Page 1



UPGRADE Ringneck Starts Up with Redesigned ICM Blueprint Page 16


E15 After RVP

Page 24

Lab Equipment Upkeep Page 30

The Power of CHP

Page 36

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Optimism in Onida

South Dakota’s newest plant starts up during industry low By Matt Thompson

A Break From the Bad By Lisa Gibson

'Zero Evidence' of Demand Destruction? Really? By Geoff Cooper





Market Movers

Factors to consider in post-waiver E15 projections By Lisa Gibson


Elevate and Collaborate By Brian Healy


Wondering What If By Steve Vander Griend








Validate and Calibrate Best practices increase accuracy, confidence By Susanne Retka Schill




Off the Grid

CHP lowers energy costs, carbon intensity scores By Matt Thompson


Ringneck Energy & Feed started up this spring in Onida, South Dakota. PHOTO: LANE WARNER, DAKOTA FILM CO.

Ethanol Producer Magazine: (USPS No. 023-974) October 2019, Vol. 25, Issue 10. Ethanol Producer Magazine is published monthly by BBI International. Principal Office: 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. Periodicals Postage Paid at Grand Forks, North Dakota and additional mailing offices. POSTMASTER: Send address changes to Ethanol Producer Magazine/Subscriptions, 308 Second Ave. N., Suite 304, Grand Forks, North Dakota 58203.




40 MAINTENANCE Enhanced for Ethanol

One-step CIP solution reduces chemical use By Michael Raab ETHANOLPRODUCER.COM | 5


A Break From the Bad As I write this, I’m digesting yet more news of plants idling, trade groups and legislators insisting that the U.S. EPA restore ethanol demand obliterated by frivolous small refinery exemptions, and investor calls where producers try to stay optimistic while reporting dismal margins. It’s a tough time in ethanol country. Lisa Gibson


But there are still gains being made and we’re reporting it this month, specifically in a profile of a brand-new plant, and coverage of our biggest recent win: E15’s Reid vapor pressure waiver. Ringneck Energy & Feed started up this spring with efficiency in mind, employing a re-engineered ICM design with evaporator innovation and Selective Milling Technology. It’s a new spin on the tried and true ethanol plant, ready to succeed even in a challenging environment. Lower inputs, more outputs, feedstock security and coproduct markets team up with the efficient design and operation to give reason for optimism at the Onida, South Dakota, plant. Turn to page 16 for the full story. May 31 brought an RVP waiver for E15 and, subsequently, June brought higher yearover-year sales. With no summer slump, planned increases in offerings by existing retailers, and new retailers looking to offer E15, the market looks favorable. Analysts say meaningful sales jumps could be a few years out yet, and several factors—including SREs—will play a role in the speed and level of E15 market development. Find out what the experts are predicting, starting on page 24. Next, we head into the lab, with some pointers about maintenance that might be surprising. Even micropipettes need a little regular TLC, and we’ll tell you why. We’ve included a simple chart to help organize the maintenance schedule of each piece of lab equipment. The story starts on page 30. Finally, we explore combined-heat-and-power (CHP) applications in the ethanol industry. Cogeneration is uncommon and is an investment, but it’s also a cost saver and potential revenue stream. Find out more on page 36. CHP is one of a few options that can help keep plants afloat in trying times like this one. But ethanol is hanging in there, and if you’re a producer hoping idled plants will free up market share for your product, you’re not alone. Hopefully this issue of Ethanol Producer Magazine can provide a break from the bad news, while the industry works on its next big win.




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‘Zero Evidence’ of Demand Destruction? Really? By Geoff Cooper

It’s one thing when oil industry lobbyists claim the massive increase in small refinery exemptions (SREs) under the Renewable Fuel Standard hasn’t affected ethanol demand. But it’s another thing entirely when

the U.S. EPA itself boldly asserts that there is “zero evidence” that SREs have had “any negative impact on domestic corn ethanol producers.” But that’s exactly what an EPA spokesman said shortly after the agency rubber-stamped another 31 exemption requests. Really? The U.S. ethanol industry has indeed been negatively impacted by the dramatic surge in SREs. Domestic ethanol consumption in 2018 was far below the level forecast by the U.S. Energy Information Administration at the start of the year. Further, 2018 domestic ethanol consumption fell from 2017 levels—the first year-over-year decline in 20 years. Ethanol’s share of U.S. gasoline consumption (the “blend rate”) also fell in 2018 relative to 2017, likely the first-ever annual decline in the blend rate. These impacts have continued into 2019. Domestic ethanol consumption is on pace to be 450 million gallons lower this year than initially expected by EIA, which now “assumes growth in higher-level ethanol blends is limited in the near-term by recent small refinery exemptions …” Moreover, ethanol prices are severely depressed, profit margins have turned negative, corn use by ethanol plants is falling, and the U.S. ethanol industry is curtailing production. On the very same day EPA suggested there is “zero evidence” of demand destruction, two major ethanol producers announced they were idling production. This means the total number of plants that have temporarily or permanently shuttered production since EPA began to massively expand the SRE program now stands at 15. Each of those facilities directly employed 40 to 50 workers and supported hundreds more jobs throughout the economy. In fact, in the week following EPA’s August announcement of 31 more SREs, ethanol prices plunged 18 cents per gallon (12 percent), corn prices fell 47 cents per bushel (11 percent), and renewable identification number (RIN) credit values dropped from the already-low level of 20 cents to just 12 cents (43 percent). All told, the August announcement


alone could result in a staggering $10 billion transfer of wealth from the agriculture and biofuel sectors to the oil industry. The evidence of demand destruction could not be any clearer. However, on top of all this is the testimony of those who suffered the losses directly and have had to tell their employees the bad news. No one is more qualified to provide perspective on the economic impacts of SREs than those who participate in these markets every day. And this testimony is so easy to find in news reports and financial filings. Here’s just a handful: • “Abuse of the RFS has dampened demand for our product,” said Neil Koehler, RFA board chairman and Pacific Ethanol CEO. • “Small refinery exemptions issued by the EPA have absolutely hurt this industry as domestic blending is lower than last year,” said Todd Becker, CEO of Green Plains Renewable Energy. “While the EPA says blending is not being impacted, they are dead wrong.” • “With negative margins in the industry persisting, you’re starting to see smaller ethanol refineries shut down now,” said Ray Young of ADM. “The small refinery exemptions are out there. That’s a negative for the industry here.” • “The federal government is sitting at a decision point about the small refinery exemptions,” said Eric McAfee, Aemetis CEO. “If we just enforced federal law, the supply/demand of ethanol will dramatically improve, resulting in a significant improvement in margins for the ethanol industry.” • Mike Jerke, Southwest Iowa Renewable Energy CEO, said, “… we continue to see very tight margins. The industry has become dependent on continued export demand to offset the EPA-induced shift in demand due to small refinery waivers.” The solution here is simple: Stop granting unwarranted exemptions to refiners that can’t prove “disproportionate economic hardship;” redistribute any exempted volumes to nonexempt parties; and follow the D.C. District Court’s order to restore the 500 million gallons illegally waived from the 2016 RFS requirements. EPA can and should do all of these things in the final 2020 RFS rule, due out in November. Author: Geoff Cooper President and CEO Renewable Fuels Association 202.289.3835


Elevate and Collaborate By Brian Healy

Collaboration across industry and government stakeholders is essential to build a role for ethanol as a transportation energy component, further normalizing its use.

