ML20056D116
| ML20056D116 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 07/23/1993 |
| From: | Christnot E, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056D114 | List: |
| References | |
| 50-321-93-11, 50-366-93-11, NUDOCS 9308050010 | |
| Download: ML20056D116 (24) | |
See also: IR 05000321/1993011
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UNITED STATES '
/p nra%ey NUCLEAR REGULATORY COMMISSION.
[' - .
.4 REGloN 11
E 101 MARIETTA STREET, N.W., SUITE 2900 *
5 4 ATL ANTA, GEORGtA 30323-0199 +
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a
Report Nos.: 50-321/93-11 and 50-366/93-11
Licensee: Georgia Power Company
P.O. Box 1295 ;
Birmingham, AL 35201
Docket Nos.: 50-321 and 50-366 License Nos.: DPR-57 and NPF-5
Facility Name: Hatch Nuclear Plant
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inspection Conducte4; June 06, - guly 03, 1993
Inspectors: Lh / 2~ L M 7*22 9
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Leonar' D. Wert, J,r/., Sr. Repdent Inspector Date Signed
ticEC ~ )f 4 t- *f o Z2* Vf
Ed'
w ard F. Christnot, ResideE[t' Inspector Dste Signed
Accompanying Inspector: Bobby Holbrook
Approved by': d [I// 7'J343
17v Pierce H. Skinner, Chief, Project Section 3B Date Signed
Division of Reactor Projects
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SUMMARY
Scope: This routine resident inspection involved inspection on-site in ;
the areas of: operations, including review of a Unit I reactor 1
scram, surveillance testing, maintenance activities, review of a ,
standby gas treatment system operability issue, engineered safety ;
feature system walkdown, short term compensatory actions in
response to NRC Bulletin 93-03: Resolution of Issues Related to .
Reactor Water Level Instrumentation in BWRs, and review of open
items.
Results: One violation and two unresolved issues were identified:
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The violation addressed a failure to comply with TS requirements
relating to inoperable standby gas treatment systems. The
violation was caused by inadequate communications between plant ,
personnel. (Violation 321,366/93-11-01: Failure to Comply With i
Standby Gas Treatment System TS Requirements, pc agraph 5.)
The first unresolved item involved actions taken during the
recovery from a Unit I scram. Reactor water level reached the
elevation of the main steam lines and the main steam isolation
valves were not shut. No damage to systems occurred and the
actions taken minimized additional complications during the
9308050010 930723 1
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recovery. Additional review is necessary to assess the ;
appropriateness of the actions. (Unresolved Item 321/93-11-02: !
Main Steam Isolation Valves Open With High Reactor Water Level, l
paragraph 2b.) j
The other unresolved item addressed inadequate testing of the ;
relative humidity sensors in the standby gas treatment systems. l
The inspectors identified that the licensee was not testing the l
sensors as discussed in a vendor manual. Additional information '
and review is necessary to assess the safety significance of this
issue. (Unresolved Item 321,366/93-11-03: Inadequate Testing of
Standby Gas Treatment Humidity Sensors, paragraph 3b.)
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The inspectors noted improvements in overall control room
professionalism in comparison to some observations in the previous I
inspection report period. In general, control room demeanor and l'
communications were more formalized.
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REPORT DETAILS
1. Persons Contacted
Licensee Employees
- J. Betsill, Unit 2 Operations Superintendent
- C. Coggin, Training and Emergency Preparedness Manager
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
C. Moore, Assistant General Manager - Plant Operations
D. Read, Assistant General Manager - Plant Support
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P. Roberts, Outages and Planning Supervisor
- K. Robuck, Manager, Modifications and Maintenance Support
- H. Sumner, General Manager - Nuclear Plant
- J. Thompson, Nuclear Security Manager
- S. Tipps, Nuclear Safety and Compliance Manager
P. Wells, Unit 1 Operations Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members and staff personnel.
NRC Resident Ins 9ectors
- L. Wert
- E. Christnot
Accompanying Inspector
B. Holbrook
- Attended exit interview
Acronyms and abbreviations used throughout this report are listed in the
last paragraph.
2. Plant Operations (71707) (92701) (93702)
a. Operations Status and Observations
Unit 1 operated at 100 percent RTP until June 15, 1993, when the
reactor scramred on a false low reactor water level signal. The
scram is discussed in paragraph 2b. A reactor startup was
commenced at 4:30 p.m. on June 16 and 100 percent RTP was attained
on June 18. On June 26, power was reduced to 60 percent to repair
a steam leak on the number 4 turbine control valve. Repairs were
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completed and power was returned to 100 percent on June 27. The
Unit operated at full RTP for the remainder of the reporting ,
period. )
Unit 2 operated at 85 percent RTP throughout this reporting *
period. Several rods remain fully inserted to suppress neutron !
flux in the area of a suspected . del leak. l
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The inspectors reviewed plant operations throughout the reporting I
period to verify conformance with TS, administrative controls, and
other regulatory requirements. Control room logs, shift turnover
records, temporary modification logs, LC0 logs, and equipment
clearance records were reviewed routinely. Discussions were ,
conducted with plant operations, maintenance, chemistry, health i
physics, instrumentation and control (I&C), and nuclear safety and 1
compliance (NSAC) personnel. The inspectors continued to I
periodically monitor the ongoing SFP cleanup project. I
The inspectors reviewed 15 TCs (Temporary Changes) to procedures
in detail. The changes were selected from the log of all TCs made
in 1993. The changes were examined for compliance with the
guidance in Procedure 10AC-MGR-003-05: Preparation and Control of
Procedures and TS 6.8.3. The safety evaluations were reviewed for
adequacy. Additionally, the inspectors verified that several of
the changes had been properly entered in the CR copies of the
procedures. Only a few minor administrative deficiencies were
noted. The safety evaluations adequately supported the procedural
changes. The inspectors did not identify any examples where
temporary changes were made that were specifically not allowed by
10AC-MGR-003-05. Paragraph 8 of this report (IFI 321,366/92-05-
01: Use of the Temporary Change Process), contains additional
discussion of this review.
Activities within the control room were monitored routinely.
Inspections were conducted on day and on night shifts, during
weekdays and on weekends. Observations included control room
! manning, access control, operator professionalism and
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attentiveness, and adherence to procedures. Instrument readings,
recorder traces, annunciator alarms, operability of nuclear
instrumentation and reactor protection system channels,
availability of power sources, and operability of the Safety
Parameter Display system were monitored. In general, the
inspectors noted that the overall conduct of control room
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operations had been strengthened in comparison to the previous
inspection period. Operators were very attentive and cognizant of i
all lit annunciators. The inspectors also observed an increase in l
the f ormality level of CR communications. Control Room !
observations also included ECCS system lineups, containment l
integrity, reactor mode switch position, scram discharge volume
valve positions, and rod movement controls,
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Several active safety-related equipment clearances were reviewed
to confirm that they were properly prepared and executed.
