NEW + OLD = VALUE: Substation Automation, Legacy Equipment & Your Utility

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by John McDonald, GE Digital Energy

As utilities upgrade the legacy equipment on their distribution systems, an opportunity arises to capture more value from the resulting, hybrid configuration of new and existing technology. An example is the distribution substation. Utilities are refreshing the basic equipment of the substation, and they also are upgrading its automation gear. Let’s focus on the addition of intelligent electronic devices (IEDs) to the existing array of remote terminal units (RTUs), both in the substation and downstream on distribution feeders, and the resulting opportunity to capture more value from the resulting data.

The implementation of IEDs provides not only a rich new source of data that can benefit the entire utility organization, it also improves the business case for IEDs and, not incidentally, aids in lowering the siloes that keep a utility’s operations staff and information technology (IT) staff from full cooperation.

Drivers of Transition

Microprocessor-based IEDs with two-way communications capabilities are augmenting analog RTUs because the former provide much greater functionality than the latter. Specifically, RTUs provide operators only with operational data. IEDs provide operational data and nonoperational data with high potential value to most if not all utility business units. Using only the operational data from an IED, which costs an average of $5,000, is tapping only some 20 percent of its potential value. Accessing IEDs’ nonoperational data can provide business units with insights that will reap benefits across the board, from planning and engineering to maintenance, asset management and power quality groups–the gamut of utility enterprise groups.

Steps at the Substation

Think of a substation upgrade as a series of steps or levels of activity. First comes the addition of IEDs, which support the three functional data paths–operational, nonoperational and remote access–taking data upstream to operators in the control center and to the enterprise data mart. Second is the integration process, which takes advantage of the two-way communications capabilities in IEDs for their operational data and recording of nonoperational data to tap the other 80 percent of their value. Third, the utility must consider which applications to run at the substation level to optimize the operation of the substation and downstream, distribution feeders. Initially, IEDs were integrated with some legacy RTUs, but that arrangement still fell short of delivering the full value of such an upgrade. But the development of a family of products known as data concentrators enabled the collection and transmission of nonoperational data from the IEDs to the enterprise–the key to greater value described here. (Operational data, meanwhile, is routed to the control center.) The result of this transition from an RTU-centric arrangement to a distributed network architecture with IEDs and data concentrators is in contrast to the legacy, serial, point-to-point communications-based architecture. With the distributed network architecture, the legacy RTUs, if they can be maintained, simply assume the role of an IED until the end of their useful lives.

The OT/IT Divide

Let’s examine an example of how the new architecture can benefit the utility in several ways. Say the protection group in operations installs a protective relay, which detects faults and trips circuit breakers to quickly isolate the fault. The protection group comes to own that relay, which is an IED. The relay contains two pieces of information of interest to the maintenance group in the enterprise. Maintenance would like to know the level of energy associated with the arc that was quenched when the breaker opened (i2t). Maintenance also would like to know how many times in a given period the breaker has operated (operations counter). Both pieces of data lead to condition-based maintenance, a huge leap ahead over time-based maintenance. The protection group might not realize the value of the IED’s nonoperational data to enterprise business units or, too frequently, the operations unit simply doesn’t want enterprise IT messing with the urgent business of operations. In either case, silos are to blame. Either people aren’t talking to one another or they disagree when they do talk. In a holistic data management approach–the only defensible path financially and in securing regulators’ approval of automation projects–a utility would take full advantage of operational and nonoperational data from all its IEDs. All business units would be familiar with all IEDs installed in the field and their available data. A utility has many management options to ensure the cooperation of OT and IT in pursuit of such underexploited value for the entire enterprise. It begins when people talk in good faith, walk a mile (perhaps of a distribution feeder) in one another’s shoes and, if necessary, compensation and job evaluations become based on enterprisewide metrics rather than departmental wins. But let’s return to the capture of enterprise value through the extraction, concentration, storage and mining of nonoperational data.

Creating a Data Mart

As stated, nonoperational data from IEDs or computer systems (such as an energy management system (EMS) or an outage management system (OMS)) is sent upstream to a data concentrator at the substation. This data then travels across the corporate firewall to the corporate side to be stored in a manner that allows queries and data mining by business units on the corporate network. Operational data has been routed from the substation to the control center. A subset of this operational data also is sent to the corporate side for access by business units. Enterprise personnel need operational data to augment their findings, and they can access it on the corporate side. The mode of storage isn’t important. What is crucial is that the enterprise must create a data mart that allows enterprise business groups to query or mine all nonoperational data for their myriad purposes. To achieve full value by its users, a data mart must provide the results of queries and mining in useful form to the end user. So the design of an informational architecture in this application must begin by addressing who needs the data, which data must be accessed, in what form and in what specific temporal intervals. (These steps echo a utility’s approach to distribution automation in general: Where are IEDs placed and what metrics are needed?) Polling (and prodding) all enterprise stakeholders on their data needs leads to an enterprisewide data requirements matrix, a map that connects data needs with data sources. This process then leads to an inventory of IEDs in the field and their data attributes. Matching the enterprise data map on the need side with the inventory of the IEDs that provide pertinent data on the distribution system completes the picture, at least conceptually.

