Why Microgrids Are Inevitable
And why smart utilities should plan accordingly
Thursday, September 01, 2011
By Peter Asmus
The fledgling electric utility companies that emerged after Thomas Edison opened his small Pearl Street, New York City, NY, power station in 1882 originally focused on distributed energy generation (DEG) operating within a microgrid. Edison envisioned that the electric utility industry would involve small firms generating direct current (DC) power for individual businesses in microgrids. By 1886, Edison’s firm had installed 58 DC microgrids and some 500 isolated lighting plants in the United States, Russia, Chile, and Australia.
These early microgrids, which often served a mix of commercial and residential customers, were not a sustainable business opportunity. In 1896, the first alternating current (AC) power flowed from a hydro plant at Niagara Falls to serve Buffalo, NY, some 35 kilometers away. This event established the trend of moving away from DC-based microgrids to AC long-distance transmission. Meanwhile, regulation shifted from local to state control. Over the course of the early 20th century, isolated microgrids offered by competing utilities gave way to a monopoly system featuring centralized power plants owned by utilities.
Rapid technological changes and the adoption of AC transmission and steam-turbine power plants, allowed small, but growing utilities to copy the economies-of-scale business models that dominated thinking at the time, with the railroad’s rail grid perhaps being the best example. New transformers spurred on the large transmission grids now so common in the industrialized world. Prices for electric service dropped consistently until the 1970s, when the energy crisis hit, and the dominant business model first came under attack as fossil fuel prices spiked, and utilities began raising rates to its captive ratepayer base. Upward pressure on rates was also fueled by cost overruns at nuclear power facilities.
For the next several decades, utility monopolies favored the economies of scale of large coal, then nuclear, and then natural gas power plants. This trend toward larger and larger generation facilities began to shift in the 1980s due to the passage of the Public Utility Regulatory Policies Act (PURPA). Another contributing factor was the emergence of independent power producers, which built generation facilities that relied on alternative fuels including wind, solar, geothermal, and biomass resources. Yet, these resources were still developed according to the central power plant radial model. The exception was the natural gas-fired cogeneration plants that provided onsite electricity and thermal energy.
Today, though, a variety of trends are converging to create promising markets for microgrids, particularly in the United States. It has become increasingly clear that the fundamental architecture of today’s electricity grid, which is based on the idea of a top down radial transmission system predicated on unidirectional energy flows from large centralized power plants, is obsolete. If, indeed, the electricity grid begins to resemble the Internet due to the proliferation of DEG, then aggregation platforms, such as the microgrid, will become vital.
What Are Microgrids—Why Are They Needed?
The fundamental concept of any “microgrid” application can be summed up as follows: an integrated energy system consisting of distributed energy resources (DERs) and multiple electrical loads operating as a single, autonomous grid either in parallel to or “islanded” from the existing utility power grid. In the most common configuration, DERs are tied together on their own feeder, which is then linked to the larger grid at a single point of common coupling.
Given the sprawling nature of today’s existing utility transmission and distribution (T&D) grid, why would any end-use customer (or electric utility) be interested in microgrids? Consider the following facts:
- The US grid was graded a lowly D+ by the American Council of Civil Engineers in 2009, with the prime shortcoming being a lack of investment in new transmission capacity to keep up with both growth in demand and corresponding investments in new generation sources.
- Lawrence Berkeley National Laboratory (LBNL) statistics show that 80% to 90% of all grid failures begin at the distribution level of electricity service. Microgrid advocates, both inside and outside of the military, argue that these failures can be mitigated at the local distribution level through microgrid technologies.
- Since electricity travels at almost the speed of light—186,000 miles per hour—a power outage of just 1/60th of a second can crash critical radar systems or critical life support systems in Veterans Administration (VA) hospitals. On average, each US consumer suffers a four-hour power loss annually, an outage rate 30 times higher than in Japan.
The most compelling feature of a microgrid is the ability to separate and isolate itself—known as “islanding”—from the utility’s distribution system during brownouts or blackouts. This ability, along with the capacity to optimize and better manage renewable distributed generation sources such as solar photovoltaics or small wind is why the US Department of Defense (DOD) is so enamored by microgrids since these islanded structures can isolate critical mission functions from the larger grid, ensuring secure power under a variety of dire scenarios, even terrorist attacks or other forms of hostile interventions.
