ML20245F547
| ML20245F547 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 06/05/1989 |
| From: | Cantrell F, Christensen H, Mathis J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20245F533 | List: |
| References | |
| 50-416-89-14, NUDOCS 8906280167 | |
| Download: ML20245F547 (17) | |
See also: IR 05000416/1989014
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
2
REGION 11
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101 MARIETTA ST., N.W.
ATLANTA, GEORGIA 30323
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Report No.: 50-416/89-14
Licensee:
System Energy Resources, Inc.
Jackson, MS 39205
-Docket No.: 50-416
License No.: NPF-29
Facility Name: Grand Gulf Nuclear Station
Inspection Conducted: April 15 through May 19, 1989
Inspectors:
.
MA
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H. O. Christensens
ipVResidentInspector
D6te' Signed
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J. LT Mathis, Residentlyegtor
Date Signed
Approved by:
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F.1.'Cantrell Secti6 /4hief.
D' ate / Signed
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Division of Reactor Frojects
SUMMAP,Y
Scope:
The resident inspectors conducted a routine inspection in the areas of
operational safety verification; maintenance observation, surveillance
. observation, engineering safety features (ESF) system walkdown, test piping
support and restraint system, startup from refueling, action on previous
inspection findings, and reportable occurrences.
The inspectors conducted
backshift inspections on April 28, 29 and May 6, 11, 1989.
Results:
Within the areas inspected two violations were identified involving failure to
follow a radiation protection procedure and the RWP during the removal of a
contamination boundary (paragraph 3.d.), and for an inadequate procedure which
contributed to a loss of feedwater control and a reactor scram (paragraph 3.e.).
One non-cited violation was identified for failure to take adequate corrective
action to prevent thermal binding of a safety related feedwater isolation valve
(paragraph 3.d.).
These violations do not appear programmatic in nature.
8906280167 890613
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-The plant completed a 43 day refueling outage which was w' ell planned,- scheduled
and managed. However, weaknesses were noted in the control of contractors in the
~ health physics area.
During the power ascension phase the plant _ experienced
several equipment problems that required a reduction in power and two shut-
downs.
During one of the plant shut downs, the' plant scrammed on low water
level. The major contributor to the reactor scram was personnel error.
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
J.G. Cesare, Director, Nuclear Licensing
W.T. Cottle, Vice President of Nuclear Operations
- D.G. Cupstid, Superintendent, Technical Support
- L.F. Daughtery, Compliance Supervisor
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- J.P. Dimmette, Manager, Plant Maintenance
S.M. Feith, Director, Quality Programs
- C.R. Hutchinson, GGNS General Manager
R.H. McAnulty, Electrical Superintendent
A.S. McCurdy, Technical Asst., Plant Operations Manager
- L.B. Moulder, Operations Superintendent
J.H. Mueller, Mechanical Superintendent
J.V. Parrish, Chemistry / Radiation Control Superintendent
J.L. Robertson, Superintendent, Plant Licensing
- S.F. Tanner, Manager, Quality Services
L.G. Temple, I & C Superintendent
F.W. Titus, Director, Nuclear Plant Engineering
- M.J. Wright, Manager, Plant Support
- J.W. Yelverton, Manager, Plant Operations
Other licensee employees contacted included technicians, operators,
security force members, and office personnel.
- Attended exit interview
NRC' Personnel
L. Trocine, Project Engineer
2.
Plant Status
Unit 1 began the inspection period in refueling outage number three and
completed the outage in 43 days.
The unit started up on April 28, 1989,
and synchronized to the grid on April 29, 1989.
During power ascension
the plant experienced several operational problems which included one
power reduction, one reactor scram and two planned unit shutdowns. At the
end of the inspection period the unit was in cold shutdown due to
vibration problems on recirculation pump B.
3.
Operational Safety, (71707)
The inspectors were cognizant of the overall plant status, and of any
significant safety matters related to plant operations.
Daily discussions
were held with plant management and variocs members of the plant operating
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staff.
The inspectors made frequent visits to the centrol room.
' Observations included the verification of instrument readings, setpoints
and rec'ordings, status of operating systems, tags and clearances on
equipment controls and switches, annunciator alarms, adherence to limiting-
conditions for operation, temporary alterations in effect, daily journals
-and data sheet entries, control room manning, anc: access controls. This
inspection activity included numerous informal discussions with operators
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and their supervisors.
