Load analysis system for fault detection

To prevent unnecessary power outages, and to remove feeder lines from service only when certain hazardous fault conditions occur, a load analysis system including an apparatus and method, monitors the load level of a feeder line and determines the presence of any arcing on the feeder line. In a two stage load pattern analysis, the presence of arcing and load current level changes are used to discriminate high impedance, low current conditions including a downed conductor, a broken and dangling conductor, a tree or object contact with the feeder line, overcurrent activities, and normal switching events such as recloser operation. The load analysis system also provides output commands including wait, alarm, trip-ready, trip and normal, depending upon which status is diagnosed.

BACKGROUND OF THE INVENTION 
The present invention relates generally to a load analysis system for use 
with an electrical utility power system, and more particularly to a load 
analysis system for distinguishing high impedance, low current faults from 
other normal events and activities on the power system. High impedance 
faults may be caused by, for example, downed, broken, tangled or dangling 
power lines, trees contacting the power lines, and various overcurrent 
fault situations. 
High impedance, low current faults are more difficult to detect than 
permanent overcurrent faults, such as when a transformer fails. 
Conventional overcurrent protection devices have time delays which allow a 
temporary fault to clear, and if the overcurrent fault persists only then 
does the device deenergize the power line. High impedance, low current 
faults may initialize the timing circuits of the overcurrent protection 
devices but, by the end of the delay, the high impedance nature of the 
fault limits the fault current to a low value. The overcurrent protection 
devices cannot distinguish this low fault current from the levels of 
current ordinarily drawn by customers, so the lines may remain energized 
even though a conductor has broken. 
Other methods of detecting high impedance faults have focused on detecting 
third harmonics generated by the arcing behavior of the high impedance 
faults. These earlier methods use detection algorithms having variations 
in harmonic current as the detection parameter. For instance, U.S. Pat. 
No. 4,851,782 to Jeerings detects high impedance, low current faults by 
analyzing third harmonic currents on the power lines. 
By relying only on the arcing behavior for detection, high impedance fault 
detection systems using such methods experience significant reliability 
problems. These systems lack security against a false trip, causing 
unnecessary blackouts for the utility's customers. For example, a tree 
limb momentarily touching a power line may cause a momentary fault, which 
is cleared when the tree limb moves away from the power line. These 
earlier systems may misinterpret this momentary tree contact as a 
permanent high impedance fault, and in response cause breakers to trip to 
deenergize the line. Such systems may also interpret normal switching 
actions of the power system protection equipment as a permanent high 
impedance fault and cause unnecessary trips. 
A primary goal of electrical utilities is to minimize such false fault 
detections. Most utilities need a load analysis system which detects and 
deenergizes a power line only for hazardous faults, such as when a broken 
conductor is on the ground. During other minor fault conditions, such as a 
broken power line dangling out of the reach of the public, it may be 
desirable to leave the power line energized. Although a dangling power 
line is hazardous, service interruptions to the electric utility's 
customers can also pose significant safety problems. 
Thus, a need exists for an improved high impedance fault detection system 
for electrical power utilities which is directed toward overcoming, and 
not susceptible to, the above limitations and disadvantages. 
SUMMARY OF THE INVENTION 
Thus, there is a clear need for a load analysis system having fault 
detection techniques which accurately identify hazardous faults requiring 
line deenergization, and which accurately discriminates, or distinguishes, 
a hazardous fault from other events for which the line should remain 
energized. The present invention encompasses such a load analysis system 
which minimizes unnecessary power service interruptions and outages. 
In accordance with an illustrated embodiment of the present invention, a 
method of analyzing faults occurring on a distribution circuit coupled to 
an AC power system, includes the step of monitoring a load current flowing 
over the distribution circuit. In an analyzing step, the load current is 
analyzed over time. In an identifying step, either the occurrence of a 
normal system event, a hazardous fault or a minor fault are identified 
from the analyzed load current. As used herein, hazardous faults are those 
requiring deenergization of the distribution circuit, and minor faults are 
those for which the distribution circuit may remain energized. The 
distribution line should also remain energized during normal system 
events, such as during switching events. 
In accordance with another illustrated embodiment of the present invention, 
a load analysis apparatus is provided for analyzing faults occurring on a 
distribution circuit coupled to an AC power system. The apparatus includes 
a monitor for monitoring a load current flowing over the distribution 
circuit and in response thereto, generating a load signal. The apparatus 
also has a controller responsive to the monitor for analyzing the load 
current over time, and for identifying the occurrence of hazardous and 
minor faults from the analyzed load current. 
An overall object of the present invention is to provide a load analysis 
high impedance fault detection system for minimizing unnecessary power 
service interruptions and outages. 
A further object of the present invention is to provide a load analysis 
apparatus and method for accurately identifying and discriminating 
selected high impedance faults which require a power outage to clear, from 
other power system events and activities during which it is preferable 
that the power line remains energized. 
Still another object of the present invention is to provide a load analysis 
system which is more reliable than the earlier systems. 
The present invention relates to the above features and objects 
individually as well as collectively. These and other objects, features 
and advantages of the present invention will become apparent to those 
skilled in the art from the following description and drawings.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT 
FIG. 1 illustrates an embodiment of a load analyzer 10 constructed in 
accordance with the present invention. The analyzer 10 distinguishes a 
high impedance fault from other occurrences on a distribution system 
conductor, power line, or feeder 12. The feeder 12 receives power from an 
AC power source, such as a generating station 14, through a substation 16. 
Other feeder lines (not shown) may also receive power from the generating 
station 14 and exit the substation 16. The feeder line 12 delivers power 
from the substation 16 to a variety of customers, such as customer 18. 
Altogether, the generating station 14, substation 16, and feeder 12 
delivering power to the customer 18 illustrate a portion of an electrical 
utility's power system 20. 
