The century-old, one-way electricity delivery model that has been serving the utility industry traditionally, is proving to be inadequate to support the rising demand and diverse energy options being explored by today’s consumers.
The widespread consumer interest in and resultant growth of distributed energy resources (DERs)—particularly, rooftop solar installations, which totaled 27.9 gigawatt (GW) of global installed capacity in 2017 — requires new electric distribution network technologies to accommodate them, and a fundamentally different approach to the electricity delivery model.
We certainly remember the paradigm of electricity being a linear system that flowed from generation to transmission to distribution, and ended with the consumer. But utility customers can no longer be considered mere “endpoints” on the grid who are passive “ratepayers,” with no control outside of the energy they consume. As laws and regulations globally continue to support customer-owned DERs for self and grid supply purposes, a growing number of utility customers can now be active grid participants. These customers have the capability to support their own generation and load control devices, providing direct influence over energy distribution and consumption. In fact, active customer participation is putting the clientele at the center of the grid equation like never before.
However, customer-connected DERs outside the utility’s direct control on the grid side, present an increasing operational challenge. The ability to manage, and ultimately optimize a much-more complex grid, is dependent upon having the visibility that comes with modelling all grid resources. This includes customer-connected DERs and other devices off the secondary distribution lines. Traditional distribution systems were not designed to take granular customer DER into account. The individual sporadic resources of DERs, as well as energy consumption pattern variations, once insignificant, now create a data void for utility distribution operators, as near real-time
DER operational data is usually unavailable to utility operators via SCADA and traditional distribution management systems (DMS).
The pitfalls of the data void
When faced with the necessity of integrating DERs within the enterprise system, the traditional approach to distribution grid management falls far short of the mark. Consider this scenario playing out in electric utility distribution territories all around the world:
Attracted by the economics and the idea of self-generating a part of the electricity they use, Mr. and Mrs. Garcia install rooftop solar panels. Then they follow procedure and request their utility provider to connect their system to the grid. Depending upon the utility’s priorities and program supporting residential solar, this is done in due course. Operations-wise, this connection is managed, using existing systems and bolt-on additions, but without the visibility needed to consider network impacts. Some of the Garcias’ neighbors then decide to do the same, and ultimately they, too, are connected and contribute their excess generation to the distribution grid. As customer rooftop solar interest snowballs without network updates, the lack of network visibility begins to create issues such as phase imbalance, reverse power flow and voltage violations for utility distribution operators.
But there are other issues beyond network visibility with “bolting on” to the same old tradition as well. Because customer-connected DERs are invisible to the network, they also cannot be optimally leveraged for outage management purposes. For the most part, risk analysis and planning continue without factoring DERs into network models and planning roadmaps. Additional DER customer services opportunities are missed. Similarly, utility-DER customer interaction remains at old-school levels, as “active grid participation” is extremely limited, with little or no third-party “aggregator” options.
Grid optimization with DERs
DER visibility is the foundation, but it’s only part of the equation. Utilities need an integrated approach to address DER planning that also includes future customer demand and the impact on grid operations, as well as asset and workforce management. Let’s consider this alternate scenario:
Mr. and Mrs. Garcia decide to install solar rooftop panels and contact their utility for connection to the grid. Using an automated new-connect process modified to accommodate the complexity involved in connecting new customer DER, the utility, simultaneously captures the key DER attributes it needs to model and manage the grid connection. It also uses this connect-and-energize process as an opportunity to increase its engagement with Mr. and Mrs. Garcia, ensuring they are aware of all the incentives they qualify for, and helping them to understand how they can adopt ongoing planning and management of their DER.
This entire process might include demand response programs and smart EV charging rates to mitigate problems inherent with renewable DER intermittency, such as partly cloudy days when solar PV output and voltage drops beyond standard limits in neighborhoods with high penetrations of rooftop solar. Demand response can be invoked for relatively short periods of cloud cover to diminish problems even before they occur.
Further, the connect-and-energize process increases an environment for deep and continued commitment between utility and DER customer. This obligation is crucial if the utility hopes to leverage customers and their DERs as resources.
From a distribution operations perspective, the utility can now treat the Garcias’ DER as a grid-side resource, and integrate it into the network model, where the DER is visible. In this way, the entire grid—including DERs—is now contributing data, with location-based profiling and the ability to apply DER supply on demand. On a macro level, the utility can begin extracting value from the volumes of complex data customer-connected DERs across its system. This data can be used in several divergent operational areas, including outage management, load shifting, demand response programs and more.
The utility also needs to approach DER service and maintenance differently. Once the DER is visible to the utility, it can be managed proactively within the context of the network model, with an eye on asset impact. It also opens new revenue opportunities where the utility may be able (depending upon regulations and geography) to deliver new, value-based services to Mr. and Mrs. Garcia. These might include alerting them when their solar panel output is dropping and their PV system needs maintenance, or increasing their choice to be able to participate in demand response or load shifting programs, or the sale of their excess or stored DER generation into other, third-party markets.
With full visibility of the entire network, outage management can be handled differently, too. For example, during an outage event, customers with self-supply DERs could be re-prioritized in favor of other urgently impacted critical infrastructure locations. As long as the self-supply DER locations are re-energized prior to exhausting their own energy supply, those DER customers avoid an outage, while others experience an outage of shorter duration. DERs can also be leveraged during a FLISR event: if a circuit that has been re-configured becomes overloaded, available DERs can help to alleviate that condition.
Once the DER is integrated into the network, the utility can leverage its value in planning and operating models. This will defer the need to build new generation or T&D infrastructure with these “non-wires alternatives (NWA)”. And finally, once all these measures are successfully incorporated into the system, the utility can circle back to Mr. and Mrs. Garcia and to its other DER-connected customers with new programs, new information, and new models for continuing customer engagement and interaction, increasing both participation and revenue.
The path forward
Using a platform-based approach to grid optimization provides the benefits of being able to fully incorporate distributed grid management with an holistic, enterprise-approach. Instead of the traditional, independent system-based efforts, an integrated approach is the next befitting step forward. Amalgamating future customer demands cost-effectively with regulatory changes, grid operations, asset management and workforce optimization will contribute to scale newer heights. While the ultimate roadmap to success is not one-size-fits-all, it begins by executing on a strategy that puts all the pieces of the grid management puzzle together and unlocks opportunities not just in one area, but across the entire utility enterprise.