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Biomassa

1. voda 2 juli 2012 16:23

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   Ondernemers in problemen door groene stroom
   
   Gepubliceerd op 2 jul 2012 om 12:05 | Views: 890
   
   DEN HAAG (AFN) - Steeds meer ondernemers in de land- en tuinbouw die duurzame energie produceren, komen in de problemen. Dat zegt LTO Nederland maandag.
   
   Er zijn in Nederland ongeveer honderd vergisters die duurzame energie produceren. Daarvan staan er volgens LTO Nederland nu zo'n twintig stil. Dat heeft onder meer te maken met hoge biomassaprijzen, lage stroomprijzen en een lage vergoeding. Voor veel ondernemers die in groene stroom hebben geïnvesteerd, is een rendabele exploitatie daardoor niet meer mogelijk en faillissementen dreigen, aldus LTO.
   
2. voda 27 september 2012 16:41

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   Afgedankt frituurvet is goud voor Simadan
   
   Wat olie voor een sjeik is, is frituurvet voor Simadan. Het Nederlandse concern maakt van frituurvet en andere afvalvetten namelijk biologische benzine. Een goudmijn en bovendien groen. In het afgelopen jaar is het vetverwerkingsbedrijf met €100 mln gegroeid en alles wijst erop dat de expansie nog lang niet aan haar einde is. Zeker niet nu biodiesel op basis van landbouwgewassen in het verdomhoekje wordt geplaatst.
   
   Iedereen is blij met ons’, zegt Chris Linderman, de topman van vetverwerkingsbedrijf Simadan Holding. ‘Zowel de linkse en de rechtse politiek als milieuorganisaties juichen onze werkwijze toe.’ Simadan heeft een fabrieksterrein ontwikkeld in het Amsterdamse Havengebied genaamd Green Mills. Daar worden afvalstromen verzameld. Het gaat voornamelijk om frituurvet, dat onder andere wordt opgehaald bij McDonald’s en Febo. Na zuivering wordt het vet omgewerkt tot biologische diesel, die gemengd kan worden met gewone dieselolie.
   
   Peter Bakker is de eigenaar van Simadan en alle bv’s die daarbij horen. ‘Ik geloof er heilig in. Het is een heel grote markt’, zei Bakker in 2007 in een uitzending van Nova. Inmiddels is zijn bedrijf zo groot dat hij Linderman als ceo heeft aangesteld. ‘Ik werkte eerste in de olie-industrie en Peter had mij daar al een tijdje aan het werk gezien. Op een gegeven moment vroeg hij of ik de dagelijkse leiding over het bedrijf wilde overnemen.’ De 56-jarige Bakker is overigens nog steeds elke dag bezig met Simadan maar kan op deze manier goed blijven focussen op het uitwerken van nieuwe ideeën.
   
   Niet voor consumptie geschikt
   
   Met Shell en BP als grootste afnemers behaalt Simadan een jaaromzet van €250 mln. Het publiciteitsschuwe bedrijf is een van de weinige ondernemingen in de wereld die frituurvet op deze manier exploiteren. De bioraffinaderij van Simadan is met een jaarlijkse productie van circa 120 miljoen liter tweedegeneratiebiodiesel en 190 man personeel zelfs de grootste in Europa en ‘misschien wel van de wereld’, aldus Linderman.
   
   Op dit moment bestaat 4,5% van het totale brandstofverbruik in de Europese Unie uit biobrandstoffen. Bij ongeveer 90% van alle biobrandstof is sprake van zogenoemde eerstegeneratiebrandstoffen. Dat zijn biobrandstoffen op basis van landbouwproducten. Die blijken helemaal niet zo milieuvriendelijk als aanvankelijk werd gedacht. Voor het verbouwen van gewassen zijn namelijk land en kostbare energie nodig. Ook zijn de ontwikkelingsorganisaties er niet blij mee. ‘Land dat nu gebruikt wordt om Europese auto’s te laten rijden op biodiesel of benzine kan bij normaal gebruik tarwe en mais produceren voor 127 miljoen mensen’, stelt de ontwikkelingsorganisatie Oxfam Novib in het rapport Hunger Grains.
   
   De frituurvetbiodiesel van Simadan valt in de tweede generatie omdat hij niet voor consumptie geschikt is. Er is geen sprake van dat de diesel voedsel voor menselijke consumptie verdringt. En hij is veel groener: ‘Biodiesel van de eerste generatie geeft slechts 20% tot 40% minder CO2-uitstoot’, weet Linderman, ‘terwijl de reductie bij de tweede generatie 80% tot 90% bedraagt.’ De Europese Commissie wil met nieuwe plannen stimuleren dat wordt overgestapt van de eerste naar de tweede generatie biobrandstof.
   
   Stimulering Brussel niet nodig
   
   Toch heeft het bedrijf stimulering vanuit Brussel niet nodig om te groeien, denkt Linderman. ‘Wij hebben het altijd helemaal zonder subsidie gedaan. Onze fabriek maakt van iets nutteloos een brandstof waar je op kunt rijden. Dat is sowieso business. Ook zonder milieudoelstellingen. Misschien dat de vraag naar ons product verdubbelt, maar de hoeveelheden vet die we binnenkrijgen, blijven hetzelfde. We hebben 20.000 afhaaladressen en er rijden honderd vrachtwagens van ons in Nederland. Wij hebben de handen al vol aan de huidige projecten.’
   
   Linderman legt ook uit waarom de omzetting van afvalstromen in biodiesel nauwelijks wordt nagedaan. Het lijkt immers een goudmijn. ‘Je zou ons concept in principe kunnen kopiëren en in andere landen kunnen opzetten, maar dat is wel erg moeilijk. Onze kracht is dat we de hele keten beheren: van de vrachtwagens tot het chemische proces. Dat is geleidelijk zo gegroeid. Zoiets is niet eenvoudig op te zetten.’
   Vetverwerking•In de jaren vijftig begon de vader van Peter Bakker een klein vetverwerkingsbedrijfje
   •Inmiddels heeft zoon Peter dat uitgebouwd naar een keten van bv’s die samen €?250 mln omzetten
   •De bedrijven van Simadan Holding verhuizen vanwege uitbreiding momenteel van Lijnden naar Amsterdam
   
   Ruben Munsterman
   
   Bron|: Fd.nl
3. voda 11 oktober 2012 17:23

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   Iran to start largest ethanol fuel production in 2013
   
   Trend News Agency cited Mr Mohammadzadeh Fazeli member of Iran's Ethanol Producers Association as saying that Iran will start the largest ethanol fuel production in 2013.
   
   Mr Fazeli noted that the construction of the complex will start in May 2013 in Iran's Khuzestan province. The establishment of the factory will create some 150 jobs. The finished unit would have a production capacity of some 250,000 liters per day using waste from agricultural production as raw material.
   
   The construction of the ethanol fuel production plant is part of the Mehr Mandegar project which is a plan that controls completion of half finished transportation, industrial, scientific, technological, cultural, agricultural and health projects by the end of Iran's current administration.
   
   Source - Trend News Agency
   
4. voda 4 december 2012 16:13

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   Biomass based power generation projects of 3462 MW
   
   Dr Farooq Abdullah minister of New and Renewable Energy informed the Lok Sabha that Biomass based power generation projects with a total installed capacity of 3462 MW which includes 86 MW in West Bengal have been set up in the country so far. State wise details of biomass based power generation projects.
   
   Ministry of New and Renewable Energy is promoting setting up of power generation projects from biomass through various technological routes such as combustion, gasification and cogeneration. Various fiscal and financial incentives such as capital subsidy and fiscal incentives including concessional customs duty on import of machinery and components, excise duty exemption, accelerated depreciation on major components and relief from taxes are being provided for setting up of biomass based power projects.
   
   Mr Abdullah said that besides, preferential tariff is being provided for sale of power from biomass power projects. 5 biomass power projects with a total capacity of 1.60 MW are at various stages of commissioning in West Bengal.
   
