ML20058J511
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| ML20058J511 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 11/19/1993 |
| From: | Bernhard R, Hughey C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058J490 | List: |
| References | |
| 50-416-93-15, NUDOCS 9312140137 | |
| Download: ML20058J511 (15) | |
See also: IR 05000416/1993015
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S UNITED STATES
4# a mao % NUCLEAR REGULATORY COMMISSION
[*1 1 .4 REGloN 11
@ S 101 MARIETTA STREET, N.W., SUITE 2900
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ATLANTA. GEORGIA 303234199
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Report No.: 50 416/93-15
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Licensee: Entergy Operations, Inc.
Jackson, MS 39205
Docket No.: 50-416 License No.: NPf-29
Facility Name: Grand Gulf Nuclear Station
Inspection Conducted: September 19, 1993, through October 23, 1993
Inspectors: [[bfMh#
R.'H.Befnhard,SeniorResidehginspector
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Date Signed
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C. 'A.
x/Y bwW/O2
Hughey, Resident inspec' tor / C '
// 9/93
Date Signed '{
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Accompanying Personnel: M.D. Sykes, Resident inspector (Intern) e
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Approved by: !
f. S. Cantrell, Chief Date Signed j
Reactor Projects Section IB ,
Division of Reactor Projects i
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SUMMARY j
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Scope:
The resident inspectors conducted a routine inspection in the following areas: :
operational safety verification, maintenance observation, surveillance
observation, refueling activities, licensee self assessment capability, ;
action on previous inspection findings, and reportable occurrences. The- !
inspectors conducted backshift inspections on September 20, 23, 27, 28, 29, l
and October 5, 6, 7, 8, 12, 13, and 21 1993. l
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Results: }
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Jet pump no.10 was verified to be displaced during a video inspection between ;
the vessel wall and the core shroud. This displacement occurred just prior to !
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a reactor scram on Septeober 13, 1993 (Paragraph 3.f).
Operators acted conservatively when the main generator " motored" during a
plant shutdown. No equipment damage occurred. (Paragraph 3.c). l
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Two loss of shutdown cooling incidents occurred during the period. An
unresolved item was identified pending the completion of the licensee's root 1
cause evaluation of the second incident (Paragraph 3.e). j
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9312140137 931119
PDR ADOCK 05000416
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! ; ! 2 , I i l Undervessel maintenance personnel disconnected numerous LPRMs not included in l
the work order. A violation for failure to follow work instructions was .
identified (Paragraph 4.c). l
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The inspector observed numerous refueling activities which were conducted in a !
controlled and deliberate manner (Paragraph 6). j
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REPORT DETAILS :
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1. Persons Contacted l
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Licensee Employees ;
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L. Daughtery, Superintendent, Plant Licensing j
W. Deck, Security Superintendent- ;
M. Dietrich, Manager, Training j
*J. Dimmette, Manager, Performance and System Engineering !
*C. Dugger, Manager, Plant Operations ;
*C Hayes, Director, Quality Assurance i
*C. Hicks, Operations Superintendent
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*C. Hutchinson, Vice President, Nuclear Operations
*M. Meisner, Director, Nuclear Safety and Regulatory Affairs
*D. Pace, General Manager, Plant Operations i
J. Roberts, Manager, Plant Maintenance ;
*R. Ruffin, Plant Licensing Specialist !
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Other licensee employees contacted included superintendents, I
supervisors, technicians, operators, security force members, and office .f
personnel, j
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NRC Personnel ,
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*Mr. F. Cantrell, Chief, Reactor Projects Section IB, Division of Reactor ,
Projects, Region II, was on site October 21-22, 1993, to meet with the' ,
resident inspectors and observe facility operations and conditions.
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* Attended exit interview
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Acronyms.and initialisms used throughout this report are listed in the ;
last paragraph.
2. Plant Status
At the beginning of the period, the plant was in startup recovering from
the scram of September 13, 1993. Sources of excessive condenser i
inleakage and anomalous jet pump differential pressure readings were i
delaying the startup. On September 28, 1993, the plant was shutdown
when readings conducted at higher recirculation pump flows indicated a
potential displaced jet pump mixer section. An outage scheduled for
. early October was entered early. The plant remained shutdown for the , l- balance of the report period. l
During the week of September 27, 1993, Region 11 personnel from the
Division of Reactor Safety conducted on-site licensed operator i
examinations (NRC Inspection Report No. 93-301). i
During the week of October 18, 1993, Region Il personnel from the !
