CASE STUDY
Small Utility Cost-Effectively Isolates, Diagnoses and Solves
Recurring Issue Using LineIQ
BACKGROUND AND CHALLENGE –
The City of Okolona Electric Department, a small rural Mississippi
utility with 5,200 customers and 710 miles of distribution line, had a
long standing reliability problem on a main feed out of a 46-12kV
substation. Customers had been complaining for some time of
“blinking lights.”
Feeder protection for that substation was provided by an ABB
breaker at the substation and a Cooper hydromechanical recloser
installed at the mid-section of the circuit, neither of which had event
or monitoring capabilities.
The city had tried to locate the fault using traditional line fault
indicators and by physically patrolling the line, but to no avail. They
chose the LineIQ transmission and distribution line monitoring solution to help them solve the
costly problem once and for all.
SOLUTION –
To diagnose the problem, LineIQ sensors were
installed along the 12kV circuit in order to monitor
load, fault and outage events.
At each “blinking light” complaint, LineIQ
wirelessly downloaded its record of one minute of
RMS current and voltage on/off values, along with
12 cycles of the fault current waveform.
“The LineIQ sensors were
instrumental in solving a long
standing reliability problem on a
politically sensitive circuit,
preventing a potentially
hazardous and costly system
failure”
By comparing the event data for each phase and
examining the change of current against the line
voltage status, the city was able to determine if the
LineIQ sensors were installed on or beyond the fault path.
GridSense, Inc.
2568 Industrial Blvd., Ste. 110
West Sacramento, CA 95691
-
Mike Parker, City of Okolona
Electric Department
CHK GridSense PTY Ltd.
Tel: 916-372-4945
Fax: 916-372-4948
Suite 102, 25 Angas Street
Meadowbank, NSW 2114, Australia
Tel: +61 2 8878-7700
Fax: +61 2 8878-7788
gridsense.com
Accordingly, Okolona then positioned the sensors on smaller sections of the circuit in order to
isolate the fault.
LineIQ Sensors were placed in 3 positions over time:
First position:
Midway between the substation and recloser
Second position: Midway from the recloser and end of the feeder
Third position:
Tap line off of the main feeder
Schematic showing circuit layout, highlighting first LineIQ installation point.
Installation 1: Midway between the substation and recloser
It was important to determine if the problem lay between the substation and recloser, or if it lay
beyond the recloser. This sensor placement was the starting point for that determination.
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Figure 1. Phase B to ground fault with a single recloser operation.
The RMS graph in Figure 1 above shows that phase B faulted to ground at 2:10 pm on August
24th during this placement. The graph also shows that the fault was cleared by a single
recloser protection operation. The lack of change in the voltage status confirms that the
downstream recloser did operate, while the upstream breaker did not. Thus, the fault sat
beyond the recloser. The details of the fault on phase B are shown in Table 1 below.
Table 1. Phase B to ground fault detail.
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Installation 2: Midway between the recloser and the end of the feeder
Now recognizing that the fault lay beyond the recloser, the LineIQ sensors were moved midway
between the recloser and end of the feeder. This would determine if the problem sat toward
the end of the line, or between the recloser and the LineIQ sensors.
Schematic showing circuit layout, highlighting second LineIQ installation point.
Table 2 below shows that the LineIQ
Sensors captured a transient phase Bto-ground fault on September 11TH at
2:42 pm (indicated by FP, SI), while
phases A and C detected the recloser
operation (indicated by SI, Power On
with no high current). This data
confirmed that there was a primary,
reoccurring phase-to-ground fault on
phase B, in agreement with data from
the installation 1 LineIQ sensors.
Table 2. Events detected at second installation point.
Figure 2 below shows the RMS plot for the event captured by phase A (red), phase B (green)
and phase C (blue) at 2:42 pm on September 11th. The graph clearly shows that a 700+ amp
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fault current on phase B tripped the recloser once, which cleared the fault. At this point,
phases A and C only detected the recloser operation; i.e. a fault current did not pass these
phases.
Figure 2. Ground fault with 3-phase protection operation.
For each RMS event, there is an event table that provides detailed information on how the fault
started, progressed and ended. The event table details for the phase B-to-ground fault are
shown in Table 3 below.