Between the substation 16 and the customer 18, the feeder line 12 may be 
subjected to a variety of different types of events, activities and 
faults, such as: a downed conductor 22, a dangling conductor 24, momentary 
contact of a tree or other object 24 with the feeder 12, an overcurrent 
(Ovc.) event 26, or a switching event 28 performed by a conventional 
recloser or the like. An overcurrent event 26 may be caused by a variety 
of events, such as a customer overload, the touching or tangling of two or 
more phase conductors, a lightning strike, or a broken conductor hitting 
grounded object or a conductor. These grounded objects may include a 
feeder pole guy wire, an under-built neutral conductor, or the like. 
Although utility engineers distinguish between recloser operation and 
switching events, with recloser operating automatically and switches being 
manually operated, the operation of both are collectively referred to 
herein as "switching events" unless otherwise indicated. Regarding the 
various faults and normal operations of the power system 20 described 
herein, the following terms are used herein interchangeably: situation, 
occurrence, operation, event, and activity. 
The load analyzer 10 includes a monitoring device such as a transducer 30 
coupled to the feeder 12 as indicated schematically by line 32. Monitoring 
device is defined broadly herein to include sensing devices, detecting 
devices, and any other form thereof known to be interchangeable by those 
skilled in the art. The illustrated transducer 30 senses or monitors a 
load current I.sub.L flowing through feeder 12. In response to the load 
current I.sub.L, the transducer 30 produces a load current signal 34 that 
indicates the magnitude and waveform of current flowing in feeder 12. The 
transducer 30 may be a conventional transducer or equivalent device, such 
as multiple current transformers typically with one current transformer 
per phase plus one on the neutral. 
The load analyzer 10 also includes surge protection, for example, a surge 
suppressor or protector 36. The surge protector 36 which may be supplied 
with the transducer 30, as illustrated, or as a separate component. The 
surge protector 36 protects the load analyzer 10 from power surges on the 
feeder 12, such as those caused by lightning strikes or the like. 
A controller 35 receives the load current signal 34 from the transducer 30. 
The controller 35 includes a signal conditioner 38 for filtering and 
amplifying the load current signal 34 to provide a clean conditioned load 
current signal 40. Preferably, the signal conditioner 38 includes a low 
pass filter for satisfying the Nyquist criteria of sampling known to those 
skilled in the art. The signal conditioner 38 also amplifies the load 
current signal 34 for the appropriate gain required by an analog to 
digital (A/D) converter 42. For example, the dynamic range of signals 
received on a power system 20 range from 10 Amps to 10,000 Amps, so the 
signal conditioner 38 appropriately scales these signals for conversion by 
the A/D converter 42 from an analog signal 40 into a digital load current 
signal 44. 
The controller 35 includes a discrete A/D converter 42 when transducer 30 
is an analog device. The transducer 30 may also be implemented in a 
digital device which incorporates the signal conditioning function of 
conditioner 38 and the analog-to-digital conversion function of the A/D 
converter 42. 
The load analyzer 10 also includes a line current sampling device or 
sampler 45 which samples the digitized current signal 44 at selected 
intervals to provide an accurate representation of the load level during 
rapidly changing conditions, such as during overcurrent faults. For 
example, the sampler 45 may measure the line current and determine either 
the fundamental frequency component or the rms (root-mean-square) current 
component. In a preferred embodiment, one rms value is calculated for each 
one or two cycles of the fundamental power system, such as sixty or thirty 
values per second for a 60 Hz nominal power system frequency. The sampler 
45 provides a sampled current signal 46 corresponding to the sampled line 
current values. The sampled current signal 46 is supplied via a 
microcomputer bus 47 to a computing device, such as a microcomputer system 
48. The microcomputer system 48 has a computer, such as a single board 
computer 50, coupled with a memory device, such as a random access memory 
52, and a data storage device, such as a hard disk 54. A suitable 
microcomputer system 48 may include a conventional personal computer or 
any other form thereof known to be interchangeable by those skilled in the 
art. 
The controller 35 includes a circuit breaker interface 60 for receiving a 
trip command signal 62 from the computer 50 via the bus 47. In response to 
the trip command signal 62, the interface 60 sends a trip signal 64 to a 
circuit breaker trip circuit 66. The trip circuit 66 drives a circuit 
breaker (not shown) located at substation 16 to deenergize the feeder 12. 
The controller 35 may include an optional serial interface 68, such as a 
modem for sending and receiving a peripheral device signal 70 over a 
telephone network. The interface 68 may communicate with an external 
peripheral device 70, such as a remotely located power distribution 
control center. In some systems, the peripheral device 70 may provide a 
remote input to the load analyzer 10 via the serial interface 68, for 
example to override previous programming of the load analyzer, such as the 
initial settings, sensitivity settings, operational delays, etc. 
The controller 35 may also include an output device, such as a visual 
display device 74 or a printer. Preferably, the output display provides a 
visual indication of the status of the load analyzer 10, the feeder line 
12, and previous operating conditions of the feeder. The controller 35 may 
also provide an alarm signal 76 via bus 47 to an alarm 78 which may be 
visual, audible, or both. 
Operational Overview 
As an overview, the operational philosophy of the system has the load 
analyzer 10 looking for arcing over a long period of time, on the order of 
several seconds to several tens of seconds, or even minutes, before 
deciding that a downed conductor condition 22 indeed exists. To reach this 
downed conductor decision, the arcing is accompanied by either a 
significant loss of load, signifying the beginning of the event, or by an 
overcurrent fault. If prolonged arcing is detected that is not accompanied 
by a loss of load or by an overcurrent condition, the load analyzer 10 
interprets the situation as being associated with other types of events, 
such as by tree contact 25 or by an insulator failure. Preferably, the 
load analyzer 10 recognizes a significant loss of load because it is 
precipitous and precedes any overcurrent or open breaker conditions. 
Preferably these other types of arcing conditions activate an alarm 
separate from a downed conductor alarm because utility practices may 
dictate different responses to the two types of arcing conditions. 
The presence of arcing may be determined by other methods known to those 
skilled in the art. Other methods known to those skilled in the art may be 
used to detect a significant loss of load, and to recognize overcurrent 
and open breaker conditions. 
