unit 2 Trip
At 2:37 p.m. on 10/23 Unit 2 tripped from 92% power following a turbine trip
on high steam generator (OTSG) level.
Prior to the trip the reactor was
restricted to 92% power by high OTSG levels (90% in B OTSG)
despite the
OTSGs having been water slap and sludge lance cleaned during the recently
completed refueling outage.
The initiating cause of the transient was the failure of an Integrated
Control System (ICS)
module responsible for control of the turbine steam
header pressure.
Upon failure of the instrument the turbine control valves
stepped open resulting in rapid decrease of the turbine header pressure.
The sudden decrease in steam pressure caused a rapid overfeed of feedwater
to the OTSG's.
Since the OTSG's were already operating with high levels,
the high level trip setpoint (96%)
was exceeded all most immediately,
preventing recovery from or corrective actions by the reactor operators.
The OTSG high level trip caused the main turbine and main feedwater pumps to
trip, resulting in an anticipatory reactor trip.
Both motor driven emergency feedwater pumps (MDEFWP)
actuated to control
OTSG levels.
At the time of the transient the turbine driven emergency
feedwater pump (TDEFWP) was out of service for maintenance. There was no
Engineered Safety Feature Actuation.
All systems responded normally.
Following a post trip review, replacement of the ICS instrument module, and
return to service of the TDEFWP,
the reactor was returned critical at 7:37
pm with the generator on line at 12:30 a.m., 10/24.
7
This type of transient is expected to occur more frequently than in the past
as the reactors continue to operate with higher than normal OTSG levels.
The licensee is pursuing additional methods for cleaning the OTSGs,
including chemical cleaning which will be tried in a future refueling
outage.
No violations or deviations were identified.
11.
Unusual Event:
Hydrazine Spill
An Unusual Event was declared at the Oconee site at 9:10 p.m. on October 21,
1986 due to a hydrazine spill of approximately two gallons in the turbine
building. The Unusual Event was declared due to the release of a toxic gas,
although there was no detectable gas at site boundaries.
There were no
injuries due to the release.
Hydrazine is used at Oconee for oxygen scavenging in the secondary system.
The spill was caused by a deionized water mixing valve leaking through and
causing the mix tank, located in the turbine building, to overflow.
The
spill was detected by an operator who smelled ammonia and tracked down the
source. A site assembly was held in order to account for all personnel.
The leakage was stopped, the spilled area cleaned, and the Unusual Event
terminated at 11:25 p.m. on October 21, 1986.
No violations or deviations were identified.
12.
Electrical Inoperability of Limitorque Valve - Unit 2
Prior to start up of Unit 2 following refueling shutdown,
the licensee
discovered damage to Limitorque operated valve 2CF-1.
Valve 2CF-1 is the
isolation valve from 2A core flood tank, which normally is in the open
position with breaker open and locked during reactor operation. Valve 2CF-1
is not on the licensee's list of valves for immediate rework as given in the
response to IE Bulletin 85-03 dated May 16,
1986.
However,
the valve
operator will be refurbished and MOVATS tested in the program presented to
Region II on August 1, 1986. The description of the event as given below is
essentially verbatim from a licensee internal report.
During the visual inspection of 2CF-1 for functional verification after
maintenance it was discovered that the limitorque operator had some sheared
bolts on the operator cap flange. When attempting to replace the bolts it
was further discovered that the cap flange bolting surface on the operator
housing has cracks around the bolt holes.
This portion of the operator
contains the stem c'ollar and bushing, stem nut and a locking nut. The lock
nut threads were found to be stripped and as a result the stem collar and
stem nut were forced up against the cap flange upon stem movement.
This
overstressed the cap flange retaining bolts causing the bolts to shear and
bolt holes to crack.
8
The licensee determined that the torque switch on the operator was not
functioning properly, causing the operator to overtorque, stripping the lock
nut. Temporary repairs were made which replaced the lock nut and cap flange
bolts.