While other countries actively search for ways to make meaningful emissions reductions, reduce healthcare costs and make significant foreign exchange savings—by purchasing ethanol as a cost-competitive source of octane—the U.S. ethanol industry simultaneously is working globally to expand the use of ethanol. In the past few years, the ethanol industry hosted the Ethanol Summit of the Americas, followed by the Ethanol Summit of the Asia-Pacific. This collaboration of high-level government officials and industry leaders generated further support of expanding ethanol use around the globe by highlighting ethanol-use benefits, policy development processes and fostering collaboration across the Asia-Pacific and Western Hemisphere regions. The Global Ethanol Summit is a natural extension of the other two and will be held Oct. 13-15 in Washington, D.C. This event will feature participants from more than 40 countries, increasing global momentum for decarbonization and expanded ethanol use. In addition to world-class speakers, the event also will offer an opportunity for U.S. ethanol sellers to meet with buyers from dozens of countries, linking policy development directly with trade. The summit will conclude with more than a dozen missions to U.S. corn states to educate participants on the production, consumption and logistics of using ethanol in the U.S. Importantly, this summit ties in the European Union, Middle East and African markets to the other regions, as each has had its own experience in producing and consuming ethanol. Several countries in Africa currently blend ethanol in fuel, like Malawi, Mozambique and Zimbabwe, while others predominantly use the


fuel for industrial uses, like Nigeria and Ghana, both of which produce ethanol from cassava. Egypt and Nigeria stand to accrue foreign exchange market savings by incorporating ethanol into their fuel supply. Several countries in the EU have announced expansions to their current policies as the new Renewable Energy Directive II goes into effect in 2020. And the Persian Gulf remains a strong importer of U.S. ethanol for use in preblended exports throughout the region. Like the upcoming summit, the U.S. industry is scaling up other global engagements to build out collaboration and expand the use of ethanol. While the benefits of ethanol are evident within the industry, misinformation and misperception exists in some areas outside of it, including multilateral, nongovernmental organizations. Ethanol, as a component of transport energy, delivers reduced greenhouse gas and particulate emissions. That important contribution needs greater recognition for the goal of expanded global use to be achieved. As countries have identified the transport sector as an opportunity to help improve air quality—mainly through their Paris climate agreement commitments—there is real opportunity to strategically and collaboratively elevate ethanol into the dialogue surrounding this upcoming event, and subsequent events. The Global Ethanol Summit offers a critical shift in how U.S. industry can structurally change global engagement and enhance opportunities for global ethanol use. Author: Brian Healy Director of Global Ethanol Market Development U.S. Grains Council 202.789.0789


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Wondering What If

By Steve Vander Griend

I was lucky enough to get away for vacation recently, but couldn’t help but keep an eye on various news clips.

In some respects, I wish I had turned my phone off because it was a depressing stretch in the media for ethanol. And as is often the case, we can thank our friends at the U.S. EPA. While we are all glad Reid vapor pressure (RVP) relief for E15 was finalized, limiting us to E15 makes this a small victory rather than the game-changer it could have been. While the RVP issue, waivers and the renewable volume obligations were in the headlines, the air quality and carbon value of ethanol continued to be maligned, with no better example than Colorado considering a move back to E0 because of what the computer models say. Whose models? You guessed it, EPA’s. Our value and future success is captive to EPA’s calculations. I wonder what a different place we would find ourselves in today if some 10 years ago, when EPA launched a series of studies and tests, it had simply added ethanol to gasoline, as is done in the real world. What would the answers to the following questions be if EPA had actually looked at real-world fuels and octane for many of its recent rulemakings? • Would the approval of E15 seven years ago have included RVP relief if the data for E10 wasn’t manipulated to say E10 raised ozone? Volatile organic compound (VOC) emissions by weight can still go up with the one-pound waiver, but ozone can still go down based on the type of VOCs emitted. • Would EPA’s Tier 3 rulemaking in 2014 have included provisions for E25 or E30 if EPA’s testing had shown that vehicles today could benefit from higher octane? When EPA only used premium fuels to support Tier 3, EPA ignored octane, even though it asked for comments on this in the rulemaking.


• Would the 2014 EPA Motor Vehicle Emission Simulator (MOVES) have shown ethanol lowering emissions? Today, Denver is considering a move back to E0, Kansas City doesn’t want E15, Mexico doesn’t want E10 in urban areas, all because of the EPA MOVES model. • Would the current E15 RVP relief rule also have promoted E15 and higher blends such as E20 and E25? Since all cars sold since 2017 are now certified on E10, current EPA data could easily say E20 and E25 are approved for 2017 and newer vehicles. • Would we even be talking about the Renewable Fuel Standard or refinery waivers if we were selling more than 15 billion gallons of ethanol domestically? RIN values would be just pennies at most and no one in the corn industry would need to rely on the RFS. As this illustrates, our world would be quite different from what we face today, with a brighter future and a pathway to higher blends to the benefit of public health, energy security, and economic and rural development. If ethanol is to move forward and help raise octane, while at the same time lower emissions and consumer cost, the bad science of the past has to be corrected. And it’s never too late. The Urban Air Initiative is working to make those corrections, challenging the models, leading the way on real-world testing and making the case that ethanol is a cleaner fuel. Our industry needs to demand transparency, real-world testing, and real-world fuels, as crucial decisions are being made at EPA that will have a significant impact on our future. That way, we won’t have to wonder, “What if ?” Author: Steve Vander Griend Technical Director, Urban Air Initiative 316.977.6222


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People, Partnerships & Projects

Lee Enterprises Consulting adds staff Lee Enterprises Consulting, a bio-economy consulting group, has added Chris Burk, Daren Daugaard, David Whittle and Tad Dritz to its team of more than 100 subject matter bio-economy experts. Burk is a licensed professional engineer and holds bachelor’s and master’s degrees in chemical engineering from Cornell University. He specializes in techno-economic modeling and analysis. He works with companies that are developing or investing in new chemical and bioprocess technologies, helping them use technoeconomic modeling to better understand their economics at a commercial scale. Daugaard has more than 20 years of experience in the thermochemical conversion of biomass starting with his doctorate in mechanical engineering from Iowa State University. He is a licensed professional engineer and holds 12 U.S. patents. He has worked with a variety of agricultural, forestry and waste-stream feedstocks in lab, pilot, demo and commercial-scale pyrolysis, gasification and torrefaction systems. Based out of the United Kingdom, Whittle has a degree in chemical engineering and a Masters in renewable energy systems


engineering. He has been involved in the global energy sector for much of his 36-year career, having worked at Texaco and Mobil, as well as through management consulting at Price Waterhouse and Arthur D. Little. Whittle has been in private consulting for many years, advising about advanced biofuels and bio-oil conversion, including recent engagements evaluating refinery coprocessing of bio-oils for two large clients. Whittle will be coordinating and leading many of LEC’s projects overseas. Dritz is a licensed professional engineer in Texas, holds master’s degrees in natural resources and environment from the University of Michigan and a bachelor’s degree in chemical engineering from Ohio University. He specializes in new technology development and deployment of biofuels and biobased processes. His areas of expertise include syngas generation from biomass and refused-derived fuel, biojet via Fischer-Tropsch and competing routes, soy biodiesel, pyrolysis, anaerobic digestion, and soy and algae bioplastics.