Division of Radiation Safety and Safeguards conducted a routine !
inspection in the area of radiological effluents and chemistry (NRC
Inspection Report No. 50-416/93-17).
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During the week of October 18,~1993, Region 11 personnel from the
Division of Reactor Safety conducted an inspection in the area of in- !
service inspection, erosion corrosion and jet pump beam cracking (NRC :
Inspection Report 50-416/93-19). l
Mr. Larry Dale was named Director, Plant Projects and Support, to become !
effective November 1, 1993. I
3. Operational Safety (71707 and 93702) j
a. Daily discussions were held with plant management and various
members of the plant operating staff. The inspectors made e
frequent visits to the control room to review the status of
equipment, alarms effective LCOs, temporary alterations, .
instrument readings, and staffing. Discussions were held as ;
appropriate to understand the significance of conditions observed. ;
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plant tours were routinely conducted and included portions of the l
control building, turbine building, auxiliary building, radwaste i
building and outside areas. These observations included safety
related tagout verifications, shift turnovers, sampling programs,
housekeeping and general plant conditions. Additionally, the
inspectors observed the status of fire protection equipment, the
control of activities in progress, the problem identification ]
systems, and the readiness of the onsite emergency response l
facilities. No deficiencies were identified. 1
b. On September 13, 1993, a reactor scram occurred at Grand Gulf from j
what was initially determined to be a " spurious" HPCS initiatico !
and an accompanying increase in reactor water level (Reference l
Inspection Report 50-416/93-14). On September 18, 1993, during
startup from the reactor scram, the licensee observed erratic -
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indications associated with the "A" loop of the jet pump '
differential pressure instrumentation. The~ licensee at that time
believed these erratic indications to be caused by crud that had
migrated into the instrumentation sensing lines after the scram.
These indications did not meet the surveillance requirements as ;
specified in TS 4.4.1.2.2 which demonstrates jet pump operability. ,
On September 20, 1993, the licensee requested and was verbally !
granted enforcement discretion for TS 4.4.1.2.2 by the Region II ,
Administrator. Written authorization followed September 21, 1993, i
This specification required that differential pressure i
measurements be taken on each individual jet pump within 72 hours - !
after entering Mode 2 and at least once per 24 hours thereafter. l
Discretion was granted to extend the 72 hours period to a maximum )
of 7 days or until completion of jet pump instrumentation I
troubleshooting. Compensatory actions were also specified.
Mode 2 was entered on September 17, at 7:29 a.m.
During the startup, an excessive amount of main condenser
inleakage prevented reactor power from being increased to greater
than 5 percent. The licensee believed jet pump flow
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instrumentation inaccuracies at this low core. flow and power also I
contributed to the inability to successfully complete the jet pump I
surveillance requirements; however, the inability to find the
source of the inleakage prevented power / flow increase into a more ,
accurate range of the jet pump flow instrumentation. From i
September 20, 1993, the licensee continued to troubleshoot jet :
pump flow instrumentation. This included venting and flushing of .;
instrument lines, the recalibration of all "A" loop transmitters !
and the replacement of a few transmitters. Concurrently, the i'
licensee attempted to determine the source of the condenser
inleakage by verifying valve lineups, walking down the condenser i
bay, and using helium, sulfur hexafluoride, infrared, and ,
ultrasound methodologies. li
On September 23, 1993, the unit was taken to hot shutdown in order :
to reduce noise levels around the condenser. By using only the j
mechanical vacuum pumps to maintain condenser vacuum, the licensee '
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hoped the lower noise levels would aid in finding the inleakage. '
This shutdown also eliminated the need for the enforcement .
l discretion granted earlier. The inleakage was not found and the ! '
unit was started up on September 24, 1993. The inleakage was -
found on the evening of September 25, 1993, ant was determined to r
be a loose MSR relief valve. The lagging and insulation around !
the component had prevented the gas detection methods from
effectively locating the leak. The valve connection was repaired,
condenser inleakage returned to normal levels, and the reactor ,
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power was increased.