   Source – PIB
   
5. voda 5 december 2012 16:57

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   LanzaTech to convert Baosteel mill fumes into ethanol
   
   LanzaTech NZ Ltd a closely held developer of transportation fuels and chemicals from waste industrial gases, plans to begin building next year an ethanol plant at a Baosteel Group Corp. steel mill in China.
   
   Chief Executive Ms Jennifer Holmgren said that the facility will use LanzaTech’s genetically modified microorganisms to convert carbon monoxide containing gas into as much as 10 million gallons of fuel grade ethanol a year starting in 2014. Financing is being arranged by Baosteel, she said, and wouldn’t disclose the expected cost.
   
   The project is a joint venture with Baosteel, China’s second largest steel manufacturer, and scales up a 100,000 gallon a year demonstration plant the companies installed at one of Baosteel’s mills near Shanghai. Results from that project have shown that the scaling of the technology has been successful.
   
   LanzaTech also has a venture with Shougang Group, China’s fourth-largest steelmaker, and industrial companies in India, South Korea, Taiwan and Japan are evaluating projects with the company. Holmgren told Bloomberg in January she may begin considering an IPO after successful operations of the Baosteel demonstration.
   
   Source – Bloomberg
   
6. voda 9 september 2013 16:29

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   Een verkeerd voorbeeld hoe het niet hoort!!
   
   'Te veel palmolie in de benzinetank'
   
   Gepubliceerd op 9 sep 2013 om 00:01 | Views: 2.388
   
   AMSTERDAM (AFN) - Het gebruik en de verwerking van de omstreden biobrandstof palmolie in Nederland is in 6 jaar tijd verdubbeld, tot 1,3 miljoen ton in 2012. Dat staat in een maandag gepubliceerd onderzoeksrapport van de Europese koepelorganisatie van Milieudefensie.
   
   Door de toenemende vraag naar deze brandstof voor onder meer auto's worden er steeds meer palmolieplantages aangelegd in landen als Indonesië en Maleisië, waarschuwt Milieudefensie. Daarvoor wordt op grote schaal tropisch regenwoud gekapt en platgebrand, wat leidt tot extra uitstoot van broeikasgassen. Vaak worden de rechten van de inheemse bevolking geschonden en op veel plekken ontstaat een gebrek aan landbouwgrond.
   
   In de hele Europese Unie is het gebruik van palmolie voor biobrandstof sinds 2006 met 365 procent gestegen. Dat is veel sterker dan verwacht, stellen de onderzoekers. Inmiddels bestaat 20 procent van de biobrandstofmix in Europese tanks uit palmolie. Nederland is van de EU-landen de grootste importeur en verwerker van palmolie. Volgens het rapport is de toename voornamelijk toe te schrijven aan het EU-beleid om het gebruik van biobrandstoffen in de transportsector te stimuleren.
   
   Onacceptabel
   
   Woensdag stemt het Europees Parlement over een voorstel van de Europese Commissie om het gebruik van voedselgewassen (waaronder palmolie) als biobrandstof te beperken tot maximaal 5 procent van de brandstofmix. Milieudefensie roept de parlementariërs op om dit plan te steunen.
   
   ,,Het is onacceptabel dat wij in Nederland en Europa onze tanks volgooien met palmolie, terwijl dat elders in de wereld leidt tot grootschalige ontbossing en voedselschaarste'', stelt campagneleider Geert Ritsema. Internationale instellingen als de wereldvoedselorganisatie van de Verenigde Naties (FAO) waarschuwen volgens hem al jaren voor de problemen rond biobrandstoffen.
   
   Palmolie geldt als de meest gebruikte plantaardige olie in de wereld en wordt gebruikt bij het maken van allerlei voedingsmiddelen, maar ook in biodiesel en producten als zeep en lippenstift.
   
7. voda 22 januari 2014 16:40

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   'Biomassa levert tienduizenden banen op'
   
   WOENSDAG 22 JANUARI 2014, 14:57 uur | 275 keer gelezen
   
   WAGENINGEN (AFN) - Als de Nederlandse chemische industrie voor de helft overstapt van fossiele grondstoffen naar biomassa, levert dat tienduizenden banen op. Dat zegt hoogleraar Johan Sanders van Universiteit Wageningen, die donderdag afscheid neemt als hoogleraar plantaardige productieketens.
   
   Sanders berekende dat zo´n omschakeling circa 30.000 nieuwe banen oplevert in de landbouw, een sector waar de werkgelegenheid nu juist gestaag afneemt. De arbeidskrachten zijn vooral nodig voor de productie van biomassa, zoals gras, maïs, suikerbieten en andere plantaardige grondstoffen.
   
   De verdere verwerking van de biomassa levert daarnaast nog eens 15.000 werkplekken op in de chemische industrie zelf, zegt Sanders.
   
   Subsidie
   
   Volgens hem kan de overstap worden gemaakt zonder dat de producten die de chemische industrie maakt duurder worden en zonder subsidie van de overheid. Dat komt omdat bij gebruik van biomassa de kapitaalskosten drastisch verlaagd kunnen worden, aldus de hoogleraar.
   
   Sanders was 12 jaar verbonden aan Universiteit Wageningen, waar hij onderwijs gaf in en onderzoek deed naar het gebruik van plantaardige grondstoffen in de industrie als alternatief voor olie, gas en kolen.
   
8. voda 9 april 2014 17:52

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   Orient Green Power Company Ltd to sell 10 MW Biomass Unit at Samathur
   
   The Board of Directors of Orient Green Power Company Limited at its meeting held on April 05th 2014, have approved the proposal to sell whole of the 10 MW Biomass Unit of the Company located at Samathur, Karianchettypalayam Village, Pollachi Taluk 642 123, Coimbatore District, Tamil Nadu by way of Slump Sale on a going concern basis, to one of its wholly owned subsidiaries subject to the approval of the shareholders and other approvals as may be required for such sale.
   
   This is to facilitate the unit to sell power on the Group Captive mode in Tamil Nadu which would help in stability of operations and realisation.
   
   Source – Strategic Research Institute
9. voda 26 mei 2014 20:47

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   Utility Biomass Use: Turning Over a New Leaf?
   
   Once thought to be an excellent method for reducing emissions at coal power plants, biomass generation is still underutilized in the U.S. Inexpensive natural gas, lack of government incentives, and power plant operations concerns have limited biomass use at the utility level. Despite these challenges, biomass has several advantages that can be leveraged in certain situations.
   
   If there is one truth to the power industry, it is that environmental regulations will only proceed down one path—that of stricter limits. Although legislatures and courts may argue over the issue for years to come, it appears inevitable that at some point a carbon or greenhouse gas (GHG) emissions tax will be applied to utility generators in the U.S. Countries that are subject to a carbon tax typically employ three solutions to reduce GHG emissions: improving plant efficiency via capital improvements plus monitoring and diagnostic tools, converting some or all of the coal generation to natural gas, or finding ways to utilize biomass fuel instead of coal.
   
   Previous articles have examined the benefits of natural gas and monitoring and diagnostic programs; this article examines the options available to successfully utilize biomass at coal-fired power plants.
   
   Even without GHG regulations for existing plants, current emissions requirements can make biomass cofiring or conversion attractive. For example, Portland General Electric’s (PGE) Boardman Coal Plant is a 585-MW pulverized coal plant that has fallen under environmental regulations, leaving its owners only three options: install expensive back-end emissions controls, close the plant completely, or switch to an environmentally friendly fuel. As a result, PGE has studied the option of reducing unit output to 300 MW and burning up to 18 types of biomass for a total coal to biomass conversion. “We at PGE are really excited to have this opportunity to keep a facility operational and maintain jobs, and help the environment at the same time,” said Randy Curtis, engineering supervisor at Boardman.
   
   Current Status of Biomass Utilization at Utility Power Plants
   
   Although biomass use is not uncommon among industrial units, and is the norm within the pulp and paper industry, biomass utilization for grid-connected utility-scale generation is rare in the U.S. According to the Federal Energy Regulatory Commission (FERC), operating biomass power capacity is only 15.8 GW, representing 1.4% of the total U.S. generation mix. Interest in biomass cofiring or conversion peaked in the early 2000s and has only been seriously pursued at utility scale at a handful of U.S. locations.
   