Stephan Wittig named USGC director in Mexico The U.S. Grains Council has named Stephan Wittig as its new director in Mexico. Wittig will be responsible for identifying and addressing trade, technical and policy-related factors that impact the market for U.S. grains and coproducts in Mexico. Wittig replaces Ryan LeGrand, who was promoted in June to USGC president and CEO. Before assuming the director role, Wittig served as an ethanol consultant with USGC, supporting ongoing ethanol programs run by the Mexico office. “Stephan has worked tirelessly as a major contributor to the council’s success in educating the Mexican government and relevant stakeholders about the value of E10 and the resulting environmental and economical benefits it offers,� LeGrand said. “Thanks to his efforts and those of the team we assembled in Mexico, we now have a potential 720 million-gallon market that did not exist before 2016.�

Wittig previously worked as a chief strategy officer for Grupo Baltico, Mexico’s largest ethanol producer and distributor, which offered the first E100 retail stations in the country. Wittig has a strong financial background with an educational specialization Wittig in distillation processes, focused on the development of alcoholic beverages. “His can-do attitude and relentless approach are just two of the many attributes that make him well-suited to fill the role of Mexico director,� LeGrand said. “I am positive the council’s programming will stay on a successful path under his leadership.�






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PRODUCTION ON THE PRAIRIE: Ringneck Energy & Feed, South Dakotaâ&#x20AC;&#x2122;s new 80 MMgy ethanol plant, began production in June. The plant features new engineering designs, aiming for immediate efficiency as it started up during historically low ethanol industry margins. PHOTO: LANE WARNER, DAKOTA FILM CO.



IN ONIDA Itâ&#x20AC;&#x2122;s a challenging time to bring an ethanol plant online, but June marked the beginning of operations at Ringneck Energy & Feed in South Dakota. By Matt Thompson


PLANT PROFILE Once commonplace for the ethanol industry, the opening of a new plant is a rare occurrence now. And despite slumping margins na-

tionwide, Onida, South Dakota’s new ICMdesigned ethanol plant, Ringneck Energy & Feed, commenced operations this spring after a longer-than-expected planning and construction phase. So far, operations at the 80 MMgy plant have gone well, according to Mike Stanley, plant manager. “We’ve still got a few little bugs to work out, but every day we’re getting closer to no bugs,” he says. Walt Wendland, president and CEO and chairman of Ringneck Energy, says the challenging economic environment made it crucial to ensure the plant was engineered for efficiency. “Definitely, we’re trying to optimize on our advantages in this area,” he says. “When they engineered the plant, they put in all high-efficiency motors and all LED lighting and where they could improve energy efficiency, they already kind of have.” Dave VanderGriend, CEO of ICM Inc., agrees. “We tried to be as economical as possible in the design. We made a few design changes to lower the overall cost to building the plant. And with Fagen as a contractor, who is probably the most knowledgeable contractor for ethanol plants, they also did some things to help economize the cost of construction.” In addition to designing the plant, ICM’s Energy Management Services manages it. Stanley adds that efficiency in operations is a focal point, also. “We bought what we thought would be the best enzymes and yeast, and tried to dose as conservatively as possible. We were trying to be as efficient as possible right out of the gate to save some money.”

Inputs and Outputs

While much of the corn growing in the Midwest was hampered by an extremely wet spring, Wendland told Ethanol Producer Magazine in June that the planting woes were less of an issue for the Onida area than oth18 | ETHANOL PRODUCER MAGAZINE | OCTOBER 2019

er regions. That can be both a blessing and challenge, Wendland says. “We’re quite a ways away from other demand for corn,” he says. “We do realize that if we’ve got corn out here, there’s going to be a lot of people trying to take it away from us. They’re going to have to be competitive.” In early August, despite a recent damaging storm, he said conditions were still favorable. “As far as crop conditions go, I still have to say, we’re as good or better than any other place in the state,” Wendland said. But, in the event there is a corn shortage, Wendland said the plant does have a grain sorghum bid. “We’ll try to utilize some of that crop, too, to fill up a shortfall, if there is any.” Stanley also says the corn crop still looks better in the Onida area than it does in other areas. “I think, if anything, it looks better than it did a few months ago, around here anyway,” he says. “I went to Minneapolis last week, and you could definitely tell it’s not as good further east of here,” he said in early August. Stanley has 20 years of experience in ethanol and has been involved with a few other plant startups. He says the biggest challenge for Ringneck so far has been finding a market for its wet cake. “The original plan was to be starting up before Christmas,” he says. “There’s just more of a wet cake market in the winter time.” But Ringneck has started to find buyers. “It’s like anything new, you’ve got to work yourself into the market,” Stanley says. Wendland agrees. “We limited production due to the wet feed that we could find a market for, although we joined forces with Dakotaland Feeds, who markets for three other plants, and that’s really helped us, too,” he says. “I know in the winter we’re going to be darn near selling all of it wet, but in the summer, especially in a summer like this, where there’s so much grass and hay, there’s not a lot of demand right now.”

Tested Technology, Different Design

Wendland says construction of the plant began in September of 2017, following some preliminary dirt work in the win-

ter of 2015. “The permitting process took a while,” he says, adding that the air permit wasn’t acquired until September 2016. “[Ringneck] signed our substantial completed document on May 13 of this year, and passed the performance test on June 4.” The plant doesn’t include much in the way of new technology, but it does incorporate some new design elements, Wendland says. “This was ICM’s first chance to build a U.S. plant that they could redesign to be more efficient,” he says. “I think they were pretty happy with the redesign to help prevent some of the issues they’ve had at other plants through the years.” A crucial part of the redesign is the Evap Zero technology. “After the vapor goes through the mole sieves, it goes through the Evap Zero and it starts the evaporation process on the thin stillage and condenses the 200-proof from the sieve, so you get some really nice heat recovery there,” Wendland says. VanderGriend says Evap Zero was designed for safety. “The original design that ICM had done 15, 18 years ago, had evap No. 1 being the 200-proof condenser, and then when a person wanted to clean that evaporator, you switched to evap No. 2 for the cleaning,” he says. “By designing an Evap Zero where we condense the 200-proof vapors with steam condensate and turn it into boiler steam rather than ethanol vapors, we were able to address that issue and make the plant just a little bit of a safer design.” That change also helped cut down on costs during construction, Wendland says. Another change from ICM’s previous designs was locating ethanol outside of the process building. “The other ICM plants always had ethanol within the process building, and some places required full or partial sprinkling, and by relocating that part of the facility outside with the rest of the distillation, it helped keep our sprinkling cost down,” Wendland says. The plant also features larger evaporators. “They’re more efficient and easier to manage because you don’t have to manage eight, you only have to manage four,” Wendland says.

