ML20057A430
| ML20057A430 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 08/27/1993 |
| From: | Christnot E, Holbrook B, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20057A427 | List: |
| References | |
| 50-321-93-13, 50-366-93-13, NUDOCS 9309140198 | |
| Download: ML20057A430 (14) | |
See also: IR 05000321/1993013
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UNITED STATES .
/pu mecg%, NUCLEAR REGULATORY COMMISSION
g* -' s REGeoN n
- .i E 101 MARIETTA STREET, N.W., SUITE 2900
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ra ATle NTA. GEORGIA 30323-0199
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Report Nos.: 50-321/93-13 and 50-366/93-13 l
(icensee: Georgia Power Company .j
P.O. Box 1295 .
Birmingham, AL 35201 l
Docket Nos.: 50-321 and 50-366 License Nos.: DPR-57 and NPF-5 !
Facility Name: Hatch Nuclear Plant
Inspection Conducted: July 04 - August 07, 1993
Inspectors: 8df, / P/77/f3
n leon ~ard rVert, Jr., Sr. Resident Inspector Date Signed
h
tdward F('Chrt,stnot, Resident Inspector
Eh?/93
D' ate Signed
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gobipHolbr~ook,Resid4tInspector
W3?/93
D~ ate Signed ;
Approved by: 7 'm <1 /- u 4C-
Pierce H. Skinner, Chief Project Section 38
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Date Signed
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Division of Reactor Projects !
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SUMMARY ;
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Scope: This routine resident inspection involved inspection on-site in
the areas of operations, surveillance testing, maintenance
activities, seismic monitoring equipment, and review of open ,
items.
Results: One violation was identified. ;
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The violation addressed inadequate procedural controls during -
maintenance activities on two Unit 2 containment isolation valves.
As a result of this inadequate control the valves were not i
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operable under certain plant conditions. (Violation
50-366/93-13-01: Inadequate Procedural Controls During
Maintenance Activity, paragraph 4.b.)
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The inspectors continued their close observations of control room
activities. Continued improvements were noted in control room
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professionalism, communications and attention tJ detail. Overall,
control room activities and demeanor appear to be on a positive
trend. Also noted is a concern in that an increase in errors in
the area of maintenance activities has occurred in the past :
several months. .
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9309140198 930830 :
PDR ADOCK 05000321
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REPORT DETAILS
1. Persons Contacted
Licensee Employees
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- G. Barker, Manager Maintenance { Acting)
- J. Betsill, Unit 2 Operations Superintendent
C. Coggin, Training and Emergency Preparedness Manager
- S. Curtis, Operations Support Superintendent
D. Davis, Plant Administration Manager
P. Fornel, Maintenance Manager
- 0. Fraser, Safety Audit and Engineering Review Supervisor
- G. Goode, Engineering Support Manager
M. Googe, Outages and Planning Manager
- J. Hammonds, Regulatory Compliance Supervisor
- W. Kirkley, Health Physics and Chemistry Manager
J. Lewis, Operations Manager
- R. Mcginn, Nuclear Security
- C. Moore, Assistant General Manager - Plant Operations
- J. Payne, Senior Engineer
D. Read, Assistant General Manager - Plant Support
P. Roberts, Outages and Planning Supervisor
K. Robuck, Manager, Modifications and Maintenance Support
- L. Lawrence, Nuclear Specialist
- H. Sumner, General Manager - Nuclear Plant
J. Inompson, Nuclear Security Manager
- S. Tipps, Nuclear Safety and Compliance Manager
P. Wells, Unit 1 Operations Superintendent
- A. Wheeler, Plant Engineering Supervisor
- J. Wilkes, Outage and Planning
Other licensee employees contacted included technicians, operators,
mechanics, security force members and staff personnel.
NRC Resident Inspectors
L. Wert
- E. Christnot
- B. Holbrook
- Attended exit interview
Acronyms and abbreviations used throughout this report are listed in the
last paragraph.