   One notable installation was the AES Greenidge plant, near Dresden, N.Y., which employed a “homemade” biomass direct injection system that allowed the operators to burn approximately 10% biomass with coal (Figure 1). Typically using waste food or crop residues as fuel, Greenidge was closed in 2012, the victim of cheap natural gas and environmental concerns.
   
   According to Dave O’Connor, biomass program manager at the Electric Power Research Institute (EPRI), “the primary barrier to biomass cofiring or conversion in the United States is low natural gas prices. Power plants with convenient natural gas access face lower capital barriers to natural gas cofiring than biomass cofiring. In addition to this barrier, most renewable portfolio standards for non-utilities are already fully subscribed.”
   
   Interest in biomass for utility-scale power is much greater outside of the U.S., with Europe and the developing world being the leaders in this field. (See also “Fuel-Flexible CFBs Add Flexibility to Resource Plans” in this issue.) One of the most notable biomass cofiring success stories to date has been the cofiring and conversion work at the 3,960-MW Drax Power Station in the United Kingdom. (For more on Drax, see “UK Struggles to Attract Low-Carbon Investment” in this issue.) The station has been working toward a goal to reduce GHG emissions by more than 70% and has explored burning several biomass fuels, such as willow, straw and wood pellets, and agricultural waste. The current plan is to convert three of the six units at Drax to being exclusively biomass by 2016; the Unit 2 conversion is already complete.
   
10. voda 26 mei 2014 20:50

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    part 2:
    
    Biomass Cofiring Project Challenges and Pitfalls
    
    Biomass utilization at existing coal-fired power plants can be implemented by several methods, from cofiring biomass and coal simultaneously to complete unit conversions to biomass combustion. Less-common methods of utilizing biomass include substituting B99 biodiesel for startup fuel oil, using a gasifier to feed hot fuel gas into an existing boiler, or even employing a separate standalone biomass unit to supply heat to the coal unit’s steam cycle.
    
    In the last two decades Black & Veatch has studied the barriers to and concerns over utilizing biomass at more than 70 fossil-fired units (see sidebar). The following details some of the most common challenges we have encountered.
    
    Biomass Heat Rate ImpactsBiomass cofiring or conversion at the utility scale is typically driven by environmental concerns. Understanding the corresponding heat rate impacts of biomass combustion is critical for evaluating the spectrum of risk and reward possibilities. Heat rate impacts from biomass cofiring and conversion, relative to coal combustion, result from three primary causes:¦ Boiler efficiency: A higher fuel moisture and hydrogen content can lead to higher latent heat losses in the boiler. Changes in combustion efficiency, furnace heat transfer, and flue gas flow can lead to higher sensible heat losses. The higher volatility of biomass fuel can contribute to lower unburned combustible losses, but oversized fuel particles can negate this benefit, or even result in greater unburned combustible losses.¦ Station service: Biomass handling, grinding, and preparation systems can result in greater auxiliary power consumption at the power plant, even with a reduction in coal equipment use.¦ Turbine heat rate: Changes in sootblowing steam use, steaming rate and final steam temperatures, and spray flows can result in changes to the net turbine heat rate.
    
    Figures 2, 3, and 4 demonstrate some potential heat rate effects of biomass combustion at a pulverized coal power plant studied by Black & Veatch.
    
    Biomass Supply. Finding a suitable biomass fuel supply at a competitive price is difficult for most power plants. Suppliers are often small “mom and pop companies” and geographically remote from the power plant. Supplies can be variable from a single vendor, mandating contracts with scores of small biomass suppliers, which greatly complicates the biomass procurement process. Sometimes biomass suppliers will promise to meet a demand for biomass at a reasonable price during a study, but once the project appears to be proceeding toward a test burn, suddenly the price will increase by 50% or more.
    
    One solution to these problems is for the utility to take ownership of its biomass fuel. Such is the case with Drax Power, which is building biomass pellet plants in Louisiana and Mississippi and shipping pellets back to North Yorkshire, England. Designed to produce more than 900,000 tons per year of wood pellets, these pellet plants are a first step toward Drax’s ultimate goal of producing 2 million tons per year.
    
    Biomass storage and handling logistics can be a serious concern for power plants with limited fuel yard space. Given a woody biomass of a typical moisture content, one rule of thumb is to assume that 1 ton per hour of biomass will be required for 1 MWh of power generation (less for pellets or torrefied biomass and more for wet, herbaceous biomass).
    
    Biomass is typically delivered by truck, and a typical biomass truck can hold from 25 to 35 tons of biomass. Trucks tend to operate on a 10-hour schedule for six days a week; therefore, converting 10% of a 250-MW power plant to biomass will require about two to three biomass truck deliveries per hour. Local residents may object to that much truck traffic on the roads, and as a result the utility may be asked to pay for upgrading bridges and roads.
    
    Trucks will require a rapid dumping system in order to avoid traffic congestion at the plant and may require a “staging area” be built by the plant entrance to hold trucks during temporary outages (Figure 5).
    
    Biomass Storage. Biomass storage is often problematic at coal-fired power plants. Because biomass fuels come in a variety of types and sizes, plant owners must design their storage and reclaim systems with care. Covered biomass storage is recommended or required for most fuels to reduce reclaim efforts and to protect the biomass from degrading. Pelletized biomass is often touted as being “rain-hardy,” but experience has shown that a single rainstorm can sometimes transform a pile of biomass pellets into a mountain of sludge. Thus, covered storage is highly recommended.
    
    Another concern with biomass storage is the high levels of dust created during handling, especially at transfer points. Biomass dust is generally less harmful to humans and the environment than coal dust, but it can be susceptible to hazardous mold accumulation, which can affect the health of both the fuel yard staff and nearby residents. Compared to coal, biomass dust is significantly more fire-prone due to its relatively low ignition temperatures. This risk was exemplified by the 2008 biomass dust explosion at the Ontario Power Generation Atikokan plant. Four years later, a biomass fire among the wood pellets stored in 600–metric ton hoppers at the Tilbury B power plant in the UK led to that plant being out of service for nearly four months.
    
    Although coal demand will decrease as it is replaced with biomass, biomass fuel has a much lower energy density than coal, and more of it is required for the same net generation. For a unit currently burning an 11,000 Btu/lb coal, cofiring just 5% straw biomass containing 40% moisture will require a biomass storage area 80% as large as the current coal pile!
    
    Comilling and Direct Injection. Many technologies are available for introducing biomass into a coal-fired boiler. Direct injection of ground biomass into the furnace via dedicated ports is one of the safest methods for cofiring, although it is also one of the most expensive.
    
    For small quantities of biomass fuel (1% to 5% by energy content) comilling can be the best choice, provided your mills are up to the task. Due to the slippery and plastic nature of biomass materials, milling with a roll-wheel mill or ball tube mill can be problematic. Although the Hardgrove Grindability (HGI) test is not intended to measure the grindability of biomass materials, a rule of thumb is to assume herbaceous biomass has an HGI of 20 to 25.
    
    
11. voda 26 mei 2014 20:55

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    part 3
    
    As part of a biomass project that Black & Veatch was involved with in conjunction with Genesis Energy, New Zealand, at its Huntly power station, the engineering and corporate staff showed exceptional diligence in planning for comilling of up to 20% biomass. Here are some of the recommendations of that study:
    
    ¦ Biomass fuel can stick in bunker hoppers and clog feeders, requiring vibratory shakers or even redesign of the hoppers. In some cases biomass fuel can jam feeders and trip a mill.
    
    ¦ Increased housekeeping should be implemented to control dust and spilled fuel from the tripper to the feeders. Improved fire detection and suppression systems may be needed for the coal conveyors, tripper room, and bunkers.
    
    ¦ Mill roll wheels can be modified with slots cut into them, to give the wheels more “bite” into the biomass fuel. Roller spring adjustments may also be required.
    
