INSIDE: UK TO USE CARBON DATING IN WASTE TO ENERGY
Elevating Waste Paper Why Paper Pellets are so Valuable in Cofiring Operations Page 20
Plus: Is it Economical for Coal Plants to Use Torrefied Biomass? Page 28
Experts Weigh in on Logistics of Mixing Coal, Biomass Page 34
Proper Fuel Sizing, Blending Can Ease Cofiring Anxiety Page 40
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SEPTEMBER 2011 | VOLUME 5 | ISSUE 9
FEATURES 20 PELLETS Paper Pellets Wisconsin power companies have discovered the benefits of cofiring petroleum coke and coal with paper pellets. By Lisa Gibson
28 Glorified, Torrefied & Cofired The economics of torrefying pellets may not make sense at the moment, but efficiency improvements may make it more attractive in the next few years. By Anna Austin
34 Biomass and Coal: A Powerful Combination
Procuring, transporting, handling and storing biomass and coal is challenging, but worth the effort for utilities looking to receive renewable energy credits. By Anna Austin
COFIRING Conquering Co-Combustion 40 Proper biomass fuel sizing and feedstock blending are imperative to successful cofiring. By Lisa Gibson
DEPARTMENTS 04 EDITOR’S NOTE The Quest to Make Cofiring as Seamless as Possible By Rona Johnson
06 INDUSTRY EVENTS 08 POWER PLATFORM Looking at the Bigger Energy Subsidy Picture By Bob Cleaves
09 THERMAL DYNAMICS Progress on the Biomass Thermal Front By Charlie Niebling
10 ENERGY REVIEW
CONTRIBUTIONS 46 INTERNATIONAL Biomass: The Ontario Opportunity Developers should consider Ontario’s strong tax incentives and resources when siting biomass power projects. By Shirley Townsend
50 Calculating the Renewable Fraction of Energy from Waste The U.K. will be using carbon dating to measure the proportion of energy from waste that is renewable. By Matthew Aylott
Biomass ’11 Delivers a Stunning Update By Chris Zygarlicke
11 LEGAL PERSPECTIVE Managing Risks in Cofiring Contracts By Todd Taylor
12 BUSINESS BRIEFS 14 FIRED UP 52 MARKETPLACE 53 ADVERTISER INDEX
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 3
The Quest to Make Cofiring as Seamless as Possible
RONA JOHNSON Editor email@example.com
It is still anyone’s guess what the impact of boiler and environmental regulations will be on U.S. coal-fired power plants. But that isn't stopping the biomass industry from making preparations for eventual plant retirements or retrofits involving cofiring. According to a study by The Brattle Group, emerging U.S. EPA regulations on air and water quality could result in a reduction in electricity-generating capacity of more than 50,000 megawatts due to coal plant retirements. Of course, there are conflicting estimates of just how much electrical capacity is at risk, but there will no doubt be some reduction. After reading the features for this month’s magazine, I’m convinced that the biomass industry understands the potential for biomass cofiring at coal plants and several companies are trying to come up with solutions to make the transition as seamless as possible. The bottom line is that cofiring biomass and coal can be done. But it can’t be done overnight and it may take some trial and error to eventually come to the right balance of feedstock and the right assemblage of equipment.
Letter to the Editor
CCS Versus Carbon-Negative Bioenergy with Biochar John Bonitz wrote this letter in response to an article that appeared earlier on the magazine website, and is published in this magazine on page 15. With debate raging over the carbon neutrality of bioenergy, America should embrace biomass technologies that are actually carbon negative. Thus, I applaud the article on the recent IEA Greenhouse Gas study, “Coupling with CCS.” Thank you for jump-starting the conversation. Beyond this, the study has limited usefulness in the U.S., as policymakers and investors have already largely rejected carbon capture and sequestration (CCS). July’s cancellation of the Mountaineer coal-fired CCS project prompted Businessweek magazine to report, "Five largescale CCS projects have been canceled or postponed, while the fate of several others remains doubtful." In a policy regime where the costs of carbon pollution remain externalized, CCS projects fail due to complexity, high operational costs, large scale and high capital costs. Current CCS technologies—often called "clean coal"—require 10 to 40 percent more energy input for the same output of a nonCCS power plant. If CCS with energy-dense coal is expensive, then CCS with low-energy density biomass will be even more expensive. In contrast, the other carbon-negative bioenergy pathway— pyrolysis or gasification with coproduction of biochar—is less complex, can be built at smaller scales, and is less capital intensive. Biofuels and/or biopower are produced while also creating biochar for use as a soil amendment. Any “energy losses” perceived in the conversion of potential Btu into charred carbon is a justifiable form of tithing back to the earth. Afterall, this biochar puts stable, 4 BIOMASS POWER & THERMAL | SEPTEMBER 2011
recalcitrant carbon back in the soil, where it has many beneficial impacts. CCS has ready markets for CO2 pumped underground to enhance oil recovery (EOR). But biomass is a distributed resource, oil wells are not, and there is little biomass in oil country—inherently limiting the EOR market. Soil scientists are finding biochar has many benefits, including increased crop yields, retention of nutrients and water, and suppression of greenhouse gas emissions. Granted, until Americans put a price on carbon, both CCS and thermochemical bioenergy are precommercial technologies. Also, additional research is needed to determine the precise benefits of different types of biochar in different soils, for different crops. But investors and policymakers with limited capital might ask themselves, which is a better investment: complex, centralized engineering monoliths or heat-treating biomass for distributed energy and beneficial biochar? Carbon-negative bioenergy with biochar is a pathway to rebuild the soil, provide for the needs of future generations and provide some of today’s energy needs, while helping to mitigate climate change. Either way, let’s stop dithering over debatable carbon accounting and take actions that prove their merits with measurable physical sequestration of multibenefit biogenic carbon. Author: John Bonitz Southern Alliance for Clean Energy Bonitz@cleanenergy.org
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SEPTEMBER 2011 | BIOMASS POWER & THERMAL 5
¦INDUSTRY EVENTS International Biorefining Conference & Trade Show September 14-16, 2011 Hilton Americas – Houston Houston, Texas The International Biorefining Conference & Trade Show brings together agricultural, forestry, waste and petrochemical professionals to explore the value-added opportunities awaiting them and their organizations within the quickly maturing biorefining industry. (866) 746-8385 www.biorefiningconference.com
Northeast Biomass Conference & Trade Show
Biomass Tours Lined Up for Northeast Conference BBI International has announced the tour sites for this year’s Northeast Biomass Conference & Trade Show, being held Oct. 11-13 at the Westin Convention Center in Pittsburgh, Pa. The tour sites are in Pennsylvania and all are engaged in leveraging various biomass streams for energy production. The first tour site is Fairview Swiss Cheese, which is the largest producer of Swiss cheese in Pennsylvania, processing more than 30,000 gallons of milk into cheese per day. The plant digests its cheese whey and produces methane gas thus eliminating permitting and cost issues associated with land application of the waste stream. The gas powers a 300-kilowatt generator that supplies about half the facility’s electricity needs. The second site is switchgrass seed producer Ernst Conservation Seeds Inc. Ernst produces, processes and markets more than 400 native and naturalized seed varieties for the entire East Coast (including Canada) and the Midwest for use in land reclamation, wildlife food plots, wetland remediation, biomass production and erosion prevention. Ernst is in the midst of building a commercial densification facility that will produce solid biomass fuel in the form of pellets and briquettes from warm season grasses. Crawford Central School District’s biomass combined-heat-and-power (CHP) district heating system will round out the tour. The system will be completed this summer and will use locally sourced wood chips to provide 85 percent of the annual heating and 15 percent of the annual electric demand for a high school building, career and technical center and recreational complex. The Northeast Biomass Conference & Trade Show program will feature more than 60 speakers, including technical presentations on topics ranging from anaerobic digestion and gasification to combined heat and power and large-scale biomass combustion, within the structured framework of general session panels and four customized tracks: power and thermal; biorefining; project development and finance; and feedstocks. The event is designed to help biomass industry stakeholders identify and evaluate solutions that fit their operations. It's time to improve operational efficiencies and tap into the revenue-generating potential of sustainable biomass resources in the Northeastern U.S. For more information about the conference, visit www.biomassconference.com/ northeast.
6 BIOMASS POWER & THERMAL | SEPTEMBER 2011
October 11-13, 2011 Westin Convention Center Pittsburgh, Pennsylvania With an exclusive focus on biomass utilization in the Northeast—from Maryland to Maine—the Northeast Biomass Conference & Trade Show will connect current and future producers of biomass-derived electricity, industrial heat and power, and advanced biofuels, with waste generators, aggregators, growers, municipal leaders, utilities, technology providers, equipment manufacturers, investors and policymakers. (866) 746-8385 www.biomassconference.com/northeast
Algae Biomass Summit October 24-27, 2011 Hyatt Regency Minneapolis Minneapolis, Minnesota Organized by the Algal Biomass Organization and coproduced by BBI International, this event brings current and future producers of biobased products and energy together with algae crop growers, municipal leaders, technology providers, equipment manufacturers, project developers, investors and policy makers. It’s a true one-stop shop—the world’s premier educational and networking junction for all algae industries. Register by Sept. 12 and save $200. (866) 746-8385 www.algaebiomasssummit.org
Southeast Biomass Conference & Trade Show November 1-3, 2011 Hyatt Regency Atlanta Atlanta, Georgia With an exclusive focus on biomass utilization in the Southeast—from the Virginias to the Gulf Coast—the Southeast Biomass Conference & Trade Show will connect the area’s current and future producers of biomass-derived electricity, industrial heat and power, and advanced biofuels, with waste generators, aggregators, growers, municipal leaders, utility executives, technology providers, equipment manufacturers, investors and policy makers. Register by Sept. 20 and save $200. (866) 746-8385 www.biomassconference.com/southeast
Looking at the Bigger Energy Subsidy Picture BY BOB CLEAVES
The first week in August, the U.S. Energy Information Administration unveiled a long-awaited study, called “Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010.” The report promises to be controversial. Already, various renewable trade associations have charged that the report fails to accurately capture subsidies for the oil and gas sector, which will in turn claim that the total support for all renewables— estimated to be $28.5 billion since 2009—is not affordable in an age of fiscal austerity. We have a slightly different take. A closer look at the report reveals the profound disparity among renewable technologies. Let’s start at the 30,000-feet level. The U.S. Department of the Treasury’s 1603 program, enacted in 2009 as part of the Obama stimulus package, provides a cash payment in lieu of an investment tax credit (ITC) equal to 30 percent of the cost of a project. Since September 2009, treasury has paid out a total of $7.78 billion to 3,159 renewable projects. Of that total, $5.6 billion was spent on wind, and another approximately $1 billion on solar. Biomass, on the other hand, received approximately $115 million—or 1 percent of the 1603 dollars—funding only a handful of projects. Geothermal (at 1.7 percent), and hydropower (1.8 percent) didn’t fare much better. The authors overlooked waste to energy, but we suspect the numbers would be the same. In other words, this means that 1 percent of the money was spent for a renewable energy that represents 50 percent of the nation’s renewable supply, while about 85 percent of this grant funding went to sources that account for only 10 percent of the nation’s renewable energy supply. So what’s going on here? Do baseload sources of renewable energy have a future? After all, according to EIA, annual growth from 2000 to 2010 was downright
8 BIOMASS POWER & THERMAL | SEPTEMBER 2011
anemic for some (geothermal grew by only 1.3 percent), while biomass actually lost ground (-0.7 percent) along with hydroelectric (-0.75 percent). Will the future of federal renewable energy tax benefits (assuming there is a future) be skewed to solar and wind (the latter growing 31.8 percent), which admittedly play an essential role, to the extent that they essentially edge out baseload sources of renewable energy? The EIA study is the best evidence yet of what happens when Congress creates a tax code that results in an unlevel playing field across renewable technologies. How unlevel? For starters, biomass, hydro and waste-to-energy facilities are only allowed 50 percent of the value of the production tax credit (PTC) compared to other renewables, with absolutely no public policy reason. Second, the code favors technologies with more immediately achievable “placed in service” dates. Remember that in order to qualify for the PTC or ITC, a biomass facility must be placed in service by Dec. 31, 2013. Given that typical biomass plants take easily five years to develop and construct, there is no certainty that projects developed now could qualify for the benefit. As a result, the code favors projects with shorter development horizons. This explains in part why so few biomass projects are qualifying for federal benefits. For starters, Congress needs to provide tax equity across all renewables by enacting H.R. 2286, the Renewable Energy Parity Act. Second, BPA joins other renewable associations in advocating for the extension of the 1603 program, but an extension alone will not correct the inequities of the code. Enactment of a longer placed-in-service date window is essential if biomass is to realize its full potential in this country. Author: Bob Cleaves President and CEO, Biomass Power Association www.USABiomass.org
Progress on the Biomass Thermal Front BY CHARLIE NIEBLING