ICM’s Selective Milling Technology was also installed, Stanley says. “We did incorporate selective milling technology right from the get-go. A lot of plants just add it after the fact, but we just kind of integrated that right with the initial construction.” VanderGriend says incorporating SMT into the design offered a few benefits to the plant, including higher conversion efficiency and the option to use larger screens in the hammermill process. Ringneck uses version two of ICM’s SMT, designed to improve energy consumption. “The real purpose behind version two compared to version one was horsepower—trying to reduce the amount of horsepower in the plant,” VanderGriend says. “And because of the (renewable identification number) credits and the carbon score, we did everything we could at this plant to keep the electrical consumption as low as possible.” Wendland agrees. “The ICM SMT incorporated the roller mills instead of the wet mill grinder that took a lot more horsepower. They get better particle size out of the roller mills and less horsepower requirement, which is important to us to keep our energy down.” Further improvements could be on the radar in the future, but Wendland is pleased with the plant’s design and efficiency. “I don’t know if there’s a lot of low-hanging fruit, so any improvements that we make because of the redesign are probably going to be fairly major,” he says. “Not just the little things.” He adds that the plant might consider upgrading its dryers to get more capacity during the summer months. In addition, Stanley says, the plant is considering adding technology to allow it to produce high-protein feed.

Friendly Location

Ringneck is located in an area of South Dakota where ethanol production is sparse. Onida is northeast of Pierre, South Dakota, and according to Ethanol Producer Magazine’s plant map, the closest plants are farther east near Redfield, Huron and Mina. While it’s a new industry for the area, both Wendland and Stanley say the community has been supportive of the plant. “The construction

EVAP EFFICIENCY: ICM’s Evap Zero technology was incorporated into Ringneck Energy’s design. The system condenses the 200-proof alcohol from the sieve, saving time and increasing overall safety. PHOTO: LANE WARNER, DAKOTA FILM CO.

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SHOW AND TELL: Walter Wendland, Ringneck president and CEO and chairman (right), leads South Dakota Gov. Kristi Noem, South Dakota Lt. Gov. Larry Rhoden (second from left), and Bill Paulsen, general manager of ICM's Energy Management Solutions (far left), on a tour of the new plant in Onida, South Dakota. PHOTO: LANE WARNER, DAKOTA FILM CO.

period was great for business and weâ&#x20AC;&#x2122;re doing as much business locally as we can,â&#x20AC;? Wendland says. â&#x20AC;&#x153;And even though weâ&#x20AC;&#x2122;re a little close to town, theyâ&#x20AC;&#x2122;re used to hearing fans for the grain bins and traffic, so it hasnâ&#x20AC;&#x2122;t seemed to be too big a deal.â&#x20AC;? â&#x20AC;&#x153;The town really seems, for the most part, receptive of having the plant here, which is kind of nice,â&#x20AC;? Stanley says. â&#x20AC;&#x153;That means the community is hoping that weâ&#x20AC;&#x2122;re successful.â&#x20AC;? And VanderGriend says the plant has been good for the local ag economy in Onida. â&#x20AC;&#x153;That plant was located in a very corn-surplus area and the farmers were experiencing lower prices because there was not enough demand for their corn,â&#x20AC;? he says. â&#x20AC;&#x153;The ethanol plant definitely improves the agricultural economy in that area.â&#x20AC;? Author: Matt Thompson Associate Editor, Ethanol Producer Magazine 701.738.4922





— P R E S E NTS —



February 10-12, 2020


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MARKET MOVERS Projections for E15 have been inconsistent since the May 31 Reid vapor pressure waiver. Ethanol Producer Magazine explores some of the factors that will influence the blend's trajectory in the coming years. By Lisa Gibson

This year, E15 was immune to the annual dip in sales the month of May traditionally brings. In fact,

the Minnesota Department of Commerce reports June 2019 E15 sales in the state—6.3 million gallons—nearly doubled from that of June 2018, 3.66 million. Mike O’Brien, vice president of market development for Growth Energy, says national year-over-year E15 sales increased by double-digit percentages in both May and June. It’s a direct result of the Reid vapor pressure waiver granted by the U.S. EPA on May 31. President Donald Trump had stoked hope of issuing the waiver in the weeks leading up to the final rule. “We’ll take that as a good sign that momentum was growing into summer, where typically we don’t see that,” O’Brien says. “We typically saw May start to crumble in sales leading into the RVP season.” The removal of the summer sales slump, along with new stations likely to now offer E15, could boost the 300 million gallons of E15 sold in 2018 to 700 million to 800 million for 2019, says Scott Richman, chief economist with the Renewable Fuels Association. “Without that dip, you get significantly higher volumes,” he says.


Before the waiver, retailers selling E15 had already planned to increase the number of sites offering it from about 1,800 to 3,600 in the next few years, O’Brien says. At the current sales rate, with the planned increases from the 17 chains selling E15 now, sales could increase incrementally by 1.2 billion to 1.4 billion gallons in the next five years, he adds. But at least six new chains are exploring their options through Growth Energy’s Prime the Pump branding and expansion initiative, with the potential to double that growth, O’Brien says. “We are seeing some other players start to warm up their interest in E15 because of the RVP waiver being gone,” he says, adding retailers are excited and are developing more aggressive plans for that market. “That’s the attitude we’ve encountered among all the retailers.” Ron Lamberty, senior vice president of the American Coalition for Ethanol, points to contact from service companies as an indication that more retailers want to offer E15. “I’ve gotten calls from several different service companies—pump and equipment companies—that have asked what they need to do. That’s a good sign because that’s who stations call when they really want to make a move.” Lamberty, O’Brien and Richman agree that enormous jumps in E15 sales as a result

of the RVP waiver are unlikely within a year, but could be two to five years out. Projections are made more difficult by the myriad factors that could tip the market one way or the other.

Negative Market Factors: Slow to Sell

Among the largest factors with the potential to slow E15 market growth are small refinery exemptions. “The incentive both to expand E15 volumes just to meet the Renew-

EXPANDING E15: With a Reid vapor pressure waiver in place, E15 sales are clear year-round. A multitude of factors could affect the speed and level of growth, but experts seem to agree that meaningful market change is a couple years out. PHOTO: GROWTH ENERGY

able Fuels Standard, and the incentive that’s provided by D6 RIN prices, are being eroded a little bit,” Richman says. Through SREs granted from 2013 to 2018, the U.S. EPA has exempted a combined 45.66 billion gallons of gasoline and diesel from meeting RFS blending obligations, representing 4.73 billion RINs. That’s roughly 4 billion gallons of ethanol and biodiesel waived. Most recently, EPA granted 31 SREs Aug. 9, for a total of 13.42 billion gallons of exempted gasoline and diesel, 1.43 billion RINs and 7.5

percent of 2018 RFS blending requirements. As of August, two more petitions were pending for compliance year 2018, according to EPA. RIN prices should reflect the cost of “not obeying the law,” Lamberty says. “It’s not supposed to be easy because you’re supposed to use ethanol.” D6 RIN prices have hovered between 10 and 25 cents in 2019, down significantly from the highs of near 90 cents at the end of 2016, according to the Energy Information Administration.