Applicable circuit breakers, switches, and valves were walked down
to verify that clearance tags were in place and legible and that ,
equipment was properly positioned. Equipment clearance program
requirements are specified in licensee procedure 30AC-0PS-001-05,
" Control of Equipment Clearances and Tags." Several clearances
which were utilized to replace solenoid vdves on primary
containment isolation valves were examined. The inspectors
verified that the appropriate compensatory action had been taken
for the inoperable isolation valves. No discrepancies were ,
identified.
Plant tours were taken throughout the reporting period on a
routine baris. The areas toured included the following:
Reactor Buildings Diesel Generator Building
Fire Pump Building Central Alarm Station
Station Yard Zone Turbine Building
Intake Building
During the plant tours, ongoing activities, housekeeping, 3
security, equipment status, and radiation control practices were i
observed. Several minor problems in the intake structure were l
noted, including corrosion on several piping supports. The I
supports were inspected by maintenance personnel and deficiency
cards were submitted. No significant deficiencies were noted.
On June 9, 1993, the inspectors participated in an emergency l
preparedness exercise conducted by the licensee. Several GEMA and 1
county EMA personnel participated. The simulated scenario began j
with an earthquake of an intensity above the Hatch OBE and i
progressed to a general emergency condition. The licensee's i
critique identified several weaknesses which will be corrected. !
No significant deficiencies were identified by the inspectors. l
On June 3,1993, one of the inspectors attended a scheduled
meeting of the Hatch Scram Frequency Reduction Committee. The
inspector noted that the meeting involved qualified personnel with
expertise in the appropriate areas to effectively review scram I
events for preventive actions. The committee had just issued its
first edition of the SFRC " top ten" items. Intentions are to
continually maintain this list of items which the SFRC has
determined would be most beneficial for reduction of scrams. The ;
list included several plant modifications which would correct I
situations which have already caused scrams at Hatch. The
inspector noted that the implementation of some of the measures
seemed inappropriately delayed, considering the potential
benefits. One example was that a lower setpoint for a low reactor
level scram had been approved by the NRC on August 30, 1991, but
the setpoints have not yet been reduced. At least one scram has
occurred which most likely would have been prevented if the lower
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setpoints had been implemented. During the meeting, substantial
progress on two of the " top ten" items was discussed. The
inspector concluded that the " top ten" list is an effective way to
communicate SFRC conclusions to management.
b. Unit 1 Reactor Scram on Low Water Level
At 3:53 p.m. on June 15, Unit I scrammed from 100 percent RTP.
The scram was caused by false low reactor water level signals I
which resulted when a reactor level instrumentation system i
variable leg was depressurized. l
I&C technicians had just begun Procedure 57SV-CAL-003-IS: ATTS
Transmitter Calibration, on level instrument IB21-N0938. 1821- ;
N093B is a differential pressure transmitter which provides an ;
input to the HPCI high water level trip circuitry. As the
technician touched the variable leg instrument isolation valve (a
normally open " Dragon" valve), to shut it, the packing gland nut
and some of the packing suddenly slid outward about 0.5 inches and ,
water began to spray out around the stem. Since the line is a
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" stagnant" line, no steam was released. The technician attempted *
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to reduct the leak by trying to tighten the nut. The leak was
reduced to about a 1/8 inch " stream" of warm water. ,
The leak resulted in the depressurization of the variable leg that
the IB21-N093B transmitter is connected to. This caused -
transmitters IB21-N80A and 1821-N080B, which provide reactor level
signals to RPS, to sense a false low reactor level and a scram ,
resulted. The leak was not large enough to cause the excess flow
check valve in the instrument line to shut. The level indicators ;
on the depressurized variable leg indicated low levels but did not >
fail downscale and in fact responded to some degree to actions
taken to control level.
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Due to confusing reports regarding which " side" of the instrument
was leaking (reference leg or variable leg) and other factors, it
was some time before operators were confident which water level
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indications were accurate. As a result, the level signals which
control the feedwater system were shifted between the "A" and "B" ,
channels. From their review of SPDS information, the inspectors '
noted that the lowest value of water level was about -34 inches
and the highest (about 20 minutes after the scram) was +117
inches. HPCI or RCIC were not required to initiate. A group II-
isolation was received and SPDS information indicated that the
valves all properly responded.
One of the inspectors responded to the site and observed actions
taken to isolate the leak (shutting the instrument line root e
valves) as well as the post scram meeting, initial investigative
actions, and some of the repairs. The inspector observed that the
area of the leak had been roped off by HP and noted several !
puddles of water on the floor. Subsequent checks by HP indicated
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that the I&C technician did not have any contamination on his face
or hands and the highest level of contamination found was about
8,000 dpm on the floor.
The reactor remained in hot shutdown and several "24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to cold 4
shutdown" LCOs were entered due to inoperable level
instrumentation and systems. (There are numerous water level
instruments connected to the depressurized variable leg.) The l
inspector noted that several key members of plant management were
involved in the initial recovery efforts.
The inspectors noted that the calibration procedure which had just ;
been initiated was required to be performed once per every 18 l
months. The test had not been completed during the recent
refueling outage. .
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The inspector observed dye penetrant testing of the involved
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packing gland nut and bonnet threads. No damage was identified. i
The inspector observed disassembly of a new " dragon" valve .
assembly identical to the failed one. It was noted that torquing t
the packing gland nut to 18 inch-pounds resulted in only 2.5
threads engaged on the bonnet and no compression of the packing !
follower into the 2 rings of hard graphite material packing. l
Increasing the torque on the gland nut made the valve handle very
difficult to turn. Other types of " Dragon" assemblies have as !
many as 6.5 threads of engagement on the packing nuts. The !
inspector also observed a maintenance worker checking the gland i
nuts on other instrumentation on the isolated line. The worker ,
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reported that several of the other nuts were also loose.
The licensee's discussions with the valve vendor indicated that
the 2.5 threads of engagement was as the valve was designed and
was not a problem. The licensee checked the torque of all '
identical safety related assemblies and tightened several loose i
nuts. The vender informed the licensee that the nuts are to be
" snugged". The licensee is considering several measures which
would reduce the probability of this type of problem in the
future. One method would be to require personnel to check that ;
the packing nuts are snugged before and after any manipulations of ;
the valves.