Table 3. Event details of faulted Phase B.
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The key data gained from this table were:
1. There were 37.9 amps of Line current on phase B prior to the fault
2. A 711.9 amp fault current was detected
3. Protection operated after 0.08 seconds of fault current
4. There was a 1.74 second momentary outage
5. Phase B inrush current peaked at 34.7 amps
6. 4.6 amps of load was lost as a result of the fault and protection operation
The city could now further isolate the issue. Since the phase B sensor detected the fault, the
fault had to be located downstream.
Installation 3: Tap line off of the main feed
The LineIQ sensors were moved further downstream on a tap line off the main feed monitoring
a short section of line.
Schematic showing circuit layout, highlighting third LineIQ installation point.
On the November 30th, the feeder locked out in the early hours of the morning. The line crew
restored supply after several attempts but could not locate the cause of the outage. Using
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LineIQ, the city was able to analyze in-depth the events surrounding the November 30th event,
shown in Figure 3 below:
LineIQ data files open, stating location
and phase positioning information.
1. Phase B to Ground fault detected on Nov. 27th 2.38
pm, phase A and C detect a short interruption, i.e.
successful recloser operation.
2. Phase B to ground fault detected Nov. 30th at
2.38am, protection lock out (outage). Phase A and C
detect the outage, a secondary fault is detected on
3. Failed line restoration at 3.30am. Phase A, B and C
detect a momentary power return with lock out. B and
C detect fault current during restoration attempt.
4. Failed line restoration at 4.04 am. Phase A, B and C
detect a momentary power return followed by a lock
out. Phase B and C detect fault current during
restoration attempt.
5. Failed line restoration at 4.27 am. Phase A, B and C
detect a momentary power return followed by a lock
out. Phase B and C detect fault current during
restoration attempt.
6. Successful line restoration at 4.49am, phase A, B
and C detect a power return.
Table 4. List of events detected at third LineIQ installation on November 27 and 30 .
th
th
Figure 4 below shows the initial fault and lockout and each restoration attempt before
successful line restoration.
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Figure 4. Graph showing initial fault and outage, 3 restoration attempts, and power return.
Figure 5 below shows details of the fault with phase A (red), phase B (blue) and phase C
(green) superimposed on same graph. By comparing the change in current with the change in
voltage status the city could easily differentiate between fault, protection operation and line
restoration. It is clear that a primary fault occurred on phase B (blue) to ground.
A secondary fault on phase A (red) can also be detected during the 2nd and 3rd protection
operations. The fault current detected on phases A and B could be interpreted as either a
flashover between phase A and B or a phase A-to-Ground fault somewhere downstream.
Figure 5. RMS capture of primary and secondary faults at 2:47 am on November 30 .
th
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OUTCOME –
Moving the sensors from point to point allowed City of Okolona to narrow the problem area to
a small section of the feeder, where LineIQ event data identified phase B-to-ground as the
primary fault and phase A as a secondary fault, which only occurred during the 2nd and 3rd
protection operations.
The city could now carry out a detailed line inspection focusing on a very small area on phases
A and B. The line crew quickly singled out one particular pole as the root of the problem.
That particular pole installation included lightning arrestors, drop fuses and three transformers
connected by a thin set of stinger cables. On close inspection, inspectors found flashover
markings on the phase B stinger wire, the cross arm bracket and the phase A stinger wire. The
stinger wire on phase B was noticeably bent, most likely from a heavy bird, and was
encroaching the clearance distance between the cross arm bracket and phase A.
Under windy conditions phase B would ground with the cross arm bracket and trip the recloser
protection. After a number of operations, the air ionized between the reduced clearances
creating the secondary fault flashover between phase A and B stinger wires.
The line inspection findings matched the LineIQ event data, giving the City of Okolona Electric
Department high confidence that they had found the cause of the reliability problems that had
plagued this circuit for so long. The city rewired the pole assembly and kept the LineIQ sensors
in place for an additional two weeks to verify that they had permanently solved the problem.
If Okolona had not diagnosed and corrected the issue, continuing events would have likely
caused a costly equipment failure and sustained outage. In addition, the city saved significant
amounts of time and money.
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