In February of this year, the U.S. Department of Energy (DOE) gave a presentation entitled Visioning the 21st Century Electricity Industry: Strategies and Outcomes for America. This was a product of an internal DOE workshop to envision what the nation’s power sector could become by 2035, in order to inform and coordinate the DOE’s electricity-related activities and programs. While it may have gone mostly unnoticed in the energy industry, this vision did point out an interesting aspect to our nation’s power grid: the “blurring of transmission and distribution (T&D) presents numerous challenges and opportunities for innovation and outreach.”
Today, we operate a power system in the U.S. (and many other nations) that relies on high-voltage transmission (> 230 kVolts) and sub-transmission circuits (generally >69 kV) networked with distribution substations, and circuits at lower voltages. Generally speaking, federally-regulated bulk power transmission networks are designed and operated with greater levels of automation (e.g., SCADA/ EMS), accommodate two-way power flow, and now with Phasor Measurement Units, can be monitored with greater visibility and precision to achieve greater levels of reliability. Contrast this with the majority of today’s state- or locally-regulated distribution systems, which are designed primarily for one-way power flow, often with radial-fed designs and with limited, real-time operational visibility. This is even more of a challenge for traditional utilities which own both types of assets, especially across multi-state jurisdictions.
However, smart grid automation technologies and applications have the potential to fundamentally transform this situation. We are certainly seeing increased implementation of distribution system sensors, automated switches and reclosers, advanced metering infrastructure (AMI), two-way telecommunications networks (based on both public and private sector frequencies), and advanced software applications to leverage data from these devices. What the DOE described as the “pinch point,” or substation in their 2035 vision, we will one day see as only another nodal link separating two equal levels of power system automation (albeit at different voltages) in their design and operations. This will especially become true as we witness an increase in distribution-connected, plug-in electric vehicles, small-scale renewable energy systems, and localized electric storage devices.
Consider, for example, the notion of an advanced energy management system, essentially bridging this T&D link such that a control room operator has full visibility from the generation well-head to the customer meter? Would it not make sense to have this level of monitoring and control in order to increase reliability, safety, and resiliency of all aspects of the nation’s electric power infrastructure—especially as load volatility and disturbances on the distribution network become of greater concern to transmission operators?
To a large extent, we have many of the automation technologies available today to make this transformation, and are witnessing continuous improvements in two-way telecommunications and data applications for improved analytics and operations. So the key questions we will need to address may primarily come down to establishing an adequate balance between market drivers and regulatory authority (federal vs. state), sufficiency of standards and protocols (especially for cyber defense), as well as suitable market drivers (e.g., customer demand, climate change policies) for sourcing and recovery of investment costs and sharing of associated benefits. These issues will take considerable debate at a national level and will not be easy to resolve, but the transformation could conceivably occur well before 2035.
Rob Wilhite is the global director, Management & Operations Consulting, DNV KEMA Energy & Sustainability.