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Additional review of the transient was conducted by the
inspectors. Information from the plant computer and SPDS was t
utilized to closely examine the water level control issues. The
inspectors also discussed details of the transient with several of
the involved personnel. The inspectors had concerns involving two
issues. Actual reactor water level was permitted to reach the L
elevation of the steam lines with the MSIVs open. Additionally, '
the inspectors noted that it was difficult for the operators to
determine which indications of reactor water level were
representative of actual level for as long as 20 minutes into the ,
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The first area of concern noted by the inspector was that actual
reactor water level as indicated on the IB21-R605 instrument (a
" flood up" range indication which has a separate reference leg)
exceeded +100 inches for a period of several minutes beginning at -
about 20 minutes after the scram. The highest level reached was
about 118 inches above instrument zero. The elevation of the 1
center of the 24 inch diameter steam lines is +122 inches. The :
inspector's discussions with the operators indicated that the HPCI
steam supply drain pot high level alarm was actuated which also
indicates that some water had entered the steam lines. Step 4.12
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of Procedure 34AB-C71-001-IS: Scram Procedure, requires that the ,
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MSIVs be shut if reactor water level exceeds 100 inches. The SS
and other operators were preparing to shut the MSIVs when the
decision not to shut the valves was made by the Operations
Manager. The SOS was informed of that decision several minutes ,
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later and concurred. The inspector discussed the decision with >
several of the involved personnel. A number of factors were
considered and evaluated before the decision had been made.
Although by this time after the scr&m, CR personnel considered the
IB21-R606B and other level instruments not supplied from the '
depressurized line were accurate, they were not yet absolutely
certain which of the level instruments were indicating actual :
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level. At this time, the lowest ("A" side narrow range)
indications indicated 18-24 inches. At the time the decision to !
not shut the MSIVs was made, CR personnel had stopped all water i
'nventory makeup to the vessel. The Operations Manager concluded
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that shutting the MSIVs under the existing conditions, given.that
l the increase in level had been stopped, would insert additional *
l complications into the recovery. Closing the MSIVs would have
resulted in loss of the condenser as a heat sink and the ,
unavailability of the feedwater pumps. The main turbine vibration
recorder was examined closely for any indications that water was i
entering the turbine. The inspectors concluded that if
management had not directed that the MSIVs not be shut, the i
operators would have shut them in accordance with the procedure. ;
After the scram, GE personnel reviewed the main turbine vibration
recordings to verify that no water had reached the turbine. ;
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Additionally, the licensee performed walkdowns of portions of the '
- main steam piping and supports to ensure no indications of water
hammer were present. Discussions were held with GE regarding any
additional measures necessary to ensure that no problems had been
caused by the water which had entered the steam lines. No
problems were noted. The inspectors review of the main steam i
piping elevation drawings indicated that most of the water
probably traveled to the TBVs and into the condenser. The
licensee is working with GE on additional review of this issue.
The departure from the procedure was directed by a member of
management that has approval authority on the procedure. The
manager also holds an active SR0 license. The inspectors
concluded that although no safety concerns resulted from not
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shutting the MSIVs in this specific event, additional review of
the GE analysis should be conducted before the safety significance-
and appropriateness of these actions can be accurately assessed.
This issue is identified as URI 321/93-11-02: Main Steam ;
Isolation Valves Open With High Reactor Water Level, pending
review of the completed analysis of the issue- .
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The second area of concern to the inspectors was the long period ,
of time that was required before CR personnel were able to 4
conclusively identify which reactor vessel level indications were .
accurate. Human factor considerations in relating a CR panel !
level indication to a specific reference or varizble leg
contributed to the problem. With the exception of P& ids available
at the SS desk and in the SOS office, the operators are not ;
provided simple listings or other aids to assist in diagnosis of i
level indication problems. The assignment of level indicators to i
reference legs is further complicated by the fact that the
arrangement differs between the two Hatch units. This specific
example was additionally compounded by the fact that the " faulted"
level indication did not fail completely upscale or downscale and )
responded somewhat to the operators actions during the recovery.
In addition to facilitating troubleshooting during such events, a
simple method of distinguishing the instrumentation by assigned
instrument leg would allow operators to more easily determine
exactly which instrumentation is potentially effected during
evolutions.
The inspectors concluded that the CR operators responded
appropriately given the ;onditions encountered during the scram
recovery. The inspectors were informed that the licensee is
considering development of an operator aid to assist in l
identification of level detectors and transmitters with various
sensing legs.
c. Review of Core Operating Limits Report !
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The inspectors reviewed the Unit 1 Cycle 15 Core Operating Limits j
Report (COLR). The inspectors verified that the report contained
the information and specific limits required by TS. Additionally,
with the assistance of reactor engineering personnel, the i
inspectors verified that a sampling of the limits loaded into the l
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plant computer reflected the requirements of the TS. Because the
routine computer printouts obtained by STAS indicate the proximity
to a thermal limit but not the value of the limit, it is important !
that the limits are correctly inserted into the computer at
beginning of cycle. Procedure 42CC-ERP-021-OS: Wrapup
Installation and Databank Control, is utilized to install and
review the core monitoring software files. Reactor engineering
personnel provided several of the printouts listed in the databank
review section of the procedure. The LHGR limits stored in the i
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PANACEA files were compared to the COLR LHGR values for each fuel 4
type. Some of the computer data for the most limiting APLHGR
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values was compared with the APLHGR limits included in the COLR.
The inspectors verified that the values stored in the computer
were equal to or greater than the COLR values. (With the exception
of the natural uranium lattices which are authorized to be
excluded from the COLR curves.) The inspectors noted that a
significant portion of the data loading and verification process
l involves translation between the PANACEA and core map grid ,
reference systems as well as cross referencing of fuel and/or
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lattice types. The inspectors noted one minor discrepancy which i
was administrative in nature. One of the references listed in l
the COLR as the NRC approved method of development listed an i
earlier TS Amendment number. Corporate NSAC personnel verified '
that the COLR was in fact developed using the method specified in l
the most recent amendment and the problem was an administrative
oversight. No significant discrepancies were identified.
d. Notice of Unusual Event - Contaminated Injured Worker Transported
Offsite
On June 8, 1993, at approximately 10:00 p.m. EST, the licensee l
l declared an unusual event due to transporting a contaminated
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injured worker to a hospital. The injured individual was a
stract worker who was involved in the ongoing SFP cleanup
project. This group was cutting up used control rod blades and
local power range monitors (LPRMs) and loading casks for disposal.