Preferably, the load analyzer 10 allows conventional overcurrent 
protection, such as fuses, reclosers, and conventional overcurrent relays 
to operate first. To accomplish this objective, the load analyzer 10 
preferably will delay issuing an output trip signal 64 until a sufficient 
time period has elapsed after the beginning of the event. Thus, the load 
analyzer 10 acts as a last resort protection device when conventional 
overcurrent protection devices have not yet operated. Preferably, this 
minimum operating time of analyzer 10 may be programmed by the user, to 
accommodate system protection philosophies which vary from one utility to 
the next. 
FIRST EMBODIMENT 
By recognizing and distinguishing the different reactions of the power flow 
through feeder 12 when subjected to the various events 22-28, the load 
analyzer 10 determines what type of event has occurred, whether it is a 
hazardous fault or a minor fault, and what response is appropriate. For 
example, the downed conductor 22 usually shows a loss of load, unless it 
is located far from the substation. The downed conductor 22 touches and 
arcs to a high impedance object, such as the ground. The arcing behavior 
of the downed conductor 22 lasts for a significantly long period of time, 
on the order of minutes as opposed to fractions of a second or seconds. 
A broken and dangling conductor 24 may also show a loss of load. However, 
no arcing behavior is exhibited because the end of the dangling conductor 
24 does not touch any high impedance objects, as does the downed conductor 
22. Momentary contact of a grounded object, such as the tree contact 25, 
with the feeder 12 may exhibit an arcing phenomenon without any loss or 
increase of load. Overcurrent activities 26 may involve any combination of 
phases and the neutral exhibiting an overcurrent which exceeds a specified 
level, with or without arcing behavior. 
A switching event 28 may or may not show any significant load change, and 
does not show prolonged arcing behavior. Any arcing from a switching event 
28 typically lasts less than one second. For example, a recloser action 
switching event 28 may show significant load increase and load loss, with 
or without arcing behavior. This load increase and load loss response to 
the recloser action 28 is repeated in a similar pattern at intervals 
dictated by the established practice of recloser operation. 
A downed conductor 22 may initially look like several different types of 
faults which complicates the diagnosis. When a downed conductor first 
breaks and starts falling to the ground, it may hit a guy wire or an 
under-built neutral conductor, and appear as an overcurrent activity 26. 
This overcurrent activity causes an overcurrent breaker (not shown) to 
trip and deenergize the line. A short time later, a recloser operates to 
reenergize the line, which appears as a switching event 28. By the time 
the line has been reenergized, the downed conductor 22 may have slipped 
off the guy wire or the under-built neutral and made arcing contact with 
the ground. The low level current flowing between the downed conductor 22 
and the high impedance ground is usually not high enough to cause further 
operation of the overcurrent breaker (not shown); hence the need for the 
load analyzer 10. 
Generally, most electrical utilities only want a feeder breaker to trip for 
a downed conductor 22. The load analyzer 10 identifies downed conductors 
22, broken and dangling conductors 24, tree contact 25, and other events, 
such as overcurrent (Ovc) fault situations 26. To initially distinguish 
between normal operating conditions and a disrupting event, the load 
analyzer 10 continually monitors a value of a parameter of the power 
flowing through the feeder 12, here, the rms of the load current I.sub.L. 
Once a disrupting event is detected, the load analyzer 10 then identifies 
what type of event has occurred. This event identification is accomplished 
within the microcomputer system 48 by analyzing the load current patterns 
in two stages of event classification logic (see FIGS. 2 and 3). 
Three important elements of this load pattern analysis scheme are detecting 
and analyzing: 
1) the presence of arcing; 
2) changes in the load level; and 
3) occurrence of overcurrent activity. 
For example, whenever a power line breaks, some percentage of the total 
feeder load current I.sub.L is lost causing an initial disruption in the 
rms data monitored by transducer 30. This conductor breakage initiates a 
sequence of events in which there is a sudden loss of load current 
I.sub.L. If this sudden loss is followed by an indication of arcing, then 
a downed conductor situation 22 most likely exists. This sequence of 
events provides a good indicator of the downed conductor scenario, which 
calls for tripping the feeder. If no arcing follows the sudden load 
current loss, then it is likely that a dangling conductor situation 24 
exists for which many utilities allow the feeder 12 to remain energized. 
If an overcurrent fault occurs and then vanishes, but is followed by a 
period of sustained arcing, this is also an indication of a downed 
conductor (with or without loss of load). 
The load analyzer 10 classifies the events by using these three elements, 
arcing, load level changes, and overcurrent level excursions, to define 
three analysis variables, flags or signals for use in the logic analysis: 
1) Arc, 
2) Load-Loss, and 
3) Overcurrent Level. 
The load analyzer 10 uses these three variables to generate pre-action 
outputs or commands, action outputs or commands, and several diagnosis 
outputs. The pre-action commands include: 
1) Trip-Ready, 
2) Alarm, and 
3) Normal. 
The action commands include: 
1) Trip, 
2) Alarm, and 
3) Wait. 
The action command Trip is initiated by the circuit breaker interface 60 
sending signal 64 to the trip circuit 66. The Alarm pre-action and action 
commands are sent to the alarm 78 by signal 76. The Trip-Ready, Trip, 
Alarm, Wait and Normal commands are preferably shown on the display 74 
along with the diagnosis outputs. The diagnosis outputs characterize the 
particular conditions of the feeder status, such as normal or one of the 
five situations 22, 24, 25, 26 or 28. The feeder status and commands may 
also be sent via signal 72 to a peripheral device 70. 
Referring FIGS. 2 and 3, a flow chart 100 illustrates a method of 
detecting, analyzing and discriminating between faults and normal events 
on a power line with reference to the operation of the illustrated load 
analyzer 10. The flow chart 100 shows one manner of operating the 
microcomputer system 48. First, data and variable preparation operations 
of the load analyzer 10 are described. 
The Analysis Unit 
To determine the presence of arcing and load level change, the rms value of 
the load current I.sub.L is monitored by transducer 30, conditioned by the 
signal conditioner 38, converted from an analog to a digital signal by 
converter 42. The digital signal 44 is sampled at the selected interval by 
sampler 45 to determine the sampled current signal 46 which is an input to 
the computer 50. To check for permanent variations in the load level and 
persistent arcing behavior, a sufficient time or number of rms data 
values, referred to herein as an analysis unit, is used. In the 
illustrated embodiment, this analysis unit is set at five seconds, which 
is equivalent to 300 rms data values. However, it is apparent that the 
analysis unit may be set at other values depending upon the particular 
implementation, such as by analyzing the energy of the load current 
I.sub.L over every two cycles. 