When the Biomass Thermal Energy Council was founded in 2009, federal and state policy makers barely understood the potential of making heat from biomass to meet our nation’s lofty energy goals. Early forays by BTEC leaders into congressional offices were met with blank stares. State energy and climate plans overlooked this energy pathway. If it wasn’t about making electricity or a liquid transportation fuel, it did not merit consideration in policy platforms such as state renewable portfolio standards (RPS) or federal renewable fuel standards. After years of persistence by BTEC and activists, this is changing. Every day I see indications that heating and combined heat and power (CHP) with biomass is increasingly being viewed as a wise component of America’s broader renewable energy strategy. Take the Northeast, for example. In the past six months, biomass heating has moved forward on several fronts: • In Massachusetts, the Mass Clean Energy Center recently funded a comprehensive analysis of renewable heating options. This study is under way and includes biomass thermal. The expectation is that the findings and conclusions will form the basis of new policies and incentives. • In Massachusetts, activist efforts by the Northeast Biomass Thermal Working Group led the state legislature’s Joint Committee on Telecommunications, Utilities and Energy to issue a critique of RPS changes calling for a strong look at policy favoring high-efficiency biomass thermal. • In Vermont, Gov. Peter Shumlin enthusiastically endorsed using state Regional Greenhouse Gas Initiative funds to support a rebate program for high-efficiency biomass heating appliances. That program is now moving forward. • In Vermont, activists responding to a NEBTWG action alert sent letters to state officials developing a Comprehensive Energy Plan to incorporate stronger consideration of biomass thermal. • In New York, the New York State Energy Research and Development Agency announced a funding opportunity that will provide grant support for high-efficiency, low-emission commercial-scale biomass heating technology. Details will become available in September. NYSERDA also announced that it will issue a request for proposals to conduct a statewide biomass heating roadmap strategic planning effort; details will come out in October. • In Pennsylvania, industry activists have come together to revitalize the Pennsylvania Biomass Energy Association
with a more focused mission “To promote and support the use of sustainable biomass feedstocks for heat and/or CHP applications.” More than 50 member companies attended an initial strategic planning meeting. • In Maine, industry activists with the Maine Pellet Fuels Association led an effort to change state regulations to allow solid fuel combustion to utilize the same chimney flue as fossil fuel combustion, a major regulatory barrier to widespread use of high-efficiency biomass in homes. • In New Hampshire, legislation to provide renewable energy certificates for thermal output from biomass CHP is moving forward. It was also the only state to use stimulus funds to finance a residential rebate for high-efficiency biomass boilers. And the state’s Public Utilities Commission is evaluating how to include thermal renewables in a revision of the state’s RPS, with recommendations due in the fall. • Finally, in September NEBTWG issued a “call to action” to Northeast governors and congressional delegation calling for inclusion of biomass thermal in incentive programs, state energy plans and the federal tax code. Representatives of nearly 400 businesses, agencies and organizations signed the letter. Individually, these actions represent small but incremental evidence that biomass thermal is gaining momentum. Collectively, they demonstrate an unstoppable movement toward recognition that biomass thermal represents a hugely overlooked renewable resource. Further indication can be found in the formation of the Midwest Biomass Thermal Working Group, with a conference being planned in the north-central states for 2012. And, with support from the USDA Forest Service Wood Education Resource Center, BTEC hosted seven webinars with nearly 2,000 participants on a range of topics related to biomass thermal. The biomass thermal community is not waiting for Washington to hand down progressive energy policy. Rather, we are making progress one community, one state and one region at a time—through innovative private/public partnerships. I have confidence that these efforts will build strength, and this most renewable resource—biomass—will be restored to its once prominent place in meeting our nation’s thermal energy needs. Author: Charlie Niebling Chairman, Biomass Thermal Energy Council www.biomassthermal.org
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 9
Biomass ’11 Delivers a Stunning Update BY CHRIS ZYGARLICKE
Biomass ’11 was held for the ninth time in Grand Forks, N.D., on July 26–27. The 250 participants from 26 states, Washington, D.C., and 11 foreign countries were provided with an eye-opening revelation: biomass industries are going to have to compete hard with other energy industries over the next few years. Of course, anyone associated with biomass utilization in the past decade knows that it is no easy task to produce renewable energy, fuels or chemicals from plant or animal matter. An overriding theme seemed to be that the United States just doesn't have the impetus and incentives for biomass to thrive, but research and demonstration are an absolute must to position biomass technologies into competitive niches. Gerald Groenewold, director of the Energy & Environmental Research Center, kicked off the event and extended gratitude to the major sponsors of the event: his institution, the EERC; the North Dakota Department of Commerce; and the U.S. DOE. Groenewold stated clearly that game-changing biomass research at the EERC began with pioneering support from U.S. Sen. Byron Dorgan more than a decade ago. This led to critical advances such as 100 percent renewable jet fuel, distributed-scale biomass gasifiers and renewable ammonia fertilizer. As important as these types of advances and many others are, the toe-to-toe ability for biomass technology to compete in U.S. markets is still lacking. Biomass industries need to be patient and continue to find those competitive or complementary niche markets. EERC research is all about finding those commercial footholds. One of the niche areas that has some competitive assistance in North Dakota was described by N.D. Gov. Jack Dalrymple. Dalrymple described North Dakota as the ethanol blender pump capital of the world … per capita, that is. Adding to the U.S. picture on incentivizing biomass, Corinne Valkenburg from the DOE Office of Biomass spoke of the tremendous investment by the federal government to spur viable technologies in produc-
10 BIOMASS POWER & THERMAL | SEPTEMBER 2011
ing biofuels and the grants and loan guarantees that have been provided for small commercial demonstrations. Margo Shaw, a senior biologist with Golder Associates Ltd., in Winnipeg, Manitoba, Canada, reiterated the theme of niche opportunities in the United States but showed that many other places around the world have tremendous incentives that provide for greater biomass promotion. Her statistics showed only 1 to 3 percent biomass electricity in the United States, with a predicted growth of 3 percent in the next 20 years. In contrast, European policies such as a 20 percent renewable energy directive, feed-in tariffs that guarantee renewable energy access to the grid at higher prices, grants and loans, and other tax incentives have created a thriving business environment, at least for biobased power and heat generation. With too many technical presentations to mention, this year’s program emphasized development and processing of biomass feedstocks. Varieties of methods were reported to chop, shred, pelletize, bale or liquefy using a method called fast pyrolysis. Fast pyrolysis uses low-oxygen heating of lightweight, low-density biomass to convert it to a mostly watery mix of low-grade organic tars and acids, with 10 to 20 percent each of char and gaseous matter. I have always liked the fast-pyrolysis process as an on-farm method of densifying straws and agricultural residues, so the work presented was quite encouraging. In summary, it was quite apparent that biomass industries are indeed up for the fight: ready to go head-tohead in hard competition with fossil energy to at least carve out a significant role in America's diverse future energy portfolio. Author: Chris Zygarlicke Deputy Associate Director for Research, Energy & Environmental Research Center (701) 777-5123 firstname.lastname@example.org
Managing Risks in Cofiring Contracts BY TODD TAYLOR
Biomass cofiring with coal is a great idea. Biomass cofiring is a technology that is readily available, energy plant improvements are often minimal, and feedstock is abundant and often low cost. It also helps lower CO2 emissions, sulfurous gases and other harmful gases. As a supplier of biomass feedstock for cofiring systems, these are surely at the top of your sales benefit list. But, when you are working on the sale, be aware of the risks and how they may impact your bottom line. Obviously, the cost of the biomass is a large issue. Make sure the price you quote your buyer is one you can manage during the life of the contract. If you don’t control the biomass, strongly consider trying to get a variable pricing structure from your customer so you are not squeezed between escalating costs on one side and a fixed sales price on the other. Think of this as well for other variable costs, specifically fuel if you have to deliver the feedstock. I had a plant client who had a fixed-price contract for feedstock, but not long after the contract started, the feedstock provider demanded more money because diesel fuel costs were rising. There was no provision in the contract for variable fuel costs and it created significant difficulties for the supplier, ultimately costing them the contract and their company. If you can’t get variable pricing for feedstock or key inputs, carefully consider your cost and pricing model so that you can survive reasonably expected changes. Think also of biomass quality. Cofiring systems require the biomass to have certain moisture content, size, ash content and other quality issues. Not long ago, a renewable energy company with a biomass gasifier had serious difficulties due to feedstock quality issues and ultimately shut down the gasifier because it would not work on anything but high quality and expensive biomass. Know up front what your customer will need and make sure that the contract provides for that. Consider what happens if you cannot supply acceptable feedstock. Usually, the customer can cancel or suspend the contract and find an alternative source. Sometimes however, when a customer has penalty clauses in their power purchase agreement or would otherwise suffer losses
from a failure to deliver feedstock, the customer asks for liquidated damages. This means that if you cannot supply the feedstock, you are liable for their losses. Pricing mechanisms are often a subject of negotiation and many mechanisms exist. Avoided cost basis, cost of feedstock, impacts of renewable energy credits or other tax or policy pricing, pricing for quality (both premiums and penalties), Btu variability, ash content and more are valid and often used mechanisms. Understanding how each works and will impact your business is important. If you are a biomass cofiring technology provider, feedstock quality issues, including the quality and size requirements for your system, should be clearly listed in the contract. Emissions profiles, ash content and disposal, performance guarantees, warranties and indemnification are also important contract provisions that need careful consideration. Too often, performance guarantees, warranties and indemnification are considered “boiler plate” and not given the attention they deserve. But, they can all have significant impact on how fault, and thus financial responsibility, is determined. While your advisers can help you with many of these issues, you need to think of how these contract provisions will impact the relationship with your customer and your own business. An unfortunate example of this was a technology provider whose contract did not define many key terms related to performance and emissions. Because they were not defined, when a problem occurred, it was uncertain whose job it was to fix the problem. Uncertainty often leads to disagreements and disagreements lead to lawsuits, which help neither party. Like most things, an ounce of prevention is worth a pound of cure. Asking your customers these questions may not be as fun as closing the deal, but both you and your customer will later appreciate your attention to detail … or you will both wish you had read that fine print. Author: Todd Taylor Co-Chair Clean Technology Group, Fredrikson & Byron P.A. (612) 492-7355 email@example.com
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 11
Business Briefs PEOPLE, PRODUCTS & PARTNERSHIPS
Metso supplies technology for French biomass plants Metso will supply automation and environmental technology to control five biomass power plants to be built by Dalkia in France. The investments are part of France’s national green energy program, which aims to reduce carbon dioxide emissions and curb climate change. Dalkia chose Metso because of its track record from Dalkia’s biomass plant in Fracture, France. Dalkia wants to standardize the automation systems at all these six plants to save costs on erection, operation and maintenance, spare parts and staff training, among others. The first plant will be built in Limoges and is due to start up in February. The others in Angers, Orleans, Tours and Rennes will be completed next year. The Limoges plant in west-central France will have a capacity of 17.5 megawatts (MW) of electricity and 17 MW tons of district heat. Vecoplan hires LaGoe Mike LaGoe has joined Vecoplan LLC as a project engineer/manager. LaGoe, formerly engineering manager at a manufacturer of air pollution control BIOMASS SYSTEM systems, brings 12 years SPECIALIST: of practical experience Mike LaGoe joins Vecoplan as a to his new position. project engineer/ LaGoe’s responsibilities manager. will include coordinating the design and development of largescale, turnkey systems for the processing and production of alternative fuels from biomass and waste, as well as general waste treatment systems. To ensure continuous quality control, he will also oversee the manufacture and implementation of his projects once the engineering phase has been completed.
HRE signs licensing agreement with Achor Anaerobic Homeland Renewable Energy announced that its anaerobic digestion (AD) division, Homeland Biogas Energy, has signed an exclusive licensing agreement with Achor Anaerobic LLC. Under the agreement, HB Energy will use Achor’s “achorlytic” enzyme and digestion inoculating technology to enhance the productivity of AD in its projects in the U.S. and elsewhere. HB Energy will also work with Achor to license the technology to third parties. Achor’s technology uses enzymes to increase the biogas production from digestible materials, including animal and food wastes as used by HB Energy at its facilities. Achor and HB Energy are carrying out large-scale tests of the Achor technology at AD facilities operated by HB Energy in Wisconsin. Test results are expected to be available during the summer, and preliminary indications show favorable improvements in productivity. HB Energy has a pipeline of more than 15 AD projects, ranging in size from 3 to 20 megawatts. DP CleanTech develops biomass fuels tool Aurelie Sol, a DP CleanTech biomass fuel expert, has developed an innovative tool to help people better understand the properties of biomass fuels and fuel mixes under combustion. The proprietary web-based tool is called Biomass Lab and is an interactive database of biomass fuels from around the world. Users can conduct a series of chemical analyses to determine the performance of biomass residues as a fuel for direct combustion biomass power. The user-friendly tool is the only biomass database that allows users to input their own fuels and conduct analyses for fuel mixes. Sol has studied biomass fuels closely and spends much of her time analyzing biomass fuels from around the world. The Biomass Lab can be accessed at www. dpcleantech.com/biomasslab/the-biomasslab.