Due to a problem with the LPRM cutting device, repair activities ;
were being conducted on that device. One of the workers struck l
the .: utter with a hammer. A small sliver came off of the device
and penetrated the worker's gloves. It lodged in the knuckle of ,
thr. middle finger of his right hand. Contamination levels were j
measured as high as 70,000 dpm on his finger. The NUE was
d2clared in accordance with Procedure 73EP-EIP-001-OS: Emergency
Classification and Initial Actions. Section 12.1 requires an NUE ,
if a contaminated injured individual with contamination levels 1
above 1000 dpm is transported offsite.
The worker was transported to Meadows Memorial Hospital in Vidalia
and was accompanied by a HP technician. A doctor made a small
incision and removed the sliver of material from the wound. The 4
individual received a small dose which was being assessed at the j
close of this inspection report period. One of the inspectors <
went to the hospital and met with some of the involved personnel l
for several minutes. Brief discussions were held with the injured i
individual and the HP technician as well as supervisory personnel. ;
All contaminated material was removed by the HP technician after l
the treatment. No significant problems were noted regarding the
actions of personnel at the hospital. The licensee has reviewed
the event in detail and is considering some measures to enhance i
the treatment of contaminated individuals in the future. The NUE I
was terminated at 11:20 p.m. EST.
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No violations or deviations were identified. One unresolved item was
identified.
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 l
that approved procedures were available, test equipment was cali-
brated, 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:
1. 34SV-E11-004-25: RHRSW Pump Operability (2A and 2C
pumps)
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2. 34SV-E41-002-15: HPCI Operability Test
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3. 345V-E41-002-2S: HPCI Operability Test
The inspector observed the Unit 1 HPCI surveillance testing on
June 11, 1993, from the HPCI room. The licensee has been trying
to correct a problem with the barometric condenser. The inspector
observed that although the barometric condencer initially had
appropriate indications of vacuum and level, the condensate pump
flowrate steadily decreased over the 30 minute test and the
condenser vacuum was lost. The inspector also noted that the
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discharge line on the vacuum pump became very hot. It appeared ,
that high condenser water level was affecting the performance of
the vacuum pump. The CR annunciator for high condenser pressure l
was received just prior to the HPCI system being secured. The
system was shutdown at about 30 minutes into the test due to high
torus temperatures. The operators had initiated torus cooling in
anticipation of the torus heating but the high RHRSW temperatures
affected the torus cooling capacity. (The Altamaha River was at
about 85 degrees F.) On June 28, the inspector verified that
appropriate DCs had been initiated and discussed the issues with
the HPCI system engineer. Although the barometric condenser has
no direct effect on the operability of HPCI, the correct
functioning of the condenser is necessary to prevent exposure of
personnel in the HPCI room % ring testing from high temperature
and radiation. A HPCI ma .cenance outage is being planned for the
second week of July to correct the problems.
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The Unit 2 HPCI testing was observed from the CR. The inspector
noted that the procedure was followed as required and no problems
were identified. The inspector noted good communications, both
within the CR and between the CR operators and personnel in the
HPCI room.
b. Standby Gas Treatment System Relative Humidity Sensors Issue
(92720) (92700) (61726) 1
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During review of the SBGT operability issue discussed in paragraph
5, the inspectors identified that testing of the SBGT relative
humidity (RH) sensors was not adequate. On June 15, 1993, one of
l the inspectors noted that the licensee's procedure for calibration
I of the RH heater controllers did not address the RH sensors.
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During review of the vendor manual for the Unit I sensors, the
inspector noted that the manual indicated the sensors should be
tested. l
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The sensors in the Unit I trains were supplied by Honeywell and ;
are Model Q464A. The sensors contain lithium chloride. !
Variations in thermal conductivity with RH result in a resistance ;
output that is inversely proportional to RH. The resistance i
output of the sensors is supplied to switches which control !
heaters used to reduce the humidity if necessary. High RH (above
70 percent) adversely effects the efficiency of the charcoal
adsorption beds. At values of relative humidity in excess of 95 ,
percent, the efficiency is sharply reduced. The FSAR for each ;
unit and the P& ids indicate that the heaters are to turn on at 70 l
percent humidity and off if humidity decreases to 50 percent.
The maintenance section of the manual for the Unit I sensors i
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states that normal aging of lithium chloride RH sensors lowers the
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indication by 1 or 2 percent each year. The manual also states ;
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that the sensor is to be checked at least once a year by
comparison with a reliable standard. The heater controller is
then to be adjusted to compensate for any loss in sensitivity.
If such loss in sensitivity occurred, the sensors would not
" sense" a high lavel of RH and may not turn the heater on as i
required. At 12:30 p.m. (EST) on June 15, the inspector
communicated this information to the system engineer. l
l At 2:55 p.m. on June 16, both Unit I trains of SBGT were declared
inoperable. In accordance with TS, a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to cold shutdown
action statement was entered on both units. At that time, Unit I
was in hot shutdown after a June 15 reactor scram and Unit 2 was
at about 85 percent RTP. The LCO was immediately terminated as a
result of a temporary change to Procedure 3450-T46-001-IS:
Standby Gas Treatment System. The heater control switch position
was changed to " manual". In this position, the signal from the RH
switch will not control the heaters. With the switch in " manual",
the heaters will be energized when the SBGT fan is turned on. A
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high temperature switch will still turn the heaters off if
necessary. ,
'
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Earlier on June 16, the system engineer had informed the inspector
that he had reviewed the Unit 2 RH sensors for similar problems.
The Unit 2 sensors were supplied by a different vendor and the
engineer did not find any guidance in the vendor manual indicating
that those sensors needed to be tested. After additional review '
,
by the licensee and discussions with the supplier of the Unit 2
sensors, it was concluded that the Unit 2 sensors may be
4 susceptible to the same problem. At 1130 a.m. (EST) on June 24,
the inspectors were informed of this conclusion. The Unit 2 SBGT
trains were not declared inoperable. At 2:25 p.m., temporary
,
modifications were implemented which placed jumpers around the
Unit 2 SBGT heater control switches (These switches are push !
buttons on Unit 2). This action resulted in the Unit 2 heaters
) being controlled the same as the Unit I heaters as discussed !
above. !
The inspectors concluded that the licensee has not been performing
>
adequate testing or other measures necessary to ensure that the RH ,
heaters would be properly controlled. The expected functioning of
the heaters is addressed in the FSAR and RG 1.52: Do.ign, Testing,
_
and Maintenance Criteria for Post Accident ESF Atmoapieric Cleanup
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System Air Filtration and Adsorption Units of Light-Water Cooled .
Nuclear Power Plants. The licensee is committed to the 1976 i
revision of the RG. Although TS do not contain the setpoints of
the heater controls, the operability of the heaters is addressed.
