The Business Case for IEC 61850

Author: Alexander Apostolov, USA

What is a Business Case?

There are many definitions that one can find on the Internet about what a business case is. They can be summarized in the following definition from
A business case is an argument, usually documented, that is intended to convince a decision maker to approve some kind of action.
Like everything else we talk about, the business case needs to answer the three questions:

  • What are we doing?
  • Why are we doing it?
  • How are we doing it?

The answer to the first question is related to the Smart Grid. The electric power industry is trying to transition into an environment in which we will have a more reliable, secure and efficient grid. From the point of view of the definition of business case above the goal is to convince the decision makers that the transition from traditionally used technologies to protection, automation and control solutions based on the IEC 61850 standard is the approach that will help meet the challenges that our industry is facing.

The answer to the second question is related to the challenges the industry faces. The need for change is driven by the combination of old and new challenges. The following is a list of some of them:
High costs of building new substations, including land, equipment, transportation, construction and installation

  • Labor intensive process of connecting primary substation equipment and multifunctional IEDs which leads to increased installation and commissioning costs
  • Labor intensive mapping of data from multifunctional IEDs to substation HMI which increases engineering costs and is prone to human errors
  • Limited number of inputs and outputs of multifunctional IEDs which may require the use of additional auxiliary equipment, resulting in increased costs, reduced reliability and degraded protection scheme performance
  • Proprietary communications interfaces between protection Intelligent Electronic Devices used in accelerated protection schemes do not support interoperability and as a result reduce the availability and reliability of such schemes
  • Unsupervised hard wired interfaces between relay outputs and opto-inputs in distributed protection schemes do not provide indication about the failure of an interface which may lead to a failure to operate when necessary
  • Labor intensive maintenance of the interface between multifunctional IEDs and the substation HMI which requires remapping of IED data to the HMI
  • Safety concerns related to possibility for open CT circuits which result in dangerously high voltages that can hurt or even kill employees
  • Labor intensive maintenance testing requiring traveling to substation location which may be under dangerous conditions raising safety concerns and possibilities for human errors
  • Outages for testing of protection IEDs or schemes which are very difficult to get and result in reduced electric power system reliability
  • CT saturation and CCVT transients may result in incorrect operation of protection functions
  • Impact of changing substation or power system topology on the performance of protection functions which has an impact on the sensitivity or selectivity of protection schemes and the fault clearing times
  • High penetration of different types of Distributed Energy Resources at all levels of the electric power grid which requires reduced fault clearing times at the different levels of the system

The traditionally used technologies have difficulties with resolving the issues as listed above. These difficulties have been discussed in many articles published in the PAC World magazine and papers presented at conferences around the world.
Taking advantage of the development and implementation of IEC 61850 can help the industry meet the goals of the Smart Grid. This is the answer to the third question above. This has to be further expanded with a description of a vision for the future, including the levels of implementation of the standard at different stages of the migration strategy.
At the same time while building the business case we need to also consider the risks and costs of change. This is a very complex issue that needs to take into consideration the short term and long term objectives. The analysis should examine the benefits and risks involved with both switching to IEC 61850 based protection, automation and control systems and, on the other hand, continuing to use the traditional solutions. 

It is very important that the goals of the transition to IEC 61850, the benefits and the risks are presented in a very focused manner without the use of very technical IEC 61850 terminology. The information included should be understandable by decision makers without any knowledge of the standard.
Addressing any of the challenges listed above needs to highlight at the end the impact on the bottom line, i.e. how it will improve the efficiency, related to reliability and security.
The following sections of this article briefly analyze the benefits and risks of the transition from conventional technologies to IEC 61850 based solutions.

Substation Costs

The cost of building new substations or expanding existing substations, especially in densely populated area can be significantly reduced by using IEC 61850 based digital substations. This cost reduction is most significant when the conventional current and voltage instrument transformers are replaced with non-conventional sensors and the combination of disconnector-breaker-disconnector is replaced by a Disconnecting Circuit Breaker (DCB) available from several major suppliers. The substation footprint in this case may be reduced to about 50% of the footprint of a conventional substation.
Reducing the number of primary devices also reduces the construction costs due to the smaller number of foundations needed.

Replacing the traditional hardwired analog and binary circuits between the primary substation equipment and instrument transformers (Figure 1) by the optical fibers of the IEC 61850 process bus results in a significant reduction in copper cables. When we include also the replacement of the hard wired interfaces between IEDs it can reach up to 80% in transmission level air insulated substations. This will lead to significant cost savings not only by reducing the cost of the copper cables, but also by limiting the transportation costs. Copper cables remain for power supply and short connections between primary equipment and marshalling kiosks in the switchyard.