During the startup, the licensee observed anomalous flow readings
on jet pump number 10. The readings, taken with the recirculation :
pump at low speed, were indicative of either an invessel broken
i jet pump differential pressure tap instrument line or of a !
displaced jet pump mixer section. The determination was made,
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i with input from the NSSS vendor, that higher flows were needed to ~
evaluate the anomalous readings. On September 28, at about
5:00 a.m. and at about 56 percent reactor power and 77 percent j
core flow, it was determined that the readings, coupled with (
vessel level instrumentation oscillations, could represent a i
displaced mixer section of JP10. The plant entered a shutdown LC0 '
based upon an inoperable jet pump, and the decision was made to
shut down the unit and enter a planned refueling outage about I
week early.
l c. On September 28, 1993, at approximately 12:30 p.m., the operators !
initiated a turbine trip as part of their normal shutdown *
procedure. The main generator should have tripped on reverse !
power within several minutes of the stop valve closure from the '
turbine trip. The operators did not observe the output breakers ;
opening as was expected, and verified the reverse power relays had !
not actuated. Generator output instrumentation still indicated j
thirteen MWe (the instrument reads in absolute values, so this :
could be MWe out or into the generator). Operators reviewed the '
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positions of major steam valves and indications showed a MSR "B"
second stage heater valve not fully closed. Stop valve positions
were verified closed locally. Operations' concern was that ;
sufficient steam might be present to allow turbine overspeed if ;
the output breakers were manually opened. Maintenance personnel
confirmed the generator's ability to " motor" for extended periods ;
without damage while the determination was made if the output i
breakers could be opened. Operations reset the turbine trip and ;
load was increased to the turbine via its normal control system. l
The indicated load changed from thirteen to nine MWe with the l
addition of steam, indicating the meter was indicating MWe into ;
the generator. The turbine was then tripped and the output i
breakers were opened. Generator support systems indicated no rise
in temperatures or other abnormal conditions caused by the .
" motoring" of the main generator for over one hour. Operations ,
acted conservatively to insure an overspeed did not result with
the loss of generator load. An engineering evaluation has j
resulted in a recommendation for a lower setpoint for the reverse ;
power relays to prevent recurrence of this in the future. The ;
inspector followed the events and found operations' actions to be i
appropriate. ;
d. The inspectors observed control room activities associated with l
the plant startup on September 17, 1993, and the plant shutdown on ,
September 28, 1993. Activities were conducted in accordance with :
the applicable Integrated Operating Instructions. No
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discrepancies were observed. Noise levels and distractions were !
kept to a minimum during rod manipulations. Control room command 6
, and control was good. I
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e. On October 4,1993, at 4:36 p.m., an automatic isolation of the
common suction piping for shutdown cooling occurred. The
isolation was caused by a failed voltage regulating and current
limiting card in one of the battery chargers. Two battery i
chargers were supporting the Division I DC loads while the :
batteries were undergoing a battery discharge test. The fault .
caused oscillations on the DC bus 11DA. Several relays in the AC '
circuit powered by the inverter dropped out, which resulted in .
several ESF actuations, closure of the IE12-F008 (isolation valve '
in the common suction line of SDC), tripping of the RHR B pump '
(f008 valve was not full open), loss of shutdown cooling, and
eventual transfer of inverters 1Y87 and 1Y96 to their alternate
power source. Operators reset the isolations and restored
equipment to the required condition but left the inverters on .
their alternate source of power until the investigation was !
complete. The failed cards in the battery charger were replaced.
The loss of shutdown cooling lasted about 5 minutes, and no. .
appreciable increase in reactor coolant temperature was noted.
The resident inspectors monitored event followup activities.
Corrective. actions included operations opening the IE21-F008 valve e
and racking out its breaker to prevent additional inadvertent
actuations, and changes to the battery inservice test procedure
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that place the inverters in alternate prior to conducting the !
test. The Alternate Decay Heat Removal System was available if it l
had been required. The safety significance of this event was low. !
Operations recognized the event immediately, and contacted l
electrical maintenance. The transfer to the alternate supply by l
the inverter, the isolation reset, and the pump restart were :
conducted in a minimum amount of time. The licensee's corrective ,
actions were appropriate, i
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On October 7, 1993, at 3:13 p.m., operators opencd the alternate !
supply breaker to inverters lY96 and lY87 and caused a Division I i
half scram, SBGT A initiation, Control Room Standby Fresh Air auto :
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start, and multiple isolations of equipment, including the closure ,
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of IE21-F009 due to a high reactor pressure signal. Closure of l
F009 caused the RHR B pump to trip, resulting in the loss of i
Shutdown Cooling for fifteen minutes. Reactor coolant temperature !