12 BIOMASS POWER & THERMAL | SEPTEMBER 2011
Covanta receives LEED award for corporate headquarters Covanta Energy Corp. announced that the U.S. Green Building Council has recognized its new corporate headquarters in Morristown, N.J., with Leadership in Energy and Environmental Design Gold Certification. LEED is the nationally accepted benchmark for the design, construction, maintenance and operation of green buildings and office spaces. The U.S. Green Building Council is a coalition of leaders from across the building industry working to promote buildings that are environmentally responsible. The LEED Green Building Rating System is a voluntary, consensus-based national standard for developing high-performance, sustainable buildings. LEED ratings are awarded through a point system that provides building owners and operators with a framework for identifying and implementing practical and measurable green building design, construction, operations and maintenance solutions. Martin Engineering finalizes Chinese expansion plans
BIGGER AND BETTER: Martin Engineering designs and supplies equipment for bulk materials handling. SOURCE: MARTIN ENGINEERING
Martin Engineering has announced final plans for a new 10,000 square meter (107,600 square foot) facility in Kunshan, which is in the Jiangsu Province of China. Scheduled to open late this year, the new building will house 8,000 square meters of manufacturing and warehouse operations and 2,000 square meters of office space, making it eight times larger than the existing space. When construction is completed on the recently purchased 16,000-square-meter property, the
Webb names Roberts regional sales manager of bulk material handling Jervis B. Webb Co., a subsidiary of Daifuku Webb Holding Co., and provider of material handling solutions, has named Mike Roberts as regional sales manager of its Bulk Material Handling division. In this role, he is responsible for supporting business development and sales throughout North America. Webb’s BMH division provides durable and reliable systems to industries such as power generation, biomass/biofuel, mining, pulp and paper. Roberts has more than 20 years experience working in bulk material handling. He has had a successful career in the solid waste, recycling and scrap metal industries where he provided material handling and processing solutions. Before joining Webb, he was a sales manager for an engineering and manufacturing firm that provided equipment for shredding and separating ferrous and nonferrous scrap metal. Bandit welcomes new dealers in Indiana, Louisiana Bandit Industries announced the addition of three dealers to its authorized dealership network. Tri-County Equipment in Evansville, Ind., Arrow Tool Rental Corp. in Indianapolis, and Emery Equipment Sales & Rentals Inc. in Baton Rouge, La., join more than 150 dealers in more than 50 countries to offer Bandit equipment. These new locations will further extend Bandit’s line of hand-fed wood chippers and stump grinders to the professionals who need
to be mixed and matched to attain the desired end product. The screens are also reversible and interchangeable to obtain the maximum usage of the wear portion of the screen. Customers also have the ability to adjust the screen support on the HG6000, allowing the screen to be moved closer or farther away from hammer tips to match clearance with the type of material being processed. Vermeer eliminated the transition area between the anvil and screen, increasing the screen area on the HG6000 by 20 percent, allowing for more throughput.
them, while also providing customer service. Arrow Tool Rental Corp. has stocked Bandit rental machines for years, and will now offer Bandit’s full line of hand-fed wood chippers and stump grinders for sale, while also continuing to rent Bandit equipment alongside their rental stock that includes everything from larger industrial equipment to basic hand tools. Tri-County Equipment operates locations in Evansville and Poseyville, Ind., serving residents of southern Indiana, Kentucky and Illinois. Bandit hand-fed chippers and stump grinders will join other represented manufacturers including Kubota, Bobcat, New Holland, Great Plains and more. Emery Equipment Sales & Rentals will sell Bandit’s line of hand-fed chippers and stump grinders alongside their new and used Bobcat machinery and King Kutter attachments. Vermeer redesigns horizontal grinder
PHOTO: VERMEER CORP.
site will produce a variety of systems used to improve efficiency and reduce fugitive material in bulk material handling, including belt cleaners, impact cradles, skirtboard seal systems, air cannons and industrial vibration. Martin Engineering’s existing China facility began operation in Kunshan in 2005, and quickly outgrew the 1,200-square-meter leased space.
WOOD WRANGLER: Vermeer's redesigned grinder meets the government's emission standards.
Vermeer Corp. has redesigned the HG6000 horizontal grinder with new design enhancements and an engine that meets wood waste processors’ needs for productivity and government emission regulations. The HG6000 is powered by a Cat C18 Tier 4i/Stage IIIB engine that meets all U.S., Canada and European Union tier regulations while producing 755 horsepower, a 20 percent increase in horsepower over the previous Tier 3 engine. A dual-screen system allows screens
Komptech beefs up its Crambo shredder Since its beginnings in 1992, Komptech has developed its machines in close consultation with customers, and been quick to create solutions to their needs. The Crambo low-speed, high-torque shredder, for example, was designed to shred whatever came its way, including logs and stumps. Now, not all stumps are equal, of course. There are stumps from regular forestry—from ground long ago cleared of rocks, where trees are harvested before they get too old, and where everything is generally under control. And then there are stumps from hardwoods that grew where the seed happened to fall, sometimes around rocks or even old pieces of metal. So Komptech decided to beef up the Crambo for more longevity with any diet, creating the new Crambo HD (heavy duty). The Crambo HD has 10 percent more horsepower, armored drum, armored teeth, heavy-duty gear box and drum bearing.
SHARE YOUR INDUSTRY NEWS: To be included in the Business Briefs, send information (including photos and logos, if available) to Industry Briefs, Biomass Power & Thermal, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. You may also e-mail information to firstname.lastname@example.org. Please include your name and telephone number in all correspondence.
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 13
FiredUp Burgeoning Biomass A U.K. white paper and accompanying energy roadmap put emphasis on biomass potential.
The U.K.â€™s Renewable Energy Roadmap, released as part of a government white paper on reforming the electricity market, identifies both biomass heat and power within the eight technologies with the greatest potential to meet the U.K.â€™s 15 percent by 2020 renewable energy goals. In fact, biomass is listed among the top three, along with wind and air heat pumps. The central range for deployment indicates that biomass electricity could contribute up to 6 gigawatts (GW) by 2020, equal to an annual growth rate of 9 percent, the roadmap says. Conversion of existing coal plants to biomass is a major new development, representing another 4.2 GW, including cofiring capacity, plus more with any new projects. Those increased expectations for biomass power have large power providers excited and hopeful that meaningful incentives will follow. â€œWe welcome the publication of the Renewable Energy Roadmap,â€? says Dorothy Thompson, chief executive of Drax Power Ltd. The company is looking to cofire biomass in its 4,000 megawatt Drax Power Station, and possibly develop more dedicated biomass power plants. â€œIn particular, we are encouraged by the recognition of the greater role that electricity generation from sustainable biomass can make to meeting the governmentâ€™s climate change targets,â€? she says. â€œThat is very much in line with Draxâ€™s focus as we seek to expand our biomass operations. However, in order to do so, we will need an appropriate level of support under the current renewables incentive mechanism. To that end, we eagerly await the governmentâ€™s proposals for the support levels from April 2013.â€? Through the U.K. Renewables Obligation, Renewables Obligation Certificates are awarded to qualifying operations. The amount of ROC support is determined by technology type, but support levels past 2013 are currently being decided. Many, including Drax, are hoping to see elevated support for biomass applications. The roadmap lists priority actions for the government to help further establish the biomass power industry, including minimizing investor risk, de-risking the feedstock supply chain, establishing access to finance, and accessing long-term waste fuel contracts. â€œBiomass electricity has significant upside potential and could feasibly exceed the industry high, helping to meet the 15 percent target cost effectively,â€? the roadmap states. â€œHowever, the projections can only be achieved if sufficient sustainable feedstocks are available.â€? The roadmap continues into biomass heat, saying the nondomestic sector could contribute up to 50 terawatt hours by 2020. That requires a large annual growth rate of up to 17 percent. Priorities in that area include technology costs, the report says, adding that implementing the U.K.â€™s Renewable Heat Incentive will help make it competitive with fossil fuel generation. Air quality regulation is another important priority, as are planning and environmental permitting, investor confidence, and RHIâ€™s capacity to help with costs associated with biomethane injection into the grid. 14 BIOMASS POWER & THERMAL | SEPTEMBER 2011
The Renewable Energy Roadmap was released along with the Electricity Market Reform White Paper, which states that the government intends to zero rate biomass in its Emissions Standards Performance program, a regime for new fossil fuel power stations supporting decarbonization objectives. â€œThe government expects sustainably sourced biomass to make a significant contribution towards achieving the U.K.â€™s renewable energy targets,â€? it says. â€œApplying the ESP to any level of biomass emissions above zero could reduce the incentive to invest in sustainable biomass generation.â€? The publication of the white On the Web paper marks the final stage of the reform process. The government White paper and link to roadmap: intends for the legislation to reach http://www.decc.gov.uk/en/content/ cms/legislation/white_papers/emr_ the statute book by spring of 2013, so the first projects can be supported wp_2011/emr_wp_2011.aspx under its provisions around 2014. â€”Lisa Gibson
Coupling with CCS Study: Biomass technologies plus carbon capture/storage have global potential for negative CO 2 emissions.
The coupling of biomass technologies with carbon capture and storage (CCS) yields negative carbon dioxide emissions and the global potential is enormous, according to “Potential for Biomass and Carbon Dioxide Capture and Storage,” a study recently released by innovation company Ecofys and international research collaborative IEA Greenhouse Gas. The study aimed to provide an assessment of the potential for biomass and CCS technologies up to 2050, with an additional focus on the medium term. Combining the two could result in up to 10 gigatonnes of negative carbon dioxide across the globe annually, researchers found. Putting that in perspective, global energy-related carbon dioxide emissions in 2010 reached almost 31 gigatonnes. “The combination actually removes CO2 from the atmosphere,” says Joris Koornneef, a consultant at Ecofys. “The biomass extracts CO2 from the atmosphere during photosynthesis and the CCS takes out the CO2 released in the energy conversion process.” The study carefully distinguishes between technical potential: potential that is technically feasible and not restricted by economic limitations; realizable potential: potential that is technically feasible and takes future energy demand scenarios for the phase out of existing generating capacity into account; and economic potential: the potential at a competitive cost compared to alternatives. Looking at both electricity and fuel production, the study explored six technology routes. For power, it included pulverized coal with direct biomass cofiring; circulating fluidized bed dedicated biomass; integrated gasification combined cycle with cogasification of biomass; and biomass
integrated gasification combined cycle. For biofuels, the study evaluated advanced production of bioethanol through hydrolysis and fermentation; and biodiesel based on gasification and Fischer Tropsch synthesis. The report also distinguishes three types of biomass: energy crops, forest residues and agricultural residues. It also includes global sustainable biomass potential. Taking only technical limitations into account, the maximum annual potential is about 10 gigatonnes of negative emissions annually in the power sector alone, or 6 gigatonnes in the biofuel sector. The realizable potential in the medium- and long-term appears to be the greatest for pulverized coal coupled with CCS and cofiring with biomass, according to the re-
port. The best economic potential in both the medium- and long-term lies in biomass integrated gasification combined cycle with CCS. It has the lowest cost of electricity when using low-cost biomass. But even with all the potential, barriers remain, including the lack of a clear economic incentive. “Without such an incentive, the huge potential for negative emissions will not be deployed,” the report says. Moving forward in the near-term, the researchers recommend a detailed look at the most promising regions. For a copy of the full report, contact Toby Aiken, IEA Greenhouse Gas communications dissemination manager, at email@example.com. —Lisa Gibson
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 15
PHOTO: PYROGENESIS CANADA INC.
THE POWER OF PLASMA: The first commercial installation of the Pyrogenesis plasma gasifier cost $7.4 million, and allows the Air Force to divert 8.3 tons a day of trash from going to the landfill.
Pyrogenesis Perfecting Plasma The first application of Pyrogenesis’s plasma gasifier is operating for the U.S. Air Force in Florida.
