ML20058J464
| ML20058J464 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 11/17/1993 |
| From: | Christnot E, Holbrook B, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058J438 | List: |
| References | |
| 50-321-93-24, 50-366-93-24, NUDOCS 9312140122 | |
| Download: ML20058J464 (24) | |
See also: IR 05000321/1993024
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UNITED STATES
_y+
f#>m nec%k NUCLEAR REGULATORY COMMISSION
REGloN 11
.Q fg 2 101 MARIETTA STREET, N.W., SUITE 2900
- s Lg ATLANTA, GEORGIA 303234199 ;
\...../ Report Nos.: 50-321/93-24 and 50-366/93-24
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Licensee: Georgia Power Company l
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
Inspection Conducted: October 03 - October 30, 1993
Inspectors: p/4/ . ///M/f.s
f Leh 'ard ~D.' REi t~, 't, r. Resident Inspector Dat'e Sig~ned !
NY/ ident Inspector
////9 lf3
Di(te Jiijned r
[ttE wird F. Cliftstno
lV f . n/M/O
p ob E. ~1tro , Resid nt Inspector Date~ Signed
Approved by: .
/4<A k.[ m
Pidrce H. Skinner, Chief, Project Section 3B
////9h
Date Signed
Division of Reactor Projects
SUMMARY n;
Scope: This routine resident inspection involved inspection onsite in the
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areas of operations including review of a Unit I scram and a
period of sustained control room (CR} observation, surveillance
testing, maintenance activities, incorrect effluent radiation
monitor setpoint, and review of open items.
, Results: One violation and one non-cited violation were identified: !
The violation addressed a failure to follow procedure by a control
room operator during surveillance testing of the Unit 2 high
pressure coolant injection pump. The deficiencies were identified
by an NRC inspector who was monitoring the test. No additional
examples of failures to follow procedure were identified during
the inspection period. It was concluded that this was an isolated i;
case of an individual operator not complying with procedures
(Violation 50-321/93-24-01: Failure to Follow Procedures During
HPCI Testing, paragraph 2.e(4)).
The non-cited violation addressed an incorrectly set effluent '
radiation monitor setpoint. The problem was caused by a personnel
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9312140122 931123 ,
PDR ADOCK 05000321 +
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error and was identified by a chemistry technician (NCV 50-
321,366/93-24-02: Incorrect Liquid Effluent Radiation Monitor
Setpoint, paragraph 5). 3
Although a decline in overall CR operators performance had been
observed earlier this year, over the last four months' the resident
inspectors have noted general improvement. Examples of strong
operator actions during transients or problems have been observed.
During this inspection period, one example of poor operator ;
communications was noted (paragraph 2a). Good operator actions r
were noted involving a-loss of feedwater flow scram and reactor '
water control system transient (paragraphs 2c and 2d).
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In order to further assess the effectiveness of the licensee's
corrective actions, a sustained CR observation inspection was ;
conducted. The inspectors concluded that the overall performance
of the CR operators was satisfactory. Strengths were noted in
several areas. Annunciator controls, overall control room
professionalism, and a low number of out of service control room
instruments were noted as particularly strong. Good performance
was noted in several specific areas in which weaknesses had >
previously been identified. Operators were attentive to alarms
and used alarm response procedures. Operators were observed to be
alert to their duties. With the exception of the HPCI
surveillance test example, operators followed procedures during
evolutions. There were some areas in which the inspectors
concluded that performance could be improved. Operators did not
exhibit a questioning attitude about some CR indications. Some
turnovers and briefings were not appropriate to support strong
operation. In general, there was a sense that senior reactor
operator oversight should be stronger (paragraph 2e).
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REPORT DETAILS
1. Persons Contacted
Licensee Employees
- L. Adams, Nuclear Security Supervisor
- D. Bennett, Chemistry Superintendent
- J. Betsill, Unit 2 Operations Superintendent
- R. Burns, Plant Operator
- B. Butler, Operations Shift Superintendent
- C. Coggin, Training and Emergency Preparedness Manager
- S. Curtis, Operations Support Superintendent
D. Davis, Plant Administration Manager
- P. Fornel, Maintenance Manager
0. Fraser, Safety Audit and Engineering Review Supervisor
- G. Goode, Engineering Support Manager
- M. Googe, Outages and Planning Manager
- J. Hammonds, Regulatory Compliance Supervisor
- B. Howard, Building and Grounds Foreman
W. Kirkley, Health Physics and Chemistry Manager
R. Mcginn, Nuclear Security
- C. Moore, Assistant General Manager - Operations
- J. Payne, Senior Engineer
- D. Read, Assistant General Manager - Plant Support
P. Roberts, Outages and Planning Supervisor
- K. Robuck, Manager, Modifications and Maintenance Support
L. Lawrence, Nuclear Specialist
- H. Sumner, General Manager - Nuclear Plant
J. Thompson, Nuclear Security Manager
- S. Tipps, Nuclear Safety and Compliance Manager
- C. Tyre, Operations Shift Supervisor
- P. Wells, Operaticas Manager
Other licensee employees contacted included technicians, operators,
mechanics, security force members and staff personnel.
NRC Resident Inspectors
- L. Wert
- E. Christnot
- B. Holbrook
- Attended exit interview
Sustained Control Room Observation Inspectors
R. Prevatte, Senior Resident Inspector, Brunswick Site
J. Munday, Resident Inspector, Browns Ferry Site
G. Harris, Region II Inspector
Acronyms and abbreviations used throughout this report are listed in the
last paragraph.
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2. Plant Operations (71707) (92701) (93702) i
a. Operations Status and Observations
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Unit 1 operated at 100 percent RTP until a manual scram was l
initiated at 5:44 pm CDT on October 22. The scram was caused by a
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loss of feedwater flow and is discussed in detail in paragraph 2c .
of this report. The unit was returned to criticality at 9:57 am j
on October 25. The turbine generator was placed on line and l
removed from service several times to support maintenance !
actiaties involving the MSR piping issue. Paragraph 2d discusses l
that issue. At 2:48 am on October 30, the generator was placed on ;
line and power was increased. At the end of the inspection period,
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repairs were still in progress on the MSR piping. The unit was i
operating at about 95 percent RTP with reheat steam supply [
isolated to the MSRs. ;
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Unit 2 operated at 85 percent RTP throughout the reporting period. [
Several control rods remain fully inserted to suppress neutron t
flux in the area of a suspected fuel leak. j
On October 31, during the routine shift from daylight savings time
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to standard, the CR clocks were shifted to eastern standard time. !