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2. Plant Operations (71707) (92701) (93702) !
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a. Operations Status and Observations
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Unit 1 operated at 100 percent RTP throughout the reporting ,
period.
Unit 2 operated at 85 percent RTP throughout the reporting period. ,
Several rods remain fully inserted to suppress neutron flux in the 4
area of a suspected fuel leak. !
Small oscillations were noted periodically in the Unit 2 "B" loop ;
recirculation drive flow indication. Electrical output of the
generator was affected by about 2 to 3 MWe during the flow :
changes. The licensee contacted GE and was informed that these
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small changes in recirculation drive flow were not unusual. On
July 28, 1988, GE issued SIL 467: Recirculation System Bi-Stable
Flow In Jet Pump BWRs, which discussed this issue. The SIL
indicated that GE had performed plant-specific safety analyses and
concluded that the occurrence is not a safety concern in the
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plants that were evaluated. The licensee performed the actions
discussed in the GE SIL 467, during investigation of the
oscillations. These actions included placing the recirculation .
pump speed controllers in manual, monitoring the scoop tube !
positioner for movement, varying the speed and difference in speed (
of the recirculation pumps and electronic monitoring of various j
parameters. After performing the recommendations listed in the :
SIL, the licensee will continue to monitor power fluctuations. i
The inspectors concluded the licensees response to the flow ,
fluctuations was appropriate. Control room operators and the STAS !
4 closely monitored plant parameters and were sensitive to the flow !
fluctuations.
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Activities within the control room were monitored routinely. .
Inspections were conducted on day and on night shifts, during i
weekdays and on weekends. Observations included control room I
manning, access control, operator professionalism and :
attentiveness, and adherence to procedures. Instrument readings,
recorder traces, annunciator alarms, operability of nuclear '
instrumentation and reactor protection system channels, i
availability of power sources, and operability of the Safety
Parameter Display System were monitored. Control Room ,
observations also included ECCS system lineups, containment i
integrity, reactor mode switch position, scram discharge volume j
valve positions, and rod movement controls. :
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Over several recent inspection reports the inspectors had (
expressed a concern involving declining operator performance. '
During one recent inspection reporting period, the inspectors had
conducted increased inspection activities to monitor operator
performance and held discussions with operations management
concerning the declining performance trend observed. Plant
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management discussed a number of corrective actions that were to
be initiated. During this inspection report the inspectors
conducted additional observations of operator activities in the
CR. These expanded observations were conducted during 4 different !
shift periods. Normal shift as well as backshift periods were ,
attended. These observations were to assess operator performance !
trends, awareness, attention to detail, professionalism, l
effectiveness of the corrective measures, and overall methodology
of conducting business. The inspectors observed normal daily i
surveillances, additional TS surveillance testing and routine
operator activities. The inspectors observed an increase in .
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operator awareness, timely response to alarms, and an increase in
the monitoring of control board indications as well as back panel
parameters. The inspectors also observed that the face to face 1
communications in the CR as well as telephonic communications have
improved. The inspectors concluded that a positive trend is now ,
being observed. However, due to the short duration of this trend, t
the inspectors will continue to closely monitor and evaluate '
operator performance and corrective action implementation.
Plant tours were taken throughout the reporting period on a li
routine basis. The areas toured included the following:
Reactor Building I
Diesel Generator Building l
Fire Pump Building
Central Alarm Station '
Station Yard Zone )
Turbine Building i
Intake Building )
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During the plant tours, ongoing activities, housekeeping,
security, equipment status, and radiation control practices were
observed. The inspectors noted that housekeeping improvement
efforts (painting) in the intake structure. A lack of
housekeeping activities was reported for this area in several
previous inspection reports. No significant deficiencies were
noted.
b. Chemical Sampling Procedure
The inspector reviewed the licensee's activities involving the
Main Stack Post-Accident Monitoring System during corrective
maintenance. Both the Unit I and 2 TS state that with the number j
of operable channels less than the required operable channels
initiate the pre-planned alternate method of monitoring the
appropriate parameter within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The inspector discussed
this action statement with operations personnel and was informed
that chemistry personnel are responsible to initiate the pre-
planned method. The operators informed chemistry of the LCO.