On a weekly bases selected engineered safety feature (ESF) :;ystems were
cor> firmed operable.
The confirmation was made by verifying that
accessible valve flow path alignment was correct, power supply breaker and
fuse status was correct, and instrumentation was operational.
The
following systems were verified operable:
Additionally, the inspectors conducted a modified system walkdown on the
emergency electric power system using the Grand Gulf probabilistic Risk
Assessment Based Inspection Plan as a guide.
General plant tours were conducted on a weekly basis. Portions of the
control building, turbine building, auxiliary building and outside areas
were visited.
The observations included safety related tagout verifica-
tions, shift turnovers, sampling programs, housekeeping and general plant
conditions, the status of fire protection equipment, control of activities
in progress, problem identification systems, containment isolation, and
the readiness of the onsite emergency response facilities.
The inspectors observed health physics management involvement and awareness
of significant plant activities, and observed plant radiation controls.
Periodically the inspectors verified the adequacy of physical security
controls.
The inspectors reviewed safety related tacouts, 892561 (SBLC)
and 892585 (ADHR) to ensure that the tagouts were properly prepared, and
performed.
During a routine tour of the 166' elevation of the turbine building on
April 24,1989, the inspectors noticed two contract carpenters removing a
fence on the southeast side of the turbine generator.
This fence
constituted a boundary for a contaminated area.
When informed by the
inspectors, a HP technician stopped work and had the the area surveyed.
The area
was used for contaminated equipment and tools storage.
The
removal of the contaminated area boundary was not coordinated with HP
prior to the work being done.
Neither worker wore PC's as required by
RWP.
Radiological Deficiency Report 89-04-017 was written to document
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this incident.
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Technical Specification (TS) 6.8.1 requires that written procedures be
established, implemented and maintained covering the activities
recommended in Regulatory Guide (R.G) 1.33, Revision 2, February 1978.
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R.G. 1.33 recommends procedures for Control of Radioactivity.
Section
6.1.1 of Radiation Protection Procedure 08-S-01-21, Radiological Practices
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for Controlled Areas,' requires that all- radiological postings', signs and'
barriers will be strictly. complied with and will not be moved or bypassed'
unless.specifically authorized by HP and requires that RWP's be followed.
Contrary to above, contractors removed a ' contaminated area boundary
without receiving HP authorization and.without following the protective-
clothing requirements.of the RWP.
This will be documented as violation
89-14-01.
.The ' inspectors verified that the following ECCS manual injection valves.
were in their locked open position; HPCS, LPCS, LPCI B and LPCI C.
Tne inspectors have noted that senior plant managers make routine tours
to the plant and the control room.
The inspectors reviewed the activities associated with the below listed
events.
a.
On April 17, 1989 at 2:15 p.m..a control room operator found the LPCI A
injection valve, E12-F042A, open.
RHR A system was in operation, in the
shut down cooling (SDC) mode. The.open valve had no adverse effect on
shutdown cooling and the valve was immediately closed.
A review of
surveillance and interviews with technicians and operators'~ failed to
identify'a probable cause. The shift turnover walkdown of the 1H13-P601
panel during the morning confirmed that the valve was closed.
The
licensee suspects the cause of the mispositioned valve to be operator
error.
An operator may have manipulated the wrong handswitch while
throttling valves on. the SDC loop A for temperature control.
The
operations management issued a memorandum to the' shift operators
concerning attention to detail,
b.
On April 20,1989,-with the plant in mode 5, the control room operator
discovered that RHR A pump had tripped while operating. in the shut .
down ' cooling mode.
A review of the event indicated. that the pump
tripped during the reinsta11ation of a DC power fuse to an optical
isolator circuit.
The reinsta11ation of the-fuse caused a voltage
spike, which energized the optical isolator and tripped the RHR pump.
.The. pump trip was reset and restarted at 5:51 p.m.
The reactor core
wm without flow for approximately 20 minutes, there was no core;
temperature increase during this period.
The licensee has in place
procedures to address inadequate decay heat removal and the operators
were aware of the need to maintain a shutdown cooling mode.
c.
On May 3, 1989, when the operator tried to open the FCV A recircula-
tion pump valve (FCV F060A), the position indicator did not respond
properly when the recirculation pumps were in fast speed.
