At one time not too long ago, North Carolina was populated with more pigs than people. While that&rsquo;s no longer true, the state trails only Iowa among pork-producing states, and the industry employs roughly 46,000 North Carolinians, provides $3 billion in annual income and $7 billion in annual sales, and its 2,100 farms&mdash;80 percent of which are family-owned&mdash;are home to 8.8 million hogs, living on farms that range from 250 to 50,000 head. For the past two decades, the industry has been increasingly regulated, as a way to manage hog waste and improve and preserve environmental quality. In 1997, a moratorium was placed on the expansion of existing hog farms and the development of new ones. Fast-forward 10 years later, and the moratorium became permanent, with a provision that new permits could be issued only to farms that meet five environmental performance standards: Elimination of discharge of animal waste to surface waters and groundwater through direct discharge, seepage or runoff, as well as substantial elimination of atmospheric emissions of ammonia, emissions of odor detectable beyond the boundaries of the parcel or tract of land on which the farm is located, the release of disease-transmitting vectors and airborne pathogens, and of nutrient and heavy metal contamination of soil or groundwater. That same year, state legislators passed a renewable portfolio standard (RPS), which requires investor owned utilities to produce 12.5 percent of retail electricity sales from eligible renewable resources by 2022, and municipal utilities and electrical cooperatives have a target of 10 percent by 2018. Relatively small goals compared to many other states that have renewable energy mandates, but a landmark bill nonetheless, as it is the only state in the Southeast that has made law a mandatory RPS. While the list of renewable energy sources a utility can derive its mandated power from is broad, the RPS has a specific carve-out for swine-based electricity&mdash;0.2 percent by 2019, or 284,000 megawatt hours&mdash;as well as one for poultry waste, provisions that apply to the state as a whole rather than each individual utility, each of which is responsible for meeting a portion of that requirement. Coupled together, the environmental quality standards and renewable energy goals make a strong case to site renewable energy projects at hog farms. Meeting Goals &ldquo;The process of creating electricity usually meets four of five of the environmental performance standards,&rdquo; says Angie Maier, spokeswoman for the North Carolina Pork Council. &ldquo;It creates a situation in which a farmer, if the conditions are right, is able to utilize the renewable energy law to put a system in.&rdquo; The first project to take advantage was at Lord Ray Farm, a team effort of Duke University, Duke Energy and Google, that uses waste from over 8,600 hogs and produces 600 megawatt-hours (MWh) per year, beginning in 2011. After that, five more projects were built, ranging in size from 7,550 hogs to a ten-farm, 74,000-hog project, or from 200 MWh to 10,200 MWh per year, respectively. Most have been built on existing farms looking to seize the opportunity of renewable energy credits (RECs) and environmental benefits. &ldquo;One farm has been permitted for expansion, and will have a renewable energy system,&rdquo; Maier says, adding that the current projects range in sophistication and utilize a mix of covered lagoons and tank digesters. All produce electricity on the backend to earn RECs. &ldquo;Recent ones have utilized a state renewable energy investment tax credit, a federal tax credit and RECs,&rdquo; Maier says. Matters of whether or not a farm can get projects to pencil out usually isn&rsquo;t an issue when a developer has the experience and understands all of the moving parts, according to Maier. &ldquo;Hopefully, the RECS are enough to cover the cost, but ultimately, the utilities have these mandates and they have cost-recovery mechanics on the electric bills that customers get,&rdquo; she says. &ldquo;Technically, the process should be working.&rdquo; Those charges typically range from 40 to 80 cents per customer bill per month. Like many other states, there have been legislative attempts to freeze or dismantle the state&rsquo;s RPS&mdash;the most recent of which was last fall&mdash;but the program creates an interesting dynamic in a red state where most legislators are opposed to wind, solar or other types of renewable energy, Maier points out. &ldquo;We have found that they likely feel different about renewable energy created from swine or poultry waste, because agriculture is North Carolina&rsquo;s number one industry,&rdquo; she says. &ldquo;We have a little bit of leverage there. Progess has been slow, but it&rsquo;s progress nonetheless. We just need some more time to get projects off the ground.&rdquo; Maier says the NCPC is aware of seven additional projects in various stages, one of which is stuck in the interconnection phase. &ldquo;We recently had a bill in committee to move all swine and poultry projects to the front of the interconnection cue for study and connection,&rdquo; she says. &ldquo;We want to get these projects connected and on their way, especially since there is a mandate for the utilities. They&rsquo;re not meeting it [the RPS], so we need to make sure these projects get priority.&rdquo; Duke Energy is one of the prominent utilities in the state working to achieve compliance, and it recently announced involvement in several different swine-based initiatives. One is with Carbon Cycle Energy and will be located in Duplin, North Carolina. The project is massive&mdash;it will process waste from 10 to 20 farms, according to Jess Kutrumbos, director of communications. Under a 15-year term, Carbon Cycle is expected to produce more than 1 billion cubic meters of pipeline-quality methane a year, allowing Duke to yield about 125,000 MWh of renewable energy annually, enough to power about 10,000 homes for a year. Renewable natural gas produced at the facility will be cleaned, upgraded and injected into the pipeline and ultimately used to generate electricity of four of Duke Energy&rsquo;s power plants, all of which are currently retired stations that previously ran on fossil fuels. They include the Buck Steam Station in Rowan County; Dan River Steam Station in Rockingham County; H.F. Lee Station Combined Cycle Plant in Wayne County; and Sutton Combined Cycle Plant in New Hanover County. For Carbon Cycle Energy, North Carolina&rsquo;s RPS was a key driving force in launching the project. &ldquo;It was definitely influential in our site-selection process,&rdquo; Kutrumbos says. &ldquo;We strategically chooses project locations at the convergence of supply of organic waste feedstocks and access to natural gas pipelines, so those were additional contributing factors for this particular site selection.&rdquo; Design and permitting are underway, and early-phase site preparation is set to begin in the last quarter of the year, with heavy construction beginning in early 2017 and startup toward the end of that year. Duke Energy also recently announced it has finalized a second deal in 2016 to buy captured methane gas derived from swine waste. The planned project in Kenansville, North Carolina, will be built at the heart of Smithfield Food&rsquo;s pork operations and, via a number of digesters built by Optima KV LLC, will produce renewable natural gas that will be sent to two Duke Energy power plants: H.F. Lee Station Combined Cycle Plant in Wayne County, and Sutton Combined Cycle Plant in New Hanover County. The project is expected to be operational by next summer. David Fountain, Duke Energy North Carolina&rsquo;s president, has emphasized the project&rsquo;s benefits and that it is cost-effective for utility ratepayers. The utility says it has remained under the RPS cost cap outlined in regulations, and, contrary to assertions made by opponents of the mandate, that it is not a cost burden to customers. Once the last kinks in the process are worked out&mdash;from project proposal to the sale of RECs, including any interconnection cue issues&mdash;North Carolina is likely to see a boom of swine waste-based energy projects come online, not only benefiting the environment, but replacing fossil-based generation, creating renewable energy and driving economic value. Author: Anna Simet Managing Editor, Biomass Magazine asimet@bbiinternational.com 701-738-4962

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North Carolina's renewable energy mandate is advantageous to pork producers, if conditions are right.

Regs and Bacon

Driving vehicles that run on natural gas reduces emissions and allows us to breathe cleaner air. But what many don&rsquo;t realize is that this is rapidly becoming truer through the increasing use of renewable natural gas in North America&rsquo;s natural gas vehicle (NGV) infrastructure. Renewable natural gas (RNG) is derived from the methane that emits from organic waste as it decomposes. This methane is captured at agricultural facilities, landfills, wastewater treatment plants, and separated municipal solid waste digesters, and then cleaned in a treatment process to produce a product indistinguishable from natural gas. The resulting biomethane, or RNG, is then either injected into natural gas pipelines, compressed or liquefied to be used as transportation fuel in the form of renewable compressed natural gas (CNG) or renewable liquefied natural gas (LNG). As CNG and LNG from renewable feedstocks are blended together with natural gas transportation fuel from geologic sources, our nation&rsquo;s transportation system becomes drastically cleaner. Switching vehicles to run on geologic-sourced CNG and LNG already reduces emissions. Natural gas provides 90 percent lower NOx emissions with new Near-Zero engines, and a 99 percent SOx reduction, compared to diesel. Blending in RNG reduces fuel emissions even further. Driving a vehicle with 100 percent RNG can reduce greenhouse gas emissions (GHG) by more than 80 percent. RNG from some sources are carbon negative, meaning that they sequester GHG during the fuel life cycle. Figures released in April by the California Air Resources Board show that, as of the end of 2015, half of the natural gas being used to fuel vehicles in the state is RNG. Only three years ago, in 2013, RNG&rsquo;s share of California NGV fuel was just 10 percent. RNG&rsquo;s growth in California evidences the effectiveness of California&rsquo;s Low Carbon Fuel Standard in driving growth in emission-reducing, clean fuels. The extent of RNG used nationally to fuel NGVs is less certain than in California. U.S EIA sources indicate that between 15 and 35 percent of natural gas transportation fuel consumed in the U.S. is RNG. However, evidence shows that use of RNG as a cellulosic transportation fuel is growing at an unprecedented rate, thanks in part to the renewable fuel standard (RFS). In 2013, prior to the RFS pathway approval of renewable CNG and LNG as eligible cellulosic biofuels, the RNG industry produced just 25.9 million estimated gallon equivalents (EGE) of transportation fuel. By the end of 2015, that volume had grown five-fold to nearly 140 million gallons, making up 98 percent of the cellulosic biofuel produced under the program. Current and future production rates look even stronger. RNG producers are on track to reach 230 million EGE in 2016, and surpass the U.S. EPA&rsquo;s draft rule renewable volume obligation (RVO) of 312 million EGE for 2017.&nbsp; The Coalition for Renewable Natural Gas, which advocates for the North American RNG industry, forecasts production of over 350 million gallons of RNG in 2017 and over 450 million gallons in 2018. RNG adoption is naturally linked with the increasing deployment of NGVs, many of which are high horsepower vehicles. Over 25 percent of transit buses in the U.S. today operate on natural gas, including those serving nearly 40 major airports. Over 60 percent of new refuse truck orders are NVGs. Fleet conversion costs to RNG stack up favorably with other renewable engine technologies. A report produced for LA Metro by M.J Bradley &amp; Associates and Ramboll and Environ in early July determined that bus fleet costs are more affordable with a new low-NOx engine plus RNG fuel combination (1 percent annual cost increase) than either an all-electric (8 to 14 percent increase) or fuel cell (9 to 13 percent) bus fleet. Together, RNG and natural gas vehicles are an affordable and proven long-term solution to reducing air pollution and carbon emissions. It is critical that companies, states, municipalities, and citizens across North America collectively continue to embrace ultra-clean, domestically produced and available fuels like RNG. If we do, the air we breathe will be cleaner. Public health will improve. We&rsquo;ll combat climate change, stabilize fuel price volatility, reduce dependence on foreign oil, and curb unsustainable waste practices. Sustainability is the future of fuels. When NGVs are fueled on RNG, we ensure that waste isn&rsquo;t wasted, but instead is used as resource that moves us down the road toward a sustainable future. Author: Marcus Gillette Director of Public and Government Affairs, Coalition for Renewable Natural Gas 916.588.3033 Marcus@rngcoalition.com

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Together, RNG and natural gas vehicles are an affordable and proven long-term solution to reducing air pollution and carbon emissions.

