Last week’s DistribuTech conference in New Orleans, the biggest electric grid technology trade show in the country, provided the latest glimpse into how utilities are seeking to reinvent themselves in a world of rooftop solar, behind-the-meter batteries, electric vehicles and other distributed energy resources.
Over the past decade of DistribuTech conferences, we’ve watched various technologies emerge from smart meters and distribution automation, to home energy management and customer engagement, to DER integration and grid optimization. We’ve also tracked the shifting vendor partnerships being formed to bring them to market, and whether they’ve borne fruit or faded away.
We’ve already covered some of the advances on these fronts from last week’s conference, including some of the first real-world products and deployments using the Wi-SUN field area network and the Open Field Message Bus specifications for managing networked nodes on the grid. But to get the big-picture view, it’s always good to check in with Mike Carlson, president of Siemens Digital Grid, who oversees the “digitalization” of one the broadest energy ecosystems out there, from wind and gas turbines to individual smart meters and behind-the-meter energy assets.
At last week’s DistribuTech conference, Carlson offered an overview of the company’s latest announcements, as well as how it’s progressing on some long-running initiatives. We also checked in with Sentient and Landis+Gyr at the show (more on that below).
Siemens on DEMS, DERMS and DERs
Siemens offers the latest advanced distribution management system (ADMS) for distribution grid operations, as well as its decentralized energy management system, or DEMS — the new name for its demand response management system, which is built “from the meter up” on the underlying software platform it acquired with its purchase of eMeter in 2012.
The past year has been a slow one for large-scale ADMS or DEMS contracts in the U.S., Carlson noted. While Siemens has competed on a number of RFPs, “the award levels aren’t as high as what we’ve been anticipating,” he said. And while there are various reasons for this trend, according to Carlson, “one of the main issues is data accuracy and how to achieve it.”
Simply put, many utilities — at least those that haven’t already undergone an ADMS upgrade — have tendered RFPs, received proposals from vendors like Siemens that detail everything they need to do before they can make use of an ADMS, and have found that they lack the data to implement the plan. Instead, they’ll settle for an extension of their outage management system, or another incremental upgrade, he said. (Read ahead for more details on this data disconnect and some of the technology solutions being offered at this year’s DistribuTech.)
Even those utilities that have done this work have to see their grid modernization investments pass muster with state regulators and the multitudes of stakeholders involved, he said. Siemens is working with Southern California Edison and integration partner Omnetric on a distributed energy resource management system, or DERMS, to provide “data and visibility across the entire distribution network, from grid planning to market forecasting, for more effective management of DERs,” and to “allow the utility to better define, forecast and control customer-owned distributed energy resources across their territory.” But, as Carlson reported, SCE’s grid modernization plan has been evolving over the year-and-a-half since it was first introduced.
Still, Siemens is moving ahead with some large-scale DERMS implementations, such as its comprehensive work with Hawaiian Electric on its island grid modernization efforts, integrating rooftop solar and energy storage systems as part of the Department of Energy SunShot grant-funded SHINES project. We covered some of the other advances from HECO’s long-awaited grid modernization plans at last week’s DistribuTech, including its pick of Landis+Gyr for an island-wide smart metering and distribution grid communications network, and its use of Opus One’s distribution grid modeling platform to manage its novel integrated distribution planning process.
Last month, Siemens was picked for the $93 million Canadian ($69.6 million) Smart Grid Atlantic project, partnering with Canadian utilities New Brunswick Power and Nova Scotia Power to deploy an Energy System Platform technology — a real-time optimization suite aimed at managing grid stability and renewable integration through tapping customer-sited or grid-connected DERs and flexible loads.
Nova Scotia and New Brunswick are already partners in the long-running PowerShift Atlantic project, which has tapped multiple technology vendors to use water heaters, refrigerators, pumps, compressors and other loads that can be turned off and on to help mitigate surges and sags in the provinces’ large and increasing share of intermittent wind power.
The new pilot project, backed by $35.6 million Canadian ($23.45 million) in government grants, is aimed at extending the connectivity and capability of this fundamental edge balancing concept. The goal is to "enable data analytics, ensure connectivity, and provide tools for developers to create customer-focused applications and services,” as Faisal Kazi, president and CEO of Siemens Canada, described it.