This
problem did not exist when the pumps were in slow speed. On May 4,
1989, power was reduced from approximately 50% to 5% to allow entry
into the drywell for rework on FCV F060A, and the turbine generator
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was taken off line.
MWO 193001 was written for troubleshooting
and monitor the work on the recirculation flow control valve A Rotary
Variable Differential Transformer (RVDT) N026A. The RVDT is used to
provide a feedback signal for determining the position of the FCV.
An inspection indicated that the flexible coupling of the RVDT was
completely compressed which caused binding around the flenible
The yoke assembly and RVDT were removed, new ones were
installed and calibrated.
When the work was completed the plant
proceeded to increase power.
The retest plan was to increase power
enough to shift to fast speed on the recirculation pump and monitor
FCV indications.
While in slow speed the recirculation pump did.not
experience indication problems.
d.
The plant power was increased to approximately 22%, and the turbine
generator was synchronized to the grid.
The A feedwater isolation
valve, (Q1821F065A) would not open.
The motor operator initially
tripped on thermal overload.
Operation personnel entered the steam
tunnel to manually open the valve. The handwheel was turned approxi-
mately 20 turns which was enough to free the stem.
When the valve
was subsequently stroked, with the motor operator, the stem would
rotate to the open position, but flow indication did not exist. The
plant was returned to cold shutdown to disassemble the valve. MNCR
214-89 was initiated for evaluation of Q1821F065A valve for thermal
binding.
The valve was reworked under MWO M93291.
Upon disassembly
of the va've, the stem was found separated from the disc, and the
" ears" at the bottom of the valve stem were found broken. The root
cause tvaluation determined that the component failure was a result
of cracks which originated on the bottom of the valve stem ears.
These cracks resulted from excessive closing force caused by thermal
growth of the valve and stem.
The cracks weakened the ears on the
stem such that the forces used during attempts to manually open the
valve separated the stem from the disc. The valve vendor representa-
tive stated that this type of failure could not have resulted from
over-torquing by the motor operator.
The representative also
stated, that the unique conditions associated with the operation of
this valve creates very high forces due to heating of the valve stem
after the valve has been closed.
During shutdown operation, the RWCU
flow through the A feedwater line causes heating of the valve disc
and stem.
Because the stem is rigidly bound when closed, subsequent
heating of the stem creates very high stresses due to the restrained
thermal expansion.
These stresses are typically much higher than
those capable of being developed by the motor operator.
The valve
stem was replaced and a LLRT and MOVAT were performed. Actions to
prevent recurrence has been outlined in MNCR 214-89, which include
rewriting the operating procedure to preclude the thermal conditions.
On September 12, 1988, a similar problem occurred to the same valve
Q1821F065A.
The valve would not open electrically nor mechanically.
It was believed that the valve stuck in the seat due to thermal
condition.
During attempts to open the valve mechanically, the
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key on tthelinside - gear box of the handwheel shaft sheared.
The
following components were replaced due 'to the shearing of-'the key;
clutch housing assembly, handwheel shaft, hand wheel gear, handwheel
~ key,: motor Edriven 1 gear and declutching spring. .
The licensee
conducted discussions with : the valve manufacturer and ruled out '
They felt the problem was attributed to. the-
actuator torque switch being set'too high.
During RF03 a MWO was-
written to reduce the torqueL switch setting and to M0 VAT the valve.
However, the Eroot cause of the valve' failure on May 5,1989 was
- determined'to be. thermal binding.
Failure to ensure the cause of the condition, thermal binding, is a-
violation of 10 CFR 50, Appendix B, Criterion XVI. The licensee has
.taken action to preclude repetition. The violation is.not being cited-
because the criteria specified .in Section V.A of.the enforcement
policy were satisfied, NCV 89-14-02.
f.
On May 4,1989, at approximately 10:40 a.m. the Division 3 Diesel
Generator auto started when a voltage fluctuation occurred as a
result of adverse weather conditions.' The operators ran Division 3
DG loaded for one hour before returning to offsite power.
e.
On May'5, 1989,.during the power reduction to cold shutdown to allow
investigation' of the feedwater isolation valve problem, the plant
scram on' low reactor vessel water level (level 3).