Driving Growth in Driving Green

Farming looks mighty easy when your plow is a pencil, and you're a thousand miles from the corn field. &nbsp;These words spoken by former U.S. President Dwight D. Eisenhower in 1956 still ring true, and are particularly relevant when it comes to renewable energy projects that involve ag biomass, especially projects that have very specific feedstock specs and large volume requirements, such as cellulosic ethanol ventures. In fact, most developers&mdash;commonly technology or chemical companies&mdash;often overlook the complexities around the feedstock collection system, according to Glenn Farris, marketing manager of biomass at AGCO Corp. &ldquo;There are misconceptions about how easy it is to harvest grasses or corn stover&mdash;a lack of understanding about what type of machinery to use, economics and logistical issues,&rdquo; Farris says. &ldquo;When a project is being contemplated, it&rsquo;s often that developers will run into some real stumbling blocks because of a lack of understanding of those issues.&rdquo; The number of machines and moving parts of a commercial-scale energy facility&rsquo;s feedstock operation is impressive&mdash;a project that requires 350,000 dry tons of input per year will need approximately 50 balers, 50 shredders, 35 collections systems and 140 tractors, according to Farris. And while mixing and matching different original equipment manufacturer (OEM) offerings may look slightly better on the financial front, in the end, it likely won&rsquo;t. Farris stresses the convenience and economics of a single technology package. &ldquo;For example&mdash;for a baling operation, there are certain aspects of our tractors that are designed to anticipate our balers, which will probably perform 3 to 5 percent more efficiently using our tractor,&rdquo; he says. &ldquo;Someone might say that&rsquo;s not much, but that&rsquo;s true until you&rsquo;re doing 350,000 to 400,000 tons of biomass and using a couple hundred pieces of equipment. That percent becomes a very large number when you look at it in dollars and cents.&rdquo; While more than one OEM can be used and different machine brands paired together, Farris says the commonalities in how a single OEM&rsquo;s equipment operates, and working with the same dealers to learn how to operate equipment and get it serviced, simply brings more efficiency to an operation. A Grip On Handling Historically, the handling, treatment and pretreatment of biomass&mdash;the collection and preparation process before it goes into the facility units&mdash;is usually where most projects experience their problems, according to Farris. &ldquo;That&rsquo;s where the bottlenecks are, it&rsquo;s the largest learning curve, and part is based on the fact that biomass is just not usually uniform,&rdquo; he says. &nbsp;There are many variabilities among crops, and even within a specific species of crop, including ash content, moisture content, weather influences and more, which typically makes biomass hard to handle, an overarching reason for having team members who know what to expect and how to deal with challenges. Aside from forest biomass, AGCO is confident it has worked or handled every potential ag feedstock. &ldquo;We&rsquo;ve participated projects that have collected hundreds of thousands, if not millions, of tons of corn stover, and we have harvested and worked with miscanthus, switch grass, energy cane, sugar cane, the list goes on. Most experience has been gained by working and making mistakes, so we can help customers not make the same mistakes. What we&rsquo;ve learned is just what we didn&rsquo;t know.&rdquo; That experience had led to equipment innovation&mdash;for example, changes to the large-square baler chamber and windrower headers&mdash;new designs that have made the machines not only a better fit for corn stover, but for other commercial crops such as hay and alfalfa. And, there are other potential changes that AGCO is ready to make when the time is right. &ldquo;There are other things we&rsquo;re ready to do when the market dictates,&rdquo; Farris says. &ldquo;We have preliminary designs, high-volume harvesting machines for grasses like miscanthus and switchgrass, and energy cane, that aren&rsquo;t available in production models, but could be reasonably quick, when the market needs them.&rdquo; Looking Forward Every project is different, and real-world experience has driven that ideology home for AGCO. &ldquo;Cookie-cutter is a utopia that doesn&rsquo;t exist&mdash;challenges vary from project to project,&rdquo; Farris says. &ldquo;And each new commercial project teaches the rest of the industry new lessons, whether it is a complete success, or whether it ultimately fails. On future opportunities within the biomass energy industry, Farris says AGCO sees much potential in South America, particularly Brazil, which has cracked down on sugarcane mills&rsquo; burning of cane fields, a practice done before harvest to manage the tops and leaves of sugarcane plants, or waste products leftover following sugar extraction. &ldquo;About one-third of the material is being left in the field&hellip;it&rsquo;s an exciting opportunity,&rdquo; Farris says.&nbsp; &ldquo;Sugarcane is normally burned in the plant to produce steam and electricity, and we&rsquo;re seeing a lot of expansion, and there are efforts to use it for cellulosic ethanol and chemicals.&rdquo; China is also another country of interest. &ldquo;It seems promising,&rdquo; Farris adds. &ldquo;The powers at be seem to be making a real commitment to the concept of using biomass for energy.&rdquo; While researchers, technology providers and project developers work on the blue prints for projects in these countries and others across the globe, AGCO will be waiting in the wings, ready to assist. Author: Anna Simet Managing Editor, Biomass Magazine 701-738-4961 asimet@bbiinternational.com

AGCOâ€™s large square baler makes its way through a field of corn stover. 

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An experienced OEM offers the experience, advice and capabilities project developers need to maximize project efficiency.

Solving the  Equipment Equation

In March, U.S. President Barack Obama and Canadian Prime Minister Justin Trudeau pledged to cut net greenhouse gas (GHG) emissions 80 percent by 2050, a historic agreement. This &ldquo;deep decarbonization&rdquo; of the global economy will require much more than basic measures in efficiency and renewable energy. It demands profound changes in how we interact with the entire global carbon cycle, from sky to sea to soil. Our modern effort at deep decarbonization can learn much from the planet&rsquo;s original endeavor in this field, and from that episode&rsquo;s central players. The lessons learned offer a vision and the tools to reverse much of the past century&rsquo;s misdeeds. Billions of years ago, Earth was transformed from toxic wasteland to temperate abundance with the aid of an astonishingly powerful, yet simple, set of carbon mitigation technologies. Algae and other early microorganisms unleashed the power of photosynthesis&mdash;and its after-hours relative, chemosynthesis&mdash;to transform CO2 and other carbon-containing gases into the fundamentals of modern existence: food, energy, soil and fresh water.&nbsp; Many of today&rsquo;s economic activities produce, at best, one of these elements, often at the expense of the remainder. Deep decarbonization demands a return to Earth&rsquo;s original approach, in which excess carbon becomes the building block for a sustainable existence. Algae scientists, engineers, and other industrial biotechnologists are developing industrial agricultural systems to do just that. These systems provide a model and a mechanism for deep decarbonization that deserve global governments&rsquo; strongest support. Global leaders now clearly recognize that even the most ambitious efforts at energy efficiency and carbon-free energy will be inadequate to avoid potentially catastrophic climate change. To halt and reverse atmospheric accumulation of CO2 and other carbon-containing greenhouse gases will require widespread deployment of carbon capture technologies. In the near-term, these technologies can be deployed at point sources, such as power plants and industrial facilities, to minimize emissions of CO2 from fossil fuels as we transition to carbon-free power sources. These technologies can also be deployed to capture industrial sources of biogenic carbon, such as from biomass power and industrial fermentation. Such applications have the benefit of not only avoiding carbon emissions, but also help begin the task of drawing down atmospheric concentrations of CO2 by removing carbon already resident in the atmosphere, rather than that which was previously sequestered underground, such as the case of fossil fuel combustion. Ultimately, to reverse the buildup of atmospheric CO2, carbon capture must be applied to the atmosphere itself through air capture or other yet-to-be-developed approaches. Regardless of how and where capture technologies are applied, they must be economically viable and they must substantially reduce emissions of CO2 to the atmosphere, whether directly or indirectly. Enhanced oil recovery (EOR) offers the potential for economically viable carbon capture and geologic storage (CCS), but is predicated on extraction and, ultimately, combustion of additional fossil carbon. Economically viable CCS without EOR has proven heretofore elusive. Carbon-negative approaches that offer bona fide prospects of economic markets for captured carbon are needed. Algae and other microorganism-based approaches to carbon capture offer perhaps the best chance to realize this vision. Today, in an industrial setting, algae and other photosynthetic or chemosynthetic microbes can do what they did in their natural setting eons ago: capture CO2 and other carbon-containing gases and convert them into valuable products, including food, energy, soil and fresh water. The tools of modern industrial biotechnology mean that the systems change the planet achieved over the course of hundreds of millions of years can be realized in a fraction of that time. A wave of innovation in algae and related technologies is bringing profoundly carbon-negative capture and use technologies to the verge of commercial deployment. With strong policy support, these technologies can be deployed today to aid in the transition to a sustainable global economy. Author: Matt Carr Executive Director, Algae Biomass Organization mcarr@algaebiomass.org 877-531-5512

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A wave of innovation in algae and related technologies is bringing profoundly carbon-negative capture and use technologies to the verge of commercial deployment.