    ¦ Ball tube mills may find many biomass fuels problematic and, therefore, may require additional vigilance to ensure that the fuel and balls don’t conglomerate together into a solid mass.
    
    ¦ Classifier settings will need adjustment for biomass use, with some plant engineers opting to open up classifiers to avoid accumulating stringy, oversized biomass.
    
    ¦ Mill air flow must be checked, and air gaps closed, to prevent under-bowl fires.
    
    ¦ Primary air ducts should be checked to ensure light biomass dust does not backflow and accumulate in expansion joints, leading to a potential fire or explosion risk.
    
    ¦ Mill inerting and fire detection systems are necessary for any long-term biomass comilling program. Special care should be taken to sweep mills clean of biomass material during shutdown.
    
    Direct injection of biomass can be into the existing coal pipes downstream of the mill or be introduced directly to the furnace via ports or burners. In the former method, no new furnace penetrations are required, the unit maintains its full coal capacity, and the capital cost is modest. In the case of direct injection into the furnace, the greatest concerns are triggering New Source Review by cutting new fuel ports into the walls, and potential space limitations that prevent optimum biomass port or burner placement.
    
    Whether biomass direct injection occurs in the coal pipes or the furnace proper, it is important to try to maintain a consistent biomass quality and quantity entering the furnace, so operators are able to keep the units tuned for the best balance of unburned carbon, CO, NOX, and furnace deposition.
    
    Boiler Concerns. Many biomass fuels can reduce boiler maintenance activities by having a low, nonabrasive ash content. Some biomass ash has a lower melting point than coal ash, which can result in slagging on water wall surfaces. Biomass ash with a high potassium or sodium content can significantly foul heat transfer tubes in the upper furnace region.
    
    Due to biomass having a lower energy density than most coals, introducing significant amounts of biomass fuel into a furnace can result in increased flue gas velocity and, potentially, more tube erosion in the close-spaced primary superheater and economizer tube bundles. Excess tube corrosion can occur with high-chlorine biomass fuels, especially those with a dry-basis chlorine content of 0.18% or greater.
    
    Ash-Handling Equipment. Dry ash-handling systems can benefit from the relatively low ash content of biomass. However, biomass ash that contains high levels of calcium and magnesium can encourage cementation in wet ash systems.
    
    Another potential problem concerns power plants that sell their fly ash for concrete use. Currently, the ASTM C618-12a standard for fly ash used in concrete does not allow the introduction of biomass ash to the mix. In addition, the chemical requirements of ASTM C618-12a may not allow biomass ash to be classified as Class N, C, or F fly ash.
    
12. voda 26 mei 2014 20:56

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    part 4
    
    In one biomass cofiring study at large coal power plant, it was quickly discovered that if the utility must pay to have its ash landfilled, as opposed to selling nearly all of its ash, the differential cost to the plant was a loss of more than $5 million per year.
    
    Emissions Controls. At biomass cofiring levels of 10% or less by heat input, most electrostatic precipitators (ESPs) can successfully collect biomass ash. However, some biomass produces ash that has either a very high or very low resistivity, thus making it difficult to collect.
    
    This is often the case in studies at power plants designed for high-sulfur coals, and significant levels of biomass cofiring may require either ESP upgrades or chemical injection. Furthermore, unless the furnace combustion and milling systems are well tuned for both the coal and biomass, boiler fly ash unburned carbon can greatly increase. This is a problem for two reasons. First, high levels of unburned carbon can change the ash resistivity and increase ash re-entrainment after being collected in the ESP. Second, biomass ash with high amounts of unburned carbon can accumulate in hoppers or in fabric filter baghouses, leading to sometimes destructive fires.
    
    Although biomass combustion often reduces NOx emissions, selective catalytic reduction (SCR) catalysts can be very sensitive to heavy metals and alkaline earth elements contained in biomass. If the biomass in question includes a significant amount of post-industrial waste, it can sometimes contain arsenic, lead, cadmium, potassium, and other items harmful to catalyst life. Where high levels of ammonia slip are encountered with either an SCR or a selective noncatalytic reduction system, biomass ash can agglomerate and form tenacious deposits on air heaters downstream (Figure 6).
    
    
    6. Air heater fouling. High levels of ammonia slip can agglomerate biomass ash on air heater baskets. Controlling ammonia distribution to the furnace or selective catalytic reduction system is critical for avoiding this problem. Source: Black & Veatch
    
    
    Flue gas desulfurization scrubbers are not normally sensitive to biomass ash, unless the ash contains excessive amounts of chlorine. Some herbaceous biomass ash can contain more than 0.5% chlorine, whereas many scrubbers have a fuel-based chlorine limit of less than 0.2%.
    
    Greenhouse Gas Emissions. Biomass fuel is rarely 100% carbon neutral, and calculating the life-cycle GHG emissions from biomass cofiring or conversion can be quite difficult, especially when one considers all of the possible feedstocks.
    
    The planting and growing cycle, fertilizer use, harvesting, transportation, milling and processing, and transportation to the power plant all contain numerous assumptions that will differ from study to study. A review of 12 studies published in the past three years regarding the net change in GHG emissions at cofiring facilities found that the carbon neutrality of biomass fuels ranged from 40% to 96.5%. Clearly, a life-cycle assessment is required for any proposed biomass cofiring or conversion scheme.
    
    Engineered Biomass Fuels
    
    Most biomass fuels suffer from three fuel properties that limit their use at existing coal-fired power plants: low energy density, high moisture content, and poor grindability. All of these limitations can be addressed via the use of engineered biomass fuels. Engineered biomass fuels can be created by many different processes—including torrefaction, steam exploding, and processing with waste heat—but the net results are very similar.
    
    Typically, a large amount of moisture is driven off the fuel, significantly increasing the heating value, while the chemical structure of the fuel itself is altered such that the biomass becomes more friable and easy to grind in a coal mill. Some processes even promise sulfur, chlorine, and heavy metal removal as part of the upgrading.
    
    The primary drawbacks to engineered biomass fuels are their price and availability. Availability is a function of the market being in its infancy, and price is a result of both handling the fuel twice and the energy and materials used in the upgrade process. Unfortunately, in most cases, engineered biomass products cannot compete with coal without some special legal, environmental, or political incentive at work.
    
    EPRI’s O’Connor is bullish on upgraded biomass. “Torrefied, steam-exploded, and other upgraded biomass products can usually be burned at existing coal-fired power plants with relatively minor modifications. The problem is operating cost—finding an upgraded biomass which can meet environmental goals economically.” But, O’Connor cautions, “ensuring sustainable biomass is the critical thing. A lot of the pellet production is from waste wood or wood unsuitable for other uses. Biomass resource planning needs a sound strategy for sustainability to keep the process as carbon-neutral as possible.”
    
    Can Biomass Blossom?
    
    Although several potential pitfalls have been discussed in this article, few should be considered fatal flaws in a plan for biomass cofiring or biomass conversion. Though it is true that cheap natural gas currently dampens the enthusiasm for biomass, many power plants have no suitable gas supply options. Furthermore, many power plants located in remote regions or on island nations operate in circumstances where even engineered biomass fuel is less expensive than imported fossil fuels. Some power plants are located near plentiful biomass sources, and others have the ability to produce their own fuel.
    
    So, despite the pitfalls, the net effect is that biomass use is increasing for electrical generation, even in the U.S. According to FERC, 219 MW of biomass capacity were added in 2013. Should a GHG emissions or carbon tax be levied in the future, or the price of gas increase significantly, then using biomass may be an option a utility can’t ignore. ¦
    
    — Una Nowling, PE (nowlinguc@bv.com) is a project manager and technology lead for fuels at Black & Veatch. She has worked on fuels-related issues and analyses at more than 550 different units over 20 years, specializing in coal, natural gas, and biofuels. She is also an adjunct professor of mechanical engineering at University of Missouri-Kansas City.
    