Preferably, the analysis unit has a duration long enough to allow operation 
of conventional automatic protection devices, such as overcurrent breakers 
(not shown), installed on the feeder 12. Most utilities want the load 
analyzer 10 to operate only after operation of the conventional 
overcurrent protective devices (not shown), so the analysis unit is 
selected to a value on the order of 30 seconds. During the time analysis 
unit, the load analyzer 10 analyzes the pattern of the load to determine 
values for the variables Arc, Load-Loss, and Overcurrent Level. 
Data Management and Storage 
The normal load level, situation exists when there are no abnormal 
indications during an analysis unit. The feeder line 12 is continually 
monitored, and the normal load level is updated over time analysis unit by 
analysis unit. Each succeeding analysis unit is compared with the previous 
analysis unit to provide a long term load comparison. The RAM 52 has two 
data storage locations designated herein as Packet #1 or P.sub.1, and 
Packet #2 or P.sub.2. The newly updated normal data is stored in the 
Packet #1 location in the RAM, and the new incoming data fills Packet #2. 
If Packet #2 is found to be normal data, then the 300 data values in Packet 
#2 are moved or swapped into Packet #1, leaving Packet #2 empty. As the 
data is read by the computer 50, if an abnormal rms value is found in 
Packet #2, then a data pointer device, index or software control is frozen 
at the abnormal rms value. This abnormal rms value is then remembered and 
stored during the analysis, with the location of the abnormal within the 
data pack indicated by the pointer. All of the data values in Packet #2 
which were entered before freezing of the pointer are moved into and 
stored in the Packet #1 located, eliminating the first portion of the data 
which was previously stored in Packet #1. Thus, Packet #1 contains and 
stores the newest normal data, which is a combination of the data from the 
previous analysis unit and the current analysis unit where the abnormal 
value is encountered. Packet #2 then stores only the post-disruption rms 
data values. 
Abnormality or Disruption Check 
To check for the presence of arcing and load level changes for each phase 
and the neutral, two data differencing checking routines are used: 
1) the short term or first difference D.sub.F, and 
2) the long-term difference D.sub.L. 
These data differencing routines are useful to find any trend in this time 
series of data. The short term differencing routine (D.sub.F) is used to 
set the Arc flag, and the long term differencing routine (D.sub.L) is used 
to set the Overcurrent Level flag and the Load-Loss flag. 
Short Term Trend Determination 
The short term differencing routine (D.sub.F) looks for changes in the 
incoming rms data stored in Packet #2 to recognize any random behavior of 
the data. As used herein, "short term variations" refers to variations 
occurring within about one second or so. The first difference D.sub.F is 
found by determining the difference between the neighboring rms values, 
indicated as X, in the incoming data stream: 
EQU D.sub.F(i) =X.sub.(i) -X.sub.(i-1) 
When the value of the first difference D.sub.F is out of a range of certain 
values defined by an abnormality threshold T.sub.AB, a difference count 
C.sub.F is incremented by one. In the analysis unit, the difference count 
C.sub.F is accumulated and compared with a preset arc threshold value 
T.sub.ARC. If the difference count C.sub.F is greater than the arc 
threshold value T.sub.ARC, then the flag of the variable Arc is set to Y 
for yes, and otherwise is set to N for normal as a default. The random 
activity of arcing causes these short term difference trends. In addition 
to this method of arc detection, the load analysis process may also use 
other equivalent methods of arc detection known to those skilled in the 
art. 
Long Term Trend Determination 
The long term differencing routine (D.sub.L) looks for changes between the 
incoming rms data stored in Packet #2 and the data from the previous 
analysis unit stored in Packet #1 to recognize any changes in the trend of 
the load level. The long term difference D.sub.L is found from calculating 
the long term load level trend from the rms data values as follows: 
EQU D.sub.L(i) =X.sub.P2(i) -X.sub.P1(i) 
where the subscript "P2" refers to the incoming data stored in Packet #2, 
and the subscript "P1" refers to data from the previous stream stored in 
Packet #1. 
When the long term difference D.sub.L is above a level of overcurrent 
threshold T.sub.OVC, then a flag for the variable Overcurrent Level is set 
to Y for yes, and otherwise as a default remains at N for normal. Once the 
Overcurrent Level flag is set to Y during an analysis unit, it remains 
unchanged for the remainder of the analysis unit. 
When the long term difference D.sub.L is above a level of significant load 
loss threshold T.sub.LOSS, then the flag of the variable Load-Loss is set 
to Y for yes, and otherwise remains as a default N for normal. For 
example, if the load drops percipitously, e.g., from 200A to 20A within a 
few cycles, then the Load-Loss flag is set to Y for yes to indicate such a 
significant loss of load. Once the Load-Loss flag is set to Y during an 
analysis unit, it remains unchanged for the remainder of the analysis 
unit. 
Load Pattern Analysis Logic 
Having described the manner in which data is handled by the load analyzer 
10 and the manner in which the data is checked for abnormalities, the 
manner of discriminating among the conditions to determine what type of 
fault or event, such as events 22, 24, 25, 26 or 28, have occurred is 
described next. With the flags set to Y for yes or N for normal for the 
three variables, Arc, Load-Loss, and Overcurrent Level, the load pattern 
analysis proceeds in two stages of analysis and classification. 
In the first stage, the flags of the three variables are analyzed to 
generate three pre-action commands (Trip-Ready, Alarm, and Normal) and the 
diagnosis status conditions or states. The six diagnosis status conditions 
with their various combinations of flag settings are shown in Table 1. If 
the pre-action command is either Alarm or Normal it is the final analysis 
output, and in the illustrated embodiment, no further analysis occurs. If 
the pre-action command is Trip-Ready, the second stage of load pattern 
analysis begins. 