Previously, the CR has operated on central time in order to !
coordinate with facilities in Birmingham, Alabama. l
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Activities within the control room were routinely monitored. t
Inspections were conducted on day and on night shifts, during !
weekdays and on weekends. Observations included control room ;
manning, access control, operator professionalism and ,
attentiveness, and adherence to procedures. Instrument readings,
recorder traces, annunciator alarms, operability of nuclear
instrumentation and reactor protection system channels, r
availability of power sources, and operability of the SPDS were
monitored. CR observations also included ECCS system lineups,
containment integrity, reactor mode switch position, scram i
discharge volume valve positions, and rod movement controls. l
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During previous inspection periods, weaknesses in CR
communications had been noted. On October 5, 1993, while doing
the restoration portion of a special purpose procedure, a valve '
was incorrectly opened. The special purpose procedure was being
performed to determine plant thermal efficiency. Inadequate
verbal directions as to which valves to re-open had been provided ;
to a PEO. As a result, valve IPil-F1308, was incorrectly opened !
and water from the hotwell was diverted to the CST. The level in
the hotwell decreased from the normal level to 22 inches and CST i
level increased from 20 feet to 24 feet. The generator output
load was lowered to 685 MWe, approximately a 15 percent decrease
in reactor power, before valve IP11-F130B could be closed. This
is one example of inadequate CR communications which significantly
affected the plant. The inspectors noted that the procedure
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should have provided more specific guidance. Paragraphs 2c and 2d
of this report contain positive observations of operator actions
and communications during transients.
The inspectors obtained information necessary to complete a survey
as directed by regional management. The survey addressed the use
and controls of temporary leak sealant. The licensee has
established procedures for the application of temporary leak
sealants. The inspectors concluded that the licensee is
appropriately controlling and minimizing the use of sealants on
safety related equipment. The licensee used leak sealant on
safety related equipment only a very few times in the past 6 to 7
years. Additionally, the controls applied for temporary repairs
of leaks involving non-safety equipment were considered adequate.
Plant tours were taken throughout the reporting period on a
routine basis. The areas toured included the following:
Reactor Building Waste Gas Treatment Building
Diesel Generator Building Main Stack (lower elevations)
Fire Pump Building Transmission Switchyard
Central Alarm Station Intake Structure
Station Yard Zone Turbine Building
During the plant tours, ongoing activities, housekeeping,
security, equipment status, and radiation control practices were
observed. The inspectors noted that major housekeeping
improvement efforts continued in several areas of the plant.
During a tour of the switchyard relay house the inspectors noted
that numerous annunciators on the breaker control and mimic panel
were lit as though in an alarmed condition. This problem'had been
noted during previous tours and involves a component problem in
the annunciator lighting circuitry. The on-duty individual in the
switchyard explained that corrective action had been requested but
had not been implemented. The individual also demonstrated that
if the alarm condition actually occurred, the alarm would actuate
until acknowledged. The inspectors noted that the DC control
power systems in the relay house appeared to be well maintained.
No significant deficiencies were noted.
b. Improper Storage of Compressed Gas Cylinders
During this inspection period, NRC inspectors identified two
instances in which compressed gas cylinders were not prope.ly
secured. The first example was noted on October 18 and involved
an unsecured cylinder on the 185 foot elevation of the Unit I
reactor building. During-an introductory tour of the plant, one
of the inspectors who was onsite to observe CR operations
(paragraph 2e), observed the unsecured cylinder. The senior
resident inspector informed the Unit 1 SS of the problem and the
cylinder was immediately tied to a railing. Additional
information indicated that the cylinder was empty and had beca
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left standing upright outside the decontamination room to be l
decontaminated. l
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During a routine tour on October 28, the senior resident inspector :
identified an unsecured cylinder located at the personnel
radiation monitor at the refueling floor egress point in the RB. l
The cylinder contained gas at high pressure. The chain normally i
used to secure the cylinder had been broken. The inspector noted j
that the cylinder was in a location such that it could have been '
inadvertently bumped by personnel using the monitor. The !
inspector informed the HP technician assigned to the refueling !
floor of the problem. The technician immediately initiated action i
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to correct the problem. A few minutes later the inspector
encountered the AGM-Operations and informed him of the deficiency.
In addition to addressing the specific example, the AGM initiated
actions to ensure all cylinders onsite were secured.
Section 603 of the Hatch Nuclear Plant Safety Standards Manual !
addresses compressed gas cylinders. All employees are expected to j
understand and comply with this manual. Cylinders are required to ,
always be considered as full, labeled " empty" if appropriate, and -
secured in an upright position by wire, chain, or other suitable i
means. >
In the example involving the empty cylinder, the safety
significance is small. The inspector noted that the cylinder in ,
the RB was not prominently labeled as empty and it was in an area '
which contains safety related equipment. The location of the
unsecured pressurized bottle was such that it would have most
likely not damaged safety related equipment if it had fallen. The i
licensee identified one additional example of an improperly :
secured empty cylinder in the turbine building. The licensee's :
review identified that a total of 27 compressed gas cylinders were
located inside the plant, a number of which were empty. The
licensee initiated steps to remove unnecessary cylinders from the i
buildings.
The inspectors routinely examine compressed gas cylinders in or
near safety related structures or equipment. No deficiencies have
been identified in the past several years involving improperly i
secured bottles. The examples noted did not have a significant i
potential to effect safety related equipment and the licensee took
prompt and effective corrective actions. The inspectors will ,
continue to closely monitor the storage of compressed gas I
cylinders.
c. Unit 1 Manual Scram on Loss of Feedwater Flow ;
Hatch Unit I was manually scrammed from full power on Friday, 1
October 22, 1993, at 5:44 pm CDT. During operation at full rated ;
power, all three condensate pumps tripped, resulting in a loss of ;
feedwater. Reactor water level rapidly decreased from +37 inches
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(normal level) and the operators manually scrammed the reactor
when level was approximately +20 inches. The automatic scram l
setpoint is +10 inches (top of the fuel is at approximately -165 i
inches). All rods fully inserted. The recirculation pumps
tripped as expected. HPCI and RCIC automatically actuated and
injected water into the vessel. The lowest reactor water level :
observed was about -52 inches. All safety systems performed as ;
required during the transient. ;
Despite focused efforts by the operators to restart the f
recirculation pumps, stratification of the water in the vessel ;
occurred before the pumps could be started. Temperature ;
restrictions delayed the restart of the recirculation pumps and a ;
cooldown was necessary. Extensive efforts, including operation '
of the shutdown cooling system were required to attain the :
temperatures to restart the pumps. The pumps were restarted at
approximately 11:00 am CDT on October 24. This has been a ,
recognized problem at Hatch and in previous instances, violations i
of the temperature limits have occurred. With the exception of i
the initial transient, no temperature limits were exceeded during ;
this recovery. l
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Even though the ERT's investigation had not been concluded at the F
end of the inspection period, the most likely cause for the trip 5
of the condensate pumps was a faulty hotwell level switch or
circuit. This level switch was the only single failure mechanism .
that would cause simultaneous tripping of all three pumps. The 1
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ERT made several recommendations to prevent a similar occurrence.
