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August 2016

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AUGUST 2016 | BIOMASS MAGAZINE 3

INSIDE¦AUGUST 2016 | VOLUME 10 | ISSUE 8

Subscriptions Biomass Magazine is free of charge to everyone with the exception of a shipping and handling charge of $49.95 for anyone outside the United States. To subscribe, visit www.BiomassMagazine.com or you can send your mailing ad-dress and payment (checks made out to BBI International) to Biomass Magazine Subscriptions, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. You can also fax a subscription form to 701-746-5367. Back Issues & Reprints Select back issues are available for $3.95 each, plus shipping. Article reprints are also available for a fee. For more information, contact us at 701-746-8385 or [email protected]. Advertising Biomass Magazine provides a specifi c topic de-livered to a highly targeted audience. We are committed to editorial excellence and high-quality print production. To fi nd out more about Biomass Magazine advertising opportunities, please contact us at 701-746-8385 or [email protected]. Letters to the Editor We welcome letters to the editor. Send to Biomass Magazine Letters to the Managing Editor, 308 2nd Ave. N., Suite 304, Grand Forks, ND 58203 or email to [email protected]. Please include your name, ad-dress and phone number. Letters may be edited for clarity and/or space.

06 EDITOR’S NOTEEquipped to InnovateBy Tim Portz

08 BUSINESS BRIEFS

POWER 10 NEWS11 COLUMN

California Biomass: Abundant Fuel Needs Policy SolutionBy Bob Cleaves

12 FEATUREAcid Gas Control StrategiesDry sorbent injection systems and wet scrubbers are effective in helping biomass plants meet regulations.By Ron Kotrba

16 FEATUREBiomass and BrexitStakeholders wonder how the United Kingdom’s decision to exit the European Union will affect biomass energy.By Amanda Saint

PELLETS 20 NEWS22 FEATURE

Apparatus AdvantageWell-equipped, in-house pellet labs give mills a leg up in meeting specifi cations.By Katie Fletcher

THERMAL 30 NEWS31 COLUMN

Keeping ScoreBy David Spindler

32 CONTRIBUTIONBaltic Rim Wood Fiber Supply and Demand The Baltic States have much of what’s needed to capitalize on the energy chip export trade as it expands.By Tracy Leslie

34 CONTRIBUTIONThe Intricacies of Pyrolyzer Furnace DesignMany key considerations can infl uence whether a pyrolyzer succeeds or fails.By Brad Waites, Pamela Buzzeta and Crystal Bleecher

BIOGAS 38 NEWS 39 COLUMN

Driving Growth in Driving GreenBy Marcus Gillette

40 DEPARTMENTRegs and BaconNorth Carolina’s renewable energy mandate is driving growth in swine waste-based energy.By Anna Simet

ADVANCED BIOFUELS 42 NEWS 43 COLUMN

Ancient Biology for Modern DecarbonizationBy Matt Carr

44 FEATURESolving the Equipment EquationAGCO’s Glenn Farris talks technology, markets and in-the-fi eld experience.By Anna Simet

Biomass Magazine: (USPS No. 5336) August 2016, Vol. 10, Issue 8. Biomass Magazine is published monthly by BBI International. Principal Offi ce: 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. Periodicals Postage Paid at Grand Forks, North Dakota and additional mailing offi ces. POSTMASTER: Send address changes to Biomass Magazine/Subscriptions, 308 Second Ave. N., Suite 304, Grand Forks, North Dakota 58203.

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ADVERTISER INDEX¦

12

2017 International Fuel Ethanol Workshop & Expo 282017 International Biomass Conference & Expo 29Andritz Feed & Biofuel A/S 10ASTEC Bulk Handling Solutions 45Astec, Inc. 2BRUKS Rockwood 37Christianson & Associates' Biofuels Financial Conference 47CPM Global Biomass Group 38D3 Max LLC 21Detroit Stoker Company 19EBM Manufacturing 8Elliott Group 4Hermann Sewerin GmbH 18Hurst Boiler & Welding Co. Inc. 36 IEP Technologies 24-25KEITH Manufacturing Company 7Laidig Systems, Inc. 20Mole Master Services Corporation 27Morbark, Inc. 15ProcessBarron 14Rawlings Waste Wood Recovery Systems 33SCHADE Lagertechnik GmbH 30 TerraSource Global (Jeffery Rader) 17Tramco, Inc. 9Vecoplan LLC 42Vermeer Corporation 5Williams Crusher 48Yargus Manufacturing, Inc. 26

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6 BIOMASS MAGAZINE | AUGUST 2016

Equipped to Innovate

In every issue of Biomass Magazine dedi-cated to equipment and equipment innovations, the men and women who put these machines to work jump off the page. This is the case in Se-nior Editor Ron Kotrba’s very thorough page-12 story, “Acid Gas Control Strategies,” in which he leverages the decades of industry knowledge his

sources possess to compare dry sorbent injection and wet scrubbing approaches. Kotrba connected with both Link Landers, CEO of PPC Industries, and Mitch Lund, a technical services engineer from Nol-Tec Systems, to outline when and why each system is deployed, and the advantages and optimal deployment of each technology. These technologies, while impressive in their own right, are merely extensions of the human minds that invent, deploy and optimize them. This is fortunate, because as Lund told Kotrba, “The general trends in the industry show that as years pass, newer compounds are added to regulation laws and existing compounds come under tighter regulations.” Lund and Landers helped Kotrba understand the connection between the emissions control technologies widely de-ployed today, and the policies that catalyzed their development.

While Kotrba’s story looks at mature technologies invented to comply with increased regulation, Managing Editor Anna Simet’s page-40 feature, “Regs and Bacon,” explores technology innovations in earlier stages of development, initiatives being spurred by North Carolina’s renewable energy mandate. Simet’s piece investigates how a carve-out for swine waste-derived electricity in the state renewable portfolio standard is driving innovation within the biogas sector. Broad-ly speaking, anaerobic digestion (AD) is not a new technology. But if ambitious goals like the kind North Carolina has set are to be met, the AD of swine waste within existing hog production systems must be perfected. Swine waste offers its own challenges for designers of AD systems, and Simet learned that the market opportunity generated by this state-specific policy has motivated more than a few designers and builders to overcome the unique challenges inherent to this abun-dant feedstock.

Policy drives innovation. The Clean Air Act gave rise to the control of acidic gases through dry sorbent injection and wet scrubbers, and North Carolina’s swine waste carve-out may well yield a workable digestion approach for a feed-stock that, for a long time, technology developers avoided. This story is playing out all across the biomass sector, proving that this industry’s most impressive machine is the one residing between our collective ears.

TIM PORTZVICE PRESIDENT OF CONTENT & EXECUTIVE [email protected]

¦EDITOR’S NOTE

EDITORIAL

PRESIDENT & EDITOR IN CHIEFTom Bryan [email protected]

VICE PRESIDENT OF CONTENT & EXECUTIVE EDITOR

Tim Portz [email protected]

MANAGING EDITOR Anna Simet [email protected]

SENIOR EDITOR Ron Kotrba [email protected]

NEWS EDITORErin Voegele [email protected]

ASSOCIATE EDITORKatie Fletcher [email protected]

COPY EDITOR Jan Tellmann [email protected]

ARTART DIRECTOR

Jaci Satterlund [email protected]

GRAPHIC DESIGNERRaquel Boushee [email protected]

PUBLISHING & SALESCHAIRMAN

Mike Bryan [email protected]

CEOJoe Bryan [email protected]

VICE PRESIDENT OF OPERATIONSMatthew Spoor [email protected]

SALES & MARKETING DIRECTORJohn Nelson [email protected]

BUSINESS DEVELOPMENT DIRECTOR Howard Brockhouse [email protected]

SENIOR ACCOUNT MANAGERChip Shereck [email protected]

ACCOUNT MANAGERJeff Hogan [email protected]

CIRCULATION MANAGER Jessica Tiller [email protected]

MARKETING & ADVERTISING MANAGERMarla DeFoe [email protected]

EDITORIAL BOARD MEMBERS

Stacy Cook, Koda Energy

Ben Anderson, University of Iowa

Justin Price, Evergreen Engineering

Adam Sherman, Biomass Energy Resource Center


INDUSTRY EVENTS¦

SWANA’s WASTECON 2016AUGUST 22-25, 2016Indiana Convention CenterIndianapolis, IndianaWASTECON is the premier solid waste industry-focused conference that features the latest news, education, advancements and products to help you achieve success in your business, all in one setting. WASTECON of-fers opportunities to see what’s new in collection, processing, marketing and management of compost, recyclables and solid waste. Join thousands of in-dustry professionals for training, technical sessions, exhibits and networking opportunities. Explore a variety of new topics and expand your knowledge of what’s happening in solid waste management.(800) GO-SWANA | www.wastecon.org

USIPA 6th Annual Exporting Pellets ConferenceNOVEMBER 6-8, 2016Fontainebleau Hotel Miami Beach, FloridaHear from experts and innovators in the field during two days of panel ses-sions and presentations on finance, market outlook, policy developments, and more; network with over 400 industry leaders and professionals; an ex-plore the exhibit hall with representatives from throughout the supply chain. (804) 775-5894 | www.theusipa.org/conference

International Biomass Conference & ExpoAPRIL 10-12, 2017Minneapolis Convention CenterMinneapolis, MinnesotaOrganized by BBI International and produced by Biomass Magazine, this event brings current and future producers of bioenergy and biobased prod-ucts together with waste generators, energy crop growers, municipal lead-ers, utility executives, technology providers, equipment manufacturers, proj-ect developers, investors and policy makers. It’s a true one-stop shop––the world’s premier educational and networking junction for all biomass indus-tries.(866) 746-8385 | www.biomassconference.com

2016 Christianson & Associates' Biofuels Financial ConferenceOCTOBER 17-18, 2016Hyatt Regency MinneapolisMinneapolis, MinnesotaProduced by Christianson & associates and organized by BBI International, this year’s Biofuels Financial Conference is focused on the best ways to explore new options in today’s changing ethanol and biodiesel industries. By understanding risks associated with various technology and marketing initiatives, and by exploring various options for making the best use of capital and resources, we’ll learn how to create a well-managed plan for growth and change—a plan which maximizes profitability while ensuring future stability and meeting the expectations of all stakeholders. (866) 746-8385 | www.biofuelsfinancialconference.com

2017 International Fuel Ethanol Workshop & ExpoJUNE 19-21, 2017Minneapolis Convention CenterMinneapolis, MinnesotaFrom its inception, the mission of the event has remained constant: The FEW delivers timely presentations with a strong focus on commercial-scale ethanol production––from quality control and yield maximization to regula-tory compliance and fiscal management. The FEW is also the ethanol in-dustry’s premier forum for unveiling new technologies and research findings. The program extensively covers cellulosic ethanol while remaining commit-ted to optimizing existing grain ethanol operations.(866) 746-8385 | www.fuelethanolworkshop.com

®


DVO installs digester in China DVO Inc. has installed and commis-

sioned an anaerobic digester at Austasia Modern Dairy Farm in Xianhe in Shandong Province, China. The project is DVO’s first installation in China. The digester processes manure from approximately 5,600 milking cows. Biogas generated by the project is used to generate heat for the digester and various onsite facilities. Future plans include the production of renewable natural gas or electricity.

ABFA welcomes new members, announces board changes

The board of the Advanced Biofuels Association has welcomed BIOX, Louis Dreyfus and the Brazilian Sugarcane In-dustry Association as members. With these three new members, the ABFA represents 9.6 billion gallons of domestic and interna-tional biofuels production. The board also elected Neville Fernandes, head of sales and marketing and a board member at Neste U.S. Inc., as chairman. In addition, Michael Whitney, general manager of renewable fu-els at Musket Corp.; Len Federico, manager of biofuels and oils at Louis Dreyfus; Jef-frey Jacobs, president and CEO of Ensyn; Paolo Carollo, executive vice president of

Beta Renewables/BioChemtex; and John Cummings, vice president of Wilmar North America, were added to the ABFA executive committee. Former Chairman Wayne Sim-mons, CEO of Sundrop Fuels, will remain as the ex-officio member of the committee.

Rural Energy adds team memberRural Energy has boosted its in-house design capabilities with the edition of Carlyne Parillon as senior design engineer. Parillon will interpret client briefs and is responsible for concept and detailed designs of energy centers. She has more than seven years of experience designing district heating systems.

Chadwick-BaRoss joins Barko distribution network

Barko Hydraulics LLC has added Chadwick-BaRoss Inc. to its distribution network for all forestry equipment product lines. With five locations across Maine, Mas-sachusetts and New Hampshire, Chadwick-BaRoss will carry Barko equipment for the New England region.

Solegear acquires bioplastics division of Ex-Tech

Solegear Bioplastic Technologies Inc. has completed the acquisition of the bio-plastics division of Ex-Tech Plastics Inc. for $1.33 million in common shares. Ex-Tech has been a leading manufacturer of extrud-ed plastic sheets for more than 30 years. The acquisition is expected to provide Solegear with annualized revenues of an estimated $2 million, which the company expects to use as a base for further growth and develop-ment.