Microgrids are another venue for DERMS integration, said Carlson. For example, Siemens is the key partner in Commonwealth Edison’s Bronzeville, Ill. microgrid project, and has built an enterprise microgrid management platform to link its microgrids from a utility context, as it is doing with its community microgrids in Brooklyn, New York. Last year, Siemens proposed a series of “mini-grids,” or autonomous yet networked regional grids, as a blueprint for redeveloping Puerto Rico’s hurricane-ravaged electricity infrastructure.
Siemens' "digital twin" of the distribution grid
Carlson also highlighted Siemens’ new partnership with utility planning software vendor Bentley Systems on an “OpenUtilities Solutions for DERs” software platform, one that seeks to integrate distributed energy integration from interconnection request to grid operations. The system will “analyze, design, and evaluate DER interconnection requests through desktop and cloud-based services,” and then integrate that data into the “automatic network analysis models” used by Siemens PSS Sincal simulation software, as well as various GIS platforms like Esri, GE and Smallworld.
This DER solutions set also employs Siemens’ “digital twin” technology — a commonly used term for big data-driven modeling and simulation of real-world systems, whether they be power turbines or entire distribution grids, to test how they’ll perform under various conditions and scenarios. In the case of the Siemens-Bentley partnership, they’re promising a “GIS digital twin,” or a model of a portion of the distribution grid as mapped by a GIS, that could be used at various stages of the DER interconnection process.
First, it could screen DER interconnection requests against the hosting capacity of the circuits they’re seeking to connect to, and see whether they’re OK to pass on without further study or need to be shunted to power system planners for review. Second, once they’re under review, the platform can perform “accurate forecasting, state-of-the-art models and the ability to efficiently study many power flow scenarios within the network.
By tapping the massive computing power of the cloud, the platform can also expand the scenarios available for testing, to “analyze both planned and existing infrastructure, optimize equipment sizing, and estimate materials and labor costs for DER projects,” to cover some of the key variables involved in DER integration. These are also some of the capabilities that utilities are being asked to develop by regulators in DER-rich states like Hawaii and California and states that are innovating with forward-thinking policy reforms like New York and Minnesota.
“Where I think Siemens is really differentiated in its plan [is] that the digital twin also becomes part of operations," said Carlson. "Typically, with the planning group and the operations group, there’s not a lot that connects the two. Digital twin will allow that connectivity to occur in real time.”
Still, the earliest cases for these types of digital twins is likely to remain in the planning realm, as with the OpenUtilities DER platform and its early application for screening DER interconnection requests. In order for grid operators to start relying on the system for day-to-day operations, “the operator has to have confidence that what the digital twin simulation is telling them is accurate.”
Sentient says it can turn grid sensor data into predictive fault detection
Most distribution grids between the substation and the metered endpoints are more or less dark to the utilities that operate them, which is a problem for those that need to manage a rising tide of DERs on their systems. Siemens’ Carlson acknowledges the challenge that this lack of data presents to utilities seeking to implement the latest ADMS and DERMS capabilities.
This view was backed up by a survey released at DistribuTech, conducted by Energy Acuity for GIS software vendor Esri, that polled 122 electric utility representatives, most of them in the U.S., and ranging from midsize to very large companies. While almost all the utilities surveyed use GIS as a multidepartmental system of record for utility distribution data, only 23 percent reported “high confidence in their GIS data,” and “most reported significant error rates.”
This is a predictable, if lamentable, result of the fact that distribution grids are constantly being repaired. They're often being patched up after storms or traffic accidents, having equipment ripped out and replaced, and undergoing other alterations that fail to make it into the GIS, or are inaccurately recorded, and need to be cleaned up before an ADMS can be useful.
New technologies to digitize this kind of work, as well as to integrate the systems used by line workers and asset management departments with those that inform the GIS and distribution grid operations, could help resolve these data gaps, the survey noted. But not all utilities are taking advantage of the latest available technology on this front. For example, while 85 percent of utilities use GIS in the field, only one-fifth use “complete viewing and editing capability” (i.e., the latest mobile workforce tech support). And while 40 percent of utilities are designing new systems within GIS technology, nearly 35 percent are redrafting from older computer-assisted design or even paper planning documents.
The current utility response to this challenge, as reflected in some high-profile grid modernization plans we’ve been covering of late, is to call for interoperable communications networks and sensors to collect the data that’s missing between substations and smart meters, along with the distributed intelligence to manage the disruptive effects of DERs that can happen too fast for grid control systems to manage.
At last week’s DistribuTech, Sentient Energy, maker of some of the country’s most widely used distribution grid sensors, unveiled its own solution to this problem — a “ubiquitous distribution grid monitoring and analytics system,” one that CEO Jim Keener claimed “officially transitions the grid reliability paradigm from reactive to proactive.”