Ancient Biology for  Modern Decarbonization 

Designing a pyrolyzer furnace is an intricate process. There&rsquo;s more to the design than making a carbon steel box, lining the walls with refractory, running some process pipes through it, and heating the pipes with burners. While this may describe the design steps in vague detail, it doesn&rsquo;t capture the intricacies involved in pyrolyzer furnace design. Knowing what to consider and evaluate can be the difference between success and failure. Key pyrolysis system design considerations include feedstock composition, pyrolysis heat of reaction and reaction kinetics, heat transfer required to achieve kinetics, system design to provide heat transfer, and pilot testing and scale-up. Feedstock Composition The feedstock&rsquo;s moisture content (MC) and composition drive the pyrolyzer design because it determines the pyrolyzer&rsquo;s required heat. MC is easily determined by taking a loss on drying (LOD) measurement. In stark contrast, many of the methods used to determine a feedstock&rsquo;s composition are lab-intensive and expensive, but obtaining the composition is essential to the design. At a minimum, Merrick &amp; Co. performs an ultimate and proximate analysis of feedstock samples. As an alternative, data for common feedstocks is available from public sources, such as the National Renewable Energy Laboratory in Golden, Colorado. Merrick frequently performs a feedstock characterization using data from sources such as NREL as a first approximation, to get projects rolling quickly. Actual feedstock analysis then confirms the use of this data as the projects progress. Characterizing a feedstock&rsquo;s composition helps predict the decomposition behavior. Different feedstocks require different temperatures and amounts of heat for decomposition. If you design the pyrolyzer for the incorrect feedstock composition, it will not function Efficiently. Worse yet, it may not work at all. Pyrolysis Heat of Reaction, Reaction Kinetics The pyrolysis heat of reaction is the amount of heat necessary to decompose and vaporize volatile matter in the feedstock. It is important to note that it does not account for the required heat to raise the feedstock temperature to the pyrolysis temperature, i.e., the sensible heat. Multiple chemical reactions take place during pyrolysis. Some are exothermic while others are endothermic, and these reactions vary depending on the feedstock. Because of this complexity, published values for the pyrolysis heat of reaction vary greatly for feedstocks. Verifying published values through experimental testing is critical to ensuring the capability of the pyrolyzer. A pyrolyzer should never be designed solely on published pyrolysis heat of reaction values. Knowing the feedstock composition and the decomposition behavior of each component allows modelling of the overall decomposition behavior. The percent conversion of each component is temperature dependent. By understanding the reaction kinetics, the required exit char temperature and the residence time can be determined. Pyrolysis modeling software uses reaction parameters such as those summarized by Miller &amp; Bellan&nbsp; to calculate product yields as a function of temperature. Heat Transfer Design, Analysis Once the pyrolysis reaction is understood, the next step is to design a heat transfer system that can achieve it. The thermochemical decomposition of pyrolysis takes place in the absence of oxygen which requires indirect heating of the feedstock. Burners fire into the furnace box releasing flue gas, which acts as a heating medium. Heat transfer within the furnace box is a complex combination of conduction, convection and radiation. Some designs utilize radiant wall burners that heat the refractory on the walls of the furnace which then radiate heat to the pyrolysis chamber. Other designs convectively heat the pyrolysis chamber by blowing flue gas across the pyrolysis chamber walls. Regardless of the heating technique employed, the heat transfer model must accurately account for all of the heat transfer mechanisms in the design of the furnace. Modelling the furnace&rsquo;s heat transfer design by hand involves complicated and laborious hand calculations. Fortunately, Computational Fluid Dynamics software exists, which greatly increases the power and sophistication of heat transfer modeling. The software also provides visuals of thermal dithers, which helps identify hot and cold spots. Without sophisticated modeling, pyrolysis system design is often guesswork, or trial and error. CFD software helps remove the guesswork from the design. Regardless of how the pyrolysis chamber is heated on the outside, its walls heat the biomass through conduction from the bottom, and radiation from the top. Further, gasses released during the pyrolysis reaction also heat the biomass through convection. Understanding the nature of this heat transfer and how to achieve it presents even more complex challenges. CFD software once again helps alleviate these challenges by accurately modeling designs to ensure they provide the necessary heat transfer to achieve pyrolysis reactions. System Design Considerations After completing process and heat transfer designs, the design team must make several pivotal decisions regarding materials, pipe supports and thermal expansion, material feed and internal transport systems, and finally maintainability. Materials: Selection of materials is one of the most important aspects of pyrolyzer design. They must be able to operate at temperatures well into their creep zone and still maintain ductility. In addition, they must be able to endure thermal cycling caused by frequent shutdowns and startups. They may also have to resist carburization, chloride stress corrosion cracking, or sulfide stress cracking, or even all three. Typically, materials for components inside the furnace box are high-temperature stainless steels such as 304 H or 310, or high-nickel alloys. To navigate strenuous requirements, assistance of a knowledgeable metallurgist is invaluable, especially since materials that can withstand these strenuous operating conditions tend to be very expensive. Blindly selecting materials can wind up costing millions and setting a project back months, if not years. Pipe Supports and Thermal Growth: Another important design consideration is pipe supports. Pipe supports that allow for thermal expansion and contraction are critical to avoiding piping failures. The supports require expert design, as portions may be inside and outside the furnace box. Due to the intense heat, the supports inside the box are typically 304 H or 310 stainless steel. Complicating the problem further is the fact that the pipes experience thermal growth in all directions. Fixing one end of the pipes while allowing the other to move during thermal cycling often solves this problem. Rollers or slide plates, as well as constant effort supports, are usually required. Accounting for these items in a cost estimate is crucial, as they, too, are rather expensive. If a portion of the horizontal process pipes protrudes outside the furnace box and the pyrolyzer has multiple runs, the furnace box will need sliding panels to allow for their thermal growth. These panels must seal the furnace while allowing the pipes to move in the longitudinal and vertical directions. This is also true for vertical process pipes that protrude outside the furnace box. They require sliding plates that allow them to grow in the vertical direction and translate in the longitudinal direction. Material Feed and Internal Transport Systems: An important design consideration, and one frequently not given enough attention, is the biomass feed system. It usually involves conveyors, bucket elevators, hoppers, and lock hoppers. In our experience, many pyrolyzer designs do not place enough attention or expertise towards the feedstock handling system, despite the fact that they are frequently the primary causes of pyrolysis system failures. Deciding to purge the process of oxygen versus just limiting the ingress of air is another vital consideration in the decision process. To limit the amount of air (oxygen) entering the system, numerous types of valves are available. These include valves such as knife gates, or rotary, and each type has its benefits as well as its drawbacks. If purging oxygen is the answer, the system likely requires pulling a vacuum. However, utilizing a vacuum greatly limits the valve options. Careful consultation with valve suppliers is a must to weigh the tradeoffs. Considering cost is important because valve prices vary greatly depending on the type. A basic design decision for the pyrolyzer will be how to move the biomass inside the furnace. Using the word &ldquo;basic&rdquo; here is misleading because whether using a drag conveyor, an auger screw, or some other method, plenty of challenges lie ahead. The component must endure high heat and extremely dirty conditions, which makes using bearings a problem. In addition, accounting for thermal growth is essential. And most importantly, the moving device must allow for heating of the biomass. Maintainability: Virtually all pyrolyzer designs require external platforms for maintenance. While these are not difficult to design compared to the pyrolyzer itself, they can still easily cost $300,000, if the pyrolyzer has multiple levels. The platforms are essential for the maintenance of drive units, burners, pipe supports, and other pieces of essential equipment. Running a plant on a daily basis is next to impossible without provisions to service the equipment. Gas Treatment: Careful design considerations should go into handling the vapor exiting the pyrolysis chamber. These hot vapors likely contain heavy hydrocarbons that readily condense and form heavy oils and tars upon contact with any cooler surfaces (e.g. discharge piping, valves, filtration equipment). To make matters worse, the vapors also carry over char particulates, which compound the risk of bridging and plugging. The management of heavy oils, tars and char particulates is a primary failure point in pyrolysis and gasification systems. The challenge is removing the char particulates before they make it downstream and prevent the heavy oils and tars from condensing out. Most pyrolyzer system designs remove char particulates from pyrolysis vapors at the exit of the pyrolysis chamber. They utilize gravity settling, centrifugal separation (e.g. cyclone separator), or filtration, or a combination of these. Removing particulates maintains product quality, helps prevent downstream plugging, and may reduce waste water treatment costs in some designs. However, preventing condensation becomes critical to avoid filter plugging by the heavy oils and tars. In fact, piping oftentimes has electrical heat tracing all the way from the pyrolyzer exit, through the cyclone, and up to the quench equipment. Candle or baghouse-type filters are difficult to implement successfully. Ceramic meshes can withstand the process temperatures, but these filter types require additional design features to extend their operational life. Most designs require back-pulsing the filter media to dislodge the char cake. In addition, maintaining elevated temperatures and preventing condensation is essential. Common techniques are injecting hot flue gases and minimally firing the filters. In general, avoiding bends and fittings in discharge piping and locating filtration equipment directly at the pyrolysis chamber outlet(s) reduces opportunities for condensation and char particulate carryover. Also, investigating designs that utilize the hot flue gasses exiting the pyrolyzer furnace to heat the discharge piping and filtration equipment can be an economical way to prevent condensation. Pilot-Testing, Scale-Up Maintaining critical design characteristics during scale-up of equipment allows accurate prediction of process parameters based on data collected during pilot testing. Understanding the heat transfer characteristics from the pilot-scale through full-scale in the pyrolyzer is essential. Services exist to model the expected heat transfer, which provides a basis for pilot plant equipment design. During piloting, data collection should verify the estimated heat transfer data for use in designing the commercial scale equipment. Understanding and evaluating changes in the surface area to volume ratios from the pilot-scale to commercial-scale pyrolysis chamber is critical to successful operation. Smaller-sized pilot units typically rely more on conduction, while larger, commercial-scale units utilize more radiation and convection to transfer heat into the biomass. Failure to comprehend and quantify these scale-up parameters results in insufficient heating at commercial scale. Another area of concern during scale-up is material handling. Overlooking material handling equipment is common during piloting, but can create unforeseen operational issues at commercial scales. For example, shoveling biomass to the pyrolyzer inlet on the pilot plant may obscure the need for a rotary valve or live bottom feeder that evenly feeds the biomass and reduces air ingress at commercial scale. As previously discussed, failure to place an emphasis on material handling can lead to huge delays and costly overruns. With all of the above in mind, there are many steps in designing pyrolyzer furnaces. Taking the time to plan and properly execute these steps directly determines the level of success your technology will achieve. A typical complete fabrication drawing package has around 250 to 300 sheets and can take anywhere from 4 months to 1 year to design the furnace and start fabrication. Failure to recognize this on the front end can lead to issues with budgets and investors later on down the line.
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Do&rsquo;s and Don&rsquo;ts of Pyrolyzer Design Do: &bull; Determine the composition of your feedstock. If you design for the wrong material, your pyrolyzer may not function correctly. &bull; Determine if purging the process of oxygen or just limiting air ingress is appropriate for your design and select valves accordingly. Keep in mind that a vacuum pump may be required. &bull; Model the heat transfer all the way into your feedstock. Even though the heat enters the pyrolysis chamber, it may not make it into the biomass and achieve the required conversion. &bull; Determine the residence time of your feedstock in the furnace. This avoids undercooking or overcooking the biomass. &bull; Select your burners before applying for permits for emissions. Solving this problem after realizing burners with sufficiently low emissions do not exist causes unnecessary headaches and delays. &bull; Perform a pipe stress analysis to allow for thermal growth and design pipe supports. Guesswork causes failures in expensive materials, and equipment, and lengthy delays. &bull; Account for gas treatment. The backend of the process causes the most plugging failures. &bull; Finally, properly designing and testing material-handling equipment is essential to continuous plant operation. There is nothing worse than a plant lying idle because of failures moving the feedstock. Don&rsquo;t: &bull; Go straight from benchtop to production. Benchtop systems rely heavily on conduction while radiation and convection predominate in production units. Develop models and follow the design process to successfully scale-up. &bull; Underestimate the feed system. Moving biomass is challenging and it doesn&rsquo;t matter how amazing your furnace is if it can&rsquo;t get the feedstock. -------------------------------------- Side Bar ----------------------------------------------------------------- &nbsp;&nbsp;&nbsp; &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Authors: Bradley Waites, Pamela Buzzetta, and Crystal Bleecher Merrick &amp; Co. www.merrick.com 303-751-0741

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Design considerations can make the difference in bringing a pyrolyzer technology to market versus burying it in the pyrolysis graveyard. 