Feedwater flow
was'through the startup. level control valve N21-F513. The plant was
experiencing difficulty in maintaining reactor vessel water level. in
its normal . band.
The startup level control valve was closed and the
isolation valve N21-F001 was closed in. preparation for directing flow
through the startup level control bypass valve N21-F040.
With both
valves closed, the reactor water level continued to rise._ Operators
attempted to align RWCU blow down flow to the condenser to aid in
establishing level control.
The A reactor feed pump turbine (RFPT)
tripped on level 8 (+53.5").
When the high water level cleared an
operator attempted to reset the A RFPT.
No increase in feed pump
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discharge pressure was observed by the operator. An attempt was made
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to start the. B RFPT, but failed because the steam supply valves
(N11-F012B and N11-F014B) were closed.
When reactor vessel water
level decrease to 20", RCIC was manually initiated and CRD flow
manually increased to 100 gpm. The RCIC flow provided approximately
0.45 mlb/hr feed flow.
The steam flow rate was 1.4 mlb/hr therefore
reactor water level continued to decrease to the scram setpoint of
11.4".
Reactor vessel water level decreased to approximately 2" and
then recovered.
The MSIVs were closed to limit the cool down rate
and RWCU blowdown and CRD flow was used to maintain reactor water
level control. The post trip investigations by the licensee revealed
the following:
The initial increase in the vessel level was caused by either
one or both of the high pressure feedwater heater string outlet
valves (N21F009A/B) being slightly cracked off their seat. This
partially bypassed the startup level cuntrol function.
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During'the feedwater/ level transient the operators were reducing
. reactor power by insertion of control rods. This. power reduction
caustd a feedwater. flow / steam flow mismatch causing a more rapid
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rise in reactor level. Control rod -insertion did not'stop until
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approximately three minutes'after'the.RFPT trip. -This evolution
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contributed to rate of increase and - the erratic behavior of~
vessel level prior to the level 8. trip.
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Once the .RFPT A trip' on leve1L 8 was cleared, the turbine was
. reset, but would not come up in speed. -The turbine may-be reset
once all trips are cleared, but the' governor valve .cannot be
re-opened until the manual speed changer (MSC) is run completely
'to the low speed stop.-'In this' case,.the. turbine was. reset, but'
the MSC had not been run completely to the low speed stop. The.
simulator does .not allow the turbine to be reset until the MSC
has been run completely to the low speed stop.
.The B RFPT could not be brought on line because it was manually.
valved out. The B pump had been run the night before, but it had
been secured per the SOI rather than being restored to a standby
status.
The shift superintendent changed reactor operators in the middle
of the event, which may have contributed to the inability to
reset the RFPT.
Technical Specification 6.8.1.a states written. procedures shall be
-established, implemented and maintained covering applicable' procedures
recommended in Appendix A of Regulatory. Guide 1.33, Revision 2,
February 1978.
Regulatory. Guide 1.33 Revision 2, Appendix A states
that. instructions for energizing, filling, venting, draining, startup,
shutdown, ' and changing ~ modes of operation should be- prepared, as
appropriate, for the.feedwater system.
501 04-1-01-N21-1, Feedwater
System,'provides direction for the operation of.the-feedwater system;
however, the 50I did not adequately address how to reset the RFPT.
The inadequate procedure for resetting the RFPT contributed to. a
reactor scram.
This will be identified as violation 89-14-03 for an
inadequate procedure.
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On May 8,1989 at approximately 9:19 a.m., RWCU system isolation
occurred after operators shifted from "prepump" to "postpump" mode of
RWCU lineup.
The reactor was in hot shutdown with pressure approxi-
mately 27 psig.
The operators attempted to stabilize delta
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flow by securing the RWCU pump and closing the filter demineralized
bypass valve (G33F044).
This should have stopped all RWCU flow;
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however, the inlet flow still indicated 150-200 gpm. When the delta
flow 45 second bypass timer timed out, all Group 8 containment
isolation valves closed.
Alternate leak detection methods such as
room temperature and drain sump levels showed no actual leak had
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The RWCU system was restored to serviceLin'the "prepump"
mode at 9:40 a.m.. in order to reestablish blowdown to the condenser.
A number of. RWCU isolations occurred at the Grand Gulf Nuclear
Station in 1987 and 1988.