The replacement of conventional instrument transformers with non-conventional sensors also reduces the transportation costs because of the significant difference in their weight. For example a non-conventional current sensor weights less than 15% of the weight of a conventional current transformer and is also smaller in size. (Figure 2)
Further construction cost reductions are achieved by the smaller size of the control house due to the reduced number of panels. This is the result of several factors, such as the smaller size of the limited number of IEDs which do not have terminal blocks for the traditional hardwired interfaces, very limited number of terminal blocks, and high levels of functional integration. In the future centralized IEC 61850 based digital substations the control house as we know it may disappear.

IED Interfaces Installation and Commissioning
The wiring of conventional substations (Figure 4) requires a significant amount of time by skilled technicians in order to provide all required interfaces:

  • Between the substation equipment in the yard and the panels in the control house
  • Between the panels in the control house
  • Between the panel terminals and the IEDs in the panel
  • Between the IEDs in the panel

This time is further extended by the preparation time of the copper wires and their labeling. Another issue is the risk for human errors and the requirements for extensive testing in order to ensure the quality of the interfaces.
In the IEC 61850 based digital substations the thousands of hardwires carrying individual analog and binary signals are replaced by a limited number of fiber optic cables transmitting sampled values, GOOSE messages or client-server communications. (Figure 3)

Mapping IED Data to HMI
One of the most time consuming engineering tasks when building a new substation and engineering its protection, automation and control system is the development of the substation Human Machine Interface (HMI). In conventional substations using communication protocols which do not use semantics based data naming the mapping of the data from the registers of each IED to the HMI is an extremely time consuming work that is also prone to human errors.

The use of a standard, semantics oriented data model in IEC 61850 allows the development of engineering tools that can generate automatically the substation HMI based on extensions to the model that support the visualization of the substation equipment on the HMI in a user customizable manner. This will lead to significant reduction of the HMI development time - from months to minutes, and will also improve its quality.

Limited Number of Inputs and Outputs
Multifunctional IEDs interface with other IEDs based on hardwired relay outputs and opto inputs.  Some protection schemes may require a large number of interfaces.
The limited number of opto inputs and relay outputs is another challenge for the development and implementation of some more advanced distributed protection, automation and control schemes. In some cases this problem is solved by using auxiliary relays, however the price is the reduced reliability of the schemes due to the increased number of devices and the hardwired interfaces between them. The addition of the auxiliary relays also increases the operating time of the scheme, which may not be acceptable. This also leads to increased installation, commissioning and maintenance costs.

Replacing the hardwired interfaces with GOOSE messages eliminates this problem due to the fact that a single fiber connection can carry the equivalent of a practically unlimited number of signals between the IEDs, resulting in significant time and costs savings.

Accelerated Protection Schemes

One of the problems with hardwired protection and control schemes is the fact that they are not supervised and as a result may represent a hidden failure component. Problems with hardwired interfaces are discovered only due to the failure of a protection scheme to operate as required or during time based maintenance testing. Maintenance testing is time consuming and requires outages, which is not acceptable in many cases. One of the significant benefits of IEC 61850 is the continuous repetition of GOOSE messages which represents a heartbeat that can be used for interface supervision.  (Figure 6.)  As soon as a message is not received, it will indicate a problem with the communications interface or the publishing IED that can be fixed as quickly as possible.

A higher level of monitoring of the communications interfaces is achieved when the IEC 61850 PAC system is using a redundancy protocol such as PRP or HSR (Figure7). The fact that there are redundant copies of each message allows the detection of communications component failure (if one copy of the message is lost) or failure of the publishing IED (if both copies are not received).
Such monitoring significantly reduces (practically eliminates) the need for time based maintenance testing, resulting in cost and time savings.

IED / HMI Data Maintenance
The changes in firmware of IEDs using protocols different than IEC 61850 require remapping of the IED data to the HMI due to changes in the data allocation in the memory of the IED. This work is performed by the utility specialists or the system integrator and requires not only update of the mapping, but also testing to verify that the update is successful.
In the case of IEC 61850 based systems changes in the firmware do not require remapping. This is because the internal IED data is still available with the same IEC 61850 name as before the update. The mapping of the data from new different registers in the memory to the same IEC 51850 data attributes is the responsibility of theIED manufacturer. 

Improved Safety
IEC 61850 process bus based solutions also improve the safety of the substation by eliminating one of the main safety related problems - an open current circuit condition. Since the only current circuit is between the secondary of a current transformer and the input of the merging unit is located right next to it, the probability for an open current circuit condition is very small. It becomes non-existent if optical current sensors are used.