Since late last year, the U.S. Air Force Special Operations Command in Hurlburt Field, Fla., has been generating energy from municipal solid waste (MSW) in lieu of landfilling, using a 10.5 metric-ton-per-day plasma gasification process. The system is small, but represents the first commercial installation of the technology for developer and vendor Quebec-based Pyrogenesis Canada Inc. “It is a showcase for them, as well as a showcase for us,” says Tom Whitton, business development leader for the company. The MSW feedstock will be sourced from Hurlburt, but the system will also use some industrial, medical and hazardous waste from nearby Eglin Air Force Base, Whitton says. The 400 to 500 kilowatts it will produce is enough to power itself, with no surplus for sale to utilities. Pyrogenesis, does, however, have systems available up to 100 metric tons per day, which would allow for excess power sales. The two-step plasma gasification system includes a furnace with graphite electrodes that operates at 1,600 degrees Celsius (2,912 degrees Fahrenheit) to create the plasma, Whitton explains. In the furnace, all inorganic materials are converted to vitrified slag that can be mixed with cement or asphalt and used in construction, while the organics begin partial gasification. The gas created in the furnace goes directly through the plume of a plasma torch, producing the syngas that is then cleaned. “What we’re doing in Florida is we’re actually feeding that gas, once it’s been completely cleaned up … into an internal combustion engine to produce electricity,” Whitton says. One of the advantages of using thermal plasma in the
16 BIOMASS POWER & THERMAL | SEPTEMBER 2011
gasification process, he adds, is that it can handle a high variation of feedstock with its temperatures in excess of 10,000 degrees Celsius. “Because of the extreme temperatures that plasma operates in, virtually no chemical substances or compounds can survive that.” The cost to build the plant was $7.4 million, funded by the U.S. Foreign Comparative Testing Office, Air Force Smart Operations for the 21st Century, the Canadian government, the U.S. Air Force Surgeon General's office, and Gulf Power. While Pyrogenesis is a vendor and does not typically operate its technology when installed, the company is operating the Hurlburt Field plant through a contract with the Air Force, Whitton says. The system is perfectly suited for the Air Force because it is transportable and designed for “plug and play,” Whitton says. It can be disassembled, moved and reassembled easily. “They work as an island,” he says of Air Force bases, adding that self-sufficiency is crucial. "This is history in the making," Terry Yonkers, assistant secretary of the Air Force for installations, environment and logistics, said at a ribbon-cutting ceremony for the plant in April. "This is the first waste-to-energy project of this technology to go into an air base. It has been a long time in the making." For the base, it will mean diverting nearly 8.3 tons of daily domestic trash from landfills, reducing gas emissions by over 83,000 tons per year and eliminating toxic materials while producing energy. “It’s much more of a waste management project than an energy project,” Whitton says. “But without the energy recovery, it wouldn’t fly.” —Lisa Gibson
By the Numbers A new online tool calculates the benefits of the U.K.â€™s Renewable Heat Incentive.
With increased interest in the U.K.â€™s Renewable Heat Incentive, The Mersey Forest has developed a free online tool to determine the payback for users interested in the program. The RHI is designed to help the U.K. meet its renewable energy goal of 15 percent by 2020. Itâ€™s based on the amount of heat used, not the amount generated, and is intended for use by public and private sectors, charities and other users of all scales. The U.K.â€™s Department of Energy & Climate Change has released the details of the program, the money has been allocated and the primary legislation is making its way through Parliament. The calculator works under two scenarios. It will determine potential income streams based on current heat usage, or calculate the paybacks if the user is switching from a fossil fuel system to woody biomass and knows the capital installation cost figures. It is designed to also calculate how quickly the usersâ€™ boilers will pay for themselves, the expected difference in annual fuel bills, and what return they could see after 20 years.
The tool is geared mostly toward On the Web woody biomass, says Nigel Blandford RHI information: www.decc.gov.uk/rhi of The Mersey Forest Team. â€œHowRHI Calculator: www.merseyforest. ever, the RHI as a whole, very interest- org.uk/rhicalculator ingly, does accept a range of fuels,â€? he adds, citing municipal solid waste. So far, the calculator has found that areas off the gas grid and plants that produce over 1 MW have the most attractive paybacks. Not all areas in the U.K. have been added to the calculator, as the necessary data in most cases is well-guarded, Blandford says. The Mersey Forest is a network of woodlands and green spaces spread across Cheshire and Merseyside. â€œBy building both supply of and demand for wood fuel in Merseyside and Cheshire, The Mersey Forest is working to not only support the local economy, but also show how sustainable renewable fuel can be part of the solution to climate change and energy security,â€? Blandford says. â€”Lisa Gibson
Standards Status PFI is working diligently on its third-party fuel certification standards.
When Chris Wiberg was introduced at the Pellet Fuels Institute Annual Conference to update attendees on PFIâ€™s standards and thirdparty certification system, it was said that he has spent thousands of hours on the project. Taking the stage, Wiberg, chief operations officer of Twin Ports Testing and co-chair of PFIâ€™s Standards Committee, said he wished that were an exaggeration. The process of forming the standards and three-level verification system is arduous, but the benefits to the market and customers of having the standards in place are hard to deny. During his presentation at the conference, held in Ponte Vedra Beach, Fla., from July 24-26, Wiberg addressed changes to the standards that have come about since the draft release in October, which outlined three fuel grades: premium, standard and utility. It specifies parameters for a number of properties including ash content, diameter, durability, fines, moisture and chloride content, among others. In the ash content category, PFIâ€™s premium fuels require 1 percent or less, standard requires 2 percent or less, and utility grade requires 6 percent or less. For moisture content, premium fuels require 8 percent or less, while both standard and utility must be equal to or less than 10 percent. The most important aspect of the system is the third-party audit of those parameters and PFI proposes a three-level verification system, beginning with the pellet mill itself. The second verification comes from monthly on-site visits by inspectors who are well-versed in the timber industry, doing other forest product inspections such as lumber grading. Finally, the inspectorsâ€™ assessments will be audited by the accreditation body, which Wiberg announced at the event will be the American Lumber Standard Committee. â€œIâ€™m feeling confident that they are the right body,â€? he said.
Wiberg also walked the audience through what he called â€œsemantic-type changesâ€? to the draft documents. For instance, in the program document, â€œcertification bodyâ€? was changed to â€œaccreditation body,â€? â€œcertified fuelâ€? is now â€œgraded fuel,â€? and â€œcertifiedâ€? is now â€œqualified.â€? â€œBottom line is, nothing changed in all of that, but we ended up with a lot of red ink,â€? Wiberg joked. Also, internal laboratories at mills are no longer required, he announced, the standards specification document has been restructured, and the inspection and re-inspection criteria have been altered. Now, a product must be within 95 percent compliance for grade qualification. And the cost of compliance will differ from mill to mill, Wiberg said. Factors to consider include the PFI enrollment and operations fee; internal lab quality assessment and quality control program development; third-party lab and testing services; auditing services; and ALSCâ€™s administration costs. Wiberg estimated it will cost 50 to 70 cents per ton. The annual conference also included a symposium detailing the standards for pellet manufacturers and compliance with the program. Program presentations are available at www.pelletheat.org. PFI hopes that the standards will be adopted by appliance manufacturers who will outline the use of certain grades and void warranties where the specifications arenâ€™t followed. Moving forward, the standards committee will finalize the language in the agreement with ALSC; and ALSC and PFI boards will need to review, approve and sign the agreement. A timeline for the release and implementation of the standards is hard to nail down, Wiberg said. â€”Lisa Gibson SEPTEMBER 2011 | BIOMASS POWER & THERMAL 17
Energy Options The Energy & Environmental Research Center’s Biomass ’11: Renewable Power, Fuels, and Chemicals Conference, which was held July 26-27 in Grand Forks, N.D., welcomed more than 250 attendees from 28 states, Washington, D.C., and 11 foreign countries, to discuss trends, opportunities, economics and technological developments surrounding the biomass energy industry. The underlying theme during the first day of the conference seemed to be that while next-generation biofuels hold a great deal of promise, commercialization is still a ways off and smaller-scale biomass-based heat and power remains the most economically feasible option. EERC Director Gerald Groenewold kicked off the ninth annual conference by discussing the EERC's mission and current areas of focus. The EERC, which is a nonprofit, high-tech division of the University of North Dakota, focuses on applied research, development, demonstration and commercialization of clean energy and environmental technologies. The center has been involved in more than 300 RENEWABLE REALM: The Energy and Environmental Research Center contracts over the past year, according to Groenewold, 87 percent of held its annual biomass conference in Grand Forks, N.D., in July. which were private-sector clients. The EERC has had clients from all 50 states and 51 countries, he added. Groenewold said. “We have Canadian friends who provide a lot “As an American citizen, if we’re talking about energy of energy to this country and they’re going to continue to, and the security, I don’t believe in the concept of energy independence,”
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Biomass is not a silver bullet but it plays a key energy role.
same thing is true for a few other places around the world. To be energy secure, we need a portfolio of all kinds of energy technologies; we need to look at every possible option.” With biomass utilization there are lots of challenges, but there are also lots of opportunities, Groenewold said. “Biomass has key roles to play, but it’s not a silver bullet,” he said. For biomass power generation specifically, Groenewold says power plants between 10 and 15 megawatts (MW) are a realistic expectation in terms of feasible development in the U.S. “Larger plants won’t be a factor in the U.S., not in the foreseeable future.” Groenewold discussed some key biomass projects the EERC is involved in, including a program focused on small distributed power generation—100- to 500-kilowatt gasifier systems for electric power that run on feedstocks such as turkey litter—and large-scale biomass gasification, in which he said EERC was seeing significant financial interest, mostly from China and India. Following Groenewold’s presentation, U.S. Sen. John Hoeven, R-N.D., addressed attendees via video message, touching on North Dakota’s comprehensive energy plan and how he’s working with federal policymakers to craft a similar national policy. “We recognized we need all of our nation’s resources to build our energy future, including fuel and electricity from biomass,” he said. He added that North Dakota has great potential for the production of dedicated energy crops and crop residues, and that its current energy policy encourages investment in projects that utilize them and other renewable energy technologies.
Chris Zygarlicke, deputy associate director for research at the EERC, addressed trends and opportunities in biomass. Fossil fuels will dominate until around 2030, he said. Natural gas leads energy source growth with about a 2 percent increase each year, he said, “and that’s having an impact on biomass and renewables. Renewables have seen some growth, but it’s small.” The main challenges for biomass growth are related to feedstock and its high cost, particularly issues related to processing, and inconsistencies in rules, regulations and policies that will help propel biomass energy forward, Zygarlicke said. “Will it grow? Yes, but it’ll grow along with all the rest of the [renewable] resources.” In terms of biopower development in the U.S., Zygarlicke said that there is really no interest from large-scale fossil baseload utilities. “That’s because we don’t have the incentives that Europe has, where they’ll pay per ton of carbon that’s alleviated from going into the atmosphere,” he said. “If we did, that would definitely bring interest to the larger scale utilities. However, smaller scale, industrial heat and power does have continued interest.” Small biopower will keep growing under the radar, from Zygarlicke’s perspective. “It doesn’t get a lot of publicity, but development of smaller plants—distributed energy or larger 15- to 20-MW combustion systems, will continue,” he said. “Larger-scale cofiring/ refiring projects will continue to wait in the wings until we see the incentives, and biofuels still need to be proved technologically at commercial scale.” —Anna Austin
20 BIOMASS POWER & THERMAL | SEPTEMBER 2011
Pellets Despite a decline in its paper product sector, Wisconsin holds the reins to an industry that shows enormous potential for cofiring with fossil fuels: pellets made from industrial paper waste. BY LISA GIBSON PHOTOS BY MIKE ROEMER
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 21
ROLLS OF RAW MATERIAL: Greenwood's pellets are made from paper, label material and poly-coated flexible film waste.
ith both a comparable price and the ability to be handled just like coal, as well as resistance to weather-related degradation, paper pellet biomass fuel was the only choice for Manitowoc Public Utilities, a small Wisconsin electricity provider. The ratepayer-owned utility is located in the small city of Manitowoc on the eastern border Wisconsin shares with Lake Michigan. MPU serves about 16,000 customers and cofires around 15 percent paper biomass pellets with petroleum coke and
coal in the circulating fluidized bed boilers employed at its main power plant on Columbus Street, according to MPU’s Power Production Manager Red Jones. “The paper pellets have been great for us because they help us handle wet fuel,” he says. “When our petroleum coke gets wet, one of the things that makes it a lot easier for us is to put quite a bit of paper pellets in at that time. Not only does it tend to suck up some of the moisture, but it literally makes the product flow better so we have a lot less bridging and blockages.”
22 BIOMASS POWER & THERMAL | SEPTEMBER 2011
Because of a Wisconsin incineration rule, MPU is not allowed to use more than 30 percent biomass in its fuel mixture. Still, cofiring paper pellets almost completely meets the utility’s obligations under the Midwest Renewable Energy Trading System. “We end up satisfying our renewable energy quotas using this and other sources as well, most of that being purchased,” Jones says, adding that the percentage of biomass burned depends completely on the supply. Fortunately, MPU is in Wisconsin, where a once-booming paper product in-
dustry set the stage for an industrial paper waste biomass sector.
Paper Pushers “We’re in what’s called the ‘paper valley’ here,” says Lee Robbert, founder and owner of Pellet America, an Appleton, Wis.-based paper pellet manufacturer. Well, technically Appleton is in Fox Valley, categorized by its position along the Fox River, but the region used to be packed with paper companies, now only boasting about half what it once did, according to Robbert. In fact, Pellet America says Wisconsin fostered the start of the paper pellet industry, beginning with a paper
FEEDING THE FIRE: Greenwood sells its product for use in cofiring with coal and other biomass.