TABLE 1 
______________________________________ 
First Stage Load Pattern Analysis 
Flag Settings 
Over- Load Analyzer Outputs 
Case Load- current 
Pre-action 
Diagnosis Status- 
No. Arc Loss Level Command Condition/State 
______________________________________ 
1 Y N N Alarm Tree Contact 
2 Y N Y Alarm Overcurrent Event 
3 Y Y N Trip-Ready 
Downed Conductor 
4 Y Y Y Trip-Ready 
Broken Conductor 
Hitting Neutral 
5 N Y N Alarm Load Change 
6 N Y Y Alarm Broken & Dangling 
Conductor 
7 N N Y Alarm Overcurrent Event 
8 N N N Normal Normal Conditions 
______________________________________ 
In the second stage of load pattern analysis, only two of the three 
variables (Arc, Load-Loss, and Overcurrent Level) are used, depending upon 
which diagnosis status condition is encountered in the first stage. For 
example, for the downed conductor 22 of case #3 in Table 1, the two 
variables considered are the Arc and the Load-Loss as shown in Table 2. 
Depending upon the status of the flags, the action commands are either 
Trip, Alarm, or Wait. 
TABLE 2 
______________________________________ 
Second Stage Load Pattern Analysis 
for a Downed Conductor 
Flag Settings Analyzer Output 
Arc Load-Loss Action Command 
______________________________________ 
Y Y TRIP 
Y N Alarm 
N Y Alarm 
N N Wait 
______________________________________ 
Case #4 of Table 1 diagnoses an overcurrent event 26 comprising a broken 
conductor hitting a neutral. This case uses another second stage of 
analysis based on consideration of the two variables the Arc and 
Overcurrent Level, as shown in Table 3. Depending upon the status of the 
flags, the action commands are either Trip, Alarm, or Wait. 
TABLE 3 
______________________________________ 
Second Stage Load Pattern Analysis 
For a Broken Conductor Hitting Neutral 
Flag Settings Analyzer Output 
Arc Overcurrent Level 
Action Command 
______________________________________ 
Y N TRIP 
N N Alarm 
Y Y Wait 
N Y Wait 
______________________________________ 
Although several cases in Table 1 have a first stage pre-action command of 
Alarm, it is apparent that some utilities may prefer a Trip-Ready 
pre-action command for some of these situations. For example, a Trip-Ready 
pre-action command may be preferred for tree contact 25 on feeders through 
certain forested areas, such as in a National forest, park or monument 
area. The second stage analysis would then be conducted for any tree 
contact events 25. As another example, in urban settings a dangling 
conductor 24 may be considered a safety hazard of the same degree as a 
downed conductor 22. For a dangling conductor 24, the second stage of 
analysis considers the states of the Load-Loss and Overcurrent Level flags 
to provide action commands of Wait and Trip, as shown in Table 4. 
Individual utility operators may determine and set these truth tables to 
other values (yes or no) as they deem appropriate for particular 
implementations. 
TABLE 4 
______________________________________ 
Second Stage Load Pattern Analysis 
for a Dangling Conductor 
Flag Settings Analyzer Output 
Arc Overcurrent Level 
Action Command 
______________________________________ 
Y Y Wait 
Y N TRIP 
N Y Wait 
N N Wait 
______________________________________ 
The analysis is divided into first and second stages with the first stage 
having a pre-action Trip-Ready command to allow more certainty and 
security in the identification of the event as a particularly hazardous 
one requiring trip, such as the downed conductor 22. The Wait action 
refers to waiting a few seconds before sampling again to allow time for 
operation of the coordinated protection devices (not shown) installed on 
the feeder line 22. Such coordinated protection devices include 
overcurrent relays, fuses and reclosers. For example, if the action 
command is Wait, the illustrated load analyzer 10 waits for about five 
seconds, and then aborts all the flags and settings, then repeats the 
first stage load pattern analysis of Table 1. 
To further enhance security of the load analyzer 10 and allow operation of 
the coordinated protection devices, an initial delay period is inserted 
before the first stage analysis begins. The two stage load pattern 
analysis is not invoked until there is an indication of an abnormal event 
which may lead to a trip or alarm decision. To accomplish this initial 
delay, the load analyzer 10 has an initialization timer (not shown) which 
may be internal to the computer 50, for setting an initial delay period. 
In the illustrated embodiment, the initial delay is set for 30 seconds, 
although duration selected depends upon the particular implementation 
because feeders typically have unique operational characteristics and 
parameters. 
Upon detecting an abnormal event, the initialization timer begins to run to 
allow the conventional protection devices (not shown) installed on the 
feeder 12 to operate before the first stage analysis begins. If the 
conventional protection devices have not worked by the end of the 30 
second delay period, before issuing a command, the load analyzer 10 delays 
an additional five seconds while the data storage Packet #2 is filled. The 
second stage analysis may immediately follow completion of the first stage 
analysis. However, in some implementations it may be preferable to insert 
an interstage delay period between the two analysis stages, for example by 
emptying and refilling Packet #2 before commencing the second stage 
analysis. 
The Wait command of the second stage analysis also increases confidence in 
the diagnosis that indeed a fault situation requiring a trip exists to 
prevent unnecessary trips. For example, many utilities want the load 
analyzer 10 to trip only when arcing is accompanied by a broken conductor 
per Table 2 (Y for Arc and Load-Loss). If the arcing is intermittent and 
goes away for seconds at a time, this indicates a conductor on the ground. 
The load analyzer 10 looks for immediately present arcing, then waits if 
there are no indications of arcing or load loss, or alarms if only 
Load-Loss is detected. 
The case #2 situation may be caused by a variety of overcurrent events 26, 
such as a customer overload, the touching or tangling of two or more phase 
conductors, or a lightning strike which occurred within the initial delay 
period, here, within the preceding illustrated 30 second period. Tangled 
conductors may appear as either case #2 or #7 conditions, depending upon 
whether or not arcing exists. If the conductors remain tangled for more 
than the illustrated 30 second initial delay period, then the conductors 
are probably permanently tangled. To prevent melting of the tangled 
conductors, the overcurrent protection devices (not shown) operate to 
deenergize the feeder 12 well before the end of the 30 second delay 
period. Momentary touching or contacting of two or more conductors may 
appear as case #2, #4, #6 or #7, each of which have an Overcurrent Level 
flag set to Y. While the exact diagnosis of some of the overcurrent events 
26 may elude the load analyzer 10, a reasonable conjecture based on strong 
possibilities may be made as to which overcurrent event has occurred. 