Inspector Followup Item 88-19-03.was
identified in September 1988 as a- result of ai RWCU isolation. to
followup- the corrective action associated with the. event
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(LER 88-04-01)'.
LER 88-04-01 supplemental .' corrective ' action stated
that SERI.would install la' separate keylock bypass switch to bypass-
the n delta flow isolation signal during anticipated RWCU system
operating transients to avoid spurious isolations.
Installation of
the bypass' switch was scheduled during the third refueling outage;
however, additional problems were identified with the proposed design
and installation' was ' put ~ on hold.
The licensee is continuing to
. pursue:a means to preclude unplanned RWCU isolation.
h..
On May -11, -1989 at 1:30 p.m., the B recirculation pump experienced
high vibrations.
The licensee continued to monitor the pump over a-
three hour period and noted that the vibration amplitude increased
from 17 mils to 31 ~ mils at the pump coupling and from 5 mils to 11
mils at the motor. A normal vibration amplitude is less than 5 mils.
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Reactor, power was reduced and the recirculation pump shifted to slow
speed.
The shaft. vibration decreased to 11 mils at the pump coupling
and 5 mils at the motor. On May 13,1989, at 7:55 p.m. the plant was
shutdown to investigate the recirculation pump vibration problem.
The planned outage is for 24 days if both pumps are opened to inspect
and repair.
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Maintenance.0bservation(62703)
During the report period, the inspectors observed portions of the
maintenance activities listed below.
The observations included a review
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~of the MW0s and. other related documents .for adequacy;- adherence to
procedure, proper tagouts, technical specifications,. quality controls, and.
radiological controls; observation of work and/or retesting; and specified
retest requirements.
MWO
. DESCRIPTION
E84706
Capacity discharge test on B0P battery
EL2693
Lube RPS motor generator set
EL2694
MEGGER RPS motor generator set
F90376
193001
' Troubleshoot FCV F060A/RVDT unit
'I93371-
Troubleshoot RFP B speed control
M85443
Disassemble valve P71F300 and actuator
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M92499
Adjust the RCIC overspeed trip mechanism
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M93291
Investigate feedwater isolation valve F065A
193585
Temperature indication and switch for SBLC
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No violations or deviations were identified.
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SurveillanceOb'servation'(61726)
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The inspectors observed the performance'of' portions of.the surveillance
-listed below.
The observation included a review of the procedure for
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technical adequacy, . conformance to ' technical specifications and LCOs, .
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_ verification of test instrument calibration, observation of all or part of
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.the actual surveillance, removal and return to service of the system or-
component, . and review; of - the data for _ acceptability based 'upon the
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acceptance criteria.
06-0P-1E12-Q-0006.. Revision 20, LPCI/RHR Subsystem B MOV Functional Test
06-0P-1E12-R-0022, Revision 21, RHR Containment Spray Initiation. Logic
Functional Test
06-RE-SC11-V-0402, _ Revision 26, Control Rod Scram Testing
06-IC-1C51-W-0006, Revision 25, APRM Calibration
06-IC-1E30-M-0003, Revision 22, Suppression Pool Level Wide Range
Functional Test for Channel B.
No violations or deviations were identified.
6.-
En','neered Safety Features System Walkdown (71710)
._The inspectors. conducted a complete walkdown on the accessible portions of
.the ADS.
The walkdown consisted of the following:
confirm that the
system lineup procedure matches the ' plant drawing and the as-built
. configuration;
identify equipment condition,and items that might degrade-
plant- performance; verify that valves in the flow path are in correct
positions.' as required by procedure and that local and remote position
indications are. functional; veri.fy the proper breaker position at local
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electrical boards- and indications on control boards; and verify that
instrument calibration dates are current.
The inspectors walked down the system using system operating instruction
'04-1-01-B21-1, Revision 28. Nuclear Boiler System and P&ID M-1077C,
Revision 28.
The operating instruction electrical lineup checksheet,
attachment III, component description differed from the actual equipment
label'for the following breakers:
. Breaker No.
Component Description
Breaker Label
72-11A23
125 Vdc ADS Logic
PGCC PNL
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72-11B34
125 Vdc ADS Logic
PGCC PNL
Div 2
1H13 -P631
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52-1P66102
ADS STATUS LIGHT
Control Room PGCC Panel
Power, Div. 1
1H13-P601 Automatic
Depressurization Sys+em.