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 23
A MOVING EXPERIENCE: The production of paper pellets is much the same as that of wood pellets, including the conveyance systems.
PELLET PRODUCTION: Greenwood is increasing production from 200 to 400 tons of pellets per day.
24 BIOMASS POWER & THERMAL | SEPTEMBER 2011
company looking for a way to successfully burn its waste paper for fuel. The use of the fuel has spread since its invention and other paper pellet manufacturers do exist in the U.S., but Robbert says making a profit and finding customers can be a challenge. PAPER PIONEER: Still, Pellet America thrives, proTed Hansen, ducing up to 1,000 tons of padirector of operations for per pellets per week from 1,000 Greenwood, tons of industrial scrap material. says all of the That includes waste from paper feedstock used is nonrecyclable and companies, printing companies, would be landfilled if converting companies and label it weren't converted makers, among others. to pellets. And itâ€™s not the only paper pellet manufacturer in the state. Greenwood Fuels LLC
IDENTICAL EQUIPMENT: The mixing and sorting processes are the only fundamental differences between production of pellets from wood and from paper.
PAPER POWER: Greenwood sells its paper pellets to utilities, universities and paper mills.
in Green Bay produces 200 tons of pellets per day and is in the process of ramping up to 400 tons per day, according to Ted Hansen, director of operations for Greenwood. The mill just started up in January but business is going so well that the company is looking to build another mill in Ohio, where it is currently sending some pellets for testing, Hansen says. “We’re very eager to expand.” Feedstock for Greenwood’s pellets is comprised of about one-third each of paper, label material and poly-coated flexible film waste. “We’re open to anything that’s classified as an industrial waste,” Hansen says. The company uses no post-consumer waste, allowing the fuel to qualify as a renewable fuel in the state of Wisconsin. “Anyone who burns our pellets is not considered to be an incinerator,” he says.
All the feedstock Greenwood uses is nonrecyclable and would otherwise end up in a landfill. It consists of cellulose, plastics, adhesives and a few other trace clean-burning materials, Hansen says, but mostly polypropylene, polyethylene, polyester, nylon, paper and adhesives from items such as labels. “The U.S. is obsessed with labels,” he laughs. All the materials coming in are currently dry, but Greenwood is experimenting with a drying process to expand feedstock capabilities. “Similar to woody biomass, we’ll have a drying operation to allow us to take more of those wet materials,” Hansen says. In fact, the process for pelletizing paper is much the same as that for pelletizing wood, both Hansen and Robbert say. “It’s fairly simple,” Hansen adds, explaining how it begins with sorting of the materials. “We
tend to sort them by fiber content, plastic content, moisture content and adhesive content,” Hansen says. Then, the sorted material is mixed and chopped, mixed and chopped again, and then pelletized in a mill identical to that of a wood pellet plant. The fresh pellets are then put through a cooler and shaker to get rid of fines, and then stored in silos, he explains. The fundamental difference between wood and paper pelletization, as can be deduced from an explanation of the process, is the fact that wood pellets generally are made with a more homogenous feedstock selection. “Whereas we’re dealing with a lot of material that has extreme swings in density,” Hansen explains. That wide array of feedstocks makes the mixing and sorting a fundamental aspect of the manufacturing process.
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 25
'We don’t really look at our materials as being better or worse than others. It’s just another technology that sometimes bridges the gap between the customer being able to start moving away from coal, or burning wet biomass.' —Ted Hansen, director of operations, Greenwood Fuels LLC
TO MATERIAL HANDLING
Both Greenwood Fuels and Pellet America provide paper pellets for companies cofiring with either coal or other forms of biomass, and mostly in Wisconsin. Their customer base includes paper mills and the state of Wisconsin, which cofires the pellets at universities and a prison. They both also provide pellets to MPU.
Paper Pellet Properties
TO WET OR DRY STORAGE
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MPU has cofired paper pellets in its boilers since before Jones was employed there 12 years ago. “We have been offered wood pellets in the past, but they really haven’t been price competitive,” he says. Robbert insists the price of paper pellets is one direct benefit and a main lure for customers. “You have to fit in the niche of cheaper than coal to get anybody’s interest,” he says. He adds that Pellet America’s product has little sulfur. “That makes them a little more attractive,” he says. Coal has a fair amount of sulfur and since paper doesn’t, boiler operators can blend the cheap, low-sulfur paper pellets to offset the coal’s sulfur emissions, he says. With new technologies, though, sulfur is less of an issue than it was when Pellet America got its start in the early ’90s. Hansen would add that the paper pellets bring a reduction in nitrogen oxide, as well, and sometimes even in hydrogen chloride. As with all power-producing feedstocks, Btu value is always a crucial factor. Hansen says in its mixing process, Greenwood Fuels aims for 11,000 Btu per pound, comparable to most coal products. And of course, a determining factor when choosing a feedstock to cofire is its ability to handle and store similar to its fellow fuel. It sounds like there are no problems in that arena, either. The densified paper fuel handles almost identically to coal in most moving grate boilers, Hansen says,
26 BIOMASS POWER & THERMAL | SEPTEMBER 2011
adding that he has no customers consistently burning in a pulverized coal boiler. But it would be possible, he believes, to cofire a 5 to 10 percent mixture in a pulverized boiler. “Can pulverized coal burn paper?” Jones offers. “Certainly, there is a way to make it happen, but you’re going to have to overcome a couple hurdles with that I think.” Other boilers can handle up to 30 percent blends with no equipment tailoring. “Basically, the whole process is to try to make a pellet that handles the same as coal,” Robbert says. MPU stores its paper pellets outdoors and while a small amount of degradation does occur from the elements, Jones says it’s not significant. “Even with really heavy rain, the paper pellets usually hold up pretty well.” And an added benefit is the fact that paper doesn’t emit any foul odors. “We are right below a high school, and so they could literally hit us with an orange juice carton, and often do,” Jones says, adding that the school has had no odor complaints. “The paper pellets don’t smell.” The size of the paper pellets MPU accepts varies, but only slightly. Pellet America provides a three-quarter-inch pellet, which blends well with Greenwood Fuels’ one-half-inch pellet, Jones explains. MPU has a special blending pit for the paper pellets, but has run them through the normal coal-processing stream as well. The size requirement for MPU is three-quarter-inch minus, putting the utility in what Jones calls “the sweet spot” with regard to paper pellets.
Endless Possibilities With so many benefits, it can be a little difficult to come up with explanations why more utilities, paper mills and universities aren’t cofiring biomass, whether it’s
PELLETS¦ made from paper waste or wood. Jones offers proximity to suppliers as a possible reason, but leans on pricing as the biggest hurdle. “The only other thing I could see is if you’ve got a pulverized coal unit, [paper pellets] are not going to grind like coal,” he says. “It tends to be more flexible and it’s not really going to break up like that.” The paper pellets are better suited for stoker or circulating fluidized bed boilers, he suggests, where fuel sizing is much more coarse. “When we first started in ’92, we thought we had the next best thing to sliced bread,” Robbert says. But to even test burn a biomass product in a fossil fuel-fired boiler, a modification to the existing permit is required and can be a nightmare. “Nobody wants to deal with that,” he says. In addition, confusion arises over what the difference is between burning a manufactured industrial paper waste pellet and burning garbage. “And the difference, of course, is the fact that we’re monitoring everything that goes in, whereas they couldn’t do that with garbage,” Robbert explains. The paper pellets manufactured at mills like Greenwood and Pellet America offer a way to get power plants “off the starting blocks,” Hansen says, particularly if they want to reduce technical or economic risks in their cofiring endeavors. “I look at us as a bridge technology,” he says. “In many cases, we’re the first step that a customer takes to start moving away from burning coal.” The paper fuel also is a good option for boilers burning wet biomass, as the pellets make igniting easier, thereby improving boiler operation. “We don’t really look at our materials as being better or worse than others,” Hansen concludes. “It’s just another technology that sometimes bridges the gap between the customer being able to start moving away from coal, or burning wet biomass.” Author: Lisa Gibson Associate Editor, Biomass Power & Thermal (701) 738-4952 firstname.lastname@example.org
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28 BIOMASS POWER & THERMAL | SEPTEMBER 2011
Glorified, Torrefied & Cofired
Cofiring torrefied biomass with coal seems like a great way to reduce emissions, but is it economical? BY ANNA AUSTIN
TOPS IN TORREFACTION: Topell Energy, a Dutch company, recently completed a 60,000-ton torrefaction plant in the Netherlands, which could be the largest plant in the world.
ver the past few years, many small torrefaction technology companies have popped up across the U.S. While some have made progress, others have disappeared as quickly as they started. While the science behind torrefaction is not in question, it seems there are two major roadblocks for most companies trying to economically produce a product that will serve as a cofired or standalone fuel—overcoming the confusion surrounding the economics of torrefaction, and coming up with the cash to prove their process on a meaningful scale. In Europe, where coal/biomass cofiring is common and carbon reduction incentives are enticing, large-scale torrefaction plants are being built. That’s a different scenario than in the U.S., where small startup companies are mostly working on pilot- and demonstration-scale units. Dutch clean tech company Topell Energy recently completed what it believes is the largest torrefaction plant in the world, a 60,000-ton facility now operating in the Netherlands. While Topell has plenty of European customers, the company believes there is great potential outside of the country, particularly in North America. But, as Robin Post van der Burg, director of business development at Topell, points out, considerable confusion still surrounds the mass and energy balance of torrefaction. “People looking at torrefaction will find that there isn’t a lot of credible information out there,” he says. When evaluating mass and en-
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SEPTEMBER 2011 | BIOMASS POWER & THERMAL 29
¦TORREFACTION ergy balances, there are three things that need to be looked at, according to van der Burg. The first is the thermal balance, or how much thermal energy comes out of a forest versus what comes out of the torrefaction process. “There’s a general understanding that you lose 20 percent of the bone-dry biomass, and that you also lose 20 percent of the thermal value, but that isn’t the case,” he says. “You have a 95 percent-plus thermal efficiency, and this is due to the nonlinear relationship between the moisture value and the heating value when you dry off the water. Beginning with 50 percent moisture, 5,000 Btu per pound, you would expect that it would go to 9,000 Btu at 0 percent moisture, but you actually get 10,000 Btu. There’s a bonus from driving off moisture, and that’s why the thermal efficiency of this process is so high.” Hiroshi Morihara, CEO of Oregon-based torrefaction technology developer HM3 Energy Inc., says what makes up for lost energy, depends on how one looks at it— whether the energy content is reduced or increased. “When you torrefy, 10 percent of the wood energy TORREFIED TECHNOLOGY: HM3 is building a torrefied biomass demonstration will vaporize,” he explains. facility in Troutdale, Ore., and has plans to That 10 percent of energy build a commercial-scale plant in Prineville, Ore.
has 30 percent of the mass of the wood, but the heat is used to dry the incoming feedstock that is normally 40 to 50 percent moisture, so that helps with the cost of the process. Though you lose 30 percent of the mass and 10 percent of the energy, the product we produce is about 20 percent more energy intense than regular wood pellets, and compared to Western coal, the heating value is very similar, about 10,000 Btu per pound.” He adds that coal typically has about 25 percent moisture, which must be vaporized and requires energy. “That’s not the case with our product, so we have 20 percent more net energy on a per pound basis.” The second thing to consider in torrefaction economics is the power balance, or how much energy is needed to convert biomass into biocoal. “This is a function of your reactor technology,” van der Burg explains. “In our case, it’s only 2 to 2.5 percent of the total energy output. In other words, if 1 ton of product has 6 megawatts (MW) of thermal output capacity, we use only about 150 kilowatts to produce that, or even less. Only 2 to 2.5 percent is lost in power needed for the process.” The third important factor is the life-cycle analysis, or the total amount of CO2 emitted in the whole production process, including the diesel used in the chipping process, trucks that bring the biomass to the plant, power consumed in the plant and fuel when shipped. “If you take that into account, it’s in the same league as wind and solar,” van der Burg says. “We meet the same sustainability standards, but it’s a way cheaper solution and it’s baseload. That’s why in the EU, more and more companies are starting to understand that in the next de-
COST COMPARISON: The total cost savings of the torrefied pellet (TP) value chain over the wood pellet (WP) value chain
cade biomass will be the major contributor in building up sustainable energy, and not so much wind and solar.” Outside of the mass and energy balances, power producers that utilize coal look at torrefied biomass for its attractive physical properties. These include power utilities, but also smaller institutions such as universities.