Permanent repair of the operator would require removal from the
valve and subsequent valve stroking upon replacement to set up the limit and
torque switches. A Performance stroke test is also required after operator
repair. This repair, at the present time with RCS system pressure
800
psig, would require direct violation of Technical Specification 3.3.3 upon
stroking the valve closed.
The temporary repair will allow the valve to be operated manually if needed.
However, there is no guarantee that the valve will operate electrically.
Presently the valve is in its normal position, open, with the breaker white
tagged and locked open.
This allows the 2A Core Flood Tank to operate as
designed during an accident situation (i.e. largeLOCA).
During a normal
plant shutdown, when isolating the Core Flood Tanks, the 2A tank will have
to be isolated by manually closing 2CF-1.
Emergency Operating Procedure EP/2/A/1800/01 directs the operators to close
the Core Flood Tank isolation valves in 3 different situations:
Cooldown
Following a Large LOCA; Steam Generator Cooldown with a Saturated RCS; and
HPI Cooling Cooldown. The licensee determined that the inability to isolate
the core flood tank after dumping following a large break LOCA is not a
concern since the nitrogen entering the system would exit out the break. In
the other two situations, isolation of the Core Flood Tanks is performed to
aid in cooldown when the following conditions exist, RCS pressure § 1000
psig and core subcooling margin
0 degrees Fahrenheit.
Attempting to
isolate 2A Core Flood Tank by electrically operating 2CF-1 should only be
done in these 2 situations if absolutely necessary and with approval of the
Operations Duty Engineer.
Control of 2CF-1 will be handled in the following way until the next
available time for repair (RCS
system § 800 psig).
The control switch will
be white tagged and an additional white tag will be put on the valve breaker
with instructions to operate electrically only with the approval of the
Operations Duty Engineer. A copy of this letter will be put in the Unit 2
Operational Guide Book and this information will be noted on the RO turnover
sheet and the Unit 2 Supervisors turnover sheet.
The inspectors will follow up on repairs to 2CF-1.
This is listed as an
inspector followup item;
IFI 86-33-01, Repairs to Valve 2CF-1.
13. Operability of Rotork Valve Actuators
On Friday, 10/24, the Oconee staff was notified by the Duke General Office
(GO)
that valve actuator testing conducted at the Catawba Nuclear Station
had determined that the torque switch settings on Rotork actuators are not
linear as previously assumed by the vendors and licensee. The non-linearity
was found in the non-conservative direction such that the torque switch
setting of installed valves may not allow adequate torque development for
operation of the valves under all conditions.
9
While the licensee's McGuire and Catawba Nuclear Stations utilize Rotork
actuated valves in numerous applications, their use at Oconee is limited to
30 valves in 12 different applications. Limitorque actuators are used more
frequently at Oconee.
The licensee's Oconee and GO staff reviewed the
applications of the 30 safety related Rotorks to determine if
the oper
ability of the valves is in question. Based on the current switch settings,
the design conditions that each valve must meet to accomplish its safety
function, and actual testing on the valves, each has been determined to be
fully operable at the present time. The licensee's findings are as follows:
1. 3LP1,
3LP2 - Suction valves to decay heat cooling pumps from the
A calibration curve is on file for each of these valves and the
torque switch settings have been field verified.
2.
1,2,3LP103 - Post LOCA boron dilution valves
1,2,3LP104 - Post LOCA boron dilution valves
1LP105
- Alternate flowpath for post LOCA boron dilution
for Unit 1 only
1,2,3HP398 - RCP seal injection from Standby Shutdown Facility
reactor coolant makeup pump
1,2,3LPSW565 - Low pressure service water isolation to the
reactor building auxiliary cooling units.
1,2,3LPSW566 - Low pressure service water isolation to the B
reactor building cooling unit.
1.2.3PR59 -
Reactor building purge system isolation to
hydrogen analyzer
1,2,3PR60 -
Reactor building purge system isolation to
hydrogen analyzer
The above listed valves are tested (ASME
XI cycled) during normal
plant operations at conditions which approximate those conditions
which would occur when each has to perform its safety function.
Each has operated satisfactorily during normal testing, therefore
each is considered operable with the current settings.
