The evolving convergence of distribution, automation and advanced metering infrastructure

The concept of Distribution Automation (DA) was introduced in the 1970s to use the latest technology computer and communications equipment to improve operating performance of distribution systems (sound familiar?). Since then, the growth of DA has been determined by the level of sophistication to be installed. Sometimes, unfortunate experiences occurred when too much “DA” was attempted all at once. The “big bang” approach was rationalized to quickly capture technology benefits. Data captured overloaded the capabilities of processor and software technology at the time.  Projected rates of Return on Investment (ROI) were also missed, leaving the industry cautious of automation projects. 

In spite of these early “starts,” the industry realized the power of automation and knew it would only be a matter of time before more universal deployment. The question then was the same as the question now: How much and how soon?

Of course, receiving data from one place to another is fundamental to the communications backbone. This is why the evolution of communications technology is so important to any automation strategy. Fortunately, great strides have been made in this area, which enable other automation technologies to be realized.

Automation applied outside of the substation fence is often called “Distribution Automation” or DA. Automation applied within the substation fence is sometimes called “Substation Automation” or SA. However, SA is rarely used.  References are almost always made to DA without regard to being inside or outside the fence.

DA, in its strictest sense, is applied to devices on distribution feeders. Communication is usually wireless (radio, cellular, satellite) or via fiber optics. Wireless generally communicates to a Master Station. Fiber optics typically goes to/through a substation and then on to a Master Station.

SA, in its strictest sense, is applied to devices within the substation. Communication goes through a Master Station but may also be to automation equipment on distribution feeders. Traditionally, communication is done either through fiber optics (for devices within the substation yard) or RS485 (for devices within a substation rack environment). Ethernet is commonly used to get data from the substation to the control center and is a popular media for interconnecting Intelligent Electronic Devices (IEDs) throughout the substation.

It is sometimes difficult to justify DA based on hard cost-benefit numbers. Benefits include enhancements to efficiency, reliability, service quality, and more effective utilization of existing equipment. Some customer-related functions, such as remote load control, Automated Meter Reading (AMR), and remote connect/disconnect are also benefits of system automation. AMR is part of a larger whole called Advanced Metering Infrastructure (AMI).
 
Parallel to DA are Automated Mapping and Facilities Management (AM/FM) technologies. AM/FM is generally integrated with a Graphical Information Systems (GIS). Common functions performed by an AM/FM system are design, facilities mapping, right of way/permit tracking, facilities inventory, and system and equipment maintenance.

Data collected around the system and processed for specific applications make up AMI. Included are customer information systems, billing/settlement systems, work order management and inventory systems, outage management systems, marketing services systems, and load management systems. AMI, DA, and SA must work together.

In a 2003 article for EnergyPulse Magazine, Peter Manos made the following point when comparing today’s technology with technologies from years gone by and those that lay ahead: The technology from years gone by “did not seem primitive at the time.” Physically placing pieces of paper on a system map to identify trouble calls was leading technology at the time. These “pin-the-paper-on-the-outage” systems felt like a great leap forward, with tickets being automatically printed so system operators and dispatchers didn’t have to talk with the Customer Service Representatives. This was a great leap forward in “automating” the process.

In the years ahead, today’s technology may seem just as primitive. It is for this reason and the desire to make the most of already installed infrastructure that DA, SA and AMI systems installed today not only integrate with legacy systems, but anticipate the need to integrate with tomorrow’s system. Put another way, when tomorrow views today’s technology as “legacy” systems, tomorrow will need to be able to integrate new with old as legacy systems continue to expand over time.

Predictions for tomorrow’s world include the following: Manual meter reading will be a thing of the past. Residential load control will be as commonplace as home thermostats. Distribution system outages will be automatically identified using dispersed low-cost sensors eliminating the need for manual reporting. Protective relays will automatically adapt settings to accommodate changing system conditions.

The importance of DA, SA and AMI will continue to increase, consistent with the need to do more with less. The ability to collect increasing amounts of information, organize it into readily usable forms, then make decisions on system operation, performance, and the condition of equipment will remain critically important. The result will be a consistent improvement in reliability, efficiency, and overall system performance – all good for the society at large, and a winning combination for utility companies, consumers, and suppliers.

Defining automation
Automation can be defined as shown in this figure. It is no more and no less than collecting data and doing something with it. The complexity is in how much data is collected and how much processing is done. 
 

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