Envitec constructs biogas plant

Germany-based EnviTec Biogas AG is constructing a 6-MW biogas plant that uses digestion to convert waste pretreated with enzymes into green energy for REne-science Northwich, a subsidiary of Danish utility DONG Energy A/S. The technique, which is used to treat unsorted household waste with the aid of a specialized formu-lation involving the use of enzymes, has been developed and tested in a pilot plant in Copenhagen. With the construction of a full-sized plant, DONG Energy aims to prove its new technology under real-world conditions. Waste will be collected by the U.K. waste management company FCC Environment, treated in the plant and then

PEOPLE, PRODUCTS & PARTNERSHIPSBusiness Briefs

Parillon


BUSINESS BRIEFS¦

processed as a bioliquid in the biogas plant to be constructed by EnviTec. The annual volume of approximately 328,000 metric tons of bioliquid will be filled into a hold-ing tank in the biogas plant and processed in four digesters. The biogas produced will be piped into four cogeneration units, creating approximately 45.5 million kWh of electric-ity, which will be fed into the local grid.

Evergreen Engineering opens new location Eugene, Oregon-based Evergreen Engi-neering Inc. has opened a branch office in Atlanta, Georgia, to pursue opportunities in the southeastern U.S. The office celebrated its grand opening July 1.

BIO adds members The Biotechnology Innovation Organiza-tion has announced several companies

joined its industrial and environmental sec-tion during the past year, including Bryan, Texas-based Earth Energy Renewables LLC; Cambridge, Massachusetts-based En-evolv Inc.; Las Vegas, Nevada-based Green Life Can LLC; Brooklyn, New York-based Modern Meadow Inc.; Boulder, Colorado-based Muse Biotechnologies Inc.; and Oakland, California-based RHO Renew-ables Inc.

NREL appoints director of Biosciences Center

Mark Davis has been named director of the Biosciences Center at the U.S. DOE’s Na-tional Renewable Energy Laboratory. He joined NREL in 1993 as a post-doctoral research associate and has served as the platform program manager for thermo-chemical processes since 2010. Davis is also currently directing the Enabling Technolo-gies Focus Area for the BioEnergy Science Center, a DOE-sponsored effort led by Oak Ridge National Laboratory. Since joining NREL, Davis has served as the group man-ager for Chemical and Catalyst Sciences in NREL’s National Bioenergy Center. In ad-

dition, he has authored or co-authored more than 90 peer-reviewed publications and three book chapters.

Energy Trust of Oregon names

executive directorEnergy Trust of Oregon has an-

nounced its board of directors appointed Michael Colgrove as executive director, ef-fective Aug. 15. Colgrove will lead the orga-nization in continuing to deliver the cleanest, lowest-cost energy available for 1.5 million utility customers in Oregon and southwest Washington. Colgrove succeeds Margie Har-ris, who is retiring after leading the organi-zation since its inception in 2001. Colgrove joins Energy Trust after 15 years with the New York State Energy Research and De-velopment Authority, where he was both the director of the New York City office and di-rector of multifamily programs.

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The International Renewable Energy Agency has released a report finding more than 8.1 million people worldwide are cur-rently employed by the renewable energy industry, up 5 percent from last year.

The report, titled “Renewable Energy and Jobs—Annual Review 2016,” deter-mined that the total number of renewable energy jobs increased in 2015, while jobs in the broader energy sector decreased.

China, Brazil, the U.S., India, Japan and Germany had the most renewable energy jobs in 2015. The report estimates 1.68 million jobs globally in the liquid bio-fuels sector, with solid biomass at 822,000 jobs and biogas with 382,000 jobs.

The report estimates 241,000 solid biomass jobs in China, with 152,000 jobs in the U.S., 58,000 jobs in India, 49,000 jobs

in Germany, 48,000 jobs in France, and 214,000 jobs in the remainder of the EU. For biogas, the report estimates 209,000 jobs in China, 85,000 jobs in India, 9,000 jobs in Bangladesh, 48,000 jobs in Germa-ny, 4,000 jobs in France, and 14,000 jobs in the remainder of the EU.

PowerNews

The United Kingdom has voted to leave the European Union and Prime Min-ister David Cameron has resigned.

The referendum, known as Brexit, was held June 23, with 51.9 percent voting to leave the EU and 48.1 percent voting to stay in the political-economic union. Nina Skorupska of the U.K. Renewable Energy Association said the U.K.’s decision “raises serious questions for investor certainty, en-ergy security and much-needed investment in U.K. energy infrastructure.”

Cameron resigned as prime minister in mid-July and was replaced by Theresa May. Negotiations with the European Union are

expected begin under the new prime min-ister.

Reacting to news of the vote, Skorup-ska stressed energy policy must be a prior-ity for the government now, with industry needing reassurance and ministerial clarity on priorities. “The vast majority of our members had fears of Brexit, and we will be consulting with them and government in the coming weeks to set out a plan for continued low-carbon energy investment, deployment and assurance of the 117,000 jobs in this sector,” she said.

IRENA reports increase in global renewable energy employment

UK votes to leave the European Union

Renewable energy jobs (in thousands) Solar photovoltaic 2,772Liquid biofuels 1,678Wind energy 1,081Solar heating/cooling 939Solid biomass 822Biogas 382Hydropower (small) 204Geothermal energy 160CSP 14SOURCE: INTERNATIONAL RENEWABLE ENERGY AGENCY


California continues to be a frustrating illustration of the paradox of biomass nationwide: So much fuel exists and needs a place to go, yet many biomass facili-ties are struggling to stay open. An estimated 66 million dead and diseased trees across California—enhanced by a years-long drought combined with a pine beetle epi-demic—means fuels are plentiful, but they aren’t being used for biomass power.

Encouragingly, there appears to be widespread agreement that a strong biomass sector would solve many problems, promoting the removal of hazardous fuels and improving air quality that worsens with open-burning and forest fires. A strong and productive biomass industry can also help the U.S. Forest Service reduce the risk of catastrophic fires and, in doing so, reduce budget spending on fighting fires.

Because of the stiff competition presented by low natural gas prices, many biomass facilities have closed their doors or are carefully considering that option. As a result, some in California are concerned about what to do with hazardous fuels that desperately need clear-ing, as well as with the agricultural waste that typically is purchased by biomass facilities.

A December 2015 Los Angeles Times story looked at the air quality issues at stake with the closure of some biomass facilities. The story noted that biomass facilities drastically reduce farmers’ costs for waste and residue removal. Without this outlet, some farmers anticipate their waste removal expenditures to increase as much as threefold.

In California, if there is no biomass facility available to take on these materials as fuel, farmers are allowed to open-burn them. This is undeniably bad for the envi-ronment, releasing increased levels of greenhouse gases (GHG) into the atmosphere.

According to a study sponsored by the Placer Coun-ty Air Pollution Control District, without a biomass

power facility—aside from carbon dioxide—dramatically higher levels of particulate matter, carbon monoxide and methane are released into the atmosphere. The authors of the study wrote, “Energy production and reductions in criteria air pollutants and GHG emissions were quan-tified from utilization of forest woody biomass wastes to fuel electricity generation as an alternative to open-pile burning.” However, they went on to caution that biomass economics are not favorable to achieve these reductions, citing transportation and processing costs, and encour-aged a state program to value the benefits of biomass on the basis of its emissions-avoidance benefits.

The tree mortality problem in California has gotten so dire that officials aren’t waiting for a biomass solu-tion. Rather than salvaging some value out of hazardous fuels harvested, as would happen if they went to a bio-mass facility, the state of California is considering the use of expensive mobile incinerators. These devices would travel around the state, simply destroying the dead and diseased trees on the spot. While these burners would solve the immediate problem of hazardous fuel removal, there are serious concerns about them from an air qual-ity and GHG perspective. A biomass facility would not only put these materials to good use, it would also greatly reduce emissions from burning them.

The California Biomass Energy Alliance has been working hard, collaborating with state officials to find a solution that would keep the biomass industry on course and help the state and U.S. Forest Service address the problem of abundant hazardous fuel. We look forward to seeing what results.

Author: Bob CleavesPresident, Biomass Power Association

[email protected]

California Biomass: Abundant Fuel Needs Policy Solution

POWER¦

BY BOB CLEAVES


Acid Gas Control StrategiesDepending on boiler or plant size and expected lifespan, two major technologies—dry sorbent injection systems and wet scrubbers—can help biomass users effectively remove acid gases for emissions compliance. BY RON KOTRBA

The emission of acid gases from power plant and boiler combustion is a major threat to human, animal and plant life, and the environment. Acid gases such

as sulfur dioxide (SO2) or hydrogen sulfide may effect ecosystems through acid rain or dry deposition. “Some acidic lakes have no fish,” states the EPA. “Even if a species of fish or animal can tolerate moderately acidic water, the animals or plants it eats might not.”

Areas effected by acid rain may be visually identifiable by the presence of dead or dying trees. Acid rain leaches aluminum from the soil, which may be harmful to plants and ani-mals. Acid rain also removes minerals and nu-trients from the soil that trees need to grow, ac-cording to EPA. “At high elevations, acidic fog and clouds might strip nutrients from trees’ fo-liage, leaving them with brown or dead leaves and needles,” the agency states. “The trees are then less able to absorb sunlight, which makes them weak and less able to withstand freezing temperatures.”

Mitch Lund, a technical services engineer at Nol-Tec Systems, a process engineering

company with a focus on bulk material han-dling and acid gas control, says the term “acid gas” is a generic chemical description for any gaseous mixture containing acid-based com-pounds. “If present in high enough concen-trations and inhaled, acid gases can be harmful to life—specifically by breaking down respira-tory and skin cells,” Lund says. “Additionally, when acid gas is released into the atmosphere, it combines with moisture to form acid rain.”

This is a problem for biomass, Lund says, because burning fuel for power or steam gen-eration creates acid gases in the combustion process. “Fuel has sulfur- and nitrogen-based compounds that, when burned, form gaseous SOx and NOx compounds that are the basis for acid gases,” he says. SOx and NOx are sul-fur and nitrogen oxides, respectively.

“Plants absorb minerals from the earth in which they grow, and some plants—citrus trees in particular—absorb more chlorine than others,” says Link Landers, CEO of PPC In-dustries, a company focusing on pollution control that, in 1988, developed an acid con-trol system using dry sorbent injection (DSI).

“And some plants absorb more sulfur than others.”

Because acid gases are hazardous to hu-man health and the environment, they are regulated by local, state and federal agencies. “Recently, acid gas regulation has been driven at the federal level, while working closely with states to enact implementation plans designed to control local economic impact,” Lund says. “The roots of these federal regulations are based in the Clean Air Act of 1973 that gave the EPA power to control air pollution at a na-tional level. Amendments to this ruling in the past 30 years have enforced the control of acid gases.”

Landers notes that the National Ambient Air Quality Standards established six criteria pollutants. “In this, hazardous air pollutants (HAP) were established, and included in these are acid gases,” Landers says. “Specifically, the heart of the current regulations states that there cannot be more than 10 tons per year of any single HAP and no more than 25 tons per year of all HAPs combined.” Lund further explains that “recent acid gas rulings like the

POWDER INJECTION: Dry sorbent injection (DSI), one effective approach at bringing acid gas emissions from boilers and power plants into compliance, involves injecting a base powder—either milled or unmilled—into the flue gas stream that reacts with the acid gases present in order to neutralize them. Shown here are the injection sites of a DSI system developed by Nol-Tec Systems. PHOTO: NOL-TEC SYSTEMS


POWER¦Mercury and Air Toxic Standards and the In-dustrial Boiler Maximum Achievable Control Technology set limits on how large boilers have to be in order to be deemed necessary to regu-late,” he says. “Any coal- or oil-fired unit that sells electricity to the grid and is greater than 25 megawatts (MW) must comply with MATS. The IB MACT applies to any process boiler that has the potential to emit 10 tons per year of a regulated pollutant or 25 tons per year of any combination of pollutants. These federal rulings require each boiler to be evaluated on a case-by-case basis. Some companies are regu-lated on an overall facility fleet basis, but these are the exceptions, not the rule.” States are re-quired to develop State Implementation Plans to carry out federal laws set forth by EPA. “The SIPs can be more restrictive than the fed-eral law, but not more lax,” Landers says.

Here is how one would calculate whether a power plant or a boiler for plant use—since the regulations do not differentiate between the two—would be subject to the IB MACT rule for one regulated pollutant: chlorine. “If we assume a 150 MMBtu-per-hour power plant utilizes a fuel that has 7,500 Btu per pound, and contains 0.01 percent of chlorine on a wet ba-sis, then that is 20,000 pounds per hour of fuel and 2 pounds an hour of chlorine, which, if the plant operated 8,760 hours per year would yield 17,520 pounds, or 8.76 tons, per year,” Landers says. “This is below the annual limit. But, in-creasing the plant size to 200 MMBtu per hour would yield 11.7 tons per year of chlorine, thus requiring some type of control.” He says the big fear is that EPA may lower the HAPs limits from 10/25 to, for instance, 8/20.

“The general trends in the industry show that as years pass, newer compounds are added to regulation laws and existing compounds come under tighter regulations,” Lund says. “In general, as technology and environmental awareness evolve, pollution control does, too.”

OptionsFor SO2, sulfur trioxide (SO3) and hydro-

chloric acid (HCl) control, the most common solutions, according to Lund, are wet scrub-bers and DSI systems. Landers says both types come in a variety of methodologies and con-figurations.

