Generac Grid Services Blog

Ten years ago or so, when utility workers first started talking about IT/OT convergence, conversations revolved around the wealth of data streaming into utility offices from advanced metering infrastructure and remote sensors.

With AMI, for instance, utility engineers could suddenly see consumption in 15-minute increments, allowing them to leverage that data for things like load studies and distribution-system transformer sizing. Utility managers could use the blink counts from advanced meters to direct tree-trimming crews, letting them know there was a pretty good chance wayward branches were causing momentary outages on a feeder. Or, they could use the last-gasp signals to more quickly triangulate an outage and dispatch restoration crews more efficiently.

IT/OT convergence is what happens when IT and OT drop the silo walls to unite systems such as outage management with front-end, field technology like advanced meters or distribution system assets. But, IT/OT convergence has begun to expand as generation assets begin to proliferate behind the meter, and IT systems will be needed to help accommodate and control these assets. The convergence is becoming more complex and all-encompassing, so here are a few pointers for utility mangers to keep in mind.

Last year, analysts at Gartner placed IT/OT convergence on their Top-10 list of trends affecting the utilities industry. Actually, it’s been in progress for nearly a decade but, now more than ever, IT/OT integration looms as a crucial utility move. What’s more, it is factors outside utility walls that are rousing such urgency. What are they? Look around your neighborhood. If you see a lot of rooftop solar panels, some of those factors are sitting right in front of you.

What’s more, GTM Research forecasts a 94 percent increase in new PV installations in the U.S. during 2016. Worldwide, Navigant Research says, “Annual installed capacity across the global distributed energy resource (DER) market is expected to grow from 136.4 GW in 2015 to 530.7 GW in 2024, representing $1.9 trillion in cumulative investment over the next 10 years." 

What does this have to do with IT/OT convergence?

Raise your hand if you sometimes feel like Mr. Scott from the original Star Trek series, frantically trying to keep the engines roaring while the ship takes one phaser hit after another: If you did raise your hand, you’re not alone. There are plenty of reasons utilities might be playing the Mr. Scott role.

One is under investment in infrastructure, which was named as the top concern by 47 percent of utility executives who answered a Utility Dive survey late in 2015. Another is what the California Independent System Operator calls the Duck Curve. It shows how behind-the-meter solar installations are creating daytime over-generation on the California grid and, because rooftop solar quits generating power about the same time people come home and start using more of it, there are steep ramps at the end of the day.

Demand response programs could help utilities deal with these issues. But, utilities that are doing simple demand response are kind of like Star Trek’s Scotty. They’re just getting by, handling one crisis after another, giving it all she’s got, Captain. “I don’t think she can take any more!”

INTRODUCTION:

Researchers at DNV-GL did a fine report for the New York Independent System Operator a few years ago. Titled A Review of Distributed Energy Resources, it offered this definition of the various distributed energy resources (DERs) examined in the report:

“… DER technologies are defined as ‘behind-the-meter’ power generation and storage resources typically located on an end-use customer’s premises and operated for the purpose of supplying all or a portion of the customer’s electric load. Such resources may also be capable of injecting power into the transmission and/or distribution system or into a non-utility local network in parallel with the utility grid. These DERs include such technologies as solar photovoltaic (PV), combined heat and power (CHP) or cogeneration systems, microgrids, wind turbines, micro turbines, back-up generators and energy storage.”

Granted, the research team did acknowledge that some sources – including the New York Public Service Commission – included customer load in its list of DERs, but load wasn’t one of the DERs covered in the report. That’s too bad because load can hold its own against other DERs for a variety of grid-supportive purposes.

INTRODUCTION:

Fight or flight may be the two most common reactions mammals have when facing a threat, but for utilities that perceive distributed energy resources (DERs) as risky to business, there’s another option: innovate.

The rapid pace of disruption

Tony Seba, a clean-technology thought leader, author and Stanford University instructor, believes that the age of what he calls “participatory energy” – user-centric generation, storage, management and energy-market participation – will eclipse the utility-centric model of today by 2030.  

On one of my many travels recently, I got a chance to catch up on some movies that I had been meaning to watch.  One of those movies was “Steve Jobs.”  This movie, starring Michael Fassbender, gives an inside look at one of the true innovators of our time. 

The National Renewable Energy Lab has a great paper titled Flexibility in 21^st Century Power Systems. The paper addresses three grid requirements to accommodate increasing numbers of variable generation resources like wind and solar energy.

1. The first among those requirements is flexible generation. We need power plants that can run efficiently with a very low output level and ramp rapidly from those deep turn-down rates.
2. We also need flexible transmission to carry power without bottlenecks and facilitate access to a broad range of balancing resources. That’s requirement number two.
3. And, finally, the NREL authors say requirement number three is flexible demand-side resources. Those resources include storage, responsive distributed generation and loads engaged in demand response programs that can support the grid by responding to market signals or direct load control.

Amen to requirement number three.

According to FERC’s most recent "Demand Response and Advanced Metering Assessment," 74 percent of the potential peak reduction in retail demand-management programs comes from C&I customers. That means that the biggest, most valuable energy customers are also the most likely  allies in a demand response initiative.

Demand side management (DSM) is the umbrella term for the various methods that power providers employ to get customers to curb consumption. It’s been around since the 1970s, notes Joseph Eto, a Lawrence Berkeley National Lab researcher who wrote a detailed history of it in 1996. He counts conservation education, energy audits, efficiency freebies, financial assistance and time-based tariffs among the forms of DSM utilities use.

Eto also covers the technological approaches designed to achieve objectives like load shifting, peak reduction and off-peak consumption increases.

For too many people, demand-side management (DSM) of energy resources means one thing: shedding load. That’s a limiting and outdated view of DSM.

Given the right control platform, Distributed Energy Resources (DERs) can move their power consumption up or down to support the needs of the power system. To get the benefit of that flexibility, you need to think of all DERs – even loads – as resources that can be charged up the same way you charge a battery energy storage system.