Under today’s grid protocols, virtually all distributed generation, whether renewable or fossil-fueled, must typically shut down during times of power outages, so they do not feed power back to the larger utility grid. This fact exasperates microgrid advocates, who argue that this is precisely when these onsite sources could offer the greatest value to both generation asset owners and society. Such sources could provide power services when the larger grid system has failed the mission critical functions of the military. DEG system owners could, with additional technology advances and standards, provide ancillary services that would help their host distribution utilities maintain reliability, while serving their own power needs.
The cultural bias against islanding by utilities that was most clearly expressed in the IEEE Standard P1547 requires an automatic and rapid disconnection of all DEG during grid outages. For well over five years, the IEEE has been working on developing a “guide” on islanding. This guide—P1547.4—received a 90% approval in voting in late 2009. This standard will finally be published in the summer of 2011. This vote is a major step forward, as not only does it spell out safe utility protocols for islanding, but puts into place standards for reactive power, which will allow microgrids to sell ancillary services to distribution utilities. Though P1547.4 may not become a binding standard for utility operators for another five to 10 years, it is a major milestone for the emerging microgrid industry.
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Photo source: Encorp
Figure 1. Typical solar PV microgrid topology |
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Photo source: Pike Research
Figure 2. Renewable Distributed Generation capacity additions, world markets: 2009
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Solar PV, Micro Storage and CHP Key Technology Drivers
The prime technology drivers behind the need for microgrids are solar photovoltaics (PV), new greener and cheaper micro-storage technologies, and Combined Heat & Power (CHP) plants.
The most advanced technological components comprising a microgrid are all forms of distributed generation. These smaller, and often cleaner, onsite generation units are increasingly being fueled by renewable resources, such as the sun and wind. However, the vast majority of today’s micro-generation units, ranging from less than 1 kW up to more than 1 MW, are fossil fuel-based systems including diesel, natural gas, and propane. The most popular renewable distributed technology today is clearly solar PV, and the IEEE and others postulate this technology has the potential to become the lowest cost electricity source, driving microgrids into the mainstream over the next two decades.
The other key hardware technology that will enable attractive microgrid value propositions will be cost-competitive micro-storage. This is the current “weak link” among the microgrid components. However, battery technologies are advancing rapidly, thanks to investments in plug-in hybrid electric vehicles (PHEV) by the auto industry. Thermal storage options are currently readily available.
The lack of current cost competitive storage has resulted in CHP systems as serving as anchors of many current microgrids, since they can provide continuous power, while also helping balance variable renewables. CHP system may be able to run on waste fuels. Since they provide electricity and heat, they make more efficient use of fuels. Finally, they can serve as a bridge battery for microgrids during the transition to island mode.
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Photo source: DOE
Figure 3. Current microgrid project/test center landscape in the United States |
Progressive Utilities Leading the Way
The federal Department of Energy (DOE) and DOD are among the critical government agencies funding initial microgrid pilot projects. However, American Electric Power (AEP), San Diego Gas & Electric (SDG&E), and the Sacramento Municipal Utility District (SMUD) are all utilities that recognize that microgrids may be a technological platform that could help them retain customers by providing premium, uninterruptible power supplies and help them stretch resources to meet peak loads.
American Electric Power
When it comes to microgrids and storage, AEP has to be considered the world’s leader and a peer-to-peer microgrid incubator. It not only hosts the Consortium for Energy Reliability Technology System (CERTS) R&D test site, which began testing in 1999 and was fully commissioned in early 2008, but has also deployed (and is deploying) more microgrids than any other utility (or other entity) in the world. The CERTS microgrid control technology is the most radical of all options—as well as the lowest cost—as it is embedded into a 100-kW CHP system offered by Tecogen.
Perhaps its most forward-looking program, however, is its Community Energy Storage (CES) effort. AEP’s CES program looks to develop 80 microgrids at the transformer on the distribution line, each serving three to four homes. Each CES project is a 25-kW microgrid with 25 kWh of storage. The utility is also looking to tap PHEV as storage devices for this program. Over the next five years, AEP projects the cost of two hours of storage at the community level with PHEVs will equate to $1,000 per kilowatt or $500 per kilowatt-hour; these costs will decline as PHEV penetration levels increase.