Since the normal range monitors were in operation, the pre-planned
sampling method procedure was already in effect. The inspectors
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reviewed procedure 64CH-ADM-001-OS: Chemistry Program, which
contained the pre-planned sampling method and noted that
attachment 24 gave directions for initiating the pre-planned
method. However, the procedure was not clear to the inspectors as
to when the pre-planned method would be initiated and when the
pre-planned monitoring data sheet would be comnleted. The
procedure seemed to indicate that the data sheet should be
completed when operations informed the chemistry department of the
TS LCO. This was discussed with the chemistry supervisor and
other chemistry personnel to gain their understanding and
interpretation of the procedure. The chemistry supervisor stated
the procedure was somewhat confusing and could be more clear. A
procedure change request was submitted. It was concluded that the
pre-planned alternate method is the normal monitoring system (A
and B channels) provided the normal systems are operating
properly. The procedure for the pre-planned alternate method
would be fully implemented only if the normal monitoring systems
are 00S; and the procedure data sheet will be completed following
grab sample analysis.
The inspectors concluded that TS requirements were met.
3. Surveillance Testing (61726)
a. Surveillance Observations
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.
The following surveillances were reviewed and witnessed in whole
or in part:
57CP-C51-012-05 LPRM Detector I/V Curve (Unit 1)
34SV-E41-002-IS HPCI Operability Test
345V-E41-002-25 HPCI Operability Test
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345V-R43-006-15 DG IC Semi-Annual fest
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b. River Conditions (61726)
The inspectors conducted a review of the required river flow,
water elevation, temperature restrictions, and ultimate heat sink
requirements of the Altamaha river for Plant Hatch. The
inspectors reviewed the Unit 2 FSAR, section 2.4, which deals with
low flow in the Altamaha River and the ultimate heat sink
requirements. The heat sink requirements reviewed included: TS
3/4.7, which deals with river water level requirements for the PSW
pumps NPSH requirements; Unit 1 TS, section 3.5, which deals with
minimum river flow; procedure OIRC-SUV-002-OS, River Stage;
drawings K-29-25 and K-29-27; Plant Hatch Intake Structure'Outside
Structure Siltation Study; and P&ID M-58459. This review was
conducted to verify the river water flow, temperature, river
bottom conditions, and the required NPSH to safety related pumps
were adequate for the present river and plant conditions.
Due to the existing draught situation, the Altamaha river
conditions are being closely monitored by the licensee and the
inspectors. During the past 2 or 3 weeks the river level has been
slowly decreasing. Temperature has been slowly increas %q. TS
require an orderly shutdown if river level decreases t~ level
equivalent to 60.7 ft MSL at the intake structure / pump . This
shutdown is to ensure the operability of safety related Nuipment
(PSW and RHRSW) to provide cooling during long-term safe shutdown
conditions. The inspectors noted that the FSAR, section 2.4,
indicated that low flow conditions of the river could be sustained
(at least 23 days) with relative little change in f' _w or level
due to ground water and aquifer flow inleakage. The inspectors
verified that the river level was being properly recorded and the
water level elevation was greater than 60.7 ft MSL. Additionally,
the iaspectors, by the use of a P&ID, checked the river level in
relation to a determined point of reference on the PSW pumps
suction piping. Additionally, they determined that the pump's
submergence was in excess of 8 feet. The minimum required
submergence for the required NPSH and vortex elimination is 4
feet.