HP398 is
required only during an SSF event.
3. 1,2,3FDW347 - SSF auxiliary service water pump supply to B
OTSG.
1,2,3CCW269 - SSF auxiliary service water pump supply to A
OTSG.
Comparison of the factory torque settings with the field installed
settings verified that the actuators were installed as received.
Those settings used will allow the valves to perform their safety
functions.
FDW 347 is required to be open during plant opera
tions.
CCW269 is required only during an SSF event.
Based on the above evaluations, these valves have been determined to be
fully operable. The licensee will adjust torque settings to their optimum
value during a future outage as part of the program to upgrade motor
operated valves through a program of signature analysis, rebuilding, and
testing (as defined by IE Bulletin 85-03).
14.
Followup on General Electric Service Information Letter (SIL) 445
Region II correspondence to the residents dated 10/20 requested followup on
SIL 445 entitled, "Intermediate Range Monitor (IRM)
Fuse Failure", dated
7/26/86. While the SIL involved specific equipment installed only at GE
Boiling Water Reactors,
the residents reviewed the intermediate range
channel equipment installed at Oconee to determine if similar problems could
exist.
In the GE IRM system, multiple fuse failures had occurred in the positive
and negative 24 Vdc power supplies to the system. Fuses for the +24Vdc were
replaced and the system appeared to be working properly.
However, it was
later discovered that there were still blown fuses in the -24Vdc power which
prevented signal processing in the system, with the ultimate result that IRM
initiated scrams provided by the Reactor Protection System (RPS)
may not
have occurred if needed.
O At Oconee the RPS uses a +15Vdc and -15Vdc
power supply system.
If any
power supply fails (blown fuse, open breaker, etc.) the respective RPS
channel will trip providing control room statalarms and a channel tripped
indication to the other RPS channels. Therefore,
any failure places the
system in a conservative configuration.
The power supplies for the source, intermediate, and power range detectors
are all separate. If any fail, the flux signal from the respective detector
fails low. Once again, control room statalarms provide indication of failed
channels.
15.
Emergency Condenser Circulating Water (ECCW)
IE Report No. 50-269, 270 and 287/86-26 discusses in detail the licensee's
finding of the plants inability to sustain ECCW gravity flow, the rapid
response in shutting down the two operating units, the determination of the
cause and the corrective action taken. Though the resident inspectors were
witnessing this test, the licensee also promptly reported the events and
developments to Region II.
Three Unresolved Items were identified in report 86-26.
One of these
concerned inadequate procedures and testing to verify gravity flow, in that
gravity flow probably could never have been maintained when Lake Keowee was
approximately nine feet below full pond.
The lake was in that condition in
the early 1980's and had been in that condition most of the preceding year
when the deficiency was identified in October 1986.
Condenser Circulating
Water System Gravity Flow Test, PT/1,2,3/A/261/06, is performed on each
refueling outage with the purpose of, as related to gravity flow, to test
that following simulated loss of power to the CCW pumps, cooling water flow
is maintained by gravity and siphon effect to the Keowee tail race.
The
acceptance criteria are that all valves assume their proper position to
establish and sustain gravity .....
flow as specified in the procedure; and,
gravity flow is verified by visual observation.
No required time of flow
was specified.
In a letter to the Region II Administrator, the licensee described the
manner in which the test will be performed in the future. This states that
flow will be maintained a minimum of four hours and that an acceptable
minimum CCW
pump discharge vacuum shall be maintained for at least four
hours.
Technical Specification 4.0 requires functional tests to demonstrate
capability of systems to perform design functions, though the ECCW system
has been tested at required frequency and met the acceptance conditions, it
is apparent that the tests performed were not capable of demonstrating that
the system met design intent.
In not analyzing the system adequately to
determine that flow would exist for a time due to draining of the system,
with or without a siphon being established, the acceptance criteria led
observers into thinking siphon flow had been established as soon as flow
appeared at the tailrace.
