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Self-Powering Ethanol Production
by Jonathan Eisenthal

Two years ago, when Chippewa Valley Ethanol Company in Benson, Minnesota brought stage one of its biomass gasifier on line, it seemed like an industry-leading position.

Here was a technology that would eventually replace 90 percent of the natural gas the plant consumed, and substitute a cheaper and more economically stable alternative using renewable biomass. The project would save CVEC millions, it was hoped, and result in an enviably small carbon footprint.

Yet the expected flood tide of imitators never came in.

Today, CVEC’s gasifier is still the only functional biomass gasifier in the dry mill ethanol industry, and when natural gas prices remain low, as they are now, the plant chooses not to operate the gasifier. However, it is important to note that the past two years have seen the worst financial turmoil since the 1930s – a situation that could take the wind out of even the most promising business developments.

Natural gas is the feedstock used by all but four of America’s ethanol plants, mostly to run both process heat and electric power systems. An abundant domestic resource that burns cleaner than oil and coal, natural gas has many advantages, but it still means taking long-trapped carbon and putting it into the atmosphere.

As the evidence supporting global climate change theory mounts, and the political will grows worldwide for a solution, it becomes clear that carbon emissions will eventually incur a bottom-line cost to businesses that use fossil energy. Until that cost becomes actual, and while the cost of natural gas remains low, biomass gasification remains a great innovation without an incentive for adoption.

Through a combination of factors that would have been hard to foresee, natural gas prices settled to a point very competitive with self-power alternatives. Four years ago, when then CVEC General Manager Bill Lee helped put together Frontline BioEnergy – a CVEC spin-off that focuses on earth-friendly self-powering solutions – gas prices ranged from seven to eight dollars per decatherm. Now, it’s four dollars per decatherm.

Another promising technology that could really flourish if a carbon accounting system becomes law is biocoal. Minneapolis-based Torrefaction Systems, Inc. – or “Torrsys,” a Bepex International LLC spin-off company – has developed a mild-pyrolysis technology that upgrades raw biomass into a coal-like product and then densifies it. Company representatives say that based on the existing pilot plant, the technology appears to be scalable, with a potential application in offsetting process heat and electricity demands at ethanol plants, while providing an additional source of revenue for the plant.

Just as gasifiers work with existing natural gas infrastructure, so biocoal can be used in regular coal-fired facilities, district heating systems, combined heat and power (CHP), and gasifiers. Its appeal lies in taking raw biomass – which has a low bulk density, can readily absorb moisture, is difficult to transport, has the propensity to rot, and is difficult to grind up – and upgrading it to virtually eliminate these negative aspects. The Torrsys biocoal process upgrades raw biomass into biocoal which can be used in existing infrastructure with little to no modification.

Seeing both the carbon savings and potential cost savings that come with these biomass solutions, a growing number of energy solutions providers are betting that self-generation will rise again. US Energy Services, based in Plymouth, Minnesota, helps companies develop the most cost-effective strategy for acquiring the energy they need for their manufacturing processes.

Average industrial electric rates nationwide have risen 30 percent in the past five years, and the potential for gasifiers and other alternatives to deliver a portion of a plant’s power could mean substantial savings, according to Steve Rambeck, an account manager at US Energy Services.

In a recent presentation for the Fuel Ethanol Workshop, Rambeck noted that four factors are driving electric rate increases: the slowing economy drastically reduced utility company revenue, and yet many of these companies at the same time are facing legislative mandates to increase the renewable generation sources in their portfolios, and there is also a rising volume of retrofits required for environmental mitigation. All this is happening while new sources like wind and more widely dispersed customers mean that new lines of transmission must be built and existing lines must be upgraded. So the utilities are winning rate increases in the public rate case process.

“You haven’t seen an explosion of self generation because (industrial) power has been around four cents per kilowatt hour for a long time,” Rambeck said. “But when it begins rising to six or seven cents per kilowatt hour, that’s when you will see a number of these options become more viable.”

This effect has hit full force on the East and West Coast where electric rates range between 10 and 15 cents per kwh, and he believes the Midwest may see similar increases due to these same factors.

“Renewable generation to meet portfolio standards, especially the introduction of wind and other sources, has forced these utilities to not simply choose the most economical path,” Rambeck said. “Also there is the replacement of the aging systems, partly driven by the need to capture all the wind generation that is being built.”

Carbon emissions policy seems to be coming along at the same time as all this dynamic change in the electric industry. We saw the passage last summer of a “cap-and-trade” law in the House of Representatives and progress by its Senate companion, the bipartisan Graham-Lieberman-Kerry bill. The essence of the law would be to limit the amount of carbon various industries can emit, and those who go over that amount must purchase offsets or credits from those whose activities remove carbon from the atmosphere.