The inspectors reviewed a May 1992, report for river bottom
conditions and a December 1792, report for the river discharge
rating curve. The data for these reports was collected and
submitted by a contract company. The licensee reviewed and
approved the reports and ensured that the TS surveillance
requirements were met. The inspectors verified that the river
bottom conditions indicated that the river water level elevation
was well within the TS limits and was more than adequate to
support normal a:; well as long-term safe shutdown operations. The
1992 bottom condition report indicated that some bottom silt had
been washed away and river bottom conditions had actually improved
from the previous year.
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The inspectors reviewed the river stage discharge rating curve,
which shows flow (cubic feet /second) in relation to elevation (ft-
MSL). The present curve was compared to the FSAR required j
discharge rate curve. The inspectors determined that the current !
river level and flow conditions are well within the required TS ;
and FSAR values.
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The inspectors concluded that the present river stage discharge l
rating curve will support current as well as long-term safe i
shutdown operations. The licensee exhibited a high sensitivity to
the adverse consequences of a low river water level and a high .
river water temperature. The inspectors concluded that the
required TS surveillances were being completed. The licensee's '
actions, which included close monitoring of the river level, flow
rate, and river water temperature; and making preliminary
preparations for the installation of a temporary river weir, were
appropriate.
No violations or deviations were identified.
4. Maintenance Activities (62703) f
a. Maintenance Observations .
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, :
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procedures, and work requests were examined to verify proper
authorization to begin work, provisions for fire hazards,
cleanliness, exposure control, proper return of equipment to
service, and that limiting conditions for operation were met.
The following maintenance activities were reviewed and witnessed
in whole or in part: >
MWO 2-92-5774 Maintenance Activities for Valve 2B31-F019 l
MWO 2-92-5199 Maintenance Activities for Valve 2831-F020 ,
MWO 2-93-2067 Loop 2B Recirculation Flow Trouble
Shooting
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MWO l-93-3333 6 Month Rebuild of IZ41-F0288, Actuator
for Control Room Damper B010B
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MWO 1-93-3729 Replacement of Lube Oil Copper tubing on j
On August 3,1993, a PE0 noticed a lube oil leak from a small hole
in a copper tube on the 1A EDG during a surveillance test. The
licensee determined that the EDG was operable at this time. The
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inspector observed the repairs on this EDG and walked down the
other EDGs to determine if a similar problem existed. Unit 2 EDGs
copper tubing runs were intact and supported by clamps with rubber
inserts. The IB and 1C EDG copper tubing runs were not clamped in
place. Some of the rubber inserts appeared to be missing and long
sections of tubing were not supported. The inspector discussed
this observation with licensee personnel who were in the process
of reviewing this item. The inspectors will review the licensee's
actions during the next reporting period.
The inspectors noted that several examples of deficiencies in
maintenance activities have been identified recently. Violation
50-321,366/93-08-03, which was associated with not adequately
testing the MSIV limit switches, indicated that the MWO work
packages did not specifically identify which procedures should be
performed to complete post maintenance testing. In IR 50-
321,366/92-29, the inspectors identified concerns associated with
weaknesses in the maintenarce activities of the EDG. In this -
instance two speed sensors had been incorrectly connected during -
reassembly.
IR 50-321,366/93-06 identified maintenance activities following
actions to replace EDG bearing metal temperature sensors
(Violation 50-321/93-06-02). In this instance maintenance
personnel rotated a metallic gasket that partially blocked the oil
supply to the bearing housing, and one bearing metal temperature
sensor was broken during maintenance activities. Later, following
additional maintenance activities, the bearing metal temperature
sensor was identified as being broken.
The inspectors are concerned with this increase in significant ,
deficiencies associated with maintenance activities and will
closely monitor the licensee's activities in this area to
determine if corrective actions are taken by licensee management.
b. Failure of Containment Isolation Valves -
During maintenance activities to flash a Unit 2 reactor water
sample line (from RR loop B to sample stations), the licensee
determined that one of the isolation valves was leaking by when
the valve was closed. The sample line contains an inboard
isolation valve 2B31-F019 and outboard isolation valve 2831-F020.