Though the licensee's actions meet the criteria of 10 CFR Part 2, Appendix C, for licensee identified violations, in the inspector's opinion,
adequate review of the procedure should have determined much earlier that
the performance test was not adequate to demonstrate proper operation of the
system.
Therefore,
UNR 50-269,270,287/86-26-04 will be changed to a
Violation, (Violation 50-269.270,287/86-33-02,
Inadequate Testing of ECCW
System).
The unresolved item will be cancelled.
The referenced report also listed two other Unresolved Items concerning the
ECCW event.
These were UNR 50-269,270,287/86-03, Questionable Design of
ECCW system and UNR 50-269,270,287/86-05, Inoperable High Point Vent Vacuum
Lines, concerning blind flanges in the vacuum lines of Unit 2. While these
events were as described, they will not be cited as violations since they
occurred over thirteen years ago, and failure to detect them earlier would
fall under inadequate testing cited earlier in this paragraph.
16.
U-3 Steam Generator Tube Leak
At the time Unit 3 was shut down on October 2 for ECCW system modification,
it had demonstrated a possible steam generator tube leak.
At the time of
shut down,
the suspected leak was too small to make identification of a
leaking tube certain.
During the shutdown for the ECCW system, the steam
generator was examined and four tubes which exhibited small leaks were
plugged along with an additional three tubes in the same area.
12
17.
Unit 3 - Reduced Power Due to Reactor Coolant Pump Problem
At 5:10 a.m. on October 30, 1986, Unit 3 was reduced in power from 96% to
65% and reactor coolant pump (RCP) 3B1 was shut down due to reduced perfor
mance and other symptoms of degraded pump operation.
Anomalies noted prior
to, during, and following pump shut down were as described below.
10/28;
6:00 p.m.
Primary chemistry detected a possible crud burst
in the RCS
and a high suspended solid concentration.
Activation product concentration using Mn 56 as an indicator
reached 2.1 uCi/ml prior to pump shutdown.
Concentration
reached 0.119 uCi/ml 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> after RCP shut down.
10/29;
7:15 p.m. Slight FDW re-ratio along with a 1-2% increase in
total RCS flow.
10/29;
11:27 p.m.
Computer alarm on RPS flow low with 6% drop in
RCS total flow indicated.
Loose parts monitor alarm for
reactor vessel, cleared upon acknowledgement.
10/30;
12:01 a.m. RCP 3B1 motor input power dropped from 6.1 to 5.1
mw.
Stattor temperature dropped 12 degrees Fahrenheit.
Motor vibration began increasing.
10/30;
4:44 a.m. RCP 3B1 motor frame vibration had increased to 2.1
mils.
10/30;
5:10 a.m. RCP 3B1 was shut down after reactor power had been
reduced to 65%.
Analysis by the licensee resulted in the evaluation that there had been no
core damage; that the noise monitor reflected normal pump shut down noise;
that there probably was a failure in the pump wear ring or intake vanes; and
that continued operation, without any starting or stopping of RCP's, should
not result in the relocation of or generation of any loose parts.
Following an evaluation to justify continued operation,
the licensee
increased power to 72% with RCP 3B1 shut down,
as permitted by Technical
Specifications.
It is planned to complete the current cycle at that power.
Unit 3 is scheduled for refueling shutdown about March 1, 1987.
18. Licensee Identified Violations
LIV86-01 (Closed) Time Limit Exceeded in Emergency Response Requalification
Training.
In a letter to Region II dated October 7, 1986,
the licensee
reported that,
due to a change in the schedule for annual
requalification of Operations Emergency Response personnel,
the
requalification training period exceeded the stated one year + 3
13
months period for certain personnel.
The licensee has taken
adequate corrective action to update training and to prevent
recurrence. This item is closed.
LIV86-02 (Closed) RIA-54, Isolation of Turbine Building Sump Discharge on
High Activity found bypassed on October 28, 1986.
All releases from the sump had been sampled daily with no high
activity noted; also, RIA-54 Statalarm in control room would have
alarmed on high activity even though there would have been no
automatic isolation.
Adequate corrective action was taken to
prevent recurrence. This item is closed.