Adopting a Standard: How ICCP Works for NSP

Dec. 1, 1998
Utilities have a reputation for being technologically conservative, and because they have so many installed proprietary systems, most are interested in

Utilities have a reputation for being technologically conservative, and because they have so many installed proprietary systems, most are interested in new technology as a way of tying together existing systems. Unfortunately, early adopters face significant challenges. It is difficult to know which new technologies and standards deserve implementation and trial, as well as when and how to undertake such implementation. This is particularly critical in light of the changes mandated by the deregulation of the electric-utility industry. As the merchant splits from the provider, traditional business and control systems must split, too; however, they must be able to communicate easily.

At Northern States Power Co. (NSP), one of the largest utilities in the midwestern United States, we have a reputation for being in front of the curve in terms of adopting new technology. Headquartered in Minneapolis, Minnesota, NSP is a major U.S. utility with growing domestic and international non-regulated operations. NSP's wholly owned utility subsidiary, NSP-Wisconsin, operates generation, transmission and distribution facilities providing electricity to about 1.44 million customers in M innesota, Wisconsin, North Dakota, South Dakota and Michigan.

Taking a Look at ICCP In the early 1990s, NSP became involved with the use of Inter-Control Center Communications Protocol (ICCP), in conjunction with a project initiated by the Electric Power Research Institute (EPRI), Palo Alto, California, U.S. ICCP was developed to give utility organizations throughout the world the ability to exchange data over wide-area networks between utility control centers, utilities, power pools, regional control centers and non-utility generators. ICCP allows the exchange of real-time and historical power system monitoring and control data, including measured values, scheduling data, energy-accounting data, and operator messages. Data exchange occurs between multiple control center energy management systems (EMS), EMS and power plant distribution control systems (DCS), EMS and distribution supervisory control and data acquisition (SCADA) systems, EMS and other utility systems, and EMS/SCADA and substations.

The EPRI/NSP joint project entailed developing a working prototype application to connect the NSP EMS environment to the corporate mainframe for data exchange. Through a successful prototype, we demonstrated proof of concept. We liked what we saw and decided to broaden our use of ICCP, which provided more flexibility than prior protocols. We wanted flexibility even though it can sometimes translate to complexity and can increase implementation time; Each subsequent implementation is easier and smoother. We know that although we may experience growing pains associated with adopting new technology, cost/benefit analyses demonstrate that the long-term benefits justify any short-term inconveniences that may exist.

Choosing a Vendor The next step for us entailed choosing a commercial product to meet our emerging requirements. For purposes of evaluation, and as a way to mitigate risk, we chose and installed two vendors' versions of ICCP. This brought new and detailed data back to the control center by connecting the distribution management system (DMS) with a CellNet environment to support a distribution-automation pilot project.

Over the next three years, we field-tested both products to determine their flexibility and applicability to our unique requirements. We chose the LiveData ICCP Server from Cycle Software of Cambridge, Massachusetts, U.S. Currently, five LiveData Servers connect the DMS and Cellnet components called CellManagers (the Cellnet environment in this context is the radio communication infrastructure that NSP uses for automated meter reading). Each Cycle server is certified to support up to 500 field devices, and each field device contains 10 to 30 or more discrete status and measurement values. Thus, the current configuration can support up to 75,000 (5 x 500 x 30) point status/measurements.

The LiveData ICCP software runs on Windows NT and on the Modicon Quantum PLC. It is the first ICCP system to use an object configuration-driven approach. This approach diminishes the cost and complexity of developing and maintaining ICCP. In addition, risk and time to integrate are minimized, resulting in more reliable and maintainable end systems. Because of its high level of integration with the Windows user interface, LiveData ICCP is easy for us to manage and administer.

Expanding Use of ICCP Our early successes with ICCP and Cycle Software led us to specify ICCP as the preferred protocol in our new EMS. We will install replacement gateways to move from a pilot implementation to the newer standardized ICCP, supported by our EMS/DMS vendor. In these systems, we have installed eight to 24 Bitronics meters with Modbus Plus communication on a network. These meters monitor various power values on feeders in the substation. The network also contains a Modicon 984 compact programmable logic controller (PLC), which controls load-tap-changing operation on two to four transformers in the substation. The Modicon Quantum PLC with Cycle's LiveData ICCP server will be connected to the network to send information from the meters and PLCs in the substation to the DMS.