At the close of this report period, the licensee was in the
process of removing the sensors from both units. The sensors will
be tested by a laboratory. The results of the testing are i
necessary to accurately assess the safety significance of this ;
issue. In addition to the sensor performance data, additional '
review of the testing criteria and results will be required to
a determine the operability of the SBGT trains. The issue is !
i identified as Unresolved Item 321, 366/93-11-03: Inadequate :
Tcsting of Standby Gas Treatment Relative Humidity Sensors. !
No violations or deviations were identified. One Unresolved Item was i
identified. ,
!
4. Maintenance Activities (62703) l
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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
j that was not within the skill of the trade. Activities, procedures, and
] work requests were examined to verify; prope.* authorization to begin
j work, provisions for fire hazards, cleanliness, exposure control, proper
5
return of equipment to service, and that limiting conditions for
j operation were met.
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i
The following maintenance activities were reviewed and witnessed in i
whole or in part:
l
1. MWO 1-93-2458: PM on IR44-5002 and S003 i
1 "
2. MWO 1-93-1476: PM on 2R44-S002 and S003 ,
3. MWO 1-93-1718: PM on SBGT Train B
f
4. MWO l-93-1396: Troubleshooting of RHR Valves 2 Ell-F103B and '
F104B
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l The inspector noted during the observation of the maintenance' activities !
l
l
involved with the RHR valves that the maintenance personnel were !
utilizating Procedure 52GM-MEL-022-05: Limitorque Valve Operator i
Electrical Maintenance, at the job location. Effective communications
with the CR were established and maintained. ,
No violations or deviations were identified. l
5. Failure to Communicate SBGT System Operability Status (71707) (92700)
LER 321/93-08: Procedure Error and Miscommunication Result in Missed TS
Action Statement, addressed a failure to meet TS requirements involving
inoperability of both trains of Unit 1 SBGT. Given the potential safety
significance of the issue, the inspectors performed a detailed review. i
The TS requirements of both units for secondary containment and SBGT
system operability were examined. The inspectors also reviewed
maintenance records and control room logs to verify some of the l
conditions stated in the LER. The safety significance of the issue was
assessed by examining the effects of the SBGT trains inoperability in
various design bases accident scenarios. The inspectors obtained
information on the performance capabilities of the SBGT systems by
reviewing test data and discussions with personnel knowledgeable of the
-
performance of the systems. The results of the review were discussed in
detail with regional management. The following is a summary of the '
significant issues. I
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At approximately 4:00 a.m. on May 2, 1993, I&C technicians and the :
system engineer had determined that the IB SBGT system was inoperable i
due to the humidity controller on the heaters being inoperable. This
information was not adequately communicated to the CR operators who
questioned the operability of SBGT upon learning that the humidity
controller was inoperable at about 1:00 a.m. Subsequently, the "1A" EDG >
was declared inoperable (due to a component failure) at 7:05 p.m., on
May 2.
The Unit I reactor was pressurized for the Class I system leakage test
from about 3:00 p.m. on May 2 until approximately 5:00 a.m. on May 4.
The test is performed using non-nuclear heatup and pressurization
through compression of an air bubble in the vessel. Unit 2 was operated
at about 74 percent RTP during the period.
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Unit 1 TS 3.7.B.I.a requires that both trains of SBGT shall be operable
when secondary containment is required. Secondary containment was
required due to the reactor being pressurized and Unit 2 was at power. i
Unit 1 TS 3.7.B.I.a requires entry into a 7 day LC0 and an operability ,
test of the other SBGT trains within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and daily thereafter with
one train of SBGT inoperable. On Unit 1, when an EDG is declared
inoperable, the licensee enters the TS LCO for the EDG only and ;
considers declaration of all the equipment powered from the EDG as
inoperable to be " cascading" of TS and thus not required. (Unit 1 TS do
not contain a "3.0.5" requirement.)
Unit 2 TS 3.6.6.1 requires both Unit I and Unit 2 SBGT trains to be '
_
operable. f.Nitionally, Unit 2 TS 3.0.5 requires that when one train of
a system is inoperable, the redundant train can only be considered i
operable if both the normal and emergency power sources to the redundant
train are operable. ,
The inspectors concluded that in accordance with Unit 2 TS 3.6.6.1 and
3.0.5, the licensee should have entered a shutdown LC0 at 7:05 p.m. on
May 2. The conditions requiring the action statement were corrected at ,
11:52 p.m. on May 5. (The IB SBGT was repaired.)
It should be noted that prior to declaring the IB SBGT train inoperable, '
there was no need to question the operability of the 1A train. The
inspectors concluded that the application of the Unit 2 B TS 3.0.5
requirements to Unit I systems is appropriate in this case since the ;
Unit 2 TS specifically require the Unit 1 systems to be operable.
The Unit I and Unit 2 TS definition of " operable" include a system
having its source of emergency power available. The resident
inspectors have examined this area in the past and revisited it when GL 91-18 was issued. GL 91-18 contains wording which implies that
" cascading" is expected. Regional management and NRR representatives
have stated that during previous discussions that " cascading" of
electrical TS requirements is not required. In 1984, the licensee
requested that a TS 3.0.5 be added to the Unit 1 TS. (Amendment 162)
The inspectors noted that in the NRC response to this request dated May
25, 1989, it was. stated that "the Unit 1 TS contain requirements at
least as restrictive as those in the 3.0.5 and changes are not needed to
incorporate the requirements of 3.0.3 and 3.0.5". The statement refers
to several Unit 1 TS which contain requirements involving ECCS systems ;
4
and EDGs. The inspectors noted that not all important systems are I
included in those TS. Currently, the operators do not apply TS 3.0.5 )
" cross system" reasoning on Unit 1 equipment. The concern is that in ,
some cases, a loss of functionality could be permitted. This was 1
discussed with NSAC personnel.
The Unit 2 SBGT trains are each capable of maintaining the Unit 2
secondary containment (smaller than Unit 1) in excess of .25 in, water
(vacuum) at 4000 cfm. Statements in the LER and discussions with
knowledgeable engineers indicate that two Unit 2 trains will maintain
the Unit I secondary containment at a negative pressure. As documented
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in Inspection Report 321,366/92-22, in past secondary containment safety
. significance evaluations, NRR representatives have stated that the :
" safety function" of secondary containment is accomplished as long as a
negative pressure is maintained in the containment.
Additionally, the inspectors reviewed Special Purpose Test Procedure
175P-020193-00-1-15 which was recently conducted due to implementation ,
'
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work associated with the " hardened vent" modification (DCR IH89-278).