The Intricacies of Pyrolyzer Furnace Design   

The latest data from Eurostat indicates that the European Union is on track to meet its renewable energy target of 20 percent by 2020. In 2014, with six years left to reach that goal, 16 percent of the region&rsquo;s energy was derived from renewable sources. The Baltic Rim countries have been some of the most successful, with Sweden (49 percent), Finland (38 percent), Estonia (25 percent) and Lithuania (23 percent) already exceeding their shares. Denmark (30 percent), Latvia (40 percent), Poland (15 percent) and Germany (18 percent) are on trajectory to meet their targets, though they have yet to do so. Demand One of the many components of these countries&rsquo; plans to successfully meet 2020 targets is a commitment to district heating (DH) and combined-heat-and-power (CHP) projects. Though these countries either have already met or are quickly approaching their targets, they continue to invest in small-scale DH and large-scale CHP projects. Denmark is a good example of this. Just 0.8 percent shy of its target, the country is slated to get two new CHP plants between now and 2019. Dong Energy plans to open a 280-MW CHP plant in Fredericia in 2017, a facility that will be fueled primarily by wood chips and use an estimated 700,000 metric tons annually, and near Copenhagen, Hofor plans to open a 500-MW CHP facility that is expected to consume 1.2 million metric tons of wood chips annually. Denmark is not the only Baltic Rim country ramping up its biomass CHP capacity. Also coming online in 2019 is a newly announced, 150-MW facility in Lahti, Finland. So where will the fiber supply come from to meet this new demand? Among the most likely suppliers will be the Baltic States. With modern and well-developed forest products industries (sawmills, panel mills and pellet mills); effective and efficient harvesting, processing (chipping) and transportation infrastructure; an excess supply of biomass (annual harvests equal approximately 70 percent of net annual growth in the region&rsquo;s forests); and a history of strong export partnerships, the Baltic States are poised to take advantage of these market opportunities. Baltic States Wood Fiber Supply According to the United Nations Economic Commission for Europe, approximately 30 million cubic meters of timber are harvested annually in Latvia, Estonia and Lithuania. Approximately 50 percent of the annual harvest is in the form of saw and veneer logs and 26 percent is pulpwood, a product that has very limited capacity for consumption in the immediate region. Other roundwood makes up 4 percent of the annual harvest, and wood fuel makes up another 20 percent. Wood Chip Classifications Wood chip classifications in the Baltic States can be fluid; they can vary based on source, quality and market conditions and destination. In Latvia, for instance, chip producers supply pulp quality conifer and hardwood chips to pulp and paper facilities in both domestic and export markets. In addition, they produce technology and energy chips for domestic and export markets that are sometimes interchangeable and sometimes not, depending upon their destination. These include: &bull; Forest residue-quality domestic energy chips: Domestic energy chips are generated from forest residues, chipped in woods post-harvest and used to fuel DH and CHP plants. &bull; Forest residue-quality export energy chips: Excess supply of forest residue quality energy chips are exported to Finland and Sweden.&nbsp; &bull; Domestic technology chips: In Latvia, hundreds of small sawmills do not have debarking capacity. Bark remains on slabs after logs are canted, and this material is stored on site awaiting chipping. Chip producers then send mobile chippers to these mills to create technology chips that are delivered domestically to medium-density fiberboard or wood pellet mills, a growing business in the region. &bull; Danish-quality export energy chips: Excess supply of technology chips are exported. Denmark sources this higher-quality energy chip from Latvia because it has a lower ash content than forest residue energy chips. Challenges Remain While the Baltic States have much of what they need to capitalize on the export energy chip trade as it expands, perhaps the single most important missing ingredient to aid this expansion is the kind of market transparency that high-quality market pricing information brings. With these eight categories of wood chips, all produced from different raw material with varying chipping and transportation costs, pricing will challenge suppliers who are trying to maximize their revenues, as well as consumers who are trying to keep their wood costs low. As export opportunities for this underutilized material from the Baltic States grows over the rest of this decade, the addition of high-quality market data will create the kind of transparency that will allow for more orderly sales and purchases of this material, and support the types of long-term supply agreements that will stabilize the market for long-term benefits for the industry as a whole. &nbsp; Contact: Tracy Leslie Director, Forest Biomaterials and Sustainability, Forest2Market Tracy.leslie@forest2market.com www.forest2market.comxx

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

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

Baltic Rim Wood Fiber Supply and Demand 

We buy boilers to provide water consistently at a specified temperature. That&rsquo;s their core function. Sound simple? If this function is so important, why not measure how well biomass boiler plants accomplish this fundamental task? DCM Logic has developed a simple and straightforward way of doing this: Compute the percentage of heating time that a biomass plant produces water greater than the set point minus 2.5 degrees Celcius. (If the plant generates steam, use pounds per square inch (psi) greater than or equal to set point minus 1 psi instead.) Add in the times when the biomass plant can&rsquo;t make this temperature (or pressure) goal, but all biomass boilers are working at greater than 95 percent modulation. (Undersizing is a rational design decision, and there&rsquo;s no need to penalize it.) We call this Boiler Plant Effectiveness, or BPE. Expressed mathematically, that&rsquo;s BPE equals percent of heating time when water produced by the biomass boiler plant is equal to or greater than the set point minus 2.5 degrees C, or modulation of all biomass boilers greater than 95 percent. For &ldquo;water produced by boiler plant,&rdquo; use the storage tank top temperature. If you don&rsquo;t have a tank, use the water temperature exiting the biomass boiler plant, before any mixing is done. This formula isn&rsquo;t proprietary to DCM Logic&mdash;one can try this at home, or in the office, or at a nearby boiler plant. One can calculate it on his or her own with just a spreadsheet. For longer periods of time, one may want to enlist the help of a controls contractor or boiler manufacturer. DCM Logic can help as well. It&rsquo;s the only way to really know and quantify how well a biomass boiler plant is doing its primary job. You may wonder how BPE relates to efficiency and emissions. It doesn&rsquo;t. A higher-performing boiler plant will generally use MORE fuel than a lower-performing boiler plant. Efficiency is nice, though focusing on it exclusively is a bit like asking which participant in an athletic competition burned the fewest calories. Times or scores in the event are far more important, as they are the performance measure that separates the competitors. Clean, green, local, and cheap (sometimes!) are just dandy, but they&rsquo;re not enough to take biomass heat from niche to mainstream. We also need to keep score, and let the world know how well biomass heat works. Author: David Spindler Chief Operating Officer, DCM Logic dns@dcmlogic.com 603-283-9183

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DCM Logic has developed a simple and straightforward way of measuring Boiler Plant Effectiveness, or BPE.