52-1P56101
ADS STATUS LIGHT
Control Room PGCC
Power, Div. 1
Panel 1H13-P601 Automatic
Depressurization System.
The ADS annunciator panels were reviewed using the system operating
instruction, Attachment IV, System Alarm Index.
The following alarm was
not on the alarm index.
Alarm Name
Panel
GRID
A5
OPEN/DISCH LINE
PRESS HI
The following deficiencies were identified during the system walkdown:
Relief Valves for AIR Accumulators A-003D and A-004D were not labeled.
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The material condition of the system appeared good.
All valves were
aligned in accordance with the 501.
The inspectors conducted a walkdown of the accessible portions of the
standby liquid control system by using system operating instruction
04-1-01-C41-1, Revision 24, Standby Liquid Control System, and P&ID
M-1082, Revision 21, Standby liquid Control System Unit 1.
The component description on the operating instruction electrical lineup
check sheet, Attachment III of the system operating instruction, differed
from the actual equipment label for numerous breakers as follows:
Breaker No.
Component Description
Actual Breaker Label
52-1P56107
120 Vac to 1H13-P601
Control Room PGCC Panel
1H13-P601 Standby Liquid Control
System.
52-1P56120
SLC Tank Level Alarms
Control Room PGCC Panel
1H13-P632 Leak Detection System.
52-1P66105
120 Vac to 1H13-P601
Control Room PGCC Panel
1H13-P601 Standby Liquid Control
System,
52-163135
SLC Storage Tank Outlet 52-163135 Storage Tank Outlet
Valve (Q1C41F001B-B).
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, 52-1P63121
SLC Pump.B Space Heater- MTR Space Heater for Standby.
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Liquid Control System Q1C41C001B-B.
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52-1P52121
SLC Pump A Space Heater Motor Space Heater for Standby
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Liquid Control System Q1C410001A-A.
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52-152115
SLC Storage Tank Outlet 52-152115 Storage Tank Outlet.
Valve Q1C41F001A-A.
52-111316-
SLC' Heat' Tracing
Heat Tracing FDR for Panel
-52-125134
F001A Heat Tracing
Heat Tracing FDR for Panel
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-The following discrepancies were identified during the Standby Liquid
Control System walkdown.
Labels were missing from F003A, XJ G514 A, and XJ G513 B.
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PP N400 B was not capped. A loose cap was noted.on the floor in the
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The licensee has implemented a labelling program that will address the-
above discrepancies.
No violations or deviations were identified.
7.
Testing Piping'Supporo and Restraint System (70370)
. The inspectors reviewed the . licensee's ' RF03-- snubber test program for
compliance with.'TS 3/4.7.4,. snubbers.
The licensee functionally tested-
-37 mechanical, eight hydraulic. and five snubbers that failed previous
test.
Additionally, 'the ' licensee conducted. visual inspections on
634-mechanical, 76-hydraulic and three high temperature snubbers.
All
snubbers successfully passed the TS acceptance requirements. However, two
,
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of the 37 mechanical snubbers failed the ~11censee's administrative
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requirements and were replaced.
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No violations or deviations'were identified.
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8.
Startup From Refueling (72700)
On April 21
1989, Unit 1 entered mode 4 at approximately 4:22 p.m. when
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the reactor vessel head was tensioned.
The inspectors verified that the
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precritical testing was conducted 'in accordance with approved test
procedures, that the test results had been reviewed and were acceptable.
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The control rod scram testing was witnessed by the inspector.
All 193
control rods were tested and successfully met the TS acceptance criteria.
The licensee used the Individual Rod Scram Test-Transient Recorder Auto
Analysis Method. All rods fell within the fast rod criteria.
On April 28, 1989, the inspector witnessed startup for cycle 4.
The
controlling procedure for startup, 03-1-01-1, provided directions for
taking the reactor from a cold shutdown, depressurized condition to a
fully pressurized condition with the main generator synchronized to the
grid carrying a minimum load.
Specified rod withdrawal ' sequence was
performed in accordance with S0I 04-1-01-C11-2.
For each control rod
withdrawn to the full out position, a rod coupling check was performed and
independently verified.
Criticality for cycle 4 was achieved at 9:51 a.m. on group 2, position 18.