The licensee identified tH "B31-F019 was leaking by. The i
inspectors reviewed the FL , section 6.2, and determined te of -
these valves are air operated to open, spring operated to clo
normally open, and required to close upon receiving a Group I
containment isolation signal. The licensee contacted the valve
vendor and was informed that the valves may only close against a ?
maximum pressure of 600 psig. 2P31-F019 was declared inoperable
in accordance with TS 3.6.3. Li;snsee management indicated there i
was a concern with the valves meeting 10 CFR 50 GDC 55
requirements for containment isolation valves. The valves were ,
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closed and 2B31-F019 valve was mechanically gagged. Manually l
operated valves were also shut to further isolate the line. There '
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were no problems or leakage observed with the Unit I valves.
However, since the Unit I and Unit 2 valves are of the same type, :
the licensee declared the Unit I valves inoperable. The Unit I
valves were closed and the outboard valve was mechanically gagged.
The licensee is using alternate sample points. )
A review of activities associated with these valves identified
that in October 1992, loc 31 hak rate testing had been completed
on both Unit 2 valves. The 2B33-F019 valve was found to have 40
ACCM leakage and was left with 0 leakage, the 2831-F020 valve was
found to have 453 ACCM leakage an.1 was left with 23 ACCM leakage.
In April 1993, an LLRT was performed on the Unit I valves, with no ,
leakage detected on either valve. i
Maintenance records indicated that extensive work had been
performed on the Unit 2 valves during the fall outage in 1992 in
order to correct the "as found" leakage rates. Plant management !
stated that they had conducted a preliminary review of the work ,
history and determined that those maintenance activities were a
contributing factor in the current valve performance. Contract
maintenance personnel had replaced the valve internals cnd plant
maintenance personnel had completed the remainder of the
maintenance activities. Apparently, the preload on the spring
pack was adjusted so the valves would pass the LLRT but the valves
were not adjusted after the test to close against a required
design pressure of 1155 psig.
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The inspectors reviewed the MWO work packages associated with the I
maintenance activities on both the 2B31-F019 and 2831-F020 valves ;
for Unit 2. The inspectors also reviewed procedures 52CM-MME-011-
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OS, Gate and Globe Valve Repair and 51GM-MNT-002-02, Maintenance :
Housekeeping and Tool Control, which governed the maintenance of ,
the two valves. It was noted that several different work groups
were involvea in the activities. The procedures did not contain
specific instructions regarding adjustment of the actuator to
close against design differential pressure.
Following the inspectors review of the MWO work packages and '
procedures associated with the maintenance activities of the '
Unit 2 valves, the inspectors concluded that there were inadequate
procedural controls for the maintenance activities. Procedure i
52CM-MME-Oll-05: Gate and Globe Valve Repair, was developed as a
generic procedure (for gate and globe valves not presently covered
by existing procedures) and was not written in such a manner to .
provide specific directions for the valve maintenance. A note l
following step 7.0 of procedure 52CM-MME-Oll-OS states that '
technical and vendor's manuals, blueprints, drawings, etc., will
be used in conjunction with this procedure, as specifications and :
acceptance criteria vary per valve. Steps 7.4.2 and 7.5.2 state
to remove operator as necessary and steps 7.8.7 states if
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required, reassemble and install actuator. Additionally, step ,
7.9.13 states to install actuator (if applicable). There were no
specific written instructions or guidance controlling the
maintenance activities for the valve actuator following
maintenance. As a result, both of these valves were not capable of !
shutting under all postulated plant conditions from October 1992
until July 21, 1993.