Keeping Score

Most pellet producers make pellet quality a priority. Increasingly, means to verify this desired quality is making its way to mills. Though not uncommon for fuel manufacturers to have testing capabilities for some of their fuels&rsquo; properties, in light of the growing interest in becoming qualified under a third-party accreditation program, producers are designating or revamping lab space at their plants. Although often modest in size, in-house labs are equipped with a variety of testing tools to assure pellets not only meet company and customer standards, but also those set by quality certification programs, like the Pellet Fuels Institute&rsquo;s Standards Program, CANplus or the European ENplus benchmark for wood pellets. &ldquo;Before we even started the mill up, we actually built and set up a rather complete testing lab right here at the plant,&rdquo; says Darren Winchester, safety quality and logistics manager at Indeck Ladysmith LLC. The 90,000-ton-capacity plant in Ladysmith, Wisconsin, began pellet production and testing in 2009, when PFI&rsquo;s quality program had not yet been fully developed. &ldquo;Up until we joined the new standards program, we would send out our sister plant samples for third-party testing every 1,000 tons, even though we didn&rsquo;t have to,&rdquo; Winchester says. &ldquo;What that&rsquo;s done for me is provided me with a substantial amount of correlation data.&rdquo; Without data to back up a pellet operation, he adds, it&rsquo;s not a very robust system. &ldquo;You can run without testing, but basically it&rsquo;s like running with a blindfold on,&rdquo; he says. Luann Lafreniere, New England Wood Pellet&rsquo;s quality manager, says when they decided to join the PFI Standards Program, the entire company was folded into the quality management system they developed. Now, even though some testing was done prior to PFI qualification, all four plants (Deposit, Schuyler, Jaffrey and Allegheny) have labs with the same testing equipment and comprehensive data-tracking system. &ldquo;We were testing before, but we were not gathering the data to compare month to month, season to season, to see where our swings are,&rdquo; she says. Testing Pellet Parameters PFI set standard specifications for residential and commercial densified fuel in documents published July 9, 2015. The normative fuel properties included in the specification, and mandatory for determining fuel quality grade, include fines, bulk density, diameter, length, heating value, chloride, moisture content, pellet durability index and inorganic ash content. Not all in-house laboratories can test this entire list of properties, and therefore rely on the accredited third-party auditing agencies and testing labs to discover the remaining unknowns. PFI-qualified facilities test internally and send pellets out for third-party testing. &ldquo;There is a verification relationship there,&rdquo; says Michael Foster, director of quality assurance with Somerset Pellet Fuel&rsquo;s 55,000-ton-capacity plant in Kentucky. &ldquo;On a daily basis, we&rsquo;re running the myriad of quality tests in our laboratory, but on a monthly basis, somebody from Timber Products Inspection will visit our plant unannounced. They&rsquo;ll do a documentation inspection of our quality processes and then they will take a sample of pellets with them.&rdquo; Foster adds that plant staff will pull a counterpart to those sample bags at the same time on the production line and retain it at Somerset, so when the lab results from TPI come back, they can test the bag made on the same day to see if they can replicate those results. Certain tests are outside the realm of in-house capabilities, mostly because of the equipment expense, so a shortened testing list of largely mechanical pellet properties is what&rsquo;s required in order for PFI Standards Program fuel manufacturers to qualify for and maintain reduced audit sample testing frequencies. These production facilities must have in-house labs capable of testing for bulk density, fines, length, diameter, durability and moisture. These tests must be verified to provide accurate results by cross-checking with an American Lumber Standard Committee accredited lab (at least twice annually), as a quality assurance measure to verify the accuracy of in-house testing equipment and methods. In addition, in-house test data must also demonstrate that the facility is within compliance of the grade requirements. According to PFI&rsquo;s residential and commercial densified fuel quality assurance and quality control (QA/QC) handbook, samples must be collected at least twice per day or once per shift, whichever generates the larger number of samples, and consist of bags of product that would typically be shipped or directly from a bulk load if bulk delivery is performed. While PFI&rsquo;s Standards Program test methods are determined in accordance with ASTM test methods, for pellet manufacturers exporting product, ENplus are based on an international standard: ISO 17225-2. Although the testing styles referenced differ, the pellet properties measured are the same.&nbsp; Whether a qualified ENplus or PFI producer, tests are not necessarily conducted in the same order every time, but there are ways more streamlined than others. Samples collected from bagged pellets usually start with a bag splitter. LJR Forest Products 150,000 ton-150,000-ton-plant located in Swainsboro, Georgia, begins with this step when testing ENplus bagged pellets. Lige Moore, plant manager, says the company decided to undergo ENplus certification to sell to that market. &ldquo;If we&rsquo;re testing for ENplus bagged pellets, we&rsquo;ll go out and get a bag, bring it in and pour a 40-pound bag into a bag splitter, which divides the bag into two halves evenly,&rdquo; Moore says. From there, those 20-pound samples can be sized down to smaller samples depending on the test. Typically, after the sample is measured, the first thing that Smith Flooring Quality Manager Steve Meier measures for is bulk density. Smith Flooring&rsquo;s 25,000-ton-capacity plant in Mountain View, Missouri, joined PFI&rsquo;s qualified manufacturer list this year. He explains that weights are critical to all of their testing. Bulk density testing, for example, is purely a matter of weighing, he says, by pouring a 15-pound sample of pellets into a known volume container (one-quarter-cubic-foot) from a specified distance, after which the pellets are shaken down and compacted in the container. For bulk density, PFI requires that these containers, or laboratory-grade aluminum pots that look like big cook pots, are tapped 25 times from a height of one inch. An important measurement producers check for is fines. At Somerset, fines content is determined using a laboratory-grade sieve with a one-eighth-inch wire screen. As outlined in PFI&rsquo;s standard specifications, the sample is screened by tilting it side-to-side 10 times. Fines are generated while testing for pellet durability. Foster says a screened and weighed sample is loaded into a two-chamber durability tester at Somerset to test pellet durability. The sample is then tumbled 50 times per minute for 10 minutes, in what he says is reminiscent of a rock tumbler. Durability is determined by rescreening and weighing the sample. In PFI&rsquo;s standard specifications, the durability tester is referred to as a &ldquo;dust-tight box,&rdquo; which is made of a rigid material with smooth and flat surfaces. Pellet diameter is another of the audited parameters. Producers record pellets&rsquo; dimensions often using a simple set of purchased calipers capable of measuring to within 0.001 inch, according to PFI testing parameters. Pellet length is determined by the weight of all pellets in the sample exceeding 1.5 inches in length. Meier uses dial calipers to measure length and diameter. Lengths can sometimes become an issue, he says, depending on the pellet mill and how it&rsquo;s performing. &ldquo;We&rsquo;re allowed up to 1 percent of over lengths, but typically, as you sift through samples you&rsquo;ll find maybe four or five pellets that exceed an inch and a half in length, so we weigh those and record that and relate it to the percentage of a 5-pound sample,&rdquo; he says. Diameter tests are conducted by randomly selecting five pellets out of the pellet sample being evaluated. The average pellet diameter, as well as the range of all pellet diameters measured, should be calculated and reported. In-house labs qualified to PFI&rsquo;s program also measure moisture, and some measure ash content, although it's not a requirement under PFI&rsquo;s QA/QC handbook section 6.11 specifications for in-house labs. At Somerset, Foster says, a laboratory-grade pellet grinder is used, which grinds up a 5-gram sample to check moisture content. Some equipment measures both moisture and ash. Indeck installed the Arizona Instruments Max 5000 moisture and ash testing instrument. Although it&rsquo;s a costlier piece of equipment, Winchester says, &ldquo;one of the critical things in the manufacturing process is moisture content.&rdquo; In fact, he adds, they have four moisture meters staged throughout the pelleting process, &ldquo;so the operators can stay on target with the moisture content of the material coming in and out of the pellet mills.&rdquo; The process moisture meters are also verified routinely using a moisture balance, which is a scale with an infrared heater on it. A 5-gram sample can be dried on it, verifying moisture content within five minutes, according to Winchester. At NEWP&rsquo;s plants, ash content is determined by burning the pellets in a Vulcan A-550 laboratory furnace at a temperature of 1,100 degrees Fahrenheit to determine the percentage of inorganic material in the fuel, Lafreniere says.&nbsp; Not only must the fuel meet certain specifications, but the equipment used to measure it must as well. Equipment like calipers, balances, scales and measuring blocks must meet certain calibration and standardization requirements. For example, producers are asked to perform an initial calibration on balances and scales using NIST or other recognized national standards, and before each test, verify the balance or scale by using at least one calibration weight that corresponds to 50 to 150 percent of the weight of the fuel sample to be measured. If the balance or scale cannot reproduce the value of the calibration weight to within 1 percent of the mass, it must be recalibrated before use. &ldquo;We have a calibration program for our equipment,&rdquo; Foster says. &ldquo;It&rsquo;s a third-party calibration program for which we have outside sources come in a couple times per year and recalibrate our balances, our calipers, and there are a few in-house verification activities we do ourselves.&rdquo; All in all, among a number of producers, the amount of hands-on time required to conduct tests seems to average around 15 to 20 minutes, with a few tests, like moisture and ash testing, taking anywhere from 30 to 90 minutes for test results to come back. For plants that aren&rsquo;t qualified under a fuel-grading program, bulk density, fines and bag weight are three basic measurements that can be done without necessarily accruing a high cost, according to Winchester. How much producers invest in testing equipment varies considerably, anywhere from a couple thousand dollars to upwards of $50,000. &ldquo;You can spend more or less, it just depends on what you order,&rdquo; Moore says. He estimates LJR invested around $5,000 for its ENplus testing lab equipment. Lafreniere manages the four NEWP labs and found the investment can actually result in cost savings. She says the company probably saved the first year&rsquo;s costs of becoming qualified in PFI&rsquo;s program by coming up with a process to fine-tune scales to measure bag weight. Training The big word with quality is consistency, Winchester says. &ldquo;If you run a day, a week, a month without doing any testing, there is variability in manufacturing and the testing process, and one of the challenges of manufacturing is striving to reduce variability,&rdquo; he says. &ldquo;Bottom line is through sampling, generally what you&rsquo;re doing is understanding your process better, what kind of variability you are having.&rdquo; Testing helps avoid variability in pellet quality, but controlling variance between how each lab member tests for that quality is important. &ldquo;Just because you test doesn&rsquo;t mean you&rsquo;re always going to get good data,&rdquo; Winchester says. &ldquo;One of the key variables in any sample is how you sample and how you test. If you have four people doing the same test, there is a good chance there will be variation, and that&rsquo;s what another one of those big challenges is to minimize that variation from person to person.&rdquo; Some test methods leave room for more variance than others. To combat that variability in one instance, Indeck made adjustments to how it measures bulk density, which is typically done by manually tapping down a sample-filled aluminum container 25 times from one inch. &ldquo;As a guy who not only does the test but also trains, I have to make sure people are doing it correctly,&rdquo; Winchester says. &ldquo;Dropping a metal container from exactly one inch for a number of repetitions, as per bulk density protocol, is challenging for many people and some have a tendency to want to slam it down because it&rsquo;s hard to let something go and drop repeatedly from one-inch high exactly every time.&rdquo; Now, having collaboration with in-house maintenance personnel, this process has been automated where the container moves up and down hands free. As for who&rsquo;s conducting the tests, the majority of plant employees are trained to conduct lab tests. At Indeck, the staff members who receive chips and sawdust do feedstock sampling and testing, shift supervisors running the mills sample out of the pellet cooler every few hours and run tests, and package line operators are also responsible for doing sampling and testing. &ldquo;Pretty much our whole staff is trained because we switch around sometimes,&rdquo; Winchester explains. Meier at Smith Flooring&rsquo;s new lab recently received training from Chris Wiberg with Timber Products Inspection, a third-party accredited auditing agency and testing lab. &ldquo;I turned around and trained people, and just about everyone is capable of running the tests on an as-needed basis, but typically I do the days and another employee does the evenings,&rdquo; he says. TPI also trained staff at NEWP, and Lafreniere says it&rsquo;s the company&rsquo;s goal to train all operators to do the testing. &ldquo;Typically, the plant managers are trained, and then they train their team leaders,&rdquo; she says, adding that every shift has a team leader who in turn trains other employees. There is an annual refresher training course for all employees involved in lab testing. Besides serving as an auditing agency under PFI&rsquo;s Standards Program, TPI certifies ENplus manufacturers. &ldquo;When ENplus mill operators are hired, it&rsquo;s about a month-long training of learning the mill operation, day-to-day procedures for running the mill, and during that time we teach them the procedure for the ENplus testing,&rdquo; Moore says. He adds that training is fairly complex, but once the process of the mill is understood and the testing procedures outlined in the ENplus handbook, &ldquo;it&rsquo;s fairly simple.&rdquo; Charting Trends Recorded lab results bring value to the plant over time, by tracking trends and providing data for monthly audits, under the PFI Standards Program. Even though Smith Flooring has been in production for less than two years and PFI-qualified for only a matter of months, Meier says he keeps a trending log of every test performed to track daily changes, and whether any mill adjustments are needed. At Somerset, dashboard-driven Excel databases are set up. Foster says all of the inputs and outputs of an audit are entered, results from the various pellet properties will be calculated, and a numerical result will appear on the screen, flashing green for good or red for bad. The entry is automatically recorded into the database, and both a written and electronic copy are kept. Another component of the dashboard Foster mentions is the help button. &ldquo;You can click the help button, then the name of the test, and it will pull up all of the parameters of the tests on the screen,&rdquo; Foster says. According to Lafreniere, monthly results from all four of NEWP&rsquo;s facilities are gathered in testing logs which are then linked to quality charts, and the results are distributed throughout the company on a monthly basis. &ldquo;We can see, for instance, the ash results as a monthly average for each one of our facilities compared to the other,&rdquo; she says. Besides monthly reports, Lafreniere holds monthly quality meetings where the staff identifies any process changes that need to be made. Of the company&rsquo;s data-gathering procedures, she says, &ldquo;Ours is a no-brainer. You can immediately see a change in any of the plant&rsquo;s trends because it&rsquo;s right there on the chart.&rdquo; As more producers move toward qualifying their product under a fuel-grade program, it becomes clear that having the equipment to test a pellet at the site of its production helps ensure consistent quality, consumer confidence and overall better plant performance. Author: Katie Fletcher Associate Editor, Biomass Magazine 701-738-4920 kfletcher@bbiinternational.com

Reducing Variability: Pellets are tested for a number of properties at Somerset Pellet Fuelâ€™s in-house lab in Kentucky, including tests for durability, fines and bulk density shown above. A balance is used in conjunction with nearly all tests, and 

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Delayed Results: Steve Meier, quality manager of the lab at Smith Flooringâ€™s pellet mill, prepares the ash and moisture pellet test. After the sample is inserted and the lid closed, the 5-gram sample is ground up, taking 30 to 40 minutes to show re

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In-House Equipment: NEWP designed its own pellet length analyzer (left) and pellet durability tester (right). The pellet length analyzer works by shaking a pellet sample into six different jars based on length. Ideally, most pellets fall between thre

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In-house pellet plant labs enable fuel quality monitoring, an asset for regularly audited producers. 