Nol-Tec Systems has more than 70 per-manent acid gas removal systems in place today, Lund says. “We have also placed more than 70 testing or leasing temporary systems over the past 10 years,” he says. “We have three systems that use biomass as their main fuel source, but we also have numerous sites that utilize some smaller percentage of biomass as a fuel. Our DSI systems are flexible to work with either biomass of any type, or more traditional fuel sources, such as coal.”

Nol-Tec has provided DSI systems for acid gas control and activated carbon injection (ACI) systems for mercury control since the early 2000s. “We got into the industry based upon our experience pneumatically conveying dry powders,” Lund says, adding that Nol-Tec also provides wet scrubbers through its Lodge Cottrell division.

Wet scrubbers work by passing the dirty gas through a liquid compound that is designed to react with the targeted acid gas for removal from the dirty stream. “On the wet side, there are packed tower scrubbers, venturi scrubbers, bubbling tray scrubbers, virtual tray scrubbers, also called spray scrubbers, which utilize cross flow, cocurrent and countercurrent flow meth-odologies,” Landers says. “These scrubbers can use a variety of bases to accomplish the acid-base reaction required to neutralize the acids.”

Caustic seems to be the reagent of choice for smaller systems, says Ray Willingham, an engineer at PPC Industries. “Larger utility-scale systems commonly use limestone,” he says.

DSI systems inject a dry chemical sor-bent, or powder, into the flue gas for the same targeted removal as wet scrubbers, Lund says, and both solutions—wet scrubbers and DSI systems—form byproducts that are sepa-rated from the process and must be properly disposed of. Landers says this powder can be milled, unmilled or evaporative. “Trona or sodium bicarbonate are typically used in these systems,” Willingham says.

“Milled and unmilled injection is accom-plished by blowing the base into a reaction chamber or duct where random probability takes over,” Landers says. “An acid molecule must come in contact with the base molecule.” Willingham notes that two factors come into play here—particle numbers and surface area.

“The greater number of base molecules compared to acid molecules, the more likely the reaction will occur and the higher the re-moval,” Landers explains. “The smaller the particle size, the longer it will stay airborne,” Willingham says, adding that this leads to bet-ter mixing in the gas and thus a greater prob-ability of the base particle coming in contact with the acid molecules. “Additionally,” he says, “the smaller the particle, the greater the surface area to volume ratio of the particles, and since the reaction requires contact between the base particle and the acid molecule, the combination of an increase in the particle numbers and the available surface area provides an improvement in the performance and removal efficiency of these systems.” Landers says this provides the basis of the argument for milled vs. unmilled injection. “Milled injection typically requires less raw material overall, thereby lowering the operating costs,” he says.

For acid gas removal, PPC Industries, which has been at its current location in Longview, Texas, since 1967, offers milled DSI systems. “We were a precipitator-only company until 1988 when we developed acid control sys-tem using dry sorbent injection,” Landers says. “In 1995, we started producing biofilters for control of volatile organic compounds, and wet electrostatic precipitators. In 2007, we de-veloped selective catalytic reduction units for NOx control and nonselective catalytic reduc-tion units for carbon monoxide control.” PPC Industries has installed DSI systems at 16 loca-tions with nine of them being biomass boilers. Those that are not biomass are glass produc-tion plants and incinerators.

Landers says evaporative systems utilize a combination of wet and dry scrubbers. “A slurry mixture is injected into a reaction cham-ber where the water portion flashes off leav-ing a fine powder—smaller than milled dry sorbent—that reacts with the acid gases,” he says. These systems, according to Willingham, typically operate using limestone or slaked lime.

Lund says a popular form of NOx remov-al is selective catalytic reduction, which involves injecting an ammonia-based material into a re-actor that reacts with the NOx in flue gases to form the nontoxic compounds nitrogen and water. Acid gas clean-up in natural gas facilities vs. coal or biomass plants, for instance, focuses on NOx-based removal. “Combustion-based technologies like low NOx burners, flue gas re-circulation, and selective noncatalytic reduction systems are commonly used to combat NOx emissions in natural gas facilities,” Lund says. “Biomass, however, has a very broad fuel base, so the options for acid gas control are wide-ranging. The fuel will determine the emissions, which determines control requirements and strategies.”

Wet or Dry? The big difference between the two tech-

nologies—wet scrubbers and DSI systems—comes down to operating vs. capital costs, says Lund. “Wet scrubbers are very efficient technologies that have low operating costs,” he says, “but they require capital investments in the hundreds of millions of dollars. DSI systems are the exact opposite. They have low capital costs—typically $1 to $2 million per sys-tem—but they have relatively inefficient use of sorbent, causing high operating costs.” While Lund admits that Nol-Tec Systems’ expertise with wet scrubbers in the biomass industry is limited, he says if a utility plant were used as a case study, wet scrubbers are anywhere from 50 to 100 times the capital cost of a DSI sys-tem, but the operating costs of a DSI system are usually 5 to 10 times that of a wet scrubber. Willingham says dry systems tend to require

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less exotic metallurgy, a main reason for the lower capital costs.

Lund says small units, or larger units with a short expected lifespan, are good candidates for DSI technology. “Biomass plants are usu-ally small enough to always be good candidates for DSI,” he says. “Cost effectiveness is re-lated to unit size and operating life.” He says the general cut off for these parameters is 10 years of operating life and 250 MW of capacity. “Anything lower than these, DSI becomes an attractive option,” Lund says. “Anything higher is generally leaning towards a wet scrubber. Ex-ceptions exist on both sides so it is important for an end-user to consider the pros and cons in both technologies when making compliance strategy decisions. The end user needs to work with an experienced provider to ensure they are getting the system the best suits their particular needs.”

Dry sorbent injection systems will have lower removal efficiencies than wet systems, according to Landers, but dry sorbent systems are easier to operate and maintain. “Wet sys-tems also have the ability to create secondary pollutants,” he adds. “Specifically, a gas stream that contains SO3 will produce submicron sul-furic acid mist (H2SO4) at the point the gases enter main scrubber area. This is due to the water molecules combining with the SO3 mol-ecules. These submicron particles will then

travel through the scrubber, since scrubbers cannot remove these submicron particles, and out through the stack. In this situation, a wet electrostatic precipitator must be placed after the precipitator to capture the sulfuric acid mist.” Landers also notes that dry sorbent and evaporative systems must also be followed by a particulate removal device such as dry electro-static precipitator or baghouse to remove the reacted sorbent.

Landers says dry systems are easier and more economical for SO2 removal less than 80 percent and HCl removal less than 95 per-cent down to about 5 parts per million. “Wet systems have to deal with leaks, corrosion and salts,” he says. “Corrosion can be dealt with if the proper stainless steel is used. Common 304 and 316 varieties are not suited for long-term exposure to some acid gases. Salts are reduced by blowing down water to the wastewater treat-ment plant.” For dry systems, those that utilize milling have increased maintenance over those that do not mill, he says. And evaporative sys-tems, due to their complexity, would have the most maintenance of all.

“Having been in the air pollution control industry for more than 20 years manufactur-ing both wet and dry systems, I can say with all confidence that anytime a pollutant can be treated with a dry system, there is less mainte-nance required and the longer the equipment

lasts,” Landers tells Biomass Magazine. “And in a world of ever-decreasing maintenance and capital budgets, these are extremely important considerations.”

Lund says with recent regulations that drove DSI sales coming and going, Nol-Tec Systems recognized that first-generation DSI systems were ultimately not what end-users wanted. “We remained committed to continu-ous innovation and improvement,” he says. “That has allowed us to work with customers to come up with truly unique features in our systems, such as silo discharging, enhanced sorbent mixing, and improved sorbent disper-sion.”

Pollution control is a necessary evil, Lund says. “It leads to a lot of tough decisions that no one enjoys making. Our No. 1 recommen-dation is to use vendors as resources. We are specialized experts that can reduce the over-whelming task of digging through all the nec-essary information and evaluation that comes with choosing the best compliance strategy.”

Author: Ron KotrbaSenior Editor, Biomass Magazine

[email protected]

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BREXIT AND BIOMASSThere are real concerns about what Brexit means for the future of the U.K.’s renewable energy sector, which has grown significantly with the help of EU-funded investments and subsidies. BY AMANDA SAINT

The uncertainty that surrounds the United Kingdom’s biomass sector has been swirling for some time, and the recent vote for the U.K. to exit

the European Union has exacerbated the situation. Since the Conservative govern-ment came to majority power in 2015, things for biomass haven't been looking as bright as before. The Brexit result was preceded by significant cuts to subsidies that had al-ready led to many projects being cancelled or scaled back. An immediate impact of the

referendum result has seen the value of the pound plummet against the euro and the U.S. dollar, meaning imports have become much more expensive. As the world’s larg-est importer of wood pellets for biomass energy, much of which comes from North America, Brexit may hard hit the pockets of many U.K. businesses.

The biggest concern for the sector is that investments will now be significantly cut. Many of the advances that have been made in the technologies and roll-out of

biomass have been funded through the Eu-ropean Investment Bank. The EIB is owned by the 28 member states of the EU, with the U.K. owning 16.11 percent of the shares. But to be a shareholder of the EIB, a coun-try must be a member state of the European Union, so the U.K. will now have to pull out of the EIB.

On the day that the referendum results were announced, Werner Hoyer, president of the EIB issued a statement, saying, “To-day is a very sad day for Europe. As presi-

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dent of the European Investment Bank, I take note of the U.K. vote with the deep-est regret, although of course the bank will work with member states and other EU in-stitutions to assure an orderly transition to a new negotiated arrangement according to the treaty.”

For now, U.K. shareholding in the EIB remains, and the EIB’s engagement in the U.K. is unchanged. While the Conservative party begins negotiating its exit from the EU, EIB shareholders will be discussing how the bank is going to engage with the country in the future.

Funding FalloutIn the past decade, the EIB has invest-

ed around 50 billion euros in U.K. projects, particularly in renewable energy and infra-structure. Amongst all the well-founded concerns about the future of the sector, there has been some good news—three big biomass projects that received European Commission approval recently for Contract for Difference (CfD) subsidies will still be moving forward. These are the 420-MW

Lynemouth coal-to-biomass conversion for Czech energy firm EPH, Drax’s full con-version of its 645-MW Unit 1, and U.K. company MGT Power’s, 299-MW Teeside combined-heat-and-power project.

Members of EUREC, the Association of European Renewable Energy Research Centres, collaborate on EU-funded projects to advance technologies for all renewable energies. Vinicius Valente, EUREC’s com-munications adviser, has concerns but is still hopeful that biomass research and de-velopment can still advance in a post-EU Britain. “We regret the U.K.’s decision to leave the European Union despite all the breakthroughs achieved by the EU in sever-al strategic areas, including excellence in sci-ence,” he says. “EUREC has a long history of engagement with the EU, and our U.K. members are all prominent research centers that have been working for many years with EU funds to unlock the potential of several technologies.”

Many of the research programs that EUREC members and other research insti-tutes and businesses in the U.K. and Europe

are involved in are funded through the EU Framework Programme for Research and Innovation, Horizon 2020. This 79 billion-euro funding initiative runs until 2020 and aims to drive forward scientific understand-ing and innovation in energy and many oth-er areas, particularly those that are tackling climate change.

Former U.K. Prime Minister David Cameron indicated in a statement to the U.K. Parliament that any contract signed under Horizon 2020 will be honored. But it’s unclear if, post-Brexit, it would be hon-oured with EU money or British money.

Carlos Moedas, EU research commis-sioner, has confirmed that researchers re-main eligible to apply for funding from the Horizon 2020 research program, since the U.K. remains a member of the EU until the end of the negotiations. But if the U.K. is not going to be a part of the EU from 2018 onward, it seems unlikely that any projects involving U.K. universities and businesses that extend beyond then will be top of the list to access that funding pot. Any projects that receive funding must be made up of a


consortium of at least three organizations from different member state countries, so the decision is likely to make U.K. organizations a less-attractive partner when consortiums are coming together.

But could the U.K. become a new Switzerland in the way it participates in projects? The “Swixit” Framework Programme that was introduced in 2014 means that Switzerland has the status of “nonassociated, third-country participant” in some parts of Hori-zon 2020, including projects under the Energy Societal Challenge Work Programme. Valente added, “The U.K. might, in the future, enjoy a similar status. But that said, it is rare that the European Commission’s Horizon 2020 money funds nonassociated, third-country participants. Instead, national funding agencies must cov-er their costs and this could be the case for the U.K.”

Climate Agreement GoalsThe growth of biomass in the EU has been driven by the

need to achieve cleaner energy generation in order to meet green-house gas emission reduction goals. Considering the backtracking the Conservative party has already done with biomass subsidies, many questions are being raised around the climate change agree-ments the U.K. has signed up to.

So far, initial signs are good. Statements coming from the U.K. government have confirmed that the commitment to increasing renewable energy generation remains. Amber Rudd, minister for energy and climate change, was an ardent “Remain” campaigner, and issued a statement saying, “We have announced record invest-ment in new heat networks, to enable new and innovative ways of heating our homes and businesses. And we made a commitment to closing unabated coal-fired power stations—a commitment that was praised by leaders across the world. All these commitments re-main in place. They will help us rebuild our energy infrastructure, and I am certain that future investment in this sector will continue to flow to Britain’s strong economy.”

