ML20247E744
| ML20247E744 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 03/16/1989 |
| From: | Cantrell F, Christensen H, Mathis J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20247E718 | List: |
| References | |
| 50-416-89-04, 50-416-89-4, NUDOCS 8904030228 | |
| Download: ML20247E744 (15) | |
See also: IR 05000416/1989004
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
REGION 11
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101 MARIETTA ST., N.W.
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ATLANTA, GEORGIA 30323
Report No.:
50 .6/89-04
Licensee: _ System Energy Resources, Inc.
Jackson, MS 39205
Docket No.:
50-416
License No.: NPF-29
Facility Name:
Grand Gulf Nuclear Station
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' Inspection Conducted: January 14 - February 17, 1989
_3 !/ 6 f(Y
Inspect rs:
/
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H. 0. Ch'ristensen, Senior Resident Inspector
Date Signed
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3/a/n
J. L. Math'e, Resident Inspector
Date Signed
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Approved by:
244-- '.
3 [4 /85
/-F. S. /Cantrell Section Chief,
Date Signed
Division of Reactor Projects
SUMMARY
Scope: The resident inspectors conducted a routine inspection in the following
areas:
Operational safety verification; maintenance observation; surveillance
observation; surveillance procedures and records; engineering safety features
(ESF) system walkdown; preparation for refueling; action on previous inspection
findings; document control program; and evaluation of licensee self-assessment
capability.
The inspectors conducted backshift inspections on January 12, 26
and February 2, 12, 1989.
Results: Within the areas inspected, one violation and one unresolved item was
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identified:
Failure to perform a safety evaluation for the storage of EC0DEX
resin inside containment, paragraph 9.
The walkdown of the RCIC system
indicated a number of labelling errors, particularly in the electrical panel
area, paragraph 7.
The surveillance procedures and records program appears
adequate with no major deficiencies.
8904030228 890316
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REPORT DETAILS
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1.
Persons Contacted
Licensee Employees
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- M. Bakarick, Superintendent, System Support
J. G. Cesare, Director, Nuclear Licensing
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W. T. Cottle, Vice President of Nuclear Operations
- D. G. Cupstid, Superintendent, Technical Support
L. F. Daughtery, Compliance Supervisor
- J. P. Dimmette, Manager, Plant Maintenance
S. M. Feith, Director, Quality Programs
- C, R. Hutchinson, General Manager GGNS
R. H. McAnulty, Electrical Superintendent
- R. V. Moomaw, Technical Assistance, Plant Maintenace Manager
A. S. McCurdy, Technical Asst., Plant Operations Manager
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L. B. Moulder, Operations Superintendent
J. H. Mueller, Mechanical Superintendent
- J. C. Roberts, Manager, Performance and System Engineering
J. V. Parrish, Chemistry / Radiation Control Superintendent
- J. L. Robertson, Superintendent, Plant Licensing
R. F. Rogers, Manager, Special Projects
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
2.
Plant Status
Unit 1 began and ended the inspection period operating at approximately
100% power.
The licensee had several surveillance electronic time
response test failures and functional test failures. However, corrections
were made without interruption of plant's operation.
The next refueling
outage is scheduled for March 17, 1989.
3.
Operational Safety Verification (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 various members of the plant operating
staff.
The inspectors made frequent visits to the control room.
Observations included the verification of instrument readings, setpoints
and recordings, status of operating systems, tags and clearances on
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equipment controls and switches, annunciator alarms, adherence to limiting
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conditions for operation, temporary alterations in effect, daily journals
and data sheet entries, control room manning, and access controls.
This
inspection activity included numerous informal discussions with operators
and their supervisors.
On a weekly basis selected engineered safety feature (ESF) systems were
confirmed 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:
Containment spray, and standby gas
treatment system (Train B).
Additionally, the inspectors conducted a
modified system walkdown on the low pressure core spray system, high
pressure core spray system, emergency electric power system, suppression
pool makeup system, and the automatic depressurization system.
The
walkdowns used the Grand Gulf Probabilistic Risk Assessment Based System
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
verifications, shift turnovers, sampling programs, housekeeping and
general plant conditions, the status of fire protection equipment, control
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of activities in progress, problem identification systems, and containment
isolation.
Additionally, the licensee's onsite emergency response
facilities were toured to determine facility readiness.