Remote Testing

Maintenance testing is something that needs to be done, regardless of the different challenges that may be faced by the crew:

  • Long distance between the substation and the base of the testing team
  • Difficult terrain with bad roads
  • Difficult weather conditions
  • Requirements for reduction of outage time because of maintenance

One of the benefits of IEC 61850 based digital substations is that all devices (PAC IEDs, substation computers and test devices) are connected to the substation communications network. If there are testing tools that are connected to the network in the substation on a permanent basis, it becomes possible to perform the tests from a remote location. (see Figure 9)

Outages for Testing of Protection IEDs
Maintenance testing in conventional hardwired schemes requires the isolation of the tested protection device which is performed typically using a test switch connecting the test device to the test object. In many cases this requires an outage, due to the unavailability of the protection device. At the distribution feeders typically there is only a single protection IED, which means that during the testing if the feeder is still in service the protection will be provided by backup functions, for example in the transformer protection IED. This will result in extended fault clearing times and may result in the shutdown of many DERs connected to the distribution system.

The virtual isolation features in IEC 61850 allow the isolation of functions, sub-functions or even a single function element (for example an overcurrent step as shown in Figure 10). In this case all remaining protection functions are active which improves the reliability of the system, reduces the fault clearing time and eliminates the need for an outage - all very significant benefits compared to the traditional testing practices.

CT Saturation
IEC 61850 process bus based applications offer some important advantages over conventional hard wired analog circuits. The first very important one is the significant reduction in the cost of the system due to the fact that multiple copper cables are replaced with a small number of fiber optic cables.

Using an IEC 61850 process bus based on standalone merging units (SAMUs) also results in the practical elimination of CT saturation because of the elimination of the current leads resistance. Traditionally the CT knee-point voltage is a function of the resistance of the different components of the current circuit:

VK = f (RCT, RL, RRP)
VK = Required CT knee-point voltage (volts)
RCT = Resistance of the current transformer secondary winding (ohms)
RL = Resistance of a single lead from relay to current transformer (ohms)
RRP = Impedance of a relay phase current input

In some cases RL is multiplied by 2 and plays a key role in determining the CT requirements.
In this case the CT secondary is connected to the phase current inputs of the Merging Units and RL is practically equal to zero.

The knee-voltage then will be only dependent on
VK = f (RCT, RRP)

The impedance of the merging unit current inputs RRP is very small, thus resulting in the significant reduction in the possibility for CT saturation and all associated with it protection issues.
CT saturation is completely eliminated when using non-conventional instrument transformers, because there is no CT circuit.

High Penetration of DERs
When a short circuit fault occurs on a transmission line connected to a substation with DERs at the distribution level, the voltage drop caused by the fault needs to be considered in the analysis of the performance of the DERs and their ability to ride through the fault. When the fault is in Zone 2 of the protected transmission line (especially on shorter lines) the time delayed trip will depend on the time delay setting which may be in the range of 300 - 400 msec. Such a delayed trip will result in the duration of the voltage sag experienced by a DER in the tripping area of the ride-through characteristic. An accelerated protection scheme can significantly reduce the fault clearing time and bring it within the stay connected area of the characteristic.

The challenge for the implementation of accelerated transmission line protection schemes is that they require a communications channel which, if it is a dedicated one, will require additional costs.
IEC 61850 routable GOOSE (R-GOOSE) messages (see Figure 11) are a technology that can help us achieve these goals without the need for additional investments.

A Very Strong Business Case
Based on the analysis of all use cases described above it is clear that IEC 61850, especially when fully implemented in digital substations with non-conventional instrument transformers and state of the art disconnecting breakers, offers significant savings in time and money. At the same time the risks are minimal, and they have to do with the fact that it is a new technology that requires training in order to apply it properly and use it efficiently.  


Dr. Alexander Apostolov received his MS degree in Electrical Engineering, MS in Applied Mathematics and Ph.D. from the Technical University in Sofia, Bulgaria. He is Principal Engineer for OMICRON electronics in Los Angeles, CA. He is an IEEE Fellow and Member of the PSRC and Substations C0 Subcommittee. He is past Chairman of the Relay Communications Subcommittee, serves on many IEEE PES WGs. He is a member of IEC TC57 WGs 10, 17, 18, 19, Convenor of CIGRE WG B5.53 and member of several other CIGRE B5 WGs. He is a Distinguished Member of CIGRE. He holds 4 patents and has authored and presented more than 400 technical papers. He is an IEEE Distinguished Lecturer and Adjunct Professor at the Department of Electrical Engineering, Cape Peninsula University of Technology, Cape Town, S. Africa. He is Editor-in-Chief of PAC World Magazine.