One of the recommendations was to remove the condensate trip ,
signal from the hotwell level switch. Following discussions with ;
the pump vendor, the level switch trips were temporarily disabled.
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Removal of the pump trips are being further evaluated prior to -;
Hatch has experienced other
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becoming a permanent change.
unnecessary scrams due to failures in balance of plant equipment.
It has been noted in previous reports that Hatch has not been
vigorous in the area of scram frequency reduction. The licensee 5
commenced restart of the unit at 3:45 am EDT on Monday,
October 25.
One of the inspectors responded to the site following the scram !
and observed activities in the CR. The inspector verified ECCS
and PCIS systems responded as required. Additionally, the
inspector verified reactor and containment parameters were correct i
for the unit condition. The inspector verified that the operating
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crew used the reactor scram procedure and entered the E0P flow
chart as required. Reactor water level was being maintained by *
RCIC and later by the CRD system. It was noted that the operators
were using system operating procedures and ARPs as necessary. The ,
SOS gave frequent updates for the operating crew and provided :
direction for operations, maintenance and other investigative :
activities. The Assistant General Manager-0perations was also :
onsite and provided immediate support for shift activities. The #
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(normal level) and the operators manually scrammed the reactor ;
when level was approximately +20 inches. The automatic scram ,
setpoint is +10 inches (top of the fuel is at approximately -165
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inches). All rods fully inserted. The recirculation pumps
tripped as expected. HPCI and RCIC automatically actuated and
injected water into the vessel. The lowest reactor water level !
observed was about -52 inches. All safety systems performed as ,
required during the transient. l
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Despite focused efforts by the operators to restart the !
recirculation pumps, stratification of the water in the vessel
occurred before the pumps could be started. Temperature i
restrictions delayed the restart of the recirculation pumps and a ,
cooldown was necessary. Extensive efforts, including operation ;
of the shutdown cooling system were required to attain the i
temperatures to restart the pumps. The pumps were restarted at
approximately 11:00 am CDT on October 24. This has been a
recognized problem at Hatch and in previous instances, violations ,
of the temperature limits have occurred. With the exception of
the initial transient, no temperature limits were exceeded during
this recovery.
Even though the ERT's investigation had not been concluded at the
end of the inspection period, the most likely cause for the trip
of the condensate pumps was a faulty hotwell level switch or
circuit. This level switch was the only single failure mechanism
that would cause simultaneous tripping of all three pumps. The :
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ERT made several recommendations to prevent a similar occurrence.
One of the recommendations was to remove the condensate trip ,
signal from the hotwell level switch. Following discussions with
the pump vendor, the level switch trips were temporarily disabled. '
Removal of the pump trips are being furtner evaluated prior to !
becoming a permanent change. Hatch has experienced other i
unnecessary scrams due to failures in balance of plant equipment. l
It has been noted in previous reports that Hatch has not been i
vigorous in the area of scram frequency reduction. The licensee
commenced restart of the unit at 3:45 am EDT on Monday, October .
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One of the inspectors responded to the site following the scram
and observed activities in the CR. The inspector verified ECCS l
and PCIS systems responded as required. Additionally, the
inspector verified reactor and containment parameters were correct
for the unit condition. The inspector verified that the operating I
crew used the reactor scram procedure and entered the E0P flow i
chart as required. Reactor water level was b.eing maintained by
RCIC and later by the CRD system. It was noted that the operators
were using system operating procedures and ARPs as necessary. The
SOS gave frequent updates for the operating crew and provided
direction for operations, maintenance and other investigative
activities. The Assistant General Manager-Operations was also
onsite and provided immediate support for shift activities. The
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inspector also observed the initial efforts of the scram ERT
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including review of SPDS tapes. The inspector concluded that the l
operators had performed well during the loss of condensate and
feedwater transient. Communications and procedure usage were '
adequate and supervision and management provided necessary
oversight. During the efforts to recover the recirculation pumps,
the operators were particularly sensitive to temperature
restrictions. The licensee is continuing efforts to address the
recicculation pump restart restrictions.
d. Reactor Vessel Level Control Syst?m Transient and Damage to MSR
Drain System
During the Unit I startup on October 26, at about 6:15 am EDT, a
loss of feedwater control event occurred. The reactor was at.
about 6 percent power. One of the inspectors was in the CR and
observed the transient. During repair activities to a CR chart
recorder (IC32-R609; Reactor Pressure / Turbine Steam Flow), a fuse
blew. The N se supplied power to the channel B level transmitter
of the reactor water level control system. The operators
immediately recognized that the channel B level indicator was
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indicating downscale while channel A was indicating a rapid
! increase in water level. There was an increase in water flow to
l the reactor from the feed pump. The actions taken by the
operators i..cluded immediately shifting control of the feed pump
to manuai, decreasing the feed water flow to the reactor vessel,
monitoring the plant conditions and adequately acknowledging
alarns as they were received. The highest level observed by ti.e
incpector was approximately 53 inches. The inspector observed
good communications during the event,-directions to operators were
concise, understandable and given in a calm manner. The inspector
concluded from this observation that the operators maintained an
awareness of the plant conditions at all times during the event
and responded well. It was also noted that the recent upgrading
of the feedwater flow controllers reduced the severity of.the
transient. The new controllers automatically switched to " single
element" control (as designed) on the loss of feedwater flow
signal.
Later that afternoon, shortly after the MSRs were placed in
operation, a loud noise and a large amount of steam was reported
in the turbine building condensate bay. ._The operators immediately
lowered turbine power and commenced isolating the MSRs.
Subsequently, it was theorized that a water hammer may had
occurred involving the C and D MSR second stage drain line to the
SB high pressure feedwater heater. Three valves were identified
as being damaged by the piping movement. Several supports were
also damaged. The licensee initiated an ERT to review the event.
One of the inspectors was in the CP. immediately after the event
occurred. Just prior to the event, the inspector had noted that
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the operators were performing the plant startup in a cautious and
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deliberate manner. The inspector reviewed the procedures
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involved, 34G0-0PS-001-15, Plant Startup Unit 1, and 34GO-0PS-042-
IS, MSR, Extraction Steam and Heater Sher! Drafa. Section 7.1 of :
procedure 34G0-0PS-042-15 directs the operators in placing the !