On June 30, the U.K. government also confirmed the Com-mittee on Carbon Change’s recommended carbon budget, aiming for a 57 percent reduction in carbon emissions from 1990 levels

Renewable electricity generation

2016 Q1 TWh

Percentage change from Q1 2015

Onshore wind 6.43 -10.5Offshore wind 5.14 10.0Hydro 2.05 +1.8Solar PV 1.34 +40.9Bioenergy 8.26 +18.0All renewables 23.22 +6.4

In the first quarter of 2016, the U.K. generated 8.26 terawatt-hours of electric-ity from bioenergy sources (including cofiring), up 18 percent from the same quarter of the previous year.SOURCE: UK DECC


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from 2027-’32. But in order to achieve these goals, they are invest-ing half of the renewables funding pot in new nuclear.

James Court, head of policy and external affairs at the U.K.’s Renewable Energy Association, says, “The fundamentals of en-ergy have not changed post-referendum, we still need new gen-eration that is cost-effective, low-carbon and secure. This would be the worst time for the government to row back or U-turn on existing commitments, which would be toxic to inward investors. So this is a positive first step, but will need to be backed up by a robust energy plan by the end of the year.”

Innovation ContinuesThe U.K. has been defined by its technological innovation

since the time of the industrial revolution, and leaving the EU will not change that. The drive to develop new and better biomass solutions continues. One of the most exciting new developments in the U.K. biomass industry in recent times has come from a new London-based business, Bio-bean, and its stakeholders are feel-ing confident that the Brexit result is not going to affect plans for growth at all.

The business started up in 2014 and believes it is the first company in the world to industrialize the process of recycling waste coffee grounds into advanced biofuels and biochemicals. The company works within the existing energy and waste infra-structure and has developed sustainable products and solutions to replace conventional fuels and chemicals. It has launched nation-wide collection services and recycles the used coffee grounds into biomass pellets and briquettes. The next step is to turn them into biodiesel, and the ultimate goal is to go international. “Historical-ly, even during recessions, the appetite for drinking coffee remains consistent no matter the economic circumstances,” says CEO Ar-thur Kay. “For our business, because our feedstock is already here and we simply divert it from less valuable forms of waste disposal, we are largely insulated from the negative influence of Brexit.”

Despite the uncertainty that has been shaking the country since the Brexit result, there is still a lot of confidence that the renewable energy sector, and biomass within it, can still thrive.

Author: Amanda SaintBiomass Magazine freelance writer

[email protected]

EDITOR'S NOTE: At press time, it was announced that new U.K. Prime Minister Theresa May has dissolved the country's Department of Energy & Climate Change. Visit www.biomassmagazine.com for continued, up-to-date coverage.


PelletNews

FutureMetrics LLC recently released a white paper discussing the current state of the global industrial wood pellet markets and potential opportunities for its growth in Japan.

Regarding potential in Japan, the pa-per, authored by FutureMetrics President William Strauss, notes several policies are driving current and future growth. Under one plausible scenario, Japan could be de-manding in excess of 15 million metric tons per year of wood pellets by the mid 2020s. Feed in Tariff (FiT) incentives offered to independent power producers are currently having an impact on the demand for wood

pellets. Wood pellets and other biomass under the current FiT is 24 yen per kilowatt-hour (kWh) (about 23 cents per kWh or $225 per MWh). This rate is set and guaranteed for 20 years.

Besides the FiT, two other fundamen-tal policy goals Strauss identified in the pa-per are Japan’s carbon emission targets and the government’s desired energy mix by 2030. Currently, there are voluntary targets

requiring power companies to reduce CO2 per kWh by 35 percent from 2013 levels by 2030.

Paper identifies potential market demand for pellets in Japan

Potential renewables demand in Japan, 2030Percent of total energy mix

Nameplate MW needed

Metric tons of wood pellets per year if 30% of MW are

produced from wood pellets

Geothermal 1% 1,351

Biomass 4.30% 6,150 7.64 millionWind 1.70% 6,889

Solar 7% 34,041

Hydro 9% 12,158

SOURCE: FUTUREMETRICS

Although an Idaho pellet plant project announced last spring by Centennial Renew-able Energy hasn’t yet come to fruition, the project is still alive and working to overcome final hurdles.

The company plans to develop a pellet plant on 48 of 135 acres on the site of the Potlatch Lumber Co. timber plant, which was built in the early 1900s and shuttered in 1979.

“The Potlatch mill was one of the largest in the country…it was turned into a brownfield site in 1981, and nothing has operated there since,” says CRE CEO Rick Fawcett. “It was a mill town, everything was owned by Potlatch, and it’s been severely economically depressed ever since.”

The current plant design is for roughly 175,000 to 200,000 tons of pellets per year, but Fawcett said it isn’t likely CRE will op-

erate on that scale. “The reason for that is there isn’t enough water at the location,” he explains.

The project is expected to utilize An-dritz’s SteamEx black pellet technology. “If we do the steam explosion pellets—and that’s what our permit was submitted as—we’ll have to descope the project down to meet the availability of water,” Fawcett said.

Black pellet project in Idaho works to overcome challenges


REDUCING VARIABILITY: Pellets are tested for a number of properties at Somerset Pellet Fuel’s in-house lab in Kentucky, including tests for durability, fines and bulk density shown above. A balance is used in conjunction with nearly all tests, and a bag splitter reduces 40-pound bags to various sample sizes.PHOTOS: MICHAEL FOSTER


APPARATUSA D V A N T A G E In-house pellet plant labs enable fuel quality monitoring, an asset for regularly audited producers. BY KATIE FLETCHER

Most pellet producers make pellet quality a priority. Increasingly, means to verify this desired quality is mak-ing its way to mills. Though not un-

common for fuel manufacturers to have testing capabilities for some of their fuels’ properties, in light of the growing interest in becoming qualified under a third-party accreditation pro-gram, producers are designating or revamping lab space at their plants. Although often modest in size, in-house labs are equipped with a variety of testing tools to assure pellets not only meet company and customer standards, but also those set by quality certification programs, like the Pellet Fuels Institute’s Standards Program, CANplus or the European ENplus benchmark for wood pellets.

“Before we even started the mill up, we ac-tually built and set up a rather complete testing lab right here at the plant,” says Darren Win-chester, safety quality and logistics manager at Indeck Ladysmith LLC. The 90,000-ton-capac-ity plant in Ladysmith, Wisconsin, began pel-let production and testing in 2009, when PFI’s quality program had not yet been fully devel-oped. “Up until we joined the new standards program, we would send out our sister plant samples for third-party testing every 1,000 tons, even though we didn’t have to,” Winchester says. “What that’s done for me is provided me with a substantial amount of correlation data.” Without data to back up a pellet operation, he adds, it’s not a very robust system. “You can run without testing, but basically it’s like running with a blindfold on,” he says.

Luann Lafreniere, New England Wood Pellet’s quality manager, says when they decided to join the PFI Standards Program, the entire company was folded into the quality manage-ment system they developed. Now, even though some testing was done prior to PFI qualifica-tion, all four plants (Deposit, Schuyler, Jaffrey and Allegheny) have labs with the same testing equipment and comprehensive data-tracking

system. “We were testing before, but we were not gathering the data to compare month to month, season to season, to see where our swings are,” she says.

Testing Pellet Parameters PFI set standard specifications for resi-

dential and commercial densified fuel in docu-ments published July 9, 2015. The normative fuel properties included in the specification, and mandatory for determining fuel quality grade, include fines, bulk density, diameter, length, heating value, chloride, moisture content, pellet durability index and inorganic ash content. Not all in-house laboratories can test this entire list of properties, and therefore rely on the accred-ited third-party auditing agencies and testing labs to discover the remaining unknowns. PFI-qualified facilities test internally and send pellets out for third-party testing. “There is a verifica-tion relationship there,” says Michael Foster, di-rector of quality assurance with Somerset Pellet Fuel’s 55,000-ton-capacity plant in Kentucky. “On a daily basis, we’re running the myriad of quality tests in our laboratory, but on a monthly basis, somebody from Timber Products Inspec-tion will visit our plant unannounced. They’ll do a documentation inspection of our quality processes and then they will take a sample of pellets with them.” Foster adds that plant staff will pull a counterpart to those sample bags at the same time on the production line and re-tain it at Somerset, so when the lab results from TPI come back, they can test the bag made on the same day to see if they can replicate those results.

Certain tests are outside the realm of in-house capabilities, mostly because of the equip-ment expense, so a shortened testing list of largely mechanical pellet properties is what’s required in order for PFI Standards Program fuel manufacturers to qualify for and maintain reduced audit sample testing frequencies. These production facilities must have in-house labs ca-

PELLET¦

It depends on a number of critical factors.

How explosible is the material you are processing? Are your process vessels indoors? How are the upstream and downstream processes configured? What ignition sources could be present? Our engineers start by understanding your process, reviewing your DHA and testing process materials if necessary. Then we apply the right solution including a combination of suppression, isolation and venting systems.

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¦PELLETpable of testing for bulk density, fines, length, diameter, durability and moisture. These tests must be verified to provide accurate results by cross-checking with an American Lumber Standard Committee accredited lab (at least twice annually), as a quality assurance mea-sure to verify the accuracy of in-house testing equipment and methods. In addition, in-house test data must also demonstrate that the facil-ity is within compliance of the grade require-ments. According to PFI’s residential and com-mercial densified fuel quality assurance and quality control (QA/QC) handbook, samples must be collected at least twice per day or once per shift, whichever generates the larger num-ber of samples, and consist of bags of product that would typically be shipped or directly from a bulk load if bulk delivery is performed.

While PFI’s Standards Program test meth-ods are determined in accordance with ASTM test methods, for pellet manufacturers export-ing product, ENplus are based on an interna-tional standard: ISO 17225-2. Although the testing styles referenced differ, the pellet prop-erties measured are the same.

Whether a qualified ENplus or PFI pro-ducer, tests are not necessarily conducted in the same order every time, but there are ways more streamlined than others. Samples col-lected from bagged pellets usually start with a bag splitter. LJR Forest Products 150,000

ton-150,000-ton-plant located in Swainsboro, Georgia, begins with this step when testing ENplus bagged pellets. Lige Moore, plant manager, says the company decided to undergo ENplus certification to sell to that market. “If we’re testing for ENplus bagged pellets, we’ll go out and get a bag, bring it in and pour a 40-pound bag into a bag splitter, which divides the bag into two halves evenly,” Moore says. From there, those 20-pound samples can be sized down to smaller samples depending on the test.

Typically, after the sample is measured, the first thing that Smith Flooring Quality Man-ager Steve Meier measures for is bulk density. Smith Flooring’s 25,000-ton-capacity plant in Mountain View, Missouri, joined PFI’s quali-fied manufacturer list this year. He explains that weights are critical to all of their testing. Bulk density testing, for example, is purely a matter of weighing, he says, by pouring a 15-pound sample of pellets into a known volume con-tainer (one-quarter-cubic-foot) from a speci-fied distance, after which the pellets are shaken down and compacted in the container. For bulk density, PFI requires that these containers, or laboratory-grade aluminum pots that look like big cook pots, are tapped 25 times from a height of one inch.

An important measurement producers check for is fines. At Somerset, fines content

is determined using a laboratory-grade sieve with a one-eighth-inch wire screen. As outlined in PFI’s standard specifications, the sample is screened by tilting it side-to-side 10 times.

Fines are generated while testing for pellet durability. Foster says a screened and weighed sample is loaded into a two-chamber durability tester at Somerset to test pellet durability. The sample is then tumbled 50 times per minute for 10 minutes, in what he says is reminiscent of a rock tumbler. Durability is determined by rescreening and weighing the sample. In PFI’s standard specifications, the durability tester is referred to as a “dust-tight box,” which is made of a rigid material with smooth and flat sur-faces.

Pellet diameter is another of the audited parameters. Producers record pellets’ dimen-sions often using a simple set of purchased calipers capable of measuring to within 0.001 inch, according to PFI testing parameters. Pel-let length is determined by the weight of all pellets in the sample exceeding 1.5 inches in length.

Meier uses dial calipers to measure length and diameter. Lengths can sometimes become an issue, he says, depending on the pellet mill and how it’s performing. “We’re allowed up to 1 percent of over lengths, but typically, as you sift through samples you’ll find maybe four or five pellets that exceed an inch and a half in

It depends on a number of critical factors.

How explosible is the material you are processing? Are your process vessels indoors? How are the upstream and downstream processes configured? What ignition sources could be present? Our engineers start by understanding your process, reviewing your DHA and testing process materials if necessary. Then we apply the right solution including a combination of suppression, isolation and venting systems.

Why risk an industrial explosion that could threaten your workers or shut down valuable processes. Count on IEP Technologies to provide the right solution. Just like we have done successfully for hundreds of industrial companies around the world.

Let’s develop a solution for you

Call the IEP engineering experts with the most experience in explosion protection at 1-855-793-8407 or visit IEPTechnologies.com.

P R O T E C T I N G T H E W O R L D ’ S P R O C E S S E S A G A I N S T E X P L O S I O N

HOW DO YOU STOP AN INDUSTRIAL EXPLOSION IN ITS TRACKS?

length, so we weigh those and record that and relate it to the percentage of a 5-pound sample,” he says. Diameter tests are conducted by randomly selecting five pellets out of the pellet sample being evaluated. The average pellet diameter, as well as the range of all pellet diameters measured, should be calculated and re-ported.