That test utilized both Unit 2 SBGT trains aligned to the common
refueling floor and the Unit 2 RB. (Secondary Containment was in the i
2 " modified" mode and thus the Unit 1 RB was separated from the R/F ;
'
floor.) The results of the test were .29 in water (vacuum) in the R/F
floor and .56 in. water (vacuum) in the Unit 2 RB. Given this
performance data, it seems likely that the two Unit 2 trains would be ;
'
l capable of pulling .25 in water (vacuum) in the Unit 1 LOCA case. If a
failure of either of the two Unit 2 SBGT trains would have occurred, it
'
is unlikely that a negative pressure could have been maintained in the
Unit I secondary containment. l
In the event of a LOCA on Unit 2 concurrent with a LOSP, both Unit 2
SBGT trains would start, aligned "from" the Unit 2 RB and R/F floor. The
- suction dampers from the R/F floor would fail open, as designed. Since
'
in the normal secondary containment alignment, the Unit 1 RB is
connected with the R/F floor, the suction of the Unit 2 SBGT trains
would be aligned to all three of the secondary containment " zones".
Based on extrapolation of the performance data discussed above, the :
inspectors concluded that the Unit 2 RB and the R/F floor would be
maintained at a negative pressure in this scenario. Had a failure of
one of the Unit 2 trains occurred, it is unlikely that a negative l
pressure could have been maintained.
The inspectors review indicated that during the period of May 2-5, no
activities which involved a significant risk of causing increased
radiation levels on the R/F floor were performed. In the event of high
R/F floor radiation levels, all 4 of the SBGT trains would have started
and maintained the negative pressure on the R/F floor area.
I
Unit 1 operated for about 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> in a condition requiring both SBGT !
, systems (or one inoperable with the others periodically tested for up to !
7 days). The LCO was not entered and the required testing was not ;
i performed. Unit 2 operated for over 77 hours8.912037e-4 days <br />0.0214 hours <br />1.273148e-4 weeks <br />2.92985e-5 months <br /> with both Unit 1 SBGT .
i trains inoperable. A 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to hot shutdown action statement should
have been entered.
'
By extrapolation of existing SBGT testing data, the licensee concluded
I
that had the most adverse DBA' scenarios occurred, the secondary
containment negative pressure would have been maintained. The
<
inspectors review of the issue did not identify information that would
. contradict this conclusion.
The licensee identified this specific issue and initiated corrective
- actions. A detailed LER was submitted. The cause of this issue was a
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miscommunications involving the operability status of the IB SBGT train.
Once the problem had been communicated, the appropriate LC0 was er.tered,
testing was performed, and repairs were completed. The inspectors
concluded that not all of the criteria of the Enforcement Policy for
non-cited violations were met. The inoperability of the SBGT train was
known by some plant personnel and should have been communicated to CR
personnel more expeditiously. This is identified as Violation
321,366/93-11-01: Failure to Comply With Standby Gas Treatment System
TS Requirements.
One violation was identified.
6. ESF System Walkdown (71710)
The inspectors conducted a walkdown of the Unit 2 HPCI system. Valve,
switch, and electrical board lineups in the CR and locally were verified
to ensure the lineups were in accordance with operability requirements.
Walkdowns of spaces were performed to verify equipment conditions,
housekeeping and cleanliness. Various piping supports and hangers,
instrument valve alignments, freeze protection, and othar support
systems were verified to be operable. The Unit 2 FSAR, TS, and
Procedure 3450-E41-001-25, High Pressure Coolant Injection (HPCI)
System, were reviewed in preparation for the inspection. The HPCI
system valve lineup section of the operating procedure was verified to
be as delineated in P& ids H-26020 and H-26021. The inspector did not
identify any safety significant issues that would affect operability.
The following minor discrepancies were noted and discussed with licensee
personnel:
-
The freeze protection insulation and wiring appeared to be damaged )
on drain valves, 2E41-F133 and F139, for the instrumentation ;
columns of level switches LS N002 and 003. These switches !
initiate a change in the suction path for the HCPI system from the l
CST to the suppression pool. l
-
A minor steam leak was noted which appeared to be from the 1/2
inch drain line valves 2E41-F069 and F072. These valves provide a
drain down path for the HPCI turbine steam supply line steam trap
-
The inspector noted a drop of oil below the booster pump bearing
closest to the HPCI pump. The oil appeared to be weeping out of
the bearing and an oil sheen was present on the pump skid.
i
A continuing problem with the turbine exhaust drain pot was reviewed. I
The Unit I and 2 HPCI drain pots were equipped with a steam trap which .
discharged condensed water back to the suppression pool. The drain pots
also had a solenoid operated drain valve,1/2 E41-F053, that opened on
high level and discharged excess condensed water to the barometric
condenser. A modification was recently installed on the Unit 2 HPCI
which removed the steam trap, providing a more direct drain path through
a check valve and a manual valve to the suppression pool. The
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16 :
modification also interlocked the HPCI steam admission valve, 2E41-001, !
and the exhaust system drain pot high level dump valve 2E41-053. The i
interlock was installed such that when the steam admission valve it
fully closed the solenoid valve 2E41-053 is open. When the steam
admission valve comes to the closed position the drain pot high level
dump closes. The solenoid operated dump valve no longer responds to a ;
high water level in the drain pot. Based on the inspectors observations '
of HPCI testing and discussions with licensee personnel, this .
modification did not adequately address the prchlem. Consequently, it
was not installed on the Unit 1 HPCI system. The licensee is continuing
to pursue resolution of this problem and the inspectors will continue to
monitor those actions. !
As part of the walkdown, the inspectors utilized information contained l
in NUREG/CR-6014: HCPI Risk-Based Inspection Guide for HNP Station,
dated May 1993. The checklist in section 5 listed some components in
order of risk significance. All items on the checklist were checked by
the inspectors as part of the ESF system walkdown. i
The inspector noted that in Table 4.2 of the guide, the HPCI failure to l
start risk contribution was 40 percent for the industry and 55 percent
for Hatch. The licensee formed a HPCI task, which worked from February,
1992 to June 1992, and performed a detailed review of the HPCI and RCIC !
systems. The task force made several recommendations and several
hardware and software modifications were implemented. In previous ;
'
inspection reports, the inspectors have documented independent reviews
and observations of these various changes made to the systems as a ,
result of this task force. ;
No violations or deviations were identified.