The inspectors observed health physics management involvement and
awareness of significant plant activities, and observed plant radiation
controls. The inspectors verified licensee compliance with physical
security manning and access control requirements.
Periodically the
inspectors verified the adequacy of physical security detection and
assessment aids.
During the week of January 31, 1989, a Regional security inspector
reviewed (see Inspection report 416/89-03) the licensee's progress of
enclosing Unit 2 within the protected area.
A number of items required
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completion before activating the new boundary area.
The resident
inspectors verified that these items were completed before the new
protected area boundary was activated on February 9, 1989.
On February 10, 1989, the licensee identified that a SERI employee
unintentionally took a handgun into the protected area.
Upgraded X-ray
machines have been put in service since this incident occurred.
This
incident was called in to NRC in a one-hour report and documented in
Incident Report 89-2-3.
Further investigation by the licensee is on-going
and will be followed by Regional based security inspectors.
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The inspectors reviewed safety related tagout 18443, to prevent operation
of RHR valve E12-F052 A and B.
The review ensured that the tagout was
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properly prepared and performed, and the tagged components were in the
required position.
The inspectors verified that the following containment isolation valves
were in there correct lineup; E61-F002A (combustible gas control) and
C41-F006 (standby liquid control).
No violations or deviations were identified.
4.
MaintenanceObservation(62703)
During the report period, the inspectors observed portions of the
maintenance activities listed below.
The observations included a review
of the maintenance work orders (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
M86133
Perform TBCW C Pump Overhaul per Procedure.
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ME0802
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ME0800
Inspect and Lubricate Throttle and Linkage
(RCIC)
ME0796
Lubricate Pump Coupling (RCIC)
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ME0804
Clean and Replace Inlet Air Filter
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ME0803
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ME0797
Check RCIC Oil for Moisture
ME1436
Replace RCIC Filters
ME0795
RCIC Bearing Oil Change
On January 31, 1989 the inspectors witnessed portions of MW0 ME0795, which
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consisted of a periodic oil change of the bearing sump for the RCIC pump.
The procedure, 07-S-14-87, required that one quart of solvent be used to
flush the bearing housing and specified that one quart of oil be used to
fill the bearing housing; however, only one pint of solvent and oil were
used.
The licensee identified this discrepancy with the procedure and
wrote a QDR.
The licensee contacted the vendor and determined that
flushing the bearing housing with a solvent is not required, and confirmed
that one quart of oil would overfill the bearing housing.
The licensee
committed to revise the procedure to reflect the vendor recommendations.
This will be identified as inspector follow-up item 89-04-01.
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No violations or deviations were identified.
5.
Surveillance Observation (61726)
The inspectors observed the performance of portions of the surveillance
listed below.
The observation included a review of the procedure for
technical adequacy; conformance to technical specifications and limiting
conditions for operations (LCOs); verification of test instrument
calibration; observation of all or part of the actual surveillance;
removal from service and return to service of the system or components;
and review of the data for acceptability based upon the acceptance
criteria.
06-EL-1E31-M-0001
Revision 24, RCIC Main Steam Tunnel Isolation Delay
Timer Channel B.
Revision 25, RCIC System Quarterly Pump Operability
Verification.
06-EL-1821-M-0001
Revision 27, ADS Timer Functional lest and
Calibration Channels B and F.
06-IC-1C11-R-0003
Revision 23, Scram Hydraulic Control Unit Calibration.
06-10-1E31-R-0025
Revision 22, Main Steam Line B High Flow (PCIS)
Electronics Time Response Test, Channel D.
17-S-02-203
Revision 0, TIP System Calibration
On January 13, 1989 during the performance of surveillance procedure
06-RE-1C51-0-0001, Revision 27, LPRM Calibration, the traveling in-core
probe (TIP) C output saturated high in channel 4.
A maintenance work
order was written for trouble shooting, and the cable was determined to be
bad.
Special instructions were written for the removal and replacement of
the TIP detector. A special ALARA meeting was held prior to replacing the
detector to coordinate the job and to adhere to ALARA principle. Once the
detector and cable were replaced, applicable steps of procedure
17-S-02-203, Tip System Calibration, were performed to check out the
system.
The post maintenance insulation resistance (IR) was lower by a
factor of two than the GE recommended acceptance criteria (greater than
10E8 ohms).