Operator inspection of the feeder 12 may be ultimately required to attempt 
to determine which type of overcurrent event 26 indeed occurred. 
Threshold Value Settings 
The first difference D.sub.F is compared to the abnormality threshold 
T.sub.AB, the difference count C.sub.F is compared with the preset arc 
threshold T.sub.ARC, and the long term difference D.sub.L is compared to 
the level of overcurrent threshold T.sub.OVC and to the load loss 
threshold T.sub.LOSS. These threshold values T.sub.AB, T.sub.ARC, 
T.sub.OVC and T.sub.LOSS, may be established by studying the normal load 
data in a statistical manner. The load level change is determined by 
comparing the normal or predisruption load level stored in Packet #1 with 
the new post-disruption load level stored in Packet #2 of the RAM 52. 
Load Analysis Flow Chart 
Referring to FIGS. 2 and 3, the flow chart 100 for the illustrated software 
embodiment of the load analyzer 10 shows one method of analyzing faults 
occurring on the feeder 12. Before beginning the actual load analysis 
routine, an initialization routine or device 102, performs an 
initialization process. The initialization routine 102 sets several flags 
and indices. A disruption index is set to zero to indicate a normal 
current status, with no disruption thus far being found. The difference 
counter C.sub.F is set at zero because no arcing behavior is found under 
normal conditions. The flags of Arc, Load-Loss and Overcurrent Level are 
set to N for normal as a default. A stage index is set at zero to indicate 
that the data analysis is not yet in second stage. The data Packet #1 in 
RAM 52 is filled with 300 normal rms data values representing the load 
current I.sub.L. From the rms data in Packet #1, the first difference 
D.sub.F is calculated, and the initialization process is then complete. 
After initialization a read data and increment pointer device or routine 
104, sequentially reads each value of rms data, and advances a data 
pointer by one as each data point is read. In a stage one checking routine 
or device 106, the stage is determined by checking the stage index. A 
stage index of "one" indicates the data analysis is in the second stage, 
and zero indicates that it is not. In a first disruption checking device 
or routine 108, the disruption index is checked to see if the rms data 
value received differs from that previously received to indicate the 
occurrence of one of the events 22, 24, 25, 26 or 28. 
In the illustrated embodiment, if both the stage index and the disruption 
index are zero, then a first difference calculating device or routine 110 
calculates the first difference D.sub.F according to the equation 
described above. The first difference D.sub.F is then compared to the 
abnormality threshold value T.sub.AB by an abnormality threshold 
comparison device or routine 112. If the first difference D.sub.F is above 
the abnormality threshold T.sub.AB or below the negative value of the 
abnormality threshold (-T.sub.AB), the disruption index is set to "one". 
In a second disruption checking routine or device 114, if the disruption 
index remains zero and no abnormality has been found, a pointer status 
checking routine or device 116 determines whether the analysis unit is 
complete. In the illustrated embodiment, the analysis unit was chosen as 
five seconds, or 300 normal rms data units. If the data pointer is indeed 
at 300, the analysis unit is complete and the data in Packet #2 is swapped 
into Packet #1 by a data packet swap routine or device 118. Then, in a 
pointer reinitialization routine or device 120, the data pointer is reset 
to zero. If the illustrated checking routine 116 indicates the data 
pointer is at a value less than 300, the rms values of the next data point 
are read by the data read and increment pointer routine 104, and the cycle 
continues. 
If the disruption status routine 114 determines that the disruption index 
is "one," a pointer freeze and data packet rearrangement routine or device 
122 freezes the data pointer to remember the value and location of the rms 
data at the disruption time. In the illustrated embodiment, the data 
packet rearrangement portion of routine 122 attaches the predisruption 
data from Packet #2 to the end of the data stream stored in Packet #1, 
which displaces the earliest data from Packet #1. Following this data 
packet rearrangement, the pointer is reset to zero by a another reset 
pointer routine or device 124, and the next rms data value is read by 
routine 104. 
Although the stage index is still set at zero, the disruption status check 
routine 108 notes the disruption index is now set at "one." When the 
disruption index is "one," a difference calculation device or routine 126 
calculates the first difference D.sub.F and the long term difference 
D.sub.L according to the equations discussed above. In a first difference 
comparison routine or device 128, if the first difference D.sub.F is found 
to be greater than the abnormality threshold T.sub.AB, or smaller than the 
negative value of the abnormality threshold (-T.sub.AB), then the 
difference counter C.sub.F is incremented by one. 
In a long term difference comparison routine or device 130, the long term 
difference D.sub.L is compared to two different thresholds. If the value 
of the long term difference D.sub.L is greater than the level of 
overcurrent threshold T.sub.OVC, then the Overcurrent Level flag is set to 
Y. If the long term difference D.sub.L is greater than the load loss 
threshold T.sub.LOSS, the Load-Loss flag is set to Y. These flag settings 
remain unchanged until the data Packet #2 is full as determined by a 
second pointer status routine or device 132. When the illustrated pointer 
status routine 132 determines that data Packet #2 is full, a difference 
count comparison device or routine 134 compares the difference count 
C.sub.F with the arc threshold level T.sub.ARC to set the Arc flag. If the 
difference count C.sub.F is greater than the arc threshold level 
T.sub.ARC, the Arc flag is set to Y, and if C.sub.F is less than or equal 
to T.sub.ARC, then the Arc flag is set to N. The flag settings and status 
of the indices are carried as a signal 135 which links together the 
portions of the flow chart 100 shown in FIGS. 2 and 3. 
With the flag settings of the three variables, Load-Loss, Overcurrent 
Level, and Arc, set as described above, the event classification logic is 
applied in two stages, as described above with reference to Tables 1-4. 
