Modern IEC61850 based Distribution Feeder Automation Systems

Authors: Andre Smit, Dr. Alexandr Stinskiy, Suraj Chanda, and Todd Houseknecht, Siemens Industry, Inc. Raleigh, NC, USA

New approach to distribution feeder protection and automation

The protection system disconnects the fault from the network through coordinated over current tripping and auto reclosing actions

The automation system then locates the faulted segment of the feeder, isolates this faulted segment, and executes automatic closing of a field switch to provide alternate power from a different power source to unaffected feeder segments

Figure 3 illustrates the many different steps that are needed to isolate the faulted segment in the feeder and provide alternate power to unaffected line segments. The system consists of substation and field reclosers interconnected to provide the capability of isolating any line segment and providing alternate substation sources to all line segments. Figure 3 illustrates protection functions for a permanent fault located on line segment E. (Note that the recloser controllers are set to two shots to lockout).

The protection devices are configured with coordinated overcurrent curves to trip only for faults downstream from its location with respect to the connected substation source.  The sequence of events is as follows:

1. Device P5 detects a fault on line segment D

2. The first fast shot coordinated overcurrent function in P5 times out and trips its recloser. (This device is set to operate faster than the substation controller P6)

3. Device P5’s auto-reclose function’s first fast dead time will time out, causing the recloser to close back onto the faulted line segment to determine if the fault was temporary in nature

4. Device P5 will detect that a fault is still present. The second shot coordinated overcurrent function in P5 times out and again trips its recloser

5. Device P5’s auto-reclose function’s second slow dead time will time out and close the recloser back onto the faulted line segment to again check if the fault was temporary in nature

6. Device P5 will detect that a fault is still present in the line segment. The selected second shot coordinated overcurrent function in P5 times out and again trips its recloser. (Note that device P5’s settings are coordinated to trip faster than the substation reclosers, thus providing time for lateral line fuses to blow for faults beyond the fuse locations and thereby activate the lockout state)

In the example of Figure 1:

1. On reception of the Lockout state from device P5, the automation system will be triggered. The first action for this system is to determine the location of the fault. This is accomplished by looking at the fault flag information provided by the protection devices or information supplied by fault sensors.

2. The fault location is determined to be between P4 and P5 on line segment D. The automation system issues an open command to Recloser P4. This completes the fault isolation actions

3. The last step is to restore service to Line segment C. The automation system will close the normally open recloser P9

The automation system must now adapt the protection settings on all affected devices to accommodate the new system topology.

Line section C, which is downstream from the affected line section D, could constitute hundreds of consumers. During the reclose cycles, these consumers are exposed to all protection interruptions in addition to the time it takes to locate the fault, isolate the line section, and finally close the recloser to provide an alternative power source. The actions could take minutes or hours depending on the remote access time to control the reclosers in the system.  Protection coordination can also be challenged in this system if a source transfer action was executed by the automation system.

In the example of Figure 2:

1. The Substation 3 source is interrupted

2. The automation system detects the loss of source and opens recloser P6 in Substation 3

3. The system then closes recloser P3 to provide power to line segments C, D and E

The protection devices P1 through P5 must then be adapted to coordinate for faults on all 5 line segments. This is typically extremely difficult to achieve on distribution systems due to the impact of fuse selections, loading and system impedances.

 New Approach:  The new approach is to eliminate the complexity of adapting the coordinated overcurrent settings when topology changes are executed by the automation system. To make this possible, the protection and automation actions must be executed synchronously. Today, most digital protection devices have powerful logic programming capability; therefore, it is possible to move the automation functions to the protection devices. It is not possible to move the protection functions to a central automation system server.

Another advantage that can be gained is the speed of operation of the automation system.

If we consider adapting our protection systems to incorporate all feeder automation actions, we can greatly improve the combined system performance as well as maximize the reliability by exposing less of the system to protection and automation operational interruptions.  If we consider the same example, the system can be protected and automated in the following steps as shown in Figure 5:

1. De vices P5 and P4 detect and locate the fault in line section D using current differential protection

2. Device P5’s controller trips the recloser to isolate the fault

3. Device P4’s controller opens its recloser to isolate the faulted line section. (This is an automation action in the first example)

4. Device P9’s controller closes its open recloser to energize line section C. An automation action

5. The auto reclose on device P5 is then released to do a first fast shot and close the recloser. (Note:  If the fault was temporary in nature this would be the last action)

6. Device P5’s Controller will detect that the fault is still present when it closes and activates its slow over current curve. (The slow curve will give the downstream lateral fuses time to blow if required). Note: This active curve on P5 needs only to be coordinated with the substation recloser and the fuses. During the reclose cycles only the device reclosing and the first devices connected to the system sources are active

7. The P5 controller will close again after the second dead time

8. Finally the P5 controller will still detect the fault, trip, and activate the lock out state

These actions have a tremendous impact on the consumers connected to line section C. They will only see a short interruption and will not be exposed to all the protection reclose interruptions as in the previous example. To get this approach to work in our example topology, it is essential that the field and substation devices communicate and share information in real time. IEC61850 “GOOSE” messages are likely the best possible platform to communicate this information between protection devices.

Though a direct fiber connection between devices is preferable, it will not be always possible to have dedicated fiber available as the communication platform for automation systems to perform protection and automation actions.

Therefore, it is required that “GOOSE” be able to function over wireless radio systems, and most modern IP based radio systems (Wi-Fi, WiMAX, Cellular 3G, 4GLTE) support Multicast traffic such as “GOOSE”.

 The Traditional Approach consists of different distinctly:

What makes “GOOSE” ideal for this application?

  • It is a small packet protocol, ideal for wireless systems
  • Analog or binary information can be shared for processing by the protection and automation controllers
  • Data traffic can be managed using set time intervals of the “GOOSE” packets
  • The “GOOSE” packets contain quality information. Therefore, devices can filter and discard “GOOSE” packets with incorrect quality information
  • An additional layer of security is added to normal IT cyber security requirements

The other requirement for this approach is the ability to locate the fault accurately and immediately on each line segment using differential protection methodologies. To accomplish this, the feeder is broken into line segments where currents are measured at either end and compared through peer to peer “GOOSE” communication to locate a fault.

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