For Over Years, Our Research Firm Has Been Studying the Early Development of the T&D automation building blocks, the embryonic and emergent stages of what is today termed the Smart or Intelligent Grid. Our team has examined the adoption and utilization rates of smart technology that encompass the dozen or so major components of today's (and tomorrow's) Smart Grid.
We need to keep in mind there is a lot more to the Smart Grid equation than simply installing advanced metering devices and systems. A large advanced metering infrastructure (AMI) program may not even be the correct starting point for hundreds of the world's utilities. Perhaps it should be a near-term upgrade to control center operations, an electronic-device integration of the key substations, an initial effort to deploy feeder automation, or even a complete protection and control migration to digital-relaying technology.
There are, in fact, multiple aspects of Smart Grid development, some of which involve the administrative and operational components of an electric power utility. The development of the Smart Grid involves information technology (IT), operations and engineering; administrative management of customer information systems (CIS) and geographic information systems (GIS), as well as the control center and dispatching operation of the outage management system (OMS) and distribution management system; substation automation and true field automation; third-party services as well as in-house commitment; and, of course, smart metering at all levels.
No utility today can afford to isolate and solve one problem, while inadvertently creating another larger or more costly problem elsewhere as a result of limited visibility and quick-fix decision making.
As the Smart Grid building blocks are put into service, and as they become integrated and are made accessible remotely, the overall Smart Grid necessarily becomes more complex, more communications-centric and more reliant on sensor-based field developments.
In looking at the operational/engineering components of Smart Grid developments, centering on the physical grid itself (whether a transmission grid, a distribution grid or both), one must include what today comprises protection and control, feeder and switch automation, control center-based systems, substation measurement and automation systems, and other significant distribution automation activities.
On the IT and administrative side of Smart Grid development, one has to include the upgrades that definitely will be required in the near- or mid-term, including CIS, GIS, OMS and the wide-area communications infrastructure required as the foundation for automatic metering.
Based on Newton-Evans' internal estimates and those of others, spending for grid automation is pegged for 2008 at or slightly above US$1.25 billion and will approach $5 billion globally. When (and if) we add in annual spending for CIS, GIS, meter data management and communications infrastructure developments, several additional billions of dollars become part of the overall Smart Grid pie.
In a 2008 Newton-Evans survey, control center managers were asked to check the two most important components of near-term (2008-2010) work on the Smart Grid. A total of 136 North American utilities and nearly 100 international utilities indicated their two most important efforts during the planning horizon. AMI led in mentions from 48% of the group. Energy management system/supervisory control and data acquisition investments in upgrades, new applications and interfaces were next, mentioned by 42% of the group. Distribution automation was cited by 35% as a near-term thrust related to Smart Grid activities. GIS followed with a 30% mention rate. Fault detection, isolation and “service restoration,” a newer term, was mentioned by 20% of the group. Eleven sites (8%) indicated “no plans” for any near-term focus on Smart Grid activities.
There were substantial changes in Smart Grid priorities when the data is reviewed on the basis of numbers of customers served. The largest utilities are likely to be investing in AMI and distribution automation, in that order, while the utilities serving from 100,000 to 250,000 customers placed slightly more emphasis on distributed automation than on AMI activities. Smaller utilities serving from 10,000 to 100,000 customers were emphasizing GIS work during the 2008-2010 period.
There simply is not a straightforward generic (one-size-fits-all) roadmap to show any one utility how to develop a Smart Grid that is truly in that utility's unique own best interests. Rather, each utility must endeavor to take a step back and evaluate, analyze and plan for its Smart Grid future based on its (and its various stakeholders') mission, role, financial and human resource limitations, and current investment in modern grid infrastructure, automation systems and equipment.
Charles W. Newton is the president of Newton-Evans Research Co. He has been a 35-year career-long researcher of information technology products, markets and trends. email@example.com