An MWO was written to investigate this lower IR value. The
retest performed on February 8,
1989 was satisfactory and determined
satisfactory.
No violations or deviations were identified.
6.
Surveillance Procedures and Records
(61700)
The inspectors verified that 35 selected TS and ISI surveillance test were
covered by properly approved procedures and that these procedures specified
prerequisites and preparations, acceptance criteria, and instructions to
restore the system to operation following testing.
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Technical Specification 4.6.4.2 requires that each automatic isolation
valve shown in Table 3.6.4-1 shall be demonstrated operable during cold
shutdown refueling at least once per 18 months by verifying that on an
isolation test signal each automatic isolation valve moves to its
isolation position.
Technical Support Procedure 09-S-05-7, Revision 16,
GGNS Technical Specification / Surveillance Program Master Cross-Index, list
all procedures that meet each required TS.
A review of the five
procedures; 06-0P-1B21-R-0006, 06-0P-1P75-R-0003, 06-0P-1P75-R-0004,
06-0P-1P81-R-0001, and 06-0P-1821-V-0001; that addressed TS 4.6.4.2,
indicated that two valves, E12-F028A and B, RHR heat exchanger to
containment spray sparger inlet valves, were not included in the five
referenced procedure.
The licensee determined that the requirements for
TS 4.6.4.2 was met by Surveillance Procedure 06-0P-1E12-R-0022, RHR
Containment Spray Initiation Logic System Functional Test.
The licensee
agreed to issue a procedure change to include the surveillance in the
" master cross-index"
and to reflect the TS requirement in
The inspectors questioned whether the intent of TS 4.6.4.2 was being met
for the main steam line isolation valves.
Surveillance procedure
06-0P-1821-V-0001, MSIV Operability Test, strokes the valves closed by
using each valve individual manual handswitch while the plant is in
operational condition 2 above 600 psig.
The licensee stated that they
believed the intent of the surveillance requirement was being met by the
above procedure.
In discussion with NRR representatives, use of the
manual handswitch was determine acceptable because the manual switch
operates the same relays that the isolation signal operates.
No other
deficiencies were identified.
Twenty-one completed surveillance tests were reviewed to determine that
the tests were in conformance with TS, ISI program, and procedural
requirements; tests had been reviewed as required by administrative
procedure 01-5-06-12, Revision 15, Grand Gulf Nuclear Station Surveillance
Program; tests had been performed within the time frequencies specified by
the TS or ISI program; appropriate action had been taken for any item
failing acceptance criteria; and test were performed by qualified
individuals.
A review of the Battery 1A3 Performance Discharge Test, 06-EL-1L21-0-0001,
conducted during the second refueling outage indicated that the
surveillance was performed correctly, but the data sheet had been filled
out incorrectly.
The electrical superintendent stated that training will
be conducted in the proper way to conduct and document the battery
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performance discharge test.
Overall, the surveillance program appear adequate and meets the
requirement of TS.
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No violations or deviations were identified.
7.
Engineered Safety Features System Walkdown (71710)
The inspectors conducted a complete walkdown on the accessible portions of
the reactor core isolation cooling (RCIC) system to verify 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; verify the proper breaker position at
local electrical boards and indications on control boards; verify that
instrument calibration dates are current.
The residents walked down the system using system operating instruction
04-1-01-E51-1, Revision 30, Reactor Core Isolation Cooling and Piping, and
instrument diagram (P&ID) M-1083A, Revision 24 and M-1083B, Revision 26.
The operating instruction electrical lineup checksheet, Attachment III,
component description differed from the actual equipment label as follows:
Breaker No.