7. Review of NRC Bulletin 93-03 Short Term Compensatory Actions (92720) !
The inspectors reviewed the licensee's short term compensatory actions .
in response to NRC Bulletin 93-03: Resolution of Issues Related to '
Reactor Water Level Instrumentation in BWRs. The review focused on
verification of the three measures which were specifically required to '
be completed within 15 days of the date of the bulletin. The licensee
has until July 30, 1993 to complete augmented operator training and to '
submit a response to the bulletin. :
Operations Department Directive 0-93-17: The Effects of Non-condensible
Gas on Cold Reference Leg RPV Water Level Instruments, was issued. The
directive was required to be reviewed by all licensed operators and ,
contained a detailed discussion of the potential effects of non-
condensible gases on Hatch RWL instrumentation. Additionally, it '
contained a brief description of " notching" which was noted through a
detailed review of recordings of narrow range level indications during a
Unit I shutdown in March, 1993. A graph of the " notching" was attached. '
(Printout of computer values of instruments 1821-R693A and B, narrow
range SPDS indicators which utilize the same level transmitters as the
IB21-R606A,B, and C instruments.) The inspectors noted that the ;
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1 \
l " notches" were about 4-6 inches in magnitude and lasted for 8-10 minutes i
before the level indications returned to the value before the " notch". l
Reactor pressure was about 60 psig and shutdown cooling had just been i
'
placed in service. Under the existing plant conditions, these " notches"
would have been very difficult to detect without an expanded time :
display of a narrow range indicator. Emphasis was placed on the 1
concern of this phenomenon during a RPV drain down event. The directive
also reminded operators that non-condensible gases only affect the cold i
reference leg instrumentation . The wide range instruments at Hatch
utilize a " heated" reference leg design and are not affected by this
issue. The directive also briefly discussed, in general terms, limiting
activities that have the potential to drain the vessel during normal 1
plant shutdowns and the licensee's plans to implement a modification in ;
the future.
Operating Order 00-02-0693S: Monitoring of RPV Level Indication During
Hot Shutdown Conditions, was developed to provide specific guidance for !
enhanced monitoring of level indications for " notching". In hot ,
shutdown, a recorder is to be connected to the C32-R606A and C32-R606B i
narrow range instruments and placed behind the P603 panel in the CR.
When above 450 psig, the recorder is checked and the indications
recorded at least once per hour. At pressures less than 450 psig, the .
frequency is increased to every 15 minutes. The operating order 1
provides specific actions to be taken if notches exceeding 6 inches or ;
12 inches are observed. If notches exceed 12 inches, all !
instrumentation on the affected reference leg is to be declared
inoperable and the TS actions are to be taken. If all narrow range ,
instrumentation is inoperable due to notching, and the wide range ;
instruments indicate lest than +30 inches, the operators are to manually
initiate the isolation functions which may not automatically occur (SDC,
SDV, and all Group II valves).
Both the operating order and the department directive briefly discuss
that it would be prudent to limit any unnecessary activities which have
the potential to drain the RPV. The Hatch Outage and Planning
organization has developed a definition of maintenance activities which !
'
have a potential to drain the RPV. Normally, those activities are not
conducted while the reactor is in hot shutdown. Discussions with
licensee management indicated that additional formal action in this area
of the bulletin is considered not necessary.
The inspector concluded that the above procedures provide sufficient 1
guidance to meet the requirements set forth in the bulletin which were
to be completed within 15 days. The inspector noted that the level
recorder was te be installed at a back panel which operators cannot
monitor from their normal positions in the "at the controls" area. !
Periodic checks of the recorder will be relied upon to alert the
operators of a notching problem. On June 16, 1993, the inspector
observed the implementation of these procedures on Unit I which was in
hot shutdown. Temporary Modification 1-93-71 was utilized to install
the level recorder in accordance with MWO 1-93-3137. The inspector
observed that the monitoring actions required by the operating order
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were being completed. The recorder was connected to the feedwater level
control circuitry. The inspector noted that the recorder paper travel i
speed and scale (0.5 inches on the recorder corresponds to 3 inches of
reactor level) seem appropriate for detection of the notching
phenomenon. Although the order did not specify when the recorder could
be removed during a reactor startup, the SOS and other CR cperators i
indicated to the inspector that the recorder would be removed from l
service after reactor pressure began increasing. On June 17, with the '
. reactor at apprcximately 100 percent RTP, the recorder was disconnected. l
During the removal of the recorder, I&C technicians noted that the
recorder had been connected in such a way that any loss of continuity in
the connectors or recorder could have resulted in a loss of feedwater.
The Temporary Modification was revised to specify the method of l
connection of the recorder in more detail. l
l
On June 28, 1993, one of the inspectors attended licensed operator l
requalification lecture LR-IH-50003-00: Condition 3 Reactor Water Level
Control. The lecture addressed the concerns of the bulletin with
emphasis on specific operator actions if a level problems is detected.
At the close of this report period, the licensee was still in the
process of finalizing some of the other actions required by the
bulletin. Additional review will be conducted after the licensee's
response is received.
No violations or deviations were identified.
8. 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 366/92-25: Less Than Adequate Procedures and
Personnel Error Result in TS Non-Compliance and LER 366/92-27:
Less Than Adequate Communications Results in Missed TS Action
Statement. These LERs involved issues which were discussed in
Inspection Reports 321,366/92-34, 93-02 and 93-08. The inspectors
reviewed the procedural revisions completed in response to these ,
events, and verified that the changes adequately addressed the i
deficiencies. Based on this review of the revised procedures 1
and the reviews documented in previous inspection reports, these
LERs are closed.
b. (Closed) LER 321/92-13: Single Failure Vulnerability Discovered
in the Intake Structure. This LER addressed the licensee's
identification of a single failure issue involving all three
intake ventilation fans. The item was discussed in Inspection j
Report 321,366/92-34. Initially, the issue involved the !
operability of all the service water pump motors but the licensee i
subsequently developed additional information which decreased the i
safety significance of the issue. The licensee implemented DCR l
92-144 during the recent Unit I refueling outage. The inspector
reviewed this modification. The design change, as implemented, l
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moved the power source for fan IX41-C009C from Unit 1 electrical
board IR24-S009 to Unit 2 electrical board 2R24-S009. Fan: 1X41-
l C009A and IX41-C0098 remain powered from Unit 1 electrical boards
1 1R24-5009 and IR24-S010 respectively. The modification corrected
the single failure vulnerability. Based on the implementation of
the DCR, this LER is closed.
c. (Closed) LER 366/92-17: Personnel Error Results in TS Non-
compliance. The issue in this LER was addressed as Violation l
366/92-22-02 which was closed out in Inspection Report 321,366/93-
02. Based on the reviews performed by the inspectors in closing
the violation, this LER is closed.
l
l d. (Closed) LER 366/92-11: Inoperability of Station Source Battery
'
and Chargers Results in TS Non-compliance. The primary concerns
in this LER were addressed as Violations 321,366/92-18-04 and 92- i
18-05. These violations were closed in Inspection Report 321/366- !