The average reactor period was 127.8 seconds with a recirculation loop
temperatures of 149 F for both A and B loop.
Immediately after the
reactor went critical, the SDM was determined to be 1.42% delta J/K. SDM
was performed using procedure 06-RE-SB13-V-0410. Criticality was achieved
in a controlled manner.
.9.
Reportable Occurrences (90712 & 92700)
The below listed event reports were reviewed to determine if the informa-
tion provided met the NRC reporting requirements.
The determination
included adequacy of event description and corrective action taken or
planned, existence of potential generic problems and the relative safety
significance of each event.
Additional inplant reviews and discussions
with plant personnel as appropriate were conducted for the reports
indicated by an asterisk. The event reports were reviewed using the
- 91 dance of the general policy and procedure for NRC enforcement actions,
regarding licensee identified violations.
a.
On April 18, 1989, the licensee reported to the NRC the failure of
RHR B heat exchanger outlet valve, E12-F003B. The valve failure was
documented in NRC inspection report 89-12.
To determine if the
failure was a common mode failure, the licensee opened, inspected and
replaced the E12-F003A valve disk and stem. The inspection determined
that the RHR A valve wcs in good condition and that the B valve
failure was not ger3ric.
b.
Da April 20, 1989, the licensee reported that a three hour rated fire
barrier, an eight inch concrete block wall between the control
buildings lower cable room and HVAC chase room, was degraded. During
a fire barrier walkdown the licensee noted a notch in the block wall,
not a through penetration, that reduces the wall thickness but does
constitute a deviation to the fire tested configuration.
The
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licensee found that the notch was documented during the construction
phase, prior to 1981, for structural integrity but was not evaluated
for fire barrier rating. The licensee is conducting the evaluation.
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.During L the development of. system design crite' ria document 'for the
c.
L suppression pool. makeup- (SPMU) . system, the licensee identified a
discrepancy. regarding the SPMU system initiation setpoint.
The-
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. suppression pool water level-low trip (16 Lfeet 4 inches): and
allowable value (15 > feet 6.5 inches) were non-conservative with
respect to . the GE analytical limit .ofa16 feet 10 inches.. An
. evaluation of the 15 feet-6.5 inches level ' conclude. that there was
sufficient- suppression pool level to provide a minimum drywell vent
- submergence of two feet 'above the top row of vents which was the
original acceptance criteria.
The ' licensee stated the following -
corrective actions have been initiated.
Submitted a TS change to address this discrepancy and administrative 1y
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established 16' feet 10 inches.as the low level setpoint.
Reduced reliance on outside contractors for engineering support.
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Nuclear plant engineering now has control and custody of the design
--
calculation and has the technical depth to perform these type
calculations without outside assistance.
.In late 1984, the licensee implemented a certification program
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requiring additional second reviews and line management sign off of
-licensing _submittals'. The licensee stated that this process alone
would have caught the SPMU system setpoint error.
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, Developed a' computerized setpoint control program that will' redevelop .
- safety related TS setpoint calculations. The TS setpoint calculation
redevelopment program is scheduled to be completed by the' spring of
1990.
Will issue .a quality engineering training bulletin .on the.
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lessons learned.
The ' inspectors reviewed the completed surveillance
06-IC-1E30-M-0001,
Suppression Pool Level Wide Range Channel Functional Test, that readjusted
the instrument trip'setpoints to the new setpoint level.
d.
On April 29, 1989 at approximately 5:00 p.m., during the performance
of surveillance procedure 06-0P-1B21-R-0002, ADS /SRV Valve Operability
Test, a RCIC Division 1 isolation occurred as a result of a steam
line differential pressure high signal.
The plant was in "Startup"
at approximately 9% power with reactor pressure at 945 psig bypassing
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steam to the condenser..
The isolation was cleared at 5:10 p.m. and-
RCIC was ' estored to service.
During the surveillance test, SRV
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B21-F051C did not opened on Division 2 handswitch but did open from
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the Division 1 side controls.
A MWO was written to replace the
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Division 2 transmitter.
After transmitter replacement the F051C SRV
was retested satisfactorily.
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e.
On May 6,1989 at approximately 2:00 a.m., 'a' portion of the' Alert
Notification System sirens in Claiborne . County inadvertently
activated.
The siren was deactivated and -investigated.