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MSRs in operation. This section contains steps to open valves, !
cautions on heatup or cooldown rates, and requires confirmation of
system component responses. The inspector noted that the
procedure directs the operators to confirm that the low level r
alarms for the MSR drain tanks are cleared, but does not mention l
the high level alarms. The inspector discussed this observation
with licensee management. The licensee was in the process of l
completing repairs and evalusting the cause of the event at the '
end of the report period. The inspectors will continue to review :
and monitor the licensee's activities in this area.
e. Sustained CR Observations (71715) (71707)
(1) Purpose and Scope of Observation
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Although a decline in overall CR operations performance had
been observed earlier this year, in recent months the
resident inspectors have noted general improvement. Several
examples of strong operator actions during transients or
problems have been observed. In order to further assess the
effectiveness of the licensee's corrective actions, a
sustained CR observation inspection was conducted. During
the period of October 18 to October 22, three inspectors
observed CR operatiens on a continuous (24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) basis. ,
Inspection Module 71715 and a detailed checklist for CR ,
observations were used to conduct the observation. The '
, following paragraphs describe some of the observations and
the resulting conclusions.
(2) Control Room Manning, Turnovers, and Briefings
Shift manning exceeded the requirements of TS 6.2.2 and TS 1
Table 6.2.2-1 on each of the observed shifts. Discussion
with shift personnel indicated that the shifts are routinely '
staffed with a sufficient number of personnel and overtime ,
was not routinely relied upon to meet staffing requirements !
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or to accomplish assigned work. On two occasions _during one
shift, there were no SR0s present in the controls portion of i
the CR. In both instances, the SR0s were not away from the l
panels for work activities, but rather for meals or breaks.
Step 8.6.7 of 30AC-0PS-003-05, Plant Operations, states that ;
a licensed SR0 shall at all times be in the main control !
room. The main control room includes the areas of the
control panels, relay control cabinets, Operations
Supervisor's Office, kitchen and the chart room. When ;
questioned, the SOS stated that expectations were that at !
least one licensed SRO be in the control room, in view of
the panels, at all times. The inspectors concluded that the :
expectations regarding the intent of the shift manning ;
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requirements need to be clearly communicated tr on-shift
personnel. The inspectors noted that, at all times, a
licensed operator was in the controls section of the CR.
The inspectors observed virtually all shift turnovers during ;
the observation period. The applicable turnover check
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sheets were completed. The inspectors noted that the actual
turnover of the R0s was accomplished very rapidly. For ,
example, it was observed that the morning turnovers on !
Unit 1, on October 20, wi.re accomplished in approximately 5
minutes. On October 21, the Unit 2 R0 turnover lasted
approximately 4 minutes. The required control board and i
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back panel walkdown was accomplished in 3 minutes and 25
seconds. The operator, when questioned by the inspector ;
about the short turnover, indicated that nothing had changed
and he did not want to hold up the offgoing operator since .
he had been on shift for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and needed to go home. '
Another inspector observed a turnover which involved a shift
that had been off for four days. It was concluded that
little information was exchanged with the oncoming CBO. Nc ,
notes were taken by the oncoming CBO. Walkdown of the
panels took approximately 5 minutes. t
Many shift turnover briefings were attended. The briefings
appeared to cover most of the important plant and equipment ,
, status and problems, events that had occurred in the !
previous shift, planned activities, and other administrative ;
items. The inspectors _noted that in some areas the
briefings did not communicate as much information as '
4 expected. Standing Orders were referenced as being new and :
needing to be read by'the shift, however no details were !
discussed. During several briefings, it was noted that only :
minimal emphasis was placed on procedural errors involving a ,
HPCI surveillance on a previous shift. An event which !
involved a blown fuse on Unit I was also not discussed.
Additionally, the inspectors noted that few questions were !
asked during the briefings. Some individuals were eating :
and did not devote full attention to the briefing. !
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On October 20, one inspector attended the 7:30 am management !
meeting and an Operations / Maintenance meeting. The meetinas .
were brief, but adequately covered plant status, problems i
and planned activities.
The inspectors noted that during routine activities the
operators were attentive to their control boards; used
" repeat back" communications to turn over their duties if
they left the "at the controls area," were responsive to
annunciators, and responded satisfactorily to any plant
event. The shift supervisors appeared to be very absorbed
in administrative activities, especially during the hours of
7:30 am until approximately 2:00 pm. During major
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surveillance tests, the SS usually placed these
administrative tasks on hold and supervised portions of the ,
activity.
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(3) Annunciator Controls, TS Interpretations, and LCO Logs ;
The annunciator logs for Unit I and 2 were reviewed. It was l
noted that monthly audits are being performed. Items that~
are older than 3 and 6 months were identified to operations
management. Items which require compensatory action are j
separately identified and tracked. The units are operated :
using a " black board" concept. There were several
annunciators with pulled cards, but they were well !
documented. All of the inspectors noted that the Hatch CR -
had very few lighted and/or disabled annunciators. The
inspectors concluded that licensee management strongly ;
supported the efforts to maintain a " black board." ';
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The inspectors reviewed the TS " clarifications" i'
(interpretations) for Units 1 and 2. It was noted that
there were approximately 20 in effect for Unit I and about
13 for Unit 2. This number was considerad excessive. ,
However, Hatch is the lead plant for the improved BWR '
Standard TS and is expected to submit those TS for approval ;
in early 1994. Because of the effort toward the improved
TS, the licensee has not been submitting TS changes unless ;
they are necessary for proper plant operation. l
The inspectors reviewed the LCO logs on October 20, and l
noted that 10 LCOs were in effect for Unit I and 12 for *
Unit 2. A large number of these involved Kaowool and s
Thermolag issues. Most of the other items appeared to be l
those which will require an outage for repairs. Appropriate ,
compensatory measures had been established for the above -
items. One example of weak SR0 knowledge of a TS was noted i
involving torus water level indications. The shift .!
supervisor had difficulty explaining the specific TS !
requirements for the instrumentation to the inspector.
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(4) Conduct of Surveillance Testing
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Several surveillance tests were observed. While observing
the performance of 345V-E41-002-25, HPCI Pump Operability !
Test, the inspector noted two examples in which the !
procedural requirements were not followed. The operator lt
performing the testing in the CR did not perform step
7.2.39.3. This step throttles valve 2E41-F008 (test line to ;
CST), until valve 2E41-F012 (minimum flow valve) opens. ;
This verifies that the minimum flow valve will actually open. l
when called upon to do so. When the inspector questioned :
the operator as to why the step had not been performed, the !
operator stated that he had missed it. After discussions.