We also will use ICCP in all new and renovation substation projects. ICCP not only will adapt to new equipment needs but also will meet the unique requirements of existing stations that have numerous PLCs, meters and protective relay gateways connected via Modbus Plus to an NT hardened personal computer. The PLCs in the integrated substation provide control functions within the substation to coordinate with the high-speed protective relays. They are distributed throughout the various panels to provide input and output capability for each three-breaker set in the breaker-and-a-half scheme. The protective relay gateways provide an interface between the Modbus Plus network and the communication ports on individual protective relays. We can use this path to gather information and status from the relay and to initiate control functions through the relay.

The personal computer provides both the local human machine interface required to monitor and control the substation locally and the ICCP link to the EMS. We intend to separate the two functions by moving the EMS ICCP link to the new Quantum/Cycle package to reduce the possibility of a single point of failure for monitoring and controlling the substation. We also anticipate that this will simplify the setup and maintenance of the systems within the substation.

In addition to these applications, we have used ICCP for connectivity to other utilities and power plants, as well as to internal systems at NSP. As of today, we have implemented more than 20 discrete instances of ICCP. Clearly, ICCP will be our communication interface standard for external utilities, external marketing entities and power pool types of interfaces. Internally, ICCP will be used within any control system and new business application that may emerge.

What Are the Benefits? Moving to ICCP as a standard protocol increases flexibility and capability and allows retrieval of far more information from substations. It can be challenging to cite specific, tangible benefits of migrating toward standard, open protocols, but the technological advantages coupled with the avoided costs of troubleshooting and maintaining older protocols will stand us in good stead over the coming decades.

Industry observers seem to agree. They note that in a time when the business environment for utilities is typified by rapid change, the ability to feed data into an EMS via open, standard protocols is a major benefit. Systems such as these are less proprietary, more modular and more easily enhanced and altered over time.

Ron Bijoch, manager of Real Time Systems Planning and Projects, has been employed by Northern States Power Co. for more than 18 years. He holds the BS degree in computer science from the University of Minnesota and has been an active participant in numerous electric utility industry forums.

Early on, it was determined that a standard protocol developed with input from a group of interested parties was necessary to provide newly required data manipulation capabilities. The Inter-Control Center Communications Protocol (ICCP) was the result of an effort by power utilities, major data exchange protocol support groups, Electric Power Research Institute (EPRI), consultants and a number of SCADA/EMS vendors to develop this comprehensive, international standard.

In September 1991, the Utility Communications Specification Working Group was formed to: - Develop the protocol specification and a prototype implementation for testing. - Submit the specification for standardization. - Perform inter operability tests among the developing vendors.

The Utility Communications Specification Working Group submitted ICCP to the International Electrotechnical Council (IEC) Technical Committee 57, chartered with developing standards for power systems control and associated data communications, as a proposed protocol standard in 1994/95.

The first successful implementations of ICCP between SCADA/EMS control centers occurred in late 1995. This led to further expansion and allowed communications and data exchange over wide-area networks, between utility control centers, utilities, power pools, regional control centers and non-utility generators. By 1996, ICCP's position as an emerging standard had solidified, and U.S. utilities accepted it as the preferred means of communication for control centers. "We say control centers, but it really goes beyond that," said Dave Becker, manager, Control Center Technologies, EPRI. Becker continues, "Wherever you need real-time data ICCP is the protocol of choice." In 1997 ICCP was approved as an IEC/ISO international standard.

In November 1996, North American Electric Reliability Council (NERC) recognized the need for a network to send real-time data and tie together all its regions. NERC's adoption of ICCP catalyzed the growing adoption of ICCP and solidified its position as a standard in the industry. In October 1997, the Union for the Coordination, Production, and Transmission of Electricity accepted ICCP for the European energy community.

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