The licensee's 10 CFR 50 GDC 55 concern, involving the containment
isolation valves, resulted in the development of a safety
assessment. The inspector reviewed the safety assessment and had
no concerns with the licensee's cenclusions. The inspectors will
continue to monitor the licensee's actions irivolving these valves. "
The procedures used to conduct maintenance for two Unit 2
containment isolation valves B31-F019 and B31-F020 did not provide ;
sufficient guidance to ensure that the valves and actuators were '
assembled and adjusted such that their d3 sign criteria was met. <
This is identified as Violation 50-366/93-13-01: Inadequate
Procedural Control During Maintenance Activity.
One violation was identified.
5. Seismic Monitoring Instrumentation (71707) ,
The inspector reviewed and observed the licensee's activities involved !
with seismic monitoring instrumentation. The system consists of one i
TS-2 Seismic Trigger, six Triaxial Time-History Accelergraphs, ten ;
Triaxial Peak Recording Accelerometers, two Triaxial TS-3 Seismic !
switches and one Triaxial Response Spectrum Recorder. The instruments
are located at various locations throughout the plant such as the EDG
building, intake structure, switchyard parking lot and reactor 1
buildings. Fourteen of the 20 seismic instruments are TS required
instruments and are contained in the Unit 2 TS only. The system ,
description is located in the Unit 2 FSAR. The TS requirevents were
implemented by five procedures. The procedures provide instructions on
the channel checks, functional tests and calibration of the various l
types of instruments. j
The inspector reviewed surveillance procedures as follows:
575V-L51-002-IS: Peak Shock Annunciator & Recorder Functional
Test
575V-L51-003-OS: Seismic Instrumentation Functional Test and
Calibration
575V-L51-004-OS: Calibration of Teledyne Geotech PRA-103 Peak
Recording Accelerometers 3
575V-L51-001-2S: Triaxial Seismic Switch FT&C
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57SV-L51-005-2S: Calibration of ENGDAHL PAR.400 Peak
Acceleration Recorder
SMA-3 CAL. Rev. H. Hatch: Kinemetrics Channel Calibration !
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The inspector also reviewed the results of the channel calibration .
performed on Triaxial Time-History Accelergraphs, the TS-2 seismic !
trigger, the control room panel IHil-P701, and the two TS-3 strong i
Motion Triaxial Seismic Switches. The calibration was performed during l
the October 6-9, 1992, time frame by the vender, Kinemetrics systems. A
discrepancy was noted during the review involving the recording of data
in the channel calibration procedure. The channel calibration
procedure, SHA-3 CAL. Rev. H. Hatch, section 8.7.29 through 8.7.31, was i
not completed. A technician's comments for these sections indicated l
that plant maintenance should replace accelerometer 112-3 and then l
complete the appropriate sections of the procedure. The inspector
reviewed MWO 2-92-2103 and found that the accelerometer was replaced and
the appropriate data was recorded on the MWO work package, but was never
transferred to the calibration procedure.
A walk down of selected irstruments indicated that hardware appeared in
acceptable condition, although some discrepancies were identified as ,
noted below. One of the inspectors had previously identified some :
frayed wires on instrument L51-N003 (Triaxial Time? History Accelergraph, :
a non-TS instrument, and located on the 185 foot elevation of Unit 1
reactor building). The licensee initiated a MWO to correct this
deficiency. The inspector noted several minor deficiencies.
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very few of the instruments were labeled and some had grey -
adhesive tape labels.
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The protective covers were not entirely intact. One instrument's !
end cover was off and lying on the floor. Many of the cover '
fasteners were missing, some were not tightened, and some showed
deterioration.
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Drawing H-16319 indicated that ten locally mounted peak
accelergraphs were installed at various locations in the plant.
The Unit TS refer to these instruments as accelerometers.
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The sensor numbers on CR panel lHil-P701, such as SN 112-4, Fire
Field Accelerometer Unit I switch, do not agree with the
designations used by the I&C group. This instrument, SN 112-4,
was designated as SN 112-2 by the I&C records. ,
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I&C records and TS indicated that instruments L51-N001 and L51-
N005 were located in the switchyard when drawings H-16319 shows
their location as being in the parking lot next to the switchyard.