13. voda 3 juni 2014 21:06

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    HECO Successfully Cofires Biofuel as No. 6 Oil Substitute
    
    The Hawaiian Electric Co. has conducted a full-scale demonstration test of a sustainable biofuel at its 90-MW Kahe Unit 3, located on the island of Oahu. HECO is committed to using biofuels as one means to reduce its dependence on imported low-sulfur fuel oil and to meet the requirements of the state’s renewable portfolio standard and Clean Energy Initiative.
    
    All states were not created equal, particularly when it comes to indigenous reserves of fossil fuels. North Dakota is experiencing a boom in oil production, which has increased almost 10-fold since 2005, and natural gas production from the Marcellus shale deposit—under New York, Pennsylvania, and West Virginia—has increased about 13 times since 2007. In fact, oil and gas production has been the fastest growing segment of U.S. industry since 2007. Hawaii, on the other hand, meets 90% of its energy needs using imported oil.
    
    In 2008, a partnership between the state of Hawaii and the U.S. Department of Energy (DOE) launched the Hawaii Clean Energy Initiative (HCEI) with the goal of making the state energy independent. As you might expect, the “HCEI Road Map” relies heavily on solar, wind, sea, and geothermal energy sources, as well as biofuel and waste-to-energy projects (see “Expanded Honolulu WTE Plant Delivers Triple Benefits for Oahu” in the March 2013 issue or online at powermag.com). Compared to most of the U.S., Hawaii is endowed with an abundance of renewable energy resources.
    
    Hawaiian Electric Co. (HECO), the largest power generator in the state, owns several low-sulfur fuel oil (LSFO)–fired conventional steam plants that are candidates for cofiring liquid biofuels. Liquid biofuels are attractive because at least a portion of the needed supply can be grown and refined locally as long as the right market conditions exist. HECO views liquid biofuels as potential “bridge fuels” until other renewable energy resources can be brought online in the future.
    
    Designing the Demonstration Test
    
    The Kahe Plant, the largest generating station in Hawaii, consists of six oil-fired generators with a total capacity of 650 MW (Figure 1). HECO designed a test program to fire and cofire (with LSFO) environmentally sustainable crude palm oil. HECO’s 90-MW, tangential-fired Kahe Unit 3 was selected for the full-scale cofiring project conducted between Jan. 4 and 28, 2011. Blends using between 0% and 100% biofuel were tested between 38 MW (baseload) and 88 MW (near full load). The test program was designed to assess the operating limitations when using biofuel without:
    •Major equipment modifications
    •Violating environmental compliance requirements
    •Derating generating capacity
    •Compromising the ability to operate the unit on LSFO
    
    1. Six-unit plant. Kahe Unit 3, the test unit, is a 90-MW gross tangential-fired boiler, originally manufactured by Combustion Engineering Corp. (now Alstom), that has design steam conditions of 1,005F and 1,965 psig. The Kahe plant consists of six boilers fired with low-sulfur fuel oil with a total capacity of 650 MW. Courtesy: Combustion Components Associates
    
    
    Palm oil was chosen because its characteristics are similar to those of LSFO. However, the higher heating value of palm oil is approximately 14% less than for LSFO, which results in increased fuel flow per burner (from 8 gpm for LSFO to 9.1 gpm for palm oil) in order to maintain the required heat input into the boiler and avoid boiler derating.
    
    HECO imported 1.6 million gallons of palm oil from Malaysia for its demonstration project, although it plans to procure locally produced fuels as they become available (see sidebar). The palm oil was transported by ship in stainless steel tanks and then stored in a dedicated oil tank at Kahe.
    
    A parallel fuel supply system was installed so biofuel could be independently controlled and fed to the boiler without LSFO cross-contamination. The new palm oil fuel-handling system included the addition of two new biofuel pumps, a static blender, and a fuel heater bypass valve as well as replacement of the secondary fuel oil pumps and installation of two viscometers, various control valves, several new flow meters, and various other valves. The fuel supply piping arrangement also allowed operators to quickly secure the palm oil supply and return to 100% LSFO should the need arise. HECO required the new supply system to be a permanent installation controlled by the plant’s distributed control system and designed and installed to meet National Fire Protection Association guidelines.
    
    Another important difference between biofuel and LSFO is the biofuel’s much lower viscosity (~133 SSU for palm oil versus ~1,600 SSU for LSFO at 122F). This difference required the fuel supply system to carefully control fuel oil temperature as the blend ratio of LSFO and biofuel changed during the testing to maintain pump performance and good oil atomization. The pour point of palm oil is <80F. This means that fuel tanks holding palm oil may require protective lined berms. LSFO solidifies at ambient conditions.
    
    The ash, sulfur, and fuel nitrogen contents and carbon-hydrogen ratio of biofuel are much lower than for LSFO. Consequently, emissions of SO2, particulate matter, NOx, and CO2 were expected to be lower than when firing LSFO.
    
    CCA Combustion Systems, a division of Peerless Mfg. Co., was retained to perform the baseline LSFO emissions tests, develop the computational fluid dynamic (CFD) model used to predict palm oil impacts on boiler performance, and to design and supply a unique atomizer that would allow cofiring from 100% palm oil to 100% LSFO with no loss in maximum load or unit turndown capability (minimum load is 25 MW). CCA was also tasked with managing the demonstration test, determining boiler performance and plant heat rate, and extrapolating the results of the demonstration test to all HECO steam plants. HECO performed NOx emission tests following the demonstration test.
    
14. voda 3 juni 2014 21:09

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    Part 2
    
    Unique Atomizer Design
    
    HECO contracted with CCA to design and fabricate new mechanical, spill-return atomizer assemblies for the biofuel demonstration test. The design criteria for the new fuel atomizers were ambitious:
    •¦ Operate at approximately the same supply/return pressures as the existing atomizers.
    •Have the same spray quality but not adversely impact spray angle at low loads.
    •Must not inhibit full-load operations nor impact unit turndown.
    •Operate with fuel blends from 100% LSFO to 100% palm oil.
    •Must accommodate 14% more flow when burning 100% palm oil due to lower heat content.
    
    Prior to the biofuel demonstration test the oil atomizer used at Kahe Unit 3 was a mechanically atomized, spill/return, four-piece assembly. The spray plate was a “conical” design with a single orifice that produced a uniform conical spray. The supply and return pressures at maximum load were typically 890 psig and 310 psig, respectively, and the differential pressure between supply and return pressures was maintained constant at approximately 580 psid over the load range. Turndown for the atomizers was from 90 MW to 38 MW (baseload) with all burners in service.
    
    To reduce flame impingement problems experienced historically at low load on the furnace sidewalls adjacent to the burners, an alternate “split-flame” atomizer spray plate was provided. The split flame produced a flatter, nonconical spray that can be oriented to reduce flame impingement. Two prototype split-flame atomizer assemblies were used in the biofuel demonstration:
    
    •100% split-flame atomizer designed for optimum performance firing 100% biofuel.
    •50/50 split-flame atomizer designed for optimum performance firing a blend of 50% LSFO and 50% biofuel.
    
    In addition to providing the proper flow rate characteristics and narrower spray angle at low load, the split-flame atomizers reduced NOx emissions approximately 20% for LSFO firing compared to the original atomizers.
    
    Visual inspection when burning palm oil showed the flames were very uniform and well attached under all operating conditions. It was not possible to visually distinguish a 100% LSFO flame from a 50% biofuel/50% LSFO flame. At 70% biofuel the flames were more transparent and less bright. At 100% biofuel, the oil spray skirts were transparent and a blue-colored flame “halo” was observed at the flame stabilizer. The flames were less bright than at 70% biofuel but still intense. Moreover, the split-flame atomizers significantly reduced but did not completely eliminate sidewall impingement at low load. As expected, opacity and visual emissions went from ~2.8% to below 0.5% as the ratio of biofuel increased from 0% to 100%.
    
    Furnace exit gas temperature (FEGT) for the two split-flame atomizers was essentially equal over the load range. For LSFO, the average FEGT at 100% load for the split-flames was approximately 140F higher than for the conical atomizers used prior to the biofuel tests. This is believed to be a result of the longer flames (low NOx) produced by the split-flame design, which reduces near-burner fuel/air mixing rates. NOx emissions were approximately 20% lower for the split-flame atomizers. Furnace residence times were sufficient to provide good fuel burnout, so opacity levels were not increased. FEGT and gas emissions data measured in the upper furnace were reasonably well balanced across the furnace.
    