In-house labs qualified to PFI’s program also measure moisture, and some measure ash content, although it's not a requirement under PFI’s QA/QC handbook section 6.11 specifications for in-house labs. At Somerset, Foster says, a laboratory-grade pellet grinder is used, which grinds up a 5-gram sample to check moisture content. Some equip-ment measures both moisture and ash. Indeck installed the Arizona Instru-ments Max 5000 moisture and ash test-ing instrument. Although it’s a costlier piece of equipment, Winchester says, “one of the critical things in the manu-facturing process is moisture content.” In fact, he adds, they have four moisture meters staged throughout the pelleting process, “so the operators can stay on target with the moisture content of the material coming in and out of the pellet mills.” The process moisture meters are

also verified routinely using a moisture balance, which is a scale with an infrared heater on it. A 5-gram sample can be dried on it, verifying moisture content within five minutes, according to Win-chester. At NEWP’s plants, ash content is determined by burning the pellets in a Vulcan A-550 laboratory furnace at a temperature of 1,100 degrees Fahrenheit to determine the percentage of inorganic material in the fuel, Lafreniere says.

Not only must the fuel meet certain specifications, but the equipment used to measure it must as well. Equipment like calipers, balances, scales and measuring blocks must meet certain calibration and standardization requirements. For exam-ple, producers are asked to perform an initial calibration on balances and scales using NIST or other recognized national standards, and before each test, verify the balance or scale by using at least one calibration weight that corresponds to 50 to 150 percent of the weight of the fuel sample to be measured. If the balance or scale cannot reproduce the value of the calibration weight to within 1 percent of the mass, it must be recalibrated before use. “We have a calibration program for our equipment,” Foster says. “It’s a third-party calibration program for which we

DELAYED RESULTS: Steve Meier, quality manager of the lab at Smith Flooring’s pellet mill, prepares the ash and moisture pellet test. After the sample is inserted and the lid closed, the 5-gram sample is ground up, taking 30 to 40 minutes to show results. PHOTO: SMITH FLOORING


have outside sources come in a couple times per year and recalibrate our balances, our cali-pers, and there are a few in-house verification activities we do ourselves.”

All in all, among a number of producers, the amount of hands-on time required to con-duct tests seems to average around 15 to 20 minutes, with a few tests, like moisture and ash testing, taking anywhere from 30 to 90 minutes for test results to come back.

For plants that aren’t qualified under a fu-el-grading program, bulk density, fines and bag weight are three basic measurements that can be done without necessarily accruing a high cost, according to Winchester. How much pro-ducers invest in testing equipment varies con-siderably, anywhere from a couple thousand dollars to upwards of $50,000. “You can spend more or less, it just depends on what you or-der,” Moore says. He estimates LJR invested around $5,000 for its ENplus testing lab equip-ment. Lafreniere manages the four NEWP labs and found the investment can actually result in cost savings. She says the company probably saved the first year’s costs of becom-ing qualified in PFI’s program by coming up with a process to fine-tune scales to measure bag weight.

TrainingThe big word with quality is consistency,

Winchester says. “If you run a day, a week, a month without doing any testing, there is vari-ability in manufacturing and the testing process, and one of the challenges of manufacturing is striving to reduce variability,” he says. “Bottom line is through sampling, generally what you’re doing is understanding your process better, what kind of variability you are having.”

Testing helps avoid variability in pellet quality, but controlling variance between how each lab member tests for that quality is impor-tant. “Just because you test doesn’t mean you’re always going to get good data,” Winchester says. “One of the key variables in any sample is how you sample and how you test. If you have four people doing the same test, there is a good chance there will be variation, and that’s what another one of those big challenges is to mini-mize that variation from person to person.”

Some test methods leave room for more variance than others. To combat that variability in one instance, Indeck made adjustments to how it measures bulk density, which is typically done by manually tapping down a sample-filled aluminum container 25 times from one inch. “As a guy who not only does the test but also trains, I have to make sure people are do-ing it correctly,” Winchester says. “Dropping a metal container from exactly one inch for a number of repetitions, as per bulk density protocol, is challenging for many people and

¦PELLET

IN-HOUSE EQUIPMENT: NEWP designed its own pellet length analyzer (left) and pellet durability tester (right). The pellet length analyzer works by shaking a pellet sample into six different jars based on length. Ideally, most pellets fall between three-quarters of an inch and an inch at the max, Lafreniere says.PHOTO: NEW ENGLAND WOOD PELLET


some have a tendency to want to slam it down because it’s hard to let something go and drop repeatedly from one-inch high exactly every time.” Now, having collaboration with in-house maintenance personnel, this process has been automated where the container moves up and down hands free.

As for who’s conducting the tests, the ma-jority of plant employees are trained to conduct lab tests. At Indeck, the staff members who re-ceive chips and sawdust do feedstock sampling and testing, shift supervisors running the mills sample out of the pellet cooler every few hours and run tests, and package line operators are also responsible for doing sampling and testing. “Pretty much our whole staff is trained because we switch around sometimes,” Winchester ex-plains.

Meier at Smith Flooring’s new lab recently received training from Chris Wiberg with Tim-ber Products Inspection, a third-party accred-ited auditing agency and testing lab. “I turned around and trained people, and just about ev-eryone is capable of running the tests on an as-needed basis, but typically I do the days and another employee does the evenings,” he says.

TPI also trained staff at NEWP, and Lafreniere says it’s the company’s goal to train all operators to do the testing. “Typically, the plant managers are trained, and then they train their team leaders,” she says, adding that every shift has a team leader who in turn trains other employees. There is an annual refresher training course for all employees involved in lab testing.

Besides serving as an auditing agency under PFI’s Standards Program, TPI certifies ENplus manufacturers. “When ENplus mill operators are hired, it’s about a month-long training of learning the mill operation, day-to-day procedures for running the mill, and dur-ing that time we teach them the procedure for the ENplus testing,” Moore says. He adds that training is fairly complex, but once the process of the mill is understood and the testing proce-dures outlined in the ENplus handbook, “it’s fairly simple.”

Charting TrendsRecorded lab results bring value to the

plant over time, by tracking trends and provid-ing data for monthly audits, under the PFI Stan-dards Program. Even though Smith Flooring has been in production for less than two years and PFI-qualified for only a matter of months, Meier says he keeps a trending log of every test performed to track daily changes, and whether any mill adjustments are needed.

At Somerset, dashboard-driven Excel da-tabases are set up. Foster says all of the inputs and outputs of an audit are entered, results from the various pellet properties will be calcu-lated, and a numerical result will appear on the

screen, flashing green for good or red for bad. The entry is automatically recorded into the da-tabase, and both a written and electronic copy are kept. Another component of the dash-board Foster mentions is the help button. “You can click the help button, then the name of the test, and it will pull up all of the parameters of the tests on the screen,” Foster says.

According to Lafreniere, monthly results from all four of NEWP’s facilities are gathered in testing logs which are then linked to quality charts, and the results are distributed through-out the company on a monthly basis. “We can see, for instance, the ash results as a monthly average for each one of our facilities compared to the other,” she says.

Besides monthly reports, Lafreniere holds monthly quality meetings where the staff iden-tifies any process changes that need to be made. Of the company’s data-gathering procedures, she says, “Ours is a no-brainer. You can imme-diately see a change in any of the plant’s trends because it’s right there on the chart.”

As more producers move toward qualify-ing their product under a fuel-grade program, it becomes clear that having the equipment to test a pellet at the site of its production helps ensure consistent quality, consumer confidence and overall better plant performance.

Author: Katie FletcherAssociate Editor, Biomass Magazine

PELLET¦

LARGEST BIOMASS CONFERENCE IN THE WORLD

ThermalNews

A recent report on Vermont’s clean en-ergy industry has determined the state has the highest number of per-capita clean energy jobs in the nation. The wood energy industry is among the clean energy industry segments addressed in the report.

The analysis determined wood energy firms employ 1,542 full-time-equivalent work-

ers across their component subsectors of log-ging, wood fuels, including chips, pellets and firewood, combustion systems and power sta-tions. These businesses are mostly small, with 84 percent reporting only five or fewer perma-nent employees.

Chip and pellet firms were found to em-ploy more workers per firm and attribute more

revenue to wood energy activities when com-pared to the overall wood energy average. Only 64 percent of these employers reported five or fewer permanent employees, with 58 percent reporting that all of their revenue is attributable to wood energy.

Vermont report features wood energy employment data

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SCHADE Lagertechnik GmbH Bruchstraße 1 45883 Gelsenkirchen Germany [email protected] www.schade-lagertechnik.com

REN21 recently published its annual overview on the state of renewable energy, reporting 2015 was a record year for renew-able energy installations and renewable en-ergy investments.

According to the report, titled the “Re-newables 2016 Global Status Report,” bio-energy contributes more to primary global energy supply than any other renewable en-ergy source. Total energy demand supplied from biomass last year was approximately 60 exajoules (EJ). The report also notes that the use of biomass for energy has been

growing at approximately 2 per-cent per year since 2010, but that the bioenergy share in total glob-al primary energy consumption has remained relatively steady since 2010, at approximately 10 percent.

Modern bioenergy applica-tions provide approximately 14.4 EJ of heat last year, with 8.4 EJ of that output for industrial uses and 6.3 EJ for residential and commercial uses. The report states modern biomass heat capacity

increased by an estimated 10 gigawatts ther-mal (GWth) in 2015, reaching 315 GWth.

REN21 shows growth in biomass power, heat Shares of biomass sources in 2015 global heat, electricity generation

Biomass heat generation

Biomass electricity generation

Solid biomass 77% 71%MSW* 18% 8%Biogas 4% 20%Biofuels 1% 1%* MSW INCLUDES THE RENEWABLE PORTION ONLY SOURCE: REN21


We buy boilers to provide water consistently at a specifi ed temperature. That’s their core function. Sound simple? If this function is so important, why not measure how well biomass boiler plants accomplish this fundamental task?

DCM Logic has developed a simple and straightforward way of doing this: Compute the percentage of heating time that a biomass plant produces water greater than the set point minus 2.5 degrees Celcius. (If the plant generates steam, use pounds per square inch (psi) greater than or equal to set point minus 1 psi instead.) Add in the times when the biomass plant can’t make this temperature (or pressure) goal, but all biomass boilers are working at greater than 95 percent modulation. (Undersizing is a rational design decision, and there’s no need to penalize it.)

We call this Boiler Plant Effectiveness, or BPE. Expressed mathematically, that’s BPE equals percent of heating time when water produced by the biomass boiler plant is equal to or greater than the set point minus 2.5 degrees C, or modulation of all biomass boilers greater than 95 percent. For “water pro-duced by boiler plant,” use the storage tank top temperature. If you don’t have a tank, use the water temperature exiting the biomass boiler plant, before any mixing is done.

This formula isn’t proprietary to DCM Logic—one can try this at home, or in the offi ce, or at a nearby boiler plant.

One can calculate it on his or her own with just a spreadsheet. For longer periods of time, one may want to enlist the help of a controls contractor or boiler manufacturer. DCM Logic can help as well. It’s the only way to really know and quantify how well a biomass boiler plant is doing its primary job.

You may wonder how BPE relates to effi ciency and emis-sions. It doesn’t. A higher-performing boiler plant will gen-erally use MORE fuel than a lower-performing boiler plant. Effi ciency is nice, though focusing on it exclusively is a bit like asking which participant in an athletic competition burned the fewest calories. Times or scores in the event are far more im-portant, as they are the performance measure that separates the competitors.

Clean, green, local, and cheap (sometimes!) are just dan-dy, but they’re not enough to take biomass heat from niche to mainstream. We also need to keep score, and let the world know how well biomass heat works.

Author: David SpindlerChief Operating Offi cer, DCM Logic

[email protected]

Keeping Score

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BY DAVID SPINDLER


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The latest data from Eurostat indi-cates that the European Union is on track to meet its renewable en-ergy target of 20 percent by 2020.

In 2014, with six years left to reach that goal, 16 percent of the region’s energy was derived from renewable sources. The Baltic Rim countries have been some of the most successful, with Sweden (49 percent), Fin-land (38 percent), Estonia (25 percent) and

Lithuania (23 percent) already exceeding their shares. Denmark (30 percent), Latvia (40 percent), Poland (15 percent) and Ger-many (18 percent) are on trajectory to meet their targets, though they have yet to do so.

DemandOne of the many components of these

countries’ plans to successfully meet 2020 targets is a commitment to district heating

(DH) and combined-heat-and-power (CHP) projects. Though these countries either have already met or are quickly approaching their targets, they continue to invest in small-scale DH and large-scale CHP projects.

Denmark is a good example of this. Just 0.8 percent shy of its target, the coun-try is slated to get two new CHP plants be-tween now and 2019. Dong Energy plans to open a 280-MW CHP plant in Fredericia in

Baltic Rim Wood Fiber Supply and Demand

CONTRIBUTION: The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of Biomass Magazine or its advertisers. All questions pertaining to this article should be directed to the author(s).

Chip quality market data will enable Baltic States to further capitalize on the energy chip export industry as it expands. BY TRACY LESLIE

This pine logging residue at a Latvian forest site is destined for domestic energy chips.

PHOTO: FOREST2MARKET


2017, a facility that will be fueled primarily by wood chips and use an estimated 700,000 metric tons annually, and near Copenhagen, Hofor plans to open a 500-MW CHP facil-ity that is expected to consume 1.2 million metric tons of wood chips annually.