93-03. Based on the detailed reviews performed by the inspectors
to close the violations, this LER is closed. l
1
e. (Closed) LER 321/92-19: Personnel Error Results in Missed TS j
Surveillance, LER 366/92-22: Less Than Adequate Communication and :
Personnel Error Results in Missed TS Surveillance, and LER 366/92- )
.
24: Personnel Error Rcsults in Missed TS Surveillance. These 1
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LERs were involved with a long term review by the inspectors
documented in several Inspection Reports including; 321,366/92-34,
93-02, and 93-08. Violation 321,366/93-08-02, was initiated to !
ensure additional levels of corrective actions would be taken.
Based on the previous documented independent inspector reviews and
issuance of the violation these LERs are closed.
l f. (Closed) IFI 321,366/92-05-02: Use of the Temporary Change i
Process. This was issued to address a concern that TCs were being
l utilized in many instances where a procedural revision would be
l more appropriate. On May 4, 1992 a memorandum was sent to all i
'
department managers which discussed the concern and emphasized l
that the managers need to be sensitive to the type of changes '
allowed as TCs. The inspector obtained data from document control
personnel indicating that the total number of TCs has been reduced
from 549 in 1990 and 618 in 1991 to 335 in 1992. The inspector's '
review of the TC log indicates that about 340 TCs should be
processed in 1993. The inspector noted several indications that
department managers are closely following the number of TCs that
they approve and are being cautious to avoid the use of TCs to
bypass the normal procedure revision process. Paragraph 2 of this
report discusses the inspectors review of a sampling of 1993 TCs. ;
No significant deficiencies were noted. Additionally, the
licensee is presently changing plant procedures from a centralized
computer system over to a personal computer application. Future :
plans are to make procedures available at workstations via a LAN. i
This is expected to increase the efficiency of the procedure
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revision process and may further reduce the use of TCs. Based on i
this review, this item is closed.
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g. (Closed) IFI 321,366/92-05-03: Resolution of Degradations
Involving Safety Systems. This item addressed several examples of ,
less than appropriate resolution of degradations or failures-
involving important systems. The specific examples noted in -
Inspection Report 321,366/92-05 have been addressed and corrected. j
Previous inspection reports discuss those issues. Licensee
management recognized that improvement in evaluation of system ;
performance was needed. In addition to increasing overall >
awareness and increasing attention to such problems, other
corrective actions were initiated. System engineering has
developed a " System Engineering Practices Manual" which contains ,
guidance and promulgates expectations for system engineers.
Issues such as system walkdowns and quarterly system reports are
addressed. Performance is monitored on both system and component
levels and reported to management. The inspectors have reviewed
several of the system reports and noted that most are highly
detailed. Discussions with engineering management and several '
engineers indicate that the role of the system engineer in
communicating equipment problems to management has been re-
emphasized. The recent resolution of a longterm main stack
problem (see Inspection Report 321,366/93-03) is an example of
good pt.suance and resolution of an equipment problem. In i
general, over the last year, the inspectors have noted an '
increased involvement of system engineers in the daily operation
of the plant. The inspectors concluded the licensee's actions,
specifically the enhancements in system engineering, should result '
in more timely recognition and resolution of equipment performance !
problems. Based on this review and discussions of problem l
resolutions in previous reports, this item is closed. j
9. Exit Interview !
The inspection scope and findings were summarized on July 6,1993, with
those persons indicated in paragraph 1 above. The inspectors described
the areas inspected and discussed in detail the inspection findings. The
licensee did not identify as proprietary any of the material provided to j
or reviewed by the inspectors during this inspection.
Item Number Status Descriotion and Reference
321,366/93-11-01 Open VIO - Failure to Comply With
Standby Gas Treatment System TS
Requirements, paragraph 5 l
321/93-11-02 Open URI - Main Steam Isolation Valves
Open With High Reactor Water
Level, paragraph 2b
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Item Number Status Description and Reference (Con't)
321,366/93-11-03 Open URI - Inadequate Testing of
Standby Gas Treatment Humidity
Sensors, paragraph 3b
10. Acronyms and Abbreviations :
AC - Alternating Current
AGM-PO- Assistant General Manager - Plant Operations l
AGM-PS- Assistant General fianager - Plant Support i
APRM - Average Power Range Monitor l
APLHGR- Average Planar Linear Heat Generation Rate l
ATTS - Aralog Transmitter Trip System !
BWR - Boiling Water Reactor '
BWROG- Boiling Water Reactors Owners Group
CFM - Cubic Feet Per Minute
CFR - Code of Federal Regulations l
COLR - Core Operating Limits Report !
CR - Centrol Room
CRD - ( rol Rod Drive
CST - Co,+2nsate Storage Tank
DC - Deficiency Card
DCR - Design Change Request
dpm -
Disintegration Per Minute l
DW - Drywell
ECCS - Emergency Core Cooling System
EDG - Emergency Diesel Generator
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 - Functional Test and Calibration
GE - General Electric Comp ny
GEMA - Georgia Emergency Management Agency
GL - Generic letter
4
'
HP - Health Physics
HPCI - High Pressure Coolant Injection System
I&C - Instrumentation and Controls
IFI - Inspector Followup Item
LC0 - Limiting Condition for Operation
LER - Licensee Event Report
LHGR - Linear Heat Generation Rate
LOCA - Loss of Coolant Accident
LOSP - Loss of Offsite Power
LPRM -- Local Power Range Monitor
MCC - Motor Control Center
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MSIV - Main Steam Isolation Valve
Mwe - Megawatts Electric
MWO -
Maintenance Work Order-
NCV - Non-cited Violation
NRC - Nuclear Regulatory Commission
NSAC - Nuclear Safety and Compliance
NUE - Notice of Unusual Event
OBE - Operating Basis Earthquake
PE0 - Plant Equipment Operator
P&ID - Piping and Instrumentation Drawing
PM - Preventive Maintenance
PRB - Plant Review Board
PSW - Plant Service Water System
RB - Reactor Building
RCIC - Reactor Core Isolation Cooling System
R/F - Refueling Floor
RFP - Reactor Feed Pump
RG - Regulatory Guide
RH - Relative Humidity
RHRSW- Residual Heat Removal Service Water System
RPS - Reactor Protection System
RTP - Rated Thermal Power
RWL - Reactor Water Level
RX - Reactor
SAER - Safety Audit and Engineering Review
SBGT - Standby Gas Treatment
0. P - Spent Fuel Pool
SFRC - Scram Frequency Reduction Committee
SOS - Superintendent of Shift (Operations)
SPDS - Safety Parameter Display System
SR0 - Senior Reactor Operator
SS - Shift Supervisor
STA - Shift Technical' Advisor
TC - Temporary Change
TS - Technical Specifications
URI -
Unresolved Item