    Excellent Test Results
    
    The palm oil/LSFO blend ratio was selected based on total heat input into the boiler. This approach to in-line fuel blending provided accurate and repeatable results. The unit load response when burning up to 100% palm oil was comparable to burning LSFO alone. The viscosity of the blended fuels was a constant 135 SSU up to 70% palm oil. At 100% palm oil, the viscosity decreased to ~85 SSU; however, the performance of the fuel atomizer was not affected.
    
    Boiler turndown met the test plan goals. The unit was able to cycle from full load (90 MW) down to 25 MW when burning 100% LSFO. The fuel oil controls limit minimum load to ~25 MW. When burning 100% palm oil, the minimum demonstrated load was 38 MW using existing burner controls, although with further combustion control tuning it is expected that minimum load on palm oil could be reduced.
    
    Excellent flame stability was observed at all fuel blends, unit load, and fuel temperatures when using the split-flame atomizer. Visible emissions (opacity) were also lower when burning 100% palm oil.
    
    The FEGT, measured below the nose of the furnace, the superheat and reheat temperatures and sprays, and boiler heat flux were measured during the demonstration test (Figures 2 and 3). NOx emissions with palm oil blends were well within permitted limits (Table 1). At 88 MW, NOx on LSFO was 300 parts per million by volume dry (ppmvd) but dropped to 213 ppmvd when burning a 70% palm oil mix and to 202 ppmvd with 100% palm oil. Figure 4 illustrates NOx emissions
    
    The impact on plant efficiency when cofiring different percentages of palm oil was calculated from the test data. At full load, the negative effects on efficiency when burning 100% palm oil included 11F higher stack gas temperature and ~17% higher water content in the flue gas than when burning LSFO.
    
    However, the excess O2 in the flue gas was nearly 1% lower than when burning LSFO. Unburned carbon and CO emissions changes were negligible for both fuels. However, 100% palm oil generally required increased superheater and reheater attemperation compared to 100% LSFO, which will decrease boiler efficiency. The existing boiler system was adequate to provide the increased attemperation needed. The “sweet spot” for optimum boiler operation based on attemperation rates was a blend of 70% biofuel and 30% LSFO.
    
    The plant’s adjusted heat rate, taking into account superheater and reheater sprays, excess oxygen, stack gas temperature, and water in the flue gas (15% higher) increased 48 Btu/kWh when burning 70% palm oil, which reflects a slight decrease in boiler efficiency. However, burning 100% palm oil increased plant heat rate further, primarily because of higher attemperation rates. At biofuel blends of 70% and higher the test data showed that a reduction in excess O2 of roughly 1 percentage point is possible with the same or lower opacity compared to LSFO firing.
    
    The low ash content of the palm oil also reduced particulate matter and unburned carbon emissions. Another positive side effect was reduced frequency of sootblowing and cleaner furnace walls.
    
    Program Goals Achieved
    
    The 30-day demonstration project achieved every goal set for the testing. The in-line blending system provided maximum operational flexibility for a biofuel that may have fuel property variations between deliveries. More importantly, there were no operational or emission limitations identified that would restrict any palm oil/LSFO blend ratio. And, by extension, the testing did not reveal any operational or emission limitations that would preclude using the biofuel at any other HECO units that now burn LSFO.¦
    
    — Robert Carr (carr@cca-inc.net) is project manager at CCA Combustion Systems. David McDermott is operations and maintenance engineer for Hawaiian Electric Co.
    
    Etc, zie link voor foto's, grafieken etc.
    
    www.powermag.com/heco-successfully-co...
15. voda 2 juli 2014 20:37

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    The Expanding Wood Pellet Market
    
    Last year, the U.S. exported nearly twice the amount of wood pellets it sent overseas in 2012—and almost all of it went to Europe for heat and power needs. This trend has gained momentum since 2009, when the European Commission (EC) enacted its 2020 climate and energy package, and will possibly continue in the long term, says the U.S. Energy Information Administration (EIA) in a new report.
    
    As recently as 2008, about 80% of U.S.–made wood pellets, typically from wood waste (such as sawdust, shavings, and wood chips), but also from unprocessed harvested wood, were consumed domestically for residential heating fuel. But the EC’s binding 2009 legislation, which calls on the European Union (EU) to reduce greenhouse gas emissions by 20% from 1990 levels and to produce 20% of its power from renewables, has sent demand for U.S. wood pellets soaring, the EIA says.
    
    At least 98% of wood pellet exports (and 99% sourced from ports in the southeastern and lower Mid-Atlantic regions of the U.S.) went to Europe in 2013, mostly to the UK, Belgium, Denmark, the Netherlands, Italy, and other countries that are using wood pellets to replace coal for power generation and space heating (Figure 2). The UK, specifically, consumed 59% of U.S. wood pellet exports to meet demand that has grown from near zero in 2009 to more than 3.5 million short tons in 2013. It also imported from Canada and other European sources.
    
    One reason for the soaring growth is the UK’s Renewables Obligation program, through which operators of several large coal-fired power plants have either retrofitted existing units to cofire biomass wood pellets with coal or have converted to 100% biomass. Last December, for example, Drax completed the $1.14 billion conversion of three of its six coal-fired units at the Drax Power Station to biomass. The facility reportedly needs at least seven million metric tons of wood pellets a year. At the same time, Drax is considering converting a fourth unit, meaning pellet demand could exceed nine million metric tons. The company is building two of its own pellet plants in Louisiana and Mississippi.
    
    According to one of the largest U.S. wood pellet manufacturers, Enviva, the primary reason that European utilities are banking on imports—rather than using wood from European forests—is because “North America has significantly more forestland than Europe as well as a long history of sustainable forest management and productive commercial forest product industries.” And, biomass isn’t being adopted on the same scale in the U.S. because it just doesn’t have a “cohesive” national renewable policy as the EU does. Meanwhile, ocean freight is “substantially more carbon and energy efficient in a per ton basis than trucking,” says the company. “This means that shipping a ton of pellets from the Southeast U.S. to England results in less carbon emissions than trucking that same ton from northern Scotland to England.”
    
    For Enviva, the growth of the wood pellet export market is sound. Though the UK recently placed a 400-MW limit on new-build biomass-fired power plants, “there’s no limit on the conversion of existing coal plants to biomass or on the construction of biomass-fueled combined heat and power (CHP) facilities,” it says. “Demand for sustainably produced biomass fuels is still expected to grow substantially through 2020 as coal-fired power facilities attempt to meet regulatory targets and improve the environmental profile of energy generation.”
    
    —Sonal Patel, associate editor (@POWERmagazine, @sonalcpatel)
    
16. voda 2 juli 2014 20:46

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    Biomass Exemption Sails into the Sunset
    
    With quickly approaching deadlines for achieving renewable portfolio standard goals, the likely lapse of a critical exemption this month may increase the
    challenges for meeting those mandates.
    
    Approximately four years ago the U.S. Environmental Protection Agency (EPA) took the first step in regulating greenhouse gas (GHG) emissions from electric generating units (EGUs) by promulgating the Greenhouse Gas Tailoring Rule on June 10, 2010. The rule was implemented over a two-and-a-half-year period with three major steps covering new and existing emission sources. This rule will significantly affect new and existing sources, as GHG emissions are now regulated pollutants. Facilities that generate more than 100,000 tons a year of equivalent carbon dioxide are now classified as major sources. Carbon dioxide equivalent is defined as the combined emissions from carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.
    
    For the majority of fossil fuel–fired sources, this rule is just another regulatory speed bump requiring EGUs to address GHGs. For smaller renewable power generators and utilities adding biomass power plants to their fleet, this regulation is a serious roadblock that will push small biomass facilities from less-regulated area emission sources to full-blown major emission sources.
    