Component Description
Breaker Label
52-153129
STM SPLY OTBD ISOL
52-1P53108
MOTOR AND COMPRESSOR HEATERS
SPARE
52-1P53118
VALVE MOTOR HEATER
MOV HTR VERTICAL
SEC I
52-1P53116
VALVE MOTOR HEATER
M0V HTR VERTICAL
SEC J
52-1P53112
VALVE MOTOR HEATER
MOV AND STARTER
SPACE HTR
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52-1P51104
VALVE MOTOR HEATER
MOV AND STARTER
SPACE HTR
(
52-1P56120
DIV 1 RCIC CONTROL POWER
CR PGCC PANEL
1H13-P632 LK DET
SYS
52-1P56112
DIV 1 TRIP UNIT ISOLATOR
CR PGCC PANEL
POWER SUPPLY
52-1P56117
RCIC 1 TEST CKTS AND
CR PGCC PANEL
STATUS LIGHTS
F066 LIMIT SWITCH
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52-IP66108
DIV 2 TRIP UNIT ISOLATOR
CR PGCC PANEL
ISOLATOR POWER SUPPLY
IH13-P618 RHR
52-1P66112
DIV 2 TEST CKTS
CR PGCC PANEL
AND STATUS LIGHTS
52-IP66111
DIV 2 RCIC CONTPOL POWER
CR PGCC 1H13-P642
LK
DET SYS
72-11B13
AIR TO A-F004 TURB EXHAUST DRAIN
72-11813E51
AIR TO A0-F025 TURB STEM LINE
PGCC 1H13-P600
DRAIN A0-F004 LIMIT SWITCH
A0-F025 LIMIT SWITCH
72-11BSo
DIV 2 TRIP UNIT ISOLATCR POWER
72-11835E21
PGCC 1H13-P618
72-11B39
DIV 2 RCIC RELAY LOG
PGCC IH13-P618
72-11B14
DIV.2 TRIP UNIT
72-11B14312
ISOLATOR POWER
PGCC PNI 1H13-P618
72-11A39
TURB GOV VALVE LIMIT SWITCH
72-11A39E51
TURB TRIP AND THROTTLE LIMIT
PGCC PNL 1H13-P601
SWITCH A0-F026 LIMIT SWITCH
A0-F005 LIMIT SWITCH
A0-F0054 LIMIT SWITCH
AIP 10 A0-F026 STM LINE DRAIN
AIR TO A0-F006 TURB EXHAUST DRAIN
72-11A24
RCIC TURB SPEED CONTROL POWER
71-11A24E51
DIV 1 RELAY LOGIC POWER SUPPLY
PGCC PNL 1H13-P621
RCIC TURB REMOTE TRIP POWER SUPPLY
72-11A32
RCIC TURB FLOW CONTROLLER POWER
PGCC PNL 1H13-P632
72-11A18
DIV 1 TRIP UNIT ISOLA 5OR POWER
72-11A18E21
SUPPLY
PGCC PNL 1H13-P629
72-11A3B
DIV 1 TRIP UNIT ISOLATOR POWER
72-11A38E12
SUPPLY
PGCC 1H13-P629
72-11A16
72-11A16E51
RCIC VALVE F045
72-11A21
RCIC TURB TRIP AND THROT-VLV
RCIC TURB TRIP
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52-1P31210
120 Vac INST BUS
CR PGCC PNL
LK DCT SYS
52-1P11305
LEAK DETECTION S0Vs
POWER SUPPLY
B0P PROCESS
INSTRUMENT CAB
52-1P56115
120 Vac FEEDER TO K500 AND K501A
LOCAL CONTROL
POWER SUPPLIES
PANEL REMOTE SD
SYSTEM
The RCIC annunciator panels were reviewed using the System Operating
Instruction, Attachment IV, System Alarm Index. The following differences
were noted:
Alarm Name
Panel
Grid
Actual Grid
Rr.C DIV 1
A2
Al
STM SPLY PRESS L0
RCIC VAC BRKR
E3
04
ISOL VLV F078
NOT FULLY OPEN
The following Alarm was not on the alarm index:
Alarm Name
Panel
Grid
RCIC GL SEAL
El
AIR PRESS HI
The folic'.-ing Alarm label differed from tLe SOI.
Panel
Name In 501
Actual Name
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RCIC TURB OIL PRESS L0
RCIC TURB
BEARING OIL PRESS
L0
The inspectors were informed that the licensee is implementing a new
labelling program, procedures are being developed, and that they are
walking down the safety related systems to determine labelling
deficiencies.
The licensee stated that full implementation of this
program will take several years, including the B0P portion of the plant.
The inspector stated that this was not an acceptable schedule for
safety-related systems. This is identified as an inspector follow-up item
(416/89-04-02).
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The following deficiencies were identified during the system walkdown:
-Instrument taps, PP-N400, N401, N402, N403 are missing caps.
-Valve F022, RCIC inboard test return to CST, local indicator indicated
10 percent open, a normally closed valve.
-Valve F045, RCIC steam supply to RCIC turbine local indicator 1-dicated
30% open, a normally closed valve.