That price point can be a compelling argument to retailers considering selling E15. “It was much easier to talk to people about E15 and E85 two years ago, when gas was over $1 higher, with the RIN price,” Lamberty says. “The margins were in the larger range, 12 to 15 (percent). You’re talking a pretty significant percentage of their margin.” While ethanol industry margins have swiftly declined, leaving plants idled and even closed this year, retailers have had a tremendous past two years. Locations not already ETHANOLPRODUCER.COM | 25


SUMMER SLUMP: Figures from the Minnesota Department of Commerce show E15 sales in the state leading into the summer months didn’t experience the traditional dip in 2019, following the May 31 Reid vapor pressure waiver. SOURCE: RENEWABLE FUELS ASSOCIATION

selling E15 might not see a need to explore it right away, even with the RVP waiver. The EIA reports that only 2 percent of retail fueling stations nationwide sell E15, which represents a small push currently for new ones to enter that market. Convenience stores move slowly

with fuel changes, Lamberty says, traditionally evaluating new options during spring and winter months, and implementing any changes around May of the following year. The process for a station to start offering E15 can be lengthy, as well, including registration with

EPA, a survey and infrastructure changes. “It might not cost a lot, but it does cost,” Lamberty says. RFS renewable volume obligation (RVO) levels in the coming years will play a part, also, Richman says, as well as gas consumption trends. While gas demand remains relatively steady, it flatlined a bit in 2017 and 2018, hovering near 143 billion gallons, according to the EIA. Analysts say a variety of factors are at play, including Corporate Average Fuel Economy standards, the increase in ride-sharing services like Lyft and Uber, and an increase in electric vehicle use. Assuming the start of a long-term decline, one of EIA’s projections shows a sharp dropoff in gasoline demand in 2020, hitting consumption of less than 110 billion gallons in 2035. That’s a decline of about 33 billion gallons, or 23 percent, from the current projection of 2019 consumption, at 142.9 billion. But an assumption that the flatlining gasoline consumption in 2017 and 2018 is the start of a sharp decline is a large one, and could be swayed by multiple factors. “EIA has understated some of its forecasts in gasoline

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consumption,” Richman says. “We would be lower than we are right now if those projections had come to pass. Some predictions of near-term reductions in gasoline consumption may have been overdone, but we do realize that, over time, with improving fuel efficiency, we’re going to need to go to higher-level blends in order to be able to maintain ethanol consumption at the levels that are envisioned.” “I expect gas demand to remain fairly steady,” Lamberty says. “Gas demand seems to be more dependent on cost of gasoline and I think people drive a lot when gas is cheap, and they don’t drive as much when it’s expensive.” Lamberty also emphasizes the effect of the fleet changing from cars and light trucks to SUVs, crossovers and trucks, as well as the effects of CAFE. CAFE regulates the distance passenger cars and light trucks can travel on one gallon of fuel. A proposed rule, the Safer Affordable Fuel-Efficient (SAFE) Vehicle Rule, would amend CAFE and tailpipe carbon emissions standards for cars and light trucks model years 2021 to 2026, retaining existing CAFE standards on models through 2020. SAFE is less

RAMPING UP: The number of stations selling E15 in the U.S. was set to increase from about 1,800 in 2019 to about 3,600 in the next few years, even before the May 31 Reid vapor pressure waiver was issued. SOURCE: GROWTH ENERGY

stringent and comes with a savings of $500 billion in “societal costs,” according to the U.S. Department of Transportation. The ethanol industry has applauded the proposed rule for addressing the potential of high-octane fuels. The SAFE rule was submitted to the White House Office of Management and Budget on Aug. 2, marking a final step before its public release.

Positive Market Factors: Bringing the Boost

But just as many factors are set up to potentially hasten E15’s rise as to derail it. The potential five-year, 1.4 billion-gallon incremental increase is set to double with six new large retailers exploring E15, and that only sets up more competition and pressure on others. “If

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TERMINAL SOURCE: In 2017, about five terminals offered preblended E15. By mid-2019, about 175 terminals were offering the fuel blend. SOURCE: GROWTH ENERGY

you can bring enough market pressure through independents that we’re working with, that’s going to force those branded sites to have to start offering the product, too,” O’Brien says. “It’s just that normal, competitive positioning that takes place in a marketplace.” E15’s discount of 3 to 10 cents per gallon over gasoline is particularly significant in a declining gasoline market. “There’ll be a fight for gallons and E15 is going to be right in the middle of that fight, so that could actually accelerate E15 adoption,” O’Brien says. As branded and other retailers lose that share in the market, they’ll want to get back in the game by offering the product that’s taking their share, he adds. “One store in a particular area can get the ball rolling,” Lamberty says. “The important thing is to always be looking for someone who’s willing to do it, so others have somebody to look at.” It’s important that the message comes from other retailers or marketers, he adds, not the ethanol industry. Lamberty uses the expansion of E10 in the southeast U.S. as an example. “Once we got the word out about what the math was, everything went pretty quickly there.” In that case, infrastructure to get ethanol to the southeast didn’t exist yet. “And that still went pretty quickly. In this case, we’re not talking about new tanks or rail infrastructure. We’re talking about adjusting the volume of what you already have. It can go very quickly.”


It only hastens further with more terminals offering E15 as interest among retailers grows. “Having a preblended E15 is a much quicker addition for a retailer to put that product in versus trying to rebuild equipment,” O’Brien says. Five terminals started offering E15 in 2017, but that number grew to 175 by mid-2019. “That’s a big function around the E15 Prime the Pump retailers coming into the marketplace,” he says. Retailers blending their own fuels is lost market share for terminals, incentivizing the preblended offerings. Growmark Energy began offering preblended E15 at a few terminals in 2018, according to Scott Long, manager of marketing and business development for fuels at Growmark. “The decision to make this available was due to customer demand and potential changes to the RVP waiver that could increase the customer demand.” In February, Growmark started offering preblended E15 at 17 additional terminals in Iowa, Missouri, Nebraska, Oklahoma, Arkansas, Illinois, Kansas and South Dakota. Long says the waiver supports the choice to add preblended E15 to more terminals. “A number of retailers were already selling E15 through a blender pump. Now they have the option of getting E15 directly from the terminal.” When asked if he thinks more terminals across the country will begin selling E15, now that the RVP waiver is in place, Long says, “I can’t speak for the whole country but in the

Midwest, we have seen an increase in sales with proper marketing and consumer education. … This is each terminal’s decision as to their offerings. I would think that the ones that are selling ethanol blends would make this another product choice for the consumer.” If E15 fully replaces E10 nationwide in three years—though highly unlikely—the U.S. could experience a 22.5 billion-gallon domestic ethanol market by 2022, assuming a 140 billion-gallon domestic gasoline market and continued 1.5 billion gallons of exports. With a current capacity of 17 billion gallons, according to Ethanol Producer Magazine’s full database of plants and capacities, an additional 5 billion gallons of production would be needed. If E15 replaced only half of current E10 consumption, an additional 2 billion gallons still would be needed.

