Common standards to help integrate digital devices in substations
Palo Alto, CA—Increasing adoption of standard communication protocols will likely fuel the North American substation automation market, which is expected to increase by more than 64% in total from $350.5 million in 2004 to $576.2 million in 2011, according to a new report, “North American Substation Automation Markets,” by Frost & Sullivan.
Palo Alto, CA— Increasing adoption of standard communication protocols will likely fuel the North American substation automation market, which is expected to increase by more than 64% in total from $350.5 million in 2004 to $576.2 million in 2011, according to a new report, “North American Substation Automation Markets,” by Frost & Sullivan .
The analyst’s report says the substation automation market previously implemented several standard communication protocols, including distributed network protocol version 3 (DNP 3), utility communication architecture version 2 (UCA 2), and Modbus. However, these standards failed because not all intelligent electronic device (IED) vendors adopted them. Consequently, common industry standards will now receive greater attention because utilities have started to realize the benefits of integrating various digital devices in a substation, which can happen only with adoption of standard protocols.
Because most devices deployed in the substation automation market are proprietary, Frost reports that communication between them is possible only through protocol converters. This extended process consumes a lot of effort and money during commissioning and reduces equipment efficiency. Utilities reportedly hope to coordinate real-time information obtained from these devices, and share data across departments. To do this, Frost adds they must implement standard protocols that are reliable and optimize device functionality.
The reports adds that greater acceptance of DNP as the standard protocol for remote terminal units (RTUs), IEDs, and master stations in North America will greatly aid integration of digital devices. The substation market will also have to deal with the problem of seamlessly integrating non-operational data and getting it to the control room. Non-operational data includes transformer temperature, dissolved gas, as well as lightning and weather conditions. The challenges associated with non-operational data are the characteristics of data, frequency of data transfer, and protocols used.
'It's difficult to retrieve non-operational data from IEDs because utilities need the IED vendor's proprietary commands for gaining access to certain ports to do this,' says Balaji, Frost & Sullivan's research analyst. IED vendors reportedly can solve this by pushing for open standards so to cull non-operational data from other vendors.
With the mounting amount of data required for monitoring and controlling substations, there is an urgent need for highly reliable, secure, and robust communication networks. These network channels will ensure that communication disruptions do not take place within the substations and remote centers.
Higher bandwidth communication channels aid efficient data acquisition and send the information to the required center in real time. Efficient authentication and encryption techniques are required to make communication safe from attacks by external factors.
'Some of the latest communication technologies include Internet-based virtual private network (VPN) and satellite, wireless, and optical fiber communication,' adds Raman. 'However, each of these alternatives has its own advantages and disadvantages, making it difficult to depend on a single mode of communication.'
For a virtual brochure, which provides manufacturers, end users, and other industry participants with an overview of the North American Substation Automation Markets, send an e-mail to Trisha Bradley at email@example.com. The e-mail must include the recipient’s full name, company name, title, telephone number, fax number, and e-mail address.
Control Engineering Daily News Desk
Jim Montague, news editor