increased two to three degrees during the incident. The operators !
were hanging clearances and failed to properly verify all -!
indications that the inverters were on their normal power supplies l
l prior to opening the alternate supply breakers. Instructions on l l the tagout requested verification of the normal power source. 1 '
Barrel switches on the inverter were manually in a normal .
position, but the inverter was powered from the alternate source ,
via an internal auto transfer. Operator verification should have !
included the panel status lights. This item will be tracked as l
Unresolved Item 50-416/93-15-02, Loss of Shutdown Cooling, pending
the licensee's final determination of root cause of the incident. :
The incident review board for this event had not met by the end of '
the report period. The Alternate Decay Heat Removal System was
available for decay heat removal if it had been required. This l
event was of low operational safety significance. Preliminary i
actions taken by the licensee'for this event included procedurally i
bypassing the non-coincident reactor high pressure isolation l
l signal when not required by TS to prevent inadvertent isolation of
the suction line to RHR/ shutdown cooling. In addition, local tags j
are hung on the inverters indicating when they are on their
l alternate source, and an EER was written to address installation ! l- of a control room annunciator to indicate when an inverter is on -
alternate power. j
f. On October 6, 1993, a video camera inspection verified a displaced [
jet pump mixer section. The mixer section of jet pump number ten l
ejected from its position, travelled upward, impacted and dented
the LPCI invessel piping and damaged the retainer housing for the- !
number fourteen shroud head screw mechanism. (During the steam '
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! separator removal this mechanism was difficult to unfasten.) The ;
jet pump mixer inverted itself and was found lodged between jet '
l pumps eight and nine. The jet pump beam was not located with the I mixer, or in subsequent searches conducted' prior to the end of I l
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this report period. The inspectors followed the events and
licensee evaluations associated with this incident and found !
actions to be conservative and prudent. f
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No violations or deviations were identified. One Unresolved Item was l
identified. I
4. Maintenance Observation (62703) [
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a. During the report period, the inspectors observed portions of the. !
maintenance activities listed oelow. The observations included a :
review of the MW0s and other related documents for adequacy; i
adherence to procedure, proper tagouts, technical specifications, .
quality controls, and radiological controls; observation of work {
and/or retesting; and specified retest requirements. i
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MWO DESCRIPTION ;
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107122 Jet pump 9 loop "A" flow transmitter. !
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97338 Rebuild HCU 40-37
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b. The inspectors conducted interviews with licensee staff to
determine the process used when leak sealant is needed for leak
repair. The leak seal used onsite for beth safety related and non ;
safety related components is usually provided by Fermanite. 'The' !
leak sealant is not used on the pressure retaining boundary of- .]
ASME components. The leaking component is documented in a MNCR l
and processed by NPE. This results in each component being l
individually evaluated rather than covered in a " blanket"
dispositioning document. If a leak seal is recommended, it is
employed as a temporary fix and documents are generated for a
permanent repair of the component by other means. The goal for
permanent repair is within 90 days of the leak seal or during the
next outage if the component cannot be worked online.
Recommendations for the process are made by the leak seal vendor
but actual procedures and limitations are generated by NPE. The
injection pressures used are limited to the materials mechanical
limits, and quantity of fluid injected is limited by the amount of
free volume available in the component. If second injections are
required, the amount of fluid is limited and closely monitored.
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As an MNCR, the process is subject to all the restrictions and !
administrative _ controls any modification is subject to, including I
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50.59 reviews and PSRC approval, if required. Components with the
modification were tracked until the permanent repair.or
replacement is made. Components with leaks are also input into
the plant's erosion / corrosion program.
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c. On October 11, 1993, contract undervessel maintenance. personnel !
were in the process of disconnecting LPRM detectors. Maintenance .
Work Order no. 94641 specified the replacement of 26 LPRM !
detectors. During work activities, 39 additional detectors i
outside the scope of the work order were disconnected. The cables j
were cut on 26 detectors and 13 detectors were' disconnected. This !
resulted in total of 65 LPRMs becoming inoperable. This did not
meet TS since an APRM channel is inoperable if there are less than -i
2 LPRM inputs per level or loss than 14-LPRM inputs to an APRM ,
channel. Consequently, the licensee entered an LCO, since APRMs !