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with the Shift Supervisor, it was decided to perform
portions of the test again in order to complete the missed
step. The HPCI turbine was restarted and upon reaching
speed, 2E41-F008 was throttled and 2E41-F012 opened as -
expected. The turbine was tripped and appropriate
verifications made. After the system was shutdown, the
inspector identified another deficiency. The inspector '
observed that valve 2E41-F0ll (test return to the CST), was
still open. The inspector reviewed the operators procedure
and noted that step 7.2.39.14, which requires the valve to
be shut, was signed as completed. The inspector questioned ,
the operator and the operator subsequently. shut the valve.
This was the second example of this operator not adhering to
the procedure. The Unit I shift supervisor was immediately
informed of the observed problems. Of particul'_r concern
was the fact that the operator did not note the deficiencies
until the inspector identified them. The failure to conduct i
the testing in accordance with the procedure is a violation
of TS 6.8.1. This issue is identified as Violation 50-366/
93-24-01: Failure to Follow Procedures During HPCI Testing. [
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The performance of 34SV-E51-002-25, RCIC Pump Operability
Test, was observed. The inspector noted that the R0
verified the correct revision of the procedure was used and
all prerequisite were completed prior to the test. A
detailed briefing was held with the PE0s assisting with the ,
test, and the assigned system engineer was contacted and '
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participated in the surveillance. It was noted that the
operator reviewed the procedure prior to the test and '
highlighted a copy of all steps that would be performed by -
the PEOs. The surveillance test was well performed and the
operator was cautious and continually checked to ensure that
all steps were being accomplished correctly. The operator
who conducted the test exhibited a high level of attention "
to detail.
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While the failure to operate the HPCI system in accordance
with procedures is significant, the inspectors did not ;
identify any additional examples of failures to follow ,
procedure during the observation period. The inspectors ,
concluded that this was an isolated case of an individual
operator not complying with procedures. j
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, (5) Clearance Records, Temporary Modifications, Key Controls, i
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and Operating Orders.
The inspectors reviewed the clearance logs for both units, !
paying particular attention to those requiring independent '
verification. The inspector verified that the appropriate
reviews and authorizations had been completed. No i
discrepancies were noted. !
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The inspectors reviewed the Temporary Modification / Lifted .
Leads log for both units. One item involving the Unit I
drywell cooler auto start circuitry was questioned. The
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documentation did not contain a 10 CFR 50.59 review. When
the SS was questioned he first stated that since the coolers
were safety related, a 10 CFR 50.59 review should have been
conducted. However after further review, it was determined !
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that a 10 CFR 50.59 review was not required. The inspectors
verified that the System Evaluation Document, which
describes the safety function of all safety related ,
equipment, supported the conclusion that the modification
did not effect a safety function. i
One of the inspectors reviewed the key controls for the
operations department. Several administrative deficiencies
were noted. The index had not been revised to incorporate ,
changes made since December of 1991. The failure to
periodically revise the index led to inaccuracies in the ,
index. As an example, the index had not been updated to
reflect the fact that the keys used to gain access to the ,
E0P gang boxes had been changed. The inspector discussed :
this discrepancy with the licensee who later verified and
corrected the error. After verifying the accuracy of the
records through a sampling of keys, the inspector concluded
that the licensee's key control program is adequate.
A review of the licensee's operating orders was conducted.
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These orders are short term directives issued by the manager
of operations that have special applications for plant
operations or equipment. Section 8.17 of 30AC-0PS-003-05,
Plant Operations, requires that the SS for each unit :
maintain a book of active operating orders for that unit. >
The inspector reviewed these books for each unit and found 1
they contained the required active orders. The inspector ,
also verified that required safety reviews of the orders .
were conducted within the 14 day time limit. Step 8.17.15 l
required that the Unit Superintendent or designated '
alternate review, on a monthly basis, the operating orders '
that are greater than one month old. Although the inspector
noted that there was no record of a review being conducted
during March of this year, it was concluded that the overall 1
control and implementation of operating orders were
adequate.
(6) Attention to Indications, PE0 Rounds, and Response to
Unexpected Events.
One of the inspectors questioned the Unit 2 operators about
. the offgas prefilter and postfilter d/p. The indicated d/p
was less than 0 psid. The operators were aware that the
postfilter had no internals due to an engineering concern
about breakthrough some years ago (the filter material was-
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removed by a modification). The operators did not know why ,
the prefilter had a negative reading, but indicated that the j
indication was not unusual. Additionally, one of the
inspectors noted that the controllers for the RHR HX level
control (2 Ell-R604B), were not in the position required by .
procedure. Procedure 34S0-Ell-010-2S requires the ,
controller tape be positioned at 100%. The A controller was ,
set at position 120 and B at position 100. The controller's !
available tape setting ranged from 0 - 200. When ;
questioned, several CR personnel differed in their i
understanding of what 100% meant. It was not known if the
requirement was for 100 on the tape or full scale on the
tape. The inspector noted that the Unit I tapes were set at
100% full scale. After discussions, it was decided to set ,
the tape at full scale and to inform the procedure writers -
'
to clarify the procedure. E0P 31E0-EOP-Il3-25, Terminate
and Prevent Injection to the RPV, contained a handwritten
cnange. The page was stamped " Typed Copy to Follow." This
condition has apparently existed since November 1991. ,
A PE0 was accompanied on daily inside rounds in the Unit 2
RB. Although the performance of the rounds by the operator ,
was adequate, the inspector noted that the emphasis during '
the round was not so much to gather information on overall '
plant conditions, but to simply complete the required logs
as directed by the electronic round tracking system. For !
example, the oil contained in the bubbler for a CS/RHR
system jockey pump was noted to be discolored. At the time
of this inspection, a deficiency card had not been submitted
on the oil.
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One of the inspectors observed operator actions when CR and
local annunciators for the hydrogen seal oil and stator
water cooling trip and alarm circuitry were disabled due to
blown fuses. The fuses blew during a ror.ine indicating-
lamp change-out by a PEO. The PEO, conducting rounds in the
control building, noticed that an indicating-lamp on panel '
IN43-P001, was not lit. The indicating-lamp provides local
indication of alarm and trip circuitry status. 34G0-0PS-
0301S, Daily Inside Rounds, requires-that the plant '
equipment operators change out burnt-out indicating lamps.