-Valve F046, RCIC water to turbine lube oil cooler, actuator has a small
oil leak.
-RCIC governor valve has water leaking from the valve spring area.
-The lube oil cooler area is dirty.
-The area under the minimum flow line next to the RCIC room wall is
dirty.
-Valves F251 and F252, minimum flow line to suppression pool drain
valves, are locked closed valves, the 50I has them as closed valves.
The correction of the above deficiencies will be an inspector followup
item. (416/89-04-03).
The inspectors reviewed M0 VATS test data and limit switch setting for five
RCIC valves.
The review ensured that the M0V limit switch settings were
set to the requirements of IE Bulletin 85-03, Motor Operated Valve Common
Mode Failures During Plant Transients Due to Improper Switch Settings.
During the MOVATS testing of E51-F045, RCIC steam supply to RCIC turbine
valve, the as-found closing torque switch trip thrust was 98,675
lbs-force. The licensee adjusted the torque switch setting to reduce the
torque below the valve's limiting thrust of 58,000 lbs-force and wrote a
material non-conformance report (0520-87).
The MNCR required the key
brushing set screws to be replaced and to inspect the yoke arms for
cracking. The actions of the MNCR were completed under MWO-M77365.
The inspectors reviewed GE Service Information Letters (SIL), IE Notices
and Bulletins applicability to the RCIC system.
The following were
reviewed:
IEN 82-16
HPCI/RCIC High Steam Flow.
IEN 82-26
RCIC and HPCI Turbine Exhaust Check Valve Failure.
IEN 88-69
AFW (RCIC) Turbine Overspeed Trip (Polyurethane
Tappet).
IEN 88-08
Reduced Reliability of Steam-Driven Auxiliary
Feedwater Pumps Caused by Instability of Woodward
PG-PL Type Governors.
Surveillance Testing Recommendations for HPCI and
RCIC Systems.
RCIC Turbiae Journal Bearing Locating Pin.
HPCI and RCIC Turbine Control System Calibration.
HPCI and RCIC Turbines Drive Gear Assembly.
The licensee has reviewed the above IENs and SIls for applicability to the
RCIC System.
GE SIL 319 recommended that the drive gear assemblies
(gears, shaft bushing and thrust washer) on the RCIC turbines be inspected
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for evidence of wear and overheating. MWO M64978 was initiated to perform
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the inspection per procedure 07-S-14-301.
The work was completed
satisfactory on September 8, 1986. Additionally, GE recommended this
inspection be performed every 6 months or after 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> accumulated run
time which ever comes first.
SERI records show that this inspection has
been performed only once since the SIL came out.
Telephone conversation
with GE by SERI System Engineer revealed that a revision to SIL 319 is
being issued soon to recommend a 18-month inspection of the turbine drive
gear assembly.
The licensee has initiated a preventive maintenance task
card for inspecting the turbine drive gear assembly every 18 months per
procedure 07-S-14-301.
This item will be tracked as inspector followup
item 89-04-03.
The RCIC system appears to be in good condition and the plant has taken
appropriate actions to maintain the system in a ready state.
No violations or deviations were identified.
8.
Preparation for Refueling
(60705)
On January 20, 1989, Grand Gulf received a load of new fuel for the third
refueling outage.
The first shipment of Advance Nuclear Fuel was in
crates containing two fuel bundle per crate.
Fuel receipt was performed
in accordance with procedure 17-S-02-110, Revision 0, New Fuel Processing.
The inspectors reviewed the shipping documentation and inspected tne
shipment to ensure that it complied with the shipping papers (Packing
List Bill of Lading, etc.).
The fuel crate accelerometers were verified
to be untripped prior to inspecting the fuel assembly by licensee.
The
fuel assemblies were inspected in accordance with procedure 17-S-02-110.
After inspection, the fuel was channeled prior to storage in the spent
fuel pool.
No violation or deviations were identified.
9.
Action on Previous Inspection Findings
(92701,92702)
(0 pen) Inspector Followup Item 416/86-36-01, Establish criteria for
determining when to clean ESF switchgear room coolers piping.
Criteria
were placed in procedures 04-1-03-T46-1 and 04-1-03-T46-2 for the A and B
ESF Switchgear Room Coolers Flow Test respectively.