Coal’s Match … MIA? The University of North Carolina has a goal of phasing out coal by 2020 and for the past couple of years has been searching for the cleanest, most cost-effective replacement. While wood pellet test burns have been conducted—results of which are still pending— UNC has also considered torrefied pellets. “The attractions are a high
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¦TORREFACTION heat density—similar to that of coal—and the physical property of being hydrophobic so it can be shipped in open containers and stored outside,” says Ray DuBose, UNC director of energy services. “We’re looking for something that will flow through our existing systems.” The energy plant at UNC was built in 1991, so it’s relatively young for a coal-fired plant. “There’s a lot of life left in the existing equipment, and torrefied biomass would al-
low us to avoid retrofit costs,” DuBose says. The initial problem associated with torrefied biomass experimentation has been securing a supply. “We’ve bid it twice now, and we’re still reviewing bids from the second round, but it doesn’t appear that anyone [in the U.S.] is producing torrefied wood on a regular basis,” DuBose says. “We’ve been contacted by a number of companies, but we can’t find anyone who has a regular supply.” The Tennessee Valley Authority—a
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government-owned power utility—has been conducting biomass/coal cofiring tests for the past several decades, and also has an interest in torrefied pellets. Unfortunately, it has run into the same problem as UNC. “There doesn’t seem to be enough material, or supply,” says Daryl Williams, head of renewable energy at TVA. “We needed a couple thousand tons for test burns at our plant in north Alabama, and we had a few vendors promising that, but when it came down to it they couldn’t provide it.” While TVA has put biomass testing on hold until regulatory uncertainties become clear, Williams says he expects that torrefied wood pellets would require no real changes to existing materials handling and storage when comilled with coal. “We have received samples of a number of different products, done some lab-scale analysis and compared it to green biomass, and it does have advantages,” he says. “It looks and feels like coal as far as the pulverizer is concerned, and it’s hydrophobic, so we’ll have no problems with insects or rot when it’s stored. One concern we have is cost, but like any new technology, the more advanced it becomes the lower the cost. We’re really curious to see how it will handle and combust at a cofired plant.” Morihara says the reason for the lack of production in the U.S. is that the technology only found its way to the country a few years ago. “It’s a very new concept here, and those working here in the U.S. are small companies. As a result, they’re having a difficult time getting enough money to build commercial plants, whereas in Europe, there are companies that are fairly large and have money to build commercial plants, so they’re already doing it.” HM3 appears to be farther along in development than other U.S. torrefaction companies. It is building a demonstration facility in Troutdale, Ore., has plans for a commercial-scale plant in Prineville, Ore., and has obtained multiple federal grants to help. Moving beyond coal, Morihara points out that torrefied biomass is capable of things that traditional wood pellets aren’t— including being pulverized and blown into the furnaces of coal-fired power plants.
TORREFACTION¦ Why Not Wood? “If you have a 500-MW plant, to retrofit it to also use wood pellets would cost about $300 million,” Morihara says. “If you use torrefied biomass, there is no retrofitting cost. For its Btu content, torrefied biomass may cost 20 percent more, but it has 20 percent more energy so the cost is actually very similar.” Van der Burg agrees there isn’t much difference between wood pellets and torrefied biomass. “Torrefied pellets come cheaper per metric ton, but you get paid for wood pellets and torrefied wood pellets per gigajoule, so considering the 25 to 30 percent higher energy density a torrefied wood pellet has over a regular wood pellet, you see the cost comparison.” In a typical case in the Southeast U.S., considering the whole integrated value chain of the product, van der Burg says wood baskets/assets/fiber baskets that were previously considered idle because they were difficult to get at will become economical because of the enormous reduction in transport costs and substantial increase in energy density. “Transport costs will become much lower than they are for wood pellets, and incomparable for untreated biomass,” he says. “Torrefied wood pellets can be handled with coal infrastructure, in the same coal pile at the same coal mill. To get it there you can transport in open rail cars, to a port where there’s an outside terminal, no warehouses needed, and then load it into a ship and off to Europe, again no need for closed storage. All of this is needed for wood pellets.” Topell and investor RWE Innogy participated in a study that aimed to calculate fuel costs for coal, conventional wood pellets and torrefied pellets at the gate of an ordinary coal plant in Western Europe. In comparing electricity production costs of cofiring (torrefied) pellets with solely coal combustion at the same coal plant, it was found that, in all cases, cofiring torrefied pellets is more costeffective than cofiring conventional wood pellets. The majority of that cost advantage comes from avoided additional capital costs. Regarding electricity production costs, coal
still has a major cost advantage over torrefied pellets, the study finds, but differences can be bridged, and it is likely torrefied pellets will start to compete with coal eventually. “Utilities like RWE are looking at black pellets to replace any wood pellet they can, in the near future,” van der Burg says. “There isn’t serious production of torrefied wood pellets right now, but it’s going to happen. Wood pellets are the best solution at this moment, but there are enormous efficiency
improvements to be made in the next few years.” More people are becoming aware of the correct economics of torrefaction and what the improvements are, van der Burg adds. “They are a lot bigger than people originally thought.” Author: Anna Austin Associate Editor, Biomass Power & Thermal (701) 738-4968 email@example.com
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PHOTO: UNIVERSITY OF MISSOURI IN COLUMBIA
34 BIOMASS POWER & THERMAL | SEPTEMBER 2011
Biomass and Coal:
A Powerful Combination Biomass Power & Thermal investigates potential technical and safety issues involved in storing and handling biomass at cofired power plants. BY ANNA AUSTIN
hen Minnesota Power began cofiring coal and biomass at its power plants in Duluth and Grand Rapids, Minn., more than 20 years ago, they started out combusting 75-25 coal to waste wood ratios. Back then, biomass was plentiful and cheap and it was common to get it for free, says Mike Polzin, renewable fuels coordinator for Minnesota Power. “We started burning wood in Duluth only because a new paper mill had bark they had to get rid of and they didn’t know what to do with it,” he says. That has changed significantly as the years have gone by, as biomass has become a hot commodity. Competition for material has become stiff and in many cases can be pricey. Still, certain incentives that have come into play during that time—such as state renewable energy credits—make it enticing for power utilities such as Minnesota Power to use more biomass. And, that’s precisely what the utility has done and continues to do. Today, the facility in Grand Rapids produces about 25 megawatts (MW) of electricity from a 15-85 coal to biomass ratio, and the Duluth facility typically generates about 50 MW from a 10-90 coal to biomass ratio. UsSEPTEMBER 2011 | BIOMASS POWER & THERMAL 35
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ing that much biomass at facilities that were meant for coal hasn’t come without its challenges, Polzin says, the biggest of which are related to materials handling and storage. While it won’t be the case at every facility, so far, there have been ways around these challenges.
Storage Situation Biomass can be bulky and requires a lot of space, but storing it isn’t as simple as just finding more space—it must be kept dry, hence requiring some type of covered storage system. “The biggest challenge has been on-site storage,” Polzin says. “We just don’t have enough of it—we’re at 90 percent biomass at Duluth, but site storage is much too small.” That necessitates deliveries of biomass seven days a week, a process which Polzin is charged with facilitating. “We have about 900 tons of on-site storage, but we burn over 1,000 tons of biomass each day,” he explains. “So it’s there only for a number of hours. We dump it into a large building then pull it back out to be used; all the wood that comes in and gets stored is gone in 24 hours or less.” Getting the appropriate amount of deliveries each day is where the challenge lies, as the weather can create havoc on timber harvesting. “Significant snow or rain handicaps loggers from getting into the woods and bringing materials to us, and spring road restrictions can also create problems,” Polzin says. When there isn’t enough stored fuel, it could mean a shortage. To mitigate that problem, Minnesota Power has 50 possible suppliers, and requires only two to three truckloads per day from a given supplier. “They have the potential to put out five or six [truckloads], but if we can get two or three from several suppliers, we make sure we can always get enough to satisfy our appetite for wood,” Polzin says. “We suggest that our suppliers have more than one market to deliver to, because inevitably we will have to go off-line due to plant outages, equipment failures and things like that. That way, they can reroute deliveries to another market. If those other markets have outages, they can deliver more to us.” However, if a situation does arise where they can't secure enough wood—and it does happen—it’s just a matter of calling for more coal. “[Using more coal] doesn’t create any problems with our infrastructure,” Polzin says. “There are large coal suppliers close to both facilities, so we can get more coal within two hours, to keep us online.” Bruce Browers, senior engineer at Barr Engineering, agrees that storage is one of the biggest challenges in cofiring. Last summer, Barr completed biomass cube test burns at Wyandotte Municipal Services in Wyandotte, Mich., and says if the company were to cofire biomass for the long-term, the current storage system would have to be significantly modified. “[Biomass] doesn’t stand up to moisture,” says Browers, who, coincidentally, was a project manager at Minnesota Power when its plants were built in the mid-1980s. “Pulp and paper guys who burn waste biomass
LOGISTICS¦ fuel have different fuel handling systems and somewhat different boilers so it can sit out in the snow and rain in those situations, but when you’re dealing with a processed biomass fuel, it has to be stored.” Adding a new biomass storage system to an existing coal plant can be costly. “We’ve seen fuel handling yards as cheap as $12 million, to all the way up to $50 million,” Browers says. “It’s a very expensive part of burning biomass; using biomass as you get it doesn’t work everywhere, and there isn’t always an active forest products residuals industry. The whole volume of storage becomes a critical driver. It’s a huge issue.” Since the biomass is used so quickly at Minnesota Power, potential storage issues such as molding aren’t relevant. At other large-scale cofiring operations, which are common in the U.K., molding and caking are potential problems when the biomass and coal are mixed and stored together.
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¦LOGISTICS coal—typically wet on the surface at 6 to 10 percent moisture—with biomass, which is often 10 percent water, the biomass sucks in all the water and that leaves the coal dry and dusty. Hence, you get much more coal dust emissions when you cohandle.” In addition, biomass has its own dust content, so even materials that have low dust tend to break down in handling and produce dust, Bradley says. “Both coal and biomass dusts are a serious explosion hazard. With the dust on cohandled coal and biomass being more mobile than on coal alone, it can easily create [hazardous] conditions in a plant.” These types of explosions occur when a mix of combustible dust and air are ignited by a hot surface or spark. “Usually this happens locally at first, typically due to an overheating bearing, a static discharge or someone doing some grinding or welding,” Bradley explains. “The draught from that small initial explosion whips accumulated dust up off the floor and other flat surfaces, creating an explosive mix of dust
and air—then a fireball sweeps through the whole building in seconds, devastating all before it.” Polzin agrees that dust can create a hazardous situation. At Minnesota Power’s Duluth facility, all of the conveyors are covered with metal, horseshoe-shaped hoods so dust cannot be blown off the conveyors. “The storage facility is completely closed, so we don’t get a lot of fugitive dust blowing around,” he says. “We have a large truck dump where, when a surge of wood is dumped from the truck into the bin or receiving hopper, it creates a dust plume, so we have some vacuums to help mitigate or minimize that.” Additionally, the company’s operating permit requires dust minimization in the entire area of the plant, so parking lots and roads are paved, and a street sweeper is used to sweep up loose dust and wood chips. The situation is similar at the Grand Rapids plant. “We’re sensitive to dust blowing around; we don’t like a lot of fines,” Polzin says. “The reason we have a hog
fuel grinder at each facility is because we’d rather have material come to us at a larger size initially, so it doesn’t blow around.” Once biomass is ready to enter the plant, another slew of potential problems can surface, including fuel feed system issues.