The operator removed the installed lamp and replaced it with !
a similar lamp. Two fuses which supplied DC power to the i
alarm and trip circuitry blew. The loss of DC power- l
subsequently caused CR annunciators to actuate. Shift ]
supervisory personnel referenced abnormal procedure 34AB-
Hil-001-25, Loss of Power to Annunciators for the Main
Control Room, and developed compensatory measures to handle
the problem. Although a subsequent investigation by
electrical technicians discovered the blown fuses, they were
not immediately replaced because it was not clear what
effect this would have on the circuitry. After an
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evaluation by engineering personnel the fuses were replaced. 1
Subsequently, it was determined that the PE0 had replaced !
the burnt-out bulb with a bulb that had a different voltage ;
rating. The inspectors observed a portion of the licensee's '
stock of spare bulbs and noted that some manufacturers had .
not prominently labeled the voltage and wattage ratings on !
the bulbs. Bulbs of significantly different ratings were l
identical in physical appearance and close examination was :
i necessary to distinguish the capacities. Although this- l
incident occurred on non-safety related equipment, it is an ;
example of inadequate attention to. detail. A similar
mistake in a safety related circuit could have more l
significant consequences. The inspectors concluded that the '
compensatory actions were appropriate and timely.
l (7) Conclusions
Based on the observations, the inspectors concluded that the l
overall performance of the CR operators was satisfactory. :
Strengths were noted in several areas. The CR was clean, !
, generally uncluttered, and well organized. There were few
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control board instruments out of service. All of the
inspectors noted that the noise level in the control room
was maintained at a very low level and access was well
controlled. Logs, records, and other materials were
returned to storage after use. Additionally, the inspectors
noted that the use of the public address system was well
disciplined. The overall level of use of the public address
system was very low compared to other plants. Annunciator
controls were very strong. Good performance was noted in
several pecific areas in which weaknesses had previously
been identified. Operators were attentive to alarms and
used alarm response procedures. A high level of operator
professionalism was displayed. No horseplay or excessive
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chatter was noted. Operators were observed to be alert to
I their duties. Rith the exception of the HPCI surveillance
test example, operators followed procedures during
evolutions.
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There were some areas in which the inspectors concluded that i
i performance could be improved. Operators did not exhibit a '
questioning attitude about some CR indications. Some ,
turnovers and briefings were not appropriate-to support '
strong operation. In general, there was a sense that SR0 l
oversight should be stronger. The observed weaknesses in i
turnovers and briefings are examples in which enforcement of l
higher expectations by the SR0s could improve performance. '
The inspectors also concluded that some R0's knowledge level
of TS was not as strong as expected. Additionally, the
licensed operators exhibited a general lack of knowledge on
some recent industry events. Examples included; the Grand
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Gulf jet pump rams head failure, bistable recirculation :
flow, and other issues at BWRs.
The inspectors briefed plant management on the results of
the observation period on October 21, 1993.
One violation was identified. i
3. Surveillance Testing (61726) l
a. Surveillance Observations
Surveillance tests were reviewed by the inspectors to verify j
procedural and performance adequacy. The completed tests reviewed ;
were examined for necessary test prerequisites, instructions, !
acceptance criteria, technical content, authorization to begin
work, data collection, independent verification where required,
handling of deficiencies noted, and review of completed work. The
tests witnessed, in whole or in part, were inspected to determine ,
that approved procedures were available, test equipment was l
calibrated, prerequisites were met, tests were conducted according ,
to procedure, test results were acceptable and systems restoration
was completed.
The following surveillances were reviewed and witnessed in whole
or in part: .
1. 34SV-E41-002-2S: HPCI Operability Test
2. 345V-E51-002-25: RCIC Pump Operability Test- ,
3. 57CP-CAL-271-IS: Core Flow Measurement Instrument Calibration I
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Paragraph 2e'of this report discusses the HPCI and RCIC testing in' I
detail. The core flow measurement instrument calibration is
discussed in paragraph 3b. j
b. Core Flow Measurement System Testing l
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During observation of 57CP-CAL-271-IS: Core Flow Measurement
Instrument Calibration, the inspector questioned the method used l
for one portion of the testing. Section-7.5.18 of the procedure ;
contains directions for checking the output of the flow-units. _
The flow units provide signals representative of jet pump flow and >
are used for total core flow measurements. The inspector noted ]
that the voltage (output of flow unit) being compared to a !
" reference" voltage was oscillating significantly, but was i
supposed to be within 0.005 V DC of the reference value. Because
the testing is performed at power, the flow signals will normally
be unsteady. The technicians performing the test did their best
and selected an " average" voltage value. The inspector questioned
the usefulness of this method of testing. It appeared that a
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small difference in the output versus the reference (0.005 V DC)
would not be detected (as required by the procedure).
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The I&C technicians and management reviewed the testing and 1
pursued a more u;eful methodology. The testing procedure had been '
developed in accordance with guidance provided by GE. After
review of the issue and discussion with GE, a different method of
testing was proposed. The purpose of the portion of the testing ;
in question was to check the operation of four operating 4
amplifiers that provide core flow output signals to the flow
network. The licensee determined that instead of obtaining an -
input voltage and then comparing it to the output values, a direct +
check across the amplifier was more appropriate. The test
procedure is being revised to include that method. The inspectors :
concluded that the licensee was responsive to the observations and
is pursuing improvements in the effectiveness of the testing.
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No violations or deviations were identified. ;
4. Maintenance Activities (62703) ;
a. Maintenance Observations ;
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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 that was not within the skill of the trade. Activities, l
procedures, and work requests were examined to verify proper ,
authorization'to begin work, provisions for fire hazards, ;
cleanliness, exposure control, proper return of equipment to !
service, and that limiting conditions for operation were met.
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The following maintenance activities were reviewed and witnessed ,
in whole or in part: ;
1. MWO 2-93-4052: Rod Block Monitor 2A ,
2. MWO 2-93-4170: Rod Block Monitor 2B ,
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3. MWO 2-93-0777: Change PSW Strainer Alarm Setpoint From 5
psig Increasing to 8 psig Increasing ;
4. MWO 2-93-0778: Change PSW Strainer Alarm Setpoint From 5
psig Increasing to 8 psig Increasing ;
5. MWO 1-93-3482: Reactor Building Chilled Water Chillers
The inspectors did not identify any problems during the !
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. observation of these maintenance activities. Paragraph 4b of this
report discusses the Rod Block Monitor maintenance.