If any flows are less
than the criteria listed, the cooler is to be declared inoperable and TSPS
101 followed. The criteria for cleaning the room cooler was satisfactory.
However, steps 7.4.1.C of the revised procedures instructed the operator
to follow TSPS 101 for any coolers found inoperable.
NRC letter dated
January 25, 1989 to SERI discussed a problem area of GGNS Technical
Specification 3/4.8.3.
The ESF room coolers specified in position
statement 101 serves the Divisional I and II electrical switchgear and
electrical penetration rooms.
When the ESF room coolers are declared
inoperable, the MCC and LCC would be declared inoperable, and the action
statements associated with this equipment must be followed.
The action
statements for TS 3/4.8.3 specifies an allowable outage time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
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rather than the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> listed in the TSPS (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> was used based on
the action statement for standby service water). The TSPS and the present
TS for standby service water reflects a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> outage time which is in
conflict with the Technical Guidance provided in the letter dated
January 25, 1989. This item will remain open.
(Closed) Unresolved Item 416/88-25-01, Review the safety evaluation for
storing Ecodex resin in containment.
An evaluation of Ecodex storage in
containment and the auxiliary building on January 16, 1989 showed that
Ecodex storage in containment presented a potential Seismic II/I hazard to
small diameter lube oil tubing required for continued operation of the
drywell purge compressor.
FSAR section 6.2.5.2.1, states that the drywell purge system is provided
to purge the hydrogen produced within the drywell into the larger
containment volume in order to maintain the drywell hydrogen concentration
below the flammability limit.
The Ecodex seismic hazard could have
affected one train of a two train drywell purge system.
Each train is a
100% capacity system. The Ecodex was removed from containment when it was
initially brought to their attention and a temporary change notice was
issued to system operating instruction 04-1-01-G33-1, Revision 33, Reactor
Water Cleanup, to remove all Ecodex boxes and bags from containment on
completion of resin changes.
The licensee was informed that failure to
perform an initial
safety evaluation on the storage of Ecodex in
containment is a violation of the requirements of 10 CFR 50.59
(416/89-04-04).
Unresolved item 88-25-01 is administratively closed and
any additional corrective action will be tracked under the violation.
10.
Document Control Program (39702)
The resident inspectors reviewed the licensee program for safety-related
drawira control.
Administrai.ive procedure 01-5-05-6, Revision 23,
Receipt, Distribution and Maintenance of Plant Drawings, provides guidance
for the receipt, distribution, maintenance, and use of plant drawing. The
review process consisted of review of critical drawings, review of drawing
change process, and as-built verification.
a.
Review of Critical Drawings
Drawings that the licensee considers to be critical for use by
operations or TSC personnel in plant operations or emergencies are
I
identified in attachment 1 of procedure 01-S-05-6.
The manager of
plant operations, in conjunction with the director of nuclear plant
engineering, identify the as-built drawings to be maintained on the
control room and TSC stick files. Presently there are approximately
50 sets of system drawings the licensee considers operations
critical.
The safeguards drawings identified as operation critical
are maintained separately in the document control safeguards file.
I
The inspectors reviewed several of the critical drawing in the TSC
'
and control room for legibility and confirmed the revision of the
drawings at each location was the current approved revision,
i
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Document control marks drawings in red (on aperture cards and on
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hardcopy drawing) to indicate any changes that are due incorporation
(CNS, DCP drawings, DRNS, Engineering Markup Attachments, Temp Alts)
3
and places the changes behind the appropriate drawings on the stick
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file and in the aperture card file.
Overall, the licensee program
q
for maintaining legible drawing and latest revisions to operation
critical drawings is satisfactory.
The only illegible drawing
reviewed was in the control room.
Drawing E1163 sheet 34 (revision
7) consisted of a tabulation for GE HFA Relays.
Area D-1 of this
drawing was not legible, however the TSC drawing was legible.
The
only other discrepancy identified in this area was on drawing E1163
sheet 51 (revision 8). -An outstanding change was stamped on the
,
drawing which referenced DCP 83-3025. The change to the drawing
I
appeared to have already been incorporated in the drawing and the
'
effected drawing (E1163) should not nave been stamped.
The inspectors interviewed an operation staff member to demonstrate
the process of determining whether a drawing represents the most
current plant configuration.
The operator was knowledgeable of the
drawing program. These discrepancies appeared to be isolated areas,
b.