Denmark is not the only Baltic Rim country ramping up its biomass CHP capac-ity. Also coming online in 2019 is a newly announced, 150-MW facility in Lahti, Fin-land. So where will the fiber supply come from to meet this new demand? Among the most likely suppliers will be the Baltic States. With modern and well-developed forest products industries (sawmills, panel mills and pellet mills); effective and efficient harvesting, processing (chipping) and trans-portation infrastructure; an excess supply of biomass (annual harvests equal approxi-mately 70 percent of net annual growth in the region’s forests); and a history of strong export partnerships, the Baltic States are poised to take advantage of these market opportunities.

Baltic States Wood Fiber SupplyAccording to the United Nations Eco-

nomic Commission for Europe, approxi-mately 30 million cubic meters of timber are harvested annually in Latvia, Estonia and Lithuania. Approximately 50 percent of the annual harvest is in the form of saw and veneer logs and 26 percent is pulpwood, a product that has very limited capacity for consumption in the immediate region. Oth-er roundwood makes up 4 percent of the annual harvest, and wood fuel makes up an-other 20 percent.

Wood Chip ClassificationsWood chip classifications in the Baltic

States can be fluid; they can vary based on source, quality and market conditions and destination. In Latvia, for instance, chip producers supply pulp quality conifer and hardwood chips to pulp and paper facilities in both domestic and export markets. In ad-dition, they produce technology and energy chips for domestic and export markets that are sometimes interchangeable and some-times not, depending upon their destination. These include:

• Forest residue-quality domestic ener-gy chips: Domestic energy chips are gener-ated from forest residues, chipped in woods post-harvest and used to fuel DH and CHP plants.

• Forest residue-quality export energy chips: Excess supply of forest residue qual-ity energy chips are exported to Finland and Sweden.

• Domestic technology chips: In Latvia, hundreds of small sawmills do not have de-barking capacity. Bark remains on slabs after logs are canted, and this material is stored on site awaiting chipping. Chip producers then send mobile chippers to these mills to create technology chips that are delivered domestically to medium-density fiberboard or wood pellet mills, a growing business in the region.

• Danish-quality export energy chips: Excess supply of technology chips are ex-ported. Denmark sources this higher-quality energy chip from Latvia because it has a lower ash content than forest residue energy chips.

Challenges RemainWhile the Baltic States have much of

what they need to capitalize on the export energy chip trade as it expands, perhaps the

single most important missing ingredient to aid this expansion is the kind of market transparency that high-quality market pric-ing information brings.

With these eight categories of wood chips, all produced from different raw ma-terial with varying chipping and transporta-tion costs, pricing will challenge suppliers who are trying to maximize their revenues, as well as consumers who are trying to keep their wood costs low. As export opportu-nities for this underutilized material from the Baltic States grows over the rest of this decade, the addition of high-quality market data will create the kind of transparency that will allow for more orderly sales and purchases of this material, and support the types of long-term supply agreements that will stabilize the market for long-term ben-efits for the industry as a whole.

Contact: Tracy LeslieDirector, Forest Biomaterials and Sustainability,

[email protected]

www.forest2market.comxx

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Designing a pyrolyzer furnace is an in-tricate process. There’s more to the design than making a carbon steel box, lining the walls with refractory,

running some process pipes through it, and heating the pipes with burners. While this may describe the design steps in vague detail, it doesn’t capture the intricacies involved in pyro-lyzer furnace design. Knowing what to consid-er and evaluate can be the difference between success and failure.

Key pyrolysis system design consider-ations include feedstock composition, pyroly-sis heat of reaction and reaction kinetics, heat transfer required to achieve kinetics, system de-

sign to provide heat transfer, and pilot testing and scale-up.

Feedstock CompositionThe feedstock’s moisture content (MC)

and composition drive the pyrolyzer design because it determines the pyrolyzer’s required heat. MC is easily determined by taking a loss on drying (LOD) measurement. In stark con-trast, many of the methods used to determine a feedstock’s composition are lab-intensive and expensive, but obtaining the composition is es-sential to the design.

At a minimum, Merrick & Co. performs an ultimate and proximate analysis of feedstock samples. As an alternative, data for common

feedstocks is available from public sources, such as the National Renewable Energy Labo-ratory in Golden, Colorado. Merrick frequently performs a feedstock characterization using data from sources such as NREL as a first approximation, to get projects rolling quickly. Actual feedstock analysis then confirms the use of this data as the projects progress.

Characterizing a feedstock’s composition helps predict the decomposition behavior. Dif-ferent feedstocks require different tempera-tures and amounts of heat for decomposition. If you design the pyrolyzer for the incorrect feedstock composition, it will not function Ef-ficiently. Worse yet, it may not work at all.

The Intricacies of Pyrolyzer Furnace Design Design considerations can make the difference in bringing a pyrolyzer technology to market versus burying it in the pyrolysis graveyard. BY BRADLEY WAITES, PAMELA BUZZETTA AND CRYSTAL BLEECHER

PHOTO: MERRICK & CO.

CONTRIBUTION: The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of Biomass Magazine or its advertisers. All questions pertaining to this article should be directed to the author(s).


Pyrolysis Heat of Reaction, Reaction Kinetics

The pyrolysis heat of reaction is the amount of heat necessary to decompose and vaporize volatile matter in the feedstock. It is important to note that it does not account for the required heat to raise the feedstock tem-perature to the pyrolysis temperature, i.e., the sensible heat.

Multiple chemical reactions take place during pyrolysis. Some are exothermic while others are endothermic, and these reactions vary depending on the feedstock. Because of this complexity, published values for the py-rolysis heat of reaction vary greatly for feed-stocks. Verifying published values through experimental testing is critical to ensuring the capability of the pyrolyzer. A pyrolyzer should never be designed solely on published pyroly-sis heat of reaction values.

Knowing the feedstock composition and the decomposition behavior of each compo-nent allows modelling of the overall decom-position behavior. The percent conversion of each component is temperature dependent. By understanding the reaction kinetics, the re-quired exit char temperature and the residence time can be determined. Pyrolysis modeling software uses reaction parameters such as those summarized by Miller & Bellan to cal-culate product yields as a function of tempera-ture.

Heat Transfer Design, AnalysisOnce the pyrolysis reaction is under-

stood, the next step is to design a heat transfer system that can achieve it. The thermochemi-cal decomposition of pyrolysis takes place in the absence of oxygen which requires indirect heating of the feedstock.

Burners fire into the furnace box releas-ing flue gas, which acts as a heating medium. Heat transfer within the furnace box is a com-plex combination of conduction, convection and radiation. Some designs utilize radiant wall burners that heat the refractory on the walls of the furnace which then radiate heat to the pyrolysis chamber. Other designs convectively heat the pyrolysis chamber by blowing flue gas across the pyrolysis chamber walls.

Regardless of the heating technique employed, the heat transfer model must ac-curately account for all of the heat transfer mechanisms in the design of the furnace. Modelling the furnace’s heat transfer design by hand involves complicated and laborious hand calculations. Fortunately, Computational Fluid Dynamics software exists, which greatly increases the power and sophistication of heat transfer modeling. The software also provides

visuals of thermal dithers, which helps identify hot and cold spots.

Without sophisticated modeling, pyroly-sis system design is often guesswork, or trial and error. CFD software helps remove the guesswork from the design.

Regardless of how the pyrolysis cham-ber is heated on the outside, its walls heat the biomass through conduction from the bot-tom, and radiation from the top. Further, gas-ses released during the pyrolysis reaction also heat the biomass through convection. Under-standing the nature of this heat transfer and how to achieve it presents even more complex challenges. CFD software once again helps al-leviate these challenges by accurately modeling designs to ensure they provide the necessary heat transfer to achieve pyrolysis reactions.

System Design ConsiderationsAfter completing process and heat trans-

fer designs, the design team must make sev-

eral pivotal decisions regarding materials, pipe supports and thermal expansion, material feed and internal transport systems, and finally maintainability.

Materials: Selection of materials is one of the most important aspects of pyrolyzer design. They must be able to operate at tem-peratures well into their creep zone and still maintain ductility. In addition, they must be able to endure thermal cycling caused by fre-quent shutdowns and startups. They may also have to resist carburization, chloride stress cor-rosion cracking, or sulfide stress cracking, or even all three. Typically, materials for compo-nents inside the furnace box are high-temper-ature stainless steels such as 304 H or 310, or high-nickel alloys.

To navigate strenuous requirements, as-sistance of a knowledgeable metallurgist is invaluable, especially since materials that can withstand these strenuous operating condi-tions tend to be very expensive. Blindly select-

Do’s and Don’ts of Pyrolyzer Design

Do:• Determine the composition of your feedstock. If you design for the wrong material, your pyrolyzer may not function correctly.• Determine if purging the process of oxygen or just limiting air ingress is appropriate for your design and select valves accordingly. Keep in mind that a vacuum pump may be required.• Model the heat transfer all the way into your feedstock. Even though the heat enters the pyrolysis chamber, it may not make it into the biomass and achieve the required conversion.• Determine the residence time of your feedstock in the furnace. This avoids undercooking or overcooking the biomass.• Select your burners before applying for permits for emissions. Solving this problem after realizing burners with sufficiently low emissions do not exist causes unnecessary headaches and delays.• Perform a pipe stress analysis to allow for thermal growth and design pipe supports. Guesswork causes failures in expensive materials, and equipment, and lengthy delays.• Account for gas treatment. The backend of the process causes the most plugging failures.• Finally, properly designing and testing material-handling equipment is es-sential to continuous plant operation. There is nothing worse than a plant lying idle because of failures moving the feedstock.

Don’t:• Go straight from benchtop to production. Benchtop systems rely heavily on conduction while radiation and convection predominate in production units. Develop models and follow the design process to successfully scale-up.• Underestimate the feed system. Moving biomass is challenging and it doesn’t matter how amazing your furnace is if it can’t get the feedstock.


At this time, more litter is being produced than the industry is able to utilize e ectively. Currently, the primary use of poultry litter in the US is as fertilizer for pasture, hay, small grains, and corn‐producing � elds.Hurst is currently installing and manufacturing several invest-ment projects where Co-generation of steam and eletricity is being applied. � e bulk of the steam energy will be suppling

turbine driven generators producing electricity and sold on the local grid. � e excess steam will be directed to any plant

processing or contract leased to nearby outside facilities.

� e utilization of litter as a boiler fuel o ers many potential bene� ts on

investment and returns that can be shared economically with the local

community and poultry farmers alike.

55,000 tons of turkey litter a year to produce the equivalent of 95 million

kilowatt hours of electricity

ing materials can wind up costing millions and setting a project back months, if not years.

Pipe Supports and Thermal Growth: Another important design consideration is pipe supports. Pipe supports that allow for thermal expansion and contraction are criti-cal to avoiding piping failures. The supports require expert design, as portions may be in-side and outside the furnace box. Due to the intense heat, the supports inside the box are typically 304 H or 310 stainless steel. Com-plicating the problem further is the fact that the pipes experience thermal growth in all directions. Fixing one end of the pipes while allowing the other to move during thermal cy-

cling often solves this problem. Rollers or slide plates, as well as constant effort supports, are usually required. Accounting for these items in a cost estimate is crucial, as they, too, are rather expensive.

If a portion of the horizontal process pipes protrudes outside the furnace box and the pyrolyzer has multiple runs, the furnace box will need sliding panels to allow for their thermal growth. These panels must seal the furnace while allowing the pipes to move in the longitudinal and vertical directions. This is also true for vertical process pipes that pro-trude outside the furnace box. They require sliding plates that allow them to grow in the

vertical direction and translate in the longitu-dinal direction.

Material Feed and Internal Trans-port Systems: An important design consid-eration, and one frequently not given enough attention, is the biomass feed system. It usually involves conveyors, bucket elevators, hoppers, and lock hoppers. In our experience, many py-rolyzer designs do not place enough attention or expertise towards the feedstock handling system, despite the fact that they are frequently the primary causes of pyrolysis system failures.

Deciding to purge the process of oxygen versus just limiting the ingress of air is another vital consideration in the decision process. To limit the amount of air (oxygen) entering the system, numerous types of valves are available. These include valves such as knife gates, or ro-tary, and each type has its benefits as well as its drawbacks.

If purging oxygen is the answer, the sys-tem likely requires pulling a vacuum. However, utilizing a vacuum greatly limits the valve op-tions. Careful consultation with valve suppliers is a must to weigh the tradeoffs. Considering cost is important because valve prices vary greatly depending on the type.

A basic design decision for the pyrolyzer will be how to move the biomass inside the furnace. Using the word “basic” here is mis-leading because whether using a drag conveyor, an auger screw, or some other method, plenty of challenges lie ahead. The component must endure high heat and extremely dirty condi-tions, which makes using bearings a problem. In addition, accounting for thermal growth is essential. And most importantly, the moving device must allow for heating of the biomass.

Maintainability: Virtually all pyrolyzer designs require external platforms for main-tenance. While these are not difficult to de-sign compared to the pyrolyzer itself, they can still easily cost $300,000, if the pyrolyzer has multiple levels. The platforms are essential for the maintenance of drive units, burners, pipe supports, and other pieces of essential equip-ment. Running a plant on a daily basis is next to impossible without provisions to service the equipment.

