CASE STUDY

  

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CHK GridSense PTY Ltd. Suite 102, 25 Angas Street Tel: +61 2 8878-7700 Meadowbank, NSW 2114, Australia Fax: +61 2 8878-7788

  gridsense.com

 

“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”

- Mike Parker, City of Okolona Electric Department

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.

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.

   

  

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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

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.

Schematic showing circuit layout, highlighting first LineIQ installation point.

   

  

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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.

Table 2 below shows that the LineIQ Sensors captured a transient phase B-to-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.

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

Schematic showing circuit layout, highlighting second LineIQ installation point.

Table 2. Events detected at second installation point.

   

  

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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.

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

Schematic showing circuit layout, highlighting third LineIQ installation point.

   

  

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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:

Table 4. List of events detected at third LineIQ installation on November 27th and 30th.

Figure 4 below shows the initial fault and lockout and each restoration attempt before successful line restoration.

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.

   

  

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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 30th.

   

  

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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.