Referring now to FIG. 3, another stage status checking device or routine 
136 determines whether the load pattern analysis is in the first or second 
stage, with the first stage being indicated by a stage index of zero, and 
the second stage being indicated by a stage index of "one." In a first 
stage of event classification routine or device 138, the logic illustrated 
in Table 1 is performed. A trip-ready output status routine or device 140 
determines whether the pre-action command of the first stage logic is 
Trip-Ready or not. 
If the pre-action command is indeed Trip-Ready, a stage advancing device or 
routine 142 changes the stage index to "one," indicating commencement of 
the second stage analysis event classification. Whether the analysis is in 
the first or second stage, an output and resetting device or routine 144 
generates a signal 145 to empty the data stored in Packet #2 of the RAM 
52. The signal 145 links together the portions of the flow chart 100 shown 
in FIGS. 2 and 3. The load analyzer 10 begins reading data using the read 
data routine 104. The new incoming data stream is stored in Packet #2 for 
the second stage of event classification. The second stage of analysis is 
noted by routine 106, and routine 126 calculates D.sub.F and D.sub.L. Then 
routine 130 sets the Overcurrent Level flag and the Load-Loss flag. When 
routine 132 indicates that Packet #2 is full, the Arc flag is set by 
routine 134. The stage status routine 136 determines the load analyzer 10 
is in the second stage of analysis, and a second stage event 
classification device or routine 146 interprets the flag settings in 
accordance with the logic of Tables 2, 3 and 4 (if used), as applicable. 
If the illustrated trip-ready routine 140 determines that the pre-action 
command of the first stage event classification is either Alarm or Normal, 
this is the final action performed by the load analyzer 10 and the status 
determined with reference to Table 1 is the final diagnosis status 
condition. Output status signals are sent to the display 74 and any 
peripheral device 70 to indicate the status of the system. For an event 
classification generating an Alarm output, the alarm signal 76 activates 
the alarm 78. If the second stage of event classification reaches the 
action command of Trip, then the breaker interface 60 sends a trip signal 
64 to the trip circuit 66 to deenergize the feeder line 12 by 
disconnecting it from the substation 16. 
Advantageously, the load analyzer 10 and method of analyzing faults 
described herein identify load patterns to recognize and distinguish 
situations in which a power line is broken or intact. In this manner, 
security against false trips is provided in the classification and 
detection of high impedance faults. Thus the overall security and 
reliability of downed conductor fault detection is greatly enhanced beyond 
the capabilities of the earlier systems described in the background 
portion above. 
SECOND EMBODIMENT 
Referring FIGS. 4 and 5, a flow chart 200 illustrates a method of 
detecting, analyzing and discriminating between faults and normal events 
on a power line with reference to the operation of the illustrated load 
analyzer 10. This second embodiment may be used alone, or in conjunction 
with the first embodiment of FIGS. 2 and 3. The flow chart 200 shows an 
alternate preferred manner of operating the microcomputer system 48. The 
variables used in flow chart 200 are defined as follows: 
______________________________________ 
OCF: Overcurrent Flag Set 
ROC: High Rate-of-Change Flag Set 
LOL: Significant Loss-of-Load Flag Set 
ARC: Arcing Flag Set 
3.phi.E: Three Phase Event Flag Set 
BRKR: Breaker Open Flag Set 
LOLI: LOL Flag was the flag which 
initially caused the 
transition into the non- 
normal state. 
OCFO: Overcurrent flag was set at some 
time while the algorithm was 
in the non-normal state. 
TIMER1: Conventional Protection 
Coordination Timer 
TIMER2: Conventional Protection 
Malfunction Timer 
TIMER3: Breaker Reset Timer 
______________________________________ 
When the load analyzer 10 is operated in accordance with flow chart 200, 
upon receiving a start command 202 from an operator, an initialization 
routine or device 204 performs an initialization process to set flags and 
indices to initial values as described below. A flag setting routine or 
device 206 uses conventional checking routines to determine from the 
sample current signal 46 whether one or more of the following events has 
occurred: 
1. A significant, precipitous loss of load (LOL); 
2. An overcurrent level is detected (OCF); 
3. A high rate of change in current (ROC); 
4. Significant arcing is detected (ARC); or 
5. A breaker-open condition is detected (BRKR). 
When a loss of load occurs, the flag setting device produces a loss of load 
flag set (LOL) signal 208. When an overcurrent level is detected, the flag 
setting routine 206 generates an overcurrent flag set (OCF) signal 210. 
When the flag setting routine 206 determines that a high rate of change in 
current has occurred, a high rate of change flag set (ROC) signal 212 is 
generated. When the flag setting routine detects significant arcing, it 
generates an arcing flag set (ARC) signal 214. When the circuit breaker 
coupled to trip circuit 66 is open, the flag setting routine 206 produces 
a breaker-open flag set (BRKR) signal 216. 
After initialization by routine 204, a line status checking device or 
routine 218 constantly monitors signals 208-216 from the flag setting 
routine 206. If none of the flags are set, the system is considered to be 
in a normal state, and the checking routine 218 issues a NO signal 220 to 
initialize the next sequence of the checking routine. 
When the checking routine 218 determines one or more of the flag setting 
signals 208-216 indicate that an event has occurred, the analyzer 10 
enters a triggered state and the checking routine 218 issues a YES signal 
222. In response to the YES signal 222, two timers are set with a set 
TIMER1 device or routine 224 setting the first timer 226 and a set TIMER2 
routine or device 228 setting the second timer 230. The first timer 226 
has a time duration selected to coordinate with conventional overcurrent 
protection on the transmission line 12. The second timer 230 detects 
whether the conventional overcurrent protection is not operating as 
intended when it continues to operate beyond a reasonably period of time. 
For instance, depending upon the conventional protection reset times used 
by a utility, certain patterns of load current may cause the conventional 
protection to start through its sequence toward lockout. If the fault 
experiences periods of inactivity which are sufficiently long to cause the 
conventional protection to reset itself, the conventional protection must 
start again from the beginning of its sequence when the fault current 
returns to a high level. If this situation occurs repetitively, the 
conventional breaker may never reach a lockout state. 