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The inspector had previously identified a concern involving fuel f
line (copper tubing) supports on the IA, 1C and IB EDGs. This ;
concern had been raised after a walkdown of all five EDGs. It had 1
been noted that all the tubing runs for the 2A and 2C EDGs were !
clamped to supports and some of the tubing runs on the 1A, 1C and ;
IB EDGs were not. This concern was discussed with the licensee.
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The inspector examined the five EDGs and noted that the copper '
tubing runs for all the EDGs were now clamped to supports.
b. Rod Block Monitor Troubleshooting and Repairs l
The inspector monitored and reviewed activities involving the Rod
Block Monitors. These included trouble shooting, site engineering
activities and GE involvement. The activities were performed over l
several weeks and ultimately resulted in the identification of an _I
electrical noise problem. The noise was detected in electrical l
cable CAX 83C32 and was a 800 KHz radio frequency of approximately i
3 volt magnitude. The options discussed included replacing the
cable or installing a filter in the Unit 2 RBM to abate the noise. i
The licensee decided to install a capacitive filter in the null
sequence initiator card of the RBM, located in CR panel 2H11-P608.
The installation activities were controlled by TM 2-93-72. The TM
l. received adequate engineering and PRB reviews and approvals. The
i inspector reviewed the TM and concluded that the installation was
accomplished in accordance with the site approved process. It was
" noted that if the filter opened or short circuited, the RBM would
be inoperable and the action statement of TS 3.1.4.3 (Reactivity
Control Systems, RBM) would apply.
The inspector performed additional reviews and held discussions
with onsite engineering personnel. It was noted that previous
electrical noise problems involved an offgas radiation monitor and
the APRM/LPRM monitoring lights. The licensee had corrected those
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problems by ungrounding one end of the radiation monitor detector !
I cable and installing diodes in the APRM/LPRM monitoring lights. i
The inspector's review did not identify any concerns with these i
corrective actions. The site engineering consensus concerning i
these problems involved grounding the plant systems to earth. '
Work activities were previously completed in this area and i
additional work may be performed.. The inspector will continue to -!
monitor the licensee's activities.
No violations or deviations were identified.
5. Incorrect Liquid Effluent Radiation Monitor Setpoint (84750) (71707)
On October 28, the licensee. informed the inspectors that a TS violation,
concerning a liquid effluent release, had occurred on October 27, 1993.
A chemistry technician, performing a post relecse review of the liquid
effluent release permit, identified tMt the effluent monitor trip
setpoint had been set higher (less conservative) than required. The
technician informed chemistry management and an investigation was
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initiated. The licensees investigation determined that a personnel !
error occurred when computer data entry was entered into the computer
from a chemistry department form. The computer program used sample
analysis data from the tank to be released plus the radiation background i
reading of the liquid effluent radiation monitor to calculate the. !
effluent monitor trip setpoint. In this instance, the technician
inserted the tank estimated volume (gallons) instead of the effluent
radiation monitor background radiation. This resulted in the computer "
program generating an incorrectly high liquid effluent monitor trip
setpoint. The chemistry foreman's review of the prerelease permit i
failed to identify the discrepancy. TS 4.15.1.1.2 states that the l
results of radioactive analysis shall be used in accordance with the !
methods of the ODCM. Section 1.1 of the ODCM states that the radwaste
effluent radiation monitor backgrcunu .:hould be added to the calculated
setpoint to determine the actual efflunt monitor trip setpoint.
The inspectors conducted an independent review of procedures 64CH-RPT-
004-05, Liquid Effluent Reports, 64CH-ADM-002-0S, Chemistry Forms, TS section 4.15.1.1.2, Radioactive Effluents, and portions of the Hatch
ODCM. Also, the inspectors conducted interviews with chemistry
management and operations personnel. The inspectors verified that the i
actual radioactivity level of the release was considerably below the "
correctly calculated effluent monitor trip setpoint and no 10 CFR Part
20 limits were violated. The inspectors noted that the actual setting l
of the radiation monitor trip was conservative in relation to the r
incorrectly calculated value. The radwaste operators indicated that the ;
settings are usually set below the calculated value because it is i
difficult to accurately set the trip. The trip is set by using a small
log scale indicator. The inspectars reviewed the licensees short and
long term corrective. actions and determined they were appropriate and ^!
timely. The corrective actions included counseling of the involved
technician and foremen. A chemistry department letter was sent to all 3
supervisors and foremen ~ explaining the event. This letter was used to l
brief chemistry department employees. The event was reviewed, in a ;
classroom setting, for chemistry employees that were in training. Also,
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the event was reviewed during shift turnover meetings. Additionally, !
chemistry supervision stated that the computer program that calculates {
the release permit will be evaluated for possible self check ;
applications for future reports. This issue will not be subject to !
enforcement actions because the licensee's efforts in identifying and )
correcting the violation meet the criteria in Section VII.B of the
Enforcement Policy for non-cited violations. This issue.is identified
as NCV 50-321,366/93-24-02: Incorrect Liquid Effluent Radiation Monitor j
Setpoint. j
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One NCV was identified. l
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6. Inspection of Open Items.(92700) (92701) I
The following items were reviewed using licensee reports, inspections, i
record reviews, and discussions with licensee personnel, as appropriate:
a. (Closed) LER 50-366/92-10: Condensation in Instrument Sensing
Lines Results in Noncompliance with TS. This LER addressed an
event on May 15, 1992, when operators noted.that the drywell
pressure indication was reading low by 0.18 psig. The licensee
determined during followup review that this difference affected a
TS set point trip of less than or equal to 1.92 psig. The 3
licensee initial corrective action was to purge the instrument !
sensing lines of any condensation using nitrogan and performing ,
comparison checks of Unit 2 drywell pressure instrumentation ,
readings. The final corrective actions included implementing MW0s i
2-92-3267, 3268, and 3300, which were issued on November 5, 1992, ,
to correct the instrument sensing line slope. Based on these
actions this LER is closed. !
b. (Closed) LER 50-366/92-15: EHC Leak Prompts Manual Scram with
Scheduled Shutdown in Progress; LER 50-321/92-24: Manual Scram
Due to High Main Turbine Vibration Caused by Component Failure;
and LER 50-366/92-28: Component Failure Results in HPCI System
Inoperability. These LERs addressed reportable occurrences
involving component failures. These failures included a switch on
a MSR, a relay in the HPCI inverter and EHC leak affecting the
main turbine bypass valves. In each case the licensee replaced
and/or rep-ired the failed component, performed worse case ,
evaluations and initiated adequate immediate and temporary l'
measures. These measures included disabling a HPCI alarm until
the inverter relay could be replaced and immediately scramming the ;
reactor due to the EHC leak. The events were addressed in detail !