This
incident is documented in incident report 89-5-4. .
The public
information officer was notified. so that a news release can- be-
<
generated.
f..
On May 8, 1989 at approximately 6:43 p.m., during attempts to relatch.
- the main turbine stop valve, the stop valves -tripped closed and
caused a Division 1 RCIC Hi Delta Flow isolation. The reactor was in
mode 2 at a reactor power of 3%. The isolation was cleared immediately
and a MWO was written to investigate.
No violations or deviations were identified.
'10.
Action on Previous Inspection Findings (92701,92702)
(Closed) .88-01-01, Violation. Failure to follow procedure to properly
store N, bottles inside containment.
The auxiliary building round sheet
(which 1ncludes the containment) were changed to ' include a generic
walkdown to check specifically for proper storage of any compressed gas
bottles.
A memo was issued to all plant personnel to reemphasize' the
importance of proper compressed gas bottle storage inside the plant. This
item is closed.
(Closed) 88-17-01, Inspector Followup Item.
Investigation of B
recirculation-loop perturbations MWO 183422 was written to investigate why
the B FCV closed down partially causing power to decrease from 3833 mwt
to 3706'mwt.
I&C replaced DSR card B33-K6498-1.
No further problems have
occurred. This item is closed.
(Closed) 88-'26-01, Violation.
Failure to follow procedure for completing-
transactions have been transmitted to DOE via Form 741 and that necessary
corrections have been made to previously transmitted forms.
PAP 01-S-06-15
- has been revised to include detailed instructions for completing DOE /NRC
Form 741.
Future SNR reports will be sent out by the General Manager.
.(Closed) 89-12-01,; Inspector Followup Item.
Improper labelling of MSIV
solenoid ammeters.
Correct labels have been installed per MNCR 0140-89
disposition. This item is closed.
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11. ExitInterview(30703)
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The inspection scope and findings were summarized on May 19, 1989, with
those persons indicated in paragraph 1 above.
The licensee did not
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identify as proprietary any of the materials provided to or reviewed by
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the inspectors during this inspection. The licensee had no comment on the
following inspection findings:
Item Number
Description and Reference
89-14-01
Failure to follow procedure for removing a
radiological boundary.
89-14-02
Failure to take adequate corrective action
for thermal binding valve F065A.
89-14-03
Inadequate procedure for resetting RFPT
control.
12. Acronyms and Initialisms
ADHRS-
Alternate Decay Heat Removal System
ADS -
Automatic Depressurization System
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APRM -
Average Power Range Monitor
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B0C -
Beginning of Cycle
Balance of Plant
80P
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BUV -
Bus Under Voltage
Control Rod Drive
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Design Change Package
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Diesel Generator
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ECCS -
ESF -
Engineering Safety Feature
Flow Control Valve
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Health Physics
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HPCS -
HPV -
Hydraulic Power Unit
HVAC -
Heating Ventilation & Air Conditioning
Instrumentation and Control
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Inspector Followup Item
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IFI
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Limiting Condition for Operation
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LC0
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Licensee Event Report
LER
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LLRT -
Local Leak Rate Test
LPCI -
Low Pressure Core Injection
LPCS -
Low Pressure Core Spray
MESI -
Maintenance Engineering Special Instruction
MNCR -
Material Nonconformance Report
Motor Operated Valve
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M0 VATS-
Motor Operated Valve Analyst Test
MP&L -
Mississippi Power & Light
MS
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Mechanical Standard
MSIV -
MWO
Maintenance Work Order
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NPE -
Nuclear Plant Engineering
Nuclear Regulatory Commission
NRC
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Pressure Differential Switch
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P&ID -
Piping and Instrument Diagram
Pacific Scientific Arrestor
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PSW -
Plant Service Water.
QDR -
Quality Deficiency Report
RCIC -
Reactor Core Isolation Cooling
RFPT -
Reactor Feed Pump Turbine
Regulatory Guide
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Revolution Per Minute
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RVDT -
Rotary Variable Differential Transformer
RWCU -
RWP --
Radiation Work Permit
SBLC -
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SERI -
System Energy Resource Incorporation
System Operating Instruction
501
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SPMU -
Suppression Pool Makeup
Standby Service Water
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Temporary Change Notice
TCN
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Technical Specification
TS
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