Since AEP has set a goal of deploying 1,000 MW of advanced “backyard” storage (2.6% of current generating capacity) by 2020, it is clearly the leader among US utilities in pushing the microgrid model, with storage being the lynchpin technology, into commercial status. Though not technically microgrids according to the Pike Research definition, AEP has also deployed NaS batteries on the scale of 1 MW to 4 MW in size in Indiana, Ohio, Texas, and West Virginia. These systems are charged up by grid power, are currently operational, and have safe demonstrated islanded operations.
San Diego Gas & Electric
In 2008, the California Energy Commission awarded a demonstration grant to San Diego Gas and Electric Company (SDG&E) to pursue its Beach Cities Microgrid Project (and then DOE followed suit). At a total cost of approximately $15 million this demonstration will explore microgrid islanding of an entire substation area. The goals of the project are to reduce feeder peak load by 15% through the integration and control of multiple distributed generation and electrical energy storage devices, while improving substation area reliability in a cost-effective manner.
SDG&E will also be working with the University of San Diego (UCSD) to identify regulatory and policy issues associated with deployment of microgrids. At 42 MW in size, the UCSD’s commercially operating microgrid is among the most complex, incorporating solar PV, fuel cells, advanced storage, and legacy natural gas-fired turbines. This new optimized microgrid is an upgrade to an existing microgrid that has already been able to act as a demand response resource for SDG&E, shrinking the campus’ need for grid electricity by 40% during peak periods of demand. With the new control systems supplied by Power Analytics and Viridity Energy, this microgrid will be able to run in “island” mode the majority of the time, generating a cleaner and more secure power system for UCSD, while offering SDG&E a more diverse set of demand response and other grid support services.
This work is only just beginning for SDG&E. The utility hopes to gain new insight regarding the regulatory implications of utility microgrid investments as both of these projects progress as well as a more practical understanding of how to institute utility-owned microgrids in restructured electricity markets.
Sacramento Municipal Utility District
SMUD is also bringing the CERTS microgrid software control system out of the laboratory into a real-world setting—its corporate headquarters. This 310-kW microgrid will feature three 100-kW CHP units manufactured by Tecogen. The other key technologies involved are an existing 10-kW solar PV system and a 12-ton absorption chiller. The islanded system will power vital loads during a grid outage including chilled and hot water distribution pumps, controllers, cooling towers, and other related equipment.
SMUD has been a pioneer among municipal utilities in developing renewable resources. The company is the only California utility offering “virtual net metering” with its Solar Shares program, and it has one of the most successful solar PV programs in the country.
Perhaps its most forward-looking work in the microgrid space, however, is a $6-million residential storage project that offers an alternative to AEP’s community energy storage concept. Working with SunPower (solar PV panels), Saft (Li-ion batteries), Silent Power (HEA inverter system), and GridPoint (power monitoring and dispatch software), this residential energy storage (RES) pilot project is designed to demonstrate how to leverage federal and state subsidies to bring down the cost of storage at the individual residential level. For example, the battery backup is included as part of the solar PV system and, therefore, is eligible for the 30% federal investment tax credit. Since SMUD is a municipal utility, the RES model does not bump up against some of the limitations facing investor-owned utilities, such as preferences for large capital costs that can be put into the rate base and conflicts between shareholders and ratepayers.
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Photo source: AEP
Figure 4. AEP’s Community Energy Storage systems |
Conclusion
Given the diversity and versatility of microgrids, it is virtually impossible to map out concise, consistent business case. As one smart grid software provider described the situation: “Microgrids are like Baskin-Robbins, but there are a lot more than 31 flavors.”
Despite intellectually appealing rationales, the fact of the matter is that utilities protecting the status quo are still frustrating the move to microgrids. Most utilities are moving forward with grid infrastructure upgrades that do not accommodate future microgrid functionality. Too much attention and investment dollars may be flowing into projects designed to upgrade the entire grid instead of differentiating services based on customer cost, reliability, and environmental needs. Pike Research sees microgrids and a truly intelligent grid as a continuum. In other words, microgrids can serve as the ideal building blocks for tomorrow’s interactive, two-way, and self-sustaining grid infrastructure.
Thomas Edison would be proud of AEP, SDG&E, and SMUD. No doubt others will soon be following in their footsteps.
Author's Bio: Peter Asmus is currently a Senior Analyst with Pike Research and has been writing about energy issues for over two decades. |
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