Other Potential Issues Biomass won’t always flow smoothly through a feeding system meant for coal for a number of reasons, one of which is winter weather conditions. “On the biomass side, [frozen] wood going through our chutes and storage system is a big problem because it tends to bridge and plug up the system because in the winter it often comes in frozen chunks,” Polzin says. Plant attendants usually realize that not enough wood is getting into the boiler when the heat rate can’t be sustained, or bin indicators sound an alarm. “We simply have to go out there and ram the wood through,” he says. “We have customized some hatch doors that we open, and then we poke and prod
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LOGISTICS¦ the wood with long rods until it is muscled through.” At Wyandotte in Michigan, which has a 25-MW circulating fluidized bed (CFB) system designed to burn coal and tire-derived fuel (TDF), Browers says the plan going into the test burns was to do 30 and 60 percent biomass ratios. Due to the limestone feeder capabilities, however, the tests had to be modified to 15 percent. “[Running the biomass through the limestone feeder] wasn’t the best way we could do the test burns, but it was about the only way,” Browers says. Since there was no way to get the desired blend out in the coal yard, the only way get it was to let the fuel feeders take the coal and TDF, and put the biomass fuel in the limestone feeders. “The measuring device coming out of the feeders allows us to control the blend.” A 60 percent blend would have worked fine in the boiler, he adds, but it wasn’t feasible because of the delivery issues with the limestone system. Another issue Browers says that needs attention are potential sparklers. “Sparklers are what happen when you burn biomass in a CFB or stoker,” he explains. “There are a lot of particles to it, and they don’t always combust where they are supposed to. They can carry over from the bed into the convection pass, and you don’t want combustion in there.” Attendants must physically open the boiler door to check for sparklers. When they do occur, it indicates a couple of problems—inefficient combustion, and carryover of carbon particles. “Then you have to worry about fires,” Browers says. “There isn’t enough to explode, but as it falls out in your duct work or gets removed in your particulate removal device, you’ve got carbon particles in there and they’re susceptible to fires.” Overall, Browers says that cofiring isn’t all that simple. “People who think it’s easy to chip raw biomass and run it through their coal system may want to rethink that assumption,” he says. In fact, it can take a long time to work out the kinks. Even at Minnesota Power, which has been cofiring for decades, the
company is working to optimize its cofiring operations, according to Polzin. In an upcoming project that will take place over the next couple of years, the company will put in new feeders, more robust material handling systems and more storage, though biomass deliveries will have to be more coordinated than ever with the near doubling of biomass consumed at each plant. Unlike the U.K., cofiring biomass with coal in the U.S. is still largely in the testing phases, and many utilities that have
been interested in cofiring in the past have slowed down plans due to regulatory uncertainties surrounding biomass. “More incentives are needed,” Browers adds. “There is a lot of talk here about cofiring, but if you look at who has actually done it, there aren’t many.” Author: Anna Austin Associate Editor, Biomass Power & Thermal (701) 738-4968 firstname.lastname@example.org
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COFIRING COMBO: The University of Missouri in Columbia cofires up to 15 percent wood chips with coal. PHOTO: UNIVERSITY OF MISSOURI IN COLUMBIA
40 BIOMASS POWER & THERMAL | SEPTEMBER 2011
Co-Combustion While cofiring woody biomass with coal is more common on a testing scale than commercial, most issues related to co-combustion within the boiler can be alleviated with proper fuel sizing and blending. BY LISA GIBSON
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 41
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PHOTO: UNIVERSITY OF MISSOURI IN COLUMBIA
ith so few U.S. coal utilities cofiring woody biomass, the practice must be fraught with combustionrelated problems, right? Not so. Fortunately, the co-combustion aspect itself, for most boilers, is surprisingly free of any detrimental issues that can’t be mitigated through proper material sizing and feedstock blending. That, however, requires a timely and often expensive trial-and-error process. “Everyone wants to [cofire], but nobody wants to spend a lot of money,” says Bill Stirgwolt, manager of biomass engineering for boiler designer and manu- COFIRING IN COLUMBIA: After conducting years of cofiring tests, the University of Missouri in Columbia is installing a 100 percent biomass boiler, while continuing to cofire in its coal boilers. facturer The Babcock & Wilcox Power Generation Group Inc. Cofiring is a simple-enough process, but Stirgwolt cautions, Paper mills have for years, and in some cases decades, successfully fired bark with pulverized coal, he adds. “To do that, the boiler is “If you want to cofire biomass, you can’t put blinders on.” designed with a grate and the course fuel is fed into the lower part of the furnace and burnt on a grate, and above it would be pulver- Size and Blend Solution “You have to get the fuel sized properly, and that’s not easy ized coal burners.” But paper mills aren’t necessarily as concerned with efficiency to do,” Stirgwolt says. “If you can make the particle size small, the as much as they are with generating steam for internal plant con- biomass burns readily. If it’s not small, then you’re going to have sumption. “The challenge is when you try to make it look like, or combustion issues.” The main problem with a biomass fuel that’s too big is the fire like, a pulverized coal,” he says. “Those folks are asking, ‘How can I get as much energy without compromising the combustion unburned carbon. The residence time for a pulverized coal furnace is short and does not provide for ample burning of larger biomass, process or taking a hit on efficiency?’”
COFIRING¦ Stirgwolt says. Under ideal circumstances, biomass devolatilizes and the fixed carbon burns out. “If you don’t have enough time for the fixed carbon to burn out, it will carry over to the convection pass, the air heaters or particulate capture device.” When hot, unburned carbon or char from oversized fuel enters an air heater precipitator or baghouse, it leaves disconcertingly high probabilities of fire, needing only a small leak that provides a source of air, Stirgwolt cautions. “If you want to fire biomass in a burner, it all comes down to size reduction.” Perhaps just as important as fuel particle sizing is fuel blending. Without uniform size and quality, biomass material can cause bridging and plugging in the combustion process, specifically ground woody biomass, according to Gregg Coffin, superintendent of the University of Missouri in Columbia power plant. Such materials tend to create flow blockages, he adds. The university has four coal-fired stoker boilers that cofire up to a 15 percent blend of woody biomass. Coffin says problems have arisen mainly in biomass fuel procurement and blending, with little difficulty on the combustion end. “A good, clean wood chip product was sized very well to blend with our coal,” he says. “They burn well. We didn’t have any combustion issues, environmental issues or operational issues.” The process for settling into the proper fuel size and blend for a specific boiler is, unfortunately, trial and error, both Coffin and Stirgwolt agree. One of the first problems the University of Missouri encountered was the lower density of woody biomass in comparison with coal. The plant uses a batch-style scale to measure the fuel—both coal and biomass—going into the furnace, he explains. “It is designed to know when it’s full by weight. So as soon as you start introducing a significant amount of wood chips at a much lower density and larger volume, they would overfill.” All that was required to fix the problem, however, was an adjustment to the scales and fuel feed.
So far, the best results for the university have come with a feedstock of mill residue from wood products manufacturing facilities, delivered in well-sized and uniform quality chips. The 66-megawatt combined-heat-andpower plant produces about 60 percent of the campus’s electricity needs and 100 percent of its steam requirements. With more than 14 million square feet of facilities including a research hospital, a Department of Veterans Affairs hospital and a veterinary hospital, that’s no small feat. The school is replacing the plant’s aging fuel handling system, as well as a coal-fired boiler, and is taking that opportunity to install a 100 percent biomass boiler and associated fuel system, Coffin says. The bubbling fluidized bed boiler will burn primarily wood chips, initially about 90 percent coming from mill residue and 10 percent from tree tops and branches. The system will also use agri-
cultural residues such as corncobs and some energy crops including switchgrass and miscanthus. “With the new coal system and new biomass system, we’ll have a much better way to meter-blend the wood chips with coal for cofiring in the existing plant, as well as a nice conveyor system for the new boiler,” Coffin says. Coffin’s advice for conquering that trial-and-error headache is to first identify the fuel source and size for the furnace, and then start slowly with small blends, incrementally increasing until the first challenges arise. “Then you either correct those challenges or you back off to where you find where the appropriate blend ratio is for your plant.”
Moisture and Ash The proper fuel blend can also mitigate issues related to moisture content
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 43
PHOTO: UNIVERSITY OF MISSOURI IN COLUMBIA
do the retrofitting that allows you to feed wood in separately from the coal and that appears to be the most effective way in a pulverized coal boiler.” The best long-term solution, he adds, is using torrefied wood, as it becomes coal-like and hydrophobic, but the material still comes at a high price and finding a large enough supply to conduct adequate testing could present a challenge. Moisture content is simpler to deal with in fluidized bed boilers than pulverized coal boilers, as fluidized bed boilers are not as susceptible to problems caused by clumping. Still, Stirgwolt says moisture is only an issue when cofiring large amounts of biomass. “Moisture content can be a problem, but it really has to do with the fact that a lot of biomass material has more moisture than coal,” says Michael Goerndt, postdoctoral fellow in the University of Missouri’s Department of BRAND NEW BOILER: The installation of a 100 percent biomass boiler and fuel system on the university's Columbia campus will also allow for better meter blending of wood chips Forestry. The extent of the disruption moisture with coal for cofiring in the existing boilers. content causes depends heavily on, of course, how the material is stored, but also the type in the combustion process. Too much moisture in the wood of material. Pellets, he says, have lower moisture content than can cause clumping, especially in pulverized coal burners, ac- chips, although it is harder to break pellets down smaller than cording to Tom Kimmerer, senior scientist at Moore Ventures their individual constituents. LLC. To avoid that, he explains, pulverized coal boiler operators But even with the use of wood chips, Coffin says the unihave three options: mixing wood and coal before pulverization, versity hasn’t experienced the moisture problems it had anticiwhich is generally not a good idea; mixing after pulverization; or pated, although the chips’ lower Btu value in comparison with injecting the wood into a separate burner from the coal, which coal’s, warranted some system adjustments. “You have to reccould be the best option. “These boilers have more than one ognize that and adjust your air flow as well as understand the burner,” Kimmerer says. “You can open up a port when you impact to your steam capacity,” he says.
44 BIOMASS POWER & THERMAL | SEPTEMBER 2011
COFIRING¦ Ash content in cofiring also proved to be a nonissue for the school, but it has a tendency to wreak havoc on heat transfer surface maintenance and cleaning, in some instances. “There are certain types of biomass that may want to slag, so it would create a drippy fouling in the furnace itself that can be difficult to clean,” Stirgwolt says, adding that additional cleaning devices in the furnace might be needed. In cooler regions of the boiler, dry ash could also deposit on the heat transfer surface requiring additional soot-blowing equipment or an increase in blowing frequency. No large difference exists between ash content of wood and that of coal, and, in fact, coal probably has more, Stirgwolt says. The trick is the nature of the ash once it’s fired. “Does it make a more difficult-to-clean combustion product?”
energy credits. “Over the past two to three ferred a portion of our fuel budget from years, we’ve had a tremendous amount of out-of-state coal expense to in-state biomass inquiries about ‘How can I fire biomass in expense. That’s regional economic developmy existing pulverized coal-fired utility boil- ment.” As the university expands its use of er?’” Stirgwolt says. “The key here is that a biomass over the next few years, it will make lot of people are investigating biomass co- a significant impact on the number of jobs firing with the thought that they were going in the region and reinvestment of those dolto have to do something for renewable ener- lars back into Missouri. Whatever the reason for minimal biogy credits, but they’ve never moved forward mass/coal cofiring action in the U.S., it with any of the studies.” Goerndt and Coffin attribute the lack doesn’t seem to stem from boiler issues in of a solid U.S. cofiring sector to cost, while the combustion process, as they can be easCoffin also adds availability. “In our case, we ily tackled. “I’ve talked to a lot of people were able to secure our biomass at a compa- who are interested in cofiring and the first thing I tell them is after you identify your rable price to coal,” Coffin says. While Goerndt’s reasoning specifies source and try to determine your sizing, biomass transportation costs, the university your challenge is to figure out how best to sees an advantage in no longer transport- get it blended [to avoid conveyance and ing coal from out of state. “Being a state- boiler problems],” Coffin says. supported public university, it’s always in Author: Lisa Gibson our best interest when we can spend our Associate Editor Biomass Power & Thermal Pondering Potential funds within the state,” Coffin emphasizes. (701) 738-4952 firstname.lastname@example.org Despite the easily mitigated boiler is- “By using biomass in lieu of coal, we transsues that may arise with the co-combustion of wood and coal, the potential for cofiring is enormous and hinges on several significant factors, Goerndt says. Infrastructure for biomass transportation is crucial and is one factor working in the University of Missouri’s favor. Goerndt also lists coal availability and price, as well as woody biomass resource availability. Electricity demand makes the list too, but is only marginBUILD ON OUR EXPERIENCE ally significant. Not surprisingly, the implementation of state renewable portfolio standards is a major factor Goerndt and his colleagues are studying. The university’s School of Natural Resources has conducted a cofiring potential study for 20 states in the Northern region of the U.S., finding that 19 of those 20 had renewable standards as of 2010, giving them higher potential for cofiring. “It was a significant enough variable that we made a pretty fine point about it in our reBULK TRANSFER FACILITIES CONCRETE SILOS port,” he said, adding that the report is not STEEL SILOS CONVEYING SYSTEMS yet released. “It means renewable portfolio STEEL ERECTION STEEL FABRICATION standards are having a significant correlaCRUSHING SYSTEMS PROCESS DESIGN tion with cofiring.” Despite all the clear potential, woody ASI-INDUSTRIAL.COM biomass and coal cofiring remain primarily email@example.com relegated to testing, and Stirgwolt attributes P 406.245.6231 F 406.245.6236 that to a lack of mandates and renewable SEPTEMBER 2011 | BIOMASS POWER & THERMAL 45
Biomass: The Ontario Opportunity Strong tax incentives, a highly trained workforce, ample forestry materials and government investment in research and development make Ontario a great location for biomass power development. BY SHIRLEY TOWNSEND
rom tax credits to stable regulation, public sector support is widely accepted as critical to the economically successful integration of biomass as a source of renewable power. For biomass companies, finding locations where the public sector environment is friendly could be one of the most important factors in designing a sustainable business model. As such, North American companies should not limit themselves to the 50 states. In fact, Ontario, Canada, has emerged as a location with a unique blend of natural resources, regulation and investment programs that make it a business-friendly location with advantages specifically beneficial to biomass power generation.
Strong tax incentives, a highly trained workforce, a surplus of forestry materials and direct government investment in research and development initiatives all contribute to the biomass-friendly culture of Ontario. By embracing the biomass industry, Ontario has cleared a path forward for both national and international companies to pilot in the new era of biomass power generation, and to do so profitably.