Review of the Drawing Change Process
The licensee's drawing change process was outlined in Administrative
,
Procedure 01-5-05-6. Document control verifies semi-annually that the
plant staff, NPE, and PM&C drawing are current.
In the future, the
control room and TSC will receive priority over other area for
updating the controlled drawing.
If a controlled drawing is revised
or changed, document control notifies the holders within two working
days after acceptance of the revision / change document by sending them
a change notification sheet. Prior to using a drawing, the drawing
holders are responsible for verifying that all drawings are current
with the changes reflected and the approved "as-built" configuration.
Except for the control room, document control will not update or
revise controlled drawings unless they are returned for validation.
NPE Administrative Procedure 315, Revision 7, Updating /As-Built
GGNS Design Document, states, the cognizant principle engineer should
attempt to ensure that closecuts are done in a timely manner to
support a 14 day incorporation target to reflect "as-built"
conditions following changes to existing plant systems, structures,
components, or records.
All outstanding DRNs must be incorporated
into a drawing anytime any of the following conditions exists:
(1) Three DRNs have been issued against the drawing.
(2)
Ninety calendar days have elapsed since the issue of the first
DRN against the current revision of an " operation critical" e
" operation sensitive" drawing.
(3) The drawing is revised and issued for any reason.
4
No violation or deviation were identified.
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11. Evaluation of Licensee Self-Assessment Capability (40500)
The inspectors evaluated the effectiveness of the licensee's
>
self-assessment programs.
The inspection focused on determining whether
the licensee's program contribute to the prevention of problems by
monitorir:g and evaluating plant performance, communicating assessments and
findings, and following up on corrective action recommendations.
On January 17,1989, the inspectors attended a quarterly Safety Review
Committee (SRC) meeting.
The SRC is the TS required offsite review
committee. The committee had the required member composition and quorums.
The SRC conducted the following activities:
Reviewed and approved past
SRC meeting minutes; summarized plant operating experience; reviewed
reports of significant operating abnormalities; reviewed SRC open action
>
items; reviewed investigations of violations of codes, regulations,
orders, TS, license requirements or internal procedures having nuclear
safety significance; reviewed audits and corrective actions; reviewed PSRC
meeting minutes and 10 CFR 50.59 safety evaluations; and assigned new SRC
action items.
The dicussion of SRC topics appeared to be candid and open.
The use of
consultants, as required by TS, appears to be benificial to the SRC in
dicussing topic from various points of view.
The SRC appears to be
fulfilling its intended function.
No violatiens or deviations were identified.
12. Exit Interview (30703)
The inspection scope and findings were summarized on February 17, 1989
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. The licensee had no comment on the
following inspection findings:
Item Number
Description and Reference
!
89-04-01 (IFI)
Review the revised RCIC periodic oil
change procedure 07-5-14-87
89-04-02 (IFI)
Revise in procedures or on equipment
labels to assure that the same
nomenclature is used on both.
l
89-04-03(IFI)
Review the licensee corrective action
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on RCIC labeling and system walkdown
I
deficiencies.
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89-04-04(IFI)
Review the revised procedure to
incorporate GE-SIL 319 recommendations
into
the
preventive maintenance
program.
89-04-05 (VIO)
Failure to perform a safety
evaluation on the storage of EC0DEX
resin inside containment.
'13.
Acronyms and Initialisms
Change Notices
-
Design Change Package
-
Diesel Generator
-
DRNS -
Drawing Revision Notices
Engineering Safety Feature
-
GGNS -
Grand Gulf Nuclear Station
HPCS -
Hydraulic Power Unit
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Instrumentation and Control
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LCC
Load Control Center
-
Licensee Event Report
LER
-
LPCS -
Low Pressure Core Spray
MCC -
Motor Control Center
MNCR -
Material Nonconformance Report
MWO
Maintenance Work Order
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Nuclear Regulatory Commission
NRC
-
P&ID -
Pipiag and Instrument Diagram
Pressure Differential Switch
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PSW
Plant Service Water
-
Quality Deficiency Report
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RCIC -
Reactor Core Isolation Cooling
-
RWCU -
'RWP
Radiation Work Permit
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SERI -
System Resource Incorporation
System Operating Instruction
501
-
Temporary Change Notice
TCN
-
-
TSPS -
Technical Specificaiton Position Statement
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