    With deadlines for meeting renewable portfolio standards quickly approaching, additional regulatory hurdles would decrease the likelihood of reaching those mandated levels of renewable generation. It is with this in mind that shortly after promulgation of the GHG Tailoring Rule, several members of the U.S. Congress filed complaints with the then-administrator of the EPA, Lisa Jackson, requesting a deferral of the rule’s applicability to biomass sources.
    
    Enough pressure had been placed on the EPA that action was taken to temporarily exempt renewable EGUs from the Tailoring Rule’s impact. On July 1, 2011, the Federal Register published an update to include a three-year deferral for the “application of Prevention of Significant Deterioration (PSD) and Title V permitting requirements to carbon dioxide emissions from bioenergy and other biogenic stationary sources.” The purpose of this three-year deferment was to allow the EPA to conduct a detailed analysis of the science associated with biogenic carbon dioxide emissions from stationary sources.
    
    For clarity, not all biomass power generators were granted the deferment. As part of the three-step implementation process of the GHG Tailoring Rule, the first step included facilities that currently were covered under Title V permitting programs. Those facilities would not be granted a deferment and would be subject to carbon dioxide equivalent regulations. For biomass facilities that were already covered under Title V programs, the EPA issued a guidance document for determining the best available control technology (BACT) for biogenic carbon dioxide emissions. The EPA also made the deferral voluntary, leaving it to the discretion of individual states to adopt the deferral and to regulate accordingly.
    
    Significance of Area Sources
    
    Area sources, sometimes also referred to as minor emission sources, are facilities that have emissions too small to be treated as a point source. The EPA defines area sources as those emitting any individual hazardous air pollutant (HAP) less than 10 tons per year, emitting combined HAPs less than 25 tons per year, or (depending on the source category) a facility emitting less than 100 or 250 tons per year of individual criteria pollutants.
    
    HAPs are defined by the Clean Air Act, which was last updated in 1990 and contains a list of 189 chemicals classified as HAPs. Criteria pollutants consist of nitrogen oxides (NOx), sulfur dioxide (SO2), fine particulate, carbon monoxide, and volatile organic compounds.
    
    EGUs that have the capability of firing more than 250 million Btu an hour of fossil fuels fall under the more stringent regulation of 100 tons per year of criteria pollutants to achieve area source classification. Assuming a facility uses biomass as its primary fuel source and the combined fossil firing of any ancillary equipment is less than 250 million Btu an hour, the facility would be regulated as an area source. This is advantageous, as biomass area sources are allowed to emit up to 250 tons per year of criteria pollutants and avoid federal PSD regulations.
    
    There are other advantages for a facility being classified as an area emission source. If a facility falls under PSD permitting requirements, the following areas must be addressed in the permit application: BACT analysis addressing emission controls technologies, an air quality analysis, an additional impact analysis, and public involvement:
    •BACT analysis is a case-by-case analysis that addresses the maximum degree of emission control for each pollutant and factors in energy, environmental, and economic impacts.
    •The air quality analysis is meant to demonstrate that the new facility will not violate any National Ambient Air Quality Standards as a result of the facility’s operation. This analysis first assesses the existing air quality of a site using ambient monitoring devices. The second part of the analysis incorporates dispersion modeling of the new emission source to predict the impact on the surrounding environment.
    •Additional impact analyses pertain specifically to the effect of construction and operation of the new facility on the proposed site. These assessments include ground and water pollution on soils, impacts on wetlands, vegetation, visibility, endangered species analysis, and archaeological impacts.
    •Public involvement allows the general public to provide comments to a draft permit and typically involves a public hearing to address any concerns directly to the EPA and owners. The time to permit a major source can take anywhere from 12 to 18 months, depending on the complexity of the facility.
    
    Because area sources have been deemed too small to be classified as a point source, their permitting process is typically done at a state level. Most states do not impose PSD permitting requirements such as BACT, air quality analysis, and impact analyses.
    
    As a result of the less-onerous permit requirements, the process to obtain a construction permit for an area source is reduced to approximately three months. The speed and reduced complexity of the permitting process is particularly favorable to utilities wishing to utilize biomass fuel sources to meet renewable portfolio standards. Private developers also favor the area source permitting process, as less capital is required and quicker construction start times are expected.
    
    How Biomass EGUs Are Affected
    
    With a greater focus on adding renewable power generation to meet renewable portfolio standards, the ability to permit and build biomass power generation facilities is becoming crucial. Biomass fuels by their nature tend to have low levels of compounds that create regulated byproducts as a result of combustion. As an example, a typical woody biomass fuel used to generate steam from a fluidized bed combustor and using only a pulse jet fabric filter for particulate control could be sized at 25 MW and still be classified as an area source.
    
    In the U.S. there are approximately 144 power generating facilities using biomass fuels as their primary fuel source (Figure 1). Of those 144 facilities, nearly half (71 facilities) have a rated capacity of 25 MW or less, making small generators a significant portion of the national biomass generation portfolio.
    
17. voda 2 juli 2014 20:48

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    part 2:
    
    1. How small is small? Currently, biomass plants of 25 MW and less fall below the threshold for being classified as “major emission sources.” If biomass plants were subject to the Greenhouse Gas Tailoring Rule, the threshold would drop to 8 MW, exempting only 16 of the 144 existing biomass facilities instead of the 71 considered area sources today. Source: Energy Information Administration
    
    If the current GHG Tailoring Rule exemption for biogenic sources were vacated, the rated capacity of the same wood burning biomass facility outlined above would plummet to approximately 8 MW of generation capacity before crossing the major emission source threshold. This reduction is significant, as the number of biomass sources currently rated at 8 MW and less is a mere 16. Assuming the same distribution of biomass plant sizes is expected in the future, approximately 89% of those facilities would be classified as major emission sources as a result of the GHG Tailoring Rule being applied.
    
    Sunset Provision
    
    The exemption of biogenic carbon dioxide sources from the GHG Tailoring Rule was not a popular move for some industry groups. This is evidenced by the more than 200-page “Summary of Public Comments and Responses” document issued on June 28, 2011. With such strong feelings against the deferral, these groups filed a challenge to vacate the EPA’s deferral.
    
    In July 2013, the D.C. Circuit Court issued a 2-1 ruling vacating the biogenic carbon dioxide deferral and caused turmoil in the biomass industry. The industry legally had 30 days to file for a rehearing on the ruling, but the opportunity to appeal is being withheld. Instead, the court decided to tie any additional actions to another key case, Utility Air Regulatory Group (UARG) v. EPA. In this case the UARG is challenging the EPA’s authority to regulate carbon dioxide from stationary sources via the Massachusetts v. EPA (2007) ruling.
    
    The D.C. court withheld the mandate of the vacatur until a ruling from UARG v. EPA was issued. As a result of this withholding, the original biogenic exemption remains in place. The Supreme Court heard oral arguments in the UARG v. EPA case on Feb. 24, 2014, and a decision is expected in the latter part of the year.
    
    Although this would appear to give renewable biomass power generators hope for the future, the reality is that time is still running out on this exemption. In the published deferral, section 51.166 provided clear direction for the lifespan of this deferral: “For the purposes of this paragraph, prior to July 21, 2014 the mass of the greenhouse gas carbon dioxide shall not include carbon dioxide emissions resulting from the combustion or decomposition of non-fossilized and biodegradable organic material originating from plants, animals,…and biodegradable organic material.”
    
    That statement is commonly referred to as a sunset provision for the deferral. Without EPA studies supporting the future exemption of biogenic carbon dioxide emissions, and barring any decisions by the federal courts to overturn the vacatur, on July 21, 2014, the deferral will simply expire.
    
    Regulatory and Permitting Complexities
    
    Although it may appear that the expiration of the biogenic deferral will be detrimental to new biomass facilities, the problem may be more complex than that. With the assumption that no further action by the courts will be realized, facilities that took advantage of the biogenic carbon dioxide deferral during this three-year period most likely will be required to retroactively obtain permits that address the GHG Tailoring Rule.
    