Sentient Energy has become one of the larger providers of sensors for overhead distribution grids, with marquee customers including Florida Power & Light, Southern California Edison, and Pacific Gas & Electric. This growth has been driven in part by its early integration with Silver Spring Networks, now part of Itron, as well as later integrations with Landis+Gyr. This scale has allowed the startup to field-test the analytics that are now going into its new platform, as well as prove its devices are capable of carrying them out, computationally speaking.
Sentient relies on its Ample Analytics Suite to turn the data gathered into predictions of when equipment will fail or operational thresholds will be exceeded. “At any point in time, significant changes in load and load direction, as well as faults and pre-fault disturbances, are detected so that applications such as State Estimation can leverage real-time data for distribution power flow applications,” the startup states. If properly used, this flow of data can “pinpoint the location and cause of potential service disruptions before they occur.”
While the company didn’t disclose the names of any customers using the platform, “major utilities that are using the system are reporting significant improvements,” according to a Wednesday press release, as well as achieving benefits to extending asset life, vegetation management, and DER siting and integration. The whole thing is enabled via mesh networks or 4G/5G cellular networks from AT&T, Verizon and Telus, and comes with tools for fleet managers, reliability engineers and other utility users.
Landis+Gyr and Sense put energy disaggregation into the smart meter
Landis+Gyr and Itron are the country’s two dominant smart meter and grid networking vendors, and both are competing to extend their core AMI networks to include the broader internet of things. We already covered Landis+Gyr’s selection as HECO’s grid modernization plan AMI and networking provider, and the Swiss-based company also announced contracts with two unnamed U.S. utilities for a combined 1.5 million smart meters last month.
At last week’s DistribuTech, Landis+Gyr was also demonstrating its meters’ latest ability on the edge intelligence front — disaggregating whole-home energy data into specific information on the energy usage of air conditioners, appliances, lights, electronics and other typical loads, courtesy of Cambridge, Mass.-based startup Sense. Under a partnership announced last month, Landis+Gyr is making Sense’s software available as an application that can be uploaded to the Connect IOT platform within its latest generation of GridStream meters
Landis+Gyr also announced that it had joined as an investor in Sense’s Series B round, bringing the round’s total to $20 million, adding about $2 million to the original $18 million announced in October. Sense has raised a total of $40.6 million since its 2013 founding from investors including Schneider Electric, Energy Impact Partners, Shell Ventures, Prelude Ventures, Capricorn Investment Group and iRobot.
Sense’s high-resolution disaggregation technology, built on speech-recognition algorithms, can parse out one to two dozen different loads in real time, down to garage doors opening or refrigerator compressors failing — a level of accuracy that simpler systems that use interval meter data can’t catch. But it also requires an in-home device that can monitor electric mains in real time, at a cost of hundreds of dollars — or at least, it did, until it became embeddable on Landis+Gyr’s meters.
"We knew the retrofit hardware was the right starting point, because we can get to market fast — but we also know it doesn’t scale,” Michael Phillips, Sense co-founder and CEO, said in a pre-DistribuTech interview. “The only way to scale is to make it so that the hardware part of what we do can live in the infrastructure itself, and the obvious spot for that is the meter.”
John Ragowski, Landis+Gyr’s vice president of portfolio management, noted that Sense’s technology can support real-time analytics as well as historical breakouts of energy usage. “Understanding in real time what’s happening in the home isn’t just about traditional disaggregation benefits,” he said. Being able to detect if an air conditioner is about to fail during a heat wave, or an electric heater during a polar vortex, for example, could be considered a valuable safety benefit for customers and utilities alike.
But to put Sense’s admittedly “rich software stack” to use for these real-time purposes, Landis+Gyr’s internet-of-things platform has to be able to properly delegate and prioritize which data has to be analyzed where, and at what speed, he noted. “Part of the intent of the platform is that not all of that data needs to be sent back” to the cloud for analysis or storage, he said. “In addition to the intelligence in the endpoint,” or the meter, “we’ve added the capability to put intelligence in the community level — that could be at a substation along the feeder. It’s our layered intelligence approach.”
“Ultimately our vision is that the traditional utility SCADA management system, or a DERMS system, won’t entirely live in a utility’s data center, in the back office,” he said. “You will have distributed computing. And we know we won’t be the ones to develop all of it. Our intention is that this platform can, even at the community level, serve smart city or smart neighborhood capabilities.”