Gas Treatment: Careful design consid-erations should go into handling the vapor ex-iting the pyrolysis chamber. These hot vapors likely contain heavy hydrocarbons that readily condense and form heavy oils and tars upon contact with any cooler surfaces (e.g. discharge piping, valves, filtration equipment). To make matters worse, the vapors also carry over char particulates, which compound the risk of bridging and plugging. The management of heavy oils, tars and char particulates is a pri-

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mary failure point in pyrolysis and gasification systems. The challenge is removing the char particulates before they make it downstream and prevent the heavy oils and tars from con-densing out.

Most pyrolyzer system designs remove char particulates from pyrolysis vapors at the exit of the pyrolysis chamber. They utilize gravity settling, centrifugal separation (e.g. cy-clone separator), or filtration, or a combina-tion of these. Removing particulates maintains product quality, helps prevent downstream plugging, and may reduce waste water treat-ment costs in some designs. However, pre-venting condensation becomes critical to avoid filter plugging by the heavy oils and tars. In fact, piping oftentimes has electrical heat trac-ing all the way from the pyrolyzer exit, through the cyclone, and up to the quench equipment.

Candle or baghouse-type filters are diffi-cult to implement successfully. Ceramic mesh-es can withstand the process temperatures, but these filter types require additional design features to extend their operational life. Most designs require back-pulsing the filter media to dislodge the char cake. In addition, maintain-ing elevated temperatures and preventing con-densation is essential. Common techniques are injecting hot flue gases and minimally firing the filters.

In general, avoiding bends and fittings in discharge piping and locating filtration equip-ment directly at the pyrolysis chamber outlet(s) reduces opportunities for condensation and char particulate carryover. Also, investigating designs that utilize the hot flue gasses exiting the pyrolyzer furnace to heat the discharge piping and filtration equipment can be an eco-nomical way to prevent condensation.

Pilot-Testing, Scale-UpMaintaining critical design characteristics

during scale-up of equipment allows accurate prediction of process parameters based on data collected during pilot testing. Understand-ing the heat transfer characteristics from the pilot-scale through full-scale in the pyrolyzer is essential. Services exist to model the expected heat transfer, which provides a basis for pilot plant equipment design. During piloting, data collection should verify the estimated heat transfer data for use in designing the commer-cial scale equipment.

Understanding and evaluating changes in the surface area to volume ratios from the pilot-scale to commercial-scale pyrolysis chamber is critical to successful operation. Smaller-sized pilot units typically rely more on conduction, while larger, commercial-scale units utilize more radiation and convection to transfer heat

into the biomass. Failure to comprehend and quantify these scale-up parameters results in insufficient heating at commercial scale.

Another area of concern during scale-up is material handling. Overlooking material han-dling equipment is common during piloting, but can create unforeseen operational issues at commercial scales. For example, shoveling bio-mass to the pyrolyzer inlet on the pilot plant may obscure the need for a rotary valve or live bottom feeder that evenly feeds the biomass and reduces air ingress at commercial scale. As previously discussed, failure to place an em-phasis on material handling can lead to huge delays and costly overruns.

With all of the above in mind, there are many steps in designing pyrolyzer furnaces. Taking the time to plan and properly execute these steps directly determines the level of success your technology will achieve. A typi-cal complete fabrication drawing package has around 250 to 300 sheets and can take any-where from 4 months to 1 year to design the furnace and start fabrication. Failure to recog-nize this on the front end can lead to issues with budgets and investors later on down the line.

Authors: Bradley Waites, Pamela Buzzetta, and Crystal Bleecher

Merrick & Co.www.merrick.com

303-751-0741

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BiogasNews

Seattle-based Impact Bioenergy, a small startup focused on distributed energy with its portable, prefabricated anaerobic digestion (AD) technology, deployed its first microdigester at the Fremont Brewery Co. in Seattle this spring.

The company manufactures and sells bioenergy systems that convert organic waste materials into renewable natural gas and fertilizer with zero waste. Impact Bio-energy has two systems: The Horse 25 se-ries, with the capacity to divert 135 pounds of waste per day from waste generators, and the Nautilus 185 series, with the capac-

ity to process 1,000 to 5,000 pounds per day. The Horse system was deployed at the brewery.

The process begins with the collec-tion of food waste, edible liquids, or fats, oils and grease in an oversized sink for in-spection and pregrinding. The system has a blending and feeding system that runs au-tomatically. The operator is only required to monitor temperature, mixing, liquid lev-el, pressure, gas storage and battery status when feeding the system.

Ontario’s government plans to spend up to $100 million over the next four years to foster growth of renewable natural gas (RNG) in the province.

The Ontario Ministry of Environment and Climate Change announced in May that the funds will be drawn from cap and trade proceeds via the province’s Climate Change Action Plan. The province’s emission re-duction targets begin at a reduction of 15

percent of 1990 levels by 2020, increasing to a reduction of 80 percent by 2050.

Coinciding with the funding announce-ment, the Canadian Gas Association out-lined new targets for country’s natural gas sector, which are 5 percent RNG-blended natural gas in the pipeline distribution sys-tem by 2025, and 10 percent by 2030, equat-ing to removing 3 million passenger cars from the road.

Microdigester launched at Seattle brewery

Ontario to fund RNG development

POWERING UP: A Chevrolet Volt plug-in electric vehicle receives an electrical recharge from Impact Bioenergy’s digester. PHOTO: IMPACT BIOENERGY

Your Partner in Productivity

Driving vehicles that run on natural gas reduces emissions and allows us to breathe cleaner air. But what many don’t real-ize is that this is rapidly becoming truer through the increasing use of renewable natural gas in North America’s natural gas vehicle (NGV) infrastructure.

Renewable natural gas (RNG) is derived from the meth-ane that emits from organic waste as it decomposes. This methane is captured at agricultural facilities, landfi lls, waste-water treatment plants, and separated municipal solid waste digesters, and then cleaned in a treatment process to produce a product indistinguishable from natural gas. The resulting biomethane, or RNG, is then either injected into natural gas pipelines, compressed or liquefi ed to be used as transportation fuel in the form of renewable compressed natural gas (CNG) or renewable liquefi ed natural gas (LNG).

As CNG and LNG from renewable feedstocks are blend-ed together with natural gas transportation fuel from geologic sources, our nation’s transportation system becomes drastically cleaner. Switching vehicles to run on geologic-sourced CNG and LNG already reduces emissions. Natural gas provides 90 percent lower NOx emissions with new Near-Zero engines, and a 99 percent SOx reduction, compared to diesel.

Blending in RNG reduces fuel emissions even further. Driving a vehicle with 100 percent RNG can reduce green-house gas emissions (GHG) by more than 80 percent. RNG from some sources are carbon negative, meaning that they se-quester GHG during the fuel life cycle.

Figures released in April by the California Air Resources Board show that, as of the end of 2015, half of the natural gas being used to fuel vehicles in the state is RNG. Only three years ago, in 2013, RNG’s share of California NGV fuel was just 10 percent.

RNG’s growth in California evidences the effectiveness of California’s Low Carbon Fuel Standard in driving growth in emission-reducing, clean fuels.

The extent of RNG used nationally to fuel NGVs is less certain than in California. U.S EIA sources indicate that be-tween 15 and 35 percent of natural gas transportation fuel consumed in the U.S. is RNG. However, evidence shows that use of RNG as a cellulosic transportation fuel is growing at an unprecedented rate, thanks in part to the renewable fuel standard (RFS).

In 2013, prior to the RFS pathway approval of renewable CNG and LNG as eligible cellulosic biofuels, the RNG in-

dustry produced just 25.9 million estimated gallon equivalents (EGE) of transportation fuel. By the end of 2015, that volume had grown fi ve-fold to nearly 140 million gallons, making up 98 percent of the cellulosic biofuel produced under the pro-gram.

Current and future production rates look even stron-ger. RNG producers are on track to reach 230 million EGE in 2016, and surpass the U.S. EPA’s draft rule renewable vol-ume obligation (RVO) of 312 million EGE for 2017. The Coalition for Renewable Natural Gas, which advocates for the North American RNG industry, forecasts production of over 350 million gallons of RNG in 2017 and over 450 million gal-lons in 2018.

RNG adoption is naturally linked with the increasing de-ployment of NGVs, many of which are high horsepower vehi-cles. Over 25 percent of transit buses in the U.S. today operate on natural gas, including those serving nearly 40 major air-ports. Over 60 percent of new refuse truck orders are NVGs.

Fleet conversion costs to RNG stack up favorably with other renewable engine technologies. A report produced for LA Metro by M.J Bradley & Associates and Ramboll and En-viron in early July determined that bus fl eet costs are more af-fordable with a new low-NOx engine plus RNG fuel combina-tion (1 percent annual cost increase) than either an all-electric (8 to 14 percent increase) or fuel cell (9 to 13 percent) bus fl eet.

Together, RNG and natural gas vehicles are an affordable and proven long-term solution to reducing air pollution and carbon emissions. It is critical that companies, states, munici-palities, and citizens across North America collectively contin-ue to embrace ultra-clean, domestically produced and available fuels like RNG. If we do, the air we breathe will be cleaner. Public health will improve. We’ll combat climate change, sta-bilize fuel price volatility, reduce dependence on foreign oil, and curb unsustainable waste practices. Sustainability is the fu-ture of fuels. When NGVs are fueled on RNG, we ensure that waste isn’t wasted, but instead is used as resource that moves us down the road toward a sustainable future.

Author: Marcus Gillette Director of Public and Government Affairs,

Coalition for Renewable Natural Gas916.588.3033

[email protected]

Driving Growth in Driving GreenBY MARCUS GILLETTE

BIOGAS¦


¦BIOGAS

Regs and BaconNorth Carolina’s renewable energy mandate is advantageous to pork producers, if conditions are right.BY ANNA SIMET

DEPARTMENT

At one time not too long ago, North Carolina was populated with more pigs than people. While that’s no longer true, the

state trails only Iowa among pork-producing states, and the industry employs roughly 46,000 North Carolinians, provides $3 billion in annual income and $7 billion in annual sales, and its 2,100 farms—80 percent of which are family-owned—are home to 8.8 million hogs,

living on farms that range from 250 to 50,000 head.

For the past two decades, the industry has been increasingly regulated, as a way to manage hog waste and improve and preserve environmental quality. In 1997, a moratorium was placed on the expansion of existing hog farms and the development of new ones. Fast-forward 10 years later, and the morato-rium became permanent, with a provision that

new permits could be issued only to farms that meet five environmental performance standards: Elimination of discharge of ani-mal waste to surface waters and groundwater through direct discharge, seepage or runoff, as well as substantial elimination of atmospheric emissions of ammonia, emissions of odor de-tectable beyond the boundaries of the parcel or tract of land on which the farm is located, the release of disease-transmitting vectors and


BIOGAS¦

airborne pathogens, and of nutrient and heavy metal contamination of soil or groundwater.

That same year, state legislators passed a renewable portfolio standard (RPS), which re-quires investor owned utilities to produce 12.5 percent of retail electricity sales from eligible renewable resources by 2022, and municipal utilities and electrical cooperatives have a target of 10 percent by 2018. Relatively small goals compared to many other states that have re-newable energy mandates, but a landmark bill nonetheless, as it is the only state in the South-east that has made law a mandatory RPS.

While the list of renewable energy sourc-es a utility can derive its mandated power from is broad, the RPS has a specific carve-out for swine-based electricity—0.2 percent by 2019, or 284,000 megawatt hours—as well as one for poultry waste, provisions that apply to the state as a whole rather than each individual util-ity, each of which is responsible for meeting a portion of that requirement.

Coupled together, the environmental quality standards and renewable energy goals make a strong case to site renewable energy projects at hog farms.

Meeting Goals“The process of creating electricity usu-

ally meets four of five of the environmental performance standards,” says Angie Maier, spokeswoman for the North Carolina Pork Council. “It creates a situation in which a farmer, if the conditions are right, is able to utilize the renewable energy law to put a sys-tem in.”

The first project to take advantage was at Lord Ray Farm, a team effort of Duke Uni-versity, Duke Energy and Google, that uses waste from over 8,600 hogs and produces 600 megawatt-hours (MWh) per year, beginning in 2011. After that, five more projects were built, ranging in size from 7,550 hogs to a ten-farm, 74,000-hog project, or from 200 MWh to 10,200 MWh per year, respectively. Most have been built on existing farms looking to seize the opportunity of renewable energy credits (RECs) and environmental benefits. “One farm has been permitted for expansion, and will have a renewable energy system,” Maier says, adding that the current projects range in sophistication and utilize a mix of covered la-goons and tank digesters. All produce electric-ity on the backend to earn RECs. “Recent ones have utilized a state renewable energy invest-ment tax credit, a federal tax credit and RECs,”

Maier says. Matters of whether or not a farm can get projects to pencil out usually isn’t an issue when a developer has the experience and understands all of the moving parts, according to Maier. “Hopefully, the RECS are enough to cover the cost, but ultimately, the utilities have these mandates and they have cost-recovery mechanics on the electric bills that custom-ers get,” she says. “Technically, the process should be working.” Those charges typically range from 40 to 80 cents per customer bill per month.

Like many other states, there have been legislative attempts to freeze or dismantle the state’s RPS—the most recent of which was last fall—but the program creates an interest-ing dynamic in a red state where most legis-lators are opposed to wind, solar or other types of renewable energy, Maier points out. “We have found that they likely feel different about renewable energy created from swine or poultry waste, because agriculture is North Carolina’s number one industry,” she says. “We have a little bit of leverage there. Progess has been slow, but it’s progress nonetheless. We just need some more time to get projects off the ground.”