B, C, D, F, G and H were declared inoperable. Core alterations ;
were not in progress at the time of this incident. This was
identified as violation 50-416/93-15-01, failure to follow work -i
instructions.
d. Borescopic examination of the recirculation system discharge
valve, IB33-F067A, determined that an anti-rotation pin in the *
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stem disc assembly was missing. Some stem thread wear was also
present. The examination was performed because operating
experience at other plants indicated problems caused by absence of
this pin. General Electric service information letters had been :
issued discussing stem / disc separation problems at BWRs with this
style Anchor Darling gate valve. The inspectors examined the !
initial borescope videos, followed the planning process for the l
proposed repair, witnessed the full scale dry runs performed by ,
maintenance personnel and HP personnel using a spare valve i
assembly and reviewed the safety analysis and work package for the
actual replacement of the anti-rotation pin with a bolt. This i
discharge valve is the maintenance isolation valve for the '
recirculation loop, and maintenance on this valve may have
potential for draining the vessel. Work techniques were developed
to allow the maintenance to be performed with the valve discs
jacked into their closed position. Jet pump plugs were installed
to allow the piping in the loop to be drained and vessel leakage
to be monitored. The full scale mockup allowed improved tooling ,
to be developed, and HP practices and lead shielding placement to '
be optimized. The bonnet was off the valve for less than 50 <
minutes during the pin replacement. This careful preplanning and _ '
practice are examples of strengths in the maintenance and HP
departments at the plant. Examinations of the F0678 valve showed ,
the pin to still be in place. Additional valve maintenance was '
planned for RF07. i
One violation was identified for failure to follow work instructions. ;
5. Surveillance Observation (61726) ,
a. The inspectors observed the performance of portions of the ;
surveillances listed below. The observations included a review of t
the procedures for technical adequacy, conformance to Technical ;
Specifications and LCOs; verification of test instrument
calibration; observation of all or part of the actual *
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surveillance; removal and return to service of the system or
component; and review of the data for acceptability based upon the -
acceptance criteria. ;
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06-IC-1821-R008, Rev. 28, Reactor Vessel Water Level ,
Calibration (ECCS) (IB21-N081E). ;
06-RE-1833-D-0001, Rev. O, Jet Pump Functional Test. .
Temp - 1 l
06 IC-lE31-R-2003, Rev-23, Main Steam Line D High Flow (PCIS).
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07-5-53-N35-4, Rev. 5, First Stage Reheater Drain Tank B i
Pump Valve (IN35LTN015B). i
No violations or deviations were identified. The observed ;
surveillarce tests were performed in a satisfactory manner and j
met the requirements of the Technical Specifications. !
b. License Condition 2.c (26) requires that the bores and keyways of l
the low pressure turbine discs be ultrasonically inspected for i
cracking prior to exceeding 50,000 hours of operation. During
ultrasonic testing of the LP-3 turbine rotor, several recordable l
indications were detected from 0 to 360 degrees at the steam inlet ;
(inboard) side of disc no. 4 (generator end). These indications j
appeared to be the result of stress corrosion cracking. The ;
deepest indications were between 6 and 9 millimeters. In ,
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addition, indications were detected on the inboard side of the no.
4 disc (turbine side) with no appreciable depth. A preliminary i
fracture mechanic calculation by the vendor was performed and a l
determination was made that the rotor could be put back in service i
for another cycle without restrictions. Further analyses were to
be performed to determine whether increased inspection frequencies
were warranted. These indications were to be reported (per
License Condition) prior to startup.
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6. Refueling Activities (60710)
a. During the period, the inspectors periodically and routinely-
observed fuel movement. This included new fuel movement from the
fuel building into the containment, and the movement of fuel into
and out of the core. The observed movements were tracked and
documented per the applicable portions of P&SE Instruction 17-S-
02-300, SNM Movement and Inventory Control. Fuel movements were
conducted in a deliberate and controlled manner. General
housekeeping in the vicinity of the refueling areas _was good.
When questioned, key personnel were aware and knowledgeable of
ongoing activities.
b. The inspectors observed activities associated with the removal of
the reactor vessel head. The lift was accomplished per the
instructions in General Maintenance Instruction 07-S-14-184, !