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Drawing H-16319, panel 1Hil-P701, and I&C records should be
updated to indicated proper sensor numbers, instrument type and
. instrument location. ,
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The inspector did not identified any significant items that affected
operability of the system.
6. Inspection of Open Items (92700) (92701)
The following items were reviewed using licensee reports, inspections,
record reviews, and discussions with licensee personnel, as appropriate:
a. (Closed) LER 50-366/92-07: RWCU Leak Results in an ESF Actuation.
On June 12, 1992, following the performance of a surveillance
procedure, an isolation signal was received on RWCU heat exchanger
room high ambient temperature. Valve 2G31-fdO4 closed as ,
designed. The licensee traced the source of the high temperature '
to a failed gasket in the shell-to-tubing assembly flanged
connection of 2G.51-B001B, RWCU Regenerative Heat Exchanger. The
licensee implemented DCR 92-112, which seal welded the flanged
connection and injected a leak repair sealant into the interface
of the flange bolt holes and fastener studs. No additional leaks
have been identified to date. At the time of this incident the
inspectors closely reviewed and observed the licensee's
activities. The results of the observations and reviews were
documented in IR 50-321,366/92-15. Based on the implementation of
DCR 92-112 and previous reviews and observations, this LER is
closed.
b. (Closed) LER 50-366/92-08: Component Failure Results in Group 5
PCIS Actuation. This failure, which occurred on June 20, 1992,
resulted in a false high process fluid temperature downstream of
the RWCU non-regenerative heat exchanger. The false high
temperature caused a PCIS actuation and automatic closure of -
isolation valve 2G31-F004 as designed. The licensee replaced the
failed components, calibrated the controller and returned the RWCU
to service on June 22, 1992. Based on the component replacement
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and calibration, this LER is closed.
c. (Closed) LER 50-321/92-14: Manufacturer Error Results in a
Reactor Scram on Turbine Valve Closure. The inspectors reviewed
and observed the licensee's activities at the time of the event t
and documented these in IR 50-321,366/92-12. The valve closure <
was caused by inadequate EHC Fluid to the #2 TSV. This was due to
filters being used in the EHC system that were not compatible with
EHC fluid. The licensee replaced the filters, drained the fluid
from the EHC system and filled the system with new fluid. Based >
on the licansee's activities and the observations and reviews
documented in IR 50-321,366/92-12, this LER is closed. j
d. (Closed) LER 50-321/92-21: Organic Intrusion Results in Main
Steam Line High Radiation Reactor Scram and Group 1 Isolation.
The inspector observed, monitored and reviewed the licensee's !
activities at the time of event and documented these in IR 50-
321,366/92-21. The licensee determined that the organic material
was from the RFP Lube Oil system. It was also determined that the
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oil had accumulated over time in the condensate
filter /demineralizers, and that when they were placed in service,
the oil came out of the filter /demineralizers (the licensee had
recently instituted a policy of valving in the
filter /demineralizers quickly). The lube oil went through the
reactor, broke down in the high temperature / radiation environment,
and caused an increase in activation product carry over to the
MSLs. As a result, operations returned to a policy of returning
the condensate filter /demineralizer to service slowly, over a
period of 15 to 20 minutes. Based on the observations, reviews
and monitoring documented in IR 50-321,366/92-21, this LER is
closed.
7 Cxit Interview
The inspection scope and findings were summarized on August 9,1993
with those persons indicated in paragraph I above. The inspectors
described the areas inspected and discussed in detail the inspection
findings. The issue involving chemistry sampling procedures (pr.ragraph
2.b) had been characterized as an NCV at the time of the exit. -
Dissenting comments were presented by licensee management on this issue.
After additional review, the inspectors concluded that a violation had
not occurred. This conclusion was communicated to NSAC management on
August 13, 1993. The licensee did not identify as proprietary any of
the material provided to or reviewed by the inspectors during this
inspection.