Apparatus Advantage 

The uncertainty that surrounds the United Kingdom&rsquo;s biomass sector has been swirling for some time, and the recent vote for the U.K. to exit the European Union has exacerbated the situation. Since the Conservative government came to majority power in 2015, things for biomass haven't been looking as bright as before. The Brexit result was preceded by significant cuts to subsidies that had already led to many projects being cancelled or scaled back. An immediate impact of the referendum result has seen the value of the pound plummet against the euro and the U.S. dollar, meaning imports have become much more expensive. As the world&rsquo;s largest importer of wood pellets for biomass energy, much of which comes from North America, Brexit may hard hit the pockets of many U.K. businesses. The biggest concern for the sector is that investments will now be significantly cut. Many of the advances that have been made in the technologies and roll-out of biomass have been funded through the European Investment Bank. The EIB is owned by the 28 member states of the EU, with the U.K. owning 16.11 percent of the shares. But to be a shareholder of the EIB, a country must be a member state of the European Union, so the U.K. will now have to pull out of the EIB. On the day that the referendum results were announced, Werner Hoyer, president of the EIB issued a statement, saying, &ldquo;Today is a very sad day for Europe. As president of the European Investment Bank, I take note of the U.K. vote with the deepest regret, although of course the bank will work with member states and other EU institutions to assure an orderly transition to a new negotiated arrangement according to the treaty.&rdquo; For now, U.K. shareholding in the EIB remains, and the EIB&rsquo;s engagement in the U.K. is unchanged. While the Conservative party begins negotiating its exit from the EU, EIB shareholders will be discussing how the bank is going to engage with the country in the future. Funding Fallout In the past decade, the EIB has invested around 50 billion euros in U.K. projects, particularly in renewable energy and infrastructure. Amongst all the well-founded concerns about the future of the sector, there has been some good news&mdash;three big biomass projects that received European Commission approval recently for Contract for Difference (CfD) subsidies will still be moving forward. These are the 420-MW Lynemouth coal-to-biomass conversion for Czech energy firm EPH, Drax&rsquo;s full conversion of its 645-MW Unit 1, and U.K. company MGT Power&rsquo;s, 299-MW Teeside combined-heat-and-power project. Members of EUREC, the Association of European Renewable Energy Research Centres, collaborate on EU-funded projects to advance technologies for all renewable energies. Vinicius Valente, EUREC&rsquo;s communications adviser, has concerns but is still hopeful that biomass research and development can still advance in a post-EU Britain. &ldquo;We regret the U.K.&rsquo;s decision to leave the European Union despite all the breakthroughs achieved by the EU in several strategic areas, including excellence in science,&rdquo; he says. &ldquo;EUREC has a long history of engagement with the EU, and our U.K. members are all prominent research centers that have been working for many years with EU funds to unlock the potential of several technologies.&rdquo; Many of the research programs that EUREC members and other research institutes and businesses in the U.K. and Europe are involved in are funded through the EU Framework Programme for Research and Innovation, Horizon 2020. This 79 billion-euro funding initiative runs until 2020 and aims to drive forward scientific understanding and innovation in energy and many other areas, particularly those that are tackling climate change. Former U.K. Prime Minister David Cameron indicated in a statement to the U.K. Parliament that any contract signed under Horizon 2020 will be honored. But it&rsquo;s unclear if, post-Brexit, it would be honoured with EU money or British money. Carlos Moedas, EU research commissioner, has confirmed that researchers remain eligible to apply for funding from the Horizon 2020 research program, since the U.K. remains a member of the EU until the end of the negotiations. But if the U.K. is not going to be a part of the EU from 2018 onward, it seems unlikely that any projects involving U.K. universities and businesses that extend beyond then will be top of the list to access that funding pot. Any projects that receive funding must be made up of a consortium of at least three organizations from different member state countries, so the decision is likely to make U.K. organizations a less-attractive partner when consortiums are coming together. But could the U.K. become a new Switzerland in the way it participates in projects? The &ldquo;Swixit&rdquo; Framework Programme that was introduced in 2014 means that Switzerland has the status of &ldquo;nonassociated, third-country participant&rdquo; in some parts of Horizon 2020, including projects under the Energy Societal Challenge Work Programme. Valente added, &ldquo;The U.K. might, in the future, enjoy a similar status. But that said, it is rare that the European Commission&rsquo;s Horizon 2020 money funds nonassociated, third-country participants. Instead, national funding agencies must cover their costs and this could be the case for the U.K.&rdquo; Climate Agreement Goals The growth of biomass in the EU has been driven by the need to achieve cleaner energy generation in order to meet greenhouse gas emission reduction goals. Considering the backtracking the Conservative party has already done with biomass subsidies, many questions are being raised around the climate change agreements the U.K. has signed up to. So far, initial signs are good. Statements coming from the U.K. government have confirmed that the commitment to increasing renewable energy generation remains. Amber Rudd, minister for energy and climate change, was an ardent &ldquo;Remain&rdquo; campaigner, and issued a statement saying, &ldquo;We have announced record investment in new heat networks, to enable new and innovative ways of heating our homes and businesses. And we made a commitment to closing unabated coal-fired power stations&mdash;a commitment that was praised by leaders across the world. All these commitments remain in place. They will help us rebuild our energy infrastructure, and I am certain that future investment in this sector will continue to flow to Britain&rsquo;s strong economy.&rdquo; On June 30,&nbsp; the U.K. government also confirmed the Committee on Carbon Change&rsquo;s recommended carbon budget, aiming for a 57 percent reduction in carbon emissions from 1990 levels from 2027-&rsquo;32. But in order to achieve these goals, they are investing half of the renewables funding pot in new nuclear. James Court, head of policy and external affairs at the U.K.&rsquo;s Renewable Energy Association, says, &ldquo;The fundamentals of energy have not changed post-referendum, we still need new generation that is cost-effective, low-carbon and secure. This would be the worst time for the government to row back or U-turn on existing commitments, which would be toxic to inward investors. So this is a positive first step, but will need to be backed up by a robust energy plan by the end of the year.&rdquo; Innovation Continues The U.K. has been defined by its technological innovation since the time of the industrial revolution, and leaving the EU will not change that. The drive to develop new and better biomass solutions continues. One of the most exciting new developments in the U.K. biomass industry in recent times has come from a new London-based business, Bio-bean, and its stakeholders are feeling confident that the Brexit result is not going to affect plans for growth at all. The business started up in 2014 and believes it is the first company in the world to industrialize the process of recycling waste coffee grounds into advanced biofuels and biochemicals. The company works within the existing energy and waste infrastructure and has developed sustainable products and solutions to replace conventional fuels and chemicals. It has launched nationwide collection services and recycles the used coffee grounds into biomass pellets and briquettes. The next step is to turn them into biodiesel, and the ultimate goal is to go international.&nbsp; &ldquo;Historically, even during recessions, the appetite for drinking coffee remains consistent no matter the economic circumstances,&rdquo; says CEO Arthur Kay. &ldquo;For our business, because our feedstock is already here and we simply divert it from less valuable forms of waste disposal, we are largely insulated from the negative influence of Brexit.&rdquo; Despite the uncertainty that has been shaking the country since the Brexit result, there is still a lot of confidence that the renewable energy sector, and biomass within it, can still thrive. Author: Amanda Saint Biomass Magazine freelance writer amandasaintwriter@gmail.com EDITOR'S NOTE: At press time, it was announced that new U.K. Prime Minister Theresa May has dissolved the country's Department of Energy &amp; Climate Change. Visit www.biomassmagazine.com for continued, up-to-date coverage.

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

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There are real concerns about what Brexit means for the future of the U.K.'s renewable energy sector, which has grown significantly with the help of EU-funded investments and subsidies. 