Maier says the NCPC is aware of seven additional projects in various stages, one of which is stuck in the interconnection phase. “We recently had a bill in committee to move all swine and poultry projects to the front of the interconnection cue for study and connec-tion,” she says. “We want to get these projects connected and on their way, especially since there is a mandate for the utilities. They’re not meeting it [the RPS], so we need to make sure these projects get priority.”

Duke Energy is one of the prominent utilities in the state working to achieve compli-ance, and it recently announced involvement in several different swine-based initiatives. One is with Carbon Cycle Energy and will be lo-cated in Duplin, North Carolina. The project is massive—it will process waste from 10 to 20 farms, according to Jess Kutrumbos, direc-tor of communications. Under a 15-year term, Carbon Cycle is expected to produce more than 1 billion cubic meters of pipeline-quality methane a year, allowing Duke to yield about 125,000 MWh of renewable energy annually, enough to power about 10,000 homes for a year. Renewable natural gas produced at the facility will be cleaned, upgraded and injected into the pipeline and ultimately used to gener-ate electricity of four of Duke Energy’s power

plants, all of which are currently retired sta-tions that previously ran on fossil fuels. They include the Buck Steam Station in Rowan County; Dan River Steam Station in Rocking-ham County; H.F. Lee Station Combined Cy-cle Plant in Wayne County; and Sutton Com-bined Cycle Plant in New Hanover County.

For Carbon Cycle Energy, North Caro-lina’s RPS was a key driving force in launching the project. “It was definitely influential in our site-selection process,” Kutrumbos says. “We strategically chooses project locations at the convergence of supply of organic waste feed-stocks and access to natural gas pipelines, so those were additional contributing factors for this particular site selection.”

Design and permitting are underway, and early-phase site preparation is set to begin in the last quarter of the year, with heavy con-struction beginning in early 2017 and startup toward the end of that year.

Duke Energy also recently announced it has finalized a second deal in 2016 to buy cap-tured methane gas derived from swine waste. The planned project in Kenansville, North Carolina, will be built at the heart of Smithfield Food’s pork operations and, via a number of digesters built by Optima KV LLC, will pro-duce renewable natural gas that will be sent to two Duke Energy power plants: H.F. Lee Sta-tion Combined Cycle Plant in Wayne County, and Sutton Combined Cycle Plant in New Ha-nover County. The project is expected to be operational by next summer.

David Fountain, Duke Energy North Carolina’s president, has emphasized the project’s benefits and that it is cost-effective for utility ratepayers. The utility says it has remained under the RPS cost cap outlined in regulations, and, contrary to assertions made by opponents of the mandate, that it is not a cost burden to customers.

Once the last kinks in the process are worked out—from project proposal to the sale of RECs, including any interconnection cue is-sues—North Carolina is likely to see a boom of swine waste-based energy projects come online, not only benefiting the environment, but replacing fossil-based generation, creating renewable energy and driving economic value.

Author: Anna SimetManaging Editor, Biomass Magazine

[email protected]


AdvancedBiofuelsNews

Valero Energy Corp. issued a petition to U.S. EPA Administrator Gina McCarthy in June asking the agency to redefine obli-gated party under the renewable fuel stan-dard (RFS).

Valero is asking EPA to redefine obli-gated party as “the entity that holds title to the gasoline or diesel fuel, immediately prior to the sale from the bulk transfer/terminal system…to a wholesaler, retailer or ultimate consumer.” Refiners and importers are cur-

rently considered obli-gated parties under the RFS.

According to Valero, “currently the obligation for RFS is placed on refiners and import-ers—the point of obligation is the refinery gate and the entity that imports—regardless whether the refiner or importer have the ability to affect the amount of renewable fu-els blended and sold to consumers.” Valero

claims this placement has created problems that impair the RFS program’s proper func-tioning and prevent it from ensuring that renewables enter the transportation fuel market.

Valero petitions EPA to redefine obligated party under the RFS

Ontario Biomass Producers Cooperative Inc., a group of Ontario farmers producing and marketing biomass, recently launched an effort to make it easier for its members to sell the miscanthus and switchgrass they produce to various markets.

The cooperative adopted a central-desk selling system and checkoff collection mecha-nism to help connect biomass producers and buyers. The central-desk selling system will be used to develop an advertising strategy to give the cooperative’s members the opportunity to sell into multiple markets and for the markets to go to one place to source material, said Lar-ry Davis, vice president of business with the Ontario Biomass Producers Cooperative.

“It’s an information gathering source,” Davis said. “Producers can learn who the buyers are and what they are using it for and the grower themselves can put their informa-tion on a website. It’s just a way for everybody to know what material is out there and how much is available at any one time.”

Biomass checkoff established in Ontario

Valero fuel production statisticsNo. of refineries Capacity

Petroleum 13 2.9 million barrels per dayEthanol 11 1.3 billion gallons per yearRenewable diesel 1 12,000 barrels per day SOURCE: VALERO


In March, U.S. President Barack Obama and Canadian Prime Minister Justin Trudeau pledged to cut net greenhouse gas (GHG) emissions 80 percent by 2050, a historic agree-ment. This “deep decarbonization” of the global economy will require much more than basic measures in efficiency and renewable energy. It demands profound changes in how we interact with the entire global carbon cycle, from sky to sea to soil. Our modern effort at deep decarbonization can learn much from the planet’s original endeavor in this field, and from that episode’s central players. The lessons learned offer a vision and the tools to reverse much of the past century’s misdeeds.

Billions of years ago, Earth was transformed from toxic wasteland to temperate abundance with the aid of an aston-ishingly powerful, yet simple, set of carbon mitigation tech-nologies. Algae and other early microorganisms unleashed the power of photosynthesis—and its after-hours relative, chemosynthesis—to transform CO2 and other carbon-con-taining gases into the fundamentals of modern existence: food, energy, soil and fresh water.

Many of today’s economic activities produce, at best, one of these elements, often at the expense of the remainder. Deep decarbonization demands a return to Earth’s original approach, in which excess carbon becomes the building block for a sustainable existence.

Algae scientists, engineers, and other industrial biotech-nologists are developing industrial agricultural systems to do just that. These systems provide a model and a mechanism for deep decarbonization that deserve global governments’ strongest support.

Global leaders now clearly recognize that even the most ambitious efforts at energy efficiency and carbon-free en-ergy will be inadequate to avoid potentially catastrophic cli-mate change. To halt and reverse atmospheric accumulation of CO2 and other carbon-containing greenhouse gases will require widespread deployment of carbon capture technolo-gies.

In the near-term, these technologies can be deployed at point sources, such as power plants and industrial facilities, to minimize emissions of CO2 from fossil fuels as we transition to carbon-free power sources. These technologies can also be deployed to capture industrial sources of biogenic carbon,

such as from biomass power and industrial fermentation. Such applications have the benefit of not only avoiding car-bon emissions, but also help begin the task of drawing down atmospheric concentrations of CO2 by removing carbon al-ready resident in the atmosphere, rather than that which was previously sequestered underground, such as the case of fos-sil fuel combustion.

Ultimately, to reverse the buildup of atmospheric CO2, carbon capture must be applied to the atmosphere itself through air capture or other yet-to-be-developed approaches.

Regardless of how and where capture technologies are applied, they must be economically viable and they must sub-stantially reduce emissions of CO2 to the atmosphere, wheth-er directly or indirectly. Enhanced oil recovery (EOR) offers the potential for economically viable carbon capture and geologic storage (CCS), but is predicated on extraction and, ultimately, combustion of additional fossil carbon. Economi-cally viable CCS without EOR has proven heretofore elusive.

Carbon-negative approaches that offer bona fide pros-pects of economic markets for captured carbon are needed. Algae and other microorganism-based approaches to carbon capture offer perhaps the best chance to realize this vision. Today, in an industrial setting, algae and other photosynthetic or chemosynthetic microbes can do what they did in their natural setting eons ago: capture CO2 and other carbon-con-taining gases and convert them into valuable products, includ-ing food, energy, soil and fresh water. The tools of modern industrial biotechnology mean that the systems change the planet achieved over the course of hundreds of millions of years can be realized in a fraction of that time.

A wave of innovation in algae and related technolo-gies is bringing profoundly carbon-negative capture and use technologies to the verge of commercial deployment. With strong policy support, these technologies can be deployed today to aid in the transition to a sustainable global economy.

Author: Matt CarrExecutive Director, Algae Biomass Organization

[email protected]

Ancient Biology for Modern Decarbonization BY MATT CARR

ADVANCED BIOFUELS AND CHEMICALS¦


¦ADVANCED BIOFUELS

Solving the Equipment EquationAn experienced OEM offers the experience, advice and capabilities project developers need to maximize project efficiency.BY ANNA SIMET

DEPARTMENT

AGCO’s large square baler makes its way through a field of corn stover. PHOTO: AGCO CORP.

Farming looks mighty easy when your plow is a pencil, and you're a thousand miles from the corn field.

These words spoken by for-mer U.S. President Dwight D. Eisenhower in 1956 still ring true, and are particularly relevant when it comes to renewable energy projects that involve ag biomass, especially projects that have very specific feedstock specs and large volume requirements, such as cellulosic ethanol ventures.

In fact, most developers—commonly technology or chemical companies—often overlook the complexities around the feed-stock collection system, according to Glenn Farris, marketing manager of biomass at AGCO Corp. “There are misconceptions about how easy it is to harvest grasses or corn stover—a lack of understanding about what type of machinery to use, economics and lo-gistical issues,” Farris says. “When a project is being contemplated, it’s often that developers

will run into some real stumbling blocks be-cause of a lack of understanding of those is-sues.”

The number of machines and moving parts of a commercial-scale energy facility’s feedstock operation is impressive—a project that requires 350,000 dry tons of input per year will need approximately 50 balers, 50 shredders, 35 collections systems and 140 trac-tors, according to Farris. And while mixing and matching different original equipment manu-

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ADVANCED BIOFUELS¦

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facturer (OEM) offerings may look slightly better on the financial front, in the end, it likely won’t. Farris stresses the convenience and eco-nomics of a single technology package. “For example—for a baling operation, there are cer-tain aspects of our tractors that are designed to anticipate our balers, which will probably per-form 3 to 5 percent more efficiently using our tractor,” he says. “Someone might say that’s not much, but that’s true until you’re doing 350,000 to 400,000 tons of biomass and using a couple hundred pieces of equipment. That percent becomes a very large number when you look at it in dollars and cents.”

While more than one OEM can be used and different machine brands paired together, Farris says the commonalities in how a single OEM’s equipment operates, and working with the same dealers to learn how to operate equipment and get it serviced, simply brings more efficiency to an operation.

A Grip On HandlingHistorically, the handling, treatment and

pretreatment of biomass—the collection and preparation process before it goes into the facility units—is usually where most projects experience their problems, according to Far-ris. “That’s where the bottlenecks are, it’s the largest learning curve, and part is based on the fact that biomass is just not usually uniform,” he says.

There are many variabilities among crops, and even within a specific species of crop, including ash content, moisture content, weather influences and more, which typically

makes biomass hard to handle, an overarching reason for having team members who know what to expect and how to deal with challeng-es. Aside from forest biomass, AGCO is con-fident it has worked or handled every potential ag feedstock. “We’ve participated projects that have collected hundreds of thousands, if not millions, of tons of corn stover, and we have harvested and worked with miscanthus, switch grass, energy cane, sugar cane, the list goes on. Most experience has been gained by working and making mistakes, so we can help custom-ers not make the same mistakes. What we’ve learned is just what we didn’t know.”

That experience had led to equipment innovation—for example, changes to the large-square baler chamber and windrower headers—new designs that have made the ma-chines not only a better fit for corn stover, but for other commercial crops such as hay and alfalfa.

And, there are other potential changes that AGCO is ready to make when the time is right. “There are other things we’re ready to do when the market dictates,” Farris says. “We have preliminary designs, high-volume har-vesting machines for grasses like miscanthus and switchgrass, and energy cane, that aren’t available in production models, but could be reasonably quick, when the market needs them.”

Looking Forward Every project is different, and real-world

experience has driven that ideology home for AGCO. “Cookie-cutter is a utopia that doesn’t

exist—challenges vary from project to proj-ect,” Farris says. “And each new commercial project teaches the rest of the industry new lessons, whether it is a complete success, or whether it ultimately fails.

On future opportunities within the bio-mass energy industry, Farris says AGCO sees much potential in South America, particularly Brazil, which has cracked down on sugarcane mills’ burning of cane fields, a practice done before harvest to manage the tops and leaves of sugarcane plants, or waste products leftover following sugar extraction. “About one-third of the material is being left in the field…it’s an exciting opportunity,” Farris says. “Sugarcane is normally burned in the plant to produce steam and electricity, and we’re seeing a lot of expansion, and there are efforts to use it for cellulosic ethanol and chemicals.”

China is also another country of interest. “It seems promising,” Farris adds. “The pow-ers at be seem to be making a real commitment to the concept of using biomass for energy.”

While researchers, technology provid-ers and project developers work on the blue prints for projects in these countries and oth-ers across the globe, AGCO will be waiting in the wings, ready to assist.

Author: Anna SimetManaging Editor, Biomass Magazine

[email protected]


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