In severe cases, such repetitive operation of a load breaking device, such 
as a breaker, can cause extensive, and perhaps even catastrophic, damage 
to the device. This continual resetting phenomenon may be caused by 
improperly coordinated trip settings with respect to downstream devices, 
or it may be caused by the intermittent nature of a downed conductor, high 
impedance fault. For either cause, the second timer initiates a 
conventional protection malfunction alarm 232 when such conditions are 
encountered. 
After setting timers 226 and 230, the analyzer 10 waits for the first timer 
226 to time out. While waiting, a second event checking device or routine 
234 monitors the OCF signal 210 for overcurrent conditions, the ROC signal 
212 for high rates of change in the phase and/or residual currents, the 
BRKR signal 216 for breaker openings, and a three phase event flag set 
(3.phi.E) signal 236 generated by the flag setting device 206. The 3.phi.E 
signal 236 is generated when the flag setting routine 206 determines the 
occurrence of a multi-phase fault event. When routine 234 detects the 
occurrence of one or more of these four events (OCF, ROC, BRKR, or 
3.phi.E) a YES signal 238 is generated. 
When a second timer monitoring device or routine 240 receives the YES 
signal 238, it checks to see whether the count of the second timer 230 has 
expired. If the second timer count has indeed expired, the monitoring 
device 240 issues a YES signal 242 to a second event output alarm 244. If 
not, the monitoring device 240 issues a NO signal 245. A first timer reset 
is generated by a NO signal 246 from the second timer monitoring device 
240. Upon receiving the either NO signal 245 or 246, the set TIMER1 
routine 224 resets the first timer 226. 
If the second event checking routine 234 detects none of the four events 
(OCF, ROC, BRKR, or 3.phi.E), then a NO signal 248 is generated. When a 
first timer monitoring device or routine 250 receives the NO signal 248, 
it checks to see whether the count for the first timer 226 has expired. If 
the count of timer 226 has not expired, the monitoring device 250 
generates a NO signal 252 which is returned to initialize the second event 
checking routine 234. If the monitoring device 250 determines the first 
timer count has expired, it generates a YES signal 254. When a set TIMER3 
initialization routine or device 256 receives the YES signal 254, a third 
timer 258 is initiated. 
Referring also to FIG. 5, while the third timer 258 counts, the proper 
output to be sent by the controller 35 to the peripheral device 70 or the 
alarm 78 is determined. Specifically, a downed conductor checking routine 
or device 260 receives a TIMER3 initiation signal 261 from initialization 
device 256. Upon receiving signal 261, the device 260 checks if and when 
the LOL signal 208, the ARC signal 214, and the OCF signal 210 indicated 
the occurrence of a significant loss of load, arcing, and overcurrent 
conditions, respectively. If arcing is present on the transmission line 12 
as indicated by the ARC signal 214, and a significant loss of load 
indicated by the LOL signal 208 initially caused the analyzer 10 to enter 
a triggered state (abbreviated as "LOLI" in FIG. 5) then the checking 
routine 260 issues a YES signal 262. 
Upon receiving the YES signal 262, a downed conductor output device 264 
provides an output to the peripheral device 70. The checking routine 260 
also monitors for arcing by checking the ARC signal 214. Routine 260 
monitors for the combination of this arcing and an overcurrent condition 
which occurred during the triggered state. This is the same overcurrent 
condition which occurs when the second event checking routine 234 receives 
the OCF signal 210. When these two conditions are encountered, the 
checking routine 260 issues the YES signal 262 to the downed conductor 
output device 264. 
If the checking routine 260 does not find that the LOL signal 208 initiated 
the triggered state ("LOLI"), or does not find that the OCF 210 was 
monitored by routine 234, and if arcing is still present, routine 260 
issues a NO signal 266. When an arc checking routine 268 receives the NO 
signal 266 and the arc signal 214 still indicates the presence of an arc, 
the checking routine 268 issues a YES signal 270. When an arcing detected 
output device 272 receives the YES signal 270, an arcing detected output 
is provided, for example to the peripheral device 70. Also, when the 
output device 272 receives the YES signal 270, a continuation signal 274 
is supplied to permit the checking routine 260 to continue to monitor for 
a downed conductor condition. 
If the arcing condition checking routine 268 determines that the arc signal 
214 is absent, a NO signal 275 is generated. When a third timer monitoring 
device or routine 276 receives the NO signal 275, it checks to see whether 
the count of the third timer 258 has expired. If not, the monitoring 
device 276 issues a NO signal 278 which is provided as a continuation 
signal to the downed conductor checking routine 260. If the monitoring 
routine 276 determines that the count of the third timer 258 has indeed 
expired, a YES signal 286 is generated and delivered to the initial line 
status checking routine 218 to return the load analyzer 10 to its "normal" 
state. 
The condition of the breaker controlled by the breaker trip circuit 66, as 
indicated by the BRKR signal 216, is monitored by a breaker monitoring 
device 282 for monitoring whether the breaker is closed (conducting state) 
or open (non-conducting state). When the monitoring device 282 determines 
the breaker is closed, it issues two YES signals 284 and 286. The first 
YES signal 284 is provided to the set TIMER3 device 256 to reset the third 
timer 258. The second YES signal 286 is supplied to a stop TIMER2 device 
288. The stop TIMER2 device 288 suspends the count of the second timer 230 
but does not reset the timer whenever the breaker is closed to conduct. 
CONCLUSION 
Having illustrated and described the principles of our invention with 
respect to a preferred embodiment, it should be apparent to those skilled 
in the art that our invention may be modified in arrangement and detail 
without departing from such principles. For example, while the illustrated 
embodiment has been implemented in software, or discussed in terms of 
devices in some instances structural equivalents of the various hardware 
components and devices may be substituted as known to those skilled in the 
art to perform the same functions. Furthermore, while various hardware 
devices, such as the transducer and microcomputer are illustrated, it is 
apparent that other devices known to be interchangeable by those skilled 
in the art may be substituted. We claim all such modifications falling 
within the scope of the following claims.