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It is our intent that you - the domain expert - add to the list of Q&A.

1. Is an RTU a device or a function?

What exactly is an RTU (Remote Terminal Unit) in this day and age? RTUs started out life as rather humble individuals, merely collecting and collating data for reporting to a master whenever the master was ready for it. These days RTUs seem to be nigh on autonmous beings. And then there are all these nice web enabled RTUs. Is it time to call a halt and lay down definitions for various levels of RTU, say, from dumb RTU right up to self governing fully autonmous rtus, and where do u draw the line before such an RTU turns into a master station? Is the traditional domain of the RTU now seriously under threat from new superior IEDs that seem to be cropping up in ever increasing numbers?

By the letter of the law, an RTU is a Remote TERMINAL Unit, i.e. one which gathers data from local I/O and reports it to a distant master. However, RTUs have become data concentrators, protocol gateways, routers, PLCs, automation application platforms, meters, switch controllers, cap bank controllers, reclosers, and are even beginning to implement some protection functions. Simultaneously, most IEDs are beginning to take on the basic I/O functions of a traditional RTU. There seems to be no need to define a "next generation RTU". The Utility Communications Architecture (UCA) proposes as part of its Generic Object Model for Substation and Feeder Equipment (GOMSFE) that the various functions within a substation be divided into what it calls "building bricks". The generic I/O functions of a basic RTU are just some of those bricks, as are metering functions, protection functions, etc.

Any set of these functions will soon be able to reside in any device in the substation. As that happens, it will cease to matter what any device is actually called. Some devices may be called IEDs, some RTUs, some PLCs, some Relays, some meters, some computers, etc. because their vendors believe that is the main function of the device. The important thing will be whether the subset of functions provided by the device meets a market niche, or whether it is flexible enough to fit several niches simultaneously.
(based on an answer from Grant Gilchrist)

2. What does seamless communication in utility systems mean?

Modern approaches like the IEC 61850 draft standard and UCA are designed in a way that the application information (information models for real world information, e.g. transformer or circuit breaker), the services to access this information (e.g. reporting, control, logging), and the communication stacks (MMS, TCP/IP, Ethernet, ...) are more or less independent of each other.

Seamless means that the information of a device can be accessed independent were the device is installed. To explain the concept of seamless communication, the following cases are discussed:

Case 1 (From Control Center directly to Device)

Location of information Device installed in a substation

Information model Standard circuit breaker model (IEC 61850-7-4/-3)
Service GetValue mapped to MMS (IEC 61850-7-2 / 61850-8-1)
Stack TCP/IP (61850-8-1)

Case 2 (From Control Center through a proxy to Device image)

Location of information Proxy computer in a substation representing device information

Information model Standard circuit breaker model

(IEC 61850-7-4/-3)

Service GetValue mapped to MMS

(IEC 61850-7-2 / 61850-8-1)

Stack TCP/IP (61850-8-1)

Case 3 (From Control Center directly to Device - different stack)

Location of information Device installed somewere

Information model Standard circuit breaker model

(IEC 61850-7-4/-3)

Service mapped to other Application layer than MMS

(IEC 61850-7-2 / 61850-8-?)

Stack TCP/IP (61850-8-?)


Seamless in the context of utility applications means:

  • The device information is defined ONCE only (in the device itself or in a proxy).
  • The device information may be located in the end device (information is consistent per definition) or may be located in a proxy server representing any set of devices or systems (consistency of information in proxy and real devices needs good data engineering).
  • The access to the device information is - from an abstract point of view - the same, independent of the ACSI (IEC 61850-7-2) mapping to a specific application layer, e.g. MMS.
  • The communication stack may be the same, similar, or different.

Seamless does NOT mean:

  • Direct access to the real device in the field from any point in the universe!

3. Is DNP3 Protocol a property of GE Harris or is it open?

This question is easy to answer: The dnp user group's web site says:

"DNP3 was developed by Harris, Distributed Automation Products. In November 1993, responsibility for defining further DNP3 specifications and ownership of the DNP3 specifications was turned over to the DNP3 Users Group, a group composed of utilities and vendors who are utilizing the protocol."


4. Which is better, IEC 608750-5-104 OR DNP3?

There are multiple answers to the second question (DNP3 or IEC 60870-5-104?) depending whom you ask. A technical comparison of the two can be found under: //news/51.html

This comparison will help you at least to understand the commonalities and differences.

The real interesting question is: What will be the future standard in telecontrol and - more general - in power systems automation? A new standard just arrived: IEC 61850 (Communication networks and systems in substations). Read what independent experts like John McDonald from KEMA recomment: "If your timeframe is one to two years, you should consider IEC 61850 and UCA2 MMS as the protocol." [Remark: UCA2 MMS is a crucial input to IEC 61850; UCA is now an umbrella: IEC 61850, ICCP/TASE.2, ...]

Gustavo Brunello from General Electric wrote recently in an article titled MICROPROCESSOR-BASED RELAYS AN ENABLER TO SCADA NTEGRATION: "The flexibility provided by the IEC61850/UCA-MMS protocols has the potential for saving millions of dollars in development costs for utilities and manufacturers, manufacturers, since it eliminates the need for protocol converters and lengthy, complex database mapping when integrating devices from different manufacturers..."

A first public draft "companion" standard to IEC 61850 has recently been published by IEC: IEC 61400-25 (Communications for monitoring and control of wind power plants). This standard relys on IEC 61850 and extends IEC 61850 mainly in the following two areas:

1. adds a comprehensive wind power plant information model including current process, statistical, and historical information of some 150 "information points" like "rotor speed".

2. adds to the MMS mapping (IEC 61850-8-1) other mappings: to IEC 60870-5-104, OPC XML-DA, web services, and DNP3 (keeping the information models!!)

5. One should opt for IEC-5-101 OR IEC-5-104?

The question IEC 60870-5-101 versus IEC 60870-5-104 is easy to answer: the 104 is almost the same as 101 BUT 104 message (ASDU) exchange is over TCP/UP.


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