    Precedence for this retroactive permit modification was demonstrated with the vacatur of the EPA’s Section 112(n) Revision Rule of the Clean Air Mercury Rule. The Section 112(n) revision rule was published Mar. 29, 2005, and removed coal- and oil-fired EGUs from the list of applicable sources in Section 112(c). On Feb. 8, 2008, the U.S. Court of Appeals for the D.C. Circuit Court vacated the Section 112(n) revision rule and issued a mandate on Mar. 14, 2008. EGUs that used this exemption in the permitting process and began construction or reconstruction between Mar. 29, 2005, and Mar. 14, 2008, were now legally required to comply with Section 112(g) requirements.
    
    Implementation of the GHG Tailoring Rule has been around for several years now, and by far the most common control method for carbon dioxide equivalent emissions has been energy efficiency methods. However, for those facilities constructed between June 10, 2010, and July 21, 2014, that used the biogenic carbon dioxide deferral and now will be classified as major emission sources, other pollutants may be subject to emissions control technologies.
    
    Depending on the specific pollutant in question, expensive control technologies may need to be retroactively installed at existing facilities. Equipment such as selective catalytic reduction systems for NOx control and wet and dry scrubbers for SO2 control potentially work their way into the economics of these biomass facilities. However, it is too early to say if any of these pollution control technologies will be mandated.
    
    Although the biogenic carbon dioxide deferral is set to expire in July, there is still the possibility that the regulation of carbon dioxide emissions from EGUs could be vacated later this year. Deadlines for meeting state renewable portfolio standards are quickly approaching—nine are set for 2015—and the need for renewable power sources is great. Adding additional permitting, capital, and operational hurdles for new and some existing sources will only make achieving these goals more problematic.
    
    With so much uncertainty, it’s hard to predict what the future holds, but new biomass EGUs should be prepared for stiffer environmental controls, and existing biomass EGUs that utilized the biogenic exemption should prepare for possible permit modifications. ¦
    
    — Brandon Bell, PE (bbell@valdeseng.com) is a project manager at Valdes Engineering and a POWER contributing editor.
    
18. voda 2 juli 2014 20:50

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19. voda 5 december 2014 21:47

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    Top Plant: Hometown BioEnergy, Le Sueur, Minnesota
    
    Using agricultural and food-processing waste products, Hometown BioEnergy is helping the Minnesota Municipal Power Agency meet state-mandated renewable energy standards while also providing a valuable fertilizer for area farmers and solid biomass as a fuel for other facilities. Courtesy: Avant Energy Inc.
    
    
    We’ve all heard the phrase “one man’s trash is another man’s treasure.” Hometown BioEnergy (HTBE) offers a case in point. The plant uses vegetable-processing waste and livestock manure in an anaerobic digestion process to produce biogas for use in engine generator sets. The agricultural trash is a real treasure for the company.
    
    Avant Energy Inc.—the energy management company that developed, oversaw construction, and continues to manage operation of the plant for Minnesota Municipal Power Agency (MMPA)—sees tremendous opportunities to redefine the term “waste.” It believes bioenergy can help utilities, large waste producers, food processors, and communities create value from waste streams and reduce overall energy costs. Its development team supports clients in the planning, design, and construction of both conventional and renewable power generation facilities.
    
    While some people may think that the plant is utilizing vital resources that could otherwise be used to fertilize area farmland, it actually increases options for the agricultural industry. Not only does it help manage disposal of the waste, but its biological process also produces a liquid fertilizer—rich in nutrients such as nitrogen, phosphorus, and potassium—that is then sold back to local farmers to spread on their land. In addition, undigested biomass is dried to create a solid fuel, which can be sold to other biomass and coal-fired facilities to fuel their boilers.
    
    A Flexible Design
    
    Variety may be the “spice of life,” but it doesn’t always make for the best “seasoning” at biomass plants. When dealing with agricultural waste products, though, variety is also a fact of life. Materials are frequently exposed to weather, which means rain, sun, and wind will all significantly affect moisture content. If waste is stockpiled for any length of time prior to delivery, quality can degrade. Farm management practices—such as cleaning schedules, herd size, square footage per animal, and base bedding material—can also affect waste quality.
    
    One of Avant’s key objectives when designing the HTBE facility was maintaining flexibility in the allowable feedstocks. Tolerating variety enables the plant to manage large seasonal changes in waste volumes from suppliers in the region. In addition, it allows the company to accept wastes that become available on a sporadic basis with fewer operational challenges.
    
    The process begins with feedstock delivery. The mixture of local agricultural and food processing waste includes sweet corn silage, food waste, livestock waste, and waste oils (all sourced from within a 60-mile radius). The material is transported to HTBE via truck and delivered to the plant’s receiving hall. The biomass is weighed, mixed, and heated in feeding modules to prepare it for the anaerobic digestion process.
    
    “The percentages of each type of material varies; however, on average, the plant sees approximately 50% higher solid wastes and 50% liquid wastes,” said Kelsey Dillon, vice president BioPower for Avant Energy.
    
    Inside the digesters, bacteria work together in the absence of oxygen to decompose organic material and produce biogas. Biogas typically contains about 55% to 70% methane, 30% to 45% carbon dioxide, and trace amounts of other gases, including sulfur in the form of hydrogen sulfide (H2S). As H2S is corrosive, it must be removed before combustion. At HTBE, the H2S is removed from the biogas through microbial processes in gas cleaners as the product leaves the anaerobic digesters.
    
20. voda 5 december 2014 21:47

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    Part 2:
    
    A Rapid Timeline
    
    Minnesota winters offer a multitude of challenges, especially for construction companies. Nonetheless, the project broke ground in December 2012 with a one-year goal for completion.
    
    “The aggressive construction schedule for the plant was a significant challenge, but we worked weekends and long hours. We also had good management and strategies in place to complete the project in the one year timeframe,” Dillon said.
    
    Avant managed the construction, hiring a variety of firms to perform mechanical, electrical, structural, and building work. Xergi A/S—a Denmark-based company that designs and builds biogas plants—delivered the anaerobic digestion technology, and Barr Engineering Co. provided engineering support for the project. Biomass loading began in October 2013 and operations commenced on schedule two months later.
    
    “As is the case with all power plants in a northern climate, especially an extreme climate like Minnesota, freeze protection is always a key priority. We started operation last winter during one of the coldest on record, but worked to successfully solve what can be very pesky freeze problems,” said Benjamin Simmons, asset manager for HTBE.
    
    Enthusiasm for Renewables
    
    Minnesota was a logical location for designing and building HTBE. The state has one of the nation’s most aggressive renewable energy standards, requiring all utilities to generate at least 25% of their electricity from renewable energy sources by 2025.
    
    Wind is the clear leader in the state’s renewable portfolio. It produced 15.7% of the in-state generation in 2013, placing Minnesota fifth nationally based on production percentages. Given the state’s latitude, many people may be surprised to learn that Minnesota has annual solar radiation similar to parts of Florida and Texas, but that potential remains largely untapped. In 2013, however, the Minnesota Legislature passed an omnibus energy bill requiring public utilities to generate 1.5% of their energy from the sun, so solar is likely to gain some ground in the future.
    
    But agriculture remains one of the state’s largest industries, so a plant that utilizes farm waste is a natural fit. HTBE filled that niche, and its success could lead to development of similar plants elsewhere. For utilities mandated to meet renewable energy standards, biogas’s dispatch flexibility offers clear advantages over wind and solar resources.
    
    “We see strong potential for more BioPower plants and are pursuing project opportunities throughout the country. BioPower is an especially attractive renewable option due to its reliable and dispatchable nature, but BioPower is also more complex than wind or solar and requires more logistical coordination during development and operations. Areas with large amounts of food or agricultural waste and a local utility with a renewable appetite make good candidates for BioPower,” said Dillon.
    
    As a unique waste solution for rural areas and a reliable renewable energy resource, HTBE is the worthy recipient of a POWER Top Plant award. ¦
    
    — Aaron Larson is a POWER associate editor (@POWERmagazine, @AaronL_Power).