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Revision 13, Installation and Removal of Reactor Vessel Head. The
inspectors attended the pre-job briefing and observed the lift i
from the polar crane. The entire evolution was well planned and i
executed. Radiation levels durin', tne litt were extremely low
requiring no respiratory protection. Communications between lift i
personnel was good. The inspectors verified that the specified '
weight limit of 119 tons was not exceeded by the polar crane
during the lift. ;
No violations or deviations were identified. l
7. Reportable Occurrences (90712 and 92700) !
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The event reports listed below were reviewed to' determine if the '
information provided met the NRC reporting requirements. The
determination included adequacy of event description, the corrective !
action taken or planned, the existence of potential generic problems and
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the relative safety significance of each event. The inspectors used the !
NRC enforcement guidance to determine if the event met the criterion for '
licensee identified violations. ;
a. On September 28, 1993, power was being increased toward 56% rated i
thermal with core flow at about 77%. After the transfer of the '
recirculation pumps from slow to fast speed, various level
iristruaentation or.cillations resulted. The licensee decided that
the oscillat'ons were most likely due to a displaced mixer section ;
on jet pump number 10. The decision was made to begin power ;
reduction toward plant shutdown. The resident inspectors were >
notified and a one hour notification was made to the NRC ,
Operations Center per 10 CFR 50.72(b)(1)(1)(A). (See paragraph
3.b) ;
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b. On October 4, 1993, surveillance activities (Division I battery i
check and discharge test) were in progress. Bus voltage I
oscillations during these activities resulted in a Division I- _ .
half-scram, loss of shutdown cooling through RHR "B", "A" standby '
gas treatment initiation, and a Division I/ auxiliary building l
isolation. The half-scram was subsequently reset, RHR "B" was !
returned to service, the standby gas treatment logic was reset, ,
and the auxiliary building isolation was restored. The resident l
inspectors were notified and a four hour notification was made to :
the NRC Operations Center per 10 CFR 50.72(b)(2)(ii). (See !
paragraph 3.e). j
c. On October 6,1993, following the removal of the steam dryer, a 'I
video camera inspection between the reactor vessel wall and the
core shroud revealed that the 180 degree elbow / mixer section of ;
jtt pump 10 was missing from the top of the common riser for jet !
pumps 9 and 10. The mixer section was found inverted and wedged j
between jet pumps 9 and 8. The resident inspectors were notified ;
and a four hour notification was made to the NRC Operations Center
per 10 CFR 50.72(b)(2)(i). (See paragraph 3.f).
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d. On October 7, 1993, operations personnel were performing tagging
operations which removed alternate power fram Division I -
inverters. When the AC bypass breaker for inverter lY87 was
opened, a Division I half-scram was received, standby gas
treatment "A" initiated, control room fresh air unit "A" iaitiated ;
and shutdown cooling through RHR "B" was lost (for approxin,ately .
15 minute.s). All systems were restored. The resident inspectors
were notified and a four hour notification to the NRC-Operations l
Center was made per 10 CFR 50.72(b)(2)(ii). (See paragraph 3.e). ;
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e. On October 14, 1993, various Division I containment isolation I
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valves closed and the Division I hydrogen analyzers automatically
started. The isolation was subsequently restored and the hydrogen
analyzers were placed back in standby. At the end of the '
inspection period the causes were unknown. The resident
inspectors were notified and a four hour notification was made to a
the NRC Operations Center per 10 CFR 50.72(b)(2)(ii). l
No violations or deviations were identified. I
8. Licensee Self Assessment Capability (40500)
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The inspectors-interviewed members of the licensee's Independent Safety
Engineering Group (ISEG) and reviewed procedures outlining the ISEG
functions to assess its effectiveness in supporting safe operation of ;
the GGNS facility. The ISEG was composed of a multi-disciplined,
dedicated, onsite group with a minimum complement of five engineers or
appropriate specialists. The mission of the ISEG was tc examine unit .
operating characteristics, NRC issuances, industry advisories, Licensee i
Event Reports, and other sources of plant design and operating ;
experience information, including plants of similar design. The ISEG ;
was aware of current industry issues and participated in numerous i
industry committees, meetings, and seminars. The ISEG reported. findings !
to the Vice President, Nuclear Operations, via the Director, Nuclear !
Safety and Regulatory Affairs. This was in an effort to ensure.a
reporting chain independent of plant operational management to preserve i
independence and objectivity in evaluating plant activities. The ISEG .!
had developed a working relationship with plant supervision and !
management and was cognizant of plant activities and trends. The
licensee had also established peer groups among the reactor sites and
their corporate office in specialized areas in order to share i
information and stimulate improvement. i
No violations or deviations were identified. i
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9. Action on Previous Inspection Findings (92701 and 92702) l
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a. (0 pen) Inspector Followup Item 50-416/93-14-03, Implementation of f
hardware changes to reactor vessel level indication system.
i
The inspectors reviewed DCP 93/0011-01 for reactor vessel water i
level reference leg purge, its associated safety analysis and )
retest requirements. The inspectors have also reviewed the !