in previous reports. Based on the inspector's review of the
events and the actions taken by the licensee, these LERs are
closed. ;
c. (Closed) LER 50-366/92-16: Radiography Results in Unplanned ESF
Actuation. This LER addressed an ESF actuation which occurred
during a Unit 2 refueling outage. The cause of the ESF actuation
was due to radiography being performed on a weld approximately 50- :
feet from radiation monitoring detectors. The strength of the :
radiography source was calculated to have caused a radiation field -
of approximately 135 mr/hr in the area of the radiation monitors. l
The monitors trip setpoint was 9.5 mr/nr_for the reactor building ;
exhaust ventilation system. Corrective actions included notifying i
control room personnel that radiography is scheduled to be >
performed and if any radiation monitoring systems will be ;
affected. Based on this action this LER is closed. j
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d. (Closed) LER 50-366/92-21: Drawing Errors and Personnel Errors
Result in ESF Actuation. This LER addressed an event that '
resulted in an ESF actuation while Unit 2 was in a refueling
outage with all fuel removed from the vessel. Additional
discussion of this item are in IR 50-321,366/92-34. The
corrective action included issuing an as-built notice against the
drawing of concern; counseling the design engineers with regard to
the need for attention to detail in reviewing the as-built
configuration of the plant; and counseling the design
implementation engineers with regard to the need to review issued -
DCRs to ensure accuracy of as-built conditions on which the design
change is based. Also included was training for the engineers on
this event with an emphases on the need to verify the accuracy of
the as-built condition of plant systems. Based on these actions .
and the discussion in IR 50-321,366/92-34, this LER is closed. l
e. (Closed) LER 50-366/92-23: Personnel Error Causes Unplanned .ESF
Actuation; and LER 50-366/92-26: Main Turbine Trip on High
Vibration Results in a Reactor Scram. These LERs addressed
reportable occurrence involving jumpering out contacts in the j
wrong panel during a LOCA/LOSP logic functional test and failure j
to monitor main turbine vibration while the high vibration alarm '
was masked. The events were addressed in detail in irs 50- l
321,366/92-32 and 50-321,366/92-34. The corrective actions
included counseling the personnel involved with the errors and a
change to the alarm system such that the MFP high vibration alarms ,
do not mask the main turbine high vibration alarms. Based on the !
completion of these actions and the inspectors reviews, these LERs
are closed.
f. (Closed) IFI 50-366/92-29-02: Inspection of Unit 2 Shroud Access
Hole Covers. This item was opened to document the corrective
actions taken to address the shroud access hole covers in Unit 2.
The hole covers were replaced in Unit 1 as documented in IR 50-
321,366/93-06. The Unit 2 access hole covers are different from i
the Unit I covers and the methodology of the Unit 2 repairs have i
not been determined. The licensee has made arrangements for the !
covers to be investigated during the upcoming refueling outage.
The inspector will continue to monitor the vendor's and licensee's
activities in this area. Based on this review, this IFI is
closed.
7. Exit Interview j
The inspection scope and findings were summarized on November 4, 1993,
with those persons indicated in paragraph I above. The inspectors who
performed the sustained CR observations briefed plant management on
their observations on October 21. 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
or reviewed by the inspectors during this inspection.
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Item Number Status Description and Reference
50-366/93-24-01 Open VIO - Failure to Follow Procedures *
During HPCI Testing, paragraph
2.e(4).
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50-321,366/93-24-02 Open and NCV - Incorrect Liquid Effluent ;
Closed Radiation Monitor Setpoint, j
paragraph 5. j
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8. Acronyms and Abbreviations (
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AGM-PO- Assistant General Manager - Plant Operations
AGM-PS- Assistant General Manager - Plant Support i
APRM - Average Power Range Monitor l
ARP - Alarm Response Procedures !
ATTS - Analog Transmitter Trip System :
BWR - Boiling. Water Reactor l
BWROG- Boiling Water Reactors Owners Group l
CB0 - Control Board Operator ;
CDT - Central Daylight Time i
CFM - Cubic Feet Per Minute ;
2 CFR - Code of Federal Regulations l
CR - Control Room :
CRD - Control Rod Drive !
CS - Core Spray .
CST - Condensate Storage Tank 1
DC - Deficiency Card ;
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DCR -
Design Change Request )
d/p - Differential pressure
DW - Drywell *
ECCS - Emergency Core Cooling System
EDG - Emergency Diesel Generator ;
EHC - Electro Hydraulic Control System i
E0P - Emergency Operating Procedures l
ERT - Event Review Team i
ESF - Engineered Safety Feature !
EST - Eastern Standard Time i
F - Fahrenheit i
FSAR - Final Safety Analysis Report !
F/T - Functional Test i
FT&C - Functional Test and Calibration j
GE .- General Electric Company .l
GL - Generic Letter i
HP - Health Physics l
HPCI - High Pressure Coolant Injection System l
Hx - Heat Exchanger l
I&C - Instrumentation and Controls
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IFI - Inspector Followup Item
. KHz - Kilohertz
LCO - Limiting Condition for Operation
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LER -
Licensee Event Report
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LOCA - Loss of Coolant Accident
LOSP - Loss of Offsite Power
LPRM - Local Power Range Monitor
MFP - Main Feed Water
MSIV - Main Steam Isolation Valve
MSR - Moisture Separator Reheater
MWe - Megawatts Electric
MWO - Maintenance Work Order
NCV - Non-cited Violation
NRC - Nuclear Regulatory Commission
NSAC - Nuclear Safety and Compliance
ODCM - Offsite Dose Calculation Manual ;
PCIS - Primary Containment Isolation System
PE0 - Plant Equipment Operator
P&lD - Piping and Instrumentation Drawing :
PRB - Plant Review Board
PSW - Plant Service Water System
RB - Reactor Building
RBM - Rod Block Monitor
RCIC - Reactor Core Isolation Cooling System l
RCS - Reactor Coolant System .
RFP - Reactor Feed Pump
RG - Regulatory Guide !
RHRSW- Residual Heat Removal Service Water System )
RPS - Reactor Protection System i
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RTP - Rated Thermal Power
RWL - Reactor Water Level .
RX - Reactor
SAER - Safety Audit and Engineering Review i
SBGT - Standby Gas Treatment t
SFP - Spent Fuel Pool i
SIL - Service Information Letter .
SOS - Superintendent of Shift (Operations)
SPDS - Safety Parameter Display System .
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SRO - Senior Reactor Operator
SS - Shift Supervisor :
STA - Shift Technical Advisor
TS - Technical Specifications !'
URI - Unresolved Item
V DC - Volts Direct Current i
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