Brexit and Biomass

The emission of acid gases from power plant and boiler combustion is a major threat to human, animal and plant life, and the environment. Acid gases such as sulfur dioxide (SO2) or hydrogen sulfide may effect ecosystems through acid rain or dry deposition. &ldquo;Some acidic lakes have no fish,&rdquo; states the EPA. &ldquo;Even if a species of fish or animal can tolerate moderately acidic water, the animals or plants it eats might not.&rdquo; Areas effected by acid rain may be visually identifiable by the presence of dead or dying trees. Acid rain leaches aluminum from the soil, which may be harmful to plants and animals. Acid rain also removes minerals and nutrients from the soil that trees need to grow, according to EPA. &ldquo;At high elevations, acidic fog and clouds might strip nutrients from trees&rsquo; foliage, leaving them with brown or dead leaves and needles,&rdquo; the agency states. &ldquo;The trees are then less able to absorb sunlight, which makes them weak and less able to withstand freezing temperatures.&rdquo; Mitch Lund, a technical services engineer at Nol-Tec Systems, a process engineering company with a focus on bulk material handling and acid gas control, says the term &ldquo;acid gas&rdquo; is a generic chemical description for any gaseous mixture containing acid-based compounds. &ldquo;If present in high enough concentrations and inhaled, acid gases can be harmful to life&mdash;specifically by breaking down respiratory and skin cells,&rdquo; Lund says. &ldquo;Additionally, when acid gas is released into the atmosphere, it combines with moisture to form acid rain.&rdquo;&nbsp; This is a problem for biomass, Lund says, because burning fuel for power or steam generation creates acid gases in the combustion process. &ldquo;Fuel has sulfur- and nitrogen-based compounds that, when burned, form gaseous SOx and NOx compounds that are the basis for acid gases,&rdquo; he says. SOx and NOx are sulfur and nitrogen oxides, respectively. &ldquo;Plants absorb minerals from the earth in which they grow, and some plants&mdash;citrus trees in particular&mdash;absorb more chlorine than others,&rdquo; says Link Landers, an engineer with PPC Industries, a company focusing on pollution control that, in 1988, developed an acid control system using dry sorbent injection (DSI). &ldquo;And some plants absorb more sulfur than others.&rdquo;&nbsp; Because acid gases are hazardous to human health and the environment, they are regulated by local, state and federal agencies. &ldquo;Recently, acid gas regulation has been driven at the federal level, while working closely with states to enact implementation plans designed to control local economic impact,&rdquo; Lund says. &ldquo;The roots of these federal regulations are based in the Clean Air Act of 1973 that gave the EPA power to control air pollution at a national level. Amendments to this ruling in the past 30 years have enforced the control of acid gases.&rdquo; Landers notes that the National Ambient Air Quality Standards established six criteria pollutants. &ldquo;In this, hazardous air pollutants (HAP) were established, and included in these are acid gases,&rdquo; Landers says. &ldquo;Specifically, the heart of the current regulations states that there cannot be more than 10 tons per year of any single HAP and no more than 25 tons per year of all HAPs combined.&rdquo; Lund further explains that &ldquo;recent acid gas rulings like the Mercury and Air Toxic Standards and the Industrial Boiler Maximum Achievable Control Technology set limits on how large boilers have to be in order to be deemed necessary to regulate,&rdquo; he says. &ldquo;Any coal- or oil-fired unit that sells electricity to the grid and is greater than 25 megawatts (MW) must comply with MATS. The IB MACT applies to any process boiler that has the potential to emit 10 tons per year of a regulated pollutant or 25 tons per year of any combination of pollutants. These federal rulings require each boiler to be evaluated on a case-by-case basis. Some companies are regulated on an overall facility fleet basis, but these are the exceptions, not the rule.&rdquo; States are required to develop State Implementation Plans to carry out federal laws set forth by EPA. &ldquo;The SIPs can be more restrictive than the federal law, but not more lax,&rdquo; Landers says. Here is how one would calculate whether a power plant or a boiler for plant use&mdash;since the regulations do not differentiate between the two&mdash;would be subject to the IB MACT rule for one regulated pollutant: chlorine. &ldquo;If we assume a 150 MMBtu-per-hour power plant utilizes a fuel that has 7,500 Btu per pound, and contains 0.01 percent of chlorine on a wet basis, then that is 20,000 pounds per hour of fuel and 2 pounds an hour of chlorine, which, if the plant operated 8,760 hours per year would yield 17,520 pounds, or 8.76 tons, per year,&rdquo; Landers says. &ldquo;This is below the annual limit. But, increasing the plant size to 200 MMBtu per hour would yield 11.7 tons per year of chlorine, thus requiring some type of control.&rdquo; He says the big fear is that EPA may lower the HAPs limits from 10/25 to, for instance, 8/20. &ldquo;The general trends in the industry show that as years pass, newer compounds are added to regulation laws and existing compounds come under tighter regulations,&rdquo; Lund says. &ldquo;In general, as technology and environmental awareness evolve, pollution control does, too.&rdquo;&nbsp; Options For SO2, sulfur trioxide (SO3) and hydrochloric acid (HCl) control, the most common solutions, according to Lund, are wet scrubbers and DSI systems. Landers says both types come in a variety of methodologies and configurations. Nol-Tec Systems has more than 70 permanent acid gas removal systems in place today, Lund says. &ldquo;We have also placed more than 70 testing or leasing temporary systems over the past 10 years,&rdquo; he says. &ldquo;We have three systems that use biomass as their main fuel source, but we also have numerous sites that utilize some smaller percentage of biomass as a fuel. Our DSI systems are flexible to work with either biomass of any type, or more traditional fuel sources, such as coal.&rdquo; Nol-Tec has provided DSI systems for acid gas control and activated carbon injection (ACI) systems for mercury control since the early 2000s. &ldquo;We got into the industry based upon our experience pneumatically conveying dry powders,&rdquo; Lund says, adding that Nol-Tec also provides wet scrubbers through its Lodge Cottrell division. Wet scrubbers work by passing the dirty gas through a liquid compound that is designed to react with the targeted acid gas for removal from the dirty stream. &ldquo;On the wet side, there are packed tower scrubbers, venturi scrubbers, bubbling tray scrubbers, virtual tray scrubbers, also called spray scrubbers, which utilize cross flow, cocurrent and countercurrent flow methodologies,&rdquo; Landers says. &ldquo;These scrubbers can use a variety of bases to accomplish the acid-base reaction required to neutralize the acids.&rdquo; Caustic seems to be the reagent of choice for smaller systems, says Ray Willingham, an engineer at PPC Industries. &ldquo;Larger utility-scale systems commonly use limestone,&rdquo; he says.&nbsp; DSI systems inject a dry chemical sorbent, or powder, into the flue gas for the same targeted removal as wet scrubbers, Lund says, and both solutions&mdash;wet scrubbers and DSI systems&mdash;form byproducts that are separated from the process and must be properly disposed of. Landers says this powder can be milled, unmilled or evaporative.&nbsp; &ldquo;Trona or sodium bicarbonate are typically used in these systems,&rdquo; Willingham says. &ldquo;Milled and unmilled injection is accomplished by blowing the base into a reaction chamber or duct where random probability takes over,&rdquo; Landers says. &ldquo;An acid molecule must come in contact with the base molecule.&rdquo; Willingham notes that two factors come into play here&mdash;particle numbers and surface area.&nbsp; &ldquo;The greater number of base molecules compared to acid molecules, the more likely the reaction will occur and the higher the removal,&rdquo; Landers explains. &ldquo;The smaller the particle size, the longer it will stay airborne,&rdquo; Willingham says, adding that this leads to better mixing in the gas and thus a greater probability of the base particle coming in contact with the acid molecules. &ldquo;Additionally,&rdquo; he says, &ldquo;the smaller the particle, the greater the surface area to volume ratio of the particles, and since the reaction requires contact between the base particle and the acid molecule, the combination of an increase in the particle numbers and the available surface area provides an improvement in the performance and removal efficiency of these systems.&rdquo; Landers says this provides the basis of the argument for milled vs. unmilled injection. &ldquo;Milled injection typically requires less raw material overall, thereby lowering the operating costs,&rdquo; he says. For acid gas removal, PPC Industries, which has been at its current location in Longview, Texas, since 1967, offers milled DSI systems. &ldquo;We were a precipitator-only company until 1988 when we developed acid control system using dry sorbent injection,&rdquo; Landers says. &ldquo;In 1995, we started producing biofilters for control of volatile organic compounds, and wet electrostatic precipitators. In 2007, we developed selective catalytic reduction units for NOx control and nonselective catalytic reduction units for carbon monoxide control.&rdquo; PPC Industries has installed DSI systems at 16 locations with nine of them being biomass boilers. Those that are not biomass are glass production plants and incinerators.&nbsp; Landers says evaporative systems utilize a combination of wet and dry scrubbers. &ldquo;A slurry mixture is injected into a reaction chamber where the water portion flashes off leaving a fine powder&mdash;smaller than milled dry sorbent&mdash;that reacts with the acid gases,&rdquo; he says.&nbsp; These systems, according to Willingham, typically operate using limestone or slaked lime. Lund says a popular form of NOx removal is selective catalytic reduction, which involves injecting an ammonia-based material into a reactor that reacts with the NOx in flue gases to form the nontoxic compounds nitrogen and water. Acid gas clean-up in natural gas facilities vs. coal or biomass plants, for instance, focuses on NOx-based removal. &ldquo;Combustion-based technologies like low NOx burners, flue gas recirculation, and selective noncatalytic reduction systems are commonly used to combat NOx emissions in natural gas facilities,&rdquo; Lund says. &ldquo;Biomass, however, has a very broad fuel base, so the options for acid gas control are wide-ranging. The fuel will determine the emissions, which determines control requirements and strategies.&rdquo; Wet or Dry? The big difference between the two technologies&mdash;wet scrubbers and DSI systems&mdash;comes down to operating vs. capital costs, says Lund. &ldquo;Wet scrubbers are very efficient technologies that have low operating costs,&rdquo; he says, &ldquo;but they require capital investments in the hundreds of millions of dollars. DSI systems are the exact opposite. They have low capital costs&mdash;typically $1 to $2 million per system&mdash;but they have relatively inefficient use of sorbent, causing high operating costs.&rdquo; While Lund admits that Nol-Tec Systems&rsquo; expertise with wet scrubbers in the biomass industry is limited, he says if a utility plant were used as a case study, wet scrubbers are anywhere from 50 to 100 times the capital cost of a DSI system, but the operating costs of a DSI system are usually 5 to 10 times that of a wet scrubber. Willingham says dry systems tend to require less exotic metallurgy, a main reason for the lower capital costs. Lund says small units, or larger units with a short expected lifespan, are good candidates for DSI technology. &ldquo;Biomass plants are usually small enough to always be good candidates for DSI,&rdquo; he says. &ldquo;Cost effectiveness is related to unit size and operating life.&rdquo; He says the general cut off for these parameters is 10 years of operating life and 250 MW of capacity. &ldquo;Anything lower than these, DSI becomes an attractive option,&rdquo; Lund says. &ldquo;Anything higher is generally leaning towards a wet scrubber. Exceptions exist on both sides so it is important for an end-user to consider the pros and cons in both technologies when making compliance strategy decisions. The end user needs to work with an experienced provider to ensure they are getting the system that best suits their particular needs.&rdquo; Dry sorbent injection systems will have lower removal efficiencies than wet systems, according to Landers, but dry sorbent systems are easier to operate and maintain. &ldquo;Wet systems also have the ability to create secondary pollutants,&rdquo; he adds. &ldquo;Specifically, a gas stream that contains SO3 will produce submicron sulfuric acid mist (H2SO4) at the point the gases enter the main scrubber area. This is due to the water molecules combining with the SO3 molecules. These submicron particles will then travel through the scrubber, since scrubbers cannot remove these submicron particles, and out through the stack. In this situation, a wet electrostatic precipitator must be placed after the precipitator to capture the sulfuric acid mist.&rdquo; Landers also notes that dry sorbent and evaporative systems must also be followed by a particulate removal device such as a dry electrostatic precipitator or baghouse to remove the reacted sorbent. Landers says dry systems are easier and more economical for SO2 removal less than 80 percent and HCl removal less than 95 percent down to about 5 parts per million. &ldquo;Wet systems have to deal with leaks, corrosion and salts,&rdquo; he says. &ldquo;Corrosion can be dealt with if the proper stainless steel is used. Common 304 and 316 varieties are not suited for long-term exposure to some acid gases. Salts are reduced by blowing down water to the wastewater treatment plant.&rdquo; For dry systems, those that utilize milling have increased maintenance over those that do not mill, he says. And evaporative systems, due to their complexity, would have the most maintenance of all. &ldquo;Having been in the air pollution control industry for more than 20 years manufacturing both wet and dry systems, I can say with all confidence that anytime a pollutant can be treated with a dry system, there is less maintenance required and the longer the equipment lasts,&rdquo; Landers tells Biomass Magazine. &ldquo;And in a world of ever-decreasing maintenance and capital budgets, these are extremely important considerations.&rdquo; Lund says with recent regulations that drove DSI sales coming and going, Nol-Tec Systems recognized that first-generation DSI systems were ultimately not what end-users wanted. &ldquo;We remained committed to continuous innovation and improvement,&rdquo; he says. &ldquo;That has allowed us to work with customers to come up with truly unique features in our systems, such as silo discharging, enhanced sorbent mixing, and improved sorbent dispersion.&rdquo;&nbsp; Pollution control is a necessary evil, Lund says. &ldquo;It leads to a lot of tough decisions that no one enjoys making. Our No. 1 recommendation is to use vendors as resources. We are specialized experts that can reduce the overwhelming task of digging through all the necessary information and evaluation that comes with choosing the best compliance strategy.&rdquo; Author: Ron Kotrba Senior Editor, Biomass Magazine 218-745-8347 rkotrba@bbiinternational.com

POWDER INJECTION: Dry sorbent injection (DSI) involves injecting a base powderâ€”either milled or unmilledâ€”into the flue gas stream that reacts with the acid gases present to neutralize them. 

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Depending on boiler or plant size and expected lifespan, two major technologies—dry sorbent injection systems and wet scrubbers—can help biomass users effectively remove acid gases for emissions compliance. 