'
modifications performed under Part 00 of this package to install
new reference columns for the fuel zone instrumentation. ,
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In response to Generic Letter 92-04 and Bulletin 93-03 involving
depressurization scenarios effecting reactor water level
indications, the licensee committed to making a modification to j
the plant to install a reference leg purge system. This system j
takes CRD charging water and after stepping the flow down using an l
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orifice permits about four pounds mass per hour to flow into the i
reference leg line to the condensing pots. In addition, the plant
installed a modification to the fuel zone instrumentation as an
additional backup to provide level indications during performance ]
of the plants EPs. The fuel zone reference legs had been changed ;
from the condensing pots B21-D004 A and B to be connected to the j
variable leg tap for the A and B narrow range instruments. This i
provided a continuous up slope to the reference leg that is i
automatically purged and backfilled any time the vessel level is j
above the narrow range variable inlet tap. The range of the !
instrument was expanded 100 inches over the old range and covered
from -20 inches to -320 inches.
Both modifications have been installed and are awaiting post j
modification testing. This item will remain open. :
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b. (Closed) Inspector followup Item 50-416/93-14-02, Root cause of j
HPCS initiation. ]
The licensee reviewed the water level variations associated with
the high flow periods during the restart from the last scram, and
the missing jet pump mixer section's position relative to the
vessel nozzle for the variable leg tap for the affected
instruments. This new information, along with the instrument
traces from the scram, indicated that the initiator for the HPCS
injection prior to the last scram was the displacement of the jet
pump mixer section. This conclusion was adequate to close IFI 50-
416/93-14-02.
10. Exit' Interview
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The inspection scope and findings were summarized on October 22, 1993,
with those persons indicated in paragraph 1. Dissenting comments were i
not received from the licensee. The licensee did not identify as i
proprietary any of the n:aterials provided to or reviewed by the ;
inspectors during this inspection.
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Item Number Type Description and Reference !
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50-416/93-15-01 VIO Failure to follow work instructions
(Paragraph 4.c.) j}
50-416/93-15-02 URI Loss of shutdown cooling (Paragraph
3.e)
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10. Acronyms and Initialisms
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AC -
Alternating Current l
APRM - Average Power range Monitor !
ARI -
Annunciator Response Instruction l
ASME - American Society of Mechanical Engineers i
BWR -
Boiling Water Reactor !
CFR -
Code of Federal Regulations- !
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CRD -
Control Rod Drive i
CST -
Condensate Storage Tank
DCP -
Design Change Package
ECCS - Emergency Core Cooling System
EDG -
Emergency Diesel Generator ;
EER -
Engineering Evaluation Report j
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EP -
Emergency Procedure j
ESF -
Engineering Safety Feature
GGNS - Grand Gulf Nuclear System !
HCU -
Hydraulic Control Unit '
HP -
Health Physics i
HPCS - High Pressure Core Spray l
IFl -
Inspector Followup Item :
ISEG - Independent Safety Engineering Group l
101 -
Integrated Operating Instruction l
LC0 -
Limiting Condition for Operation !
LER -
Licensee Event Report
LP -
Low Pressure l
LPCI - Low Pressure Coolant Injection I
LPRM - Local Power Range Monitor -i
MCP -
Minor Change Package
MNCR - Material Nonconformance Report
L MSR -
Moisture Separator Reheater
MWe -
. Megawatts Electrical
MWO -
Maiatenance Work Order
NPE -
Maclear Power Engineering
NRC. -
Nuclear Regulatory Commission
NSSS - Nuclear Steam Supply System
PSRC - Plant Safety Review Committee
RCIC - Reactor Core Isolation Cooling
RHR -
Residual Heat Removal
Rf0 -
Refueling Outage i
RO -
Reactor Operator 1
RPV -
Reactor Pressure Vessel
SBGT - Standby Gas Treatment
SDC -
Shutdown Cooling
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l , i l j SNM -
Special Nuclear Material !
S01 -
System Operating Instruction ,
TS -
Technical Specification ;
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