The Value of Standards

The addition of new technology to legacy systems and the resulting hybrid configuration underscores the value of standards. A utility’s legacy system is constrained by its current capabilities, thus the need for an upgrade. So a utility must inventory that gear–let’s focus on RTUs here–and answer certain questions. Does the legacy vendor remain in business? Is the legacy equipment based on open architecture and industry standards, and can it be upgraded? Are spare parts still available? Also, is there a logical migration path to the newer technologies?

The historic work of the power industry-funded Smart Grid Interoperability Panel 1.0 and its transition to a membership-driven SGIP 2.0 laid the foundation for the smart grid standards process and global harmonization of related efforts and outcomes. This includes the backwards compatibility of IEDs, for instance, and continued use of legacy RTUs as automation is improved.

For instance, IEC 61850, a global standard for substation automation communications, provides the benefit of standard variable nomenclature in place of the unique variable nomenclature of each vendor, endemic to legacy systems. The standardization of terminology regarding technology makes assembling a points list, for instance, much simpler, and eases the transition to automation.

Standards also apply to data extraction, concentration and storage, a critical process that delivers much value of automation to grid operators.

Conclusions

New technologies can be integrated with legacy systems and that creates a hybrid configuration with a new data network architecture. The integration of old and new is one challenge. But the promise, in the case of substation automation–an important first step in distribution automation in particular and grid modernization in general–is a new distributed network architecture with IEDs and data concentrators that yields high value with the delivery of (operational and) nonoperational data to business units. This improves the return on investment for an expensive proliferation of IEDs, it requires a degree of cooperation between OT and IT and it brings enterprisewide value to the utility. Proper integration of new technologies with legacy systems, particularly in the case of substation automation, opens a new, significant value stream in addition to the operational benefits one would expect.

John McDonald is director of technical strategy and policy development at GE Digital Energy. He earned a Bachelor of Science in Electrical Engineering and a Master of Science in Electrical Engineering specializing in power engineering at Purdue University and an MBA in finance at the University of California, Berkeley. He is past president of the IEEE Power & Energy Society (PES), an IEEE PES distinguished lecturer, board chairman of the Smart Grid Consumer Collaborative and board chairman of the Smart Grid Interoperability Panel 2.0 Inc., among many other affiliations. Reach him at johnd.mcdonald@ge.com.


Global Substation Automation Systems Market Value

Global Substation Automation Systems Market Value by Region, 2012 - 2020

Global smart grid deployments mean advanced grid optimization opportunities for utilities–the market for global substation automation systems is expected to reach $15.58 billion by 2020, according to a PennEnergy research report.

Substation automation systems allow electric utilities to optimize their substations and thus their overall distribution systems through technologies such as communication networks, switches, voltage regulators, sensors, substation monitors, intelligent electronic devices (IEDs) and data analytics packages. Companies such as ABB, GE, Schneider Electric, Alstom Grid and Siemens are striving to capture the lion’s share of the substation automation market. Niche technology vendors, however, have an opportunity to develop next-generation systems and software to build advanced substation systems rather than retrofits.

The analysis-ready strategic dataset in “Global Substation Automation Systems Market Value” includes global substation automation system market forecasts from 2012 to 2020, regional forecasts, and country-specific forecasts for 15 countries. (Premium members have access to all datasets). In 2012, North America accounted for 40 percent of the global market while Europe and Asia-Pacific accounted for 20 percent and 25 percent, respectively. By 2020, Asia-Pacific will hold 39 percent of the global substation automation market while North America and Europe will account for 25 percent and 18 percent of the market, respectively. By 2020, China, the U.S. and Japan will be the three largest markets for substation automation technologies, according to the report.

Major technologies in the data-set include control and protection, IT systems and applications, communication networks, and monitors, IEDs and sensors. In 2012, communication networks and monitors, IEDs and sensors accounted for 59 percent of the global substation automation market. By 2020, communication networks and monitors, IEDs and sensors will account for 58 percent of the market. In 2012, 55 percent of the market was made of new and advanced substation systems (vs. 45 percent for retrofit systems). In 2020, new and advanced substation systems will account for 60 percent of the global market (vs. 40 percent for retrofit systems).

Report site: www.ogjresearch.stores.yahoo.net/global -substation-automation-market-forecasts.html

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