The Ontario Biomass Opportunity Ontario could be considered a natural early adopter of the biomass opportunity. The province identified early on that its North American location, forestry industry commu-
The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of Biomass Power & Thermal or its advertisers. All questions pertaining to this article should be directed to the author(s).
46 BIOMASS POWER & THERMAL | SEPTEMBER 2011
nity expertise and vast natural resources would make it an advantageous location for biomass power generation. With fuel prices fluctuating, concerns about North America’s dependence on fossil fuels are increasing. Countries, states and provinces are looking to create innovative energy solutions while strengthening economies. Increasingly, biomass is emerging as an important new source of renewable fuel, and Ontario offers an early blueprint. Leveraging significant investment in research and development and tax incentives, Ontario has begun converting coal plants to biomass generation facilities, including one already operating at Atikokan, in northern Ontario. This early adoption of biomass is not surprising, given that Ontario’s forests cover an area larger than the size of forests in Bel-
gium, France and Germany. With their vast size and excellent track record for sustainable forestry, Ontarioâ€™s forests provide a wealth of high-quality and diverse wood and bioenergy products from a reliable source of renewable and diverse forests. In fact, 80 percent of the total licensed land base has been independently certified to one of the following performance standards: Forest Stewardship Council, the Canadian Standards Association and the American Forest and Paper Associationâ€™s Sustainable Forestry Initiative. Additionally, many Ontario communities offer a labor force that is educated in the processing of wood and related wood products and outputs. The value-added wood products field represents one such industry, and it makes up 60 percent of Ontarioâ€™s $18 billion ($18.3 billion) forest products industry. There are more than 2,000 companies producing everything from pallets to engineered products using composite technology. With the global downturn and worldwide restructuring of the forestry industry,
Ontario Forest Facts Share: 2 percent of the worldâ€™s forests; 17 percent of Canadaâ€™s forests Size: 71.3 million hectares (176,186,136 acres); 85 billion trees Size of Productive Area (area of the undertaking): 38.5 million hectares Annual Allowable Harvest Area: 350,000 hectares (0.5 percent of forests) Average Annual Harvest Area: 220,000 hectares (0.3 percent of forests) Ownership: 81 percent of forests are Crown (public) forest; 9 percent are within parks and protected areas; 10 percent are privately owned. About 90 percent of timber supply comes from Crown lands. Forest Types: Softwoodâ€”68 percent; Hardwoodâ€”17 percent; Mixed woodâ€”16 percent Main Types of Trees: Black Spruce (37 percent of growing stock); Poplar (21 percent); and Jack Pine (11 percent)
however, many of Ontarioâ€™s forestry facilities have experienced decreased demand. But there is a silver lining for biomass energy productionâ€”the downturn has spurred a number of innovative uses for the unused wood, including increased energy production.
MAXIMUM ENERGY GAIN FROM FLUE GASES
In fact, in addition to those resources already mentioned, bioenergy resources are plentiful in Ontario and include residual materials from forestry operations left on the forest floor, waste matter from agricultural production and byproducts of food-processing operations. As such, the Ontario Power
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¦INTERNATIONAL Authority estimates that a total of 450 megawatts (MW) of energy could be produced by biomass projects in the province by 2027, five times the current and committed capacity.
Trading Coal for Biomass in Atikokan To achieve this goal, Ontario is converting multiple existing coal power stations to use biomass to generate energy. The first power plant to undergo the conversion to biomass is the 211-MW Atikokan generating station, which has already achieved full load on 100 percent wood pellets. The fuel contract for Atikokan was put in place in 2010, and Ontario Power Generation (which is owned by the province and produces 66 percent of Ontario’s electricity) has published a fuel supply request for an initial 90,000 tons of wood pellets, a figure that is expected to increase over time. There is good news at Atikokan both economically and environmentally. The annual fuel requirements for the plant are estimated to amount to less than 1 percent of the total allowable forest harvest in Ontario each year. Even given this low consumption of wood,
the plant is expected to generate enough power to support 15,000 homes each year.
Support for R&D, Entrepreneurship In addition to the direct power generation already taking place, research in the biomass field to pioneer future relevant technologies is also supported by the Ontario government. Ontario is home to the Centre for Research and Innovation in the Bio-Economy. CRIBE’s role is to aid the transformation of the forest products industry in northern Ontario by acting as a conduit for companies interested in investigating opportunities in the bioeconomy. CRIBE is able to partner financially with relevant industry organizations and private sector partners to bring emerging technologies to fruition.
Biomass-Friendly Government Programs The future has never been brighter for biomass and other renewable energy technologies in Ontario and in other jurisdictions ready to make the investment to move to such an efficient renewable energy source. Stephen Roberts, a strategic sector coordinator at the
Ontario Ministry of Northern Development, Mining and Forestry points to the wide variety of market entry options for U.S. companies, and emphasizes that the Ontario government is supportive of U.S. investment and welcomes U.S. technology, experience and investment. “A smart operator could be very successful with a business model that draws on our surplus wood supply, our new bioenergy legislation, and our existing forestry and logistics infrastructure,” he says. Through leveraging its natural resources, its early adoption of biomass as a renewable energy source, and its direct government support for research and development and entrepreneurship within the industry, the Ontario government has created an environment designed to support the success of biomass-related companies. In doing so, Ontario is demonstrating to the rest of the world how to use biomass to truly diversify sources of energy, and move into an era of clean, green power. Author: Shirley Townsend Senior Economic Officer, California Ontario Ministry of Economic Development and Trade Shirley.Townsend@international.gc.ca
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INSIDE: RESEARCHERS STUDY CATTAILS AS A PELLET FEEDSTOCK
Pellet Prowess How Brazilians Plan to Create a Market for Bagasse Pellets Page 18
Plus: How Standards Benefit Producers and Protect Consumers Page 12
Manufacturers Share Thoughts on Production, Marketing, Competition Page 30
Why North American Biomass Suppliers are Watching the UK Page 42
Calculating the Renewable Fraction of Energy from Waste A technique based on carbon dating will soon be used in the U.K. to determine the proportion of energy from waste that is renewable. BY MATTHEW AYLOTT
n the U.K. every year nearly 35 million metric tons of municipal solid waste (MSW) is generated. And up to 60 percent of MSW can be made up of renewable materials that could be used to generate energy. In the U.K., generators of renewable energy can receive Renewable Obligation Certificates, which can then be sold on to electricity suppliers. ROCs are issued for every megawatt hour (MWh) of renewable electricity generated and each of these ROCs currently sells for around £50 ($81.13). When you convert mixed waste streams into electricity, however, it can be difficult to determine how much of this energy is renewable. Many approaches have been considered (see table on page 51) but up until now, only one energy-from-waste (EfW) power station in the U.K. has received any ROCs.
The Energos plant on the Isle of Wight has been receiving ROCs since the start of this year, but its approach is to measure the biomass content of the fuel and the gross calorific value of the flue gas. This can be an unrepresentative and time-consuming affair.
Carbon 14 Now, the British electricity and gas market regulator, Ofgem, which issues ROCs, has approved the use of a new method known as the carbon 14 technique to help calculate the renewable content of EfW so installations can benefit financially from the renewable energy they produce. “Independent reports concluded that the carbon 14 technique is based on mature and well-understood technology,”
The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of Biomass Power & Thermal or its advertisers. All questions pertaining to this article should be directed to the author(s).
50 BIOMASS POWER & THERMAL | SEPTEMBER 2011
says Richard Bellingham, biomass, waste and cofiring manager at Ofgem. “We are therefore prepared to consider fuel measurement and sampling (FMS) procedures that propose to use the carbon 14 technique. As always, the FMS proposals will be considered on a case-by-case basis, taking into account the different feedstock used and the nature of each generating station.” The approach takes advantage of the fact that as living organisms die and are converted to fossil fuel, the proportion of carbon 14 isotopes they contain will decrease, due to radioactive decay. So fossil fuels contain far fewer carbon 14 isotopes than recently living biomass. This can be measured in the smokestack (or flue gas) of power plants so they can claim ROCs.
Double or Nothing EfW installations can receive double ROCs if they can prove the renewable content
Declared renewable content
Presumes untreated waste has a biogenic content >50 percent, thus declare it to be 50 percent
A generator can use indirect evidence of the biogenic content
Inaccurate and subjective
Separates fuel components into fractions, which are either (mostly) biomass or nonbiomass
All waste, even after processing, is considered to be heterogeneous
Accuracy is dependent on samplers’ ability to distinguish between fractions, challenging if small size, composite or dirty
Biomass typically oxidizes more quickly than nonbiomass, so by dissolving biomass in certain chemicals, we can work out how much is renewable
Presumed to be the most accurate method of determining biomass
Relies on assumption that biodegradation is the same as biogenic, but rubber, wool, fat, resist biodegradation while nylon, polyeurethene do biodegrade
Based on a decaying isotope carbon 14, which has a half life of 5730 years, so fossil fuels contain lower proportions of carbon 14
Samples reliably represent the material burnt
Retrospective and expensive
PROS AND CONS: Comparison of advantages and disadvantages of different methods for measuring renewable content of energy from waste SOURCE: NNFCC
of their feedstock. The double ROCs banding is the highest incentive available under the U.K. Renewables Obligation system and is designed to support investment in emerging technologies, such as advanced gasification and pyrolysis. Finding a technique to simply and accurately determine the renewable energy produced by EfW installations has been a major stumbling block for the industry, and has until now presented a missed opportunity for energy generators who could be claiming ROCs. “Waste-derived fuels are a vital indigenous source of renewable energy for electricity, heat and ultimately transport fuels,” said Chris Manson-Whitton of clean energy project development company Progressive Energy Ltd. “We are very pleased that Ofgem has adopted this technique, which will facilitate industry in unlocking this valuable resource.” “This has been the culmination of a fouryear story to establish this exciting technique as a method for measuring the renewable content of waste-derived energy. We, along with other advocates like the National Non-Food Crops Centre, New Earth Energy and the Renewable Energy Association welcome Ofgem’s decision and are pleased that our efforts have opened the door for generators to use this pioneering approach,” he adds. While the technology is new to the U.K., it is already in use in countries such as Belgium and the Netherlands and has proven highly successful in measuring the renewable carbon in their flue gases. Now several U.K. EfW installations have decided to start using the technology.
The U.K.’s National Centre for Biorenewable Energy, Fuels and Materials—the NNFCC—were amongst the first to propose carbon 14 as a simple and accurate method for measuring the renewable carbon of flue gas. “The carbon 14 method is enabling easy and accurate differentiation between carbon dioxide emissions created from fossil sources and those from renewables,” says John Williams, head of materials for energy and industry at the NNFCC. “As a long-term advocate, the NNFCC hopes this trusted and established analysis technology will significantly increase the number of power stations making renewable energy from waste biomass.” The carbon 14 technique starts with a sample of carbon dioxide taken from the flue gas of a facility. This can be taken in small increments every 30 minutes or so, then a composite sample can be made to accurately represent the whole month. The carbon dioxide is then sent to a lab for analysis, where it is burned, reduced to graphite and tested for isotopic abundance using a process known as accelerator mass spectrometry. From this, the renewable content of an EfW power station can be determined. The method itself is an established technique operated under international standards ASTM 6866 and CEN 15591/15747. In 2010, the NNFCC was invited to be the U.K. representative on the European Committee for Standardisation panel for adopting a standard measurement of renewable content. This led to the creation of a new U.K. standards committee, designed to look at the wider implications of developing a biobased standard, which helped influence Ofgem’s decision.
But the carbon 14 method has some critics, including Richard Black, operations director of the U.K. Resource Efficiency Knowledge Transfer Network, who says “The advantage of this process is that gas analysis is very representative of the actual feedstock input, but the major disadvantage of the method is that it's retrospective and expensive.” Similarly Tony Grimshaw, technical director of Energos, says. “This is the first step that Ofgem accepts it is an alternative,” he says. “But some trials need to take place and it needs to be demonstrated on the ground. Cost is the other issue. In my view, it is probably a year away before it all beds down.”
Future EfW could play an important role in contributing toward European Union targets to produce 20 percent of its energy from renewable sources by 2020. However, the problem until now has been how to measure the renewable content of waste. But all things have a built-in time clock to differentiate, between renewable carbon (carbon 14) and fossil carbon (carbon 12). By measuring this ratio in a power station smokestack, we can determine the renewable carbon content of any source material using a single physical measurement, independent of secondary information. This will allow simple regulation of certification schemes in the future. Author: Matthew Aylott Staff Writer, U.K. National Non-Food Crops Centre M.Aylott@nnfcc.co.uk www.nnfcc.co.uk
SEPTEMBER 2011 | BIOMASS POWER & THERMAL 51
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52 BIOMASS POWER & THERMAL | SEPTEMBER 2011
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SEPTEMBER 2011 | BIOMASS POWER & THERMAL 53