We won’t know how expensive traditional fossil energy sources will become compared to the alternatives until the actual incentives, taxes, or other mechanisms for encouraging low carbon alternatives become law.

What can be said about CVEC and a handful of technology providers now launching their first large-scale projects is that they are gaining experience which should put them out in front of the pack, and in a position to capture handsome portions of an emerging market. Experience running these new technologies, overcoming challenges, working out the bugs, would put the pioneers in the driver’s seat.

The 3,700 accrued hours of biomass gasifier operation at the Benson ethanol plant provide invaluable information to CVEC and Frontline BioEnergy, the company that is focused on renewable repowering solutions, not just for ethanol, but also for all industrial applications.

“The guys involved in trying to market these gasification systems have to have data to show to potential customers to say, ‘hey, I can guarantee this process.” said Bruce Folkedahl, a senior research manager and expert in renewable energy at University of North Dakota’s Energy and Environment Research Center (EERC) in Grand Forks. “CVEC’s experience is incredibly valuable.”

Frontline isn’t out there alone, however.

Colwich, Kansas-based ICM, Inc. is in position to capture a portion of the retrofitting market for its self generation solutions, being the design engineering firm for 102 ethanol plants nationwide. The company offers a scalable gasification system and something it calls a BioMethanator™, which turns organic compounds in the ethanol plant process water into methane gas that can be burned to generate power. Not only does this process buy down a plant’s energy costs, but it can also help it to recycle and reuse water, potentially representing another savings, the company says. ICM has been running its pilot gasifier at a rate of 150 tons per day, and its commercial scale gasifier will be designed to handle between 300 and 400 tons of biomass per day.

“Most of the ethanol plants looking at gasification systems are looking at them in conjunction with cellulosic material – grasses, stover, corn cobs – to convert those into ethanol. Then, a residual stream of recalcitrant lignin can be gasified to provide processs heat for the front end of the process,” Folkedahl said.

POET Energy’s cellulose ethanol demonstration plant in Emmetsberg, Iowa, dubbed Project Liberty, will take the lignin left over after processing corn cobs for ethanol and use that lignin as a source for at least a of portion of the plant’s power requirements. A biomass gasifier may also become part of ICM’s cellulose ethanol process at its plant in St. Joseph, Missouri.

Frontline BioEnergy’s solution can also work at the front end of a cellulose operation. Part of the gasifier’s production can be converted into ethanol.

Both gasification and biocoal solutions would develop new markets, new revenue streams for agricultural and forestry producers – perhaps even turn part of a city’s waste stream into a marketable commodity.

Gasification – the conversion of solids into liquid or gaseous fuels via partial combustion

Biomass gasification is burning that stops short, according to Folkedahl.

He explains that complete burning of a solid piece of organic matter produces carbon dioxide and water, and this is an exothermic reaction – it creates heat. In gasification technologies, the feedstock is purposely burned incompletely under special conditions. In addition to carbon dioxide and water, the reaction produces carbon monoxide and pure hydrogen (H2) – gases that can be burned in a boiler system to produce heat or steam.

“If you already have a natural gas boiler and then you can provide your own gas that is cheaper than natural gas, or if you had credits that made it an economically viable solution, it could make a lot of sense to opt for a renewable-feedstock gasifier,” Folkedahl said.

In the case of a cellulose ethanol process, part of the biomass can be converted into a syngas, which can then be fermented into ethanol, methanol, and other advanced fuels.

Some consensus is arising around the notion that fluid bed gasifiers (as opposed to fixed-bed gasifiers) are more flexible in the range of feedstocks that can be used, but Folkedahl says the matter is not yet settled. EERC has worked with gasification technology for more than 50 years, focusing over most of that period on coal-fired systems, but in the past decade including renewable gasifiers, too.

“Frontline uses a bubbling fluid bed design,” said Bill Lee, the former general manager of CVEC who has transitioned to the role of CEO for Frontline BioEnergy. “The bubbling fluid bed can use anything two-inch or minus. It could be woody material, energy crops, ag residues, sorted municipal waste. We think it makes most sense to be prepared to opportunistically use whatever feedstock is the most economical – we can alternate among them or even blend them, as long as meet criteria.”

Biomass run through a gasifier still emits carbon dioxide equivalents, but the difference is that during the growth phase of the plant matter it was binding carbon into the plant, the root and the soil – the net effect is no increase in carbon volume in the atmosphere, in the case of natural gas or coal-fired boiler processes.

The conditioning and clean-up of the gas at the front end makes Frontline BioEnergy’s gasifier ideal for retrofitting existing natural gas boiler and turbine equipment, according to Lee.

Torrefaction Systems also touts the biocoal solution from the standpoint of flexibility. Not only can it take in a wide spectrum of biomass over a wide range of size and moisture conditions, but the final product, which is dry and grindable like coal, is not apt to rot, as raw biomass feedstock might.