Item Number Status Description and Reference ,
50-366/93-13-01 Open VIO- Inadequate Procedural Controls ,
During Maintenance Activities,
paragraph 4b.
8. Acronyms and Abbreviations
AC -
Alternating Current
ACCM - Average Cubic Centimeters Per Minute
AGM-P0- Assistant General Manager - Plant Operations
AGM-PS- Assistant General Manager - Plant Support
APRM - Average Power Range Monitor i
APLHGR- Average Planar Linear Heat Generation Rate
ATTS - Analog Transmitter Trip System
BWR -
Boiling Water Reactor *
BWROG- Boiling Water Reactors Owners Group
CFM - Cubic feet Per Minute :
CFR - Code of Federal Regulations '
COLR - Core Operating Limits Report
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CR -
Control Room
CRD - Control Rod Drive
CST - Condensate Storage Tank i
DBA - Design Basis Earthquake :
DC -
Deficiency Card
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DCR -
Design Change Request
DPH - Disintegration Per Minute i
DW - Drywell i
ECCS - Emergency Core Cooling System
EDG - Emergency Diesel Generator i
EHC - Electro Hydraulic Control System
EMA - Emergency Management Agency
ERT - Event Review Team
ESF - Engineered Safety Feature
EST -
Eastern Standard Time . ;
F - Fahrenheit '
FSAR - Final Safety Analysis Report
F/T - Functional Test :
FT&C - Fur.ctional Test and Calibration
GDC - Generic Design Criteria
GE - General Electric Company
GEMA - Georgia Emerger.cy Management Agency
GL - Generic Letter
HP - Health Physics
HPCI - High Pressure Coolant Injection System
IB -
Inboard
I&C - Instrumentation and Controls
IFI -
Inspector Followup Item
IR -
Inspection Report
LC0 - Limiting Condition for Operation
LER - Licensca Event Report
LHGR - Linear Heat Generation Rate
LLRT - Local Leak Rate Test
LOCA - Loss of Coolant Accident
LOSP - Loss of Offsite Power
LPRM - Local Power Range Monitor
MCC - Motor Control Center *
MSIV - Main Steam Isolation Valve
MSL - Main Steam Line '
MSL - Mean Sea level
HWe - Megawatts Electric l
MWO - Maintenance Work Order
NCV -
Non-cited Violation
NPSH - Net Positive Suction Head ,
NRC - Nuclear Regulatory Commission
NSAC - Nuclear Safety and Compliance
NOVE - Notice of Unusual Event
OB - Oatboard l
OBE - Operating Basis Earthquake '
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00S - Out of Service '
PCIS - Primary Containment Isolation System
PE0 - Plant Equipment Operator !
P&lD - Piping and Instrumentation Drawing
PM - Preventive Maintenance
PRB - Plant Review Beard
PSW - Plant Service Water System .
RB - Reactor Building
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RCIC - Reactor Core Isolation Cooling System
R/F - Refueling Floor
RFP - Reactor Feed Pump ,
RG -
Regulatory Guide l
RH - Relative Humidity
RHR -
RHRSW- Residual Heat Removal Service Water System !
RPS -
RPV - Reactor Pressure Vessel i
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RR - Reactor Recirculation
RTP - Rated Thermal Power i
RWCU - Reactor Water Cleanup '
RWL - Reactor Water Level :
RX - Reactor .
SAER - Safety Audit and Engineering Review ,
SBGT - Standby Gas Treatment 3
SFP - Spent Fuel Pool
SFRC - Scram Frequency Reduction Committee ,
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SIL -
Service Information Letter
SOS -
Superintendent of Shift (Operations) l
SPDS - Safety Parameter Display System -
1
SR0 - Senior Reactor Operator
SS - Shift Supervisor
STA - Shift Technical Advisor
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TC - Temporary Change -
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TS -
Technical Specifications
TSV - Turbine Stop Valve
URI - Unresolved Item ,
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