Crystal Ball Cliché

Market projections always revolve around assumptions that are difficult or impossible to confirm ahead of time, and many economists will add that disclaimer to their predictions. While E15 sales likely won’t see an immediate jump that drives the market and margins back up industry-wide, strong figures could start to emerge in two or three years. Lamberty reflects the sentiment of most ethanol industry insiders regarding the overdue RVP waiver, when he jokes, “We should see larger volumes in 2013.” Momentum is building and retailers who had previously said they’d explore E15 when they can sell it year-round have come back to Growth Energy to discuss it since the RVP waiver was issued, O’Brien says. Others, like Casey’s General Stores, have announced they’ll expand their E15 offerings at even more locations. “We have a good start,” Richman says. “If we can continue to get the momentum that we see, and we can continue to get real, meaningful RFS levels, then we could see greater acceleration in 2021 and 2022 as a result of that.” Author: Lisa Gibson Editor, Ethanol Producer Magazine 701.738.4920




CALIBRATE Deploying best practices that include a regular schedule for equipment monitoring, as well as staff with eyes on the details, improves accuracy. By Susanne Retka Schill

Precision in the ethanol laboratory is important to the bottom line. Being 100 percent accu-

rate is unrealistic, but consistently hitting the target close to the bullseye is important when tiny samples from enormous tanks are used to monitor fermentation or end-product quality assurance. Most plants have well-run labs, says Tera Stoughtenger, technical services manager at Lallemand Biofuels & Distilled Spirits, but there are times when labs might be understaffed or overworked. She cites one plant that started up without appropriate staff for the necessary

sampling. The pH probe in the liquefaction tank was indicating high levels, and with the probe in a control loop, sulfuric acid was automatically added. Because of the missed sampling, the probe’s results weren’t being crosschecked with a lab test and the operators were unaware the pH probe was producing a false high. Not only could that result in unneeded chemical addition, Stoughtenger says, but if the pH gets too low, interference with enzyme action or the inhibition of yeast could reduce ethanol yield. Another potentially costly mishap occurred at a plant where Stoughtenger worked years ago. Samples were saved in

a refrigerator, but the labels used were similar to those used on standards. A standard is a solution with known values used to verify that the high performance liquid chromatography (HPLC) instrument is reading correctly. The night shift operators had run a sample to monitor fermentation and when the HPLC results seemed off, called the lab manager. “The operators were told to do a standard check, which they had been trained to do, but they grabbed the wrong solution and didn’t look at the values before continuing on,” she recalls. “There were quite a few values completely off. They went into panic mode, thinking the

FERM CHECK: A corn mash sample is prepared for the HPLC. The instrument is used throughout fermentation to monitor the breakdown of starches into sugars, the conversion to ethanol and the presence of contaminants. Proper calibration of lab instruments helps avoid costly mistakes. PHOTO: LALLEMAND BIOFUELS & DISTILLED SPIRITS



Lab Schedule Instrument

Validate (method)



Weekly (mass standard)



Monthly (ultrapure water)


pH meter

Daily (check sample)



Daily (check sample)

As needed


Daily (traceable thermometer)


ferms didn’t get the correct ingredients, and started adding things.” The lesson learned is to make sure things are labeled properly, Stoughtenger says. “And make sure operators are up to speed. You need to go through the SOPs (standard operating procedures) in the lab more than once. Do refreshers every quarter, if you can, because there’s so much going on in the plant and operators do change positions.” She also recommends striving for simplicity in SOPs. “Make sure they aren’t too lengthy, are easy to follow and easily repeatable.” Reliable results require everyone running tests to follow the same procedures.

Best Practices

Andrew Hawkins, director of laboratory services at Phibro Ethanol Performance Group, encourages ethanol plant laboratories to adopt the best practices developed by other technical industries, such as pharmaceuticals, by implementing a metrology program. “Metrology means keeping your instruments in good working order, so you get the best, most-accurate and lowest-error data possible,” he says. “Some plants I’ve been to keep a log book for every instrument, which shows when they’ve calibrated it and when they’ve validated it. And then, there’s other plants that 32 | ETHANOL PRODUCER MAGAZINE | OCTOBER 2019

say, ‘I’m supposed to calibrate that?’ about some of the less obvious equipment.” While the need for validating and calibrating HPLCs and pH probes and meters is commonly understood, Hawkins says all lab instruments need proper attention. “When I started in microbiology, I had to calibrate micropipettes. Some people recognize they’re supposed to be calibrated, or at least validated, every six months or so. Others have them in a drawer, pull them out, use them, and have never done anything.” Micropipettes measure small quantities of liquids, anywhere from 1 or 10 micro liters to 100 or 1,000 micro liters. (An average drop is 50 to 100 micro liters.) “They are designed for a specific volume when you’re making dilutions so you can quantify the chemicals in that solution,” Hawkins explains, adding that the nature of working with corn mash in a laboratory means anything and everything can get fouled by the sticky mash. “It’s not uncommon to have stuff get dirty,” he says. “You might get rushed. There’s lots of stuff to analyze in the lab. Sometimes days are crazy. Maybe you don’t clean your equipment or maybe someone spills some mash.” A mash spill could easily get into the mechanism of a balance, throwing off the weight. Even moving the instrument on the counter can throw off a

highly sensitive balance. Balances are primarily used to weigh samples of corn mash before and after being dried to determine the percentage of solids, and maintaining consistent solids loading is a main control point for an ethanol plant. Hawkins recommends the balance be validated weekly by using a standard set of weights. “Put a 1-gram weight on and verify the balance reads 1 gram, or within the tolerance.” “Keeping track of how your instruments are working can alert you when there’s an issue,” Hawkins says. “The hardest part is getting into a routine and being disciplined enough to keep doing it.” The challenge is that many only start investigating their instruments when there’s a problem, he says. “For example, they report some data and make a change in the plant and go, ‘Oh, that went south fast.’ And then they start doing an investigation to figure out why, and they might track it back to some bad lab data and say, ‘I need to validate and calibrate.’” Phibro is one of several companies that organizes round robins for plants to compare their HPLC results, Hawkins says. “We send out quantified mixes of chemicals that have been made by an independent group and verified. We use that to cross validate instruments. We’ll run it here on our instruments and last year we sent it out to 51 plants. They’ll run it and tell us the numbers.” Everyone sees how their plant’s result compares. While some error and variation always will create some noise in the data, Hawkins says when comparing 20 or 50 plants, the outlier—the instrument that is substantially off—is easily identifiable. Hawkins cautions about over calibration as well. “If you recalibrate when it’s random error, you can introduce bias and cause your machine to constantly read high or low.” He recommends calibrating HPLCs only as needed. In a recent survey

MICRO MEASURE: Corn mash can get stuck in the plunger mechanisms of micropipettes. Costing around $200 each, it’s worth the time to properly maintain and validate. PHOTO: PHIBRO ETHANOL PERFORMANCE GROUP

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of plants asking about their procedures, Hawkins found the highest response was for calibrating daily or three times a week. The second highest was monthly. “There were a few folks who said they’ll calibrate when they make changes on the instrument, and that’s actually a pretty good guide,” Hawkins says. “We’ll tell people you should check your HPLC every day. Have a check standard, a mixture of known chemicals in known concentration that you buy, or very carefully make, and make sure that’s what your machine reads. If it’s plus or minus a small amount, that’s normal. But if it’s plus or minus, say 10 percent, and it’s constantly plus or minus that 10 percent, then it’s time to recalibrate.”