Public policy and existing infrastructure may dictate where these technologies take hold

In the late 1970s and early 1980s, federal policy put the brakes on nuclear energy just at the moment when electric generation development was ramping up to meeting surging demand from business and residential customers in the Midwest. The result – the utilities developed a whole lot of coal-fired generation. What was a benefit then – non-radioactive energy that is domestically abundant – may turn into a liability now. Depending on how cap-and-trade turns out, electric customers that depend on coal-fired electric generation could see major rate hikes.

The existing coal infrastructure and abundance of biomass are two reasons Torrsys may find a natural base here in the upper Midwest, while also being able to leverage international markets via the Great Lakes. Its energy medium, biocoal, shares many of the positive aspects of coal – the ability to transport it in dense mass and then pulverize it to the appropriate size and use it in systems engineered for coal-fired power systems – without changing any of the coal-burning equipment.

But unlike coal, biocoal can be created on site using corn stover or residual lignin, for example. During production, biocoal produces significant excess heat that can be used onsite to help offset process heat and electrical loads at the ethanol plant, while at the same time providing a new “biocoal” product for the plant to sell to electrical utilities.

The Torrefaction Systems business model is centered on the idea of co-owning the equipment with the power consumer, in order to help capitalize the implementation at the plant.

Bill Lee noted that only about half of the states have renewable energy standards on the books.

“That’s 27 states, not 50,” Lee said. “A national renewable electric standard would open up a lot of opportunity. As it stands, many of the 27 states have already started down the path of renewable development, mostly into wind power. We’ve found they have less appetite for renewable gasification than some of the states that haven’t passed a renewable standard yet. Also, the states that haven’t launched major wind power projects are often unsuited to wind development, so biomass gasification can make more sense in those places.”

The right balance – what portion of its total need should an ethanol plant generate for itself?

Experts call generating 100 percent of one’s own power, without reliance on the grid, going to “island mode.” They predict that few plants would choose that option. The decision of how much power to offset, or even to produce more than one needs and sell back to the grid, will be a very site-specific calculation , according to US Energy Services.

When the company worked with CVEC to develop its self-powering strategy, there were a number of factors to consider, according to Matt Haakenstad, the US Energy Services account manager working with CVEC.

“We manage their energy procurement, buying natural gas on an ongoing basis and electricity,” Haakenstad said. “They have a special interruptible rate. During the control periods they have to reduce plant loads to 4 megawatts in order to take advantage of that rate. When considering putting in the gasifier, CVEC had to consider how it would affect their gas contracts.”

And it was not a simple one-time change, but the development of the gasifier was conceived as a multi-stage project, meaning that its natural gas consumption would change over time.

“CVEC is still in phase one, where its gasifier can displace 15 to 20 percent of its natural gas use,” Haakenstad said. “They have not been running it the past few months due to competitive natural gas prices, but on the positive side, they are using that down time to put improvements into the system.

Gasification, ideally, is a system where nothing is wasted. The ash leftovers from the process, with a minor amount of processing, can be marketed as “char,” a product that farmers can use to enhance soil fertility in their fields. It takes things full circle, returning carbon to the soil that yielded it as biomass in order to produce energy.

Haakenstad noted another example of self-powering, also known as distributed generation – Sterling Ethanol LLC, a 42 million gallon per year plant in Sterling, Colorado, in the northeastern corner of the state.

“They’ve got a back pressure steam or steam let-down turbine system, which drops the steam pressure from 130 psi down to ambient pressure, but captures that energy along the way,” Haakenstad said. “It has to do with how boilers are configured. They need the 130 psi steam for part of their process, but not all. Their evaporators need ambient pressure. Without the let-down turbine they would have to bleed the steam down to atmospheric pressure. In this case they are able to capture and make use of that energy.”

The let-down turbine generates about a megawatt of electricity. This represents between a quarter to a third of the plant’s electric demand, which runs to three or four megawatts.

“These types of partial self-powering solutions – gasifiers, biocoal, methods of capturing the energy from process heat – these are all about being competitive,” Rambeck said. “You balance the cost of the energy you can offset, and the change in rates with the capital cost of the equipment and an interconnection charge. Different utilities have different types of billing, which enters into the calculation, too. Sterling, which is an Xcel energy customer, has to deal with integrated demand billing – if their turbine is down even 15 minutes, they go to a higher rate. Some utilities have coincidental billing, some have non-coincidental billing. There can be standby charges. This is all part of the picture that we can develop, so the ethanol company can focus on its grind margin and its expertise in producing the ethanol.”

© American Coalition for Ethanol, all rights reserved.
The American Coalition for Ethanol publishes Ethanol Today magazine each month to cover the biofuels industryís hot topics, including cellulosic ethanol, E85, corn ethanol, food versus fuel, ethanolís carbon footprint, E10, E15, and mid-range ethanol blends.
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