Acid Gas Control Strategies

California continues to be a frustrating illustration of the paradox of biomass nationwide: So much fuel exists and needs a place to go, yet many biomass facilities are struggling to stay open. An estimated 66 million dead and diseased trees across California&mdash;enhanced by a years-long drought combined with a pine beetle epidemic&mdash;means fuels are plentiful, but they aren&rsquo;t being used for biomass power. Encouragingly, there appears to be widespread agreement that a strong biomass sector would solve many problems, promoting the removal of hazardous fuels and improving air quality that worsens with open-burning and forest fires. A strong and productive biomass industry can also help the U.S. Forest Service reduce the risk of catastrophic fires and, in doing so, reduce budget spending on fighting fires. Because of the stiff competition presented by low natural gas prices, many biomass facilities have closed their doors or are carefully considering that option. As a result, some in California are concerned about what to do with hazardous fuels that desperately need clearing, as well as with the agricultural waste that typically is purchased by biomass facilities. A December 2015 Los Angeles Times story looked at the air quality issues at stake with the closure of some biomass facilities. The story noted that biomass facilities drastically reduce farmers&rsquo; costs for waste and residue removal. Without this outlet, some farmers anticipate their waste removal expenditures to increase as much as threefold. In California, if there is no biomass facility available to take on these materials as fuel, farmers are allowed to open-burn them. This is undeniably bad for the environment, releasing increased levels of greenhouse gases (GHG) into the atmosphere. According to a study sponsored by the Placer County Air Pollution Control District, without a biomass power facility&mdash;aside from carbon dioxide&mdash;dramatically higher levels of particulate matter, carbon monoxide and methane are released into the atmosphere. The authors of the study wrote, &ldquo;Energy production and reductions in criteria air pollutants and GHG emissions were quantified from utilization of forest woody biomass wastes to fuel electricity generation as an alternative to open-pile burning.&rdquo; However, they went on to caution that biomass economics are not favorable to achieve these reductions, citing transportation and processing costs, and encouraged a state program to value the benefits of biomass on the basis of its emissions-avoidance benefits. The tree mortality problem in California has gotten so dire that officials aren&rsquo;t waiting for a biomass solution. Rather than salvaging some value out of hazardous fuels harvested, as would happen if they went to a biomass facility, the state of California is considering the use of expensive mobile incinerators. These devices would travel around the state, simply destroying the dead and diseased trees on the spot. While these burners would solve the immediate problem of hazardous fuel removal, there are serious concerns about them from an air quality and GHG perspective. A biomass facility would not only put these materials to good use, it would also greatly reduce emissions from burning them. The California Biomass Energy Alliance has been working hard, collaborating with state officials to find a solution that would keep the biomass industry on course and help the state and U.S. Forest Service address the problem of abundant hazardous fuel. We look forward to seeing what results. &nbsp; &nbsp; Author: Bob Cleaves President, Biomass Power Association bob@usabiomass.org www.usabiomass.org

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The tree mortality problem in California has gotten so dire that officials aren't waiting for a biomass solution. Rather, it  is considering the use of expensive mobile incinerators. 

California Biomass: Abundant Fuel Needs Policy Solution

DVO installs digester in China DVO Inc. has installed and commissioned an anaerobic digester at Austasia Modern Dairy Farm in Xianhe in Shandong Province, China. The project is DVO&rsquo;s first installation in China. The digester processes manure from approximately 5,600 milking cows. Biogas generated by the project is used to generate heat for the digester and various onsite facilities. Future plans include the production of renewable natural gas or electricity.&nbsp; ABFA welcomes new members, announces board changes&nbsp; The board of the Advanced Biofuels Association has welcomed BIOX, Louis Dreyfus and the Brazilian Sugarcane Industry Association as members. With these three new members, the ABFA represents 9.6 billion gallons of domestic and international biofuels production. The board also elected Neville Fernandes, head of sales and marketing and a board member at Neste U.S. Inc., as chairman. In addition, Michael Whitney, general manager of renewable fuels at Musket Corp.; Len Federico, manager of biofuels and oils at Louis Dreyfus; Jeffrey Jacobs, president and CEO of Ensyn; Paolo Carollo, executive vice president of Beta Renewables/BioChemtex; and John Cummings, vice president of Wilmar North America, were added to the ABFA executive committee. Former Chairman Wayne Simmons, CEO of Sundrop Fuels, will remain as the ex-officio member of the committee. Rural Energy adds team member Rural Energy has boosted its in-house design capabilities with the edition of Carlyne Parillon as senior design engineer. Parillon will interpret client briefs and is responsible for concept and detailed designs of energy centers. She has more than seven years of experience designing district heating systems. Chadwick-BaRoss joins Barko distribution network Barko Hydraulics LLC has added Chadwick-BaRoss Inc. to its distribution network for all forestry equipment product lines. With five locations across Maine, Massachusetts and New Hampshire, Chadwick-BaRoss will carry Barko equipment for the New England region. Solegear acquires bioplastics division of Ex-Tech Solegear Bioplastic Technologies Inc. has completed the acquisition of the bioplastics division of Ex-Tech Plastics Inc. for $1.33 million in common shares. Ex-Tech has been a leading manufacturer of extruded plastic sheets for more than 30 years. The acquisition is expected to provide Solegear with annualized revenues of an estimated $2 million, which the company expects to use as a base for further growth and development. &nbsp; Envitec constructs biogas plant Germany-based EnviTec Biogas AG is constructing a 6-MW biogas plant that uses digestion to convert waste pretreated with enzymes into green energy for REnescience Northwich, a subsidiary of Danish utility DONG Energy A/S. The technique, which is used to treat unsorted household waste with the aid of a specialized formulation involving the use of enzymes, has been developed and tested in a pilot plant in Copenhagen. With the construction of a full-sized plant, DONG Energy aims to prove its new technology under real-world conditions. Waste will be collected by the U.K. waste management company FCC Environment, treated in the plant and then processed as a bioliquid in the biogas plant to be constructed by EnviTec. The annual volume of approximately 328,000 metric tons of bioliquid will be filled into a holding tank in the biogas plant and processed in four digesters. The biogas produced will be piped into four cogeneration units, creating approximately 45.5 million kWh of electricity, which will be fed into the local grid. Evergreen Engineering opens new location Eugene, Oregon-based Evergreen Engineering Inc. has opened a branch office in Atlanta, Georgia, to pursue opportunities in the southeastern U.S. The office celebrated its grand opening July 1. BIO adds members The Biotechnology Innovation Organization has announced several companies joined its industrial and environmental section during the past year, including Bryan, Texas-based Earth Energy Renewables LLC; Cambridge, Massachusetts-based Enevolv Inc.; Las Vegas, Nevada-based Green Life Can LLC; Brooklyn, New York-based Modern Meadow Inc.; Boulder, Colorado-based Muse Biotechnologies Inc.; and Oakland, California-based RHO Renewables Inc. NREL appoints director of Biosciences Center Mark Davis has been named director of the Biosciences Center at the U.S. DOE&rsquo;s National Renewable Energy Laboratory. He joined NREL in 1993 as a postdoctoral research associate and has served as the platform program manager for thermochemical processes since 2010. Davis is also currently directing the Enabling Technologies Focus Area for the BioEnergy Science Center, a DOE-sponsored effort led by Oak Ridge National Laboratory. Since joining NREL, Davis has served as the group manager for Chemical and Catalyst Sciences in NREL&rsquo;s National Bioenergy Center. In addition, he has authored or co-authored more than 90 peer-reviewed publications and three book chapters. Energy Trust of Oregon names executive director Energy Trust of Oregon has announced its board of directors appointed Michael Colgrove as executive director, effective Aug. 15. Colgrove will lead the organization in continuing to deliver the cleanest, lowest-cost energy available for 1.5 million utility customers in Oregon and southwest Washington. Colgrove succeeds Margie Harris, who is retiring after leading the organization since its inception in 2001. Colgrove joins Energy Trust after 15 years with the New York State Energy Research and Development Authority, where he was both the director of the New York City office and director of multifamily programs.

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Business Briefs

In every issue of Biomass Magazine dedicated to equipment and equipment innovations, the men and women who put these machines to work jump off the page. This is the case in Senior Editor Ron Kotrba&rsquo;s very thorough page-12 story, &ldquo;Acid Gas Control Strategies,&rdquo; in which he leverages the decades of industry knowledge his sources possess to compare dry sorbent injection and wet scrubbing approaches. Kotrba connected with both Link Landers, CEO of PPC Industries, and Mitch Lund, a technical services engineer from Nol-Tec Systems, to outline when and why each system is deployed, and the advantages and optimal deployment of each technology. These technologies, while impressive in their own right, are merely extensions of the human minds that invent, deploy and optimize them.&nbsp; This is fortunate, because as Lund told Kotrba, &ldquo;The general trends in the industry show that as years pass, newer compounds are added to regulation laws and existing compounds come under tighter regulations.&rdquo; Lund and Landers helped Kotrba understand the connection between the emissions control technologies widely deployed today, and the policies that catalyzed their development. While Kotrba&rsquo;s story looks at mature technologies invented to comply with increased regulation, Managing Editor Anna Simet&rsquo;s page-40 feature, &ldquo;Regs and Bacon,&rdquo; explores technology innovations in earlier stages of development, initiatives being spurred by North Carolina&rsquo;s renewable energy mandate. Simet&rsquo;s piece investigates how a carve-out for swine waste-derived electricity in the state renewable portfolio standard is driving innovation within the biogas sector. Broadly speaking, anaerobic digestion (AD) is not a new technology. But if ambitious goals like the kind North Carolina has set are to be met, the AD of swine waste within existing hog production systems must be perfected. Swine waste offers its own challenges for designers of AD systems, and Simet learned that the market opportunity generated by this state-specific policy has motivated more than a few designers and builders to overcome the unique challenges inherent to this abundant feedstock. Policy drives innovation. The Clean Air Act gave rise to the control of acidic gases through dry sorbent injection and wet scrubbers, and North Carolina&rsquo;s swine waste carve-out may well yield a workable digestion approach for a feedstock that, for a long time, technology developers avoided. This story is playing out all across the biomass sector, proving that this industry&rsquo;s most impressive machine is the one residing between our collective ears.
&nbsp;
Author: Tim Portz Vice President of Content &amp; Executive Editor tportz@bbiinternational.com

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In every issue of Biomass Magazine dedicated to equipment and equipment innovations, the men and women who put these machines to work jump off the page.

August 2016

Business Briefs

Business Briefs

Columns

Driving Growth in Driving Green

Ancient Biology for Modern Decarbonization

Keeping Score

California Biomass: Abundant Fuel Needs Policy Solution

Equipped to Innovate

Featured

Apparatus Advantage

Brexit and Biomass

Acid Gas Control Strategies

Contributions

The Intricacies of Pyrolyzer Furnace Design

Baltic Rim Wood Fiber Supply and Demand

Departments

Regs and Bacon

Solving the Equipment Equation

August 2016.css-7jxktu{position:absolute;bottom:0px;left:0px;right:0px;height:3px;border-radius:3px;background-color:var(--chakra-colors-brandBlack);}

Business Briefs

Business Briefs

Columns

Driving Growth in Driving Green

Ancient Biology for Modern Decarbonization

Keeping Score

California Biomass: Abundant Fuel Needs Policy Solution

Equipped to Innovate

Featured

Apparatus Advantage

Brexit and Biomass

Acid Gas Control Strategies

Contributions

The Intricacies of Pyrolyzer Furnace Design

Baltic Rim Wood Fiber Supply and Demand

Departments

Regs and Bacon

Solving the Equipment Equation

August 2016