RIGHT WEIGHT: Balances may seem foolproof, but they do need regular validation with a known weight to ensure accuracy when weighing wet and dry samples for solids calculations. PHOTO: PHIBRO ETHANOL PERFORMANCE GROUP

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“It’s important to do validation,” says Caleb Ogden, technical services manager at LBDS. “If you can back up your numbers and results with validation and verification, you’ll have a lot better confidence in your results. Most plants are doing this, but lab coverage—having somebody there to get things done properly—is often a challenge.” Maintaining good records over time gives credibility to a lab’s program, he adds. “When somebody comes in to look at your data, they feel more comfortable buying into what you're providing, rather than questioning it. Lately, with margins as tight as they are, it’s not something you can ignore. It definitely is important to keep chemical costs down.” Good lab results also help a plant’s operations, Stoughtenger says. “The main thing with the lab is you want to make sure it’s running accurately so that fermentation and solids are consistent. It makes your plant run more consistently. Then you can tell if something is off in the plant if you start to see values go off the rails, or your measurements look different. As long as it’s been known the lab equipment is working fine and the upkeep is there, you can focus on pinpointing the plant issues.” Author: Susanne Retka Schill Freelance Journalist


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OFF THE GRID From reducing energy costs to lowering carbon intensity scores, the benefits are many for ethanol plants that cogenerate. By Matt Thompson

Conversations about how to squeeze more value out of ethanol plants often focus on corn fiber-toethanol systems and production of high-protein coproducts, or minimizing input costs like power and feedstocks. But as those types of improvements become more

common, plants are looking to other areas to cut costs and increase revenue, says Bernie Hoffman, CEO of TotalGen Services, which specializes in combined-heat-and-power systems (CHP) for ethanol plants. “Most plants have picked off all of the low-hanging fruit with respect to upgrades,” he says. “People are looking at some pretty big commitments from a capital perspective to go to the next step.” One potential next step is installing a CHP system. The systems generally burn natural gas, which powers a turbine that generates electricity. A heat recovery steam generator (HRSG) then uses excess heat from the turbine to produce the steam that’s used in the plant, and in many cases, allows a plant to discontinue use of its boilers. While the capital cost to install a CHP system can be substantial, so can the benefits. CALGREN COGENERATION: Calgren Renewable Fuels in Pixley, California, uses a combined-heat-and-power (CHP) system. The plant is able to generate excess electricity, which it sells back to the grid. CHP systems can bring cost savings and revenue, but only about 5 percent of ethanol plants employ them. PHOTO: CALGREN RENEWABLE FUELS




COGENERATION Pierson agrees that while steam-powered turbines cost less to install, they are limited in the amount of power they can generate. He says Poet plans to continue using both CHP systems and steam turbines, and potentially expand their use to other plants. “We have a few additional potential projects identified and we’ll be looking for that along with any other opportunities,” he says. “We’re always looking for those opportunities to reduce CI and improve our production process to be more environmentally friendly.”

Savings and Revenue NATURAL FIT: A Titan T-130 gas turbine used in a typical CHP system. TotalGen Services CEO Bernie Hoffman says the turbine and HRSG systems TotalGen proposes for ethanol plants are over 90 percent efficient. PHOTO: TOTALGEN SERVICES

“The real significant benefit is if you are in a geographic position to sell into California,” Hoffman says. He estimates plants, on average, see a carbon intensity (CI) score reduction of about nine points. “Of course, a nine-point CI reduction, if you’re selling to California, can be monetized pretty dramatically,” he says. CHP, also called cogeneration, has been used successfully in industries such as paper and fertilizer, according to Hoffman. But it’s somewhat uncommon in ethanol, he says, estimating that 5 percent of U.S. dry mill ethanol plants use the system. A combination of low electricity costs when ethanol plants were first built, the challenge of raising enough equity to build, and the lack of a low-carbon incentive kept plants from initially considering CHP systems, he says. While Hoffman says any plant can potentially benefit from CHP, plants in Nebraska have a difficult time installing systems. “There’s a lot of eligible plants in Nebraska that we really can’t look at because the state of Nebraska regs, in effect, prohibit you from doing that,” he says. “It’s not that simple, but they make it such that you wouldn’t do this.” He adds that CHP systems using biomass would be an option for Nebraska, but those systems add another level of complexity.

In Action

Poet uses CHP systems at several of its plants. “Our mission is to produce biofuels in an environmentally friendly way,” says Rod Pierson, senior vice president and general 38 | ETHANOL PRODUCER MAGAZINE | OCTOBER 2019

manager of Poet Design and Construction. “So definitely reducing CI is critical to that, because anytime you reduce CI, you’re better for the environment.” He adds that while the company does realize an energy savings, its main focus is on the environmental benefits of using the systems. Pierson says Poet has used CHP systems for several years. Original installations included a natural gas-fired turbine. “The initial installations had a few challenges, but, essentially, we were able to hit the ground running with our first installation and have had very few major issues, only small issues,” Pierson says. The company has, more recently, also installed steam turbine generators, which produce electricity from high-pressure steam, allowing letdown steam to run the plant, Pierson explains. These turbines, while similar to the natural gas-powered turbines, are not true CHP systems, according to Hoffman. “In the case of a letdown turbine, a small steam-driven turbine is installed in a step in the ethanol plant where process steam pressure is dropped from roughly 125 psi to atmospheric pressure,” he says. That pressure drop drives the turbine, which produces a small amount of electricity, generally less than would be provided by a CHP system with a natural gas-powered turbine and HRSG. “The gas-fired turbines used in CHP are larger and can provide all of the electricity needed by the host ethanol plant,” Hoffman says. “The waste heat recovery can provide most or all of the steam. This results in efficiencies at 90 percent or a little higher.”

Hoffman says TotalGen has modeled the data from about 20 U.S. ethanol plants. “Depending on the design of the plant, we cut their energy use by, on the low end, about 35 percent, and on the high end about 55 percent,” he says. “We’ve actually seen one that was about a 58 percent reduction in energy use, depending on the efficiency of the plant.” Hoffman’s estimates are in line with a 2007 U.S. EPA report that says the use of CHP in ethanol plants can reduce energy use by almost 55 percent. That savings in energy results in an attractive return on investment. “It’s not the kind of thing people have seen in some of the low-hanging fruit type enhancements that pay out in a year or so,” Hoffman says. “But you’re talking about a three-year [ROI], plus or minus, just on energy savings. “The key thing is that these things are highly efficient,” he adds. “What people probably don’t necessarily realize is that a lot of the traditional power that’s generated by the utilities is something in the neighborhood of 60 percent efficient because they condense steam either in cooling towers or into lakes and rivers. That heat is lost. In a turbine/HRSG configuration like we would propose for an ethanol plant, you’re recovering all of that waste heat. A typical CHP is something just above 90 percent efficient.” CHP systems can also offer an additional source of revenue. The systems can be designed to generate more power than the plant uses, allowing the excess electricity to be sold back to the utility company or marketplace. While it is an option, Hoffman says it’s not common for ethanol plants. “What we have found is that the excess electricity sales will generate revenue, but it’s not a significant revenue generator.”

COGENERATION Pierson agrees. He says Poet has explored the option but has opted not to sell excess electricity. “Unfortunately, you don’t get paid very much to put electricity to the grid, so it’s just not attractive,” he says. While it may be rare, Calgren Renewable Fuels in Pixley, California, does sell its excess electricity. Lyle Schlyer, Calgren’s president, says the plant’s CHP system was incorporated into the original design because of limitations of the local power grid. After adding a new turbine in 2016, the plant’s electrical generation capacity increased, allowing it to generate more power than it consumes. “We’re 11 megawatts and we only draw about 3.8 these days, and we sell a little bit to a carbon dioxide plant, but the remainder goes back to the grid, about 5 megawatts,” he says. However, he agrees it may not be attractive for every plant. He says Calgren’s Kansas plant doesn’t sell excess power. “It does not make sense to do it in Kansas,” he says, adding that the electricity market isn’t favorable. Schlyer also backs up the efficiency claim about CHP turbines. “It allows us to run these units the way they were intended. These gasfired turbines run way better when they’re running at or close to full load than they do when they’re running at half-speed.” The other major benefit is being able to generate power and keep the plant running, even when the local utility isn’t able to. “I like the fact that when there’s a tornado or cyclone or earthquake in California, or wildfire or a tree limb takes out an electrical feeder, we just soldier on,” Schlyer says. “It’s a huge advantage.” While Hoffman says one of the major advantages for plants in the Midwest to use CHP is a lower CI score, making low carbon markets more attractive, Schlyer says Calgren’s California plant doesn’t see that same benefit. “Midwest electricity, under the [Greenhouse Gases, Regulated Emissions, and Energy Use Transportation] model, is generated, to some extent, in coal-fired plants, and coal-fired plants end up creating a higher life cycle CI,” Schlyer says. “California’s a little cleaner because of its hydro.” But, Schlyer says, the plant does benefit in electricity savings. “California electricity is through the roof,” he says. “If you look at a typical ethanol plant’s electric bill, they pay X per megawatt hour for power,” Hoffman says. “But then they have all sorts of ancillary charges, and in some states, those can be pretty excessive.” Those charges

for demand usage and time of use become a nonissue for plants that generate their own power. “You’re fundamentally paying a flat rate. At the end of the day, it’s indexed to natural gas, but it’s immune from all of those sorts of swings and charges.” Both Pierson and Hoffman say cogeneration will increase in the ethanol industry. Hoffman says the carbon benefits of such systems make it perfect for the California market now, and any other carbon markets that open in the future. “Ontario’s the largest motor fuel market in Canada, and that would be a terrific

market for a low-carbon fuel ethanol, if and when that market comes into being,” he says. “And Canada has indicated they are going to do that.” Additionally, markets in Washington, Oregon and the Northeastern U.S. would potentially offer incentives for low-carbon fuels as well, he says. Author: Matt Thompson Associate Editor, Ethanol Producer Magazine 701.738.4922



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SINGLE-STEP SOLUTION: A clean-in-place system has been designed to reduce chemical use and downtime. PHOTO: FILE PHOTO



A one-step clean-in-place solution designed for ethanol plants decreases chemical usage while cleaning both inorganic and organic compounds. By Michael Raab

In the dry grind corn-to-ethanol process, operators are continually seeking ways to improve process efficiency and lower operating costs to help drive the overall profitability of their plants. Multi-step, clean-in-place (CIP) procedures

are employed in many process steps to chemically and physically remove deposits that have fouled the surfaces of equipment, including tanks, piping and heat-transfer surfaces. Plant design, water quality, pH, enzyme mix, phytase addition and corn oil extraction are just a few of the dozens of factors that contribute to the fouling of the evaporator chain, as well as many other areas in the

process stream. Understanding the nature of the fouling is key to effectively removing these deposits.

Two Types

Deposits can be divided into two types: organic and inorganic. Organic deposits generally consist of proteins, fiber, starches and fats. Proteins adhere rapidly to heat exchanger

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surfaces, and protein/carbohydrate interactions (such as the Maillard reaction) can occur, as well. Inorganic deposits are mineral in nature and are driven by species solubility based on concentration and temperature. These inorganic species demonstrate inverse solubility and, at high temperature, precipitate out of solution. This change is typically irreversible, so a change in concentration or temperature will not resolubilize these deposits. Typical inorganic deposits in this type of system are magnesium phosphate, calcium phosphate and calcium oxalate. Most deposits contain a matrix of the two types, but the ratios at which they can be present vary drastically. Analysis of the deposits from evaporators are critical to understanding how to best approach instituting an effective and robust cleaning process.

Efficient Approach

Historically, the approach to effective CIP has been a combination of acid cleaning, alkaline cleaning and hydroblasting, which is a physical, not chemical, approach. Plants often undergo an extended acid cleaning, followed by an extended alkaline cleaning, and then evaporator tubes are hydroblasted to remove any remaining deposits. This multistep approach leads to significant downtime and chemical costs. Each of the cleaning steps can range from six to eight hours or more. Additionally, these chemistries will end up in the distillers dried grains with solubles (DDGS), so they must be approved for animal feed. This restriction puts severe limitations on which chemistries are allowed in the process. It is possible to employ a single-step alkaline cleaning approach that can address the broad range of deposit samples encountered and meet the animal feed regulations. By addressing the removal of both organic and inorganic deposits in the same cleaning step, a decrease in the overall downtime, as well as a decrease in overall chemical usage, can be achieved. In some cases, the physical hydroblasting step can be eliminated, as well. It can be done with a solution additive to the caustic (sodium hydroxide) CIP already used throughout the plant. The additive would ideally work over a wide range of alkaline pH,


as CIP make-up and life vary greatly from plant to plant, and even from week to week within the same plant. This approach incorporates additives to help the caustic do its job better, with improved wetting and solids suspension. Most critically, additional additives can be included that would directly target inorganic deposits in an alkaline cleaning environment, such as in the evaporator chain and other heatexchange surfaces.

A Cleaning Case Study

Suez conducted a case study on the CIP approach at an ICM-designed plant on evaporator No. 6. The evaporator was fouled with a matrix of organic and inorganic deposits. The CIP was conducted over a period of 24 hours, with an average temperature of 120 degrees Fahrenheit and a CIP caustic concentration target of 5 percent. The one-step CIP removed both types of deposits, and operators noted a much larger amount of organic material sloughing off into solution than they had in past CIPs. (See Figure 1.) Borescope analysis confirmed the removal of deposits down to bare metal along the length of the tubes. Laboratory analysis of the CIP solutions confirmed the presence of a majority of magnesium phosphate, with some calcium phosphate and oxalate, as well. Samples were collected at periodic intervals throughout the cleaning and sent to the

laboratory for analysis. This analysis confirmed the removal of magnesium and calcium deposits, as evidenced by the rapid increase of both materials (as well as phosphate) in solution. When compared to caustic-only CIP, the enhanced one-step CIP was able to remove roughly 10 times the amount of magnesium, and six times the amount of calcium. By addressing both types of cleaning in one step, a significant downtime reduction can be expected, from one-half to possibly one-third of the time typically allotted for evaporator CIP. In this case study, cleaning was effective enough that hydroblasting was not necessary. It eliminated the use of sulfamic acid and improved heat transfer efficacy, generating an estimated savings of $20,000. Utilizing a single-step, enhanced alkaline cleaning solution is a viable and attractive alternative to the historical approaches for CIP cleaning. This approach is effective over a broad range of operating conditions and deposit type combinations. Author: Michael Raab Lead Technologist, SUEZ â&#x20AC;&#x201C; Water Technologies & Solutions 215.633.4312



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2019 October Ethanol Producer Magazine  

The Ethanol Lab Tech Issue. Plus: E15 Market Update

2019 October Ethanol Producer Magazine  

The Ethanol Lab Tech Issue. Plus: E15 Market Update